Real-time simulations have become a crucial tool for life cycle studies of VSC-based HVDC systems. This paper introduces real-time Multi-Terminal HVDC (MTDC) power [1] system network models with real-time wind pro le feedback. It addresses the shortcomings of existing benchmark network models and lls the modeling gaps. ® RSCAD/RTDS environment represents the real-time modeling techniques for studying the life cycle of Bipolar Metallic Return con guration of HVDC systems. This paper evaluates the performance of the proposed network model using unscheduled events, startup, and black start events. Future studies can be conducted using the proposed network models by mimicking the actual performance of cable-based DC grids while considering the computational insights from this paper. The ndings of this paper shall enable the identi cation of various stress points that can be utilized to specify technical requirements for component design and AC/DC protection studies concerning startup and black start sequence.

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It is challenging to determine the active filter control factors in wind power plants (WPP) to obtain effective harmonic voltage mitigation and avoid over-modulation or system instability problems caused by overlarge feedforward or feedback gains. To address this issue, an active filter tuning (AFT) method is proposed in this paper to offer a common parameter tuning and stability assessment strategy for both current-controlled and voltage-controlled harmonic impedance reshaping (HIR) methods by introducing a coordination factor including different weight coefficients for system stability margin, wind turbine (WT) harmonic suppression, and grid harmonic mitigation. The superiority of the proposed method is verified in a 20 MW WPP with four cases considering both WT harmonic voltage amplification and grid voltage amplification. Compared to previous methods, the AFT-based HIR method achieves a more flexible balance between system stability and harmonic voltage mitigation, obtaining better performance in WT harmonic suppression, grid harmonic suppression, system robustness, and transient response.

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An economical approach for incorporating Battery Energy Storage Systems (BESS) onto DP-2 vessels is presented in this research. The paper deals with developing a Battery Optimization for Optimal Sizing and Throughput Energy Regulation (BOOSTER) framework for putting research findings into practice by optimizing battery size, technology choice and power generation scheduling while considering battery degradation. Twelve battery sizes are analyzed based on three key performance metrics: return on investment, payback period, and years of profitability. A Mixed Integer Linear Programming (MILP) is developed to operate the energy and power management system of the vessel in a fuel and economically efficient manner. The study considers two load profiles of a DP-2 vessel operating near Taiwan and the North Sea. Our findings emphasize the significance of taking battery ownership costs in the form of energy throughput cost and fuel price into account, resulting in a longer battery lifetime and higher return on investment. The research also proposes a BESS operation matrix that provides vessel operators with valuable information on BESS usage for economic benefits. This matrix translates analytics and decision-making into tangible actions that can be implemented in real-time operations. Based on the findings, energy systems may be optimized for a sustainable future, which benefits vessel operators and industry stakeholders.

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AC/multi-terminal DC (MTDC) hybrid power systems have emerged as a solution for the large-scale and long-distance accommodation of power produced by renewable energy systems (RESs). To ensure the optimal operation of such hybrid power systems, this paper addresses three key issues: system operational flexibility, centralized communication limitations, and RES uncertainties. Accordingly, a specific AC/DC optimal power flow (OPF) model and a distributed robust optimization method are proposed. Firstly, we apply a set of linear approximation and convex relaxation techniques to formulate the mixed-integer convex AC/DC OPF model. This model incorporates the DC network-cognizant constraint, enabling DC topology reconfiguration. Next, generalized Benders decomposition (GBD) is employed to provide distributed optimization. Enhanced approaches are incorporated into GBD to achieve parallel computation and asynchronous updating. Additionally, the extreme scenario method (ESM) is embedded into the constructed AC/DC OPF model to provide robust decisions to hedge against RES uncertainties. ESM is further extended to align the GBD procedure. Numerical results are finally presented to validate the effectiveness of our proposed optimization method.

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The heterogeneous distribution of frequency support from dispersed renewable generation sources results in varying inertia within the system. The effects of disturbances exhibit non-uniform variations contingent upon the disturbance's location and the affected region's topology and inertia. A screening method for inertia-zone identification is proposed considering the combination of network structure and generator inertia distribution that will aid in comprehending the response of nodes to disturbances. The nodes' dynamic nodal weight (DNW) is defined using maximal entropy random walk that defines each node's spreading power dynamics. Further, a modified weighted kmeans++ clustering technique is proposed using DNW to obtain the equivalent spatial points of each zone and the system to parameterize the inertia status of each zone. The impact of the proposed scheme is justified by simulating a modified IEEE 39 bus system with doubly-fed induction generator (DFIG) integration in the real-time digital simulator.

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The extensive integration of distributed renewable energy resources (DRES) can lead to several issues in power grids, particularly in distribution grids, due to their inherent intermittency. This paper presents a stochastic simulation-based approach to estimate the maximum permissible penetration level of DRES and to determine the optimal capacity of centralized battery energy storage systems (BESS) in distribution networks while adhering to technical constraints. The stochastic method creates a wide range of scenarios under various conditions. For each scenario, our proposed approach calculates the maximum allowable penetration level of DRES and the required BESS capacity with different DRES control logics. The maximum allowable penetration level of DRES and the requirements of the BESS capacity are determined by an analysis of various simulation results. This paper's unique contribution lies in equipping distribution system operators (DSOs) with the ability to compare results and select the most appropriate voltage control and power smoothing methods. This aids in mitigating challenges associated with overvoltage and intermittency issues arising from DRES-generated power, thereby enhancing the overall resilience and reliability of the power grid. Case studies that include four voltage control algorithms and three power smoothing methods demonstrate the universality and effectiveness of the proposed approach.

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Identifying faulty lines and their accurate location is key for rapidly restoring distribution systems. This will become a greater challenge as the penetration of power electronics increases, and contingencies are seen across larger areas. This paper proposes a single terminal methodology (i.e., no communication involved) that is robust to variations of key parameters (e.g., sampling frequency, system parameters, etc.) and performs particularly well for low resistance faults that constitute the majority of faults in low voltage DC systems. The proposed method uses local measurements to estimate the current caused by the other terminals affected by the contingency. This mimics the strategy followed by double terminal methods that require communications and decouples the accuracy of the methodology from the fault resistance. The algorithm takes consecutive voltage and current samples, including the estimated current of the other terminal, into the analysis. This mathematical methodology results in a better accuracy than other single-terminal approaches found in the literature. The robustness of the proposed strategy against different fault resistances and locations is demonstrated using MATLAB simulations.

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Fast, sensitive, and selective protection principles are one of the major challenges in the feasibility of modular multi-terminal (MMC) high voltage direct current (HVDC) grids. Rate of change of voltage (ROCOV) and transient-based solutions are the traditional and widely accepted protection principles. Despite the speed and practicality of these solutions, they generally suffer from sensitivity and selectivity issues, particularly when dealing with high-resistance faults and low-size current limiting inductors (CLIs). To improve upon these methods, this paper proposes a new primary protection method that utilizes a selective drop rate of fault-generated voltage traveling waves (TW) to detect internal DC line faults. This is achieved by a comprehensive analysis of the line-mode fault-generated voltage (LFGV) under various internal and external fault scenarios. As the key fault characteristics, the proposed method exploits the minimum points of initial LFGV and the corresponding time to form the basis of the proposed protection method. The effectiveness of this approach is evaluated using a four-terminal MMC-HVDC grid in PSCAD/EMTDC. Compared to ROCOV and transient-based solutions, the proposed method identifies internal faults up to 1250 Ω with fast response, while maintaining its practicality and independence to CLI size.

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Existing line protection methods for multi-terminal direct current (MTDC) systems are constrained by the placement and values of boundary elements. To overcome this limitation, this paper proposes a non-unit DC line protection method based on the normalized backward traveling waves (BTWs) of the 1-mode voltage. Firstly, this article studies the traveling wave characteristics and derives the expressions for the normalized BTWs. Then, the Levenberg-Marquardt algorithm is used for amplitude fitting and normalization calculation. Based on the normalized BTWs, a non-unit protection method is proposed. Finally, the proposed method is evaluated with a simulation model on the PSCAD/EMTDC platform. The results demonstrate that the proposed method can accurately identify faults of different resistances and distances without requiring boundary devices, and is robust against noise disturbances (35 dB).

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High local electric field intensity in transformer windings originating from transient signals is one of the reasons for transformer failures. Due to the integration of renewable energy sources into the power grids and the increased number of transients, the likelihood of transformer catastrophic failure increases accordingly. Therefore, to ensure the reliable performance of transformers and associated power networks studying their behavior during these events is required. Accordingly, there is a need for accurate modeling of transformer windings capable of simulating electromagnetic transients. Using these models, it is possible to identify frequencies that can be dangerous to the transformer windings and to study different protection schemes. This paper aims to find an accurate analytical model of transformer winding validated by experimental measurements and to study the performance of the R-L protection device during the transient phenomena. The protection device is designed based on the winding model to introduce an impedance comparable to that of the transformer winding at critical frequencies where voltage amplification in the winding is significant. This approach ensures enhanced protection against potential transformer damage to the transformer. By using this protection scheme, the high inter-turn voltage originating from transient signals may be mitigated. At the same time, it does not affect the grid's performance during normal conditions.

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Due to the vast number of substations at the distribution level and increased costs of differential busbar protection, DSOs are in search of cost-effective protection schemes for busbar protection. This includes the use of various communication-based protection schemes, such as the reverse-blocking schemes used at Stedin. However, due to impedance grounding, the single-phase-to-ground short circuit currents have small values in medium voltage impedance-earthed distribution grids. As a result, the reverse-blocking scheme fails to detect this type of fault. This paper introduces a novel distributed protection scheme based on the detection of zero-sequence components of the currents and voltages and the negative-sequence current component. The proposed scheme successfully detects single-phase-to-ground busbar faults by using the standard settings of the widely available overcurrent IEDs, and an IEC 61850 communication between them. Firstly, the detection of the zero- and negative-sequence current components is used to distinguish between a busbar and a feeder fault. Secondly, zero-sequence voltage detection is used to distinguish between the faulty and healthy sections of the busbar when the busbar coupler is opened. This also increases the proposed scheme's reliability by avoiding miss-operation due to human errors during maintenance or testing. The grid is modeled in a Real Time Digital Simulator (RTDS), and a Hardware-in-the-Loop (HiL) simulation is carried out to test the protection scheme. The extensive simulations show the strengths and the limitations of the proposed scheme. Based on the research results, the developed protection scheme is implemented as a standard protection scheme in all of Stedin's new distribution substations.

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Reliable Power Electronic Systems (PES) are vital for enabling energy transition technologies of the future. Power hardware-in-the-Loop (PHIL) test bed can be used to validate such systems cost-effectively and time-efficiently. In general, the Real Time Digital Twin (RTDT) is a virtual representation of the PES and its operating environment that mimics its behavior in real-time to provide adequate flexibility to the test bed. The workflow of alternating between the prototype and twin, for instance, overcomes the dilemma of needing 100 % details (due to fast dynamics), but optimization during design choices requires cheap flexibility. In this paper, some use cases in applications of RTDT-based PHIL test bed such as fault tolerant converters, power electronic interface for green technologies, survivable all-electric ships, mission profile-based reliability testing, protection of multi terminal dc systems and reconfigurable hybrid ac-dc links is discussed. Furthermore, the co-simulation potential of real-time platforms is briefly described.@en

This paper explores the possibilities of providing fast frequency support as an emergency support service to the disturbed AC system through the MTDC grid. A two-layer hierarchical control structure of the MTDC grid is proposed to assure the minimum cost of the frequency control actions, the minimum voltage deviations, or the minimal impact on the frequencies of not-affected AC systems while ensuring the stable operation of MTDC grid. An optimization algorithm is executed at the secondary control level to find the optimal reference values for the voltage-droop characteristics of the voltage-regulating converters, and consequently their DC voltages and active power references. Then, at the primary control level, the reference values are tuned with the optimization results. Implemented control structure confirms that MTDC can provide set values at its terminals without endangering its stability. The secondary control layer is implemented in MATLAB, while the performance of the controller is successfully evaluated through simulation in RSCAD.

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Due to the extension of the power grid with many complex and compact pieces of power equipment, transformers will be more exposed to fast transient, resulting from various resonance conditions. Transformer resonance can result in severe overvoltage on internal parts of the winding, leading to insulation failure and, consequently, transformer outage. The main reasons for resonance occurrence, the practical method to measure the resonance of transformers, and the solution for preventing transformer resonances have been discussed in the scientific reports over the past few decades; however, a comprehensive review of these studies is not present in the literature. Hence this paper aims to provide a comprehensive review to categorize the main reasons for transformer resonance, modeling methods, and appropriate solutions to suppress this phenomenon and suggest some prospective protection for future works.@en

This paper deals with a systematic assessment of the power system frequency dynamics under high penetration of converter-interfaced renewable energy sources (CI-RESs). Specifically, the concept of the virtual synchronous generator (VSG) is implemented in the CI-RESs located at the transmission system (TS) side and/or the distribution network (DN) side. Dynamic RMS simulations are performed on a testbed consisting of the IEEE 9-bus TS grid and the CIGRE medium-voltage DN grid under different CI-RES penetration levels and VSG control parameters to assess the VSG impact on the power system frequency dynamics. It is shown that the decommissioning of conventional power plants coupled via synchronous generators can be safely performed in case the VSG concept is adopted correctly.@en

The significance of battery energy storage systems (BESSs) technology has been growing rapidly, mostly due to the need for microgrid applications and the integration of renewables. Relevant to the importance of utilization of BESS in microgrids, the protection of the BESS during microgrid faults has become a concern too. The short circuit in a microgrid cause overcurrent for all of the integrated sources. BESS, as one of the sources in the microgrid, is heavily influenced by fault occurrence. The overcurrent can easily damage power electronic converter switches, battery management systems, and damage battery banks. Fault current limiters are appropriate protection devices that have been massively studied. In this article, we propose a controllable reactor fault current limiter (CRFCL) to protect the BESS against fault currents. The proposed CRFCL can control the fault current value supplied by BESS during a fault condition as a current regulator. It is realized by means of the operation of solid-state switches and series dc-reactor behavior. The main achievement of CRFCL is the protection of BESS against fault currents without delay. The simulations of the proposed structure are carried out in a MATLAB/Simulink platform, and they are confirmed and validated by experimental test results.

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In a multi-terminal direct current (MTdc) system based on a modular multilevel converter (MMC), high-speed and large interruption capability direct current circuit breakers (dc CBs) are required for dc fault interruption. However, commercializing these breakers is challenging, especially offshore, due to the large footprint of the surge arrester. Hence, a supplementary control is required to limit the rate of current rise along with the fault current limiter. Furthermore, the operation of the dc CB is not frequent. Thus, it can lead to delays in fault interruption. This study proposes the indirect model predictive control (MPC)-based zero-sequence current control. This control provides dc fault current suppression by continuously controlling the zero-sequence current component using circulating current suppression control (CCSC) and by providing feedback to the outer voltage loop and inner current loop of MMCs. The proposed control is simulated for pole-to-pole and pole-to-ground faults at the critical fault location of an MTdc system. The simulation is performed in Real Time Digital Simulator (RTDS) environment, which shows that the predictive control reduces the rate of rise of the fault current, providing an additional 3 ms after the dc fault occurrence to the dc CB to clear the fault. Besides, the energy absorbed by the dc CB's surge arrester during the pole-to-pole and pole-to-ground fault remains the same with the proposed control.

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The distribution network (DN) reconfiguration is a well-known optimal power flow (OPF) problem. However, with the transition of DN from 'passive' to 'active', new technical challenges arise in DN reconfiguration. This article addresses two key issues in this regard. Firstly, the integration of local renewable generation (LRG) introduces uncertainty into the system-wide power flow of the DN. Secondly, the coupling between DN and the external power grid (EPG) affects the determination of DN root voltage. Consequently, a novel DN reconfiguration approach is proposed in this article. To begin with, an explicit mixed-integer convex OPF model is constructed that incorporates both the EPG and DN sides. Notably, the OPF model embeds the function of local droop control that is provided by LRG. Subsequently, the original OPF model is decomposed, and the distributed optimization methods based on the augmented Lagrangian relaxation are employed. The article comprehensively discusses parallel processing and asynchronous implementation as parts of the distributed optimization procedure. Furthermore, to address the uncertainty related to LRG integration, the extreme scenario method is used to provide a robust decision regarding DN reconfiguration. The application of the extreme scenario method in the distributed OPF model concerning DN reconfiguration is successively developed. Finally, numerical results are presented to demonstrate the acceptable performance of the distributed optimization methods, in terms of optimality and convergence. Also, these are validated that the proposed DN reconfiguration approach exhibits robustness to LRG integration, the system-wide voltage profile is improved, and the active power loss is effectively reduced using the proposed DN reconfiguration approach.

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Overvoltage instability is a growing concern in a standalone low-voltage (LV) microgrid (MG) with non-dispatchable intermittent renewable energies such as residential and commercial photovoltaic generators (PVGs). Several overvoltage controllers used in PV arrays have adopted the concept of standard deviation from the maximum power point (MPP) to curtail the generated power. However, these solutions lack presenting analytical expression for the MPP deviation size, settings tuning independent of the MG's/PV's characteristics, scalability, and accurate power-sharing in the same control structure. To overcome these limitations, this paper proposes a new analytical MPP tracking (MPPT)-based overvoltage and power-sharing control method using the series equivalent resistance of the PV module model. By applying this analytical expression, the size of the PV array voltage shift to the right-hand side of the MPP is obtained in terms of overvoltage level, while all PVGs proportionally curtail the active power output. The effectiveness of the proposed methodology is shown in various low-demand and high-PV generation cases through a real time digital simulator (RTDS) platform. In addition to the fast and accurate performance, the presented method benefits from the straightforward and communication-free structure as it solely exploits the point of common coupling (PCC) voltage. Also, the method's threshold does not require re- tuning after MG restructure, ensuring scalability. Without relying on other microgrid facilities, the proposed methodology is accordingly an effective solution for practical PV-based LV MGs.

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This paper presents the modular-multilevel-converter (MMC) control interoperability (IOP) and interaction within the High Voltage Direct Current (HVDC)-based power system. IOP is a crucial issue in the large-scale HVDC grid with different suppliers. To accommodate future multi-vendor HVDC grids developments, this article comprehensively investigates the MMC control IOP issue. Firstly, the most commonly adopted proportional-integral (PI) control and other non-linear controllers, e.g., model predictive control (MPC), back-stepping control (BSC), and sliding mode control (SMC), are constructed for MMC. Then, the IOP simulations are carried out in a multi-terminal direct current (MTDC) system in real-time digital simulator (RTDS) environment. The most frequent transients of the practical projects, e.g., power flow changing, wind speed changing, and DC/AC grid faults, are simulated with eight different scenarios. Each scenario presents different control capabilities in maintaining system stability, more precisely, the scenarios with non-linear controllers show faster settling time and fewer DC voltage and power variations. Controller switchings are also achieved without bringing large system oscillations. This paper provides the optimal allocation strategy of controllers to cope with system transients.@en