The reduction of system strength, driven by the integration of Power Electronic Interfaced Resources (PEIR), challenges Small-Signal Stability (SSS) in modern power systems. The deployment of Grid-Forming (GFM) control is widely recognized as a potential mitigation measure. This work proposes a stability-oriented methodology for the optimal placement and minimal sizing of GFM solutions. It introduces an iterative approach based on identifying system weak points using the Frequency Averaged Grid Impedance (FAGI) metric and evaluating stability via the novel Modal non-Passivity Index (MnPI), compatible with black-box models. The methodology determines critical GFM capacity thresholds, ensuring sufficient yet minimal GFM deployment. Time-domain simulations on a benchmark inspired by the northern French transmission system validate the effectiveness of the proposed approach across various scenarios, highlighting its adaptability to different deployment strategies and the evolution of system needs.

In this paper, a case study is presented to demonstrate the mechanism of overvoltage long-term instability in a simple test system subject to increased penetration of converter-interfaced generation with unity power factor. It is shown that due to the underexcitation limit of a synchronous generator, a local minimum of net power transfer may exist, below which local equilibrium is lost through a limit-induced bifurcation. In this case the system is attracted to a non-viable high-voltage solution possibly leading to a blackout. Countermeasures are discussed including load tap changer blocking and reactive power absorption by the electronic converter.

In this paper several mechanisms that can lead to overvoltage conditions with potentially catastrophic consequences are reviewed for both interconnected and isolated systems, in the long-term and short-term time frames. A distinction is made between the case of steady-state overvoltage due to loss of voltage control, and the occurrence of overvoltage instability that excites a dynamic sequence. Even though both cases may lead to successive trips, the case of overvoltage instability is much more difficult to predict and contain. Since the overvoltage is due to generator’s limited capability to absorb reactive power, the modeling of generator underexcitation limiter is also considered. For the case of autonomous system voltage instability it is shown that underfrequency load shedding will initiate an overvoltage and underfrequency collapse. Specific countermeasures involving load tap changer (LTC) blocking and converter contribution to reactive power absorption are also presented in the paper.

Abstract The increasing penetration of power‐electronics interfaced resources brings new challenges regarding the small‐signal stability of power systems. To address this issue, grid‐forming (GFM) controlled converters have emerged as an alternative to their conventional grid‐following counterparts. This paper investigates the mechanisms behind converters driven stability and quantifies the stabilizing effect of GFM controls. The linearized state‐space model of different combinations of control strategies is analysed in a multi‐infeed system considering various operating points. Through a parametric sensitivity study and an examination of the participation factors of key eigenvalues of the linearized models, it is confirmed that GFM controls contribute to system stabilization. Moreover, this paper demonstrates that this stabilizing effect varies significantly depending on the specific GFM control implemented: whether a current control loop is used or not notably impacts stability.

With the increasing penetration of power electronic converters in the power system induced by the energy transition, Grid Forming (GFM) technology emerges as crucial for complementing traditional synchronous generators in fulfilling system needs. All over the world, TSOs have started introducing performance-based requirements to define the desired behaviour of GFM units without prescribing specific technical solutions. Based on these specifications, manufacturers design their grid-connected equipment. However, depending on requirements, challenges may arise in optimizing control strategies without hardware modifications, potentially becoming cost-driving factors. Intellectual property protection limits information disclosure, restricting the guidance available to TSOs during cost-benefit assessments. Academic contributions on GFM control and generic models can bridge the gap, providing a fair portrayal of the general behaviour and then facilitates an open discussion on their ability to meet the requirements and contribute to fulfil system needs. This survey paper provides a comprehensive overview of the perspectives offered by these diverse stakeholders.

This paper investigates the mechanisms behind converters driven stability and the stabilizing effect of grid-forming control. The study is carried out by analyzing the linearized state space model of different combinations of controls in a multi-infeed system at various operating points. By conducting a parametric sensitivity study and analyzing the participation factors of key eigenvalues of the linearized models, it is confirmed that grid-forming controls bring a stabilizing effect to the system. Moreover, this paper will demonstrate that this effect varies significantly with the considered grid-forming control: whether a current control loop is used or not significantly impacts stability.

The validity of reported contributions of different grid-forming controls to small-signal stability is investigated for LCL-connected converters. A two-converter test setup is proposed to overcome the limits of the Thévenin equivalent setup. Simulation results confirm that voltage controlled grid-forming control provides a better stabilizing impact than its current controlled counterpart.

In many power systems, the increased penetration of inverter-based renewable generation will cause a decrease in kinetic energy storage, leading to higher frequency excursions after a power disturbance. This is the case of the future Nordic Power System (NPS). The look-ahead study reported in this paper shows that the chosen units participating in Frequency Containment Reserves (FCR) cannot keep the frequency above the prescribed threshold following the outage of the largest plant. This analysis relies on a detailed model of the Northern European grid. The latter is compared to the classical single-mass equivalent, and the impact of voltage-dependent loads is assessed in some detail. Next, the paper focuses on emergency power control of the HVDC links that connect the NPS to the rest of the European grid, which can supplement or even replace part of the FCR. The proper tuning of that control is discussed. Finally, the analysis is extended to the HVDC links connecting the future North Sea Wind Power Hub under two configurations, namely low and zero inertia. The impact of outages in the latter sub-system is also assessed. The material to simulate the system with industrial software is made publicly available.

This article provides a new take on the impact brought by Grid Forming (GFM) converters by showing that not all GFM converters improve the system stability with the same efficacy. It paper investigates the mechanisms behind converters driven stability and quantifies the stabilizing effect of grid-forming controls. The linearized state space model of different combinations of control strategies is analyzed in a multi-infeed system considering various operating points. Through a parametric sensitivity study and an examination of the participation factors of key eigenvalues of the linearized models, it is confirmed that grid-forming controls contribute to system stabilization. Moreover, this paper demonstrates that this stabilizing effect varies significantly depending on the specific grid-forming control implemented: whether a current control loop is used or not, notably impacts stability.

This paper proposes a new application for a Battery Energy Storage System (BESS) connected at the main substation of a distribution grid. It consists of controlling the BESS in such a way that the net active and reactive powers entering the distribution network matches as closely as possible the response of a dynamic equivalent model of the latter, used in large-disturbance dynamic simulations of the transmission system. Thus, the BESS compensates for the inevitable inaccuracies of the equivalent, which can be used with higher guarantee of accuracy. Its active and reactive powers are controlled without resorting to any model of that grid. Simulations results are reported on the CIGRE MV test system. Good performances are found in response to disturbances of various severities. The proposed approach would lead to a new service for the BESS, in addition to other purposes for which it has been installed.

As the inverter-based generation replaces the conventional synchronous generators, it may also need to fill in the missing ancillary service support. One of these ancillary services is dynamic reactive power provision and voltage control. This paper analyzes optimal strategy of reactive and active fault-current support of the inverter-based generation leading to fast voltage recovery of the system. For the purpose of the analysis, new ramping active current controller able to emulate different behavior of active current injection is proposed. By optimizing its parameters for different case studies of the system, the conclusions about optimal behavior of the inverter based generation with respect to system parameters and operating conditions are drawn. It is observed that the optimal combination of active and reactive fault-current is the most sensitive to the dynamic load component penetration levels in the system. With the increasing penetration levels, the significance of active fault-current injection increases. The results show that with higher penetration levels of dynamic load component in the heavy load areas, the ramping down of the inverter-based generation active fault-current results in slower voltage recovery of the system. Following this conclusion, a recommendation on update of current European grid codes is proposed.

This paper provides a general overview of some previously reported schemes for the on-line detection and corrective emergency control of long-term voltage instability in a power system with a significant share of Inverter-Based Generators (IBGs) connected at the distribution level. Next, it proceeds to introduce new wide-area emergency controls to avoid an imminent voltage instability. Reactive support from IBGs is utilized as part of voltage stability emergency control, while in normal operation IBGs are operating at unity power factor. Results are shown for the IEEE Nordic Test System with increased IBG penetration, through feeders adapted from Hellenic Interconnected System wind farms. The newly proposed wide-area controls are compared with existing local emergency control schemes and are shown to have superior performance.

In this paper, a reliable methodology is proposed in order to implement and validate a Model Predictive Control (MPC) scheme on an actual Voltage Source Converter (VSC) integrated in a scale-down multi-terminal DC grid. The objective of the investigated MPC controller is to enable AC frequency support among two asynchronous AC areas through a High Voltage Direct Current (HVDC) grid, while considering physical constraints, such as maximum and minimum DC voltage. A systematic and accurate implementation strategy is proposed, based mainly on the Hardware In the Loop (HIL) and Power Hardware In the Loop (PHIL), leading to the real-life testing on VSC, controlled by a classical microcontroller. The technical problems during the implementation process, as well as the proposed solutions, are described in detail through this paper. This procedure is deemed valuable to bridge the gap between offline simulation and the actual implementation of such advanced control scheme on experimental test rig.

Dynamic state estimation (DSE) accurately tracks the dynamics of a power system and provides the evolution of the system state in real-time. This paper focuses on the control and protection applications of DSE, comprehensively presenting different facets of control and protection challenges arising in modern power systems. It is demonstrated how these challenges are effectively addressed with DSE-enabled solutions. As precursors to these solutions, reformulation of DSE considering both synchrophasor and sampled value measurements and comprehensive comparisons of DSE and observers have been presented. The usefulness and necessity of DSE based solutions in ensuring system stability, reliable protection and security, and resilience by revamping of control and protection methods are shown through examples, practical applications, and suggestions for further development.

The analysis of the frequency response of integrated transmission-distribution networks with deep penetration of solar photovoltaic (PV) generation faces major challenges due to the complexity emerging from the dynamic models of the numerous and diverse PV units involved. This article proposes converter-based dynamic equivalent models for both distributed (distribution network-connected) and large-scale (transmission network-connected) PV units, which take into account practical issues, such as measurement and coordination delays. Different from the previous work that adopted an open-loop identification, the unknown model parameters are identified here through a novel closed-loop identification process based on the least-square minimization. This allows capturing the continuous interaction between system and PV responses, thus improving the outcome of the overall frequency response model. The proposed models are validated with the real data from the August 2018 separation event in Australia. The results demonstrate the excellent performance of the proposed models in determining the frequency response from PV in both transmission and distribution networks, hence paving the way to its adoption in the frequency stability analysis in low-carbon grids dominated by frequency-responsive renewables.

Non-negligible amounts of Distributed Generating Units (DGUs) are already connected to power systems, predominantly to medium- and low-voltage networks. The interaction between distribution and transmission systems is gaining the attention of system operators. Given the high controlability of DGUs, the active distribution networks can potentially support the transmission system during emergency situations. Previously proposed voltage emergency controls involving distribution network assets focused on preserving the transmission system integrity, even if it implies affecting the distribution system operation (intrusive schemes). More attention needs to be devoted to supporting transmission voltages, while preserving the distribution network operation (non-intrusive schemes). This paper introduces a new adaptive and non-intrusive voltage emergency control scheme based on the synchronization of DGUs and the load tap changer of the corresponding distribution transformer. The conclusions are derived from time-domain simulations using an extended version of the IEEE Nordic test system for voltage stability assessment.

This report of TF on dynamic state and parameter estimation aims to 1) clearly review its motivations and definitions, demonstrate its values for enhanced power system modeling, monitoring, operation, control and protection as well as power engineering education; 2) provide recommendations to vendors, national labs, utilities and ISOs on the use of dynamic state estimator for enhancement of the reliability, security, and resiliency of electric power systems.

This paper deals with the derivation of dynamic equivalents of active distribution networks, hosting inverter-based generators as well as static and motor loads. Equivalents are reduced-order models for use in dynamic simulations of the transmission system. They are of the grey-box types and their parameters are identified from large-disturbance Monte-Carlo simulations accounting for model uncertainty. After presenting an overview of the identification method at a single operating point, the paper deals with the update the equivalent when the operating conditions of the distribution network change. A procedure identifies the parameters to update, hence avoiding a complete new identification. Besides illustrative examples, two sets of simulation results are reported. First, the accuracy of the equivalent is validated in a long-term voltage instability scenario. Second, a larger-scale application is presented, with numerous instances of the equivalent attached to the model of the IEEE Nordic transmission test system. This combined model is used to assess the impact on short- and long-term voltage stability of the inverter-based generators with fast and slow controls.

Analysis of the frequency response of integrated transmission-distribution networks with deep penetration of solar photovoltaic (PV) generation faces major challenges due to the complexity emerging from dynamic models of the numerous and diverse PV units involved. This work proposes converterbased dynamic equivalent models for both distributed (distribution network-connected) and large-scale (transmission network-connected) PV units which take into account practical issues such as measurement and coordination delays. Differently from previous work that adopted open-loop identification, the unknown model parameters are identified here through a novel closed-loop identification process based on least-square minimization. This allows capturing the continuous interaction between system and PV responses, thus improving the outcome of the overall frequency response model. The proposed models are validated with real data from the August 2018 separation event in Australia. The results demonstrate the excellent performance of the proposed models in determining the frequency response from PV in both transmission and distribution networks, hence paving the way to its adoption in frequency stability analysis in lowcarbon grids dominated by frequency-responsive renewables.

Since the publication of the original paper on power system stability definitions in 2004, the dynamic behavior of power systems has gradually changed due to the increasing penetration of converter interfaced generation technologies, loads, and transmission devices.In recognition of this change, a Task Force was established in 2016 to re-examine and extend, where appropriate, the classic definitions and classifications of the basic stability terms to incorporate the effects of fast-response power electronic devices.This paper based on an IEEE PES report summarizes the major results of the work of the Task Force and presents extended definitions and classification of power system stability.