The growing penetration of renewable energy resources such as wind and solar into the electric power grid has changed grid dynamics. Particularly, the large-scale displacement of synchronous generators with inverter-based resources significantly reduces the short-circuit strength and thus increases the risk of the small-disturbance stability issues, such as sub/super-synchronous oscillation issues, resulting from fast-acting inverter controls and the power network. It is challenging to assess grid strength in terms of small-disturbance stability in power systems in high penetration level of inverter-based resources due to the complex interaction between power networks and different inverter control configurations such as grid-forming and grid-following inverters. It becomes more challenging for the 100% inverter-based power system, where all synchronous generators are displaced with inverter-based apparatus. In such a power system, the commonly used methods for grid strength assessment are invalid due to their assumption that synchronous generators are used to provide voltage support for grid strength assessment. To address the challenges, this paper presents a method for assessing grid strength in terms of small-disturbance stability in a 100% inverter-based power system. First, we reveal voltage support characteristics of grid-forming inverters. Then, we further analyze the small-disturbance stability of a multi-inverter system of grid-forming and grid-following inverters. On this foundation, a method is proposed by extending our previously developed generalized short-circuit ratio to assess grid strength in terms of the small-disturbance stability of the 100% inverter-based power system while considering the complex interaction between grid-forming and grid-following inverters coupled by the power network. The efficacy of the proposed method is demonstrated on a modified two-area-four-machine system and a modified IEEE 39-bus system via the eigenvalue analysis and electromagnetic transient simulation.

The high penetration of converter-based renewables (CBRs) is challenging the stability and security of modern power systems, e.g., power balance, due to the fast fluctuation of renewables. Storage energies (SEs) are good choices for addressing the power balance issues, due to their flexibility of bi-directional power regulation. However, the bi-directional power regulation of SEs increases the complexity and difficulty for analyzing the CBRinduced small-signal stability issues in a multi-CBR system, which is one kind of key stability issues in modern power systems, especially in weak grids. It has not been theoretically revealed how the placement of SEs influences the CBR-induced small-signal stability issues, when the SEs absorb active power from grids. This paper aims to fill this gap. Based on modal decomposition theory, this paper explicitly demonstrates that the placement of SEs (when absorbing active power from grids) is equivalent to increasing the grid strength and thus enhancing the CBR-induced small-signal stability. Moreover, this paper investigates the optimal placement of SEs for effectively improving the small-signal stability by using a grid-strength-evaluation indicator, named as generalized shortcircuit ratio (gSCR). Finally, the analysis in this paper is validated based on a modified 39-bus test system.

Inertia assessment is an important step for frequency stability analysis in power systems. Typically, the total inertia of all devices in the system is summed up to obtain the system inertia. However, such method may be optimistic when there are a considerable number of converter-interfaced generations (CIGs). Particularly, if the CIGs saturate under large disturbances, their inertia to be provided will be significantly reduced. To this end, this letter proposes a method to assess the system inertia considering the power limits. Then, the distribution of system inertia under uncertain power limits is also analyzed. Simulations are conducted to validate the analysis.

Synchronous Condensers (SynCons) are widely used in the voltage source converter (VSC) integrated weak grid for voltage support and oscillation suppression. Whereas recent research suggests that the SynCon may accelerate and lose transient rotor angle stability due to the excessive active power injected by nearby VSCs during metallic faults. However, the transient stability of the SynCon cannot be guaranteed even if it decelerates during non-metallic faults. To reveal this phenomenon, the transient stability of SynCon during non-metallic faults is investigated in this paper. After deriving power-angle characteristics in different operating conditions, a novel transient instability mechanism is discovered, and the effect of the system parameters is analyzed based on the Equal Area Criterion (EAC). It reveals that inertia, excitation, VSC size, and voltage support during FRT all contribute to such transient instability. To mitigate unbalanced active power during faults and improve transient stability, an adaptive fault ride-through (FRT) strategy is proposed. The electromagnetic transient (EMT) simulations based on the PSCAD/EMTDC are carried out to validate the effectiveness of the theoretical analysis and the proposed adaptive control strategy.

High penetration of renewable energy resources is widely connected to the grid via grid-following converters, which may threaten the transient voltage stability of the system. However, most researchers only pay attention to the transient voltage stability of inductive motors in the electromechanical transient time scale, and the electromagnetic dynamics of voltage source converters (VSCs) are ignored for simplicity. Therefore, the potential transient voltage instability risk of the system in the electromagnetic transient time scale is concealed. To fill this gap, the transient voltage instability mechanisms for grid-following VSCs with various control strategies are revealed, which can be concluded that the positive-feedback process after the state variable exceeds the unstable equilibrium point is the main cause. Then, the effect of the current limitation of VSCs on the transient voltage stability and transient performance of the system is theoretically illustrated. On this basis, the indexes for transient voltage stability margin considering the active power recovery process are presented, and a robust current limitation based stability enhancement scheme is proposed to stabilize the system. Simulation results verify the correctness of the theoretical analysis and the effectiveness of the proposed control strategies.

The increasing penetration of converter-interfaced generators (CIGs) in power systems has posed great challenges in frequency stability analysis, as the frequency dynamics of CIGs may be strongly coupled with voltage dynamics. However, existing analytical models for system frequency generally cannot precisely account for the impact of voltage dynamics, leading to potentially incorrect results. The main challenge here is how to understand system frequency in the case of non-constant bus voltages, and how to integrate the voltage dynamics of devices at different bus locations into the system frequency model. To address this issue, this article defines the voltage-influenced common-mode frequency (VCMF), serving as a system frequency analysis model considering voltage dynamics. The VCMF is derived through the decomposition of bus frequency responses, leveraging the connection between the consistent part of bus frequencies and the rotational invariance of power flow. The decomposition process introduces voltage dynamics of devices into the system frequency response, represented as a global term that interconnects all devices through the power network. To address the complexity of this global term, an algebraic graph theory-based network partitioning method is introduced. This method effectively divides the globally coupled term into several locally coupled components, making the analysis of the VCMF more manageable. Finally, simulations are used to validate the proposed methods and confirm their validity.

Deployment of Synchronous Condensers (SynCons) has become one popular solution in accommodating large-scale renewable energy resource (RER) for existing power systems. In  this paper, rotor angle instability of SynCon is investigated. To  derive intuitive understandings and quantitative analysis, the  swing equations of the equivalent synchronous generators (ESG)  are derived. The Lyapunov’s direct method is employed to analyze  the attraction domain for a typical benchmark system. Based on  that, a rotor angle stability margin index is developed and an  adaptive low voltage ride through (LVRT) control strategy is  proposed for assessment and enhancement of rotor angle stability.  The criterion and effectiveness are verified with on EMT  simulations, respectively.

The ever-increasing adoption of power electronic converters for renewable integration and energy-saving applications has weaken grid and caused new types of small-signal stability issues, such as sub-/super-synchronous oscillations, resulting from the interaction between the fast-acting converter control and the power network. It is challenging to analyze the small-signal stability issues by grid strength assessment due to the complex interaction between many converter-interfaced generators (CIGs) and the power network in a multi-CIG system (MCIGS). This complexity is further increased when considering different non-rated operating conditions of each CIG, such as their actual power injections and terminal voltages, which manifest the heterogeneity in the MCIGS. Moreover, in such a heterogeneous MCIGS, it is difficult to characterize the small-signal stability boundary under non-rated operating conditions. To address the challenges, this paper derives generalized operational short-circuit ratio (gOSCR) and critical gOSCR (i.e., CgOSCR) by the small-signal stability analysis in such a heterogeneous MCIGS. Based on gOSCR and CgOSCR, a method is proposed for grid strength assessment to identify the small-signal stability issues in such a heterogeneous MCIGS. This proposed method can be used when CIGs are modeled by either black-box or white-box modeling in a MCIGS under non-rated operating conditions. More importantly, the proposed method can also be used to assess grid strength in terms of the static voltage stability in a MCIGS under non-rated operating conditions, since the static voltage stability issue is a special case of the small-signal stability issue with focus on zero frequency band for converter controls. The efficacy of the proposed method is demonstrated in the IEEE 39-bus system and a practical power system with a large-scale renewable integration.

Temporary overvoltage (TOV) is becoming one challenge for the integration of significant power electronics resources into a power system. To assess the risk of TOV in a Multi-Infeed Power Electronic System (MIPES), a worst-case estimation approach is proposed to assess TOV risk. The paper starts with analyzing the mechanism of TOV, which reveals that TOV is dominated by excessive reactive power resulting from control lagging of converters. Then, the principle of approximating the TOV for a Voltage Source Converter (VSC) connecting to an infinite bus is introduced within the context of the RMS model. After that, a methodology based on the concept of generalized short-circuit ratio for overvoltage (gSCR-TOV) is introduced to quantify the risk of TOV in a multi-bus system. The intent of this concept is to permit screening to identify those nodes at greatest need for further EMT assessment. To localize these nodes, a concept of weighted sensitivity matrix is further proposed to pinpoint the bus subject to highest TOV in a MIPES. Finally, case studies of EMT time-domain simulations are carried out and verifies the effectiveness of the proposed methodologies.

The modern power gird is being transformed into a multiple converter system (MCS) driven by the increasing integration of converter-based resources (CBRs) such as wind and solar. In such an MCS, the dynamic interaction between converter controls and the power network may cause the small-signal stability issues. While static var generators (SVGs) are integrated into the MCS for providing voltage support, they may affect the small-signal stability. To understand the impact of SVGs, this paper investigates the small-signal stability of the MCS with SVGs. By constructing an equivalent model, the theoretical analysis finds two key factors affecting the small-signal stability when SVGs are connected to the MCS: 1) the topology and parameters of the power network interconnecting SVGs and CBRs; 2) the dynamic interaction between the SVGs and CBRs. Based on the results, a computationally efficient method is proposed to assess the small-signal stability of the MCS with SVGs. The analysis results and the proposed method are validated through eigenvalue analysis, and electromagnetic transient simulation.

While renewable resources are increasingly integrated into the electric power grid, the small-signal instability risk may be induced by grid-following converters using phase-locked loops (PLLs) for grid synchronization, especially under weak grid conditions. The analysis of the instability mechanism is complex in a multi-converter system due to the dynamic interaction between PLL-based converters and the power network. The analysis complexity is further increased in a heterogeneous multi-converter system (HMCS), where all converters have different control configurations and parameters from different manufacturers. To understand how the different PLL dynamics collectively affect the stability of the HMCS, this paper analytically derives the small-signal stability boundary condition of the HMCS dominated by the PLL dynamics (HMCS-DPLL). The derived stability boundary allows us to obtain analytical results about how the stability of the HMCS-DPLL is affected by grid strength, converter operating conditions, different PLL control parameters and the interaction among different PLLs. Based on the stability boundary condition, a computationally efficient method is also proposed to identify the design rationality of PLL control parameters as well as the small-signal stability and stability margin of the HMCS-DPLL. The analytical results and proposed method are validated by modal analysis and electromagnetic transient simulation with detailed models on a 9-converter heterogeneous system.

The increasing penetration of renewable resources into the power network through grid-following converters has increased the risks of oscillation instability. In such a power system, it is challenging for assessing the small-signal stability due to the complex interaction among converters interconnected through the power network. Moreover, the assessment complexity is further increased in a heterogeneous multi-converter system, where the interconnected converters have different control configurations or parameters from different manufacturers. To tackle the challenges, this paper proposes a method for the small-signal stability analysis of a heterogeneous multi-converter system. To this end, it is first theoretically proved that the small-signal stability of a heterogeneous system can be characterized by an equivalent homogeneous one, where all interconnected converters have the same control configurations and parameters. This can reduce the complexity of the small-signal stability assessment of the original heterogeneous system by decoupling the equivalent homogeneous system into a set of subsystems. To further reduce the assessment complexity, it is derived that the small-signal stability and stability margin of the heterogeneous system can be estimated based on the smallest eigenvalue of a weighted Laplacian matrix of the power network. Based on the analysis results, a scalable method is developed for assessing the small-signal stability of heterogeneous multi-converter systems. The efficacy of the proposed method is validated by performing both modal analysis and time-domain simulations on two heterogeneous multiple-converter systems with different network sizes and converter numbers.