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Due to the increasing number of power electronics-based devices in modern power systems, there are concerns about the impact of higher-frequency interactions on system stability. The typically-used algebraic representation of networks fails to capture these newly emergent issues, but dynamically modelling the entire network with differential equations will lead to a prohibitively long simulation time. This paper proposes a computationally-efficient analysis framework to determine the system loadability in power electronics-rich, large networks with the consideration of multiple types of stabilities. The framework developed in this paper identifies the critical network elements based on the eigenvalue sensitivity in order to exploit a hybrid modelling approach. Within the hybrid model, only the critical network portion is modelled dynamically with the rest of the network represented by algebraic equations. Bifurcation theory is used to simultaneously analyze both small-disturbance rotor angle and small-disturbance voltage stability. The results obtained show that the high-frequency interactions are accurately captured with the proposed framework. Additionally, applying this methodology results in a small dimension for the system matrix and a reduction in the computational burden. Two test networks, a three-bus system and the IEEE 39-bus system, are used to illustrate and verify the analysis framework.

Security and transient stability (TS) constrained OPFs do not include network switching and often require excessive computation time due to discretization of the TS model. This paper proposes a non-simulation methodology to optimize active power dispatching and network switching to ensure TS and system security in the preventive control mode. Network switching is introduced in the security constrained OPF and classical TS models, giving a general dynamic security and TS constrained OPF. To ensure TS constraints are manageable in the optimization framework, TS is assessed by using proposed non-simulation based proxy measures. To this end, the key factors impacting TS are investigated and new composite robustness metrics for TS assessment are proposed; they consist of two terms, the nodal and network topology metrics. The former models generator features just before a fault, whilst the second considers impact of a fault on units. The general problem is then decomposed into two stages, the first being economic dispatching and the second optimization of network topology for TS via developed network robustness metrics. The minimum cost topology solutions are ranked by the TS performance. The proposed approach is tested on the IEEE68 Bus test system and compared with time-domain TS results.

Security concerns have been raised about cascading failure risks in evolving power grids. This article reveals, for the first time, that the risk of cascading failures can be increased at low network demand levels when considering security-constrained generation dispatch. This occurs because critical transmission corridors become very highly loaded due to the presence of centralized generation dispatch, e.g., large thermal plants far from demand centers. This increased cascading risk is revealed in this work by incorporating security-constrained generation dispatch into the risk assessment and mitigation of cascading failures. A security-constrained AC optimal power flow, which considers economic functions and security constraints (e.g., network constraints, $N - 1$ security, and generation margin), is used to provide a representative day-ahead operational plan. Cascading failures are simulated using two simulators, a quasi-steady state DC power flow model, and a dynamic model incorporating all frequency-related dynamics, to allow for result comparison and verification. The risk assessment procedure is illustrated using synthetic networks of 200 and 2,000 buses. Further, a novel preventive mitigation measure is proposed to first identify critical lines, whose failures are likely to trigger cascading failures, and then to limit power flow through these critical lines during dispatch. Results show that shifting power equivalent to 1% of total demand from critical lines to other lines can reduce cascading risk by up to 80%.

It is anticipated that a large number of voltage source converters (VSCs) will be integrated into future power systems, which can potentially be detrimental to system stability. Previous work has utilized an impedance-based approach to analyze the feasibility region boundaries of power systems with multiple VSCs. However, impedance-based modeling limits the analysis of the system feasibility region to just two or three dimensions. Hence, this paper develops a methodology based on bifurcation theory that enables the system multi-dimensional feasibility region to be identified efficiently with consideration of multiple different varying parameters. The developed methodology is generalized so that it can be applied to identify system feasibility region boundaries in other power systems with multiple varying parameters. The partial Spearman correlation coefficient is adopted in this paper to identify the key parameters that affect the feasibility region boundary. Additionally, the calculated correlation indices quantify the interactions between the control loops VSCs in the system. The proposed methodology is verified against other analytical methods and the impact of key parameter variation on the system feasibility region boundaries is discussed.