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Reactive power management (RPM) in electric power systems is usually based on a rule‐based control derived from the transmission system operator's (TSO) experience. This approach faces challenges as the number of decisions and the complexity of the system operation is increasing. With the increasing generation from renewables and the evolution of electricity markets, the available resources must be optimally utilized. This paper compares the optimization‐based approach (OBA) and the experience‐based expert approach (EBA) for RPM. The OBA is based on security‐constrained optimization with minimum redispatch cost as the objective function for a reference contingency. In contrast, the EBA's actions are based on the system operator's experience. Comparison is made in terms of the generator redispatch cost, active and reactive power redispatch volume, active power losses, nodal voltages, and the number of actions to ensure secure operation. The analysis using a reduced model of an actual transmission system shows that OBA is more beneficial than EBA, with up to 22% and 42% reduction in redispatch cost and volume, respectively. Moreover, the control decisions from both approaches are seen to be similar. This study aims to show the usefulness of the OBA and motivate TSOs to move towards optimization‐based reactive power management. [ABSTRACT FROM AUTHOR]

With the increased penetration of wind generation in power systems, there is a rising interest in the provision of frequency regulation by wind turbines in order to relieve the burden on remaining conventional generation units. As a first step, the possible contribution of wind power to frequency regulation by optimally anticipating load imbalances in the power system is investigated. This ability is studied by implementing a receding horizon control which takes future load and wind variations into account. In this way, the available energy reserves of the wind turbine over a certain time horizon are optimally exploited to damp frequency oscillations while keeping the energy losses within defined limits. Results indicate that the receding horizon controller will mainly damp overfrequencies as its upward regulation capability is restricted to the available kinetic energy in the turbines. Moreover, it is shown that load forecast errors only slightly influence the results as the controller iteratively determines the optimal trajectory. Even if no load forecast is available, the proposed controller is still capable of damping frequency variations resulting from the simulated load profile by 25%, while keeping the energy yield above 97% compared to optimal power point tracking. [ABSTRACT FROM AUTHOR]

The inertia of today׳s power system decreases as more and more converter connected generation units and load are integrated in the power system. This results in a power system which behaves differently from before which causes concerns for many grid operators. Therefore, a detailed study is needed to investigate the relevance of this inertia in the operation, control and stability of the system. Moreover, a new definition of the term system inertia is necessary since is it expected that in the future also the renewable electricity generation units will deliver the so-called virtual (synthetic) inertia. In this paper a review of the research related to inertia in a power system is given. Both the challenges as the solutions from an operator point of view to control a system with low inertia are discussed. Also a new definition of inertia is proposed to incorporate the different forms of inertia which are each described in more detail. From recent studies, it can be concluded that the influence of reduced inertia on frequency stability is generally considered as the main challenge for system operators, but with the additional measures listed in this paper, this impact can be mitigated. [ABSTRACT FROM AUTHOR]

An electrical power system is intended to transmit power from generation to load. To do so, it needs ancillary services to guarantee a certain level of reliability and quality. With the emergence of DC grids, it becomes necessary to ask what ancillary services they may themselves require, and how DC grids should be required to interact with the remainder of the system. This study defines a first basic set of ancillary services for High Voltage Direct Current (HVDC) grids which did not exist so far, and it shows that this development could affect the ancillary services in AC grids. This study describes how the origin of ancillary services can change if an HVDC grid is added to the existing AC grids and gives an overview of existing definitions for ancillary services. [ABSTRACT FROM AUTHOR]

This paper presents a quantitative method to determine delay requirements of the information and communication technology (ICT) system supporting wide-area power oscillation damping (WAPOD) controllers. An allowable time delay for the ICT infrastructure named “equivalent time delay (ETD)” is defined. The ETD is calculated by numerically comparing the damping behavior of the system when local input signals (LI) and remote input signals (RI) are used in the damping controller. The use of a WAPOD is only justified when its response outperforms that of a controller using local inputs. Therefore, the total time delay in the control loop must be below the calculated ETD. As such, the ETD serves as a design criteria to determine ICT latency requirements. The selection of an effective RI signal can be carried out by considering the maximum delays (ETDs) of different wide-area measurements. A damping improvement ETD^x~\% has been proposed using the same methodology indicating a minimum outperformance of the remote signals. The proposed method is demonstrated using the well-known Klein-Rogers-Kundur multi-machine power system and the Vietnamese power system model. [ABSTRACT FROM PUBLISHER]

In Europe, significant amount of interconnection capacity investments are expected in the next decades. However, the risks associated with transmission network investment in the cross-border context are rarely discussed. In this paper, we develop a conceptual framework to assess the cross-border transmission network investment risks from the third party investor perspective. Risks are examined in relation to cost benefit perceptions in different phases of projects to shed lights of the dynamics in the life cycle of the project. The risk framework also takes into account the energy governance at different institutional level to characterize the uncertainties from cross-border coordination. The proposed risk framework is applied to the European case study. [ABSTRACT FROM AUTHOR]

Highlights • Fairness is essential for the social acceptability of power system decisions. • Widely studied economic tools are useful to assess fairness of service reliability. • Proposed generic indices can quantify overall and individual equality and equity. • Proposed indices outperform currently used variance and standard deviation. • Proposed Gini-based indices facilitate interpretation via a bounded zero-one scale. Abstract As the power system is undergoing major changes that affect different stakeholders unequally, power system literature increasingly recognizes the importance of fairness. This paper focuses specifically on the concept and quantification of fairness in the context of power system reliability. Power system decisions not only affect the overall, system reliability level, but also the reliability level for individual end-users, such as generators, flexibility providers and end-consumers, depending on their location and characteristics. We analyze and propose Gini-based and variance-based fairness indices. The proposed indices summarize the inequality and inequity of the distribution of reliability between different entities in power systems in a single number, which is a measure of the perceived fairness of the reliability level. These indices allow decision makers to assess the effect of power system decisions on fairness of reliability, to track it over time and to take appropriate actions to decrease unfairness. This will help to ensure the social acceptability of power system decisions. The use of the fairness indices is illustrated using two case studies: real reliability data and system development. [ABSTRACT FROM AUTHOR]