Many wide area monitoring, protection, and control (WAMPAC) systems are being deployed by grid operators to deal with critical operational conditions that may occur in power systems. Thanks to the real-time measurements provided by a set of distributed phasor measurement units (PMUs), different protection algorithms can be run in a central location. In this context, this article presents and validates a novel method that can be used as a backup protection for a selected area in a power system. It merges the integrated impedance angle (IIA) protection method with the theory of virtual buses in wide area electrical power systems. The backup protection works this way: once a fault is detected (pickup time), another delay (added to the pickup time) is defined in order to wait for the primary protection to act. If this does not happen, the algorithm generates its backup trip. The proposed method has been called the zone integrated impedance angle (Zone IIA). A real-time PMU laboratory has been used to test the proposed algorithm using a real-time digital simulator (RTDS). The algorithm has been programmed in a real-time automation controller (RTAC). It has been tested in two different simulated setups: first, a 400 kV transmission system, with and without the use of renewable energy sources (RES); second, a 150 kV submarine line between the Greece mainland and an island, which is currently the longest submarine alternating current connection in the world. The results obtained during the tests have yielded tripping times for area protection in the order of 48 ms, if no time delay is used between the fault detection and the trip order. According to the test results, the proposed method is stable, reliable, obedient, and secure, also with RES installed in the power system. Additionally, the method is selective, i.e., during the tests no trip was executed for external faults, no trip was executed in no-fault condition, and all the applied internal faults were detected and tripped correctly. Finally, the protection method is easy to implement. The method is also applicable to protection against short circuits in distribution systems. According to the trip times observed during the tests, it is clear that these algorithms are well suited to implement backup protections in transmission grids, even in scenarios with high penetration of renewable energies. Considering that backup trip times in transmission grids are usually set between 400 and 1000 ms, and that the actuation times obtained by the proposed algorithm are under 100 ms, the method is suitable for its use as a backup protection.

Renewable power is expected to increase drastically in the coming years due to the energy transition. A large part of the newly installed generators will be connected to the power system through inverters and electronic converters, whose behaviour differs from the generators connected synchronously to the network. One of the main differences is the current contribution during symmetrical and asymmetrical faults which can affect protection systems. New grid codes establish requirements for fast current injection, but the converter’s maximum current limitations during faults make it difficult to establish control strategies for such current contribution. This paper studies the performance of faulted phase selector algorithm of a commercial relay under the current contribution from renewables before unbalanced faults. Two positive and negative sequence current injection strategies in compliance with new Spanish grid code requirements are proposed and tested under fault conditions in HiL (Hardware in the Loop). Test results show that the selected injection strategy affects the fault phase identification algorithm. Furthermore, the negative sequence injection requirements established in the new grid code improve the relay performance when line-to-line faults are applied, but they are not enough to identify all fault types.

The IEC 61850 standard has brought new opportunities for developing Centralized Substation Protection and Control (CPC) platforms to be used in digital substations. The CPC operation requires a proper signal processing module that provides the necessary parameters and signals accurately and at times needed to ensure the platform’s control and protection services can operate correctly. This paper proposes and implements a sampled values-analog processing module (SV-APM) for a software-based CPC in a digital substation developed in the framework of the EPICS project. The SV-APM decodes the digital messages published by merging units and extracts the information required by control and protection functions implemented in a software-based CPC platform. To check SV-APM performance, a set of tests is carried out using Real-time digital simulator (RTDS) and EPICS platform in Hardware in the Loop configuration (HiL). These tests evaluate SV-APM behavior against disturbances in communication channels, voltage and current variations, harmonic contents and frequency variations. Furthermore, latency tests are carried out to evaluate CPC response times. From tests, it is concluded that SV-APM output satisfactorily fulfills all the time response and accuracy requirements demanded during its development.

The growing integration of renewable-based distributed energy resources within local energy communities is significantly reshaping the operational dynamics of medium voltage distribution networks, particularly affecting their reliability and protection schemes. This work investigates the technical impacts of the high penetration of distributed generation within sustainable local energy communities on the effectiveness of fault detection, location, isolation, and service restoration processes, from the point of view of Distribution System Operators. From a supply continuity perspective, the methodology of the present work comprises a comprehensive, quantitative, system-level assessment based on probabilistic, scenario-based simulations of fault events on a CIGRE benchmark distribution network. The models incorporate component fault rates and repair times derived from EPRI databases and compute standard IEEE indices over a one-year horizon, considering manual, hybrid, and fully automated operation scenarios. The results highlight the significant potential of automation to enhance supply continuity. However, the qualitative assessment carried out through laboratory-based Hardware-in-the-Loop tests reveals critical vulnerabilities in fault-detection devices, particularly when inverter-based distributed generation units contribute to fault currents. Consequently, quantitative evaluations based on a sensitivity analysis incorporating these findings, varying the reliability of fault-detection systems, indicate that the reliability improvements expected from increased automation levels are significantly deteriorated if protection malfunctions occur due to fault current contributions from distributed generation. These results underscore the need for the evolution of protection technologies in medium voltage networks to ensure reliability under future scenarios characterised by high shares of distributed energy resources and local energy communities.