Sahar Pirooz Azad

Protection of High Voltage Direct Current (HVDC) grids is a crucial step that requires further advancements to ensure the secure integration of green renewable energy sources (RESs). This paper proposes a fast, reliable, and selective singleended primary protection scheme for multi-terminal HVDC grids. In the proposed scheme, Hilbert-Huang Transform (HHT) is applied to local voltage measurements to extract the instantaneous frequency and energy features. Abrupt changes in these features during internal faults are detected as outliers. Simultaneous outliers in the extracted features correspond to internal faults, which offers a setting-less fault detection criterion; thus, eliminating the need for simulation-based and grid-specific thresholds. The proposed scheme can detect internal faults with high fault resistances up to 1000 Ω within 1 ms. In addition, the proposed scheme can reliably distinguish between internal and external faults even when the boundary reactor size is as small as 10 mH. A four-terminal HVDC grid is simulated in PSCAD/EMTDC software, and various fault scenarios are investigated to verify the effectiveness of the proposed scheme in detecting and discriminating between internal and external faults under severe fault conditions.

Breaker failure backup protection schemes are essential for the reliable operation of high voltage direct current (HVDC) grids and to prevent damages to power system equipment due to sustained faults. This paper proposes a rapid, reliable, and setting-less breaker failure backup protection scheme for multi-terminal HVDC grids. The proposed scheme employs Hilbert-Huang Transform (HHT) to extract two features from local voltage measurements, namely the instantaneous frequency and energy. Based on detected outliers in the extracted instantaneous features, breaker failure events are rapidly detected. The proposed setting-less outlier-based criterion can be applied to HVDC grids with various configurations, parameters, and breaker technologies. The proposed scheme depends only on local voltage measurements to detect breaker failure events within 1 ms from the intended breaker trip time without requiring breaker voltage or current measurements. In addition, the proposed scheme can successfully detect breaker failure events during high-resistance faults (1500 Ω) and in grids with small boundary reactors (10 mH). Numerous simulations in PSCAD/EMTDC software environment for a four-terminal HVDC grid are executed to demonstrate the rapid and reliable performance of the proposed breaker failure backup protection scheme under severe fault conditions

The large integration of inverter-based resources will significantly alter grid dynamics, leading to pronounced stability challenges due to fundamental disparities between inverter-based and traditional energy systems. While grid-following inverters (GFLIs) dominate current inverter configurations, their increased penetration into the grid can result in major stability issues. In contrast, grid-forming inverters (GFMIs) excel over GFLIs by offering features like standalone operation, frequency support, and adaptability in weak grid scenarios. GFMIs, unlike GFLIs, control the AC voltage and frequency at the common coupling point, impacting the inverter dynamic response to grid disturbances and overall stability. Despite the existing literature highlighting differences between GFLIs and GFMIs and their control strategies, a comprehensive review of GFMIs’ stability and the effects of their control schemes on grid stability is lacking. This paper provides an in-depth evaluation of GFMIs’ stability, considering various control schemes and their dynamics. It also explores different types of power system stability, introduces new stability concepts that correspond to power grids with integrated inverters, i.e., resonance and converter-driven stability, and reviews small-signal and transient stability analyses, which are the main two types of GFMI stability studied in the literature. The paper further assesses existing studies on GFMI stability, pinpointing research gaps for future investigations.

The formation of hybrid alternating current (AC)-(DC) direct current systems from converters built by different manufacturers has attracted considerable attention in recent years. In multi-vendor AC-DC systems, the converter stations and their controllers are designed independently due to confidentiality requirements. If the converters have a physical connection at their AC side, unforeseen interactions among adjacent converters may disrupt stability and alter the dynamic performance of the converters from that intended by their designers. This paper contributes to seamlessly integrating converters with independently designed controllers into a multi-VSC (voltage-sourced converter) system. An $H_\infty$ control problem is defined to design two supplementary filters (SFs) per converter, one for the direct (d)-axis and one for the quadrature (q)-axis control loop, to simultaneously stabilize the multi-VSC system and minimize the perturbation of the dynamic response of the interconnected converters from the vendors' designed dynamic behavior. Adding the SFs to the control system of converters will not cause new disruptive interactions, because the coupling dynamics among the converters are considered in designing the SFs. It is also analytically shown that employing the proposed SFs increases the robust stability margin of the multi-VSC system. Various studies based on the nonlinear model of a 2-VSC system verify the effectiveness of the presented method in integrating independently designed converters into a multi-VSC system.

This article presents an adaptable method for fault current derivative calculation in high voltage direct current (HVDC) grids composed of modular multilevel converters (MMCs). The proposed method can be used for current derivative calculation under different fault scenarios including pole-to-pole, pole-to-ground, and pole-to-metallic. The proposed method is adaptable as it can provide accurate fault current derivatives in various grid topologies such as symmetric monopole, asymmetric monopole with ground or metallic return, and bipole with ground or metallic return, as well as grids with different types of converters with and without fault-blocking capability including full-bridge MMCs (FB-MMCs), half-bridge MMCs (HB-MMCs), or a mix of HB- and FB-MMCs. The article also demonstrates how the proposed current derivative calculation method can be used to form a derivative relay, which is fast, selective, computationally efficient, and insensitive to fault resistance. Furthermore, using the proposed current derivative calculation method, all relay settings are analytically calculated instead of being obtained through time-consuming simulation studies. Simulation results for various fault scenarios, grid topologies, and converter configurations show that the calculation method is accurate and the presented relaying algorithm can detect various faults within 10 $\mu$ s, even when the fault resistance is as high as 500 $\Omega$ .

Integration of converter‐interfaced renewable energy sources (RESs) into the power system and the transfer of power from RESs to remote load centres over high‐voltage direct current (HVDC) lines may require connecting multiple voltage‐sourced converters (VSCs) to a common alternating current (AC) system. Because of this connection, control loops of various converters will interact through the AC grid, leading to instability and an undesirable transient response. This paper focuses on the system‐level integration of multi‐VSC systems for the integration of RESs. μ analysis is used to determine under which control modes the independently stabilized VSCs connected to a common AC system ensure the multi‐VSC system stability. Furthermore, a sufficient criterion is proposed for the design of the converters' outer control loops independently to ensure the stability of the interconnected multi‐VSC system. For cases of severe interactions, where the interconnected multi‐VSC system may become unstable even if individual VSCs are stable, a joint controller design for converters is proposed to stabilize the multi‐VSC system. The interaction analysis indicates that employing AC voltage control mode by all the converters causes the highest interaction level, and having more converters in reactive power control mode reduces the impact of interactions on the interconnected system stability.

Multi-terminal HVDC grids facilitate the integration of various renewable resources from distant locations; in addition, they enhance the reliability and stability of the grid. Protection is one of the major obstacles in realizing reliable and secure multi-terminal HVDC grids. This paper presents a comprehensive review of the existing protection schemes for multi-terminal HVDC grids. First, DC fault current stages are demonstrated; in addition, fault analysis studies and the existing fault current calculation methods are reviewed. Then, HVDC grid protection requirements including multi-vendor interoperability conditions are extensively discussed. Furthermore, primary protection algorithms are classified into single- and double-ended schemes, and a detailed comparison between each category is presented such that the distinctive algorithms from each group are highlighted. Moreover, the recent DC reclosing schemes are reviewed highlighting their role in enhancing grid stability and ensuring supply continuity. Finally, available standards for HVDC protection systems alongside their design considerations and procedures are thoroughly outlined. This paper focuses on the recently proposed methods to design reliable protection schemes for multi-terminal HVDC grids and highlights the main advantages and disadvantages associated with them; thus, it offers a beneficial guide for researchers in the HVDC protection field.

In the event of a DC side fault in modular multilevel converters (MMCs), the fault current contributions are initially made by submodule (SM) capacitor discharge, which occurs before the fault is detected, followed by the AC side contribution to the DC side fault. While the AC side currents can be regulated using fault blocking SMs, the initial discharge of the SM capacitors results in high DC fault currents, which can take several milliseconds to be brought under control. This paper presents a method to actively control the rate of rise of the DC fault current by regulating the discharge of SM capacitors and accelerating the suppression of fault current oscillations during fault ride-through (FRT) in a full-bridge (FB)-MMC system. In the proposed method, the discharge direction of the FBSM capacitors is reversed following the detection of a DC side fault, which leads to a reversal in the fault current direction and a fast drop-off towards the zero-crossing. Immediately after the zero-crossing of the DC fault current, the DC fault is cleared by adjusting the arm voltage references and operating the MMC as a static synchronous compensator (STATCOM) to provide voltage support to the AC grid. The proposed control scheme provides faster fault current suppression, more effective SM capacitor voltage regulation, low AC side and MMC arm current transient peaks, and an overall superior DC-FRT performance compared to methods in which the conventional fault ride-through operation is initiated immediately upon DC fault detection.