Multiterminal (MT) HVDC networks have been proposed as a techno-economic solution for the integration of renewable electricity sources and increased interconnection of large-scale grids. However, moving from point-to-point links to MT grids brings new challenges for DC-side protection. If protection schemes including DC circuit breakers are to be implemented, the appropriate measurement equipment must be selected. This article proposes a generic instrument transformer (IT) bandwidth selection methodology based on the minimum requirements for three HVDC protection critical cases. The methodology is described and applied to different study cases to show how varying HVDC system parameters can impact the required functional specifications, particularly bandwidth. The results show how bandwidth requirements are affected by the line termination impedance, line lengths, and protection system selectivity requirements.

Current/OS zoning provides an important basis for system-level LVDC protection design by classifying subcircuits from a risk-and safety-oriented perspective. The synthesis of a coordinated protection architecture, however, must not only consider the local fault environment but also selectivity requirements resulting from power supply continuity needs of connected devices and systems. This paper proposes a functional characterization framework for LVDC protection systems that links these complementary views by making branch-and subsystem-level protection functions explicit. A case study demonstrates that the same Current/OS zone classification can be realized by different breaker-based and breaker-less protection strategies, while the proposed functional characterization makes their differences in allocation, sequencing, and co-design requirements explicit.

To transition towards a carbon-neutral power system, considerable amounts of renewable energy generation capacity are being installed in the North Sea area. Consequently, projects aggregating many gigawatts of power generation capacity and transmitting renewable energy to the main load centers are being developed. Given the electrical challenges arising from having bulk power capacity in a compact geographical area with several connections to the main grid, and a lack of a robust definition identifying the type of system under study, this paper proposes a general technical definition of such projects introducing the term Electrical Energy Hub (EEH). The concept, purpose, and functionalities of EEHs are introduced in the text, emphasizing the importance of a clear technical definition for future planning procedures, grid codes, regulations, and support schemes for EEHs and multiterminal HVDC (MTDC) grids in general. Furthermore, the unique electrical challenges associated with integrating EEHs into the power system are discussed. Three research areas of concern are identified, namely control, planning, and protection. Through this analysis, insights are provided into the effective implementation of multi-GW scale EEH projects and their integration into the power grid through multiple interconnections. Finally, a list of ongoing and planned grid development projects is evaluated to assess whether they fall within the EEH category

Protection system design for multi-terminal HVDC grids is challenging due to the complexity of the system and the often conflicting design requirements. Effective specification of protection component parameters (e.g., DC circuit breakers and series DC inductors) during component-level design is crucial due to interdependencies among components, the need for detailed modeling, and the complex interactions between the protection system and converter control systems. Both analytical and simulation-based approaches have been proposed as solutions for component-level design. However, analytical methods may not accurately represent system behavior given that approximation is necessary, and simulation-based approaches often require extensive computational effort and time. Therefore, this paper presents an efficient systematic design method, combining both approaches. First, a fundamental analytical solution is derived to consider the protection system requirements. Then, a hybrid analytical–EMT methodology is proposed to accelerate convergence toward the required design parameters, after which detailed models are applied to ensure accuracy in design and validation. The approach is applicable to component-level design for both fully and partially selective protection strategies in HVDC grids.

HVDC protection will be required in future multiterminal HVDC grids to prevent large outages caused by DC faults. Therefore, system-level protection design is essential for the development of HVDC switching stations that connect several converter stations and lines within these grids. This paper presents an optimization method for the design of HVDC circuit breaker (DCCB) configurations in HVDC switching stations and electrical energy hubs. This approach builds on the current practice of using selected configurations based on pre-defined protection strategies. In contrast to these existing methods, the DC switching station design in the proposed method offers significantly more flexibility and allows the consideration of large numbers of relevant operating conditions, leading to more effective, optimal design outcomes. A mixed-integer linear optimization problem is formulated to design the DC protection and minimize the risk of high impact DC faults. An example case study demonstrates that the optimization method allows the calculation of the optimal number of DCCBs for a given DC switching station, based on the failure rates of DC grid components and the DCCB cost relative to the fault impact. With these results, the marginal benefit to risk reduction of each additional DCCB included in a DC switching station is calculated. Moreover, the result of the optimization problem provides the optimal breaker configuration for the required number of DCCBs and can consequently be used as a topological design tool for DC switching stations.

Modular Multilevel Converter (MMC) High Voltage Direct Current (HVDC) systems are controlled through a plethora of control loops arranged in a complex hierarchy. Their response to AC-side short-circuit faults will be an interplay of multiple interacting control loops. The control loops must balance compliance to grid codes with impact on system protection, within the limits imposed by the power-electronic components. This paper uses global sensitivity based on elementary effects and Morris screening to identify the most critical parameters in a partially black-boxed MMC control model. Results show that fault current injection parameters and PLL gains have an impact on both internal and AC-side fault behavior, with nonlinear interaction observed between the PLL gain and droop of fault current injection. Results also show that total energy control has a significant impact on AC-side fault behavior and protection performance, which is usually overlooked by the existing literature. The impact of grid strength, pre-fault operation modes, and fault types is studied to generalize the results under different conditions. The application of global sensitivity analysis in MMC-HVDC systems offers transmission system operators a practical tool for identifying critical control parameters without requiring full model access.

High-voltage direct current protection systems utilise transient information from electrical signals following disturbances or short-circuit faults. Stray capacitance and system inductance can induce high-frequency resonances, altering the filtering characteristics of boundary elements in DC protection systems. This paper addresses the need to accurately represent travelling waves (TWs) in protection studies by including stray capacitance in DC substations. In this paper we analyse stray capacitances in air-insulated DC substations and their impact on TWs. The findings reveal that TWs on adjacent lines can traverse boundary elements and cause oscillations, potentially affecting the performance of DC substation protection.

Moving towards truly multivendor HVDC grids requires definition of the functional performance at the system and device level, as well as decision making on control and protection architecture. While many technical solutions to solve protection system challenges have been developed and demonstrated in the past decade – e.g. DC circuit breakers and protection relays – there is still no consensus on how to divide the required functionality across different physical devices. This is particularly of interest for multivendor systems, in which well defined functional requirements must be developed for the individual devices and their interfaces. This paper examines a method to perform the splitting of protection system functionality, enabling systematic rules to be applied when choosing a protection system implementation in a multivendor system where different parties have different interests. Behavioural or functional modelling of the system, e.g. using Model Based Systems Engineering (MBSE), is applied to describe the system and enable choices in splitting of functionality between different physical devices and/or devices from different manufacturers.

Advancements in Multi-terminal HVDC systems necessitate complex protection systems, typically including HVDC circuit breakers (DCCBs). Protection system design and component sizing for these systems are not straightforward and require (extensive) EMT studies. For these EMT studies, several reduced HVDC component simulation models could be used, each with an associated level-of-detail and accuracy. The (in)accuracy of HVDC component models directly impacts the outcomes of the EMT studies. This paper aims to shed light on the accuracy requirements for component simulation models, e.g., converter models, that need to be considered for protection studies such as DCCB sizing. To achieve this, a method for determining accuracy requirements based on cost and performance is presented, providing a guideline for selecting models. Different converter models are then compared for several system parameters and fault parameters to determine their use in protection design studies.

The growing reliance on power-electronic-based renewable energy and high-voltage direct current (HVDC) systems poses challenges for distance protection, as converter fault responses differ from those of synchronous generators. At the same time, grid codes require converters to inject reactive current during AC faults, yet these requirements are typically studied independently of protection considerations. This paper addresses the gap by selecting control parameters in modular multilevel converter-based HVDC systems to enhance distance protection performance while ensuring compliance with grid codes and system stability under varying grid conditions. A global sensitivity analysis is conducted to identify the most influential control parameters, which are then systematically grouped for selection. The approach is evaluated across different system topologies and short circuit ratios, demonstrating its effectiveness in enhancing control-protection coordination and identifying the conditions where parameter tuning remains inadequate. These findings provide insights into the limitations of parameter tuning and identify scenarios where fundamental changes in control and protection may be required.

Control systems for modular multilevel converter based high voltage direct current (MMC-HVDC) systems involve numerous parameters and control loops, impacting AC system protection. This paper tries to answer the following question: Which control loops are more critical for impacting distance protection performance under different time scales? For this purpose, this study investigates the performance of key control loops, such as the phase-locked loop, fault current injection, total energy control, horizontal and vertical energy balancing, and current control across various time scales. By analyzing the impact of these loops during transient and steady-state periods, the study highlights their critical roles in optimizing distance protection during faults.

The ongoing development of offshore renewable energy sources creates a growing need to integrate offshore transmission systems into existing power grids. Multiterminal HVDC grids are well-suited for this application, since they offer efficient and flexible transmission capacity over long distances. However, the need to prevent the loss of the entire grid in case of contingencies requires the use of expensive DC protection systems which pose a significant burden on the development of such multiterminal grids. Therefore, recent studies have proposed an alternative approach to limit the impact of DC faults by preventively decoupling the multiterminal grid and operating it as separate point-to-point links, or smaller decoupled multiterminal systems. Decoupled grids are expected to be less flexible and efficient than fully coupled multiterminal grids. However, this disadvantage can be mitigated by only performing the decoupling when possible fault impacts exceed a predetermined limit. Through techno-economic analysis using optimal power flow calculations, this paper evaluates how preventive decoupling impacts energy generation costs. The analysis is performed for two example systems representing possible offshore multiterminal HVDC grids.

This paper proposes a methodology for shortlisting protection system configurations for large HVDC switching stations, which are expected in multiterminal HVDC grids and electrical energy hubs (or energy islands). This novel approach focuses on the configuration of protection equipment and the arrangement of lines and converters in various protection zones, instead of expert decisions on protection strategies based on numerous simulations. A graph-based approach that allows high-level evaluation of possible DC fault impacts is presented. This fault impact evaluation method can evaluate many possible protection configurations allowing the selection of less obvious choices, as experts cannot consider all possible configurations, especially when the switching station size increases. A filtering process is applied to reduce the number of possible configurations based on multiple protection performance metrics which are evaluated for different power flow scenarios. The results for these performance metrics can be compared for configurations with different numbers of HVDC circuit breakers to assess the benefit of increasing the amount of protection equipment in different network topologies. It is also shown that, through continued filtering using additional performance metrics or fault scenarios, the number of possible breaker, cable and converter configurations can be further reduced, leading to a protection design that is well suited for many operational scenarios. The results of the shortlisting process provide insights on the required number of HVDC circuit breakers to limit fault impacts to a given value. Moreover, observed trends in the results could, in future studies, contribute to new design principles and priorities, allowing system developers to more effectively design HVDC protection systems for different operational scenarios and possible investment levels.

As the use of HVDC for transmission increases and more complex system configurations are developed it becomes more important to understand the fault behavior of mixed overhead line and cable DC systems. The impact of having an heterogeneous transmission medium in protection algorithms has not yet been fully explored in literature. This paper identifies the main challenges for fault detection in mixed underground and overhead systems through the use of a simulation based case study. The analysis of the results show how algorithms can be severely impacted by the transition between sections with different surge impedances. In addition, the most problematic fault cases are singled out along with system parameters that can further reduce protection algorithm performance.

This paper proposes a methodology for conceptual HVDC protection design for multiterminal HVDC grids used for the integration of offshore wind power into onshore AC systems. The applicability of HVDC protection strategies is discussed for each grid topology and evaluated in the context of different AC grid codes. Through worst-case fault impact analyses, it is shown that DC protection requirements vary significantly according to the total DC grid capacity and AC grid requirements. The protection design methodology shows that HVDC grids with a low infeed capacity or connected to AC grids with high loss of infeed limits can make use of protection strategies with fewer DC circuit breakers, compared to larger DC systems or stricter AC grid requirements.

HVDC systems that interconnect large generation and load centres are expected to facilitate the massive expansion of offshore wind energy. These HVDC systems combine vendor-specific technical designs and operation concepts. The successful operation of these HVDC systems requires well-defined functional specifications and test procedures for all the components of the protection system. To validate the performance of DC protection relays, a test bench for DC relays is necessary. However, existing requirements for DC relay tests are unclear, and no standardized procedures exist to validate the functionality of HVDC protection. Currently, real-time simulation is the most advanced testing method available, but it has accuracy limitations for high bandwidth testing, and its practicality and cost-effectiveness can vary based on the application. This paper presents a novel design of a DC protection relay test bench and discusses key considerations and hardware specifications for a suitable test bench. The presented test bench meets future testing requirements and includes high sample rates, accurate models, and necessary automation controls. Finally, several case studies are presented to demonstrate the practical implementations and test limitations of the test bench.