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In recent years, there has been considerable interest in convertor‐based generating solutions which to a greater or lesser extent mimic the behaviour of synchronous machines, thus overcoming many of the disadvantages of the existing technologies which are potentially destabilising at high penetration. Such solutions are frequently referred to as grid‐forming convertors (GFCs). This study focuses on the application of GFC technologies in offshore windfarms, where installation, maintenance and/or modification of any offshore equipment is very expensive and carries greater commercial risks, requiring extensive testing and confidence building prior to deployment in real applications. This is time consuming and particularly significant for GB and where there are large quantities of offshore generation. Onshore solutions to stability are therefore desirable for off‐shore transmission owners (OFTOs), especially, if they could be applied by retrofitting to existing conventional converter plant. Consequently, this study proposes and investigates the performance of hybrid solutions for offshore networks where the conventional STATCOM onshore unit is replaced by alternative options such as synchronous compensator and virtual synchronous machine converter of similar (or appropriate) rating with the aim of achieving grid‐forming capability. A laboratory‐scale implementation of the proposed control algorithm is also presented with selected validation test results. [ABSTRACT FROM AUTHOR]

This study presents a flexible model and testing arrangement that can be used to mimic the fault infeed characteristics of power electronics converters and evaluate the performance of transmission protection schemes to faults when the system is 'converter‐dominated'. That is sources (e.g. renewables) and infeeds (e.g. HVDC interconnectors) that are interfaced to the main power system via converters. Actual protection relays are injected, in real‐time, using the outputs of the various fault simulations. A range of potential protection issues, including slow tripping, erroneous discrimination and non‐operation, are illustrated for particular scenarios. The main contributions of the study include knowledge of how different protection schemes may be affected by converter‐interfaced sources and guidance on possible solutions to the observed problems. Two solution options are highlighted: changes to the fault detection methods used within relays, and/or defining the fault‐response elements of future grid codes (and therefore future converter fault responses) to ensure that existing protection schemes will not be adversely affected in future low‐carbon, converter‐dominated systems. [ABSTRACT FROM AUTHOR]

This study presents a method for discriminative detection of direct current (DC) faults on voltage source converter‐powered multi‐terminal high‐voltage direct current transmission systems using two fundamental guiding principles, namely instantaneous current‐differential and travelling waves. The proposed algorithm utilises local voltage and current measurements from all transmission lines connected to a DC busbar, and current measurement from the DC side of the converter. The scheme operates at a sampling frequency of 96 kHz, which conforms with IEC 61869‐9. No long distance communication is involved while measurements and signal exchange within DC substations are enabled by the utilisation of IEC 61850. Performance is assessed firstly through detailed transient simulation, using verified models of modular multi‐level converters, hybrid DC circuit breakers and inductive DC‐line terminations. Furthermore, practical performance and feasibility of the scheme are evaluated through laboratory testing, using the real‐time Opal‐RT hardware prototyping platform. Simulation and experimental results demonstrate that the proposed protection algorithm can effectively, and within a very short period of time (i.e. <1 ms), discriminate between busbar and line faults (internal faults), while remaining stable during external faults. Additionally, it has been demonstrated that IEC 61869‐9 is suitable for enabling fast DC protection schemes incorporating travelling waves. [ABSTRACT FROM AUTHOR]

The installed capacity of non‐synchronous devices (NSD), including renewable energy generation and other converter‐interfaced equipment is expected to increase and contribute a large proportion of total generation capacity in future power systems. Concerns have been expressed relating to operability and stability of such systems, since NSD are typically decoupled from the grid via power electronic devices and consequently reduce the 'natural' inertia, short‐circuit levels and damping which are inherently provided by synchronous machines. This study establishes the instantaneous penetration level (IPL) limits of NSD connected to a model power system in terms of steady‐state stability beyond which the system condition becomes unstable. The NSD used in this example will be a conventional dq‐axis current injection (DQCI) convertor model. The study introduces a set of system 'viability' criteria relating to locking signal in converter phase‐locked loop, frequency, rate of change of frequency and voltage magnitude, which are used to determine the IPL limits. Among many factors which can affect the IPL limits, the impact of frequency and voltage droop slopes and filter time‐constants of DQCI converter is quantified. Finally, a frequency domain visualisation method referred here as 'network frequency perturbation' is introduced to provide additional insight into contributions of individual generators. [ABSTRACT FROM AUTHOR]