Multi-vendor (MV) interoperability is a key prerequisite for the development of robust and expandable multi-terminal (MT) HVDC grids; however, the design of individual subsystems, such as converter and DC switching stations, as well as the control, operation and protection of the DC network, remain challenging. To address this, the EU-funded InterOPERA project is deploying a real-time demonstrator of a MT MV HVDC system. The preparation phase included the definition of a functional framework and its application to the selected topology, resulting in detailed technical specifications supported by HVDC grid design studies.

An important outcome of the design studies is the assessment of temporary overvoltage conditions, which may be managed within the dynamic timeframe through primary control actions, and the coordinated use of dynamic braking systems (DBS). In point-to-point HVDC links, DBS are typically designed to support AC fault ride-through by dissipating the energy that cannot be injected into the onshore grid until the fault is cleared. In practice, the implementation of DBS technology varies among manufacturers. In a MV HVDC grid, a wider range of operating conditions (initial and post-event) naturally arises, and interoperability risks between different solutions may emerge. While generic models for HVDC converters are well-established and comprehensively documented in the literature, less attention has been given to other components, such as DBS. To address this gap, this work investigates the influence of DBS modelling on the dynamic behaviour of MT HVDC systems under various operating conditions and disturbances.

Specifically, this paper first demonstrates the limitations of basic generic DBS models, which perform adequately in classical point-to-point HVDC links but may exhibit spurious behaviour when applied to MT HVDC systems. In particular, the influence of a DC circuit breakers and, most notably, their associated inductances introduced for fault current gradient limitation, on the DBS model response is discussed. The paper then presents different generic DBS models suitable for early-stage design studies of MT HVDC systems, addressing the need for representative modelling approaches that are not tied to any vendor-specific solution.

Furthermore, this work explores potential interaction risks between DC voltage control concepts deployed at different stations, both in the DBS and at the converter terminals. Comprehensive simulation results for temporary AC faults and converter pole blocking scenarios, applied to different variants of the InterOPERA demonstrator topology, are presented. It is shown that in case of pole blocking, although wind curtailment is not strictly required in a three-terminal topology with two onshore and one offshore station, DBS activation may still limit dynamic DC voltage excursions, thereby supporting primary control actions and potentially relaxing design constraints on the surviving parts of the grid.