The essence of digital substation automation: Timing precision & real-time data

Precision time synchronization

Almost all substation protection and control applications require accurate time-stamping. The performance of systems such as Network Time Protocol (NTP), IRIG-B and one pulse per second (1-PPS) have been sufficient to date. However, new applications, including IEC 61850-9-2 process bus and phasor measurement, require accuracy of 1 μs or better.

Furthermore, process bus applications are taking time synchronization out into high voltage switchyards where cable lengths may have an impact on timing accuracy.

IEEE Std 1588, Precision Time Protocol (PTP), is the means preferred by the smart grid standardization roadmaps (from both the IEC and US National Institute of Standards and Technology) of achieving this higher level of performance, and integrates well into Ethernet based substation automation systems.

Significant benefits of PTP include automatic path length compensation, support for redundant time sources and the cabling efficiency of a shared network.

Experimental results show that a PTP timing system maintains the synchronizing performance of 1-PPS and IRIG-B timing systems, when using the same fibre optic cables, and further meets the needs of process buses in large substations.

Substation Application

The high voltage equipment in a substation (for example busbars, circuit breakers, isolators, earth switches, power transformers, current transformers and voltage transformers) is referred to as the ‘primary plant’.

The control equipment in a substation is termed the substation automation system (SAS), and includes protection, control, automation and monitoring devices. A ‘process bus’ carries sampled value measurements and status information from the primary plant to the SAS, and conveys commands from the SAS to the high voltage circuit equipment (e.g. circuit breakers and transformer tap change controllers), over a digital network.

Merging units (MUs) sample the output of conventional current transformers and voltage transformers and transmit this information over the process bus.

Secondary converters (SCs) convert the proprietary output of Non-Conventional Instrument Transformers (such as optical or electronic transducers) into a standard form that then connects to the SAS.

Intelligent electronic devices (IEDs) require that the current/voltage samples are synchronized. Any synchronizing error (regardless of method used) will manifest as phase error, and this in turn gives ‘spill current’ in differential protection schemes, increasing the chance of false tripping.

Figure 1 (above) shows two example configurations where this is required.