At the consumer end there is a lot of talk in Smart Grid circles about home automation systems with the meter as the node, however the role of the energy meter doesn't change as far as measuring I, V and F and giving W, Var, VA and PF.

In terms of implementing IEC 61850 from the user or the meter vendor's perspectives, the application and need is vital to know.

General Metering Requirements

Metering related data structure are defined in the IEC 61850 7-4 Logical Nodes M Group - Measurement Functions

That satisfies the simple statement of complying to a 7-4 Data Model.

In principle, it would still be possible to talk to that device with say DNP3 or Modbus if it maps info into a point based listing - a huge a waste since all the semantics for engineering and other applications are lost.

IEC 61850 is about structuring and configuring communication between devices and between functions, hence defined semantics that are used and understood from top to bottom, left to right. Even just domestic meters for billing can do with all meters having the same semantics and data structure across all vendors.

We are even seeing now Data Models for Electric Vehicles, Distributed Energy Resources, PV, Battery, Microturbines, Fuel cells – and metering is involved with all these.

There is an impressive array of functionality with structured information for Harmonic Power Quality, Schedules, Pricing, Statistical and Historical analysis with interval, periodic and sliding calculations

Not only do we need the data structure but also the communication services.

The famous GOOSE is probably not a key requirement for meter applications - GOOSE is for extremely fast communication of status changes for real time (<10milliesecond) automation. However the Reporting mechanisms and the ACSI command language for GetValues etc are essential for this 'upstream' application for Smart Grid.

Substation Metering

The last element for applying IEC 61850 in metering is more applicable to the substation applications where there is a huge issue of the engineering effort to specify, design and implement the hundreds of cables per feeder purely associated with CT and VT wiring.

These wires can all be replaced with one optical fibre running past all the bays saving thousands of wires and associated engineering.

This can be achieved with conventional CT and VT using Stand Alone Merging Units such as available from Schniewindt (ask me for a quote) which give Sampled Value IEC 61850 9-2 or 9-2LE messages to the meter.

Moreover where utilities are seeking to eliminate CT explosions, eliminate saturation, extend dynamic range, reduce number from five or six cores per feeder to just two (main and backup), and many other benefits...... the move to Low Power Instrument Transformers is growing rapidly. (LPIT: previously referred to as Non-Conventional Instrument Transformers are now becoming seen as ‘conventional technology’, hence the acronym change).

LPIT use optical measurement (to name just a couple of examples) are available from ALSTOM Grid or Smart Digital Optics (sold via Arteche) or the Rogowski coil based technology. These may have been a bit slow to be implemented to date but I would suggest simply because of supposed perceived lack of experience and confidence – the fact is optical CTs have been in service since 1984 and proprietary sampled value formats, even IEC60044-8, have been in use in numerical bus bar protection since the 1990’s.

Whilst an MMXU Logical Node would satisfy the output data flow requirements to the upstream SCADA and billing etc using Part 8-1 comms, we also need the meter to accept Part 9-2 Sampled Value inputs via a comms port from a 1A/110V Merging Unit or an LPIT Merging Unit with TCTR Logical Nodes providing the Sampled Value streams.

Here in Australia we already have utilities wanting to buy IEC 61850 9-2 input meters for their substations simply because they want to get rid of the thousands of CT/VT wires for one optical fibre and then have one common communication system talking between the meters, relays, condition monitors, controllers and the SCADA system.

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