IEC 61850 Process Bus - It is Real!

Authors: Damien Tholomier and Denis Chatrefou, AREVA T&D

Voltage Transformer Based on Capacitor Divider and Primary Electronics

The Voltage Transformers based on a Capacitive Divider and Primary Electronics (VTCE) are devices able to measure the voltage of High Voltage lines for revenue metering application, as well as for protection and redundancy features.

One phase Unit includes:

  • A capacitive divider, isolated with film-paper-oil, or SF6 technology represents technology that is well-known and mastered by many manufacturers.
  • A redundant Primary Converter, replacing the conventional transformer in the bottom of CCVTs ; these electronics are designed for digitalization and transmission to the merging unit with an optical cable.

Advantages of the VTCE solution:
This Non Conventional Capacitor divider Voltage Transformers, where the magnetic part is replaced by electronics Primary Converter, offers many advantages:

  • Takes advantage of inherent low cost technology (CCVT)
  • Uses standard products manufactured in several unit of production ; proven solution for capacitor divider using mixed film/paper/oil technology
    EHV-VTCE could be developed for Extra High voltage applications and improves measurement performances by offering:
  • Harmonics capability
  • Extended metering Class
  • Digital communications to Merging Unit (MU).

The solution offers also the Power Quality capability, allowing harmonics measurements up to the 100 of the rated frequency.

The VTCE Unit:
The VTCE unit includes:

  • Head, including primary conductor to high voltage terminals
  • Composite insulator, including the capacitive divider
  • Capacitor junction
  • Base with primary electronics, and fibre transmission.

IEC 61850-9-2 Digital Interface for Sampled Values
Electronics technology has fully evolved in the last decade and the consequence is the generalization of digital hardware designs for electronics devices like Merging Units (MU) and Intelligent Electronic Devices (IED), including protection relays and meters, as well as the digital communications between them. A previous RTE experiment at Vielmoulin 400 kV substation has successfully demonstrated during more than three years the feasibility of such a digital link.
Unfortunately, there was a delay of several years before receiving a standard communications protocol that is accepted worldwide. This fact has considerably slowed down the NCIT applications.

We also need to remember that the technology of optical sensors is well proven. Indeed, since the end of the nineteen's many CTO units for revenue metering and protection function have been installed at the HV terminals of IPPs (Independent Power Producers). These devices have the major advantage of extra high dynamic range for current measurement that can be achieved with conventional current transformers only by using separate CTs for protection and metering.

As already mentioned previously, the publishing of IEC 61850 creates a great opportunity because of its main objective - to ensure "Interoperability" between IEDs coming from various suppliers, to enable the unrestricted exchange and usage of data to perform their individual dedicated functionality.

This is not an easy task, especially if we consider the many different requirements for various substation and power system related applications. Many chapters exist in this standard that define several levels of abstract communications and their implementation in real substation communication networks - in particular Parts 8-1 and 9-2 that are respectively dedicated to defining in detail the digital protocols between the different types of substation secondary devices.

The three main types of substation communications are:

  • Client (mostly an HMI or other substation level function) - Server (IED)
  • Peer-to-Peer based on GOOSE (Generic Object Oriented Substation Events) between IEDs
  • Instrument Transformers (Conventional or Non-Conventional) to IED - based on the sampled values produced by a Merging-Unit.

Because the IEC 61850-9.2 was a protocol largely open to the future that should not restrict any possible applications, there were many parameters that are not fixed and are subjected to different technical choices. This supports the required flexibility of the standard that makes it future-proof. However, it introduces an interoperability issue that had to be resolved.

The joint efforts of several major manufacturers under the umbrella of the UCA International Users Group resulted in the publication of implementation guidelines for substation applications.

Interoperability between merging units and protection, control, monitoring or recording devices is ensured through this document. Two modes of sending sampled values between a merging unit and a device that uses the data are defined. For protection applications, the merging units send 80 samples/cycle in 80 messages/cycle; i.e each Ethernet frame has the MAC Client Data containing a single set of V and I samples. For power quality monitoring and waveform recording applications such sampling rate may not be sufficient. That is why 256 samples/cycle can be sent in groups of 8 sets of samples per Ethernet frame sent 32 times/cycle.

The information exchange for sampled values is based on a publisher/subscriber mechanism. The publisher writes the values in a local buffer, while the subscriber reads the values from a local buffer at the receiving side.

A time stamp is added to the values, so that the subscriber can check the timeliness of the values and use them to align the samples for further processing. The communication system shall be responsible to update the local buffers of the subscribers. A sampled value control (SVC) in the publisher is used to control the communication procedure.

Figure 4 shows a simplified block diagram of a merging unit including amplifiers, filters, analog to digital converter and DSP signal processing. The merging unit is synchronized using 1 PPS signal from a GPS receiver. As can be seen from the figure, there is a time delay D = D1 + D2 introduced within the device. If this time delay is not compensated, it will be seen as a phase shift (Figure 6) that will affect all functions using the sampled analog values.

The receiving devices then process the data, make decisions and take action based on their functionality. The action of protection and control devices in this case will be to operate their relay outputs or to send a high-speed peer-to-peer communication message to other IEDs in order to trip a breaker or initiate some other control action.

There is an important detail that needs to be considered when processing the data by the receiving IED. The sampling rate in the merging unit is fixed, because the samples/cycle are defined at the nominal frequency of the system.
At the same time, the protection algorithms in most cases are based on frequency tracking with a fixed number of samples/cycle at the frequency of the system.

Many devices that are used both as conventional IEDs and IEDs with process bus interface capabilities have sampling rate different from the 80 samples/cycle. This will require re-sampling in order to run the different protection and other algorithms. (Figure 5)

A document itself can never convince a user that all interoperability issues are resolved. Especially protection engineers. They need to see it to believe it. That is why multiple interoperability demonstrations between major manufacturers on NCIT and protection and other IEDs were organized to show that this is not emerging, but existing technology.

The recent CIGRE 2006 DEMO presented a small part of a substation where several devices from different vendors were involved in an IEC 61850 process bus interoperability demonstration involving both merging units and protection devices. The test device injected currents and voltages into the different merging units that were interfacing with IEDs from a manufacturer different from the one that produced it.

The Demo was a real success and the perspective of using this technology excited many visitors.

Following the very successful experiment made with NCIT and distance protections interfaced by a digital communication at EDF/RTE France during more than three years, several other pilot projects were launched:

  • NGT (U.K.), Osbaldwick 400 kV GIB, with hybrid sensor like: Rogowski coils and capacitor electronics
  • RTE (France), Saumade 245 kV GIS substation with hybrid sensors, MU and distance protections,
  • HQ (Canada), La Prairie 315 KV AIS substation , with CTOs, and conventional CCVTs mixed in the Merging Unit. (Figure 7)

The first experiment is conducted with NGT on a GIL connecting two parts of a substation. Osbaldwick and Thornton substations, separated by thirty miles, are involved.  A differential line protection is installed working with NCITs on one end and conventional ITs on the remote end.

The second one with RTE is Saumade GIS 245 kV substation, using NCIT based on hybrid technology (Rogowski coils and capacitors), connected on the merging-unit and interfaced digitally with two Distance protections, provided by AREVA and Siemens, and a Landys+Gyr meter.

The third one is driven by Hydro Quebec and shows an application with optical Faraday sensors at 315 kV, in the substation La Prairie, near Montreal. Extreme temperature variations make a good demonstration of the technology reliability and stability in accuracy. Here again, protection devices come from different manufactures, showing interoperability. (Fig. 8)

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