Since the introduction of protective relays with the capability of exchanging data over a communication link, several architectures have been proposed to offer a coherent system that can offer benefits for applications ranging from medium voltage distribution substations to large EHV substations. These architecture types provide different levels of integration in an electrical substation. Each of these levels require particular characteristics to meet the level of functionality required.
Type 1 - Maintenance And Commissioning
This entry level system allows the interconnection of several intelligent electronic devices (IEDs)
for the purpose of retrieving data, usually at irregular intervals and setting protection parameters
from a central point inside the substation or from a remote location over a telephone line and a
modem. This configuration is the most economical system but is confined to applications that are
not time-critical.
This network is usually not permanently connected to a desktop type PC but rather to a "notebook PC" or dial-up modem allowing access whenever required.
Software (PC/DOS/Windows) provides a user friendly method to view the relay settings and fault records, and allow setting changes from the central PC if desired.
The protection access software provides remote indication of:
Advantages:
Type 2 - Substation Supervision System
The next type consists of protective relays, measurements centers, possibly programmable logic
controller (PLC), and a permanent full-graphic user interface. All these devices are usually
connected on one or several sub-networks. A communication processor or data concentrator is
used to connect the sub-networks together and concentrate the information into a centralized
database.
It is important to note that typical communicating protective relays are of mono-processor design, and a very high priority is obviously assigned to protection tasks. As a result, the single processor is unable to serve a communication network within a reasonable time for the transfer of critical protective signals.
With this configuration, only low speed control functions can be implemented (i.e. inside a PLC).
The analog measurements retrieval and storage to a centralized database could also be quite slow. This can be annoying for an operator opening a breaker from the user interface and seeing a response only after 5 to 10 seconds. It is therefore recommended that the number of IEDs per communication channel is limited in order to speed up to the overall cyclic polling of the substation data.
Additional functions supported:
Advantages:
Disadvantages:
Slow communication speed and turn-around time of the protective relays. With the use of a
single microprocessor in the IED, there is incompatibility between the protection and the
communication functions; the IED has to communicate mostly when the microprocessor is
performing its protection task, and the required data cannot be made available on the
communication network in time. It could take from a few hundred milliseconds to a few seconds
to extract data from an IED, rendering the transfer of protective signals over the network
impossible.
Complex wiring scheme: For example, in the case of breaker failure or transfer of blocking signals, each of these critical protective signals has to be hardwired to another IED, and this increases the amount of engineering, wiring, installation and testing.
Complex implementation of redundancy: By using a master-slave protocol, the system usually creates a single point of failure (the master), often unacceptable in a substation. If redundancy is required, the addition of a stand-by master is required, increasing cost and complexity. The data consistency and switch-over of both units becomes complicated and the implementation of a hot stand-by substation computer is particularly complex and expensive.
Non-deterministic communication scheme: When communicating on some network types, the device which has to transfer information first has to sense the communication line to see if the path is free. Depending on the communication load, the channel may not be free, and in that case the device will retry after a certain time which is randomly defined. In that case the time to transfer information from one device to another is unpredictable.
Type 3 - Substation Control System
With the following architecture, the control system is built around a Local Area Network (LAN)
using PLC. The protection devices are usually not connected to the control system via a
communication link but rather using direct hardwired connections.
The control logic implemented inside the PLC's is organized on a per bay configuration. The LAN is usually a Ethernet-TCP/IP type with a local user interface and a gateway to a SCADA/EMS system also connected to it. The same configuration can also be fully redundant using Ethernet rails and dual connection from the various IED's.
Additional functions supported:
Advantages:
Disadvantages:
Type 4 - The Integrated Protection And Control System
To overcome the disadvantages of the architectures described above, a token ring network
topology can be used to control and protect the entire electrical substation and provide full
automation capabilities.
With this architecture the protective relays are equipped with a dedicated communication processor and they can be connected directly on a dual high-speed optical fibre network. The system is now able to provide transfer of data at a sufficient speed to allow several protection functions to be integrated at the station level.
Recognizing the fact that most of the IED's are still communicating over a standard RS232/RS485 link and using different communication protocols, a Bay Module can be used as a gateway between the IED's and the high-speed substation communication loop, thus allowing a mix of IED's from different manufacturers.
Typical devices and functionality supported on the ring network:
Protective Relays:
Programmable Logic Controller:
Input/Output Interface:
Local Control Computer:
Gateway:
Bay Module:
Additional functions supported:
Advantages:
Disadvantages:
Since the installation of the first integrated substation control and protection system in 1985 at La Cazerie substation of the National French Electricity Company (EDF), this type of microprocessor based system has been installed in numerous MV and HV.
In July 1995, the first integrated protection and control system in North America was installed in Canada at the new R.E. CAVANAGH 230 kV Transformer Station owned by Scarborough Public Utilities Commission (Ontario, Canada).
General Overview Of This Type Of System
The integrated substation control and protection system has replaced the complex conventional
secondary circuit technology that uses a number of discrete devices and a significant amount of
wiring and intercabling. It also minimizes space requirements and drastically reduces the high
degree of maintenance that is required by conventional systems.
Reliability and availability have been improved by the constant self monitoring facility implemented in the equipment. Errors and malfunctions are detected as they occur and the appropriate actions initiated instantaneously. Regular preventive maintenance therefore becomes a thing of the past.
Distributed intelligence ensures that process data is logged and processed where it is generated and, only when necessary is it then formatted and transmitted via the local area network to the local control center.
The Communication Network
There is no master or slave on the token ring network, and each partner on the ring has its own
distributed database updated in real-time. It provides a high degree of availability through the
redundancy of its optical data transmission.
The communication speed on the network is 3.5 Mbits/s and the maximum distance between two IED's is 1,000 meters, (5,000 meters with an enhanced optical interface) the maximum length of the network is 52 km, allowing the connection of more than one control building on the same network. The optical cables are made of 62.5 to 125 um multimode silicon fibre and the ends of each cable are fitted with ST type bayonet connectors. The typical delay time through one IED is around 30 us.
Network Redundancy / Self-Healing Mechanism
Each device has a transmitter/receiver pair for the working medium (main fibre) and a
transmitter/receiver pair for the standby medium (alternate fibre). Both pairs are in the same cable.
Under normal conditions, the information circulates on the working medium in a clockwise
direction. If a fibre break occurs, the devices on either sides of the rupture will detect the fault and
initiate a self-healing mechanism. Information will now circulate in the standby medium in
counter-clockwise direction as shown below.
Conventional Protective and Metering Devices
To allow the connection of conventional low-speed communicating relays, a LAN interface can
be inserted in the optical fibre loop and relays polled on a serial interface (RS232 or RS 485).
Time critical protective signals will not be captured over the serial link but rather through the use
of a digital input / output interface.
Bay Module functions:
Digital / Analog I/O Interface: The Bay Module provides digital and analog input/output interfaces with the switchgear cubicle or conventional protection relays. Digital inputs are time stamped by the Bay Module. Analog input thresholds with two high and two low setpoint limits can be also time stamped.
Local interlocking: The Bay Module can also act as a PLC to provide bay level interlocking facilities.
Serial Interface to IED's: The Bay Module can provide a variety of other interfaces such as IEC 870.5, DNP3.0, VDEW, (RS232C, RS485) while other types of protocol can be added upon request.
Conclusion
Depending on the kind of application and functionality required, several communication
architectures are available to cover most of today's needs in the substation.
Distributed Systems offer more functionality and even at higher initial cost, they provide savings through the reduction of inter-cabinet wiring, installation and commissioning costs and the elimination of RTU's or SER devices.
John Attas and Pierre Berger are with GEC Alsthom Canada..