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Substation, Its Function And Types

Substation, Its Function And Types

An electrical sub-station is an assemblage of electrical components including busbars, switchgear, power transformers, auxiliaries etc.

These components are connected in a definite sequence such that a circuit can be switched off during normal operation by manual command and also automatically during abnormal conditions such as short-circuit. Basically an electrical substation consists of No. of incoming circuits and outgoing circuits connected to a common Bus-bar systems. A substation receives electrical power from generating station via incoming transmission lines and delivers elect. power via the outgoing transmission lines.

Sub-station are integral parts of a power system and form important links between the generating station, transmission systems, distribution systems and the load points.


…Associated with major sub-stations in the transmission and distribution system include the following:

  1. Protection of transmission system.
  2. Controlling the Exchange of Energy.
  3. Ensure steady State & Transient stability.
  4. Load shedding and prevention of loss of synchronism. Maintaining the system frequency within targeted limits.
  5. Voltage Control; reducing the reactive power flow by compensation of reactive power, tap-changing.
  6. Securing the supply by proving adequate line capacity.
  7. Data transmission via power line carrier for the purpose of network monitoring; control and protection.
  8. Fault analysis and pin-pointing the cause and subsequent improvement in that area of field.
  9. Determining the energy transfer through transmission lines.
  10. Reliable supply by feeding the network at various points.
  11. Establishment of economic load distribution and several associated functions.


The substations can be classified in several ways including the following :

  1. Classification based on voltage levels, e.g. : A.C. Substation : EHV, HV, MV, LV; HVDC Substation.
  2. Classification based on Outdoor or Indoor : Outdor substation is under open skv. Indoor substation is inside a building.
  3. Classification based on configuration, e.g. :
    • Conventional air insulated outdoor substation or
    • SF6 Gas Insulated Substation (GIS)
    • Composite substations having combination of the above two
  4. Classification based on application
    • Step Up Substation : Associated with generating station as the generating voltage is low.
    • Primary Grid Substation : Created at suitable load centre along Primary transmission lines.
    • Secondary Substation : Along Secondary Transmission Line.
    • Distribution Substation : Created where the transmission line voltage is Step Down to supply voltage.
    • Bulk supply and industrial substation : Similar to distribution sub-station but created separately for each consumer.
    • Mining Substation : Needs special design consideration because of extra precaution for safety needed in the operation of electric supply.
    • Mobile Substation : Temporary requirement.
      NOTE :
    • Primary Substations receive power from EHV lines at 400KV, 220KV, 132KV and transform the voltage to 66KV, 33KV or 22KV (22KV is uncommon) to suit the local requirements in respect of both load and distance of ultimate consumers. These are also referred to ‘EHV’ Substations.
    • Secondary Substations receive power at 66/33KV which is stepped down usually to 11KV.
    • Distribution Substations receive power at 11KV, 6.6 KV and step down to a volt suitable for LV distribution purposes, normally at 415 volts


Each sub-station has the following parts and equipment.

  1. Outdoor Switchyard
    • Incoming Lines
    • Outgoing Lines
    • Bus bar
    • Transformers
    • Bus post insulator & string insulators
    • Substation Equipment such as Circuit-beakers, Isolators, Earthing Switches, Surge Arresters, CTs, VTs, Neutral Grounding equipment.
    • Station Earthing system comprising ground mat, risers, auxiliary mat, earthing strips, earthing spikes & earth electrodes.
    • Overhead earthwire shielding against lightening strokes.
    • Galvanised steel structures for towers, gantries, equipment supports.
    • PLCC equipment including line trap, tuning unit, coupling capacitor, etc.
    • Power cables
    • Control cables for protection and control
    • Roads, Railway track, cable trenches
    • Station illumination system
  2. Main Office Building
    • Administrative building
    • Conference room etc.
  3. 6/10/11/20/35 KV Switchgear, LV
    • Indoor Switchgear
  4. Switchgear and Control Panel Building
    • Low voltage a.c. Switchgear
    • Control Panels, Protection Panels
  5. Battery Room and D.C. Distribution System
    • D.C. Battery system and charging equipment
    • D.C. distribution system
  6. Mechanical, Electrical and Other Auxiliaries
    • Fire fighting system
    • D.G. Set
    • Oil purification system

An important function performed by a substation is switching, which is the connecting and disconnecting of transmission lines or other components to and from the system. Switching events may be “planned” or “unplanned”. A transmission line or other component may need to be deenergized for maintenance or for new construction; for example, adding or removing a transmission line or a transformer. To maintain reliability of supply, no company ever brings down its whole system for maintenance. All work to be performed, from routine testing to adding entirely new substations, must be done while keeping the whole system running.

Perhaps more importantly, a fault may develop in a transmission line or any other component. Some examples of this: a line is hit by lightning and develops an arc, or a tower is blown down by a high wind. The function of the substation is to isolate the faulted portion of the system in the shortest possible time.

There are two main reasons: a fault tends to cause equipment damage; and it tends to destabilize the whole system. For example, a transmission line left in a faulted condition will eventually burn down, and similarly, a transformer left in a faulted condition will eventually blow up. While these are happening, the power drain makes the system more unstable. Disconnecting the faulted component, quickly, tends to minimize both of these problems.


Related articles

FIGURE 1 – Voltage gradient around a substation under fault condition

FIGURE 1 – Voltage gradient around a substation under fault condition

The purpose of this paper is to report a new test method and make a recommendation to improve the procedures according to the findings.

The test method involves measurement of high voltage substations earth grid impedance, by utilization of a variable frequency current source and frequency selective measurement techniques.

Safety policies require that the values of earth impedances remain within the specified acceptable range and every utility is required to guarantee safe step-and-touch potential levels. It is therefore necessary to carry out periodic testing on substation earthing to monitor the condition of the substation earthing system.

Knowledge of earth grid impedance of high voltage substations is also very important for correct operation of protection schemes and fault clearance. As the condition of grounding components change over time due to corrosion of earth cables, changes in the adjacent infrastructures and so on, it is necessary to measure the impedance of earthing grid periodically to ensure that the values are within expected range.

Knowledge of the overall resistance ZE allows calculation of the total voltage rise of a substation under maximum fault current. Knowledge of the voltage gradient around the substation, especially close to the substation allows calculation of the step-andtouch voltages under worst-case conditions.

Measurement principle

According to international standards such as CENELEC HD637S1 [1] or ANSI IEEE 80-2000 [2], 81-1983 [3] it is recommended to use a current-voltage method otherwise known as fall-of-potential [4].

Generally in a 90° angle (birds-eye view) two electrodes are placed outside the influence of the grounding system under test. One is used to inject the current (current electrode) and one to measure the voltage (voltage electrode). However because the area which is influenced by the grounding system is not so easy to determine, the current electrode is usually placed at a distance of at least 10 times, and up to 15 to 20 times the diameter of the grounding system under test. The voltage electrode then is placed in various distances.

Close to the system under test, large voltage degradation is visible. The further the voltage probe is located from the system under test, the more stable the measured voltages become (FIGURE 2 & 6).

FIGURE 2 – Voltage Degradation

FIGURE 2 – Voltage Degradation

Problems with Conventional Measurement Methods

For small grounding systems like a single tower, it is generally no problem to place the two needed electrodes and low currents generated by battery-operated equipment can generally do the job satisfactorily. However when measuring large substations, the distances are substantial and should be as large as 10 to 20 times the diameter of the substation. In some cases, measurements show peaks and drops until an area free of buildings and buried conductors or pipes is reached. Until then, erroneous results can be obtained.

Voltage drops can be observed when measurement points are set close to objects, like towers of power lines leaving the substation, connected to the grounding system under test. Voltage rises can be observed when for example measurement points are placed over a buried pipe that runs close to the current electrode. Therefore it is often difficult to distinguish between drops, rises and stable results.

To place the current electrode very far away is certainly a good idea, because then at least the influence of the current electrode can be minimized, however here the effort becomes even bigger. The biggest challenge is when the current electrode has to be relocated several times, before a stable measurement can be achieved.

Usage of existing power lines

One method to overcome these measurement problems is to use diesel generators (weighing several tons) to generate currents that have frequencies slightly different from mains frequency and to feed in the currents over existing, de-energized power lines leaving the substation. The grounding system of the remote substation where the power line terminates is used as current electrode (see FIGURE 2 Impedance Measurement).

The amount of current needed for such a test still has to be quite large to overcome mains frequency disturbances and the power requirement is enormous. But with these devices it is possible to measure ground impedances. However, the effort is by far too high to use it as a realistic approach for maintenance measurements.

Combination of the good ideas

FIGURE 3 – Test equipment for line impedance measurement

FIGURE 3 – Test equipment for line impedance measurement

A new approach of Omicron is to combine the principle of simple battery operated equipment based on the variable frequency principle and use the existing power lines and the grounding system of the remote substation as current electrode.

The test set CPC 100 and CP CU1 from OMICRON comprises of a frequency variable amplifier (29 kg), a coupling unit (28 kg) and a protection device (6 kg).

The CPC 100 is a multi-functional, frequency-variable test set for testing various primary equipments. It is capable of generating currents up to 800 A or voltages up to 2000 V, with special software modules to be used for various automated tests on CTs, VTs, power transformers or other primary equipments. With other accessories it can also be used for tangent delta testing on power transformer bushings or windings, with test voltages up to 12 kV.

In the application of ground impedance measurement it is used as frequency variable power generator, measurement tool and analyzer. Due to the variable frequency generation, it is possible to generate signals first under and then above mains frequency. Using digital filter algorithms, the test set will measure only the signal with the frequency that is currently generated and filters out signals at other frequencies. Disturbances due to noise and electrical interference thus no longer influence the result.

FIGURE 4 – Frequency selective measurement

FIGURE 4 – Frequency selective measurement

For safety reasons, the coupling unit CP CU1 is used for galvanic decoupling of the current output and the measurement inputs from the power line. This way, if fault or lightning occur during the test, the operator can be safe from dangerous voltages. For optimum performance there is a range selector switch for the current output, and a built-in voltmeter for a quick check of induced voltages or burden. Test currents of up to 100A can be generated for short cables, and for long lines of up to a few hundred kilometers, currents over 1A are still possible.

The protection device CP GB1 is a tool for easy connection to the overhead line or power cable and existing grounding cables of the substation may be used. In case of unexpected high voltage on the power line due to faults on a parallel system, lightning discharges or transients due to switching operations, the GB1 is capable of discharging short transients or permanently shorting fault currents of up to 30 kA for at least 100 ms. These features will protect the operator in unexpected situations.

The test itself is simple: the combination of CPC 100, CP CU1 and CP GB1 is connected to a de-energized power line (FIGURE 2&5); after removing the near end ground connection, test current with a different frequency than the mains frequency is injected. The voltage test probe then is located at various distances until stable voltage measurements can be observed. At this point the measurement is completed And the results can be stored in the CPC, downloaded to a PC and analyzed in a Microsoft Excel application.

Case study

The test was carried out on 7th October 2004 by confirming outage on Western Power Corporation’s Landsdale Northern Terminal line. Northern Terminal Substation was the remote terminal and the earth grid at Landsdale Substation was measured.

Earth Switches at both substations were closed and portable earths were applied to the lines in preparation for the test.
CPC 100 and CP CU20 (a predecessor of the CP CU1) were connected to the line as per test set up and voltage measurements stake was inserted at different distances from the test point in a different direction from that of the transmission line in order to avoid induction. Measurements were carried out and test files were saved to the CPC 100 memory to be retrieved in the office.

Test was performed at various frequencies (between 30-110 Hz) to suppress the noise and achieve a precise characteristic of the grid impedance under test. Impedances for 50Hz were extrapolated from the test results.

FIGURE 5 – Measurement of Landsdale Local Substation's Earth Grid

FIGURE 5 – Measurement of Landsdale Local Substation's Earth Grid

The mass of the earth is not the only path for feeding the ground current. All metal structures such as pipes tubes, railway lines and Multiple Earthed Neutral (MEN) of distribution systems between the test point and the current auxiliary electrode form the path for the ground current, including the shield wire on the top of the pole.

Test Results

The graph for the impedance measurement was as follows:

FIGURE 6 – Voltage degradation measurement results

The impedance profile of the earthing system was obtained and the stabilization of the impedance at a distance above 100m was obvious.

This data was then used to calculate the earthgrid potential rise during maximum earth fault conditions.


Substation earthing system testing using the conventional method is arduous, time consuming and involves multiple heavy equipment producing end results that are sometimes unreliable due to electrical interference and noise. The conventional method requires high test currents in order to achieve a higher signal-to-noise ratio, therefore heavy equipment and generators are required to produce such currents.

The alternative method using variable frequency technique, achieves the desired outcome with less cost, effort and resources and increases efficiency and accuracy.

Ulrich KLAPPER  – OMICRON electronics (Australia)


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One of the significant challenges that substation engineers face is justifying substation automation investments. The positive impacts that automation has on operating costs, increased power quality, and reduced outage response are well known. But little attention is paid to how the use of a communication standard impacts the cost to build and operate the substation. Legacy communication protocols were typically developed with the dual objective of providing the necessary functions required by electric power systems while minimizing the number of bytes that were used by the protocol because of severe bandwidth limitations that were typical of the serial link technology available 10-15 years ago when many of these protocols were initially developed. Later, as Ethernet and modern networking protocols like TCP/IP became widespread, these legacy protocols were adapted to run over TCP/IP-Ethernet.

This approach provided the same basic electric power system capabilities as the serial link version while bringing the advantages of modern networking technologies to the substation. But this approach has a fundamental flaw: the protocols being used were still designed to minimize the bytes on the wire and do not take advantage of the vast increase in bandwidth that modern networking technologies deliver by providing a higher level of functionality that can significantly reduce the implementation and operational costs of substation automation.

IEC 61850 is unique. IEC 61850 is not a former serial link protocol recast onto TCP/IP-Ethernet. IEC 61850 was designed from the ground up to operate over modern networking technologies and delivers an unprecedented amount of functionality that is simply not available from legacy    communications    protocols.    These    unique characteristics of IEC 61850 have a direct and positive impact on the cost to design, build, install, commission, and operate power systems. While legacy protocols on Ethernet enable the substation engineer to do exactly the same thing that was done 10-15 years ago using Ethernet, IEC 61850 enables fundamental improvements in the substation automation process that is simply not possible with a legacy approach, with or without TCP/IP-Ethernet. To better understand the specific benefits we will first examine some of the key features and capabilities of IEC 61850 and then explain how these result in significant benefits that cannot be achieved with the legacy approach

Key Features

The features and characteristics of IEC 61850 that enable unique advantages are so numerous that they cannot practically be listed here. Some of these characteristics are seemingly small but yet can have a tremendous impact on substation automation systems.

For instance, the use of VLANs and priority flags for GOOSE and SMV enable much more intelligent use of Ethernet switches that in and of itself can deliver significant benefits to users that aren’t available with other approaches. For the sake of brevity, we will list here some of the more key features that provide significant benefits to users:

  • Use of a Virtualized Model. The virtualized model of logical devices, logical nodes, ACSI, and CDCs enables definition of the data, services, and behavior of devices to be defined in addition to the protocols that are used to define how the data is transmitted over the network.
  • Use of Names for All Data. Every element of IEC 61850 data is named using descriptive strings to describe the data. Legacy protocols, on the other hand, tend to identify data by storage location and use index numbers, register numbers and the like to describe data.
  • All Object Names are Standardized and Defined in a Power System Context. The names of the data in the IEC 61850 device are not dictated by the device vendor or configured by the user. All names are defined in the standard and provided in a power system context that enables the engineer to immediately identify the meaning of data without having to define mappings that relate index numbers and register numbers to power system data like voltage and current.
  • Devices are Self-Describing. Client applications that communicate with IEC 61850 devices are able to download the description of all the data supported by the device from the device without any manual configuration of data objects or names.
  • High-Level Services. ACSI supports a wide variety of services that far exceeds what is available in the typical legacy protocol. GOOSE, GSSE, SMV, and logs are just a few of the unique capabilities of IEC 61850.
  • Standardized Configuration Language. SCL enables the configuration of a device and its role in the power system to be precisely defined using XML files.

Major Benefits

The features described above for IEC 61850 deliver substantial benefits to users that understand and take advantage of them. Rather than simply approaching an IEC 61850 based system in the same way as any other system, a user that understands and takes advantage of the unique capabilities will realize significant benefits that are not available using legacy approaches.

  • Eliminate Procurement Ambiguity. Not only can SCL be used to configure devices and power systems, SCL can also be used to precisely define user requirement for substations and devices. Using SCL a user can specify exactly and unambiguously what is expected to be provided in each device that is not subject to misinterpretation by suppliers.
  • Lower Installation Cost. IEC 61850 enables devices to quickly exchange data and status using GOOSE and GSSE over the station LAN without having to wire separate links for each relay. This significantly reduces wiring costs by more fully utilizing the station LAN bandwidth for these signals and construction costs by reducing the need for trenching, ducts, conduit, etc.
  • Lower Transducer Costs. Rather than requiring separate transducers for each device needing a particular signal, a single merging unit supporting SMV can deliver these signals to many devices using a single transducer lowering transducer, wiring, calibration, and maintenance costs.
  • Lower Commissioning Costs. The cost to configure and commission devices is drastically reduced because IEC 61850 devices don’t require as much manual configuration as legacy devices. Client applications no longer need to manually configured for each point they need to access because they can retrieve the points list directly from the device or import it via an SCL file. Many applications require nothing more than setting up a network address in order to establish communications. Most manual configuration is eliminated drastically reducing errors and rework.
  • Lower Equipment Migration Costs. Because IEC 61850 defines more of the externally visible aspects of the devices besides just the encoding of data on the wire, the cost for equipment migrations is minimized. Behavioral differences from one brand of device to another is minimized and, in some cases, completely eliminated. All devices share the same naming conventions minimizing the reconfiguration of client applications when those devices are changed.
  • Lower Extension Costs. Because IEC 61850 devices don’t have to be configured to expose data, new extensions are easily added into the substation without having to reconfigure devices to expose data that was previously not accessed. Adding devices and applications into an existing IEC 61850 system can be done with only a minimal impact, if any, on any of the existing equipment.
  • Lower Integration Costs. By utilizing the same networking technology that is being widely used across the utility enterprise the cost to integrate substation data into the enterprise is substantially reduced. Rather than installing costly RTUs that have to be manually configured and maintained for each point of data needed in control center and engineering office application, IEC 61850 networks are capable of delivering data without separate communications front-ends or reconfiguring devices.
  • Implement New Capabilities. The advanced services and unique features of IEC 61850 enables new capabilities that are simply not possible with most legacy protocols. Wide area protection schemes that would normally be cost prohibitive become much more feasible. Because devices are already connected to the substation LAN, the incremental cost for accessing or sharing more device data becomes insignificant enabling new and innovative applications that would be too costly to produce otherwise.


IEC 61850 is now released to the industry. Ten parts of the standard are now International Standards (part 10 is a draft international standard). This standard addresses most of the issues that migration to the digital world entails, especially, standardization of data names, creation of a comprehensive set of services, implementation over standard protocols and hardware, and definition of a process bus.

Multi-vendor interoperability has been demonstrated and compliance certification processes are being established. Discussions are underway to utilize IEC 61850 as the substation to control center communication protocol. IEC 61850 will become the protocol of choice as utilities migrate to network solutions for the substations and beyond.

SOURCE: Ralph Mackiewicz SISCO, Inc. Sterling Heights, MI USA


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Procedure for the establishment of a new substation

Procedure for the establishment of a new substation

Large consumers of electricity are invariably supplied at HV. On LV systems operating at 120/208 V (3-phase 4-wires), a load of 50 kVA might be considered to be “large”, while on a 240/415 V 3-phase system a “large” consumer could have a load in excess of 100 kVA. Both systems of LV distribution are common in many parts of the world. As a matter of interest, the IEC recommends a “world” standard of 230/400 V for 3-phase 4-wire systems.

This is a compromise level and will allow existing systems which operate at 220/380 V and at 240/415 V, or close to these values, to comply
with the proposed standard simply by adjusting the off-circuit tapping switches of standard distribution transformers.

The distance over which the load has to be transmitted is a further factor in considering an HV or LV service. Services to small but isolated rural consumers are obvious examples. The decision of a HV or LV supply will depend on local circumstances and considerations such as those mentioned above, and will generally be imposed by the utility for the district concerned.

When a decision to supply power at HV has been made, there are two widely followed methods of proceeding:

  1. The power-supplier constructs a standard substation close to the consumer’s premises, but the HV/LV transformer(s) is (are) located in transformer chamber(s) inside the premises, close to the load centre
  2. The consumer constructs and equips his own substation on his own premises, to which the power supplier makes the HV connection

In method no. 1 the power supplier owns the substation, the cable(s) to the transformer(s), the transformer(s) and the transformer chamber(s), to which he has unrestricted access. The transformer chamber(s) is (are) constructed by the consumer (to plans and regulations provided by the supplier) and include plinths, oil drains, fire walls and ceilings, ventilation, lighting, and earthing systems, all to be approved by the supply

The tariff structure will cover an agreed part of the expenditure required to provide the service. Whichever procedure is followed, the same principles apply in the conception and realization of the project. The following notes refer to procedure no. 2.

Preliminary information

Before any negotiations or discussions can be initiated with the supply authorities, the following basic elements must be established:

Maximum anticipated power (kVA) demand

Determination of this parameter is described in Chapter B, and must take into account the possibility of future additional load requirements. Factors to evaluate at this stage are:

  • The utilization factor (ku)
  • The simultaneity factor (ks)

Layout plans and elevations showing location of proposed substation

Plans should indicate clearly the means of access to the proposed substation, with dimensions of possible restrictions, e.g. entrances corridors and ceiling height, together with possible load (weight) bearing limits, and so on, keeping in mind that:

  • The power-supply personnel must have free and unrestricted access to the HV equipment in the substation at all times
  • Only qualified and authorized consumer’s personnel are allowed access to the substation
  • Some supply authorities or regulations require that the part of the installation operated by the authority is located in a separated room from the part operated by the customer.

Degree of supply continuity required

The consumer must estimate the consequences of a supply failure in terms of its duration:

  • Loss of production
  • Safety of personnel and equipment

The utility must give specific information to the prospective consumer.

Project studies

From the information provided by the consumer, the power-supplier must indicate:

The type of power supply proposed and define

  • The kind of power-supply system: overheadline or underground-cable network
  • Service connection details: single-line service, ring-main installation, or parallel
    feeders, etc.
  • Power (kVA) limit and fault current level

The nominal voltage and rated voltage

(Highest voltage for equipment) Existing or future, depending on the development of
the system.

Metering details which define:

  • The cost of connection to the power network
  • Tariff details (consumption and standing charges)


Before any installation work is started, the official agreement of the power-supplier must be obtained. The request for approval must include the following information, largely based on the preliminary exchanges noted above:

  • Location of the proposed substation
  • One-line diagram of power circuits and connections, together with earthing-circuit
  • Full details of electrical equipment to be installed, including performance
  • Layout of equipment and provision for metering components
  • Arrangements for power-factor improvement if eventually required
  • Arrangements provided for emergency standby power plant (HV or LV) if eventually

The utility must give official approval of the equipment to be installed in the substation, and of proposed methods of installation.


When required by the authority, commissioning tests must be successfully completed before authority is given to energize the installation from the power supply system.

After testing and checking of the installation by an independent test authority, a certificate is granted which permits the substation to be put into service.

Even if no test is required by the authority it is better to do the following verification tests:

  • Measurement of earth-electrode resistances
  • Continuity of all equipotential earth-and safety bonding conductors
  • Inspection and testing of all HV components
  • Insulation checks of HV equipment
  • Dielectric strength test of transformer oil (and switchgear oil if appropriate)
  • Inspection and testing of the LV installation in the substation,
  • Checks on all interlocks (mechanical key and electrical) and on all automatic
  • Checks on correct protective-relay operation and settings
    It is also imperative to check that all equipment is provided, such that any properly executed operation can be carried out in complete safety. On receipt of the certificate of conformity (if required):
  • Personnel of the power-supply authority will energize the HV equipment and check
    for correct operation of the metering
  • The installation contractor is responsible for testing and connection of the LV installation
    When finally the substation is operational:
  • The substation and all equipment belongs to the consumer
  • The power-supply authority has operational control over all HV switchgear in the substation, e.g. the two incoming load-break switches and the transformer HV switch (or CB) in the case of a MV switchgear, together with all associated HV earthing switches
  • The power-supply personnel has unrestricted access to the HV equipment
  • The consumer has independent control of the HV switch (or CB) of the transformer(s) only, the consumer is responsible for the maintenance of all substation equipment, and must request the power-supply authority to isolate and earth the switchgear to allow maintenance work to proceed.
    The power supplier must issue a signed permitto- work to the consumers maintenance personnel, together with keys of locked-off isolators, etc. at which the isolation has been carried out.


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Testing performances of IEC 61850 GOOSE messages

Testing performances of IEC 61850 GOOSE messages

One of the frequent requests for relay protection devices is support for the IEC 61850 standard. As part of the standard special messages are also planned for a quick exchange of information between the IEDs – so called  GOOSE (Generic Object-Oriented SubStation Event). These are mainly trip, interlocking, breaker failure and similar signals. Time of transfer of these signals is critical, its delay may cause undesirable blackouts  or damage to equipment.

In this paper we explore which software architecture is most appropriate to achieve the required performance. Software for sending / receiving GOOSE messages can be located in real time (RT) or user space of the operating system. We will consider the RT and user space implementations of two different microprocessor architecture – ARM9 and PowerPC.
Performance degradation can occur from 2 reasons:

  • Protection  function has the highest priority. At least 500 μs during each millisecond GOOSE thread will be deprived of CPU time.
  • In the case of pure user-space implementation, the operating system will interrupt GOOSE task in a completely nondeterministic way.

User Space Test

To test the performance of GOOSE messages in user space, the environment is developed based on the ARM7 architecture:

  • ARM7 with integrated Ethernet for sending, receiving and time-stamping of messages.
  • The PC application for setting parameters and collecting the results.
Figure 1 Test configuration for user space test
Figure 1 Test configuration for user space test

The essence of the test is as follows: ARM7 board launches a series of messages and records the time for each outgoing message. ARM9 and PowerPC boards are set up to immediately respond to received GOOSE messages  with identical message and  with the same serial number.
ARM7 registers  the answer and uses the serial number to match with the original message and calculates the elapsed time.

Figure 2 Analysis time
Figure 2 Analysis time

On the figure above we can see the analysis of time. A and B are negligible. Due to the nature of the test 2C + D  can be accurately measured but we can’t know exactly  the amounts of C and D are respectively. But ultimately this is not important from the point of standards. Let’s look at test results. ARM7 board launches a series of GOOSE messages with pause of 100ms. Results are measured and displayed in Excel.

To make it more realistic result overcurrent protection was turned on.  Y axis shows the time in milliseconds and the X axis shows GOOSE messages.

Figure 3 ARM9 100ms (X axis - number of messages, the Y axis the time of transfer)
Figure 3 ARM9 100ms (X axis – number of messages, the Y axis the time of transfer)

We see that during 20 seconds response time oscillates around 2 milliseconds. The next step was to involve several protection functions. It is expected that the GOOSE performance will drop.

This is actually happening as we see in the following figure:

Figure 4 ARM9 100ms, 700μs (X axis - number of messages, the Y axis the time of transfer)
Figure 4 ARM9 100ms, 700μs (X axis – number of messages, the Y axis the time of transfer)

The time now oscillates about 7 ms. Although it is expected that the performance will decline, it is still above expectations. 7 milliseconds is still enough for some applications. These are the results from the ARM9 platform. PowerPC platform has proved to be something better, because it has almost 2 times more processing power. On the next 2 images we see the results.

Figure 5 PowerPC 100ms (X axis - number of messages, the Y axis the time of transfer)
Figure 5 PowerPC 100ms (X axis – number of messages, the Y axis the time of transfer)

Slika 6. PowerPC 100ms, 700μs (X osa – redni broj poruke, Y osa vreme transfera)
Figure 6 PowerPC 100ms, 700μs (X axis – number of messages, the Y axis the time of transfer)

In a small load time oscillates around 0.8 ms and at most about 2.5 ms. The measured  times are suitable for  a solid range of applications. Unfortunately, these times are only valid if the GOOSE task is only active task. In the case of other tasks – for example, disturbance recorder, event recorder, embedded web server, IEC 61850 MMS server and so on … transfer time become unpredictable and can go up to 80ms, which is of course unacceptable.

Real Time Test

Figure 7 Test configuration for real-time test
Figure 7 Test configuration for real-time test

Although the real time GOOSE is something more difficult to implement, it offers some significant advantages as we shall see. Test environment for real-time is significantly different. The network analyzer was used. The program is available as a free download from the Internet (1). The essence of the test is as follows: protection relays is configured to receive GOOSE messages from a laptop computer and to immediately respond with the same value in the dataset. When analyzing a series of messages network analyzer will come to the moment when the relay and laptops are sending an identical value.
The time between the moment when the laptop starts broadcasting and the moment the relay begins to broadcast the same value as the laptop is the required time.

In the following figure we can see the results displayed in the network analyzer.

Figure 8 Ethereal Network Analyzer
Figure 8 Ethereal Network Analyzer

Figure 9 Goose series with a time of receipt of messages, network addresses and protocol label
Figure 9 Goose series with a time of receipt of messages, network addresses and protocol label

Message number 42 is from a laptop, a message 43 from relay protection. If you subtract the time of receipt: 3.757 to 3.753 = 4msec. When measurements  are repeated result oscillates around 4ms. The reason for this is that the task for sending and receiving is set to be run every 2 milliseconds.


At first glance, real-time and user space implementation operates in a similar timeframe. But there is a substantial difference. GOOSE  RT implementation task may share the processor with an arbitrary number of other task such as the disturbance recorder and others. This architecture greatly reduces the ultimate cost of the device and gives the user more functionality. Otherwise the GOOSE software would have to reside on separate hardware.



Veljko Milisavljević | ABS Control Systems, Serbia

Veljko Milisavljević

Veljko Milisavljević


Related articles

IEC 61850 Standard

International Standard - IEC 61850

The traditional approach to substation integration used standardized RTU protocols that were designed to provide protocol efficiency for operation over bandwidth limited serial links.

While such limitations remain for many applications, substation hardened equipment implementing modern networking standards like Ethernet now provide a cost effective means of enabling high speed communications within the substation.

To truly take advantage of this technology and dramatically lower the total cost of ownership of substation automation systems, a new approach to substation integration that goes beyond a simple RTU protocol is needed.

The recent international standard IEC 61850 proposes a unified solution of the communication aspect of substation automation. However, the standard itself is not easily understood by users other than domain experts. We present our understanding of the IEC 61850 standard as well as the design and implementation of our simulation tool in this report. Also, we give suggestions on the implementation of this standard based on our experience and lessons in the development of our simulation.

1. Introduction

Today, power substations are mostly managed by substation automation systems. These systems employ computers and domain specific applications to optimize the management of substation equipment and to enhance operation and maintenance efficiencies with minimal human intervention [8].

Once upon a time, substation automation systems utilized simple, straightforward and highly specialized communication protocols [7].    These protocols concerned less about the semantics of the exchanged data, data types of which were relatively primitive. Equipment was dumb and systems were simple. However, today’s substation automation systems can no longer enjoy such simplicity because of their growing complexity — equipment becomes more intelligent and most of those simple old systems have been gradually replaced by open systems, which embrace the advantage of emerging technology like relational database systems, multi-task operating systems and support for state-of-the-art graphical display technology.

Besides, devices from different manufacturers used different substation automation protocols [9, 3, 12], disabling them to talk to each other. Utilities have been paying enormous money and time to configure these devices to work together in a single substation. Today most utilities and device manufacturers have recognized the need for a unified international standard to support seamless cooperation among products from different vendors.

The IEC 61850 international standard, drafted by substation automation domain experts from 22 countries, seeks to tackle the aforementioned situation. This standard takes advantage of a comprehensive object-oriented data model and the Ethernet technology, bringing in great reduction of the configuration and maintenance cost. Unlike its predecessor, the Utility Communication Architecture protocol 2.0 (UCA 2.0) [12], the IEC 61850 standard is designed to be capable for domains besides substation automation. To make the new protocol less domain dependent, the standard committee endeavored to emphasize on the data semantics, carving out most of the communication details. This effort, however, could result in difficulties in understanding the standard.

In this research project, we aim to get a clear understanding of the IEC 61850 standard and simulate the protocol based on J-Sim [11]. Our ultimate goal is to investigate the security aspect about the IEC 61850 standard.

2    The IEC 61850 standard

The first release of the IEC 61850 consists of a set of documents of over 1,400 pages. These documents are divided into 10 parts, as listed in Table 1. Part 1 to Part 3 give some general ideas about the standard. Part 4 defines the project and management requirements in an IEC 61850 enabled substation. Part 5 specifies the required parameters for physical implementation. Part 6 defines an XML based language for IED configuration, presenting a formal view of the concepts in the standard. Part 7 elaborates on the logical concepts, which is further divided into four subparts (listed in Table 2). Part 8 talks about how to map the internal objects to the presentation layer and to the Ethernet link layer. Part 9 defines the mapping from sampled measurement value (SMV) to point-to-point Ethernet.

The last part gives instructions on conformance testing. Since Part 7 defines the core concepts of the IEC 61850 standard, we will focus on this part in this report.

7.1.Principles and Models
7.2.Abstract Communication Service Interface
7.3.Common Data Classes
7.4.Compatible Logical Node Classes and Data Classes
Table 2: Subparts of IEC 61850-7

The IEC 61850 standard is not easy to understand for people other than experts in the substation automation domain due to the complexity of the documents and the assumed domain-specific knowledge. Introductory documents on the standard abound [13, 4, 7, 5, 8, 2], but most of them are in the view of substation automation domain experts. Kostic et al. explained the difficulties they had in understanding the IEC 61850 standard [7].

In this section, we provide another experience of understanding this standard, trying to explain the major concepts of the IEC 61850 standard.

2.1 Challenges

Understanding the IEC 61850 standard proposes the following challenges for a outsider of the substation automation domain:

  1. As a substation automation standard proposed by a group of domain experts, the IEC 61850 protocol assumes quite an amount of domain-specific knowledge, which is hardly accessible by engineers and researchers out of the substation automation domain. To make things worse, the terms used in the standard is to some extent different from those commonly used in software engineering, bringing some difficulties for software engineers in reading the standard.
  2. The entire standard, except Part 6, is described in natural language with tables and pictures, which is known to be ambiguous and lack of preciseness. This situation is problematic because the IEC 61850 concepts are defined by more than 150 mutually relevant tables distributed over more than 1,000 pages. A formal presentation of all these concepts would be appreciated.
  3. The experts proposing this protocol come from 22 different countries and are divided into 10 working groups, each responsible to one part of the standard. Due to the different backgrounds and the informal presentation style of the standard, the standard contains a considerable number of inconsistencies. Such inconsistencies are more obvious for different parts of the standard, e.g. the data model described in Part 6 is clearly different from that described in Part 7.
  4. The standard committee made a great effort to describe the protocol in an object-oriented manner but the result is not so object-oriented. For example, the ACSI services are grouped by different classes, but reference to the callee object is not defined as a mandatory argument of the service function.
  5. The standard is designed to be implementation independent but this is not always true. For example, the data attribute TimeAccuracy in Part 7-2 Table 8 is defined as CODED ENUM, while what it virtually represents is a 5-bit unsigned integer; the frequent use of PACKED LIST (i.e. “bit fields” in the C language) also brings implementation details to interface design.
  6. Things are mixed up in the documents. Mandatory components and optional components are mixed in the standard, and domain independent concepts are mixed up with domain specific concepts. Even though the optional components and mandatory ones are marked with “O” and “M” alternatively, it would be a tough task to refine a model consisting only the mandatory components due to the implicit dependences between attributes in different tables and the conditional inclusion of some attributes. In fact, there are 29 common data classes and 89 compatible logical nodes defined in the standard, the relationship among which is unclear.

2.2    Intelligent electronic device

In the past, utility communication standards usually assumed some domain-specific background of the readers. Consequently, they contained a lot of implicit domain knowledge, which is hardly accessible to outsiders (e.g. software engineers) [7]. The IEC 61850 standard does not escape from this category. To help understanding the logical concepts of IEC 61850, we would like to lay a basic idea of intelligent electronic devices (IED), the essential physical object hosting all the logical objects.

Basically, the term intelligent electronic device refers to microprocessor-based controllers of power system equipment, which is capable to receive or send data/control from or to an external source [8]. An IED is usually equipped with one or more microprocessors, memory, possibly a hard disk and a collection of communication interfaces (e.g. USB ports, serial ports, Ethernet interfaces), which implies that it is essentially a computer as those for everyday use.

However, IEDs may contain some specific digital logics for domain-specific processing.
IEDs can be classified by their functions. Common types of IEDs include relay devices, circuit breaker controllers, recloser controllers, voltage regulators etc.. It should be noted that one IED can perform more than one functions, taking advantage of its general-purpose microprocessors. An IED may have an operating system like Linux running in it.

1.Introduction and Overview
3.General Requirements
4.System and Project Management
5.Communication Requirements for Functions and Device .Models
6.Configuration Description Language for Communication in .Electronic Substations Related to IEDs
7.Basic Communication Structure for Substation and Feeder .Equipment
8.Specific Communication Service Mapping (to MMS and to .Ethernet)
9.Specific Communication Service Mapping (from Sampled .Values)
10.Conformance Testing
Table 1: Parts of the IEC 61850 standard documents

2.3 Substation architecture

A typical substation architecture is shown in Figure 1. The substation network is connected to the outside wide area network via a secure gateway. Outside remote operators and control centers can use the abstract communication service interface (ACSI) defined in Part 7-2 to query and control devices in the substation. There is one or more substation buses connecting all the IEDs inside a substation. A substation bus is realized as a medium bandwidth Ethernet network, which carries all ACSI requests/responses and generic substation events messages (GSE, including GOOSE and GSSE).

There is another kind of bus called process bus for communication inside each bay. A process bus connects the IEDs to the traditional dumb devices (merge units, etc.) and is realized as a high bandwidth Ethernet network. A substation usually has only one global substation bus but multiple process buses, one for each bay.

Figure 1: Substation architecture

Figure 1: Substation architecture

ACSI requests/responses, GSE messges and sampled analog values are the three major kinds of data active in the substation network. Since we are less interested in communication on the process buses (like sampled value multicasting), we focus on the activities on the substation bus in this report, especially the ACSI activities.

Interactions inside a substation automation system mainly fall into three categories: data gathering/setting, data monitoring/reporting and event logging.

The former two kinds of interactions are the most important — in the IEC 61850 standard all inquiries and control activities towards physical devices are modeled as getting or setting the values of the corresponding data attributes, while data monitoring/reporting provides an efficient way to track the system status, so that control commands can be issued in a timely manner.

To realize the above kinds of interaction, the IEC 61850 standard defines a relatively complicated communication structure, as is shown in Figure 2.

Figure 2: The communication profiles

Figure 2: The communication profiles

Five kinds of communication profiles are defined in the standard: the abstract communication service interface profile (ACSI), the generic object oriented substation event profile (GOOSE), the generic substation status event profile (GSSE), the sampled measured value multicast profile (SMV), and the time synchronization profile. ACSI services enable client-server style interaction between applications and servers.

GOOSE provides a fast way of data exchange on the substation bus and GSSE provides an express way of substation level status exchange. Sample measured value multicast provides an effective way to exchange data on a process bus.

2.4 Abstract communication service interface

ACSI is the primary interface in the IEC 61850 standard not only because it is the interface via which applications talk with servers, but also in the sense that the ACSI communication channel is an important part of a logical connection between two logical nodes. ACSI defines the semantics of the data exchanged between applications and servers, thus it becomes the major part of the IEC 61850 standard.

The standard committee adopt an object-oriented approach in the design of ACSI, which includes a hierarchical and comprehensive data model and a set of available services for each class in this data model. Although the data model is usually described outside the scope of the ACSI, it is actually part of it. The benefits of using an object-oriented utility communication interface are two fold. On the one hand, objects (e.g. registers) can be referenced in an intuitive way (e.g. “Relay0/MMXU0.voltage”) instead of by the traditional physical address (like Reg#02432). On the other hand, software engineers can build more reliable applications using such service interface.

In the following two sections, we present a brief description on these two ACSI components.

2.5    Data model

The hierarchical data model defined in the IEC 61850 is depicted in Figure 3 and Figure 4.
Server is the topmost component in this hierarchy. It serves as the joint point of physical devices and logical objects. Theoretically one IED may host one or more server instances, but in practice usually only one server instance runs in an IED. A server instance is basically a program running in an IED, which shares the same meaning with other servers like FTP server etc.. Each server has one or more access points, which are the logical representation of a NIC. When a client is to access data or service of the server, it should connect to an access point of this server and establish a valid association.

Each server hosts several files or logical devices. Clients can manipulate files in the server like talking to a FTP server, which is usually used as a means to upload/update the configuration file of an IED. A logical device is the logical correspondence of a physical device. It is basically a group of logical nodes performing similar functions.
Functions supported by an IED are conceptually represented by a collection of primitive, atomic functional building blocks called logical nodes.

The IEC 61850 standard predefines a collection of template logical nodes (i.e. compatible logical nodes) in Part 7-4. Besides the regular logical nodes for functions, the standard also requires every logical device have two specific logical nodes: Logical Node Zero (LN0) and LPHD, which correspond to the logical device and the physical device, alternatively. Besides holding status information of the logical device, LN0 also provides additional functions like setting-group control, GSE control, sampled value control etc..

In the IEC 61850 standard, the entire substation system is modeled as a distributed system consisting of a collection of interacting logical nodes, which are logically connected by logical connections. It should be noted that the term logical connection refers to the logical concept of the connections between two logical nodes, which can be direct or indirect or even a combination of many different kinds of communication channels. In fact, the connection of two logical nodes is usually both indirect and a combination of TCP, UDP and direct Ethernet connections. We will explain logical connections in Section 2.9 (next article).

Data exchanged between logical nodes are modeled as data objects. A logical node usually contains several data objects. Each data object is an instance of the DATA class and has a common data class type.

Figure 3: Hierarchy of the IEC 61850 data model

Figure 3: Hierarchy of the IEC 61850 data model

Similar to the concept of objects in most object-oriented programming languages, a data object consists of many data attributes, which are instances of data attributes of the corresponding common data class. Data attributes are typed and restricted by some functional constraints. Instead of grouping data attributes by data objects, functional constraints provide a way to organize all the data attributes in a logical node by functions. Types of data attributes can be either basic or composite.

Basic types are primitive types in many programming languages, whereas composite types are composition of a collection of primitive types or composite types.
In the IEC 61850 standard, data attributes are at least as important as, if not more than, data objects for two reasons.

Figure 4: The data model of the IEC 61850

Figure 4: The data model of the IEC 61850

Firstly, data objects are just logical collections of the contained data attributes while (primitive) data attributes are the de facto logical correspondence to the physical entities (memory units, registers, communication ports, etc.); secondly, the purpose of data objects is for the convenience of managing and exchanging values of a group of data attributes sharing the same function.

Despite data objects, the IEC 61850 standard provides the concept of data set as another ways to manage and exchange a group of data attributes. Members of a data set can be data objects or data attributes. The concept of data set is somewhat similar to the concept of view in the area of database management systems.

In the IEC 61850 standard, most services involve data sets. Members in a data set unnecessarily come from the same logical node or the same data object, thus providing high flexibility of data management. Data sets are categorized into permanent ones and temporary ones.

Permanent data sets are hosted by logical nodes and will not be automatically deleted unless on the owners’ explicit requests; temporary data sets are exclusively hosted by the association having created them and will be automatically deleted when the association ends.

To be continued soon in next article: IEC 61850 in details (2)


  • Understanding and Simulating the IEC 61850 Standard by Yingyi Liang & Roy H. Campbell, Department of Computer Science University of Illinois at Urbana-Champaign


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8DN8 switchgear for rated voltages up to 72.5 kV

8DN8 switchgear for rated voltages up to 145 kV

A fundamental feature of Siemens gas-insulated switchgear is the high degree of versatility provided by its modular system. Depending on their respective functions, the components are housed either individually and/or combined in compressed gas-tight enclosures. With a remarkably small number of active and passive modules, all customary circuit variants are possible. Sulphur hexafluoride (SF6) is used as the insulating and arc-quenching medium.
Three-phase enclosures are used for type 8DN8 switchgear in order to achieve extremely low component dimensions. This concept allows a very compact design with reduced space requirement. Aluminium is used for the enclosure. This assures freedom from corrosion and results in low weight of the equipment. The use of modern construction methods and casting techniques allows optimizing the enclosure’s dielectric and mechanical character- istics. The low bay weight ensures minimal floor loading and eliminates the need for complex foundations.

All the modules are connected to one another by means of flanges. The gastightness of the flange connections is assured by proven O-ring seals. Temperature-related changes in the length of the enclosure and installation tolerances are compensated by bellows-type expansion joints. To that end, the conductors are linked by coupling contacts. Where necessary, the joints are accessible via manway openings.

Gas-tight bushings allow subdivision of the bay into a number of separate gas compartments. Each gas compartment is provided with its own gas monitoring equipment, a rupture diaphragm, and filter material. The static filters in the gas compartments absorb moisture and decomposition products. The rupture diaphragms prevent build-up of an im- permissible high pressure in the enclosure. A gas diverter nozzle on the rupture diaphragm ensures that the gas is expelled in a defined direction in the event of bursting, thus ensuring that the operating personnel is not endangered.

Three-phase enclosure allows compact design

Three-phase enclosure allows compact design

8DN8 switchgear parts

8DN8 switchgear parts (click to see large)

Circuit-breaker module

The central element of the gas-insulated switchgear is the three-pole circuit-breaker module enclosure comprising the following two main components:

  • Interrupter unit
  • Operating mechanism

The design of the interrupter unit and of the operating mechanism is based on proven and in most cases identical designs, which have often been applied for outdoor switchgear installations.

Operating mechanism

The spring-stored energy operating mechanism provides the force for opening and closing the circuit-breaker. It is installed in a compact corrosion- free aluminium housing. The closing spring and the opening spring are arranged so as to ensure good visibility in the operating mechanism block. The entire operating mechanism unit is completely isolated from the SF6 gas compartments. Anti-friction bearings and a maintenance-free charging mechanism ensure decades of reliable operation.
Proven design principles of Siemens circuit-breakers are used, such as vibration-isolated latches and load-free decoupling of the charging mechanism. The operating mechanism offers the following advantages:

  • Defined switching position which is securely maintained even if the auxiliary power supply fails
  • Tripping is possible irrespective of the status of the closing spring
  • High number of mechanical operations
  • Low number of mechanical parts
  • Compact design
Three-position switching device


The functions of a disconnector and an earthing switch are combined in a three-position switching device. The moving contact either closes the isolating gap or connects the high-voltage conductor to the fixed contact of the earthing switch. Integral mutual inter- locking of the two functions is achieved as a result of this design, thus obviating the need for providing corresponding electrical interlocking within the switchgear bay. An insulated connection to the fixed contact of the earthing switch is provided outside the enclosure for test purposes. In the third neutral position neither the disconnector contact nor the earthing switch contact is closed. The three poles of a bay are mutually coupled and all the three poles are operated at once by a motor. Force is transmitted into the enclosure via gas-tight rotating shaft glands. The check-back contacts and the on-off indicators are mechanically robust and are connected directly to the operating shaft. Emergency operation by hand is possible. The enclosure can be provided with inspec- tion windows, in the case of which the “On” and “Off” position of all three phases is visible.

Outgoing feeder module

The outgoing feeder module connects the basic bay with various termination modules (for cable termi- nation, overhead line termination and transformer termination). It contains a three-position switching device, which combines the functions of an outgoing feeder disconnector and of a bay-side earthing switch (work-in-progress type). Installation of a high-speed earthing switch and of a voltage transformer is also possible where required. The high-voltage site testing equipment is generally connected to this module.

Busbar module

Connections between the bays are effected by means of busbars. The busbars of each bay are enclosed. Adjacent busbar modules are coupled by means of expansion joints. The module contains a three-position switching device, which combines the functions of a busbar disconnector and of a bay-side earthing switch (work-in-progress type).

Bus sectionalizers

Bus sectionalizers are used for isolating the busbar sections of a substation. They are integrated in the busbar in the same manner as a busbar module. The module contains a three-position switching device, which combines the functions of a bus sectionalizer and of an earthing switch (work-in-progress type).

High-speed earthing switch

The high-speed earthing switch used is of the so-called “pin-type”. In this type of switch, the earthing pin at earth potential is pushed into the tulip-shaped fixed contact. The earthing switch is equipped with a spring-operated mechanism, charged by an electric motor.

Proven switchgear control

All the elements required for control and monitoring are accommodated in a decentralized arrangement in the high-voltage switching devices. The switching device control systems are factory-tested and the switchgear is usually supplied with bay-internal cabling all the way to the integrated local control cubicle. This minimizes the time required for com- missioning and reduces the possibilities of error.
By default, the control and monitoring system is implemented with electromechanical components. Alternatively, digital intelligent control and pro- tection systems including comprehensive diagnos- tics and monitoring functions are available. More detailed information on condition of the substation state permits condition-based maintenance. This consequently reduces life cycle costs even further.

Gas monitoring

Each bay is divided into functionally distinct gas compartments (circuit-breaker, disconnector, voltage transformer, etc.). The gas compartments are con- stantly observed by means of density monitors with integrated indicators; any deviations are indicated
as soon as they arrive at the defined response thresh- old. The optionally available monitoring system includes sensors that allow remote monitoring and trend forecasts for each gas compartment.

Flexible and reliable protection in bay and substation control

Control and feeder protection are generally accom- modated in the local control cubicle, which is itself integrated in the operating panel of the switchgear bay. This substantially reduces the amount of time and space required for commissioning. Alternatively, a version of the local control cubicle for installation separate from the switchgear is available. Thus, different requirements with respect to the arrange- ment of the control and protection components are easy to meet. The cabling between the separately installed local control cubicle and the high-voltage switching devices is effected via coded plugs, which minimizes both the effort involved and the risk of cabling errors.
Of course we can supply high-voltage switchgear with any customary bay and substation control equipment upon request. We provide uniform systems to meet your individual requirements.

Left: Spring-stored energy operting mechanism; Right: Integrated local control cubicle

Left: Spring-stored energy operting mechanism; Right: Integrated local control cubicle

Neutral interfaces in the switchgear control allow interfacing

  • conventional control systems with contactor interlocking and control panel
  • digital control and protection comprising user- friendly bay controllers and substation auto- mation with PC operator station (HMI)
  • intelligent, uniformly networked digital control and protection systems with supplementary monitoring and telediagnostics functions.

Given the wide range of Siemens control and protection equipment, we can provide customized concepts with everything from a single source.

Technical Data
.Switchgear type.8DN8
.Rated voltage.72.5 / 145 kV
.Rated frequency.50 / 60 Hz
.Rated power frequency withstand voltage (1 min).140 / 275 kV
.Rated lightning impulse withstand voltage (1.2/50 μs).325 / 650 kV
.Rated normal current busbar
.Rated normal current feeder
.2500 / 3150 A
.2500 / 3150 A
.Rated short-breaking current.31.5 / 40 kA
.Rated peak withstand current.85 / 108 kA
.Rated short-time withstand current.31.5 / 40 kA
.Leakage rate per year and gas compartment.≤ 0.5 %
.Bay width.650/800/1200 mm
.Height, depth.see typical bay arrangements
.Driving mechanism of circuit-breaker.stored-energy spring
.Rated operating sequence.O-0.3 s-CO-3 min-CO
.CO-15 s-CO
.Rated supply voltage.60 to 250 V DC
.Expected lifetime.> 50 years
.Ambient temperature range.–30 / –25 °C up to +40 °C
.Standards.IEC / IEEE
Operation and maintenance

Siemens gas-insulated switchgear is designed and manufactured so as to achieve an optimal balance of design, materials used and maintenance required. The hermetically-sealed enclosures and automatic monitoring ensure minimal switchgear mainte- nance: The assemblies are practically maintenance- free under normal operating conditions. We re- commend that the first major inspection be carried out after 25 years.


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Transformator shot with thermovision camera

Transformator shot with thermovision camera

Substation ventilation is generally required to dissipate the heat produced by transformers and to allow drying after particularly wet or humid periods. However, a number of studies have shown that excessive ventilation can drastically increase condensation. Ventilation should therefore be kept to the minimum level required. Furthermore, ventilation should never generate sudden temperature variations that can cause the dew point to be reached. For this reason: Natural ventilation should be used whenever possible. If forced ventilation is necessary, the fans should operate continuously to avoid temperature fluctuations. Guidelines for sizing the air entry and exit openings of substations are presented hereafter.

Calculation methods
Natural ventilation

Natural ventilation

A number of calculation methods are available to estimate the required size of substation ventilation openings, either for the design of new substations or the adaptation of existing substations for which condensation problems have occurred.

The basic method is based on transformer dissipation. The required ventilation opening surface areas S and S’ can be estimated using the following formulas:


S = Lower (air entry) ventilation opening area [m2] (grid surface deducted)
S’= Upper (air exit) ventilation opening area [m2] (grid surface deducted)
P = Total dissipated power [W]
P is the sum of the power dissipated by:

  • The transformer (dissipation at no load and due to load)
  • The LV switchgear
  • The MV switchgear

H = Height between ventilation opening mid-points [m]

This formula is valid for a yearly average temperature of 20 °C and a maximum altitude of 1,000 m.
It must be noted that these formulas are able to determine only one order of magnitude of the sections S and S’, which are qualified as thermal section, i.e. fully open and just necessary to evacuate the thermal energy generated inside the MV/LV substation. The pratical sections are of course larger according ot the adopted technological solution.

Indeed, the real air flow is strongly dependant:

  • on the openings shape and solutions adopted to ensure the cubicle protection index (IP): metal grid, stamped holes, chevron louvers,…
  • on internal components size and their position compared to the openings: transformer and/or retention oil box position and dimensions, flow channel between the components, …
  • and on some physical and environmental parameters: outside ambient temperature, altitude, magnitude of the resulting temperature rise.

The understanding and the optimization of the attached physical phenomena are subject to precise flow studies, based on the fluid dynamics laws, and realized with specific analytic software.


Transformer dissipation = 7,970 W LV switchgear dissipation = 750 W MV switchgear dissipation = 300 W The height between ventilation opening mid-points is 1.5 m.


Dissipated Power P = 7,970 + 750 + 300 = 9,020 W

Ventilation opening locations

To favour evacuation of the heat produced by the transformer via natural convection, ventilation openings should be located at the top and bottom of the wall near the transformer. The heat dissipated by the MV switchboard is negligible. To avoid condensation problems, the substation ventilation openings should be located as far as possible from the switchboard.

«Over» ventilated MV/LV Substation

«Over» ventilated MV/LV Substation. The MV cubicle is subjected to sudden temperature variations.

Substation with adapted ventilation

Substation with adapted ventilation. The MV cubicle is no longer subjected to sudden temperature variations.

If the MV switchboard is separated from the transformer, the room containing the switchboard requires only minimal ventilation to allow drying of any humidity that may enter the room.

Type of ventilation openings

To reduce the entry of dust, pollution, mist, etc., the substation ventilation openings should be equipped with chevron-blade baffles. Always make sure the baffles are oriented in the right direction.

MV cubicle ventilation

Any need for natural ventilation is taken into account by the manufacturer in the design of MV cubicles. Ventilation openings should never be added to the original design.

Instruction: Medium Voltage equipment on sites exposed to high humidity and/or heavy pollution by Schneider Electric


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Air Insulated Substations

Air Insulated Substations

Various factors affect the reliability of a substation, one of which is the arrangement of the switching devices. Arrangement of the switching devices will impact maintenance, protection, initial substation development, and cost. There are six types of substation bus switching arrangements commonly used in air insulated substations:
1. Single bus
2. Double bus, double breaker
3. Main and transfer (inspection) bus
4. Double bus, single breaker
5. Ring bus
6. Breaker and a half

1. Single Bus Configuration

Single Bus Configuration

Single Bus Configuration

This arrangement involves one main bus with all circuits connected directly to the bus. The reliability of this type of an arrangement is very low. When properly protected by relaying, a single failure to the main bus or any circuit section between its circuit breaker and the main bus will cause an outage of the entire system. In addition, maintenance of devices on this system requires the de-energizing of the line connected to the device. Maintenance of the bus would require the outage of the total system, use of standby generation, or switching to adjacent station, if available. Since the single bus arrangement is low in reliability, it is not recommended for heavily loaded substations or substations having a high availability requirement. Reliability of this arrangement can be improved by the addition of a bus tiebreaker to minimize the effect of a main bus failure.

2. Double Bus, Double Breaker Configuration

Double bus, double breaker

Double bus, double breaker

This scheme provides a very high level of reliability by having two separate breakers available to each circuit. In addition, with two separate buses, failure of a single bus will not impact either line. Maintenance of a bus or a circuit breaker in this arrangement can be accomplished without interrupting either of the circuits. This arrangement allows various operating options as additional lines are added to the arrangement; loading on the system can be shifted by connecting lines to only one bus. A double bus, double breaker scheme is a high-cost arrangement, since each line has two breakers and requires a larger area for the substation to accommodate the additional equipment. This is especially true in a low profile configuration. The protection scheme is also more involved than a single bus scheme.

3. Main and Transfer Bus Configuration

Main and transfer bus configuration

Main and transfer bus configuration

This scheme is arranged with all circuits connected between a main (operating) bus and a transfer bus (also referred to as an inspection bus). Some arrangements include a bus tie breaker that is connected between both buses with no circuits connected to it. Since all circuits are connected to the single, main bus, reliability of this system is not very high. However, with the transfer bus available during maintenance, de-energizing of the circuit can be avoided. Some systems are operated with the transfer bus normally de-energized. When maintenance work is necessary, the transfer bus is energized by either closing the tie breaker, or when a tie breaker is not installed, closing the switches connected to the transfer bus. With these switches closed, the breaker to be maintained can be opened along with its isolation switches. Then the breaker is taken out of service. The circuit breaker remaining in service will now be connected to both circuits through the transfer bus. This way, both circuits remain energized during maintenance. Since each circuit may have a different circuit configuration, special relay settings may be used when operating in this abnormal arrangement.

When a bus tie breaker is present, the bus tie breaker is the breaker used to replace the breaker being maintained, and the other breaker is not connected to the transfer bus. A shortcoming of this scheme is that if the main bus is taken out of service, even though the circuits can remain energized through the transfer bus and its associated switches, there would be no relay protection for the circuits. Depending on the system arrangement, this concern can be minimized through the use of circuit protection devices (reclosure or fuses) on the lines outside the substation.
This arrangement is slightly more expensive than the single bus arrangement, but does provide more flexibility during maintenance. Protection of this scheme is similar to that of the single bus arrangement. The area required for a low profile substation with a main and transfer bus scheme is also greater than that of the single bus, due to the additional switches and bus.

4. Double Bus, Single Breaker Configuration

Double bus, single breaker configuration

Double bus, single breaker configuration

This scheme has two main buses connected to each line circuit breaker and a bus tie breaker. Utilizing the bus tie breaker in the closed position allows the transfer of line circuits from bus to bus by means of the switches. This arrangement allows the operation of the circuits from either bus. In this arrangement, a failure on one bus will not affect the other bus. However, a bus tie breaker failure will cause the outage of the entire system. Operating the bus tie breaker in the normally open position defeats the advantages of the two main buses. It arranges the system into two single bus systems, which as described previously, has very low reliability. Relay protection for this scheme can be complex, depending on the system requirements, flexibility, and needs. With two buses and a bus tie available, there is some ease in doing maintenance, but maintenance on line breakers and switches would still require outside the substation switching to avoid outages.

5. Ring Bus Configuration

Ring bus configuration

Ring bus configuration

In this scheme, as indicated by the name, all breakers are arranged in a ring with circuits tapped between breakers. For a failure on a circuit, the two adjacent breakers will trip without affecting the rest of the system. Similarly, a single bus failure will only affect the adjacent breakers and allow the rest of the system to remain energized. However, a breaker failure or breakers that fail to trip will require adjacent breakers to be tripped to isolate the fault. Maintenance on a circuit breaker in this scheme can be accomplished without interrupting any circuit, including the two circuits adjacent to the breaker being maintained. The breaker to be maintained is taken out of service by tripping the breaker, then opening its isolation switches. Since the other breakers adjacent to the breaker being maintained are in service, they will continue to supply the circuits. In order to gain the highest reliability with a ring bus scheme, load and source circuits should be alternated when connecting to the scheme. Arranging the scheme in this manner will minimize the potential for the loss of the supply to the ring bus due to a breaker failure. Relaying is more complex in this scheme than some previously identified. Since there is only one bus in this scheme, the area required to develop this scheme is less than some of the previously discussed schemes. However, expansion of a ring bus is limited, due to the practical arrangement of circuits.

6. Breaker-and-a-Half Configuration

Breaker and a half configuration

Breaker and a half configuration

The breaker-and-a-half scheme can be developed from a ring bus arrangement as the number of circuits increases. In this scheme, each circuit is between two circuit breakers, and there are two main buses. The failure of a circuit will trip the two adjacent breakers and not interrupt any other circuit. With the three breaker arrangement for each bay, a center breaker failure will cause the loss of the two adjacent circuits. However, a breaker failure of the breaker adjacent to the bus will only interrupt one circuit.

Maintenance of a breaker on this scheme can be performed without an outage to any circuit. Further- more, either bus can be taken out of service with no interruption to the service. This is one of the most reliable arrangements, and it can continue to be expanded as required. Relaying is more involved than some schemes previously discussed. This scheme will require more area and is costly due to the additional components.

Table of configurations
ConfigurationReliabilityCostAvailable area
.Single busLeast reliable — single failure can cause complete outageLeast cost — fewer componentsLeast area — fewer components
.Double busHighly reliable — duplicated components; single failure normally isolates single componentHigh cost — duplicated componentsGreater area — twice as many components
.Main bus and .transferLeast reliable — same as
Single bus, but flexibility in operating and maintenance with transfer bus
Moderate cost — fewer componentsLow area requirement —  fewer components
.Double bus, .single breakerModerately reliable — depends on arrangement of components and busModerate cost — more componentsModerate area — more components
.Ring busHigh reliability — single failure isolates single componentModerate cost — more componentsModerate area — increases with number of circuits
.Breaker and a.halfHighly reliable — single circuit failure isolates single circuit, bus failures do not affect circuitsModerate cost — breaker-and-a-half for each circuitGreater area — more components per circuit


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