automation
9.1 Overview
Power system automation, as defined in this manual, is illustrated in Figure 9.1. Datacommunications is the core of a power system automation system. Withoutcommunications the whole system will collapse. The role and requirements ofcommunications for each segment in the context of power system automation is nowanalyzed.
Figure 9.1
Power system automation
120Practical Electrical Network Automation and Communication Systems9.2 Configuration
The typical power system automation configuration is illustrated in Figure 9.2.
Figure 9.2
Typical power system automation structure
• The process level consists of the equipment providing information to the baylevel, e.g. instrument transformers, temperature sensors, auxiliary contacts ofcircuit-breakers, etc. The application process is therefore a voltage, current,temperature, breaker status, etc.
• The equipment executing a command from the bay level, e.g. trip coil ofcircuit-breaker. The application process is then the command ‘open breaker’.• The bay level consists of four main application processes (APs): protection,control, measurement/metering, and monitoring. These APs can reside indifferent devices, or all in one device (the typical IED), as discussed inChapter 5.
• The station level consists of the station SCADA (optional) and possibly agateway or communications processor. The importance of the station SCADAwill depend on the specific application. In large transmission substations, thiswill form the main SCADA for the specific substation, with several SCADAsystems forming a network. On the other hand, for a distribution substation,the station SCADA may be dispensed with, and only a gateway will berequired to connect the substation to the network and to the main SCADA.
Communications in power system automation121
• The gateway is usually some form of communications processor, star coupleror such, depending on the vendor’s system.
• The network level may consist of a central SCADA, to which each substationis connected, and/or a LAN, MAN, WAN or the Internet.
9.3 Communication requirements
The communication requirements for the various applications in power system
automation will be evaluated in this section according to the following attributes:PerformanceSpeed/DatathroughputResponse timeTimeSynchronizationAvalancheHandlingData IntegrityLink AvailabilityData PriorityLow<10 kbps>1 s1 sNo data through-put requiredduring avalancheSome errorsallowedAll data can waituntil link availableCan be sent afterall other dataMedium>10 kbps< 1 Mbps<1 s>10 ms1 ms ± 0.1 msSome datathrough-putrequiredLimited errorsallowedSome data canwait for a limitedtimeTo be sent afterhigh priority data;can wait forrequestHigh>1 Mbps< 0 ms1 µs ± 0.5 µsAll data through-put requiredNo errors allowedNo data can waitTo be sentimmediately;cannot wait forrequestTable 9.1
Communication requirements
9.3.1 Protection
Electrical protection has always functioned independently on the bay level, and that ishow it should stay. Protection needs to be fast, reliable and secure. In the early 1990sthere have been some proposals to move protection to a network level. Thankfully, it wasrealized, mainly by protection engineers, that a network level could not support thestringent requirements of protection, and these proposals died a natural death.
Nowadays, with communication networks becoming faster, more reliable, more secureand more powerful by the day, there is again periodic, although tentative, suggestions toconsider providing protection on a network level. Fortunately, no switchgear or relaymanufacturer is seriously considering this at present.
Protection functions have been traditionally provided by electromechanical relays, withone relay dedicated for one function. Digital relays opened the way for multi-functionrelays, with more than one protection function in one device. Today, IEDs provideprotection functions together with control functions, measurement, monitoring and
122Practical Electrical Network Automation and Communication Systemscommunications. This is making some protection engineers nervous, and many of themprefer to have protection and control functions in different devices. The advantages anddisadvantages of this approach are discussed in detail in Chapter 11.
The fact is that protection is often not the dedicated function of one or more devicesanymore; therefore it is more appropriate to view protection as an application, rather thana hardware device.
A.Lower Level
The field information to the protection application is provided by the instrumenttransformers (mainly) and other electrical transducers. This information has always beenprovided as analog values in the form of current and voltage. The instrument transformersand other equipment are hardwired to the input terminals of the protection device.
The concept of ‘smart instruments’, i.e. field instruments that have local intelligenceand advanced communication capabilities, has also influenced the electrical industry.Instrument transformers and other electrical transducers have been developed that convertthe analog values into a data message, to be sent over a serial communication bus to theprotection AP (typically using fiber-optic).
The following are the advantages and disadvantages of having a digital communicationbus between the process level and the bay level, compared to the conventional hardwiredmethod:
Advantages
• Huge reduction in wiring, as all the input information can be sent via onefiber-optic cable, replacing a multitude of copper wiring.
• Eliminating the risk of faulty wiring and/or loose connections.• Reducing the risk of human error, e.g. to open-circuit a CT.
• The field information can be easily made available to more than one AP(instead of having, for example, one set of CTs for each function).
• Eliminating the risk that high electrical transients can damage equipment.
• Intelligent field information bus with self-supervision and fault diagnosticcapabilities.
Disadvantages
• More complex to configure and maintain
• Higher risk that ‘something can go wrong’, compromising the reliability ofthe protection scheme• Inherent time delay
• Compatible equipment required• Higher initial costAlthough data communications do not commonly apply to the process or lower level asyet regarding electrical substations (as this level constitutes mainly the direct electricalvalues of voltages and currents), the very near future will see data communications beingutilized on this level more and more.
Therefore, it is appropriate to examine the requirements that will apply to this level.Herewith follows the requirements for communications on the lower level concerning theprotection application:
Communications in power system automation123
Requirements
PerformanceSpeed/Data throughputResponse timeTime synchronizationAvalanche handlingData integrityLink availabilityData priorityLevel requiredHighHighHighHighHighHighHighNotes:
• Very high response times are required for some protection schemes, e.g.differential and distance protection.
• Very high time synchronization is required for distance protection,synchronizing check, etc.
As can be seen, a high level (minimum) is required from all the performance attributes.This is due to the fact that immediate and absolute reliable information is needed for theprotection scheme to function correctly, effectively and reliably.
This stringent requirements for this communication level will probably see to it thatconventional wired systems will still be predominantly used for a long time, especially indistribution applications, both due to high initial cost and scepticism among protectionengineers that the requirements will not be met by having a data communication link onthis level.
Protection schemes like differential protection, busbar protection, etc must rely onpoint-to-point communications and not communications in a ‘public domain’.
B. Higher level
This is the communication level from the protection AP to the station or central SCADA.The protection AP performs its functions independent from the SCADA. Informationsend to the SCADA will include disturbance records, event records, and statusinformation. Information from the SCADA to the protection AP will include programconfiguration and protection settings data.
Requirements
PerformanceSpeed/Data throughputResponse timeTime synchronizationAvalanche handlingData integrityLink availabilityData priorityExplanatory notes:Level requiredLowLowHighLowHighLowLow• The requirements for speed, response time, avalanche handling, data priorityand link availability are low, as the information required is stored in the IEDand can be retrieved again. The information is usually not of an urgent nature.Similarly, data from the SCADA to the IED, like protection settings, is nothigh priority.
124Practical Electrical Network Automation and Communication Systems• Time synchronization is high to aid in sequence-of-event recordings.
• Data integrity is high as no corruption of critical data, like protection settings,can be allowed.
9.3.2 Control
Traditionally, substation control has been utilized exclusively in large transmissionsubstations. This has been achieved with a huge amount of hardwiring to a central RTU.The station RTU then communicates to a SCADA system, forming the only level of datacommunications in a substation monitoring and control system.
Control has now been moved to the bay level with power system automation. Controlmay be executed by a dedicated bay controller, or may take the form of control functionblocks in an IED, alongside the protection, monitoring and measurement function blocks.(The advantages and disadvantages of each are discussed in Chapter 11.) As withprotection, control functions will be seen as an application, rather than a device.
Local control is executed on the lower communication level (between the bay level andthe process level), and remote control is dependent on the higher communications level(between the bay level and the station/network level).
A.Lower level
The information needed from the field for the control application is mainly limited tostatus of switchgear (open/close type digital inputs). This is provided by hardwiring theauxiliary contacts of the switchgear to the input terminals of the control device. Thisinformation will possibly be provided in future on a communications bus (shared withprotection information) to create a ‘wireless’ switchgear panel. This will mostly bebeneficial where the bay controller is located some distance away from the switchgear,e.g. in a high voltage switchyard. In a typical distribution type switchgear panel, wherethe bay controller is located within cms from the actual switch, hardwiring will still be themost sensible option.
Requirements
PerformanceSpeed/data throughputResponse timeTime synchronizationAvalanche handlingData integrityLink availabilityData priorityLevel requiredHighHighHighHighHighHighHighNote:
All the requirements are high, as certain local control commands, for example open acircuit-breaker due to the occurrence of a critical event, can have the same priority as aprotection-initiated command.
B. Higher Level
This is the communication level from the control AP to the station or central SCADA.The local control and remote control applications are interdependent, with muchinformation shared between them. Information sent from the bay level control AP to theSCADA will include status information, command acknowledgment, and protection lock-
Communications in power system automation125
out information. Data sent from the SCADA to the control AP will include programconfiguration and specific commands.Requirements
PerformanceSpeed/data throughputResponse timeTime synchronizationAvalanche handlingData integrityLink availabilityData priorityLevel requiredMedium to High 1Medium to High 1HighHighHighMedium to High 1HighExplanatory notes:
• The requirements for speed, response time and link availability will bemedium to high, depending on the criticality of the data. ‘Normal’ data willgenerally be medium, whereas the requirements for critical data, for examplein an inter-bay interlocking scheme, will be high.
• The requirement for time synchronization will be high for sequence-of-eventreports.
• Avalanche handling, data integrity and data priority will be high as generallyall control commands and related data to/from the SCADA must receive firstpriority in all circumstances, without compromising integrity.
9.3.3 Measurements
Measurements may include electrical measurements, such as voltages, currents, power,power factor and harmonics, as well as other analog values obtained from transducers,e.g. transformer and motor temperatures.
Traditionally, different sets of CTs are used for protection and metering applications.However, IEDs in a power system automation system use only one set of CTs for bothapplications. Therefore, CTs should be used which are accurate enough for bothapplications. Most manufacturers’ IEDs will guarantee an accuracy of 0.5% or betterfrom 1% to 600% of FLC. If a higher accuracy is required, e.g. for electricity billingpurposes, a dedicated metering system should be employed, and the metering informationcould still be sent to the SCADA through the power system automation communicationssystem. Dedicated metering devices have powerful data storage and processingcapabilities, and updated information would be sent through to the SCADA, rather thanraw data.
A.Lower level
This is the raw input from the field instruments (e.g. CTs, VTs, temperature transducers,etc) to the measuring application. The same instruments may be shared with theprotection application, or separate dedicated metering instruments may be used. Themetering device may send its information to the IED or directly to the SCADA (whichwould normally be the case). Measurement data in the context of power systemautomation is for information and alarm purposes only, and is not needed for the controlor protection applications. When the latter is the case, the protection and/or controlapplications will obtain the data directly from the field instruments as an input to theirfunction blocks.
126Practical Electrical Network Automation and Communication SystemsRequirements
When the measurement application shares the same field instruments with the protectionapplication, the communication requirements as discussed in section. 9.3.1 will berelevant, for the lower level communication requirements will always be higher forprotection than for measurement information.
If separate field instruments and metering equipment were used, the following tablewould be relevant:
PerformanceSpeed/data throughputResponse timeTime synchronizationAvalanche handlingData integrityLink availabilityData priorityLevel requiredLowLowLowLowLowLowLowNote:
All requirements are low, as the data is for information and non-critical alarm purposesonly. This does not mean that the data may be discarded. It is still required, but as a lowerpriority to the other applications. Data errors will be corrected the next time theinformation is updated, which will usually be within seconds.
B.Higher level
Measurement information will be sent through to the SCADA, either by the IED, or byother dedicated devices capable of communicating on the network. IEDs and otherdevices will generally have sufficient data storage capacity, so that data can be storedwhen the communication link to the SCADA is not available, and send when the linkbecomes available again.
PerformanceSpeed/data throughputResponse timeTime synchronizationAvalanche handlingData integrityLink availabilityData priorityLevel requiredLowLowLowLowLowLowLow9.3.4 Monitoring information
Monitoring refers to information such as switchgear status (those not used directly as
inputs by the local control application), trip circuit status, condition monitoringinformation, maintenance information, etc. The urgency of this information is generallyconsidered as low, and can be sent through as soon as the communication link allows it.This information will normally be used to generate alarms and event records (notsequence-of-event reports of important information, which will be part of the protectionor control function blocks).
Monitoring information of high priority will usually constitute inputs directly to thecontrol or protection applications.
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A.Lower level
This is the information from the switchgear and other monitored devices (e.g. a batterytripping unit) to the monitoring application. Some of the information is assembled by theIED itself, e.g. trip circuit supervision, trip operation counters, etc. Other information isusually in the form of digital inputs to the IED.Requirements
PerformanceSpeed/data throughputResponse timeTime synchronizationAvalanche handlingData integrityLink availabilityData priorityB.Higher level
Level requiredLowLowLowLowLowLowLowThis is the level from the monitoring application to the SCADA.RequirementsPerformanceSpeed/data throughputResponse timeTime synchronizationAvalanche handlingData integrityLink availabilityData priorityLevel requiredLowLowLowLowLowLowLow9.4 Example of Requirements
Table 9.2 is an example of requirements that will be applicable to a typical distribution
substation.
ExampleEvent recordingsAlarmingCommandInterlocking BLOCKInterlocking RELEASEDiff protection TRIPParameter setFault analysisResponse Time1–20 ms1 s0.5 s<10 ms1 s1–5 ms3 s>1 minData IntegrityLowMediumHighHighHighHighMediumLowTable 9.2
Example of communication requirements in a substation
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