24417931 substation automation architecture a brief over view

8/2/2019 24417931 Substation Automation Architecture a Brief Over View

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GUIDELINES FOR SELECTION OF EFFECTIVE

SUBSTATION AUTOMATION ARCHITECTURE

(- by Javed Ahmed)

1.0 INTRODUCTION

In a Substation, various tasks are performed such as Control, Protection, Metering & Monitoring, Tele-Protection with remote Substations, Tele-metering to & Tele-control from Regional/National ControlCenters or Power Dispatch Centers.

A Substation Automation System (SAS) performs Control, Protection, Metering & Monitoring functionsusing Intelligent Electronic devices (IEDs) which digitally communicate with each other to perform thesetasks in a coordinated & efficient way. By efficient way here means these IEDs are interoperable (i.e.information from one IED to another follows open protocol) and every IED in a SAS can practically accessinformation from any other IED(s).

A SAS is presently limited to performing tasks within a Substation. This system is fairly safe since SAS

performs functions which are based on information available locally in the IEDs within the Substation itselfand no external communication or interaction is required. Certain tasks or functions such as Tele-Protection & Tele-Control (requiring external communication to Remote Substation & Control Centers etc)do not form part of a SAS. Even though, such task or function is also performed by the same IED(s)(which are part of SAS) by using communication system external to SAS.

This means a function/task within a SAS can be performed by exchanging data/information between theLogical Nodes within the Substation itself (Logical Nodes of another remote Substation SAS do notcommunicate with Logical Nodes of Local Substation SAS and two SAS do not communicate with eachother). Eventually, such a system will become standard.

Typical example is a Line Differential Protection. The Line Differential Protection function for aTransmission Line is performed by comparing Local measured Currents with Currents measured at

Remote Substation(s) flowing in to or out of the Line. However, only local Line Differential ProtectionIED(s) form part of the Local SAS system and not remote Substation IED(s). This implies that exchangeof these Local/remote currents between IEDs (Local & Remote) are not bound by SAS and treated asexternal to SAS.

Theoretically, Local & Remote Line Differential IEDs may be connected by dedicated direct fiber-link butstill that communication is not covered under a SAS [Line Differential protection is defined as a LogicalNode in SAS].

Similarly, a Gateway RTU within a Substation may be part of SAS (being connected to the same LocalSAS Station bus) but communication from Control Center to Station RTU is external to SAS and ControlCenter HMI will not form part of local SAS. Where as a local HMI connected with Local RTU on theStation bus is part of Local SAS.

Bottom line of this is SAS boundary is Local Substation.

From above, it can be concluded that Communication system within a SAS is fairly safe (since all externalto Substation communications are excluded). Due to this, problems like access denial, congestion, failureof external third party communication links are eliminated (limited problems may arise which can beminimized by design). One problem is there though which communication technology. Presently,Communication technology is growing at rapid rate due to extreme miniaturization of hardware, extensiveR&D in consumer Video/Audio and associated open system Protocols. This problem is overcome in SASby defining ACSI and mapping it to Specific communication Protocol stalk.


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Therefore, it is necessary to distinguish & design communication systems as communication which formspart of SAS & communication which are external to SAS. Separate design & Engineering process isrequired to deal with local SAS and for Tele-Protection, Tele-Metering & Tele-Control to remote placesexternal to the Local Substation.

2.0 COMMUNICATION SYSTEM FOR SAS

A SAS consists of intelligent Electronic Devices (IEDs) with Logical Nodes which are in continuouscommunication to fulfill the assigned tasks. These communications involves broadcast of piece ofinformation such as status, system condition, system configuration, measured data, computed data,commands etc in digital form. These are automatically being carried out.

Consider an example of a Traditional Distance Protection with built-in Directional Earth fault Protection(DEF) and an IED Distance Protection with built-in DEF. Both of these Protections perform the same job.

However, in case of IED Distance Protection with built-in DEF, the Distance Protection function & DEFProtection function are two separate Logical Nodes (namely PDIS & PDEF) and the outputs and status ofthese two Logical Nodes are separately accessible to all IEDs in the SAS. In Traditional Distance

Protection with built-in (DEF) such an information was not mandatory.

IEC 61850 based SAS does not standardize the IEDs but standardize only Logical Nodes. This is in orderto allow for Users preference, philosophy and application requirement.

Thus a Distance Protection IED from one Manufacturer (let us call as Main-1 in a specific line application)may contain PDIS, PDEF, PIOC, PDOC, PTOC Logical Nodes while a Distance Protection IED fromanother Manufacturer (let us call as Main-2 in the same application) may contain PDIS, PDEF, PTOVLogical Nodes. As long as two IEDs are not identical 100% interchangeability is not possible butinteroperability is possible as information from each Logical Node is accessible to other Logical Nodes inthe SAS and Flexible Logics can be built in each IED to make both behave in same pattern. Thusinformation from PTOV of Main-2 may be used in Main-1 and Flexible Logic built inside IED-1 to performa task exactly like performed in Main-2. This is a major benefit in a SAS. Similarly, Digital CTs & VTs also

forms also forms as part of SAS (Logical Nodes TCTR & TVTR) and can be used by any Protection IEDwithout any physically connection to CTs & VTs yet perform function similar to another Protection IEDwith physical connection to CTs & VTs as TCTR & TVTR are logical nodes and they can communicatewith any Logical node in any IED (say PDIS logical node of an IED without physical CT & VT input canuse this TCTR & TVTR data to perform Distance Protection function).

It becomes therefore essential to have a SAS Engineering process performed to optimally use theTechnology to make a reliable and safe substation. SAS therefore requires an efficient and reliableCommunication system.

In order for SAS to be fail-proof and future proof, IEC 61850 defines use of Abstract CommunicationServices interfaces which are then mapped on to Specific Communication stalk. Thus changes inCommunication system stalk are independent of SAS system.

The Communication system structure shall describe the data origin & destination in terms of LogicalNodes. This is setup shall be configured during initialization. IEC 61850 defines Substation Configurationlanguage for formal description of device & system.

2.1 LOGICAL NODES THAT ACTUALLY COMMUNICATE IN PERFORMING SAS TASKS

IEC 61850 defines various Logical Nodes (LN) as smallest subpart of a function which is performed in aSAS such as a Distance Relay, an Overcurrent Relay, a digital CT, a Circuit Breaker etc [see Appendix-1


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for List of Logical Nodes defined in IEC 61850 & Semantics]. In a SAS, these Logical Nodes exchangedata with each other.

IED is a physical device connected to communication stalk. But actual data flow takes place betweenLogical Nodes only. An IED performs functions as well as communicate as physical device in SASarchitecture. IED uses information from one or more logical nodes (either within itself or in different IED)and performs the tasks assigned to it.

Physical device which is an Intelligent Electronic device [refer to Appendix-2 for typical IEDs in a SAS].These Physical devices are connected through Physical links to the Physical Communication System.These Physical communication systems can be formed as a Process bus, Bay bus or a Station bus.However, IED may be physically connected to any bus and still can perform the same functions.

An IED may contain many Logical nodes. By IEC 61850 definition, only Logical Nodes can exchangedata. This means that there must be at least one Logical Node in any IED.

In a distributed function based SAS system, an IED may perform a function based on outputs of its ownLogical Node(s) as well as output(s) of a Logical Node(s) which is residing in another IED(s) and finaloutput command may be issued from another IED to a Process device (e.g. output to a CB trip coil).

Therefore, Communication between various Logical Nodes, IEDs forms basic backbone structure of aSAS. Logical Nodes communicate via ACSI and IEDs communicate in Communication stalk Protocol (e.g.TCP/IP).

Logical Nodes know the data required for performance of its task and validity of data. It is essential toassign reliable time reference to the data. Any degradation of Logical Node function due to data (missingdata or errors in data) shall be informed and intervention such as healing, request for resending, reroutingetc shall be initiated.

Logical Nodes exist at three levels Station Level, Bay Level and process level.

Station level LNs are HMIs (IHMI), Station wide Interlocking (CILO), alarm & event handling (CALH),Station wide Voltage Control (ATCC), etc. Prefixes are I, A & C (I is most common prefix).

Bay level LNs includes bay level Control, Protection, Measuring, Automatic, fault locators (e.g. PIOC,MMXU, CILO, CSWI, ATCC, RFLO, etc). Prefixes are P, A & C (Prefix X may also occur)..Process level Logical Nodes are related primary equipment from secondary side (CTs, VTs, CB contacts,CB Trip coils, CB Closing coils, interlocks, Disconnect auxiliary contact, all IOs like Transducers, etc).Common prefixes are X, Y & Z.

2.2 SAS TASKS

The functions such as Control, Protection, Monitoring, recording etc are referred to as Tasks of a SAS.

These functions may be allocated on three levels:

Process Level Bay Level

Station Level

Hardwired interfaces to Bay level, Station level & Process level devices which are not carrying digitalcommunication of Logical Nodes are not part of SAS. Only communication links which carry Logical nodedata between IEDs form the SAS communication architecture.


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Process level functions interface with the Process. Process level devices are process interfaces likeIntelligent I/Os, Intelligent Sensors/Transducers & actuators which are connected physically to Processlevel bus and information exchanged is Logical node information between various devices.

Bay level functions use the data related with one bay and performs related functions & process of thatbay and transfer the information to other bays and station level. Bay level devices are Control, Protection,Metering & Monitoring devices per each bay connected physically to bay level bus and informationexchanged is Logical node information between various devices.

Station level functions are performed by Local Station HMI computer with data for whole Substation,Station RTU a GPS timing clock signal receiver used to synchronize all bays etc.

Station level functions are two types:

Process related

Interface related

Process level functions are those related with intra bay tasks which are using station level based on theSingle Line Diagram built into SAS.

Interface level functions are those related with Local HMI, RTU etc. These do not carry intra bay dataexchanges between IEDs of different bays.

2.3 PHYSICAL INTERFACES & DEVICES

IEC 61850 based SAS achieves Logical information interchange between devices by mapping the logicalfunction structure on to the physical structure. This achieves also future proof as physical communicationstalks between IEDs are separated from logical communication between logical Nodes.

Redundancy in architecture, technology of communication system, cost effectiveness, Users &application requirement is basis for selection of a suitable SAS architecture.

To protect control & Protection functionality in a SAS, IEC 61850 mandates that no single point of failure

should disable critical functions (protection, primary control function, metering, etc.).

The SAS architecture selected shall meet the following three core characteristics:

Protective functions shall operate autonomously (independent of other functions and in theexisting philosophy being adopted in terms of redundancy)

The SAS can be used to execute control logic actions which are not time-critical. For examplelogical action of automatic failover following a Transformer fault can be performed by a SASsystem subject to Transformer Manufacturers recommended time (in milliseconds) for such anaction by SAS.

The SAS HMI shall be capable of independent operation of the Tele-Control interface to the

control centre.

For example Station functions can be performed in centralized way by Station Computer (similar fashionlike a mini SCADA) or may be performed by bay unit devices in a distributed fashion. Centralizedfunctioning of SAS demands highly reliable, sophisticated & redundant communication system but mayhave less physical devices. While decentralized is opposite. Most of the Traditional Unmanned Substationwere using Centralized Station Control but was also having discrete non SAS based Protection & controldevices which were hardwired. Redundant Station Computers were used with physically redundant chardconnections and two physical systems as Main-1 & Main-2 working simultaneously with interlocksbetween two.


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Similarly bay level functions may be performed by dedicated bay level devices or moved up or down toprocess level or station level.

Thus physical allocation of functions, devices & associated interfaces are based on actual engineeredarchitecture, application & Clients-Manufacturers agreement.

2.4 SAS ARCHITECTURE FOR EXISTING & NEW SUBSTATION:

Presently, not all devices in existing Substation are IEC 61850 compliant IEDs and hence not all Control,Protective & monitoring/measuring devices have logical nodes which can interact with one another.

Different approaches such as use of Protocol converters may be used when the existing devices areNumerical in technology. Based on the amount of data being interchanged a solution can be devised.

Following are the possible type of interchanges between devices:

Protection data exchanges between bay & station level devices

Data exchanges between bay level devices (inter bay & intra bay). These data may contain toppriority data as well as standard data. Top priority data may require high-speed transfer betweendevices for a specific process such as for example CB health status within High-speed Auto-Reclose dead time, Power swing detection blocking high-speed zones, or interlocking logicaloperations etc

Instrument Transformer instantaneous sample values between process bay & bay level devices

Control data exchange between Process & bay level devices

Control data exchange between Station & bay level devices

Data exchange between Station level device like HMI and station level devices

Based on the IEDs capability such information can be made in IEC 61850 compliant by some of the IEDs.

For example an IED physically connected with conventional CTs & VTs may convert the CT & VTsampled data and transfer it (real time time-tagged) to another IED without physical connection to CTs &VTs. In this way, Process bus does not exist at all. But the bay level device itself performs such a task as

a process level device like a digital CT/VT.

As far as communication system itself concerned, it is possible to connect all devices on to one of threebuses (bay, process station). It is only important to meet SAS mandatory characteristics mentioned undersection 2.3 above.

In all cases Tele-communication with remote Substation & Control Centers shall be treated separate fromSAS. If Remote Substation & Control Center happens to be having dedicated Network efficient networktopography may also be prepared based on existing SCADA protocols.

The architecture shall be based on the composition of Logical Nodes within IEDs. Engineering of SASarchitecture shall be based on available Logical Nodes within the IEDs, data attributes and description ofPICOMs (inclusive of optional & mandatory attributes).

The SAS Engineering shall device the task function based on the application & clients philosophy withthe data base from the Manufacturers devices. Criteria forstarting of the function, result of the functionaltask and overall performance with respect to the security, stability & reliability of Power system.

2.5 SAS DEVICES:

All devices in a SAS are interoperable as:


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All Logical Node to logical Node information exchange is in mutual understandable format(whether they are part of one IED or distributed in different IEDs from same or differentManufacturer) (Semantics of IEC 61850)

All IEDs (from different Manufacturers) on the common bus follow same protocol .

2.6 IEDs ROLE AND REQUIREMENTS IN SAS:

SAS main goal is to achieve interoperability. By being not interchangeable, the allocation of functionaltasks to particular IEDs is free to application & Users choice. This will also result in selection of bestsuitable functions. Generally, Manufactures product design Engineers are constrained by their software &processor capability. Various IEDs therefore may have different approaches. This is true betweenmanufacturers which may be based on the cost and design. For example same Manufacturer mayrecommend different IED from his own product line up (i.e. Manufacturer may recommend differentDistance Protection IED for EHV & HV systems with same Logical functions). This is one way is better forUser as single point failure of devices due to use of same technology is minimized. As the processorspeed and loading reaches peak, eventually interchangeability will arrive (Manufacturers may look atcompetitors product and try to out beat each other will finally arrive at unified device functions over thetime.

User can tell many cases where a particular Manufacturer revised his product version to includeadditional functionality when his product got rejected because his competitors product has suchfunctionality. Sometimes such revision is also based on failures of a particular functionality due to design.

Logical Nodes within IED & its exchanged Piece of Information for Communication (PICOM) must beclear.

In addition to Logical Nodes which deliver data for a task functionality, IEC 61850 mandates a LogicalNode LLN0. These communicate data such as nameplate information, healthiness etc which are notuseful in any task functionality and are device specific.

2.7 COMMUNICATION SYSTEM DESIGN IN SAS:

The communication design for SAS functionality shall be independent of physical communication of IEDs.

SAS is based on format and amount of mandatory data which needs to be exchanged between theLogical Nodes. Optional data exchanged may help in achieving greater flexibility to SAS. Logical Nodescommunicate via Logical interfaces which is free of physical interfaces like LAN protocols. Being open forfuture functionality IEC 61850 allows for changes in communication technology. Today manufacturers areproviding products which can support many protocols legacy as well as fiber-optic based high bandwidthones.

All data communicated between Logical Nodes shall carry unambiguous data with all associatedattributes and shall be independent of physical communication stalk within acceptable and guaranteedtime frame. Logical Nodes communicate via logical connection which is configured between sending &receiving logical nodes.

Logical Nodes knows what is the required data for its function and able to verify its accuracy and quality

in terms of errors and time associated with the data as well as its validity. Such verification is essentialfunction of logical nodes. When the error limit is crossed or data is not latest within its time limit or istotally lost either Logical node completely goes to alarm & non-operative mode or gets degraded basedon the decided design philosophy. Other devices are informed of this degradation or loss by logical NodeLLN0 (all physical devices have LLN0 as mandatory).

Various Logical Nodes are located in different physical devices (IEDs). An IED can have more than oneLogical Node. Similarly a Logical Node exchange of data/information may take place with one or morelogical Nodes. A physical device like an IED may perform one or more functions


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Information which Logical Nodes communicate is described by concept of PICOM.

Attributes of a PICOM that are only at configuration time:

Value for transmission and its semantics (test or default value as applicable)

Name: Type (structure) of data like Analog or binary, single value or data set

Information like valid transmission time limit (time tag & time limit), integrity, whether data is event

related or on demand or periodic, Priority of data transmission Sending & receiving Node (which is logical connection between Source & sink)

Attributes of a PICOM that are to be used for data flow calculations only:

Value for transmission and its semantics (test or default value as applicable)

Format of data

Data length

State of operationInformation exchange described is based on data by LNs. Each PICOM data model has at least one data(status and values) or one data exchange (event).

2.8 SYSTEM SUPPORT FUNCTIONS:

Since the functioning of SAS is dependent also on external support functions in addition to its devices itis essential to select proper architecture which supports the external functions. Typical support systemsare:

Network technology, design, redundancy and management (star, ring, dual redundant, duplex,separate Tx & Rx etc)

Time Synchronization

Self-Diagnostic functions of each device (both SAS device & support system device)

2.9 MAINTENANCE FUNCTIONS:

The SAS design shall consider maintenance aspects such as: Management of software & configuration of system

Setting

Testing and implications

Security measures

2.10 OPERATIONAL FUNCTIONS:

The SAS design shall consider following aspects such as:

Access security (availability, hacking, denials)

Control functions

Event management Fault, disturbance, event retrieval & archiving functions

Analysis tools

Alarm system

Adaptation to special switching for transient mitigation


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2.11 TIMING REQUIREMENT FOR SAS:

Basic Time requirement:A common format for tagging the IEDs which are manufactured by various Vendors shall be used. Timemodel & format shall meet the following:

Accuracy requirement of various applications (Protection, Control, measuring & monitoring

Standard Time stamp (UTC is acceptable standard) Time model shall have sufficient information to allow for delta time calculations for paired events

crossing the leap second boundary

Easily derived time signal like GPS may be used

Timing model shall allow computation of local time (especially some devices like Line Differentialrelates to Local & remote end time stamped data)

Time stamp format shall be compact & easily manipulated by IEDs

Event Time:A dedicated time allocation procedure is required for the following kinds of events:

Event which is computational requiring time tagging immediately within a time resolution of clock(no special correction measures are needed)

Event based on change in binary input (these shall be locally corrected based on debouncingprocedure)

Event based on change in analog input (these shall be locally corrected based on filteringprocedure)

Transfer Time:When the transfer time is specified, handling time delays at sending & receiving as well as transmissiondelay shall be considered.

2.12 PERFORMANCE CLASSES:

For Control & Protection:Performance classes P1, P2 & P3 as defined in IEC 60870 is applicable. Performance P1 is applicable tolow requirements.P2 is applicable for Transmission bays and P3 is for highest performance like auto synchronizingfunction, breaker time switching etc.

For Metering & Power Quality:

Performance classes M1 for revenue metering classes 0.2 (IEC 60044-8) and 0.5 (IEC 62053-22)and up to 5

thHarmonic

Performance classes M2 for revenue metering classes 0.1 (IEC 60044-8) and 0.2 (IEC 62053-22)and up to 13

thHarmonic

Performance classes M3 for revenue metering quality up to 40th

Harmonic

Message types & performance classes:

Type 1A (TRIP)

Type 1B (Others)

Type 2, 3, 4, 5, 6 & 7

Type 1A messages are most important type in a Substation. These messages have demandingrequirement in terms of security & reliability as well as speed. Performance class P1 is for messages withacceptable total transmission time of order of half cycle (10msec is defined for P1). Performance classP2 & P3 is applicable for messages with acceptable total transmission time of order of quarter cycle(3msec is defined for P2 & P3).


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Type 1B messages are less demanding compared to Type 1A. Performance class P1 is with 100msec.P2 & P3 is applicable for messages with acceptable total transmission time of order of one cycle (20msecis defined for P2 & P3).

Type 2: Medium speed messagesThese class messages are those for which time of origin of message is important but transmission time isless critical. For these messages, IEDs are expected to have their own clock. These messages havesenders time tag. Receiver reacts after internal delay and correct the senders time. Transmission timesof less than 100msec are applicable for these types.

Type 3: Low speed messagesThese are complex class messages which may require being time tagged. These are slow speedmessages. Application like slow speed auto control functions, transfer of event records, reading/changingset point values, general presentation of system data etc. whether time tag is required or not is decidedbased on application. Transmission times of less than 500msec are applicable for these types.

Type 4: Raw data messagesThese messages include digitized outputs of Digital CTs, Digital VTs, Digital Transducers etc. These arecontinuous stream of synchronized data from (Logical Nodes) IEDs interleaved with other data from otherIEDs.

Raw data for Protection & Control functions are decided based on Protection performance class P1, P2 &P3. Raw data for Metering functions are decided based on Protection performance class M1, M2 & M3.

Raw data for Protection & Control (as per IEC 61850-5)

Data Type Class Accuracy class & harmonics Resolution (Bits)Amplitude

Rate(Samples per sec)Frequency

Voltage

CurrentP1 10.0

13

13480

Voltage

Current

P2 3.016

16

960

Voltage

CurrentP3 3.0

16

181920

Raw data for Metering (as per IEC 61850-5)

Data Type Class Accuracy class & harmonics Resolution (Bits)Amplitude

Rate(Samples per sec)Frequency

Voltage&

Current

M1Class 0.5 (IEC 62053-22)Class 0.2 (IEC 60044-8)

Up to 5th

Harmonic

12

14

1500

Voltage&

CurrentM2

Class 0.2 (IEC 62053-22)Class 0.1 (IEC 60044-8)

Up to 13th

Harmonic

14

164000

Voltage&

CurrentM3

Class 0.1

Up to 40th

Harmonic

16

1812000


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Type 5: File Transfer functionsThese messages are used for transferring large data files such as recording, event achieving, settingsupload/download etc. Such data must be split into blocks (packets) of limited length to allow for bandsharing with other communication network activities. Typical bit lengths of this type of PICOMs are 512bits or more. Since transfer time is not critical (1000 msec or more typical). For remote access, an accesscontrol with authorization is required (this request message is as per Type 7).

Type 6: Time synchronizing messagesThese messages are used for IED internal clock synchronization. Synchronizing accuracy depends onapplication.

Time class performances for synchronization messages are T1 & T2 (except for the resulting timeaccuracy in the whole system).

IED Time Synchronizing for Protection & Control (as per IEC 61850-5)

TimePerformanceClass

Accuracyclass (ms)

Purpose

T1 1

Time tagging of events

T2 0.1Time tagging of zero crossings and data for the distributedSynchronism check. Time tags to support point on waveSwitching of CBs

IED Time Synchronizing for Instrument Transformers (as per IEC 61850-5)

Time PerformanceClass

Accuracy class(s)

Reference Phaseangle ()50 Hz

Phaseangle ()60 Hz

FaultLocation(m)

T3 25 P1 27 32 7500

T4 4 P2 M1 4 5 1200

T5 1 P3 M2/3 1 1 300

Type 7: Command messages with access controlThese messages are used Control commands issued from local/remote HMI. These command messagesrequire high security. Messages of this class require access control. These message types are based onType 3 with additional password &/or verification procedures.

2.13 DATA INTEGRITY:

As per IEC 60870-4 integrity classes.

Three groups of integrity measures are applied for limiting noise interference:1. Proper design of devices and communication system2. Use of appropriate coding (hamming distance)3. For command messages use of two step sequence (Select-before-operate, SBO)


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APPENDIX-1LOGICAL NODES LIST IN A IEC 61850 BASED SAS

Logical Nodes for protection related functions:

IEC 61850

Logical

Nodes

Description or comments

PTEF

The Transient Earth Fault (TEF) protections are used for detection of Earth Faults in

Compensated or Isolated or Petersen coil Neutral Power Systems.

Compensated or Isolated or Petersen coil Neutral systems are typical of some MV

Networks. These systems are designed for continuing operation upon occurrence of a

Single Earth Fault for longer duration. Conventional Earth Fault Relays which operate

on Fundamental Frequency Steady State Earth Fault Currents are not suitable for such


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systems.

High Peak, extremely short duration Transient Surge Currents & Transient Over

Voltages occur due to resulting Unsymmetrical Phase to Earth system during Single

Earth Faults in such systems. Amplitude & duration of Transient surge currents

depends on the System design (Capacitance & Inductance) & resistance at the fault

location. Surges self extinguish at zero crossing & reappear intermittently by charging

& discharging stored energies.

Transient Earth Fault Protections (TEF) operates when they detect the residual surge

current. Due to extremely short duration of the surge they indicate only Start of an

Earth Fault.

Further Protection/functions or sophistication may be necessary for detection of

direction, location & Isolation of such faults.

PZSU

Zero-Speed / Under-Speed (ZSU) device used for detecting the Motion of Equipment.

The function of such a device may be such as to detect Loss of rotation/linear

motion/reciprocating motion, Failure to start/stop of a Drive/Machine, Stalled

machine, process/equipment Jam/Overload, Low-speed/over-speed of a machine etc.

The IEEE C37-2 device function number of such a device is 14.

PDIS

A Distance Protective Relay (DIS) is a non-unit Protection whose operation depends

on local measured Voltage and Current at the Relay location. Distance Protection

operates when the actual Impedance, admittance, reactance or combination of

resistance & reactance falls within its setting boundary limit. Distance Protection

setting boundary limits are indicated on R-X plane. Distance Protections are applied


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for detecting faults with or without earth.

The Distance Protection is most commonly used as Main Protection for High Voltage

Transmission systems, backup protection for Generator/Unit Transformer, Shunt

Reactor bank etc in some systems it is reverse-set to provide backup protection for

Bus bar faults.

The Distance Protection function is used for various applications such as Tripping of

Circuit Breakers, Controlling other Protections (like blocking, Starting), Monitoring

disturbance in system, Fault-detection, Phase selection in Single-pole Auto-Reclosing

schemes, Power swings detection, System Islanding, Power systems out of step

detection, Distance to Fault location etc. With Numerical technology its applications

are ever increasing. In most HV, EHV & UHV AC Transmission systems it providesadditional communication-aided unit-type protection.

Typical Transmission line Distance protection (DIS) tripping scheme is made of

standard three-step zone protection (Zone-1, 2 & 3 for Phase-Ground faults and

Zone-1, 2 & 3 for Phase-Phase faults). These Protection zones are set to provide time-

coordinated tripping with upstream/downstream Equipment Protections.

Numerical Distance Protections can have additional advantages like possibility of

setting each Zone as Forward or Reverse, any zone can be set instantaneous or

delayed, any zone can be deactivated, separate settings for phase faults & earth

faults for each zone, characteristic matching with load/fault resistance, preventing

trip during stable power swings as well as many logical configurations to perform

additional application based schemes.


PVPHOver Fluxing or Volts per Hertz Protection (VPH) is a Protection operates when the

ratio of Voltage to Frequency exceeds its setting.


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Over Fluxing of Magnetic Iron cores results in Magnetic Saturation which leads the

stray flux which follow other paths like equipment enclosure etc which are not

designed to limit eddy currents. These eddy currents may lead to Over-heating and

subsequent loss of Insulation life of Equipment.

Power Transformers, Generators, Unit Transformers, Reactors, Motors have limited

Over Fluxing capabilities as they are optimally designed for operation close to

saturation point. Volts per Hertz protection is intended to detect Over Fluxing and

provide Alarm & or Trip or both in accordance with application for these equipment.

The Volts per Hertz Protection functions may provide definite time delayed trip,

inverse-time delayed trip (based on application) or provide an Alarm.

Numerical Volts per Hertz Protection may include both trip & Alarm stage with its

own time characteristics which can be selectable from standard curves or can be

custom built based equipment withstand capability.


PTUV

An Undervoltage relay (UV) operates when the measured System Voltage falls below

its setting.

Undervoltage Protection functions may be instantaneous, definite delayed, inverse-

time delayed. Undervoltage relay (TUV) function is used for various applications like

Load shedding schemes, Tripping of Motors, Tripping of Shunt Reactors, tap changer

application, Switching of VAR devices, Monitoring system disturbances, detecting

dead Line/bus dead while interconnecting systems, Fault detection, Voltage control

supervision of other protections etc as well as various ancillary functions.


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Numerical Undervoltage Protection may include both trip & Alarm stage with its own

time characteristics with settable pickup & dropout delays.


.

PDPR

A Directional Power Relay (DPR) operates when the measured real power flow in a

particular set direction exceeds its setting.

Directional Power relay (DPR) function is used for various applications like Protection

of Generator & Prime mover on loss of mechanical input to its Prime mover,

Preventing Co-Generation plants from feeding the Utility, sequential restoration of an

interconnected systems, Low forward power of Generators, loss of load detection etc

. Numerical Directional power Protection may include both trip & Alarm stage with its

own time characteristics. This relay is also called Wattmetric type Power relay.


PWDE

A Wattmetric type Directional Earth Fault Relay (WDE) operates when the Earth fault

power in the circuit flows in a specific direction exceeding its setting. It is used in

Petersen coil grounded/ compensated Neutral networks.

Compensated or Petersen coil Neutral systems are typical of some MV Networks.

These systems are designed for continuing operation upon occurrence of a Single

Earth Fault for quite long time. Conventional Earth Fault Relays which operate onFundamental Frequency Steady State Earth Fault Currents are not suitable for such

systems. Sensitive Wattmetric Directional Earth fault Relays are used for detection &

location of an Earth fault in compensated network to provide selective tripping using

residual Voltage & Currents and phase angle difference between them.


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Based on the quality of CT input and scheme design it may provide Alarm only or Trip.

The IEEE C37-2 device function number of such a device is 32N [Suffix N for Earth

fault].

PUPC

Undercurrent or Underpower relay (UPC) operates when the current or Power falls

below its setting.

Some of their applications are Loss of load on Motors, Monitoring Open-Pole, Detect

Pump running dry, Failure of drive belts, Conveyer systems, Fans, Loss in process loadsequence etc.


PUEX

Loss-of-field relay or Under Excitation relay (UEX) operates when the there is low or

failure of Synchronous Machine excitation.

The Protection may be based on the DC Field Current or detecting Reactive Current in

Armature flowing from system. It may have an Impedance type Characteristics using

Armature current and Voltage as input or part of Excitation system either in AC & DC

circuit.

The failure of excitation or under excitation could be from AVR malfunction,

Generator feeding capacitive loads, failure in components of Excitation system etc.

Loss of Synchronous Generator excitation results in its operation as an Induction

Generator losing synchronism with system. The machine runs above its synchronous

speed & draws Reactive power from the system through its armature.


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PPBR

Phase Balance or Reverse Phase Current Relay (PBR) operates when it detects the

Phase Currents in Reverse Sequence or when there is Unbalanced Phase Currents or

when there is Negative Sequence component Current exceeding its setting.

Negative sequence currents are highly destructive to the Rotating Machines like

Generators & Three-Phase Motors are optimally designed for Positive sequenceVoltage & Currents and direction of rotation. Excessive heating & loss of life or

subsequent failure may occur based on the design temperature rise class, insulation

class & cooling system.

For Poly phase Motors the Negative Sequence Over Current Relay provides protection

against phase open circuit operation leading to extensive damage to Rotor.


PPBV

Phase Balance or Phase Sequence Voltage Relay (PBV) operates when it detects the

Unbalanced Phase Voltages or when there is Negative Sequence component Voltage

exceeding its setting.

Negative sequence Voltages are highly destructive to Poly Phase Motors due to

double frequency induced currents in the rotor. Rotating Machines like Generators &

Three-Phase Motors are optimally designed for Positive sequence Voltage & Currents

and direction of rotation. Excessive heating & loss of life or subsequent failure may

occur based on the design temperature rise class, insulation class & cooling system.


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PMSU

Motor start-up protection (MSU) is combination of control, protection & monitoring

functions which Overload, longer startup times, permissible cooling time before start,

available heat within Motor and prevents thermal damage to the Motor. It may

include such function as sequence of operation or failure to satisfy defined sequence

or incomplete sequence.

Such a supervision system may be made up of combination of functions as per IEEE

C37-2 device function numbers 48, 49. 51 & 66.

PTTR

Machine or Transformer Thermal Relay (TTR) operates when it detects the Machine

or Transformer temperature exceeds the set level.

Winding temperature of machine or Transformer is proportional to the square of the

current. The protection may detect temperature rise above ambient or total

temperature of the Winding and follows the cooling/heating time constants. It may

be based on the Heat run test.

The IEEE C37-2 device function numbers of such a device is 49.

PROL

Machine Rotor Thermal Overload Relay (ROL) operates when it detects the Machine

Rotor winding temperature exceeds the set level.

Winding temperature of Machine rotor winding is proportional to the square of the

field current. Its application may be based on the Heat run test of actual machine or


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as agreed between User & manufacturer as well as based on machine size, design and

applicable standards. It working may be based on total temperature or ambient

compensated temperature rise.

The IEEE C37-2 device function numbers of such a device is 49R [Suffix R for Rotor].

PSOL

Machine Stator Thermal Overload Relay (SOL) operates when it detects the Machine

Stator winding temperature exceeds the set level.

Winding temperature of Machine Stator winding is proportional to the square of theArmature current. Its application may be based on the Heat run test of actual

machine or as agreed between User & manufacturer as well as based on machine

size, design and applicable standards. It working may be based on total temperature

or ambient compensated temperature rise.

The IEEE C37-2 device function numbers of such a device is 49S [Suffix S for Stator].

PIOC

Instantaneous overcurrent or rate-of-rise current relay (IOC) is a protective relay

which operates instantaneously without additional time delay when the measured

instantaneous current or measured rate of current rise exceeds its setting.

Instantaneous Over current Relay provides fastest operation upon detecting a fault in

the Protected object. Instantaneous Overcurrent relay may be based on RMS current

or Phasor value. Numerical IOC can be given intentional time delay to ride through

Transient currents or when it needs to coordinate with fuse or in reverse interlocking

scheme to allow a blocking input from downstream device start. Similarly a dropout

delay may be set based on the application. Instantaneous Overcurrent Relays are

designed for Transient over reach of less than 5% typically. Additionally, some IOC

relays can allow release by Direction sensing fast device making IOC as a Directional


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IOC.

Rate of rise Current relay detects the steepness of the current rise and thereby

indicative of high peak prospective current. It is particularly useful in high-speed

tripping devices with limited interruption capability thereby clearing fault when there

is less arc energy generated between its parting contacts establishing thermal &

dielectric recovery.


PTOC

AC Time overcurrent relay (TOC) is a protective relay which operates when the

measured current exceeds its setting current after an intentional set time delay. The

intentional delay time selection may be fixed (definite) time or Inverse function of the

ratio of measured current to setting current.

These relays are intended to coordinate with Time-Current characteristics of other

Protections as well as to allow transients to die down like inrush currents.

Historically, these relays followed time-current current curves to optimally protect

equipment withstand capability curves by means of Electromechanical relays based

on resultant torques due to operating & restraint forces. Accordingly various

standards were followed to define the degree of steepness of Inverse current-time

curves. Commonly called by names like Standard, Normal, Moderately, very,

extremely inverse and so on and defined based on governing Standard. Traditional

Electromechanical relays have a definite minimum time for each inverse time setting

and were called IDMTL characteristics. Additionally, some TOC relays can allow

release by Direction sensing fast device making TOC as a Directional TOC.

Numerical TOC may provide large numbers of selectable Inverse time characteristics

matching the need as per different standards and to coordinate with existing devices

in the system. Additionally, they allow a characteristic to be custom built and used by


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the relay and to fix any required definite minimum time delay.


PVOC

Voltage-Controlled/dependent Over Current Relay (VOC) is a Protective Relay is a

Time Overcurrent Relay with inverse current-time characteristics [refer to PTOC] with

dependency on the Measured Voltage.

Based on application, there are two types VOC Relays namely Voltage Controlled

Overcurrent Relays and Voltage restraint Overcurrent Relays. Voltage ControlledOvercurrent relays will operate only when the measured voltage falls below a set

value. Voltage Restraint Overcurrent relay pickup and time multiplier progressively

gets reduced depending on the reduction in the measured voltage.

Generator fault current decreases as time progresses due to Armature reaction.

Current reduces based on increased reactance from Subtransient to Transient and

finally steady state value. Final current will be less than rated current & hence

conventional backup Overcurrent relays set above Generator rated current will

dropout in the event of fault leaving the fault uncleared. Depending on the

connection of Generator whether direct on to bus or through Unit Transformer VOC

type can be selected whether Voltage controlled or restraint type.

The IEEE C37-2 device function numbers of such a device is 51V [Suffix V is indicating

Voltage dependency].

PPFR

A Power factor Relay (PFR) is a Relay which monitors the Power factor of an AC circuit

and operates when it rises above or falls below its setting.

Asynchronous motors (Inductive loads) draw reactive Power (lagging VARs) in


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addition to real power thereby causing voltage to dip as well as increase in apparent

power, losses & efficiency. Most of the loads are predominantly inductive. Similarly,

capacitive loads tend to increase Voltage by generating leading VARs. PFR are

typically used to monitor PF based on the phase angle between the measured

Voltage & Current and provide control & alarm which can be to switching Capacitor

banks, Shunt Reactors, provide interlock to AVR, VAR control interlocks or to apply

any other techno-commercial aspect.


PTOV

Time Over Voltage Relay (PTOV) is a Relay which operates when measured voltage

exceeds its setting after a lapse of selected time delay. The Time delay selection may

be definite time or inverse time as a function of Voltage.

Steady state Over voltages are caused when there is loss of major load, energizing a

long EHV Transmission line, Capacitor bank switched on light loads, OLTC

malfunction, AVR malfunction etc. Dielectrics (Insulating media, capacitor) are

susceptible to increased Electric field which is Volts per length and may cause

permanent damages to Insulation strength and failures. Every Electrical Equipment is

made up of insulation which has limited capability to withstand voltage beyond ratedvalue.

PTOV may be used to provide protection to insulation or as safety mean or as

control/monitoring functions.

The IEEE C37-2 device function numbers of such a device is 59

PDOV DC Overvoltage relays (DOV) are intended for protection against excessive DC voltage

in DC systems.


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Operation of the DC overvoltage relays is carried out whenever the DC input voltage

grows higher than its setting. The Time delay selection may be definite time or

inverse time as a function of Voltage

The IEEE C37-2 device function numbers of such a device is 59DC

PVCB

Voltage or Current balance Relay (VCB) operates when the difference between

Voltage or Current input or output between two circuits exceeds setting.

Typical application of Voltage balance Relay is as Fuse supervision comparing two

voltage circuits to identify genuine loss of supply or fuse failure condition of truly

energized system. This also find critical application in Generator Excitation control

systems.

Current unbalance has typical application of detecting broken conductors, CT circuit

supervision etc.


PHIZ

Earth fault protection / Ground detector relay (HIZ) detects failure of insulation to

ground.

Ground fault detectors are used in AC as well as DC systems. Ground fault protection

detects earth faults in applications like Generator/Motor fields, Battery systems,

Telecommunication systems, High Impedance or ungrounded systems, MV Motors in

High resistance grounded systems etc.


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The IEEE C37-2 device function numbers of such a device is 64

PREF

Rotor Earth fault protection (REF) detects Earth faults in the Rotor field circuit of a

Synchronous machine.

Rotor field circuits are normally ungrounded. A single earth fault is not very

dangerous and does not cause immediate damage. When a second earth fault occurs

it may fully short circuit the field winding or when first fault involves some windingturns it may lead to interturn fault. Severe magnetic imbalance and heavy rotor

vibrations leading soon to severe damage can occur

The IEEE C37-2 device function numbers of such a device is 64R.

PSEF

Stator Earth fault protection (SEF) detects Earth faults in the Stator armature Winding

of a Synchronous Machine.

Large Generator Neutral is usually grounded through some kind of High Impedance to

limit the magnitude of Phase to ground faults and extensive core damage. Phase to

phase faults are avoided by means of Isolated or segregated bus ducts. In Medium

Voltage smaller Machines low resistance grounding is common to limit the current

typically down to less than 150% rated but above conventional Earth fault Relay

detection capabilities. LV and very small Generators are solidly grounded. In all cases

stator Earth fault detection is provided, Two concepts are applied 95% and 100%

Earth fault detection [latter one is for larger Machines]. Faults near the Neutral end

are detected by 100% earth fault Protection.


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Damage to a large Generator is of great consequence in terms of financial loss.

Various techniques are adapted for providing 100% Stator earth fault even involving

last part of turn close to neutral in high impedance earthed neutral. Such technique

may involve use of low frequency 20Hz injection, 3rd harmonic monitoring etc

The IEEE C37-2 device function numbers of such a device is 64S.

PITF

Interturn Fault Detection Relay (ITF) is applied to detect a short circuit that occurs

between turns of same phase in a Machine or Transformer.

Machines with one turn per slot can have a turn to turn faults only from two separate

earth faults one in each turn which can be detected by Earth fault Protection. An

interturn fault without earth fault can occur when there is more than one turn in a

slot.

If interturn faults occur in the stator slots they quickly develop into faults to earth and

are cleared by the stator earth fault protection. The possibility exists that the faultmay occur at the winding ends and so can cause extensive damage to the generator

before the fault evolves into one detectable by other protection.

The IEEE C37-2 device function numbers of such a device is 64W.

PDOC

AC Directional Overcurrent Relay (DOC) is a Relay which operated when the

measured phase current in a desired direction of flow exceeds its setting after a

desired set time delay. The Delay may be zero (instantaneous), definite time or

inverse time based on current.


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Directional Inverse time Relays are particularly useful in interconnected MV or HV

system lines as in Co-Generation plants [Refer to PTOC for inverse time curves].

Depending on application, the Relay maximum characteristic angle/Maximum torque

angle/Relay characteristics angle (MCA or MTA or RCA) is selected which also

depends on the inputs used and type of fault. A quadrature (100% cross polarization)

polarization is quite common for HV & MV Overhead Transmission system.

Numerical Relays have wide range of selectable characteristic angles and time-

current curves. Different characteristic angle and polarizing inputs are applicable

based on the system.


PDEF

AC Directional Earth fault Protection (DEF) is a Relay which operated when the

measured residual current in a desired direction of flow exceeds its setting after a

desired set time delay. The Delay may be zero (instantaneous), definite time or

inverse time based on current.

Directional Inverse time Relays are particularly useful in interconnected system lines

as in Co-Generation plants [Refer to PTOC for inverse time curves]. Depending on

application, the Relay maximum characteristic angle/Maximum torque angle/Relay

characteristics angle (MCA or MTA or RCA) is selected which also depends on the

inputs used and type of fault. Relay Polarizing input may be polarized by Voltage

(residual voltage) or current (Neutral current of Power Transformer or circulating in a

Transformer Delta winding) or both voltage & current simultaneously.

Directional earth fault protection is also used as communication assisted comparisonscheme for Over Head Transmission lines to detect & clear high resistance earth

faults.

Numerical Relays have wide range of selectable characteristic angles and time-


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current curves.

The IEEE C37-2 device function numbers of such a device is 67N.

PDCO

DC Time overcurrent relay (DCO) operates when the DC load current exceeds its

setting value with a time delay.

It is useful in DC systems, Battery systems and Protection circuits of DC Motors, DC

drives etc.


PPAM

Phase Angle Measuring (PAM) is a relay that operates at a preset phase angle

between voltage and current or two voltages or two currents. This relay determines

asymmetry in currents and voltages between phases.

Phase angle relays find application in Co-Generation Plants to detect Vector jumps

and in Automatic Motor bus transfer schemes

Out of step relay detects two system of voltages are in stable operating mode. In HV

& EHV systems Out of Step blocking and Tripping schemes are used based on whether

power swings during disturbances are stable or system needs to be islanded. Out-of-

step blocking Protections work on Impedance measurement principle similar toDistance relays and cover the Zone Characteristics which needs to be Blocked. Out-of-

step Protections are applied to Generators. Also, in EHV & UHV lines when Electrical

Center of system lies on the Protected Transmission line it results in Islanding

preventing in systems collapsing.


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PFRQ

Frequency Relay (FRQ) is a Relay which operates when measured System frequency

falls below or rise above its setting or when rate of change of frequency exceeds it

setting.

In a Power system Frequency is directly proportional to the real power. When the real

power demand increases the system Frequency tends to reduce which under steady

state is sensed by the Generator Governing system and Increased power is produced

to maintain the system frequency (depending on the Generator droop setting &

available capacity). When additional real Power is no longer available to support,

system frequency reduces. Such actions like load shedding in stages are used to

maintain system frequency to operating levels.

Motors produce increased torque as the Frequency is reduced if its Voltage is

maintained. Similarly, produce less torque when frequency rises.

Machines are designed for optimum operation at rated Frequency. Operation aboveor below frequency needs corrective action or shutdown of Machines. Generators

and large motors are protected against over-speeding and under-speeding by Over-

Under Frequency Relays.

Under Frequency and df/dt based load shedding schemes are frequently used when

an Industrial Power Plant connects with Utility system to Island the systems and

maintain process.

Under Frequency & df/dt schemes are also applied to remove loads as well as to

disconnect two systems when removal of a system part restores stability of one of

the region.


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PDIF

Differential Protection (DIF) operates when it measures difference between Currents

or Voltages or any other electrical quantities exceeding its setting. It may measure

difference in percentage, phase angle or any other electrical quantity.

Current Differential Relays are typically used for protecting Generators, Transformers,

Reactors, Busbars, Transmission lines, Motors etc. Where in the relays compares

currents entering and leaving the Protected object. To allow for CT mismatch and DC

time constants, restraints are added which are functions of through current or some

adaptive values.

Low Impedance & High Impedance are two main types of Current Differential Relays.

High impedance Relay may be Voltage operated or Current operated with Stabilizing

resistors.

Voltage Differential protections are used in capacitor bank application where in

voltages at Mid tap and bus are compared to detect failed capacitor units.

Differential Protection is one of the main Protections for major Electrical equipment.

The IEEE C37-2 device function numbers of such a device is 87 [Ground Differential as

87N, Transformer Differential as 87T, Motor Differential as 87M, Generator

Differential as 87G, Reactor Differential as 87R, Bus Differential as 87B and Voltage

Differential will have device number 87V].


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PPDF

Phase Comparison Protection (PDF) compares the phase angle difference between

two quantities and operates when it satisfy operation setting.

For Transmission Lines, phase comparison protection compares phase angle of

current entering the protected circuit and leaving it. Thus it obtains and compares

phase angle of current from remote end and compares it with local current. For

external faults the measured currents will be in antiphase. This is due to the current

flowing in at one end of the protected line, and out at the remote end. For an

internal fault currents will be in phase. Where one terminal is open then the internal

fault may cause a current flow in, without a corresponding flow out at the remote

end.

The IEEE C37-2 device function numbers of such a device is 87P [suffix P for phase

comparison].

PLDF








adaptive values. Transmission line Differential Relay may include Transformers within

its zone.

Line Differential Protections (LDF) are available for two terminal lines as well as multi-

terminal lines. With High speed optical communication system Line Differential

Protection is applied for long Transmission lines of few hundred kilometers (which

was not possible with traditional metallic pilots with allowable maximum length of

10km or less)


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The IEEE C37-2 device function numbers of such a device is 87L [Suffix L for line].

PNDF




Restricted Earth fault Protection (NDF) is a form of Current Differential Protection

which compares Residual current entering and leaving a Protected Object.

Typically, Star windings of Transformers are Protected by Restricted Earth fault Relays

which compares winding Neutral current with Residual currents of phases. It is also

applicable for Zigzag type Grounding Transformers.

The IEEE C37-2 device function numbers of such a device is 87N [Suffix N for

Neutral/Earth].

PTDF







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adaptive values.

Transformer Differential Protections may provided with 2nd and 5th harmonic

restraints. There may be as many numbers of restraint inputs as numbers of CTs in

case of Transformer Differential Protection and from each voltage side.

Differential Protection is one of the main Protections for Transformers.

The IEEE C37-2 device function numbers of such a device is 87T [suffix T for

Transformer].

PBDF





Reactors, Busbars, Transmission lines, motors etc. Where in the relays compares



adaptive values.

Bus differential Protections (BDF) are two types namely Low Impedance & High

impedance type. High impedance Relay may be Voltage operated or Current operated

with Stabilizing resistors.


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Differential Protection is main Protection for Busbars.

Numerical low impedance type are applicable for as many zones as numbers of

Busbars in Centralized or decentralized configuration.

CT switching problem associated with older generation Relays in case of double bus,

two main & transfer bus schemes are eliminated.

Different CT ratio can be used in Numerical Bus Differential schemes based on feeder

rating. Other advantages like adaptive stabilization (to prevent over-stabilization

problem), end zone protection, check- zone can be implemented.

The IEEE C37-2 device function numbers of such a device is 87B [Suffix B is for Bus

bar].

PMDF








adaptive values.


High impedance Relay may be Voltage operated or Current operated with Stabilizing


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resistors.

Motor Differential protection (MDF) is compares currents at both ends of each phase

winding and provides trip output when it detects fault within its zone inclusive of

windings. Differential protection is applicable for Star connected & Delta connected

Motors by means of CT connection. Also, scheme with CTs only at main side of

winding is possible if the Motor neutral is formed at supply panel or close to it.

Differential Protection is one of the main Protections for Large Motors.

The IEEE C37-2 device function numbers of such a device is 87M [Suffix M for Motor].

PGDF








adaptive values.


High impedance Relay may be Voltage operated or Current operated with Stabilizingresistors.

Generator Differential protection (GDF) is compares currents at both ends of each

phase winding and provides trip output when it detects fault within its zone inclusive


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of windings.

Generator-Unit transformer Overall Differential protection is applicable for Covering

both Generator & Step-up Unit Transformer.

Differential Protection is one of the main Protections for Generator.

The IEEE C37-2 device function numbers of such a device is 87G [Suffix G for

Generator].

Protection Related Logical Nodes:

RDRE

RDRE is a logical node representing the acquisition functions for current and voltage

waveforms from the CTs and VTs, and for position indications of binary inputs. This function

may also record the calculated values such as frequency, power and calculated binary signals,

if applicable. RDRE is used also to define the trigger mode, pre-fault, post-fault etc. attributes

of the disturbance recording function.

RDRS

RDRS is a logical node for disturbance record handling and evaluation and for management of

fault data acquired by some local function. This logical node is needed as a server for HMI on

substation or even on a higher level.

RREC

This is a relay that is used for automatic reclosure of AC electrically operated circuit breakers

after they have been open by the action of other protective devices. The relay may be

adjusted to provide several reclosures at predetermined time intervals, so that in case that

the breaker does not remain closed after the first reclosure additional reclosures will be

made.

The first reclosure is usually instantaneous one. It is common practice for relay to make two

additional reclosures.at suitable graded intervals but it may be adjusted to make more

reclosures if desired.


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RBRF

Breaker failure relay is a current monitoring relay used to determine whether or not current

continues to flow into a faulted circuit for a predetermined time after a circuit breaker has

been instructed by the primary protection relays to interrupt the circuit.

The breaker failure relays are intended to act as secondary protection for the primary

protection relays). In normal operation, the breaker failure relay asserts an additional trip

signal (re-trip) to the breaker as soon as it receives the signal from the primary protection

relay. This is intended to back-up the primary protection relay in case the output from the

primary relay did not initiate the breaker trip operation.

If the retrip is successful, a larger outage opening of backup breakers is avoided. If the retrip is

unsuccessful the breaker failure relay will open all of the adjoining, upstream breakers to clear

the fault. The breaker failure relay only opens these upstream breakers if the current in the

primary breaker persists for a pre-set period of time, indicating the primary breaker is

malfunctioning. Tripping upstream breakers prevents the continued fault from causing further

damage to the system.

RCPW

A pilot wire or carrier relay protection system is used for detecting and responding to phase-to-phase, three-phase, phase-to-phase to ground, and ground current faults including

relatively low level ground current faults occurring within an electrical power network. The

pilot wire relay protection system includes current transformers coupled to transmission lines

of the electrical power network for developing coupled currents representative of the

transmission-line currents. The current transformers are positioned at the ends of a section of

the electrical power network for which protection is desired. The coupled currents from the

current transformers are inputted to pilot relays having an analog device for producing a

composite signal indicative of the condition of the protected section of the network. The pilot

wire relay also includes an electronic device to detect if preset fault limits have been

exceeded. Upon detecting a condition indicative of a fault within the protected section, the

pilot relay transmits an electrical signal to a power circuit breaker which in turn disconnectsthe protected section of the electrical power network from the remainder of the network.

RFLOThe fault locator logical node, RFLO, in case of a fault can calculate, based on the known line

parameters, the distance of the fault in kilometers.

RSYN

The synchronism-check or synchronizing device is used when two separate networks or two

electrically interconnected network sections are to be connected together.

The synchronism-check device allows circuit breaker closing only if the voltages on both sides

of the circuit breaker fulfil the preset conditions as to magnitude, phase and frequency

difference.


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RPSB

Power Swing is basically caused by the large disturbances in the power system which could

cause wrong operation of the distance relay, if not blocked. They can generate wrong or

undesired tripping of the circuit breaker and could cause severe damage to the machine if not

prevented from the generator.

A Power Swing Blocking device is available as a function in modern relays to prevent

unwanted distance relay element operation during power swings. The main purpose of the

power swing blocking function is to differentiate between faults and power swings and block

distance or other relay elements from operating during a power swing. However, faults that

occur during a power swing must be detected and cleared with a high degree of selectivity

and dependability.

The power swing or out-of-step device detects the difference in the rate of change of

the positive-sequence impedance vector, In that way it can distinguish a power swing

or an out-of-step condition. This detection method is based on the fact that it takes a

certain time for the rotor angle to advance because of system inertias. The rate of

change of the impedance phasor is slow during power swings, while during a system

fault the impedance changing rate is very fast.

Practical implementation of measuring the rate of change of the impedance is normally

performed through the use of two impedance measurement elements together with a timing

device. If the measured impedance stays between the settings of the two impedance

measurement elements for a predetermined time, the relay declares a power swing condition

and issues a blocking signal to block the distance relay element operation. After a

predetermined time the relay will trip if the power swing element is not reset.

An out-of-step tripping scheme may use the same measuring element or a different set of

measuring elements. The general operation is similar to power swing blocking except that the

expected behavior is that the apparent impedance passes through both the inner and outer

characteristic.

Control function Logical Nodes:

CALH

The definition and handling of alarms is an engineering issue. Individual alarms are generated

in the corresponding logical nodes. Alarm handling allows the creation of group warnings and

alarms. The related logical nodes can be used to calculate new data out of individual data

from different logical nodes.

For the communication purposes if a time tag is added to any data there is no differencebetween alarms and events. Remote acknowledgement with different priority and authority

can be possible.

CSWI

The switch control logical node is used to control all switchgear condition above the process

level. This logical node represents the status and control of the switching device.

The CSWI has a data object Poswith the attribute ctlVal(control value) that can


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be addressed by a substation computer. The substation computer sends a control

message to the device with the Logical Node CSWI it addresses the attribute

CSWI.ctlValand sets it to Open or Close. The operation to close a circuit breaker will

not be allowed if the configured conditions for blocking the open or close are fulfilled.

For example, if an adjacent earthing switch is in the closed position, closing a circuit

breaker would cause a short circuit and would probably damage the primaryequipment.

The function which checks whether the conditions are met is modeled in IEC 61850

with the Logical Node CILO(control interlocking condition). This interlocking

function is well known in substations. The CSWI has to communicate with the CILO to

figure out what is allowed.

CPOW

The point-on-wave breaker controller logical node should be used if the circuit breaker is able

to perform point-on-wave switching. This logical node always closes a circuit breaker with

reference to a defined phase angle of the system voltage or current. Based on the circuit

breaker operating times the tripping pulse is controlled so that the arcing contacts touch at a

defined voltage (or current) phase angle (voltage zero or maximum system voltage).

These logical nodes continuously measure the phase angle of the system via the reference

voltage and control the breaker tripping coils accordingly. It is started by a request either from

CSWI or from RREC. The developed algorithm determines the zeros of the system voltage and

detects deviation from the standard sinusoidal curve. The close command is sent to the

control logical node and then transmitted to the circuit breaker after a delay based on a fixed

relation to the phase angle. The instant of tripping pulses release are controlled by the circuit

breaker operating time, as stored in the logical node.

Controlled point-on-wave switching is a very effective way of reducing switchingtransients and enhancing circuit breaker performance, it reduces transient over-

voltages and currents associated with switching operations of shunt capacitor banks,

shunt reactors, transformers and transmission lines, It allows for optimization of the

circuit breaker arcing time.

CILO

This interlocking function logical node is used to enable a switching operation if the

interlocking conditions are fulfilled. In the case of CILO, the required input data (status

information from a few switches) are communicated through IEC 61850. They are

modeled as data objects of other Logical Nodes, e.g. XCBRs.

The standard defines two data objects that represent the outputs of the interlocking

logic: EnaOpnEnable Open and EnaClsEnable Close.

Interlocking of switchgear can be done at the bay level and at the station level.

1. Interlocking of switchgear at bay levelAll interlocking rules referring to a bay are included in this logical node.

Releases or blocking of requested commands are issued.

2. Interlocking of switchgear at station level


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All interlocking rules referring to a station are included in this logical node.

Releases or blocking of requested commands are issued. Information with the

LN bay interlocking is exchanged.

Interface, logging and archiving function Logic Nodes:

IHMI

The IHMI is an operator interface logical node. This logical node represents the operator

interface at bay level and at station level.

Front-panel operator interface at bay level is used for configuration and local control.

Local operator interface at station level is used as a workplace for the station operator.

ITCI

Telecontrol interface or remote control interface, logical node ITCI, allows users to manage a

network from a remote control point and provides the necessary interface between control

stations and the higher control level.

The role of the different interfaces is not fixed for most of the functions and is defined in the

engineering phase.

ITMI

This logical node is used for remote monitoring and maintenance using a subset of all

information available in the substation, but it is not meant to do any control.

The role of the different interfaces is not fixed for most of the functions and is defined in the

engineering phase.

IARCThis logical node is to be used as sink and source for long-term historical data used for

complete substation on station level.

Automatic process control Logical Nodes:

ATCC

The automatic tap changer controller controls automatically the transformer on load tap

changer, so that the power supply voltage is practically constant. The controller is used tomaintain a constant voltage level at feeders busbar. The controller gives commands to

increase and decrease the transformer OLTC. As these differences

in the tap position are usually discrete, the controller allows the user to set the percentage of

change between taps.

The automatic tap changer controller can receive a command for automatic or manual


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operation. Manual operation, by the operator, has priority over automatic, in order to avoid

performance failures in the case of manual operations.

AVCO

Automatic voltage control strengthens system efficiency and power quality by automatically

monitoring and controlling voltage on busbars, transformers, and tertiary reactors within a

specific range. On a power distribution system experiencing varying loading conditions, this

automatic function can effectively maintain a steady transformer secondary voltage (LV)

within predetermined limits.

Implementing automatic voltage control also decreases system losses by minimizing voltage

fluctuation and out-of-limit operation and extends life of older primary equipment by

optimizing functionality.

ARCOAutomatic reactive power control is a function to keep the reactive power flow in a substation

within a preset range using and/or capacitors.

ANCR

The grounding of a transformer star point can influence the short circuit in a network. This

grounding is dynamically determined by a Petersen coil.

In medium- and high voltage networks, the earth fault neutralizer controller (controller of

Petersen coil) is used for the automatic control of Petersen-coils, which are continuously

adjustable on load. The controller can control either to a percentage or absolute detuning-

current or a given zero-sequence-voltage. During a ground-fault, the Petersen-coil can be

corrected by the detuning and adjusted to the resonance point.

AZVTThis logical node operates when a line connected to a substation is without voltage longer

than a predetermined time. This logical node is a binary function only (voltage/no voltage).

GAPC

Logical node type Generic Automatic Process Control comprises of functions that are

sequences. These sequences may be implemented with standard PLC languages. This is a

generic node for all undefined functions.

Examples for generic automatic process node are:

1. Load sheddingRemoval, in a very selective way, of pre-selected customer demand from a power

system, as a result of the occurrence of an abnormal condition, to avoid the collapse

of the network. This load-shedding function include actual power balance, frequency

criteria etc.

2. In-feed transfer switching detects the weak in-feed. If one power in-feed becomes

unavailable or is detected as weak then the in-feed transfer switch seamlessly

switches to the remaining power in-feed to keep power flowing to the attached

8/2/2019 24417931 Substat

24417931 substation automation architecture a brief over view

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