Biblia Autom de SE.pdf

8/14/2019 Biblia Autom de SE.pdf

1/87

SC34/WG07 Book1r14

Report No: Book 1

September 2001

The automation of new and existing substations:

why and how

Sponsored by theCIGRE Study Committee 34

Copyright 2001 by theCIGRE

Need locationAll rights reserved.

This [DKH1]is an unapproved draft of a proposed GIGRE report, subject to change. Permission ishereby granted for CIGRE participants to reproduce this document for purposes of CIGREactivities. Permission is also granted for member bodies and technical committees of IEEE, ISOand IEC to reproduce this document for purposes of developing a national position. Other entitiesseeking permission to reproduce this document for standardization or other activities, or toreproduce portions of this document for these or other uses, must contact CIGRE for theappropriate license. Use of information contained in this unapproved draft is at your own risk.

CIGRECopyright and Permissions

Need location


2/87

SC34/WG07 Book1r14

ERRATA

Date Referencelocation

Change Author BaseDocument

ID

ChangeDocument

ID21-Jul-01 Chapter 04 Add Chapter 4 Ojanguren Book1r9 Book1r1021-Jul-01 Chapter 08 Editorial changes Holstein Book1r9 Book1r10

22-Jul-01 Chapter 10 Editorial changes. Clarificationof the role of a system supplierdeveloping a turnkey system.

Corlew 10D3r1 Book1r11

31-Aug-01 Chapter 03 Add Chapter 3 with editorialchanges by Holstein.

Baass Book1r13 Book1r14

Editors Notes:

1. Review and editor comments are integrated into the text as comments, which

should be printed with the document or printed separately. PDF documents willinclude all comments at the end of the document.

2. All authors should review comments, and recommendations for changes to resolvethe issue should be prepared and discussed at working group meetings. Agreementon resolution and text/figure/table changes should be sent as an attachment anEmail to the editor ([email protected]) for incorporation into the next revision.

3. Changes to the document will be identified in the Errata table shown above. Thetable includes a brief description of the change, the author of the change, the basedocument ID used to describe the change, and the change document ID thatincorporates the change.

4. When reasonably stable contributions for each chapter are in place, the editor willbegin an editorial review of the document from beginning to end to make sure that allacronyms and references are properly specified. In addition text changes will berecommended for review to smooth the language of the document for final review.

Chapter StatusChapter Status Remarks

1 To be supplied2 Book 13 Book 14 Book 15 Book 16 Book 1

7 Book 1 Version 4 update received. Editor returned draft to author for corrections.8 Book 19 Book 1 Examples received but not incorporated into Book 1.

10 Book 111 To be supplied First draft will be incorporated when chapters 2 through 10 stabilize.A Book 1B Book 1

C1 To be supplied Editor returned draft to author for corrections.C2 To be supplied


3/87

SC34/WG07 Book1r14

At the time this report was completed, Working Group 07 of CIGRE Study Committee 34 had the followingmembership[DKH2]:

Walter Baass, Chair

Riyadh Al-Umair Jurij Curc Dennis Holstein

Han Lauw John Newbury Inaki Ojanguren

Denis Rebattu Holger Schubert Ioan Viziteu


4/87

SC34/WG07 Book1r14

Table of contents

1. INTRODUCTION................................................................................................................. 1

2. WHY DO EXISTING SUBSTATIONS NEED TO BE AUTOMATED.................................... 12.1.1 Economical..........................................................................................................................12.1.2 Changes in the power system market..................................................................................12.1.3 New nature of power system market requirements.............................................................. 22.1.4 Cost reduction in operation..................................................................................................22.1.5 Cost reduction in maintenance ............................................................................................ 22.1.5.1Reduction of troubleshooting and fixing............................................................................... 22.1.5.2Reduction in maintenance cost of primary equipment ......................................................... 22.1.5.3Reduction cost in maintenance and operation of control and protection equipment............. 32.1.6 Substation installation cost reduction................................................................................... 32.1.6.1Reduction in cabling for control and protection in conventional control technology.............. 32.1.6.2Reduction in dedicated equipment for each function ........................................................... 3

2.1.6.3Additional requirement in substation.................................................................................... 4

2.2 Technical ........................................................................................................................... 42.2.1 Data requirement.................................................................................................................42.2.2 Documentation....................................................................................................................42.2.3 Functionality ........................................................................................................................ 42.2.4 Reliability.............................................................................................................................4

3. WHAT FUNCTIONS CAN BE DESIGNED INTO AUTOMATED SUBSTATIONS............... 5

3.1 From control to protection and monitoring.....................................................................5

3.1.1 Introduction .........................................................................................................................53.1.2 Typical structure of an automated system ...........................................................................5

3.2 Protection and control ......................................................................................................63.2.1 Protection............................................................................................................................63.2.1.1Bay protection .....................................................................................................................63.2.1.2Station protection ................................................................................................................63.2.2 Control ................................................................................................................................6

3.3 Metering .............................................................................................................................7

3.4 Monitoring, analysis and diagnostics..............................................................................7

3.4.1 Monitoring ...........................................................................................................................73.4.2 Analysis and Diagnostics..................................................................................................... 7

3.5 Local intelligence for operation and restoration............................................................. 83.5.1 Example support functions for intelligent operation..............................................................83.5.2 Example support functions for intelligent restoration............................................................ 8

3.6 Automatic documentation ................................................................................................83.6.1 Substation changes, upgrades, and modifications).............................................................. 83.6.2 Substation actions...............................................................................................................9

3.7 Safe and secure operation................................................................................................9

3.8 Multiple use of data...........................................................................................................9


5/87

SC34/WG07 Book1r14

3.9 Todays technologies tomorrows technologies......................................................... 10

4. EXPERIENCES TO DATE WITH THE APPLICATION OF AUTOMATION....................... 11

4.1 The experience of Iberdrola (Spain)...............................................................................11

5. POSSIBLE ARCHITECTURE OF AUTOMATION SYSTEMS........................................... 15

5.1 Computers.......................................................................................................................15

5.2 Operating systems..........................................................................................................15

5.3 Communication networks...............................................................................................16

5.4 Supervision software......................................................................................................16

5.5 Synchronization .............................................................................................................. 17

5.6 Remote interface............................................................................................................. 17

5.7 Example architectures describing substation logical structures ................................ 175.7.1 Japanese system .............................................................................................................. 185.7.2 Western hemisphere system.............................................................................................185.7.3 European system .............................................................................................................. 19

6. TIE INTO MEDIUM VOLTAGE AUTOMATION SCHEMES ..............................................19

6.1 Physical dimensions and configuration ........................................................................ 196.1.1 Switchgear dimensions .....................................................................................................19

6.1.2 Number of bays.................................................................................................................196.1.3 Secondary equipment integration......................................................................................206.1.4 Bay equipment ..................................................................................................................206.1.5 Network objects to be automated ......................................................................................206.1.5.1Switching stations.............................................................................................................. 206.1.5.2Transformer stations ......................................................................................................... 206.1.5.3Pole-tops...........................................................................................................................20

6.2 Position and importance in the power system.............................................................. 21

6.3 Operation......................................................................................................................... 21

6.4 Control system................................................................................................................ 226.4.1 Facts important for the control system............................................................................... 226.4.2 Basic configurations ..........................................................................................................226.4.3 Suggested configuration....................................................................................................226.4.4 Deviations from the HV substation control systems........................................................... 22

7. INCORPORATION OF WIDE AREA FUNCTIONS REQUIRING EXCHANGE OF DATAFOR CONTROL AND PROTECTION ............................................................................... 23

7.1 The incorporation of Wide Area Network structures in Substation Automation ........ 23

7.2 Types of applications requiring exchange of data for automation, protection, and

Control ............................................................................................................................. 24


6/87

SC34/WG07 Book1r14

7.3 Incorporation of data from remote sites........................................................................24

7.4 Speed requirements over the network........................................................................... 25

7.5 Protocols for LAN and WAN; development and evolution of IEC standards .............. 25

7.6 IED availability.................................................................................................................26

8. CURRENT STATE OF COMMUNICATION STANDARDS AND APPLICATIONS ........... 26

8.1 General............................................................................................................................. 26

8.2 Inside Substations ..........................................................................................................288.2.1 IEC 60870-5 Series...........................................................................................................288.2.1.1Introduction .......................................................................................................................288.2.1.2IEC 60870-5-103...............................................................................................................298.2.2 IEC 61850.........................................................................................................................308.2.3 IEEE-SA TR 1550 .............................................................................................................31

8.2.4 IEEE P1379....................................................................................................................... 328.2.5 IEEE P1525....................................................................................................................... 328.2.6 EN 50170..........................................................................................................................338.2.7 DNP ..................................................................................................................................338.2.8 IEC 60834.........................................................................................................................348.2.9 IEEE P1565....................................................................................................................... 348.2.10 Instrument Transformer.....................................................................................................348.2.10.1 IEC 61850-9-1.............................................................................................................348.2.10.2 IEC 60044-7 and -8.....................................................................................................358.2.11 Metering............................................................................................................................368.2.11.1 IEC 60870-5-102.........................................................................................................368.2.11.2 IEC 61107...................................................................................................................37

8.2.11.3 IEC 62056...................................................................................................................378.2.11.4 IEC 61334-4 DLMS, COSEM ......................................................................................388.2.11.5 AMRA ......................................................................................................................... 38

8.3 Surroundings...................................................................................................................398.3.1 Communication to Substations, to Power Plants, and between Control Centres ............... 398.3.1.1IEC 60870-6, TASE.2........................................................................................................398.3.1.2IEC 60870-6, TASE.1........................................................................................................408.3.1.3ELCOM90 ......................................................................................................................... 408.3.1.4IEC 60870-5-101...............................................................................................................408.3.1.5IEC 60870-5-104...............................................................................................................418.3.1.6IEC 61970 EMS ................................................................................................................41

8.3.1.7IEC 61968 DMS ................................................................................................................428.3.1.8IEC 62210.........................................................................................................................428.3.2 Wind Power, IEC 61400-25............................................................................................... 428.3.3 Market Communication, IEC 62195 TR .............................................................................43

8.4 Conclusion.......................................................................................................................43

9. LIFE CYCLE COST MODEL.............................................................................................46

9.1 Basic objectives.............................................................................................................. 46

9.2 Methodology....................................................................................................................46


7/87

SC34/WG07 Book1r14

9.3 Life cycle..........................................................................................................................489.3.1 Announcement of product discontinuation......................................................................... 499.3.2 Support after discontinuation.............................................................................................49

9.4 Details to implement the methodology..........................................................................509.4.1 Target architecture definition ............................................................................................. 509.4.1.1Requirements....................................................................................................................50

9.4.1.2Technology baseline .........................................................................................................509.4.1.3Risk management constraints ........................................................................................... 519.4.2 Logistics support: sparing strategy and support functions.................................................. 54

9.5 Cost model....................................................................................................................... 559.5.1 Cost breakdown structure..................................................................................................569.5.2 Non-recurring cost parameters..........................................................................................569.5.3 Recurring cost parameters ................................................................................................579.5.3.1Training cost......................................................................................................................579.5.3.2Maintenance cost ..............................................................................................................57

9.6 Cost estimating methods................................................................................................57

9.7 Example applications {waiting for input from EDF and others}................................... 609.7.1 Modernizing an existing substation.................................................................................... 609.7.2 Deploying a new substation............................................................................................... 60

10. ROLE OF THE SYSTEM INTEGRATOR .......................................................................... 61

10.1 The vision of the utility ...................................................................................................62

10.2 System Integrator responsibilities................................................................................. 6210.2.1 Target architecture ............................................................................................................63

10.2.2Applicable compliance documents .................................................................................... 6410.2.3 System test plans & procedures........................................................................................6410.2.4 Common Graphical User Interface ....................................................................................6510.2.5 Configuration management ............................................................................................... 6510.2.6 Operational control ............................................................................................................ 6610.2.6.1 Access control............................................................................................................. 6610.2.6.2 Settings management .................................................................................................6610.2.6.3 Report management....................................................................................................6710.2.6.4 Time synchronization ..................................................................................................67

11. FINDINGS......................................................................................................................... 69

A. DEFINITION OF TERMS AND ACRONYMS ....................................................................70

B. BIBLIOGRAPHY............................................................................................................... 74

C. PRACTICAL EXAMPLES TO RECOVER COST..............................................................75

C.1 Use of information for condition monitoring and main plant refurbishment .............. 75

C.2 Use of load profiles for system planning....................................................................... 75


8/87

SC34/WG07 Book1r14

Table of figures

Figure 3-1 Typical structure of todays automated substation.......................................................... 5

Figure 3-2 Typical structure of tomorrows automated substation.................................................. 11

Figure 4-1 Total number of failures and units installed per year.................................................... 12

Figure 8-1 Inside substations a variety of communication standards are used.............................. 27

Figure 8-2 Outside substations a variety of communication standards are used ........................... 28

Figure 8-3 Typical configuration of bay to station level communication in a HV substation ........... 29

Figure 8-4 One possible hierarchically structure in a substation.................................................... 30

Figure 8-5: Digital interface block diagram....................................................................................36

Figure 8-6 Possible trend in the close future ................................................................................. 45

Figure 8-7 Possible trend in the far future ..................................................................................... 45

Figure 9-1 Life cycle cost development methodology.................................................................... 47

Figure 10-1 System integration specification................................................................................. 62

Figure 10-2 Example of a distributed communication architecture ................................................ 63

Figure 10-3 Response time performance components.................................................................. 65

Figure 10-4 Generic Reporting Model ........................................................................................... 68

Table of tables

Table 4-1 Comparison of the experience of conventional and new technology ............................. 14

Table 8-1: Documents standard series IEC 60870-5..................................................................... 29

Table 8-2: Documents standard series IEC 61850........................................................................ 31

Table 8-3: Structure of standard series IEC 6205x for electricity metering .................................... 37

Table 8-4: Documents standard series IEC 62056........................................................................ 37

Table 8-5: Documents standard series IEC 60870-6..................................................................... 39

Table 9-1 A mathematical model for probability of failure.............................................................. 52

Table 9-2 A mathematical model for consequence of failure......................................................... 53

Table 9-3 Recommended CBS framework for cost analysis.......................................................... 56

Table 9-4 Estimating methods ......................................................................................................58

Table 9-5 Opportunity for cost reduction ....................................................................................... 59

Table 9-6 Actions affecting life cycle cost...................................................................................... 59


9/87

SC34/WG07 Book1r14

1. Introduction

2. Why do existing substations need to be automatedThe power system industry is in a fast competition to have an optimal management of thepower system network in all system levels. The privatisation of the power system industrycreates the opening of new electricity market differs in all aspects from the traditional oldmarket. A market where the consumers become customers due to which new energysupply and traders are appearing in the market. In fact, in very near future, power systemindustry all-round the word will see more and more of power producer, retailers andnetwork companies.

Therefore the need to automate the existing substations shall be evaluated by the utilities inorder to meet the expected challenges of the future market and the reliability of the existingequipment.

Each utility shall first of all, prepare itself for a coming future challenge for its networkSubstations for all levels - Transmission and Distribution. In order to do this process, theutility must acquire full knowledge of its needs of the automation and its benefits. Theutilities in their effort to automate the existing substations shall focus on two aspects thatshall influence the optimum control of its power system management business. These twoaspects are economical and technical.

2.1.1 Economical

The economical reason plays a major part in justifying existing substation automation (SA).The information about the power system gives the utility the strength to be more successfuland competitive in a free market where there will be a competition between utilities and thederegulation of the power system industry is being introduced. In this type of environmentthe information becomes a very strategic requirement in power system industry market of afast decision making environment, which cant be obtained from existing conventionaltype substation. The changes, which are occurring presently and expected in near future inthe power systems industry can be listed as follows:

2.1.2 Changes in the power sy stem market

Major changes have been taken place in the power system market and more is expected infuture. The traditionally market where Nation/Area-wise power control centres plays the roleof control and marketing the energy, since there was no other suppliers of electricity tocustomer, is disappearing gradually and this trend will continue at a faster rate. Energyservice Companies are replacing power system companies and new retailers of energy

being introduced in the market. Also, the privatisation/deregulation of the nations electricalnetworks find interest for even non-national Companies in the market. This gives thechance to have new power producer and retailers.

Such type of a market shall be open type where the consumer is becoming a customer whocan choose his supply contractor. This shall increase the competition in power system andlead to a market having a variable electricity price depending on the market competitions aswhat can be said Electricity at the Market price.

Activities of transmission and distribution utilities have to separate to open market business(energy market) and regulated business (transmission and distribution). On the energybusiness there are new functions required for running energy market, while on theregulated field, there are no major changes regarding required functions. There is only the

need to provide all necessary data for supporting energy market activities.


10/87

SC34/WG07 Book1r14

This type of environment may require that the existing substation be upgraded to providethe necessary urgent information. However, this is not the only factor, which shall beconsidered, and other additional functions in SA have to be economically proved by otherfactors, than new energy market situation.

2.1.3 New nature of pow er system market requirements

As mentioned previously, the Electricity Consumers in the new market changes point viewand becomes customers. These customers will have the choice to get power supply fromdifferent suppliers that are geographically spread over.

Therefore, new types of power supply agreements shall be introduced in the market. Thesepower agreements shall handle the power supply at different interval of different prices anddifferent suppliers. This is what is called a free market price and place. Suppliers providedaily information of the power transfer capabilities and retailers receive consumptioninformation. This requires huge, accurate, fast information of data for billing the Customersinstantaneously. Moreover, the customers also are in need to know their daily operationalcost in order to properly plan their production to minimize cost and increase their profit. Inthis case information is becoming a must and existing substations should looked intoautomation if they are going to play part of such market.

2.1.4 Cost reduc tion in operation

Operational costs have major influence of overall economic performance of the utility.Savings can be achieved on the following fields.

Personal reduction by implementation of remotely controlled substations. This is notonly the dispatching personal but also the field and maintenance crews that can bebetter co-ordinated and guided due to remote information about the current situationin substations and in the network.

Faster fault location and clearance, what cause shorter supply interruption andtherefore better economic results. This is also valid for failures of control and

protection equipment. Sequential switching and expert systems, which perform sophisticated functions

faster and more precisely than human operator.

Better and more co-ordinated network control functions as voltage/VAR control,network reconfiguration, supply reestablishment after faults and so on.

2.1.5 Cost reduc tion in maintenan ce

Utilities in such type of competitive market are looking forward to cut down cost inmaintenance. Maintenance cost cut can be divided into three categories.

2.1.5.1 Reduct ion of troub leshoot ing and f ix ing

Due to huge wirings that are interconnecting different panels, control protection etc. andequipment in existing substations, trouble shooting is a tedious and some time a toughtask. But in case of automated substation troubleshooting can be minimized due to veryminimum wiring and its limited distance. The most of trouble shooting will be towardsoftware where manpower and equipment testing is limited.

2.1.5.2 Reduct ion in maintenance cost of primary equipment

This is in simple words all material, spare parts, man-hours spent in maintaining regularschedules for primary equipment is reduced by means of proper data about the operationof such equipment. For example new distribution feeder protective relays may have featurethat can provide information about how many times the feeder breaker operated on fault

conditions rather than simple counters which counts the number of total operation of the


11/87

SC34/WG07 Book1r14

breaker. So the decision to maintain the breaker is based on actual fault operation of thebreaker. This type of data cant be obtained from conventional type substation.

2.1.5.3 Reduct ion cost in maintenance and operat ion of contro l and protect ion

equipment

With new software technology and the revolution of the digital communication andnumerical relays and digital control equipment, there will be great reduction in man-hoursspent in operation, routine testing and maintenance of conventional solid-state relays andcontrol devices.

With the use of SA system many control functions can be implemented automatically (loadshedding, sequence operation, etc) saving a lot of time and effort of the operator andavoiding misoperation. Moreover, the continuous supervision of the various signals andcomponents resulted in powerful monitoring and diagnostics of the entire installation duringoperation. As a result the maintenance work need not be on regular basis and can beplanned according to needs.

2.1.6 Substat ion instal lat ion cost reduct ion

It is expected that with the new modern equipment cost reduction can be achieved.Specifically cost reduction will be seen in consolidating of a lot of individual equipment intoone unit. However, this depends on the size and functions requirement of the substation.

However, utilities as well industrial customers need to see clear comparison examplesbetween the conventional type and the new system clarifying this cost reduction toencourage retrofitting of old substations with new modern equipment. Until now themanufacturers could not provide the required data for this study. Annex C are giving somepractical examples of the areas where cost recover are achieved.

The following equipment arrangements are considered the major cost reduction.

2.1.6.1 Reduct ion in cabl ing for con trol and protect ion in con vent ional contro l

technologyA lot of massive cabling is required between various bay in the substation and control roomin the existing conventional type substation. This huge cabling work suffers fromenvironmental factors as well as deterioration, induction, loss of signal, cable failure. Cablefailures require attendance and it taken time to trouble shout and replacement/repair.

Where in digital signal processing the problem of huge cabling is solved and massivecabling interconnection is no longer required. Only cabling is needed between primaryequipment and its local bay control cubical. The rest of the cabling to the master station inthe control room is done digitally.

In addition to the cost cut achieved by reducing the amount of cabling required, huge spaceduring construction of new substations can be saved.

2.1.6.2 Reduct ion in dedicated equipment for each funct io n

In modern substation automation, there should be expected major cost reduction toconvince the utilities to convert the existing substation to the new technology, which willprovide major saving in upgrading, installation, and maintenance of individual type functionequipment like SCADA RTUs, digital transient fault recorder (TFR), sequence of eventrecorders (SOE), interface cubicles, metering panels, control panels. This equipment if it isreplaced with a new one modern equipment, then it should have major impact in costreduction without affecting the reliability of the neither substation nor equipmentredundancy.


12/87

SC34/WG07 Book1r14

2.1.6.3 Add it ional requirement in subs tat ion

Existing substations with conventional system requires massive changes whenever a newrequirement or a function is needed. Cabling, space for new panels which to be evaluatedon case-to-case basis. Some times with the new modern system this matter is being solvedwithout the need to such type of massive changes.

2.2 TechnicalThe new business needs, which require more information, will direct the utilities to upgradethe existing substations. Therefore information is needed about the industrial as well asother types of customers, i.e. computerized load forecast, and complicated meteringsystem bulk trading and energy management. How much the data is being accurate, andmuch it can be trusted how much will be the return to the utilities/traders. Therefore thedata availability gives the utility the chance to be strong in very competitive field. Thefollowing are the major technical issues that require the upgrading of the existingconventional substation.

2.2.1 Data requ irement

Information or (data) plays a very essential part in optimal management of the powersystem. The utilities will not be able to compete if it doesnt have very well accurateinformation about all the power system components. Therefore, data is neededcontinuously to the master control stations. Data, such as alarms, breaker status, real timesampling of watts, Vars, volts, Amps, energy management programs availability and energymetering. This huge data requirement, its availability and accuracy are a must needed inmodern power system industry. Therefore, the power control centres in near future willbecoming Information Technology centres. This requires that the existing substation to beupgraded as automated substation to be able to cope with required information.

2.2.2 Documentation

Utilities at present are facing difficulties in documenting all changes and upgrades, whichare done to the network. In other words, there is no as built which reflects the actual siteconditions specifically the secondary equipment. There will be a lot of time wasted inverifying the existing installation before starting any implementation upgrade or modificationto existing installations.

With the new numerical system, it offers the system documentation as a part of the currentsystem implementation. This makes system modification of all the secondary equipment. Inthis case, the software is being updated with current system modification before putting thenew system into operation. Therefore, As Built is being updated continuously.

2.2.3 Functionality

The new modern system offers the addition of new function to the existing modernequipment, unlike the conventional existing system which might requires a lot of changes inthe secondary equipment to add additional functions. With modern control system itprovides the chance to obtain a function from different hardware units into the masterstation software.

2.2.4 Reliability

Due to fast diagnostic of the problems in the system and more information about the powersystem it increases the reliability of the substations and shortens the period of diagnosis.This resulted in a faster restoration of the substations.


13/87

SC34/WG07 Book1r14

3. What functions can be designed into automated substations[DKH3]

3.1 From contro l to protect ion and monitor ing[DKH4]

3.1.1 Introduction

All equipment for protection, control, monitoring, metering, communication, etc[DKH5]. in a

substation (S/S) is called secondary equipmentAll this secondary equipment can be linked together with serial communication buses tocommunicate with each and another.

A substation with such technologies is called an automated substation

3.1.2 Typic al stru ctur e of an autom ated sys tem

The typical structure of an automated substation [DKH6]is:

Bay-oriented intelligent electronic devices (IEDs) for all functions required in abay[DKH7]

Serial communication with a station computer

Serial communication with the network control centre (NCC)

Figure 3-1 Typical structure of todays automated substation[DKH8][DKH9]


14/87

SC34/WG07 Book1r14

3.2 Protect ion and contro l

3.2.1 Protection[DKH10]

3.2.1.1 Bay pro tectio n

All protection functions required in a bay (Line, Transformer, Generator, etc.) are performedin the bay protection IEDs[DKH11].

Examples for bay protections are:

Distance protection

Overcurrent [DKH12](O/C) protection

Differential protection

Thermal protection

3.2.1.2 Station pro tectio n

Examples for station protections are:

Busbar protection

Breaker failure protection

The data for the station protections are collected in the bays (currents, voltages, isolatorimages etc)

These datas are (pre-processed in the bay and) transmitted to by a station levelIED[DKH13] were they are processed. The result is distributed to the bay units. The bay unitsperform the necessary functions (e.g. start breaker failure function, trip functions).

3.2.2 Control

The control functions can be classified in basic and enhanced functions.

Examples for basic functions are:

Control of circuit breaker (CB)

Control of isolator (IS)

Control of earthing switch (ES)

Control of transformer tap changer

Interlocking, blocking

Synchrocheck (SC) before closing CB

Examples for enhanced functions are:

Switching sequences

Automatic isolating of faulty sections

Automatic changes of busbars

Intelligent auto reclose (AR)

Shifting of loads between lines

Intelligent load shedding

Intelligent power restoration

Optimisation of power exchange between different utilities


15/87

SC34/WG07 Book1r14

3.3 Metering

The data used for billing purposes are the metering data[DKH14].

The control and protection devises do not have the required accuracy for meteringpurposes. Therefore the metering system is normally an independent, dedicated systemwith independent, dedicated hard.- and software. The metering devices are connected tospecial metering current transformers (CT) cores and instrument voltage transformers (PT)

cores[DKH15].

The metering data can be pre-processed in a station computer (same or different HW asstation control computer), and are then transmitted to the metering department[DKH16].

3.4 Monitor ing , analysis and diagnost ics

3.4.1 Monitoring

The monitoring functions can be classified in basic and enhanced functions

Examples for basic functions are:

Switchgear status indication

Measurements (U,I,P,Q,f[DKH17])

Event list

Alarm list

Examples for enhanced functions are:

Fault records

Disturbance records

Trend curves

Measurement calculations

3.4.2 An alysis and Diagnos tics

One of the main advantages of an automated system is its ability to generate intelligentinformation, e.g. information to support the analysis or diagnosis of the substationequipment.

Examples for analysis and diagnostic functions are:

Suppression of not relevant alarms

Failure analysis

Automatically generated fault reports

Sequence of event analysis

Alarm statistics (e.g. of a feeder)

Disturbance evaluation

Condition monitoring

Maintenance prediction


16/87

SC34/WG07 Book1r14

3.5 Local intel l igence for operat ion and restoration

The station computer has all relevant date of the substation. These data are quicklyavailable and can be used for intelligent (automated) operation and restoration ofsubstation.

Typical improvements achieved are:

Clear indication of substation status (substation is ok, incipient failure, faultoccurred, etc)

System can be worked harder to the limits

Automated notification of problems

Tracking of events, alarms, faults

Detection of incipient failures

Earlier preventive measures

Maintenance on request

Performance based maintenance Reduced down time for repairs

Reduced repair cost

3.5.1 Example supp ort funct ions for intel l igent operat ion[DKH18]

Integrated substation diagnostics

Integrated condition monitoring

Plausibility checks

(Value) limit supervision

Alarm categorisation (class 1, class 2, class 3)

Automated notification of problems

Maintenance prediction (immediately, next week)

Automatic load shedding

3.5.2 Example supp ort funct ions for intel l igent restorat ion[DKH19]

Clear indication of faulty device, section

Reliable evaluation of fault history

Operating instruction Automatic change of feeder from faulty to healthy busbar

Automatic power restoration programs

3.6 Autom at ic documentat ion

3.6.1 Subs tation changes, upg rades, and mo dif icatio ns[DKH20])

Automated systems also need changes, modifications, upgrades or extensions. Suchactions are made at station level in modern systems. Datas are from there are thendownloaded to the bay devices. All changes made at station level are thereforeautomatically documented.


17/87

SC34/WG07 Book1r14

3.6.2 Subs tation action s[DKH21]

Modern automated systems record all activities, switching, changes, etc made in asubstation.

Example actions automatically monitored are[DKH22]:

Status

Events, alarms

Limit values

Plausibility checks

Example actions automatically monitored, controlled, supervised or stored are[DKH23]:

All switching (breakers, isolators, tap controller, interlocking, blockings)

Operating values (15 min average, trends)

Switching sequences

Auto reclosures

Fault / disturbance recordings

Selected events

Performance values (e.g. breaker times, running times of isolators)

3.7 Safe and secur e operation

One of the most outstanding qualities of modern automated systems is their distributedintelligence.

All actions, Interlocking, plausibility checks etc are made as close to the process aspossible. Most of the functions are therefore performed in the bay units.

The station computer (only) records all activities.

A failure in the station computer or in the communication path should therefore not result inany maloperation.

The theoretical probability of an executed wrong command is extremely small.

3.8 Mult ip le use of data

All data available in an automated system is stored and generally made available for furtherprocessing by any device

Example: The currents and the voltages are digitised in the A/D converter. The digitised

values are used for:

Protection

Metering

Display of the operational value

Disturbance recording

Reports

Evaluation

Limit value supervision


18/87

SC34/WG07 Book1r14

Multiple use of data practically and simplifies the wiring and the amount of wiring in asubstation.

3.9 Today s techno logi es tom orro ws technolog ies[DKH24]

Typical characteristic of todays technology are:

Conventional wiring from the primary equipment to the secondary devices, or Communication with proprietary field bus

Modern bay devices

Communication with proprietary station bus

Station computer

Communication Station NCC with over existing (slow) protocol

Typical characteristic of tomorrows technology are:

Modern bay device

Functionality increased with the same speed as computing capacity of the baycomputer increases

Standardised station bus (IEC61850)

Station computer functionality increased with the same speed as computingcapacity of the station computer increases

Standardised field bus (IEC61850)

Sensor and actors [DKH25]instead of CT, PT drives

Fast communication Station NCC (centre centre links)

Enhanced network function


19/87

SC34/WG07 Book1r14

4. Experiences to date with the application of automation

4.1 The experience of Iberdrola (Spain)

The following is the experience of Iberdrola, an electric utility in Spain, with a total of morethan 600 P&C [DKH28]digital units installed, taking into account bay and substation levelunits, whose installation began in 1996.

Our system basically is based on substation and bay level units. At bay level there is totalintegration of protection and control in one unitless than 100 kV, while above this, there isno integration for distance protection and control equipment (communication between themis done through conventional cabling of signals, or by means of Procome protocol foruploading protection signals). However, from Iberdrolas experience, there is no significantdifference between both situations as regards commissioning, maintenance, organisation,etc.

Iberdrola has two different manufacturers of all equipment, with full compatibility betweenthem. The typical situation, however, is that substation level equipment is from one supplierand bay level units from the other, although more complex configurations are also possible.Compatibility is reached by the Procome protocol that is being used in Spain.

The Procome protocol is a Spanish protocol, fully compatible with IEC 60870-5, which usesthe private area in order to define compatible functions.

The overall experience of these systems is good and the new technology is seen as anopportunity to improve performance, reliability and to reduce total life costs of substations.

Since the first substation was installed in 1996, no major operational problems haveoccurred. The systems have behaved as they were designed to do, with few exceptions.

Figure 3-2 Typical structure of tomorrows automated substation[DKH26][DKH27]


20/87

SC34/WG07 Book1r14

In fact, Iberdrola is stepping ahead to take advantage of this new technology:

In the year 2000, Iberdrola launched a project whose main objective is to use thisnew technology also in the upgrading of one bay in an entire substation withconventional P&C, or in extensions of existing substations with conventional control.

Also, some functions, such as, for instance, interblockings[DKH29], that in thebeginning were not included in the digital equipment due to reliability and securityreasons, are now being introduced in the digital equipment.

Moreover, the system is evolving to a higher degree of integration: for instance, at220 kV, the synchronism checking relays and circuit breaker tripping coilssupervisory relays are going to be introduced in the digital equipment, so that twodistance digital relays and one bay control digital unit are the main equipment itemsin the cubicle.

The advantages that are foreseen in the new technology are:

5. Total life costs are reduced, not only considering investment costs, but alsomaintenance costs, due to the self-checking function of new equipment.

6. Integration highly improves reliability as, on the one hand, cables and auxiliaryrelays, etc. are reduced (they are responsible for a large number of failures), and onthe other hand, integration of several functions in one unit reduces the probability offailure.

7. It is a good opportunity to achieve standard protection and control logics as the logicnow is programmed by the only two manufacturers and not determined by a lot ofdifferent engineering suppliers as before.

8. More functionality can be implemented by this technology than by previous ones.Important modifications of functionality during the life of the equipment are mucheasier.

9. A large amount of information for analysis and maintenance is available remotely.

Up to now we have had the following rate of failure of bay equipment:

3 4 5 2

78

151

296

456

0

100

200

300

400

500

1996 1997 1998 1999

Installedu

nits

Failures Equipment

Figure 4-1 Total number of failures and units installed per year


21/87

SC34/WG07 Book1r14

The typical failures of bay units are: failure of input/output boards, supply boards,communication interfaces. Typical failures of substation level units are: CPU failures,supply failures, HMI PC blocking, CPU failure avoiding reconfiguration, and communicationerrors with remote control centres, with the number of failures of substation level unitsbeing three times the number of those of bay units.

The most important failures occurred are related to hidden software bugs that were not

detected in factory reception tests. The first one came to light when a new substation levelversion of software was put under service in some substations, and this caused thesoftware of one bay unit to crash, due to a software error. The second one was also ahidden error that appeared only several months after commissioning, in one especial bay,in which the probability of happening was very high, because of especial conditions.

These problems show the importance of doing very thorough type-tests of softwareversions, so that the probability that these bugs may finally cause errors is highlydecreased.

Of the two manufacturers, one is a traditional relaying manufacturer and the other is atraditional manufacturer of Remote Telecontrol Equipment. The former has had moretrouble with substation level units while the latter has had more with bay units.

As can be seen, the failure rate of this equipment is quite good, and it has not increasedwith the number of units.

However, as with any new technology, in the early days, several problems have begun toarise:

1. The commissioning of the substations has become more complicated because neworganisations have appeared: the manufacturer of P&C equipment, digital controlengineer, and also because the changes that were previously done on site are nowprepared in the office by more skilled personnel, causing a delay between detectionof a problem and its solution.

2. Maintenance: at the moment, this is the major problem, for the following reasons:

The digital equipment evolves very fast and therefore it is costly to maintain aspares policy.

At this moment, there is a strong dependence on the manufacturer when a unitfails and has to be put in service. The maintenance departments are still notprepared to do the work without the help of the manufacturer.

3. As different functions are integrated into the same equipment, it is more difficult todetermine the commissioning and maintenance responsibility of each traditionaldepartment.

4. New versions of software implemented during commissioning may reproduce errorssolved in previous versions.

Therefore, the new challenges that utilities face is:

1. The number of software versions that are used during the commissioning processmust be reduced and a procedure that determines how a new version must betested has to be developed, in order to reduce the risk mentioned in point number 4.

2. The maintenance of new equipment has to be organised, taking into account thatutilities cannot depend on manufacturers. The documentation that has to bedelivered with the system also has to be determined.

3. A new commissioning procedure has to be developed in order to take advantage ofthe new technology and to solve the problems that appear.

4. One single organisation has to be responsible for the whole system.


22/87

SC34/WG07 Book1r14

Up to now, Iberdrola has mainly faced the commissioning step, and the following actionshave been taken, with the result that commissioning times have been reduced:

Factory tests have been established, in order to test software thoroughly beforebeing installed on site. These tests include simulation with remote telecontroldatabases. The goal of these tests is to reduce the number of software versions,and to decrease the number of errors detected on site, so that they can be solved in

real time, i.e. as they are detected. The number of organisations participating in commissioning tasks has been

reduced, and protection personnel have taken the responsibility for on site finaltests.

Complex automatisms are thoroughly laboratory tested. These tests are type-tests,so that only simple final functional tests are carried out on site each time.

As a summary, a comparison between conventional and new technology is attached.

Table 4-1 Comparison of the experience of conventional and new technology

Conventional control Integrated control

On site modifications during commissioning areperformed by erection personnel

On site modifications during commissioningare performed by erection personnel or bydigital equipment manufacturer

These personnel are permanently on siteduring commissioning.Their qualification is low.

Digital equipment manufacturer personnel arenot on site permanently. Modifications aremade in the office and afterwards sent to thesubstation. Their qualification is medium.

Control equipment is similar in all substationsand easily interchanged => It is quite easy tohave spares with a minimum stock

Digital equipment develops very fast and is noteasily interchanged => a big stock is neededin order to have spares.

Control/protection/telecontrol functions aredone by different equipment => maintenanceresponsibilities are perfectly defined and limited

Control/protection/telecontrol functions aredone by the same equipment => difficulty todefine the limits of maintenanceresponsibilities of each organisation.

Maintenance and simple control modification issimple and the risk of errors is low

Maintenance and simple control modification iscomplex and the risk of errors is high, due tothe complexity of software/configuration/firmware/hardware versions

Commissioning can be done unit by unit, withfinal functional tests

Final functional tests are the only way to docommissioning tasks, due the high level ofintegration

High reliability Very high reliability

High necessity of space Low necessity of space

Medium cost of equipment and high cost ofinstallation

Medium cost of equipment and low cost ofinstallation

Low information for analysis and maintenanceand locally available

Extensive information for analysis andmaintenance and remotely available

Limited functionality High functionality

Long life Life unknown but probably medium

Introduction of important modifications is Introduction of important modifications is


23/87

SC34/WG07 Book1r14

Conventional control Integrated control

complex and expensive simpler and less expensive

5. Possible architecture of automation systemsToday, most automation substation systems developed by manufacturers have a similar

architecture, except for a few differences. Usually, the system includes a central computerconnected to decentralized computers and protection relays, and also synchronization andcommunication components. The system operates by means of a local communication(LAN) with a human-machine interface (HMI) for control and monitoring of the system andprocess. However the HMI is dedicated to the human interface, and the system andprocess can operate undegraded even if the HMI is out of service. However, there areminor differences in terms of architecture. They result from the number of networks usedand their types, the number of computers and their locations, etc. There are only four majoralternatives to the architecture that is usually chosen. The first two are whether or not thereis a central computer (and database) or whether there is no central computer and thedatabase is distributed. In either of these cases, the decision may be made to combineprotection and control in one IED, or to have protection in a physical device separate from

control.

First, we will endeavour to investigate the specific points of each different type ofarchitecture: computers and their operating systems, communication networks, supervisionsoftware, synchronization and remote interface.

Then, we will consider the architecture overall. This general description is completed by thepresentation of three typical architectures at an international level in order to betterunderstand the differences that exist between them.

5.1 Computers

At present, most industries offer automation substation systems for which the CPU is a

dedicated controller. In their industrial versions, they can be used without any problems ofimmunity to electrical interference. However, this is not the case for the associatedconnections. The supply is abundant but the input/output boards available on the market donot take the environmental constraints of an electrical substation into consideration.

To deal with this type of problem, there are two solutions facing the automation substationsystems supplier: to develop specific boards in-house or to adapt the boards available off-the-shelf. The second solution is more interesting for the following reasons: PC typeequipment and the associated material is changing quickly and only a board supplier who iscommitted to the profession has fast enough reactions and the knowledge needed to fullyaddress these changes. Delegating this activity means that an automation substationsystems supplier may only handle adaptation to electromagnetic constraints and can

therefore focus on this basic profession.

5.2 Operating sys tems

In addition to proprietary solutions now less widely used than previously, two families ofoperating systems are now available on the market:

GPOS (General Purpose Operating System): Windows, Unix, Linux,

RTOS (Real Time Operating System): pSOS, QNX, VxWorks, RTX, Lynx, CMS, etc.

The former are widespread for the following uses: Unix for master stations in controlcenters, Windows NT for HMI in electrical substations. The latter are more generally usedwhen real-time constraints are particularly demanding i.e. for protection and logic controlfunctions.


24/87

SC34/WG07 Book1r14

To add additional functionalitys to their operating systems, GPOS manufacturers areattempting to upgrade them and equip them with some real-time characteristics; however,the corresponding performance is still particularly remote from the performance offered bygenuine real-time systems. The best approach consists in upgrading them in greater depth.Products like RTX 4.1 from VenturCom or INTime 1.20 from Radisys or Hyperkernel 4.3from Imagination System mean that the same processor can offer a particularly widespreadoperating system, Windows NT, with the same real-time characteristics as an RTOS. In

parallel, other upgrades will allow developments based on Unix systems.

5.3 Comm unicat ion networks

Communication networks can be used at station level or bay level. In the case of twodistinct networks using the same system, these networks can be of different types andtherefore not operate with the same protocols. There are also systems equipped with asingle local area network fulfilling functions at different levels.

Overall, all the communications networks used in automation substation systems can beused for well implementing the functions attributed to them. More particularly, they can beused for adapting automation substation systems to the SCADA protocol and to the various

IED communication protocols (standard or even proprietary). There is no problem ofimmunity to interference with optical fiber. But there is a major problem with UTP-5 cable(copper for Ethernet) in substations. Tests have shown that the use of copper Ethernetcabling in substations should be limited to lengths of 1 meter or less, and within the sameequipment rack or cabinet.

For the protocols used, we will simply mention the most widespread protocols.

For the lower levels (physical levels and link as per ISO classification), substation networksare above all distinguishable by two main characteristics:

The topology: ring, star or bus,

The access mode: CSMA/CD, Token.

TCP/IP based on Ethernet is an example of widely used networks.

Then, there is a major standard draft that appears to be more and more essential: the IEC61850 (Ref. Clause 3). This draft tries to standardize data and service models for thecommunication in substations. In the USA, the Utility Initiative project is refining theGOMSFE data objects and providing this work as input to IEC 61850-7-4.

Today, communication network developments concern more essentially the standards usedand, in particular, interoperability between automation substation systems and theequipments connected to them.

The systems offered by manufacturers are more or less open and some projects providefor interoperability that is far more extensive than that concerning IEDs. However, this is

still on the borderlines and is at some distance from the international proposal dealt withhere. Indeed, at present, it is impossible on the commercially available systems to have acentral computer from a given manufacturer cohabit with the decentralized modules ofanother.

5.4 Superv isio n sof tware

This point is, strictly speaking, on the sidelines of the system architecture but it is worthmentioning in that the HMI is an integral part of the system.

The software available on the market like iFix from Intellution or InTouch from Wonderware,come from other application areas and are not entirely tailored to use in electrical

substation control and monitoring systems. They involve limitations or require manufacturer


25/87

SC34/WG07 Book1r14

arrangements that are difficult to implement. That is why several manufacturers aredeveloping their own supervision software independently of the market supply.

5.5 Synchronization

The manufacturers are using two approaches:

Synchronization at the central computer, which then dispatches the information tothe other computers via the communication network. This simplifies clockconnection but causes problems of synchronization between various systemcomponents. Furthermore, this method doesnt allow high performance.

The central computer, the decentralized computers and the IEDs receive timeinformation directly from the sync clock. In this case, synchronization is better butimplementation is more difficult (requirement to equip each component with asuitable input and have an associated timing bus).

5.6 Remo te interface

The analyse leads to state there are two main types of communication depending on the

security and on the kind of traffic.

The conventional real time SCADA requiring high availability,

The other one allowing data exchanges and maintenance for example.

5.7 Example architectures describ ing subs tat ion logical structu res[DKH30]

As regard manufacturer proposals, there are basically three architectures for automationsubstation systems: the Japanese one, the western hemisphere one and the Europeanone. These architectures are very similar, with few differences[DKH31]. So first, we can quoteseveral factors influencing the architecture:

The size of the station (number of LANs, a single Ethernet segment for bothsubstation and bay level, or several segments, one for substation level and othersfor bay level),

The voltage level, safety requirements, availability (redundancy or not of LANs andbay controllers; integration control / protection or not),

The cost (number of devices, redundancy, which is not shown in the pictures),

The topology of the substation,

The operating procedures of the country or the utility.

Nevertheless, the functionalitys proposed by each of the systems are not described in that

they are relatively similar from one system to another.


26/87

SC34/WG07 Book1r14

5.7.1 Japanese sy stem

Protection and control are independent in this system, even if in transmission a protection /control configuration is used. The operation support is a dedicated LAN.

LAN 1: protection and control,

LAN 2: station level,

LAN 3: operation support system.

5.7.2 Western hem isph ere sy stem[DKH32]

IED: bay controller and protection

JAPAN

ELECTRICAL PROCESS

Station Control Unit

LAN 2

Operation Support Unit

Remote Terminal Unit

LAN InterfaceModem

LAN Interface

Star Coupler Star Coupler

Data Acquisitionand Control Unit

Data Acquisition and

Processing Unit

Protection

LAN 1Modem

LAN 3

StationLevel

Bay Level

WESTERN HEMISPHERE

ELECTRICAL PROCESS

Local HMI

RTU

BASECALCULRemote SCADA

IED (bay controller + protection)

Time generatorIrig B

ELECTRICAL PROCESS

IED

Database server

Serial Bus Bus fordisturbance

recorder

Timing


27/87

SC34/WG07 Book1r14

5.7.3 Euro pean sys tem

This architecture can be centralized, if there is a substation controller with a PLC, anddistributed, if there is not a substation controller but bay control units[DKH33].

6. Tie into medium voltage automation schemes

6.1 Physical dimension s and conf igu rat ion

6.1.1 Switc hg ear dim ension s

MV switchgear requires because of smaller isolation distances less space, thanconventional HV switchgear. MV switchgear normally consists of cubicles, where differentbays are located. All primary equipment including circuit breakers (CBs) and CTs VTs ishoused in such a cubicle. The width of such cubicle does not exceed 2 m, often even lessthan 1 m. Therefore the whole MV switchgear is very compact.

There are also MV Gas Insulated Switchgears (GIS) available on the market, but from thepoint of view of the space needed, they dont bring many advantages. Their advantages aresupposed more in total life-cycle costs and easier maintenance, especially in heavieroperation conditions.

6.1.2 Number of bays

Since MV substations (substations) are used for power distribution, high number of bays inone substation is very often. Number of MV bays can be easily up to 40. Even in that case,switchgear dimension will be from 40 to 80 m long.

EUROPE

ELECTRICAL PROCESS

HMI and storing data

Bay Controller

Substation network

AL

IMENTATION

BASECALCUL

Gateway

Lead MasterController

(optional)

Protection unit

Bay 1 Bay 2 Bay 3

or

Substation bus


28/87

SC34/WG07 Book1r14

6.1.3 Second ary equipment integratio n

Secondary equipment can be located directly in switchgear cubicles. Sometimes, there areadditional protection panels located in the other (protection) room. Because of less wiringintegration of secondary equipment into cubicles is better.

There are local control equipment, protection relays, interlocking, synchro-check, energymetering, power quality metering, logical function relays, all located in cubicles. If

distributed control system is applied for telecontrol, also bay control units are integrated intocubicles. Modern bay units already cover most of mentioned functions therefore only onedevice per cubicle is needed. Since the secondary equipment is mounted very close to theprimary equipment, it is more exposed to electromagnetic (EM) disturbances, especially inolder substation, where primary equipment remain the same in the phase of stationautomation.

Smaller dimensions of the switchgear and less important position in overall power systemnetwork have influence on substation automation system functionality and economicalcriteria for different solutions. There is not always newest technology or distributedautomation system the correct and most economical solution. There are much more MVsubstation in the system and therefore costs are much more important criteria for

substation automation system configuration and installation. Since dimensions are smaller,hard-wired connections can be often used instead of powerful communication networksespecially at process bus level and serial communication links instead of network do justgood on station level. In such case, little more is spent on installation works, but on theother hand cheaper equipment can be chosen and multi-vendor solutions can be applied,which give the utility brighter choice of secondary equipment to be installed.

6.1.4 Bay equipment

It is very common, that MV CBs are mounted on trolleys and can be drawn out from thecubicle. This has many advantages regarding maintenance and operation. CBs can bereplaced in a minute. Contacts on the trolley are than used as disconnectors. For thisreason, signal lists and commands at this point are different from these for HV switchgearand also operation is different. Position of trolley cant be controlled remotely. CBs arecapable only of 3-pole operation, since all tree poles are driven by the same mechanism.No single pole operation is possible normally.

6.1.5 Networ k ob jects to be autom ated

6.1.5.1 Swit chi ng station s

These objects can be connected into the substation control system. They are remotely orlocally controlled. Since switching stations can be controlled from control centre orsubstation Human Machine Interface (HMI), attention should be paid to the controlauthorisation. If substation is controlled locally, switching station can still be controlled by

control centre even in the case when it is connected directly into the substation controlsystem. Therefore, substation control system has to be able, to control part of equipmentlocally and part of equipment remotely.

6.1.5.2 Transfo rm er statio ns

Transformer stations have normally no influence on substation automation system, evenwhen they have information links into the network control system.

6.1.5.3 Pole-tops

Pole-tops have normally no influence on substation automation system, even when theyhave information links into the network control system.


29/87

SC34/WG07 Book1r14

6.2 Posit ion and impo rtance in the power system

MV substations are less important for the integrity of the entire power system. They areused only for distribution purposes and affect only limited area of the MV network.Configuration of the network normally doesnt change during operation. Since there are notmany activities, that personnel have to do during operation, automation and remote controlof these substations is logical.

Generally, there is more MV substation (Distribution HV/MV) than HV substation(Transmission EHV and HV) in the power system. Ratio in Slovenia for example is 3.5 to1 and similar in the other members of the UCTE. Since there are so many MV substationsin the network and they are less important for the power system as a whole, priceoptimisation in the process of automation is necessary. This is done in less redundancyused and less functionality applied.

6.3 Operation

It is typical for MV network that it operates in radial configuration. Network is built inmeshed configuration, but is than configured by switching states of disconnectors, loadswitches and CBs into a radial network.

Generally, in MV substation different protection functions are applied, than in HVsubstation. There are normally no backup relays used in bays. Backup is located one levelhigher, since MV network is supplied in radial configuration. The time co-ordination insettings is applied to achieve selectivity. Because of economical reasons, integratedsolutions of so-called feeder terminals are used with integrated protection and controlfunctions. Main protection is over-current (O/C) earth-fault (E/F) protection for short circuitand earth fault clearing.

In the case of meshed network configuration, ring lines or power supply located on MVfeeder also directional protections have to be used. If MV feeder is not of threeconfigurations, but is just point to point supply feeder, also other protection schemes areused, as pilot-wire protection for example.

There are generally three different ways of neutral point grounding in MV network. Forsmaller networks, isolated neutral point is often used. When the networks are of biggersize, capacitive current grows bigger and operation with isolated neutral point is notacceptable any more. In that case, compensated or low resistance earthed neutral point isapplied. All the details about neutral point treatment depend additionally on earthingsystems of transformer stations and substation, ground characteristics and operationalpractise in utility. Protection schemes and control functionality are in close relation to theway of neutral point grounding.

The operational switching state of the MV network remains unchanged during the season.The only interventions are necessary because of faults or maintenance. Few times in theyear, network configuration might be changed any way because of optimisation purposes.New state is adapted to the new season loading conditions in order to minimise losses andoptimise voltage profile.

Voltage profile is maintained by tap position of transformers. Taps of MV/LV transformerstations are set manually and remain in a position for years. These tap changers are notable to change during operation. They are set based on the seasonal measurements ofloads and voltages. Dynamic voltage control is performed in substation on powertransformers. They are equipped with ULTCs (Under Load Tap Changer). There are oftenalso capacitor banks or shunt reactors in a substation and network it-self to additionallycompensate the reactive power and so co-operate in voltage control. On transformers, twokinds of automatic voltage/VAR control are applied. The first one keeps voltage constant onMV busbar and actually compensates only HV network voltage drops. The second one

actively control voltage in MV network using so called compensation based on active orcomplex power and network parameters.


30/87

SC34/WG07 Book1r14

6.4 Control system

6.4.1 Facts impo rtant for the contro l system

There are some facts that cause differences in control system configuration of MVsubstation in comparison with HV substation.

MV substation is not so important for the HV transmission power system operation.

There are more MV substation-s, than HV substations, what influence costsreduction.

There is less and different functionality of control system required in MV substation.

Physical dimensions of the MV substation, especially MV switchgear, are smaller.

Therefore, generally no redundancy of equipment on bay level is required in the controlsystem of MV substation. Since there are many MV substation, cost reduction andoptimisation is much more important by purchasing of the substation control system.

6.4.2 Basic con figu rations

Basically, there are two configurations of the control system: Decentralised system with smaller intelligent decentralised bay units interconnected

with communication links (station bus) to the station level. Processing power islocated in every bay.

Centralised system with one centrally located unit at the station level. Amount ofneeded wiring is not so critical since the MV switchgear is small in physicaldimensions.

There are also numerous configurations available on the market, where combination ofboth approaches is applied. Only distributed I/O units can be connected to the mainprocessing unit or some distributed intelligent units can be connected to the central unit,which acts also as communication/station computer.

All mentioned configurations can very well serve MV substation automation functionalityand each of them can be good choice in particular substation configuration and particularcriteria combination.

6.4.3 Sugg ested con figu ration

However, basic suggested configuration is distributed one, where IEDs are interconnectedusing station bus. It remains the same as in HV substations, since MV is normallycombined with HV in the same substation.

6.4.4 Deviat ions from the HV sub stat ion control systems

There is generally no need for process bus, since all the elements of the bay, as CTs andVTs, breakers and disconnectors are physically very close together in the cubicle. They caneasily be hardwired to the integrated protection/control unit in pre-fabricated MV cubicles.

For station level communication guidelines, IEC 61850 can be recommended, since itallows exchangeability of equipment and facilitate maintenance and possible expansions ofthe control system.

There are strong communication links connecting substation with CC (Control Centres)similar to the situation in the HV substation.

For MV network objects, communication facilities are selected, which are available on thespot because of economical reasons. These facilities can be initially even meant for otherpurposes (CTV, cellular telephones and others). It is reasonable therefore to concentrate

information into substation control system and then route them to CC. Influence of MVnetwork objects automation on substation automation system is in the first place integration


31/87

SC34/WG07 Book1r14

of information from these objects into substation automation system. Therefore additionalinformation interfaces have to be added to the control these systems using differentcommunication facilities. Pole tops are connected into the system via radio links, leastlines, CTV, PSTN, DLC or any other available communication media.

Another change is, that also these objects have to be considered in substation structure,especially in functions of interlocking, sequential switching orders and of course in faulted

network segment isolation process and network reconfiguration. These functions aregetting automated, what helps the personnel to locate the fault in the network faster andreduce the supply interruption time, what is actually the basic task of MV networkautomation.

It is very important in such case, that control can be switched from local (substation HMI) toremote (Control Centre HMI) for these objects separately from the substation itself.

7. Incorporation of wide area functions requiring exchange of datafor control and protection

7.1 The incorp orat ion of Wide Area Network structures in Substat ion Autom at ionWide area functions aim at the execution of (automated) protection and/or control functionsin a substation, that need to use information coming from a more extensive area than iscovered by the substation itself to be performed correctly. Normally, the information neededis coming from directly interconnected substations, but it can also be information comingfrom an even wider area or connected networks e.g. from different voltage levels. Possibleapplications range from regional interlocking and synchronization schemes, regionalvoltage control schemes up to inter-tripping and protection schemes.

Over the last years the incorporation of LAN and WAN technologies in the Automation andcontrol of electrical power networks has become more and more common. Both inside andoutside the substation environment, devices and communication protocols have been or

are being adapted to the use of Local and Wide Area Networks. The use of computernetworks like Ethernet for communication between intelligent electronic devices (IEDs)offers speed, transfer capacity and versatility. Thus suggesting, that the implementation ofwide area functions is now feasible.

There are, however other considerations that prevent the practical implementation of suchfunctions. Factors that have to be taken into account are security, availability,communication speed, and response time. Of importance to the performance required isthe load imposed upon the communications medium, the limitations that protocols imposeon the speed and functionality of communication, and the suitability of the softwareapplications in the devices to make full use of the communication capability. Manyapplications aimed at in wide area functions require on-line information at a speed that iscurrently only feasible within very strict limitations and conditions of the communicationnetwork. Examples of applications requiring communication between IEDs are covered bye.g., IEEE PSRC Working Group H5. Currently, there are several pilots in progress todetermine the network conditions to be able to guarantee the data transfer rates requiredfor these applications.

Taking these conditions into account, the incorporation of computer networks in powernetwork automation, control and protection represents a huge potential for new and moreefficient methods to be implemented, and with it a huge potential for cost reduction andincrease of efficiency in the use of the power network.


32/87

SC34/WG07 Book1r14

7.2 Types of appl icat ions requir ing exchange of data for automat ion, protect ion,

and Control

For applications to be automated on a substation level, the need for human interferencehas to be excluded, or at least minimized. The reason for this is the ongoing trend forunmanned substations. It shall be possible to pre-program the schemes to be automatedwithout the need for human evaluation. Typically, the requirement for exchange of data

includes the requirement of information to be made available to the network by IED'sconnected to the network and a data model to enable the processing of these data in thedesired application