lecture 7 final

EE599d Smart GridsLecture No: 7a

DISTRIBUTION AUTOMATION EQUIPMENT(CHAPTER NO: 6)

6.1 INTRODUCTIONPower Transmission and Distribution

4/8/2015Dr. Syed Abdul Rahman Kashif

Power Delivery Steps(Generation, Transmissionand Distribution).

Operation of the generationand transmission systems ismonitored and controlled bySupervisory Control and DataAcquisition(SCADA) systems.

Traditionally, the distributionnetwork has been passivewith limited communicationbetween elements.

Primary circuits

Generating Plant

Step-up transformers

Circuit breakers

Transmission System

Transformers in Bulk power substations

Solar orWind Sources(100KW to 1MW)

One-phaselateral feeder

DistributionTransformer

DispersedStorage and generation (DSG)

VoltageRegulator

Capacitorbank

Sub-transmissionsystem

Distributionsubstation

Three-phasePrimary feeders

Battery orFuel cells,1 to 25 MW

DSG Sectionalizing switch

DSG PhotovoltaicPower supply, up to 100 KW

Home

Detailed Overview of Power Delivery Steps

Generation System

Transmission System

Distribution System

substations transformers circuit breakers feeders sectionalizing switches capacitor banks voltage regulators DSGs customers

- HT customers- LT customers

Smart Grid Infrastructure

Electricity DispatchingControl Center

PowerGeneration

Transmission Distribution

Substation Automation

Customers

Distributed Energy Integrated

Advanced Metering Infrastructure

Substation Automation in Smart Grid

Electricity DispatchingControl Center

Electricity consumption, switchboard operation, information gathering, station decision making feedback

Grid intelligence strategic decision,T&D automated management

Substation

6.1 INTRODUCTION ContdFunctions performed by SCADA

These link the various elements through communication networks (for example, microwave and fiberoptic circuits) and connect the transmission substations and generators to a manned control center thatmaintains system security and facilitates integrated operation.

Central Control

In larger power systems, regional control centres serve an area, with communication links to adjacentarea control centres.

In addition to this central control, all the generators use automatic local governor and excitation control.Local Control

Local controllers are also used in some transmission circuits for voltage control and power flow control,for example, using phase shifters (sometimes known as quadrature boosters).

Local Automation Functions

Local automation functions are used such as on-load tap changers and shunt capacitors for voltagecontrol and circuit breakers or auto-reclosers for fault management.

The connection and management of distributed generation are accelerating the shift from passive toactive management of the distribution network due to connection of distributed generators.


Generation

Transmission

Distribution

6.1 INTRODUCTION ContdNeed of Active Management in Distributed Generation

Without active management of the network, the costs of connection of distributed generationwill rise and the connection of additional distributed generation may be limited

The connection of large intermittent energy sources and plug-in electric vehicles will lead toan increase in the use of Demand-Side Integration and distribution system automation.

The video link will depict the Distributed Intelligence !!


6.2 Substation Automation Equipment

Old Substation

The secondary circuits of the circuit breakers,isolators, current and voltage transformersand power transformers were hard-wired torelays.

Relays were connected with multi-drop seriallinks to the station computer for monitoringand to allow remote interrogation.

The real-time operation of the protection andvoltage control systems was through hard-wired connections.


6.2 Substation Automation Equipment

Modern Substation

Two possible connections (marked by boxes) ofthe substation equipment are shown in Figure 6.3

Levels of Automation

The station level includes the substationcomputer, the substation human machineinterface(which displays the station layout and thestatus of station equipment) and the gateway tothe control centre.

The bay level includes all the controllers andintelligent electronic devices (which provideprotection of various network components and areal-time assessment of the distribution network).

The process level consists of switchgear controland monitoring, current transformers (CTs),voltage transformers (VTs) and other sensors.


CONNECTION 1

Analogue signalsare received fromCTs and VTs (1 A or5 A and 110 V) aswell as statusinformation and aredigitised at the baycontroller and IEDs.

CONNECTION 2

Analogue & digital signalsreceived from CTs & VTsare digitized by theinterfacing unit. Theprocess bus and stationbus take these digitalsignals to multiplereceiving units, such asIEDs, displays, and thestation computer that areconnected to the Ethernetnetwork.

Control Hierarchy

( From: Turan Gonen, Electric Power Distribution System EngineeringMcGraw-Hill Book Company )

Control Center Architecture

.

..

Modems

FES 1 & 2

DAH

RTUs inthe field

SCADA Host Systems

LAN

MMI 1 MMI 6

VideoProjector

App Server

DMP -1

DMP -2

DT 1 & 2

PERIPHERALSERVER -1

PrinterSharer PERIPHERAL

SERVER -2

TimeCenter


6.2.1 Current Transformers

Current transformers (CTs) are used to transform the primary current to a lower value(typically 1 or 5 A maximum) suitable for use by the IEDs or interfacing units.

Measurement CTs are used to drive ammeters, power and energy meters. They provideaccurate measurements up to 120 per cent of their rated current. In contrast, protection CTsprovide measurement of the much greater fault current and their accuracy for load current isgenerally less important.

Measurement CTs are specified by IEC 60044-1 according to their accuracy classes, of 0.1,0.2, 0.5 and 1 per cent at up to 120 per cent of rated current.

Protection CTs are normally described for example, as 10 VA Class 10P 20. The first term(10 VA) is the rated burden of the CT that can have a value of 2.5, 5, 10, 15 or 30 VA. Theaccuracy class (10P) defines the specified percentage accuracy. The last term (20) is theaccuracy limit (the multiple of primary current up to which the CT is required to maintain itsspecified accuracy with rated burden connected).

Measurement versus Protection CTs

Rogowski Coil While iron cored CTs and hybrid CTs (an iron cored CT with an optical transmitter) remain the most widely

used CTs in the power system, high accuracy designs such as the Rogowski coil formed on a printed circuitboard and optical CTs are becoming available.

Rogowski coil CTs are used in a Gas Insulated Substations (GIS). The secondary winding of the coil is amulti-layer printed circuit board as shown in Figure 6.7 with the upper and lower tracks of each layerconnected by metal vias (thus forming a rectangular coil). The voltage induced on the secondary windingsdue to primary current is integrated (as a Rogowski coil gives di/dt) by the sensor electronics to obtain thevalue of the primary current.


Optical CTs Optical CTs use the Faraday

effect, whereby the plane ofpolarisation of a light beam whensubjected to a magnetic field, isrotated through an angle. Thisangle of rotation is proportional tothe magnetic field thus to theprimary current.

The opto-electronics comparesthe polarisation of the light beamentered into the optical fibre andthat collected after beingsubjected to the circular magneticfield. The angle of deflection isused to generate digital signalsproportional to the line current.



6.2.3 Voltage Transformers

It is necessary to transform the power system primary voltage down to a lower voltage to be transferredthrough process bus to IEDs, bay controller and station computer.

The secondary voltage used is usually 110 V. At primary voltages up to 66 kV, electromagnetic voltagetransformers are used but at 132 kV and above, it is common to use a capacitor voltage transformers (CVT).

Accuracy classes such as 0.1, 0.2, 0.5, 1.0 and 3.0 are commonly available. For example, Class 0.1 meansthe percentage voltage ratio error should not exceed 0.1 per cent at any voltage between 80 and 120 per centof rated voltage and with a burden of between 25 and 100 per cent of rated burden.

The basic arrangement of a high voltage CVT is a capacitor divider, a series reactor (to compensate for thephase shift introduced by the capacitor divider) and a step-down transformer (for reducing the voltage to 110V). The voltage is first stepped down to a high value by a capacitor divider and further reduced by thetransformer.

Some VTs use a similar technique to optical CTs based on the Faraday effect. In this case, an optical fibre issituated inside the insulator running from top to bottom and is fed by a circular polarised light signal.


6.2.2 Intelligent Electronic Devices

The name Intelligent Electronic Device (IED) describes a range of devices thatperform one or more of functions of protection, measurement, fault recording andcontrol.

An IED consists of a signal processing unit, a microprocessor with input and outputdevices, and a communication interface. Communication interfaces such as EIA232/EIA 483, Ethernet, Modbus and DNP3 are available in many IEDs.

Various Devices include: Relay IED Meter IED Recording IED


6.2.3.1 Relay IEDProtection Functions of Relay IED

Three-phase instantaneous over-current: Type 50(IEEE/ANSI designation)

Three-phase time-delayed over-current (IDMT): Type 51 Three-phase voltage controlled or voltage restrained

instantaneous or time-delayed overcurrent: Types 50Vand 51V

Earth fault instantaneous or time-delayed over-current:Types 50N and 51N

The local measurements are first processed and madeavailable to all the processors within the protection IED.Various algorithms for different protection functions arestored in a ROM.


6.2.3.2 Meter IED A meter IED provides a comprehensive range of functions and features for measuring three-phase and

single-phase parameters.

A typical meter IED measures voltage, current, power, power factor, energy over a period, maximumdemand, maximum and minimum values, total harmonic distortion and harmonic components.

6.2.3.3 Recording IED Even though meter and protection IEDs provide different parameters (some also have a data storage

capability), separate recording IEDs are used to monitor and record status changes in the substation andoutgoing feeders.

Continuous event recording up to a resolution of 1 ms is available in some IEDs. These records aresometimes interrogated by an expert to analyze a past event. This fault recorder records the pre-faultand fault values for currents and voltages. The disturbance records are used to understand the systembehaviur and performance of related primary and secondary equipment during and after a disturbance.


6.2.4 Bay Controller

Bay controllers are employed for control andmonitoring of switchgear, transformers and otherbay equipment.

The bay controller facilitates the remote controlactions (from the control centre or from an on-sitesubstation control point) and local control actions(at a point closer to the plant).

The functionalities available in a bay controller canvary, but typically include: CB control switchgear interlock check transformer tap change control programmable automatic sequence control.


6.2.5 Remote Terminal Units

The distribution SCADA system acquires data (measurements and states) of the distribution networkfrom Remote Terminal Units (RTU).

This data is received by an RTU situated in the substation (referred to here as the station RTU), from theremote terminal units situated in other parts of the distribution network (referred to here as the fieldRTU).

The field RTUs act as the interface between the sensors in the field and the station RTU. The mainfunctions of the field RTU are to: monitor both the analogue and digital sensor signals (measurements)and actuator signals (status), and convert the analogue signals coming from the sensors and actuatorsinto digital form. The station RTU acquires the data from the field RTUs at a predefined interval bypolling. However, any status changes are reported by the field RTUs whenever they occur.

Modern RTUs, which are microprocessor-based, are capable of performing control functions in additionto data processing and communication. The software stored in the microprocessor sets the monitoringparameters and sample time; executes control laws; sends the control actions to final circuits; sets offcalling alarms and assists communications functions. Some modern RTUs have the capability to time-stamp events down to a millisecond resolution.

6.3 Faults in the Distribution System

Transmission systems use fast-acting protection and circuit breakers to clear faults within around 100 ms. Incontrast, the time-graded over-current protection of distribution circuits and their slower CBs only clear faultsmore slowly, typically taking up to 500 ms.

Short-circuit faults are inevitable in any distribution system and so interruption in function of sensitive loadequipment can only be avoided by doing the following: Ensuring the load equipment is robust against these transient voltage changes Using very high speed protection and circuit breakers Adding equipment to mitigate the voltage depressions for example, a Dynamic Voltage Restorer

(DVR) or STATCOM


Substation with Two Feeders

Existing: Feeder Fault without DA

Breaker at the substation clears the fault All customers on the feeder lose power Crews need to patrol the entire length of the feeder to

locate the fault

Future: Feeder Fault with DA Fault Isolation

Breaker at the substation clears the fault

DA locates the fault and isolates the faulted segment of the feeder

Future: Feeder Fault with DA Service Restoration

DA reconfigures feeders, closes the breaker and restores power to all unfaulted segments

Crews can be dispatched directly to the faulted segment

RDifferent Types of Devices

R2

Over-Head Networks: Types of faults

Temporary faults

Permanent faults

80% 20%

Temporary Faults

Temporary faults can be cleared by the use of Automatic Circuit Reclosers (ACRs)

RTemporary Fault: One Recloser

R15 s

C

O

Time

100%

Temporary Fault: One Recloser

R15 s

C

O15 s

Time

100%


R15 s

C

O15 s 15 s

Time

100%


R15 s

C

O15 s 15 s

Time2 mn

100%


R1

Temporary Fault: Two Reclosers

R2

R1Network A- 50% Network B- 50%

Network B

Time

Temporary Fault: Two Reclosers

R2

Permanent Faults

Permanent faults cannot be cleared by automatic reclosing

To manage permanent faults, the best solution is to add some sectionalizers

R5H 6H

100%

Case 1: No Network Automation Permanent fault

R5H 6H

100% 95%

Case 1: No Network Automation Permanent fault

RCase 2: Addition of Non-Communicating Fault Passage Indicators (FPI)

An FPI for each branch of the network

Add an FPI around each major obstacle

Case 3: Addition of Communicating FPIs

R

Put several communicating FPIs in strategic locations

ase 4: Addition of Communicating FPIs and Remote Controlled Loadreak Switches

RT

TT

T

T remote controlled load break switchesCommunicating FPI

Case 5: Recloser and Sectionalizer Load Break Switches

R

Schneider Electric - Energy MONTHLY REVIEW

Case 5: Recloser and Sectionalizer LoadBreak Switches

S1 = opens after ONE reclosing operation S2 = opens after TWO reclosing operations S3 = opens after THREE reclosing operations S4 = opens after FOUR reclosing operations

Sectionaliser load break switches are always associatedwith a recloser or circuit breaker:

S4

S3

S3

S2

S1

1 1

1 S2

Case 5: Recloser and Sectionalizer Load Break witches

R

Permanent fault

S4

S3

S3

S2

S1

2 2

2 S2


R

Permanent

S4

S3

S3

S2

S1

2 2

2 S2


R

Permanent

2

S4

S3

S3 S2

S2

S1


R

Permanent

2 60

75%95%

Summary of Over-head Networks 1/2Permanent fault

95%Case 2A recloser

+ FPIs3 h

6 h

Case 1A recloser

95%Case 3A recloser

+ FPI with Com1h30

Summary of Over-head Networks 2/2Permanent fault

95%

1h2

75 %

Case 5A recloser

and sectionalizers

95%

1h10

70 %

Case 4: A recloser,remote controlled switchesand FPI with Com


6.3.1 Components for Fault Isolation and Restoration

Whenever there is a fault on a part of the distribution network, the fault current should beinterrupted rapidly, the faulted section isolated from the healthy network and, then once thefault has been removed, supplies to customers should be restored. This is achieved throughrange of equipment generally known as switchgear.

The term switchgear includes: a circuit breaker which is capable of making and breaking fault currents a recloser which is essentially a CB with a limited fault-breaking capacity and variable pattern of

automatic tripping and closing, a switch dis-connector which has a limited fault-making capability (and which is capable of making

and breaking normal load current) a sectionaliser which is capable of making and breaking normal load current but not the fault current.


6.3.1 Components for Fault Isolation and Restoration Contd

33 kV substation switchgear may be located inside the substation building or in an outdoorhigh voltage compound; whereas 11 kV substation switchgear is normally indoor type ormounted on the overhead line poles.

The protection and metering equipment of substation switchgear is housed inside thesubstation control room.

Out on 11 kV circuits, away from primary substations, switchgear is usually outdoors, often asa Ring Main Unit (RMU). A typical RMU consists of two switch-disconnectors and a switch-fuse or circuit breaker. This will be depicted in upcoming slide.



Automatic versus Manual Operation of RMU In the past, switch-disconnectors in an RMU

required manual operation but automaticoperation can now be achieved for thesedesigns by retrofitting an actuator mechanism.

The most commonly used retrofit actuatormechanism is a motor wound spring. Remoteswitching is initiated from a field RTU as shownin Figure 6.17.

For clarity, only switch-disconnectors areshown in Figure 6.17. The fuse switch eitheracts directly on the switch-disconnect trip bar oris automated by connecting a shunt trip coil.

In modern switchgear, instead of a motorwound spring, compressed gas or magneticactuators are increasingly used



Reclose Sequence for Temporary andPermanent Faults

The upper sequence of Figure 6.18 shows howa recloser clears a temporary fault after tworecloses.

The purpose of the delayed tripping (see thelower sequence of Figure 6.18) is if the fault ispermanent, the delay allows sufficient current(and time) to pass through the downstreamfuse so as to clear the fault.



Pole Mounted Reclosers

Pole-mounted reclosers are widely used indistribution circuits.

They have different voltage ratings (for example,11, 15, 33 kV) and interrupting currents of 8 to 16kA.

The energy required to operate the reclosingarrangement is provided by a solenoid as shownin Figure 6.19.

In this arrangement, whenever the line current ishigh (due to a fault), the series trip coil opens thevacuum CB. As the CB is opened, the auxiliarycontacts are closed automatically, thus providingenergy for the reclosing operation.



Distribution Feeder with polemounted Recloser

A distribution feeder which employs apole-mounted recloser is shown inFigure 6.20.

The recloser characteristic is selectedso as to make sure that its fastoperating time is much faster than theoperating time of the downstreamfuses and its slow operating time isslower than the operating time of thefuses



Sectionalizer

A sectionaliser is an automatic isolator which can only be used to isolate a section of adistribution circuit once a fault is cleared by an upstream recloser.

When the recloser opens, a self-powered control circuit in the sectionaliser increments itscounter. The recloser is reclosed after a short delay to see whether the fault is temporary. Ifthe fault is temporary and cleared by the recloser, the sectionaliser resets its counter andcomes back to its normal state.

However, if the fault is permanent, when the number of counts in the sectionaliser reaches apre-defined number, it opens and isolates the downstream section of circuit. If the fault isdownstream of the sectionaliser, the recloser then restores supply to the upstream section.

This minimises the number of consumers affected by a permanent fault, and a more preciseindication of the fault location is provided.


6.3.2 Fault Location, Isolation and Restoration

When there is a fault on the network at the location shown, the over-current protection element in IED1 detectsthe fault and opens CB1. This will result in an outage at loads L1 to L5. Since there are no automatedcomponents in the network, supply restoration for a part of the network requires the intervention of a restorationcrew and in some areas may take up to 80 minutes.

Supply restoration is normally initiated by phone calls from one or more customers (in the area where outageoccurred) reporting a loss of supply to the electricity supplier. Upon receiving these calls a restoration crewdispatched to the area. It will take some time for the team to locate the fault and manually isolate it by openingSD3 and SD4.

Then CB1 is closed to restore the supply to L1, L2 and L3.

The normally open point (NOP) is closed to restore the supply to L5. Load L4 will be without supply until the faultis repaired.

A simple method to reduce the restoration time of loads L1, L2, L3 and L4 is using a pole-mounted recloser andsectionaliser . When a fault occurs, the recloser trips. Upon detecting the interruption, the sectionaliser,increments its counter by 1.

After a short time delay, the recloser closes and if the fault persists, it will trip again. The counter of S incrementsagain and it is then opened. The recloser then closes successfully.

The operation of the sectionaliser facilitates restoration of supply to L1, L2, L3 and L4 within a coupleminutes. However, the restoration of supply to L5 requires the intervention of the crew. As this method does notneed any communication infrastructure, it is reliable and relatively inexpensive.


6.3.2 Fault Location, Isolation and Restoration Contd

Automatic Restoration Method

Send a command to IED1 to close CB1

Send a command to RTU1 to reclose R1. If

the fault current prevails, initiate a trip but as there is no fault current, R1 remains

closed. Similarly send commands to RTU2, 3 and 4 to reclose R2, R3

and R4. When R3 is closed, fault current

flows, thus causing R3 to trip and lock-out.

Then send a command to RTU9 to close the normally open point.

Finally, send a command to RTU4 to close R4. As the fault current flows, a trip

command is initiated for R4. R3 and R4 thus isolate the fault and supply is restored to loads L1, L2, L3 and

L5.

6.4 Voltage Regulation

Distribution circuits are subject to voltage variations due to the continuous changes of the network load. The voltage variations may become severe when distributed generators are connected under light load

conditions, the power flow may be reversed.

Sustained voltages above 10 per cent or below10 per cent of the nominal voltage may damage or may prevent normal operation of IT equipment. As many consumers (domestic, industrial and commercial) are now heavily dependent on this equipment, regulating the voltage within the national limits is very important.

ATC & AVC

Traditionally, an automatic tap changer and Automatic Voltage Control (AVC) relay, sometimes with line drop compensation , is used on the HV/MV transformers to maintain the voltages on distribution circuits within limits. These transformers whose output voltage can be tapped while passing load current are referred to as having On-Load Tap Changers (OLTCs).

The operation of the OLTC is achieved by operating a tap selector in coordination with a diverter switch as shown in Figure 6.30 a, b, c ( in upcoming slide)


6.4 Voltage Regulation Contd

Automatic OLTC

In automatic arrangements (with a motorized tap changer), an AVC relay is introduced to maintain the MV busbar voltage within an upper and lower bounds (a set value a tolerance).

The main purpose of introducing a tolerance is to prevent the continuous tapping up and down (huntingeffect). A time-delay relay is also usually employed to prevent tap changing due to short-term voltagevariations. In modern automatic on-load tap changers, the AVC software and time-delay relay are in a baycontroller as shown in Figure 6.31.


6.4 Voltage Regulation Contd

Pole Mounted Variable Capacitors

In the USA, pole-mounted capacitor banks are used in distribution circuits for voltage regulation. They providepower factor correction closer to load, improve voltage stability, increase the line power, flows are lower andreduce network losses.

These capacitors may be fixed or variable.

Modern pole-mounted variable capacitors come with current- and voltage sensing devices, data logging facilityand local intelligence.

Variable capacitors are essentially a number of switched capacitors where the number of capacitors that areswitched in is determined by an intelligent controller fixed to the pole.

The location of the capacitor bank that provides reactive power and its value of reactive power support arecritical to achieve the optimum voltage profile while minimizing network losses and maximizing line flows. Insome cases coordinated control of the OLTC transformer, pole-mounted capacitors and any distributedgenerators in the network may provide enhanced optimization of different parameters.


Examples from BOOK


lecture 7 final

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