distance priciples_basic principles

> Distance Protection - January 2004

Distance Protection

Popular, widely used on Sub-Transmission and Transmission Systems

Virtually independent of Fault Current Level (ZS/ZL ratios)

Fast Discriminative Protection:- Zone 1 or ‘Aided’ Distance Scheme

Time Delayed Remote Back-Up:- Incorporated at little extra cost

Advantages of Distance Protection

Measures Z, X or R correctly irrespective of System Conditions

Compare this with Instantaneous OvercurrentProtection:-

115kV 50

IF1ZS = 10 Ω

ZS = 10 Ω

ZL = 4 Ω

IF1 = 115kV/√3(5+4) = 7380A

∴ Is > 7380A

Consider with one source out of service:-

IF2 = 115kV/√3 x 10 = 6640A

∴ Is <6640A

>7380A - IMPRACTICAL

ZS = 10 Ω

Basic Principle of Distance Protection

Generation

DistanceRelay

Impedance Seen By Measuring Element

LOADLRR

R Z Z V Zmeasured Impedance +=Ι

RelayPT.

Normal Load

IR ZLZS

VRVSZLOAD

Impedance Measured ZR = VR/IR = ZF

Relay Operates if ZF < Z where Z = setting

Increasing VR has a Restraining Effect ∴VR called Restraining Voltage

Increasing IR has an Operating Effect

Plain Impedance Characteristic

TRIP STABLE

Impedance Seen At Measuring Location For Line Faults

Impedance Characteristic Generation

Operate

Restrain

Spring

Ampere Turns : VF IZ

Trip Conditions : VF < IFZ

IZ V1V2V3

TRIP STABLE

Voltage to Relay = VCurrent to Relay = IReplica Impedance = Z

Trip Condition : S2 < S1

where : S1 = IZ ≈ Z

S2 = V ≈ ZF

I1/I2 ZP

Relays are calibrated in secondary ohms :-

RATIOV.T.RATIO C.T. x Z Z

/VV/ x V

/ x /VVxV /V Z

12FP12FP

ΙΙΙ

=ΙΙΙ

Example

ZP = 4Ω; V1/V2 = 115kV/115V; I1/I2 = 600/5A

ZR(5) = 4 x 600/5 x 115/115x103 = 0.48Ω -5A Relay

ZR(1) = 2.4 Ω - 1A Relay

C.T. RATIOZR = ZP x

V.T. RATIO

Input Quantities for ∅-∅ Faults

FAULT VRESTRAINT IOPERATE

A - B VA - VB IA - IB

B - C VB - VC IB - IC

C - A VC - VA IC - IA

VRESTRAINT & IOPERATE are selected inside the relay

No setting adjustments are required apart from Z1 = Phase Replica Impedance

Input Quantities for Phase to Earth Faults

FAULT VRESTRAINT IOPERATE

A - E VA ? IA ?

Neutral Impedance Replica Vectorial Compensation

Replica impedance circuit :-

∑IZN

Z1 = Phase replica impedance

ZN = Neutral replica impedance

IRA passes through Z1

IRN passes through ZN

ZT = Z1 + ZN

Neutral Impedance Compensation

For a single phase to ground fault the total earth loop impedance is given by :- (Z1 + Z2 + Z0)/3 = ZT

ZT = (Z1 + Z2 + Z0)/3 = Z1 + ZN

ZN = (Z1 + Z2 + Z0)/3 - Z1

= (2Z1 + Z0)/3 - Z1

= - Z1 + Z0

= KN Z1

where KN = (Z0 - Z1) 3Z1

Neutral Impedance Vectorial Replica Compensation

Line CT’sA

ZPH IBZPH

ZPH ICZPH

ZN INZN

Set Z PH = ZF1

Set Z N = (ZF0 - ZF1 )3

Usually ∠ ZN = ∠ ZPH for OHL’s

Neutral Impedance Replica Compensation

For cables ∠Z0 ≠ ∠Z1

∴ VECTORIAL COMPENSATION MUST BE USED

KN = Z0 - Z1 = KN ∠∅N

Characteristics

Distance Characteristics

OFFSETMHO

IMPEDANCE

CROSS-POLARISEDMHO

POLYGON

QUADRILATERAL

LENTICULAR

Self Polarised Mho Relays

Very popular characteristic

Simple

Less sensitive to power swings

Inherently directional

Operates for F1, but not for F2

Mho = 1/OHM

Settings :-

Z = reach settingϕ = characteristic angle

OPERATE

RESTRAIN

Neutral Impedance Replica Vectorial Compensation

Vectorial compensation allows for ∠ZN ≠ ∠ZPH which is especially important for cable distance protection where ∠ZN < ∠ZPH and ∠ZN is sometimes negative.

ZE = Earth-loop impedance for ∅ - earth fault on a cable

Offset Mho Characteristic

Normally used as backup protection

Operates for zero faults (close up faults)

Generally time delayed (as not discriminative)

Mho Relays

Directional circular characteristic obtained by introducing VPOLARISING

VF → self polarisedVSOUND PHASE → fully cross-polarisedVF + xVS.F. → partially cross-polarisedVPRE-FAULT → ‘memory’ polarised

Purpose for this is to ensure operation for close up faults where measured fault voltage collapses

Quadrilateral Characteristic

Lenticular Load Avoidance Characteristic

Lenticular characteristic created from two offset Mho comparators

Aspect ratio = a/b

Lenticular Characteristic

Z3Aspect ratios a/b

0.410.671.00

Load impedance area

Z3 reverse

Zones of Protection

Z2A Z2C

Z3A Z3C

Z1CZ1A

Z1B DCA

Z1A = 80% of ZAB

Z2A = 120% of ZABZ3A(FORWARD) = 120% of ZAB + ZCD

Zones of Protection

Zone 1

FAST OPERATIONTrips circuit breaker without delay as soon asfault within Zone 1 reach is detected.

REACH SETTINGCannot be set to 100% of protected line or mayoverreach into next section.Overreach caused by possible errors in :-

CTsVTsZLINE informationRelay Measurement

Zone 1

PossibleOverreach

ZONE 1 = ZL

ZONE 1 = 0.8ZL

Possible incorrect tripping for fault at ‘F’

∴ Zone 1 set to ∼ 0.8ZL

Zone 1 Settings for Direct Intertrip Schemes

Z1AReceiveSend

Trip ‘B’

Z1BReceive Send

Zone 1 Settings for Direct Intertrip Schemes

Effective Zone 1 reaches at A and B must overlap.Otherwise :- No trip for fault at ‘F’

∴ Effective Z1A and Z1B must be > 0.5ZL

Settings for Zone 1 > 0.8ZL are o.k.

Minimum Zone 1 Reach Setting

Dictated by :-

Minimum relay voltage for fault at Zone 1reach point to ensure accurate measurement.

Minimum voltage depends on relay design typically 1 → 3 volts.

System Impedance Ratio :- SIR

SIR = ZS/Zn

where :- ZS = Source impedance behind relayZn = Reach setting

VRPA = Minimum voltage for reach point accuracy

Can be expressed in terms of an equivalent value of SIRMAX

SIRMAX = ZS MAXZn MIN

∴ Zn MIN ≡ ZS MAXSIRMAX

Zone 2

Covers last 20% of line not covered by Zone 1.Provides back-up protection for remote busbars.

To allow for errors :-Z2G > 1.2 ZGH

Zone 2 is time delayed to discriminate with Zone 1 on next section for faults in first 20% of next section.

TIMEZ1G

Zone 2

Overlap only occurs for faults in first 20% of following line.Faults at ‘F’ should result in operation of Z1H and tripping of circuit breaker ‘H’.

If ‘H’ fails to trip possible causes are :-Z1H operates but trip relays fail.

Z2H may operate but will not trip if followed by the same trip relays.Fault must be cleared at ‘G’ by Z2G.

Z1H and trip relays operate but circuit breaker fails to trip.

Zone 2 on adjacent line sections are not normally time graded with each other

Z1G Z1H

Z2G Z2H

‘H’‘G’F

Zone 2

No advantage in time grading Z2G with Z2H

Unless Z2H + trip relays energise a 2nd circuit breaker trip coil.

Zone 2Z1H fails to operate.

Results in race between breakers ‘G’ and ‘H’ if Z2H and Z2G have the same time setting.

Can only be overcome by time grading Z2G with Z2H.

Problem with this :-

Zone 2 time delays near source on systems with several line sections will be large.

End zone faults on lines nearest the infeed source point will be cleared very slowly.

Z1G Z1H

‘H’‘G’

Maximum Allowable Zone 2 Reach to Allow for Equal Zone 2 Time Settings

Z2A must not reach beyond Z1B

i.e. Z2A(EFF) MAX must not reach further than Z1B(EFF) MIN

Z1BSETTING = 0.8ZL2Z1B(EFF) MIN = 0.8 x 0.8ZL2 = 0.64ZL2

∴ Z2A(EFF) MAX < ZL1 + 0.64ZL2∴ 1.2 Z2ASETTING < ZL1 + 0.64ZL2

Z2ASETTING < 0.83ZL1 + 0.53ZL2

Z2A (EFF) MAX

Z1B (EFF) MIN

ZL2ZL1 BA

Zone 2 Time Settings on Long Line Followed by Several Short Lines

Z2HZ2J

Z1H Z1JZ1G

‘H’ ‘J’‘G’F

Z2G reaches into 3rd line section.

To limit remote back-up clearance for a fault at ‘F’, the time setting of Z2G must discriminate with Z3H.

Zone 3

Provides back-up for next adjacent line.Provides back-up protection for busbars (reverse offset).Actual Zone 3 settings will be scheme specified, i.e. permissive or blocking schemes.Many modern relays have more than 3 Zones to allow the use of three forward and an independent reverse zone.

Z1G Z1HZ2G

Z3G REV Z3G FWD

Typical settings : Z3FWD > 1.2 x (ZGH + ZHK)Z3REV 0.1 to 0.25 of Z1G

Zone Time Coordination - Ideal Situation

Zone 1 :- tZ1 = instantaneous (typically 15 - 35mS)

Zone 2 :- tZ2 = tZ1(down) + CB(down) + Z2(reset) + Margine.g. tZ2 = 35 + 100 + 40 + 100 = 275mS

Zone 3 :- tZ3 = tZ2(down) + CB(down) + Z3(reset) + Margine.g. tZ3 = 275 + 100 + 40 + 100 = 515mS

Note: Where upper and lower zones overlap, e.g. Zone 2 up sees beyond Zone 1 down, the upper and lower zone time delays will need to be coordinated, e.g. tZ2(up) to exceed tZ2(down).

Under / Overreach

Under-Reach

Impedance presented > apparent impedance

%age Underreach = ZR - ZF x 100%ZR

where ZR = Reach settingZF = Effective reach

Underreaching Due to Busbar Infeed between Relay and Fault

IA IA+IB

Relay LocationIB

VR = IAZA + (IA + IB) ZB

IR = IA

ZR = ZA + ZB + IB . ZB

Underreaching Due to Busbar Infeed between Relay and Fault

∴ Relay with setting ZA + ZB will underreach withinfeed.

Relay with setting ZA + ZB + IB . ZB will measureIA

correctly with infeed present but if infeed is removed the relay will overreach.

Maximum allowable setting dictated by load impedance

Under-Reach

What relay reach setting is required to ensure fault at F is at boundary of operation ?

Impedance seen for fault at F= ZG + IG + IP . ZK

IGLimit of operation is when Impedance Seen = Reach Setting

∴ Reach setting required= ZG + IG + IP . ZK

ZK FIG+IP

Over-Reach

Impedance seen < apparent impedance

%age Overreach = ZF - ZR x 100%ZR

where ZR = Reach settingZF = Effective reach

Mutual Coupling

Mutual coupling causes distance relays to either underreach or overreach.

Positive and negative sequence has no impact.

Zero sequence mutual coupling can have a significant influence on the relay.

Only affects ground fault distance.

Mutual Coupling Example Under Reach

Z2 ‘Boost’ G/F

Mutual Coupling Example Over Reach

Z2 ‘reduced’ G/F

Mutual Coupling Example Over Reach

Z1 G/F (optional)

Z1 G/F (normal)

Ancilliary Functions

Switch on to Fault (SOTF)

Fast tripping for faults on line energisation, even where line VTsprovide no prefault voltage memory

Voltage Transformer Supervision

A VT fault and subsequent operation of VT fuses or MCB’s results in misrepresentation of primary voltagesRelay will remain stable as the current phase selector will not pick upSubsequent system fault may cause unwanted / incorrect trippingVTS operating from presence of V0 with no I0 or V2 with no I2 is used to block relay if required

VT Supervision

Under load conditionsLoss of 1 or 2 phase voltagesLoss of all 3 phase voltages

Upon line energisationLoss of 1 or 2 phase voltagesLoss of all 3 phase voltages

Digital input to monitor MCB

Set to block voltage dependent functions

Illustration of Basic Power Swing Blocking System

Power Swing Locus

Power Swing BlockingA power swing will result in continuous change of current

Continuous output from the relay superimposed current element can be used to block for a power swing

Using this method the relay is able to operate for faults occurring during a power swingv

TS ~ 0.2 to 2 s

Load R

Directional Earth Fault Protection (DEF)

High resistance ground faults

Instantaneous or time delayed

IEC and IEEE curves

Single or shared signalling channel

Independentsignalling channel

distance priciples_basic principles

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