03-Non-Dir. Overcurrent.ppt

Application of Non-Directional Overcurrent
and Earthfault Protection

Non-Directional Overcurrent and Earth
Fault Protection

Overcurrent Protection
Purpose of Protection
 Detect abnormal conditions
 Isolate faulty part of the system
 Speed
 Fast operation to minimise damage and danger
 Discrimination
 Isolate only the faulty section
 Dependability / reliability
 Security / stability
 Cost of protection / against cost of potential hazards

Co-ordination
 Co-ordinate protection so that relay nearest to
fault operates first
 Minimise system disruption due to the fault
F1 F2
F3
F3
F2
F1

Fuses
 Simple
 Can provide very fast fault clearance
 <10ms for large current
 Limit fault energy
Pre Arc Time
Arcing Time
Prospective Fault Current
Total
Operating
Time
t

Fuses - disadvantages
 Problematic co-ordination
 IFA approx 2 x IFB
 Limited sensitivity to earth faults
 Single phasing
 Fixed characteristic
 Need replacing following fault clearance
Fuse A Fuse B

Direct Acting AC Trip
 AC series trip
 common for electromechanical O/C relays
51
IF
Trip Coil

Direct Acting AC Trip
 Capacitor discharge trip
 used with static relays where no secure DC
supply is available
IF'
Sensitive
Trip
Coil
IF
51
+
-

DC Shunt Trip
 Requires secure DC auxiliary
 No trip if DC fails
IF'
IF
DC
BATTERY
SHUNT
TRIP COIL
51

Principles
 Operating Speed
 Instantaneous
 Time delayed
 Discrimination
 Current setting
 Time setting
 Current and time
 Cost
 Generally cheapest form of protection relay

IF1
IF1
IF2
Instantaneous Relays
 Current settings chosen so that relay closest to
fault operates
 Problem
 Relies on there being a difference in fault level
between the two relay locations
 Cannot discriminate if IF1 = IF2
50
B
50
A
IF1
IF2

Definite (Independent) Time Relays
TOP
TIME
IS Applied Current
(Relay Current Setting)

Definite (Independent) Time Relays
 Operating time is independent of current
 Relay closest to fault has shortest operating time
 Problem
 Longest operating time is at the source where
fault level is highest
51
0.9 sec 0.5 sec
51

IDMT
 Inverse Definite Minimum Time characteristic
TIME
Applied Current
(Relay Current Setting)
IS

Disc Type O/C Relays
 Current setting via plug bridge
 Time multiplier setting via disc
movement
 Single characteristic
 Consider 2 ph & EF or 3 ph
plus additional EF relay

Static Relay
 Electronic, multi characteristic
 Fine settings, wide range
 Integral instantaneous elements

Numerical Relay
 Multiple characteristics and stages
 Current settings in primary or secondary
values
 Additional protection elements
Current
Time
I>1
I>2
I>3
I>4

Co-ordination Principle
 Relay closest to fault
must operate first
 Other relays must have
adequate additional
operating time to
prevent them operating
 Current setting chosen
to allow FLC
 Consider worst case
conditions, operating
modes and current
flows
T
IS1
IS2
Maximum
Fault
Level
I
R2
R1
IF1

Co-ordination Example
C A
B
0.01
0.1
1
10
Operating
time
(s)
Current (A) FLB FLC FLD
E
D
C
B
D
E

IEC Characteristics
 SI t = 0.14
(I0.02 -1)
 VI t = 13.5
(I2 -1)
 EI t = 80
(I2 -1)
 LTI t = 120
(I - 1)
Current (Multiples of Is)
0.1
1
10
100
1000
1 100
10
Operating
Time
(s)
VI
EI
SI
LTI

Operating Time Setting - Terms Used
 Relay operating times can be
calculated using relay
characteristic charts
 Published characteristcs are
drawn against a multiple of
current setting or Plug Setting
Multiplier
 Therefore characteristics can be
used for any application
regardless of actual relay current
setting
 e.g at 10x setting (or PSM of 10)
SI curve op time is 3s
0.1
1
10
100
1000
1 100
10
Operating
Time
(s)

Current Setting
 Set just above full load current
 allow 10% tolerance
 Allow relay to reset if fault is cleared by
downstream device
 consider pickup/drop off ratio (reset ratio)
 relay must fully reset with full load current
flowing
 PU/DO for static/numerical = 95%
 PU/DO for EM relay = 90%
 e.g for numerical relay, Is = 1.1 x IFL/0.95

Current Setting
 Current grading
 ensure that if upstream relay has started
downstream relay has also started
 Set upstream device current setting greater than
downstream relay
e.g. IsR1 = 1.1 x IsR2
R1 R2
IF1

Grading Margin
 Operating time difference between two devices to
ensure that downstream device will clear fault before
upstream device trips
 Must include
 breaker opening time
 allowance for errors
 relay overshoot time
 safety margin
GRADING
MARGIN

Grading Margin - between relays
 Traditional
 breaker op time - 0.1
 relay overshoot - 0.05
 allow. For errors - 0.15
 safety margin - 0.1
 Total 0.4s
 Calculate using formula
R2
R1

Grading Margin - between relays
 Formula
 t’ = (2Er + Ect) t/100 + tcb + to + ts
 Er = relay timing error
 Ect = CT measurement error
 t = op time of downstream relay
 tcb = CB interupting time
 to = relay overshoot time
 ts = safety margin
 Op time of Downstream Relay t = 0.5s
 0.375s margin for EM relay, oil CB
 0.24s margin for static relay, vacuum CB

Grading Margin - relay with fuse
 Grading Margin = 0.4Tf + 0.15s over whole characteristic
 Assume fuse minimum operating time = 0.01s
 Use EI or VI curve to grade with fuse
 Current setting of relay should be 3-4 x rating of fuse to
ensure co-ordination

Grading Margin - relay with upstream fuse
 1.175Tr + 0.1 + 0.1 = 0.6Tf
or
 Tf = 2Tr + 0.33s
Allowance for CT
and relay error
CB Safety margin Allowance for fuse
error (fast)
Tf
Tr
IFMAX

Time Multiplier Setting
 Used to adjust the operating
time of an inverse
characteristic
 Not a time setting but a
multiplier
 Calculate TMS to give
desired operating time in
accordance with the grading
margin
0.1
1
10
100
1 100
10
Operating
Time
(s)

Time Multiplier Setting - Calculation
 Calculate relay operating time required, Treq
 consider grading margin
 fault level
 Calculate op time of inverse characteristic
with TMS = 1, T1
 TMS = Treq /T1

Co-ordination - Procedure
 Calculate required operating current
 Calculate required grading margin
 Calculate required operating time
 Select characteristic
 Calculate required TMS
 Draw characteristic, check grading over whole
curve
Grading curves should be drawn to a common
voltage base to aid comparison

 Grade relay B with relay A
 Co-ordinate at max fault level seen by both relays =
1400A
 Assume grading margin of 0.4s
Is = 5 Amp; TMS = 0.05, SI
I
FMAX
= 1400 Amp
B A
200/5 100/5
Is = 5 Amp

 Relay B is set to 200A primary, 5A secondary
 Relay A set to 100A  If (1400A) = PSM of 14
relay A OP time = t = 0.14 x TMS = 0.14 x 0.05 = 0.13
(I0.02 -1) (140.02 -1)
 Relay B Op time = 0.13 + grading margin = 0.13 + 0.4 = 0.53s
 Relay A uses SI curve so relay B should also use SI curve
Is = 5 Amp; TMS = 0.05, SI
I
FMAX
= 1400 Amp
B A
200/5 100/5
Is = 5 Amp

 Relay B Op time = 0.13 + grading margin = 0.13 + 0.4 = 0.53s
 Relay A uses SI curve so relay B should also use SI curve
 Relay B set to 200A  If (1400A) = PSM of 7
relay B OP time TMS = 1 = 0.14 x TMS = 0.14 = 3.52s
(I0.02 -1) (70.02 -1)
 Required TMS = Required Op time = 0.53 = 0.15
Op time TMS=1 3.52
 Set relay B to 200A, TMS = 0.15, SI
Is = 5 Amp; TMS = 0.05, SI
IFMAX
= 1400 Amp
B A
200/5 100/5
Is = 5 Amp

LV Protection Co-ordination
ZA2118B
Relay 1
Relay 2
Relay 3
Relay 4
Fuse
1
2
3
4
F
350MVA
4 4
3 3
2
F
11kV
MCGG CB
ACB CTZ61 (Open)
CTZ61
ACB
MCCB
27MVA
20MVA
Load
Fuse
2 x 1.5MVA
11kV/433V
5.1%
K
1

ZA2119
1000S
100S
10S
1.0S
0.1S
0.01S
0. 1kA 10kA 1000kA
TX damage
Very
inverse

ZA2120C
Relay 1
Relay 2
Relay 3
Relay 4
Fuse
1
2
3
4
F
350MVA
4 4
3 3
2
1
F
11kV
KCGG 142 CB
ACB (Open)
KCEG 142
ACB
MCCB
27MVA
20MVA
Load
Fuse
2 x 1.5MVA
11kV/433V
5.1%
K

ZA2121
1000S
100S
10S
1.0S
0.1S
0.01S
0. 1kA 10kA 1000kA
TX damage
Long time
inverse

ZA2135
R3
R2
R1
Block t >
I > Start
IF2
IF1
M (Transient backfeed ?)
Graded
protection
Blocked
protection
Blocked OC Schemes

 Fast clearance of faults
 ensure good operation factor, If >> Is (5 x ?)
 Current setting must be co-ordinated to prevent
overtripping
 Used to provide fast tripping on HV side of transformers
 Used on feeders with Auto Reclose, prevents transient
faults becoming permanent
 AR ensures healthy feeders are re-energised
 Consider operation due to DC offset - transient
overreach
Instantaneous Protection

 Set HV inst 130% IfLV
 Stable for inrush
 No operation for LV fault
 Fast operation for HV
fault
 Reduces op times
required of upstream
relays
HV2 LV
HV1
HV2
LV
TIME
CURRENT
HV1
IF(LV) IF(HV)
1.3IF(LV)
Instantaneous OC on Transformer Feeders

 Earth fault current may be limited
 Sensitivity and speed requirements may not be met by
overcurrent relays
 Use dedicated EF protection relays
 Connect to measure residual (zero sequence) current
 Can be set to values less than full load current
 Co-ordinate as for OC elements
 May not be possible to provide co-ordination with
fuses
Earth Fault Protection

 Combined with OC relays
E/F OC OC OC E/F OC OC
 Economise using 2x OC
relays
Earth Fault Relay Connection - 3 Wire System

 EF relay setting must be
greater than normal
neutral current
 Independent of neutral
current but must use 3 OC
relays for phase to neutral
faults
E/F OC OC OC E/F OC OC OC
Earth Fault Relay Connection - 4 Wire System

 Solid earth
 30% Ifull load
adequate
 Resistance earth
 setting w.r.t earth fault
level
 special considerations
for impedance earthing
- directional?
Earth Fault Relays Current Setting

 Settings down to
0.2% possible
 Isolated/high
impedance earth networks
 For low settings cannot use residual connection, use
dedicated CT
 Advisable to use core balance CT
 CT ratio related to earth fault current not line current
 Relays tuned to system frequency to reject 3rd
harmonic
B
C
E/F
A
Sensitive Earth Fault Relays

 Need to take care with core
balance CT and armoured
cables
 Sheath acts as earth return
path
 Must account for earth current
path in connections - insulate
cable gland
NO OPERATION OPERATION
CABLE
BOX
CABLE GLAND
CABLE GLAND/SHEATH
EARTH CONNECTION
E/F
Core Balance CT Connections

03-Non-Dir. Overcurrent.ppt

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