Trf. diff calculation basic

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Wiring Diagram :
SETTING CALCULATION FOR DIFFERENTIAL PROTECTION SPAD346C
I . Basic schematic Diagram of Comprehensive Protection ;

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A. SLD :
B. Protections possible :
II. Existing Scheme :
III. New Scheme :
 External E/F on star side of DYn11 Tr. will have ZPS currents flowing in the CTs associated with Y (star)
but due ∆ of ICT, there will be corresponding ZPS current in CTs associated with Delta winding.
 To ensure stability of protection, the LV ZPS current must be eliminated for differential current is done by
∆ winding line CTs or ∆ connected ICT.

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A. Schematic :
B. Wiring Diagram of New scheme :
(i) W.e.f 18-3-2016 :
IV. Transformer details :
(A)Data : 20 MVA, 33/6.9 KV, Dyn11, 3.81 Ohm NGR, Z% of 12, Off-Circuit Taps +5%.

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I 1n = Pn = 20 x 103
= 350 Amp
3 x U1 3 x 33
I 2n = Pn = 20 x 103
= 1675 Amp
3 x U2 3 x 6.9
(B) Matching CT ratio:
(i) HV Side: CT used = 400/1 A, Class: PS, Rct<5.2 Ohm, Imag=10 mA
I1 / In = 350/400 = 0.875 (Set I1 / In =0.87)
(ii) LV Side: CT used=2000/1 A, Class: PS, Rct<9.5 Ohm, Imag=10 mA at Vk/2,
Vk=40(Rct) + 70 V
I2 / In = 1675/ 2000= 0.84 (Set I2 / In = 0.84)
(iii) Other CT Available on LV side: 2000/1 A, 30 VA, 5P10
(iv) Interposing CT (ICT) available on LV side : 1.66/1 A, Cl:PS, Rct<0.3 Ohm,
Imag=30 mA at Vk/4, Vk>40 V
NOTE: No ICTs are required for SPAD relay if above setting used for ratio error correction.
Hence, this can be bypassed.
V. SETTINGS :
A. Differential Module (SPCD 3D53) :
1. Basic Setting (or sensivity setting of stabilized stage) (P/In %) :
- Under No-load conditions, Id=0 but CTs, tapings etc. cause some current.
- On loading Id increases along with load.
For transformer:
Normal setting = 0.5 S + (No load loss of transformer + Tapping)
If not known, Consider Transformer no load losses = 10%
P = 0.5 S + 10 = 0.5 S + 10% = [0.5*( )]+10 = %
 P = Id = Min. current in operating coil only to cause operation of relay X 100 %
In In Rated current of operating coil of relay (when Ib = 0)
 It is used to set the max. sensitivity of relay and used to influence the level of whole operating
characteristic.
 It is typically between 20% – 40%

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 Generally 20% setting is OK to ensure sensitivity to internal faults up to load current and is equal to
Basic slope.
 This is up to first turning point (TP-1) which is fixed at 0.5 (i.e., normal loading of Transformer).
 Recommended setting for transformer protection is between 25-35% (Set P/In= 20 %)
2. Starting Ratio (Bias setting) (S %):
Taken into account of :
CT primary error (LV) = + 0.25 (Class:PS)
CT secondary error (HV) = + 0.25
Max. Tap change position error = + 5
Relay A/D converter error = + 2
Relay internal matching CT error = + 4
CT leads error = + 4
Margin of safety = +2
No-Load current of transformer = 1 to 3% = take 3%
%S = Min. current through operating coil to cause relay operation X 100
Restraining current
= No = ∆ Id
NR ∆ Ib
= Max. external fault current with which Relay will not operate X 100
Min. internal fault current where Relay operates

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 Takes into account of :-
 ALF of CTs.
 Tap Changer (5%)
 TP2 of characteristic
 Error in matchi9ng CTs (4%)
 Accuracy of CTs (0.25%)
 Inaccuracy in A/D converter (2%)
 CT leads error (5%)
 No-load ( or excitation current of Tr. (1 to 3% ≈ 3%)
 Margin of safety (2%)
 “S” setting (min.) = 2 X Max. Tap position
Normally, S = 0.5P + No load losses @ 10%
⸫ S = 5 + 4 + 2(0.25) + 2 + 5 + 3 + 2 = 21.5%
 Recommended for Transformer with off-circuit tap changer is 20% to 35% and 20% to 40% for
OLTC (SET at 20%)
 Set at higher side (35%) if ALF of both side CTs are different.
 Too higher ‘S’ reduces sensitivity of differential element for internal faults. (⸫ avoid higher ‘S’)
 It affects the slope of operating characteristic between TP! And TP2.
 Bias or %difference improves security but at the lost of sensitivity.
3. Second turning point I2 tp / In setting :
I2tp recommended setting for transformer protection is between 1.5…2.0 ( Set I2tp = 1.5)
Part 1: P/In = Id1 / In =
I1tp = Ib / In = 0.5 (Fixed)
Id is constant ≈ 0 to 0.6 In
Also sometimes effective upto liner operating characteristic of CT.
Part 2: S = Id2 / Ib2 =
Ib2 = I2tp - I1tp = 1. 5 –0.5 = 1 (0.4 to 2.0)
Here variation in ‘S’ effects the slope i.e., how big the change in Id requires w.r.t.
change in load current is required to trip the relay. Dictates the relay residual
current over the load current . Also sometimes effective up to linear operating Char.
of CT.

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Part 3: Slope is always 100% and Angle is 450
.
The table below shows the diff. current required for operation in the different parts of operation characteristic:
 It is generally between 1.5 to 2 for Transfer fed from 1 side (2 to 2.5 fro fed from
both sides).
 Influence the tripping sensitivity at values above rated current.
 Generally set at 1.5 for more stability for external faults.
 Setting of 2.0 provides somewhat more sensitive protection for in-zone faults.
 Setting of 1.5 provides somewhat more stability for external faults.
Ib/In > I2 tp/In The slope is constant (= 100%) i.e., increase in Id is equal to corresponding
increase in Ib.
4. Third turning point I3 tp (Part-3 of Curve)
Slope – 3: Always 100% (set a min. of 80%) with angle of 450
. It is intended to ensure
additional restraining with severe through fault currents that could lead to CT saturation.
 Calculate S.C. fault current (Isc) with %Z of Transformer and to ensure detection of Isc; set at
80% of Isc.
5. Instantaneous differential current stage Id/In >> setting (High-Set Unit)
 It should be above starting current of Transformer and between 5 to 10 times In and
should not trip during energisation.
 No stabilization here and operates for the value exceeding Id/In >> or when the value
of differential current exceeds 2.5 Id/In >>
 If Ib is below 30% of Id, the fault is protected zone. Then the set value of Id/In >>
automatically halved and internal blocking signal of stab. Stage will be initiated.
 Setting is based on one set of CTs saturated under worst case through fault
considering max. DC offset.
Recommend setting for Id / In >> Between 5 to10 for transformer protection ( Set Id/In >>=10)

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6. Ratio of second harmonic and fundamental Id2f/Id1f > % setting:
 Id2f/Id1f > If not blocked, Relay will sense inrush current and relay operates.
 This stage blocks relay operation if 2nd
harmonic current is above 15%. Set at 10%
for first energisation or switch ON after long shutdown, due to low remenance, it may
not block. ( Set Id2f/I.1f =15%)
7. Ratio of fifth harmonic & fundamental Id5f / Id1f > % setting:
 Over fluxing due to over voltage.
 Set at 35% for blocking relay operation (Set Id5f/Id1f>=35%)
8. Fifth harmonic de-blocking Id5f / Id1f >> % setting :
 Set at 35% or disable if not required.
 Magnetising current with 5th
harmonic current will be high due to sudden voltage rise
or drop in frequency.
 If increase when core saturates. (Set Id5f / Id1f >> % = 35%)
9. Switch Group setting :
9.1 SGF (Functions) :

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9.2 SGB (Blocking) :
9.3 SGR (Relays) :

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10. FINAL CONNECTION DIAGRAM AND SETTINGS OF Diff. Module :
Number Check sum Number Check sum Number Check sum
SGF 1 SGB1 SGR 1
SGF 2 SGB 2 SGR 2
SGF 3 SGB 3 SGR 3
SGF 4 SGB 4 SGR 4
SGF 5 SGB 5 SGR 5
SGF 6 SGB 6 SGR 6
SGF 7 SGB 7 SGR 7
SGF 8 SGB 8 SGR 8
SGF 9
SGF 10
SGF 11

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B. Earth Fault Module (SPCD 2D55) :
The earth-fault relay measures the HV and LV side phase currents and neutral currents of the transformer. Four
alternative principles can be used for implementing the HV side and LV side earth-fault protection of the transformer
to be protected:
i. the stabilized differential current principle (low-impedance type protection)
ii the high-impedance principle (REF)
iii. the neutral over current principle
iv. the residual over current principle
The protection principle to be used depends on the connection of the windings of the power
transformer and on the requirements for the earth-fault protection.
1. Earth Fault Settings :
i. Stabilized differential current principle

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The operation is based on the comparison of the amplitude and the phase difference (ϕ) between the sum
of the phase currents (ΣI) and the neutral current (I0). The differential current (Id) is calculated as the
absolute value of the difference between the sum of the phase currents and the neutral current:
The directional differential current (Id×cosϕ), which is used for protection, is based on the differential
current (Id) and the angle between the sum of the phase currents and the neutral current. Cosϕ is specified
to be 1, when the phase difference is 180°. Further, tripping is possible only when the phase difference is
between 90° and 270°.
 For earth fault within protected zone. (HV or LV)
 Relay operation for external fault is inhibited by a stabilising resistor.
 Setting P1/In (HV) or P2/In (LV) → D.T. characteristic.
 Operates for faults between Residual and Neutral CT.
 2nd
Harmonic blocking is required.
ii. High-impedance principle
A well known and conventional protection method is the high-impedance principle, also known as
the Restricted Earth-Fault (REF) principle. The advantages of this protection principle are
absolute selectivity (unit protection) and fast operation, even though the CTs are partially
saturated.

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 For earth fault within protected zone (HV or LV)
 Absolute selectivity (unit protection) and fast operation.
 The Residual current measured (Holmgreen connection of phase CTs) and neutral current are summed
at the Io input of relay.
 Set at minimum for REF.
 Harmonics are not suppressed since relay senses differential current. No need for Harmonic blocking.
 A stabilizing resistor and often a non-linear voltage limiting resistor are required.
iii. Neutral current principle : When the neutral current principle is used, a current transformer is
installed to the neutral to earth connection of a power transformer star point. In this principle the relay cannot see
where the fault is, i.e. this is no unit protection. The protection is based on the fundamental frequency components
of the current. The DC component and harmonics are suppressed by a digital filter.
51S: DC component & Harmonics are suppressed by a digital filter. – No unit protection.
iv. a. Measured residual over current principle ;From the relay point of view, this principle is the
same as the previous neutral current principle. From the application point of view, residual over current is
measured with the residual connection of the phase CTs (known as the Holmgreen connection) or a core
balance CT.

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The settings are the same as those used at the neutral current principle.
 For ∆ connected winding or unearthed star winding.
 Setting: Same a neutral current principle
 Time: long (Several seconds) to prevent unwanted operation due to CT saturation when heavy
asymmetric inrush or start up current is passing through the protected object.
iv. b. Calculated residual over current principle : When the calculated residual over current
principle is used, the phase current transformers are connected to the relay in the usual manner. The relay
will then calculate the residual current from the phase currents (virtual I0).
 Relay calculates Residual current from phase CTs (Io).

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B. COMBINED OVERCURRENT AND EARTH FAULT MODULE (4D28):
1. OVERCURRENT:
 For 1 Ph, 2 Ph, & 3 Ph over current
 Start & Trip indicator available.
 3 stage over current protection
 I > 1.5In (min.) to 4In. To utilise the over load capacity of Transformer.
 I >> & I>>> can be set out of operation.
2. EARTH FAULT:
 Used as back up for PTRs.
 Generally used for over current of HV & neutral current of LV.
3. ∆I: for unbalanc3e protection of networks. Mainly monitoring Generator.
 DT characteristic
 ∆I = (Imax - Imin)/Imax X 100
 This will not be in use when measured currents falls below 0.1In.
 10 to 100%withtime 1 t0 300 sec.
2. Switch Groups :
2.1 SGF 1 :The switch group SGF1 is used to select the protection principle to be used on the HV side
and LV side. When the switch is in position 1the protection principle is used. It should be noted that
one protection principle at a time can be used on the HV side or the LV side.
SGF2: The switches of switch group SGF2 are used to define the influence of the directions of the connected
currents and to configure the blockings based on the second harmonic of the neutral current.

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SGF3 Circuit-breaker failure protection (CBFP) : SGF 3/ 1 to 8 not used. Checksum=0
SGF4 Self-holding of output signals : SGF 4/ 1 to 8 not used. Checksum=0
SGF 5 Activation of TRIP indicator LED :
SGF6...11 : Selection of the start and operate signals of the protection stages, the blocking signals and the external control
signals BS4 and BS5 to be used as inter modular signals AR1...3 and BS1 INT1...3. The signal configuration is presented in Fig
below.

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2.2 SGB : SGB1 to 7 Not used. Check sum = 0.
2.3 SGR 1 to 11 :
3. FINAL DIAGRAM AND SETTINGS :
DAIAGRAM :
Settings :

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C. Over current and earth-fault relay module - SPCJ 4D28
Overcurrent unit : The overcurrent unit of the combined overcurrent and earth-fault relay module SPCJ 4D28 is
designed to be used for single-phase, two-phase and three-phase overcurrent protection. The overcurrent unit
includes three overcurrent stages: a low-set stage I>, a high-set stage I>> and a superhigh-set stage I>>>.
1. Time/current characteristics : as per IEC – 60255 :
2. Earth-fault unit : The earth-fault unit of the combined overcurrent and earth-fault relay module SPCJ 4D28 is
provided with two protection stages: a low-set neutral overcurrent stage I0> and a high-set neutral overcurrent
stage I0>>.
The SPCJ 4D28 module measures the phase currents on the HV side, but the I0 current on the LV side,
i.e. both the earth-fault protection of the SPCJ 4D28 module and the earth-fault protection of the SPCD
2D55 module on the LV use the I02 input (terminals X0/37-38-39).
Differences between the earth-fault protection of the SPCD 2D55 and SPCJ 4D28 modules :

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3. Switch Groups :
3.1 SGF :
SGF 2 / 1 to 8 not in use. Check sum=0
SGF 3 :
SGF 4 / 1 to 8 not in use. Check sum=0

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SGF 5 :
SGF 6 to 8 :
3.2 SGB 1 to 3 :
3.3 SGR :

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4. Final diagram and settings :
Diagram ;
Settings ;
VI. ONE EXAMPLE OF SETTINGS EARTH FAULT:

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Does: CT vector group matching
CT Ratio correction
Elimination of ZPS current from
phase
current on HV & LV
3D53:
Differential
Input: 2 X 3 phase CTs.
Setting P/In = 5 to 50%
t01 = 30 mSec to 100 Sec
S= 10 to 50% (Inst)
Id/In>> 5 to 30, time 30 m Sec.
Measured residual O/C for HV side E/F Residual O/C for E/F

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Both LV & HV; Definite time (DT)
Neutral CT on any side: Use as I01 or I02
back up protection (neutral current
principle)
Star connected CTs: Calculated residual
current
2D55: E/F Residual (o ) neutral CTs.
Input 2 X 3 ph CT
2 X Neutral CTs
∆I01 > REF HV
∆I02 > REF LV
E/F: DT or IDMT or Standby for entire
system on LV only
4D28: O/C
& E/F
Input: 1 X 3 ph CTs.
1 X Neutral or Residual connection
CT
Over current:
Low set 3I > 0.5 to 5 times: 50 msec to
300 sec. (DT or IDMT 4 curves)
High set 3I >> 40 m sec, K=0.05 , DT
Super high set: 3I>>> 40 mSec with DT
∆Z; not in use.
E/F: Low set neutral O/C stage:
I0> 0.1 to 0.8 In with DT or IDMT
T0: 0.05 to 300 sec
K; 0.05 to 1.0 (4 curves)
High set : I0>>: DT or out of operation
(t0>>)

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C.Ts. Requirement:
 Differential CTs. Parallely connected shall have same ratio.
 Rating of CT Primary = 70 to 200% of rated current of Transformer.
 Isc (through fault current) to be measured without saturation.
 Also the first 25 m sec through fault current contains DC component shall be transmitted
correctly.
 ALF > 40 or 4 ∆I>>.