Reles de Proteccion T60 & T35

No Slide Title*
This presentation is focused on one of the GE Universal Family relays known on the market as T60 Transformer Management Relay. The material covers:
Introduction of the relay
Wiring and setup
Instantaneous differential protection
Configurable multi-protection transformer package
Up to 4 sets of CTs and/or VTs (T60) – Optional 5/6 windings
Up to 6 sets of CTs and/or VTs (T35)
Programmable FlexLogic
Easy access through HMI(Human Machine Interface)
Easy for monitoring and control PC program
Varieties of communications
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The T60 is a multifunctional digital relay, built to provide reliable protection on different size power transformers, with capabilities to handle up to 4 windings/restraints. The protection package of main biased and unbiased protections, together with all backup protections is fully configurable on the “Enable/Disable” basis. The customer chooses which elements to enable, and which ones not.
All relay settings can be done either using the relay front panel keypad and display, or through the PC program. The relay is equipped with varieties of com ports: Front port RS 232, rear ports for RS485 communication and/or Ethernet ports
The hardware has modular design, and is configurable to meet the customer specifications.
The advantages of the T60 and the whole family of UR relays are:
protections designed to meet the very fine customer requirements
designed tools, to build protection and control logic(FlexLogic) using variety of contact inputs, outputs, virtual inputs, outputs, protections, GOOSE messages, ect.
High visualization of real time data, and data recording tools for analysis
GE Consumer & Industrial Multilin
Phase and Neutral directional OC (67P, 67N)
Phase under- and over-voltage (27P, 59P)
Auxiliary under- and over-voltage (27X, 59X)
Neutral over-voltage (59N)
FlexElements - universal comparators
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The main protection elements on T60 relay are Percent and Instantaneous current Differential elements, and they are built to respond to all kinds of transformer internal faults, and secured against faults outside the zone.
Included in T60 are also – Restricted Ground Fault for detecting internal ground fault currents, and the over-excitation(Volts/Hertz) protections.
The backup protections are presented by the common for the UR family protections: varieties of time over-current and over-voltage elements, under and over frequency, FlexElements. The last so called FlexElements are GE invention type of protection, and as the name tells for itself, are fully customizable.
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The relay is equipped with 6 independently configurable setting groups, which can be automatically switched upon identified logic. For more flexibility in monitoring the FlexLogic operands, provided are 16 Digital elements, with attached to them Pickup, Operate, and Dropout operands.The elements can be named to provide more confort.
The digital counters, is a feature, used to detect and count the status of any FlexLogic operand, used for monitoring and control purposes.The real application can be counting the number of breaker trips, and issue an alarm.
The T60 metering includes per-phase differential and restraint currents display, together with % 2-nd and 5-th harmonics, as well as measuring of 2-nd to 25-th harmonics and THD per-phase current.
For better visualization and data gathering, provided are the tools of Oscillography, Event Recorder and Data Logger.
Voltages(phasors and true RMS) – phase, ground, neutral and symmetrical components
Power - active, reactive, apparent, power factor
Energy and energy demand
Per-phase 2-nd and 5-th harmonics on differential currents
2-nd to 25-th harmonics currents and THD
Oscillography
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The relay measures all AC signals available on its terminals, and computes signals used later for protection purposes.
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Wye
Wye
Delta
Wye
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As we know from the past, the Current Transformers used for the transformer differential protection, were connected in a way opposite to the winding connection type to compensate the transformer phase shift. The CT on Wye connected winding were connected Delta, and the others on the Delta winding connected in Wye. This requirement has been dropped for the recent years, as the relay producers implemented the phase compensation into the relay algorithm. The T60 relay works perfectly with inputs from Wye connected CTs. The standard positive marked CT sides(away from the transformer) should be wired to the positive marks of the relay terminals.
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CT secondary currents, when connected to the relay – phase A
i2 sec
i1 sec
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The single line diagram shows how the relay is connected to the secondary circuits of the CTs, and how the secondary currents are seen by the relay. The shown on the diagram currents, correspond to D/Y30 connected type transformer. The correct connection of the relay to the CTs is very important, or else the main percent differential protection may not operate properly. Another words, if the relay is differently connected, this in return will produce some differential current, and may operate the differential element.
STEP 1. CT inputs
STEP 2. Source configuration
STEP 4. Transformer windings
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The transformer setup starts with configuration of the CTs for each winding. The secondary currents of the field CTs are connected to certain terminals on the relay identified by by the slot letter and bank number. Each letter corresponds to one DSP card of CTs and/or VTs, and the numper 1 or 5 correspond to first and second CT or VT bank. One CT bank contains three phase CTs and a ground CT. One VT bank contains three phase VTs and one auxiliary VT.
Further, the setup continues with configuration of sources SRC1,…... . SRC4. The sources are flexible tool for identifying which CTs and VTs will be used for certain application. The sources can be also used for internal current summation.
In the general settings of the transformer identified is the number of transformer windings. The entered number enables displaying the same number transformer windings menu in the windings setup.
In the transformer windings menu, there are number of data to be entered: transformer power, winding phase-to-phase voltage, connection type, grounding, and phase angle. The last setting “Angle WRT Winding1” defines the phase shift of the protected transformer. The setting for the angle of the Winding 1 must be 0 deg. The angle for the next windings must be entered as a negative value WRT(With Respect To) Winding 1.
Source (SRC) for winding currents per Step 3
Winding capacity (MVA) per transformer nameplate
Winding phase-to-phase voltage rating as per transformer nameplate
Winding connection type
Winding grounding within 87T protection zone
Angle, by which winding 2 currents lag winding 1 currents With Respect To (WRT) winding 1 angle of 0° degrees
Winding series resistance
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LOAD LOSS AT RATED LOAD: This setting should be taken from the transformer nameplate. If not available from the nameplate, the setting value can be computed as , where is the winding rated current and R is the three-phase series resistance. The setting is used as an input for the calculation of the hottest-spot winding temperature.
RATED WINDING TEMP RISE: This setting defines the winding temperature rise over 30°C ambient temperature. The setting is automatically selected for the transformer type as shown in the table below.
The loss of life function calculates the insulation aging acceleration factor using the settings entered in this section, by following equation:
The aging acceleration factor is computed every minute. It has a value of 1.0 when the actual winding hottest spot temperature is equal to the rated temperature, is greater than 1 if the actual temperature is above the rated temperature, and less than 1 if the actual temperature is below the rated temperature.
EM relay setup:
Magnitude compensation:
Relay tap calculation per CT input (introduces inaccuracy due to approximation matching the field CT with relay tap setting)
Phase shift compensation:
External Delta connected CTs on Wye, and Wye connected CTs on Delta windings(increases the chance of making connection mistakes)
Digital relay setup:
Automatic magnitude compensation:
Software computes magnitude compensation factors for all winding currents, and scales them internally
Phase shift compensation:
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The old method of external phase compensation, was to connect the CTs for Delta connected windings in wye, and for Wye connected windings in Delta. The phase compensation, performed in the relay is “universal” as the algorithm is able to take not only the standard transformer shifts, but any angle from 0 to 360, and compare to the phase shift between the winding currents presented on its terminals. Upon entered angle WRT, the relay computes by how many degrees, and in what direction to shift the currents, and make them 180 degrees apart from the currents of the reference winding .
The magnitude compensation is also performed internally on T60, where the closest to the winding rated current CT primary is taken as a reference for per unit calculation.
T60 phase compensation rules:
The first Delta or Zig-Zag winding from the transformer setup becomes phase reference winding. When non of the above winding connections are present, the reference is the first Wye winding.
For ABC rotation, the phase compensation angle is calculated as follows:
comp[w] = [w ref.] - [w]
Example: Transformer type D/Y30
WYE: comp[w] = 0° - (-30°) = 30° = 330 lag
For ACB rotation, the compensation angle is:
comp[w] = [w] - [w ref.]
Example: Transformer type D/Y30
UR T60 : PHASE COMPENSATIONS
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Used as a phase reference in the T60 transformer setup are the angles of the first Delta or Zig-Zag winding currents in the order they appear in the transformer winding set up. If all transformer windings are connected in Wye, the first Wye becomes a reference. For ABC rotation, the angle by which the vectors of the winding 2 currents should be rotated by 30 degrees in the example. If ACB rotated source is connected to the D/Y30 transformer, the angle displacement between the winding 1 and winding 2 currents becomes 330 degrees. Therefore, the compensation angle becomes (-30 degrees).
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For the example of D/Y30 transformer, the phase compensation is performed as shown on the picture. The 30 degrees lagging currents from the WYE winding are 180 degrees shifted by the current transformers reversed connection, and therefore flow through the relay with 210 degrees apart from the DELTA currents. The phase compensation algorithm shifts the currents by 30 degrees in positive direction, till the angle between the currents of identical phase becomes 180 degrees.
r
H1
H2
H3
X1
X2
X3
IA '
IB '
IC '
IA
IB
IC
IA'
IB'
IC'
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For a Wye/ Delta 30 transformer connected to a source with ABC rotation sequence, the angles of the Delta are the reference angles, means that the phase compensation is calculated as -30 – 0 = -30 degrees. The vectors of the Wye currents will be moved by 30 degrees in negative direction to match the vectors of the Delta winding currents. In this case the winding currents on the relay seen as displaced by -210 degrees = -180 –30, will be prepared for the biased differential protection with 180 degrees displacement.
r
H1
H2
H3
X1
X2
X3
IA '
IC '
IB '
IA
IB
IC
IA'
I b
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For a Wye/ Delta 30 transformer connected to a source with ABC rotation sequence, the angles of the Delta are the reference angles, means that the phase compensation is calculated as -30 – 0 = -30 degrees. The vectors of the Wye currents will be moved by 30 degrees in negative direction to match the vectors of the Delta winding currents. In this case the winding currents on the relay seen as displaced by -210 degrees = -180 –30, will be prepared for the biased differential protection with 180 degrees displacement.
UR T60 : MAGNITUDE COMPENSATION
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Irated(w1)= MVA/(kV(w1)* 3)
Irated(w2)= MVA/(kV(w2)* 3)
L margin(w1) = CT primary(w1)/I rated (w1)
L margin(w2) = CT primary(w2)/I rated (w2)
Finds the lowest CT margin:
REFERENCE CT: = min [L margin(w1), L margin(w2)]
Finds the magnitude coefficients, by which the currents from the corresponding winding are multiplied
M(W)= [CT prim(W).V nom(W)] / [CT prim(Wref).V nom(W ref)]
87T magnitude reference set to “Automatic”:
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The magnitude compensation performed on T60 uses a reference CT which is defined by the criteria of minimum margin after division of the primary rated CT current by the corresponding winding rated current. It is assumed that this reference CT would saturate first, as normally will carry current close to its primary rated. Once the relay defines the magnitude reference CT, it calculates the magnitude coefficients by which the currents from the other CT be scaled. The coefficient for the currents from the reference CT will be set to 1, and the other one will be set by calculation including the CT and transformer entered parameters.
If this is three-winding transformer, the magnitude scaling coefficients by which the currents from each winding are multiplied are the following:
M(W1)= [CT prim(W1).kV(W1)] / [CT prim(W3).kV(W3)]
M(W2)= [CT prim(W2).kV(W2)] / [CT prim(W3).kV(W3)]
M(W3)= [CT prim(W3).kV(W3)] / [CT prim(W3).kV(W3)]= 1 : as reference
UR T60 : MAGNITUDE COMPENSATIONS
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I2COMP = C2*M2(w2)*(I2SEC/CT2RATIO) where,
C1, C2 - phase shift coefficients ( C = 1 for the phase reference winding)
M1, M2 - magnitude coefficients ( M = 1 for the magnitude reference winding)
DIFFERENTIAL SIGNAL:
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The differential currents on T60 are formed after applying phase, zero sequence(if grounding into the zone is chosen) and magnitude compensations. The value is calculated and displayed in per unit( per reference CT). The relay performs summation of already scaled in per unit and displaced by 180 degrees winding secondary currents.
The restraint signal is defined as the maximum of the compensated currents.
UR T60 : DIFFERENTIAL-RESTRAINT CHARACTERISTIC
small errors during linear operation of the CTs (S1) and
large CT errors (saturation) for high through currents (S2)
S1
S2
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The T60 Percent Differential element uses two slope, two breakpoint defined differential restraint characteristic. The two slopes are fully adjustable, to cope with required internal fault sensitivity, and external through fault currents security. The Slope 1 requires entering of setting in percent, and it should match the linear region of the CT magnetizing characteristics, where the error is defined as not exceeding 10%.
The Slope 2 setting in percent, is designed to cope with large CT errors beyond the CT linearity, where the large fault currents with or without DC offset, may saturate the CT, and produce big differential current in return.
the safe limit of linear CT operation (B1) and
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The two Breakpoints of the characteristic define the restraining signal, and are to be set for the safe limit of the CT linear operation – Breakpoint 1, and at the minimum current that may cause saturation – Breakpoint 2.
The logic of the element is the following:
* If Id> PKP and Ir < B1 and Id/Ir > Slope 1, OR
* Id>PKP and B1<Ir<B2 and Id/Ir > B1&B2, OR
* Id>PKP and Ir> B2 and Id/Ir > Slope 2 – TRIP,
else NO TRIP
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The settings of Percent differential protection are displayed in one window and applies for all three phases. Here is also the place, where the levels of the 2-nd and 5-th harmonic are entered. For better visualization of the settings, provided is View screen window, where the characteristic is displayed.
DIFFERENTIAL SIGNAL:
Removal of the zero sequence component from the differential signal:
optional for delta-connected windings
enables to cope with in-zone grounding transformers and in-zone cables with significant zero-sequence charging currents
Removal of the decaying dc component
Full-cycle Fourier algorithm for measuring both the differential current phasor and the second and fifth harmonics
RESTRAINING SIGNAL:
Full-cycle Fourier algorithm for measuring the magnitude
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The example shows the magnitude compensation of the currents and the per unit values considering a load of 800 Amps on the 69kV side.
Unit definition for biased and unbiased differential protections:
(Automatic selection)
The unit used by the T60 percent and instantaneous differential protections, is ”the primary rated CT, representing the magnitude reference winding”
From the Example: XFMR: D/Yg30, 100MVA, 230/69kV
230kV side: CT1(500:5), I rated(230kV) = 251 Amps
69kV side: CT2(1000:5), I rated(69kV) = 836.7 Amps
Margin(230kV) = 500/251 = 1.99
REFERENCE: > Winding 2
UNIT: CT2 (1000:5)
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The computation for the magnitude compensation ends with the following results:
CT2(1000:5) – reference
(Id/Ir)*100 = 0%
I2SEC = 800/(CT2RATIO = 200) = 4 Amps
I1SEC = 240/(CT1RATIO = 100) = 2.4 Amps
compensated currents:
I2COMP = (800/1000)*(M2 = 1) = 0.8 pu (reference)
differential current: Id = 0.8 pu - 0.8 pu = 0 pu
restraining current: Ir = max(0.8, 0.8) = 0.8 pu
UR T60 : 87T CALCULATION EXAMPLE
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This case of normal transformer operation moves the restraint current to 0.8 pu, with 0 pu differential current.
Min PKP: = 0.3 pu = 0.3 * 1000 = 300 Amps differential current
Break 1: = 2 pu = 2*1000 = 2000 Amps restraint current
Break 2: = 8 pu = 8*1000 = 8000 Amps restraint current
Slope 1: = 25% = (Id/Ir)*100 = (0.25)*100
Slope 2: = 95% = (Id/Ir)*100 = (0.95)*100
UR T60 : 87T CALCULATION EXAMPLE
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(Winding 1 selected as reference)
The phase-to-phase voltage of Winding 1 is the reference voltage, and the primary rated CT, is the unit for magnitude scaling computations
…..or for 800 Amps load at Winding 2 ,
I2SEC = 800/(CT2RATIO = 200) = 4 Amps
I1SEC = 240/(CT1RATIO = 100) = 2.4 Amps
Magnitude coefficients:
M2 = (1000*69)/(500*230) = 0.6
Compensated currents:
I2COMP = (800/1000)*(M2 = 0.6) = 0.48 pu
differential current: Id = 0.48 pu - 0.48 pu = 0 pu
restraining current: Ir = max(0.48, 0.48) = 0.48 pu
UR T60 : 87T SETTINGS CALCULATION EXAMPLE
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Worst case:
+ 10% CT1 error of In(w1) = 25.1 A, therefore In(w1) =276.1 Amps
- 10% CT error of In(w2) = 83.67 A, or In(w2) = 753 Amps
753 Amp/1000 = 0.75 pu CT2(1000:5) - reference
(276.1 Amp* 1.668)/500 = 0.92 pu
Differential current = 0.92pu - 0.75pu = 0.17 pu (Min Pick Up setting)
The tap changer adds another 10% error
In(w1) = 251 Amps
In(w2) = 836.7 Amps
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The example from the slide is just used for the presentation purposes, and doesn’t replicate any real system conditions. The calculation of the settings are based on the given in the example data and eventually do not represent the best approach in the art of protection calculation.
Slope 1 setting: (Id/Ir)*100 = 18% + 5%(safety margin) = 23 %
Breakpoint 1:
The setting should correspond to the maximum of the linear operation of the CT, counting up to 80% remanent flux in the core of the CT.
CT1(500:5), C400 has Vsat = 125V, and Zb = 5 - total burden
CT2(1000:5), C400 has Vsat = 240V, and Zb =4 - standard burden
Therefore:
Imax(CT2) = 60 Amps
Imax, pu(CT2) = Imax(CT2)*M2/CT tap = 12 pu
The 80% CT remanent flux will lower the smaller per unit value to 1.668 pu, which will be used for Breakpoint 1 setting
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Breakpoint 2:
The per unit setting, should correspond to the smallest fault current (no DC offset) that can cause a CT to saturate. The Breakpoint 2 can be set to 8.34 pu.
Slope 2:
The setting for Slope 2 should be high enough to override the differential current, caused by CT saturation.
The worst case for example would be if say CT1 doesn’t saturate on through fault current, and CT2 saturates heavily producing very small current
In such cases the Slope 2 should be set as high as 95-98%.
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Saturation of CT(1000:5) on ph A to G fault on 100MVA, 230/69kV, D/Y30 transformer.
Max Id/Ir ratio = 0.57 *100% = 57%
Full DC offset
TDC = 67 ms
Light CT saturation on fault current with full DC offset
UR T60 : 87T PERFORMANCE ON CT SATURATION
Id/Ir =0. 57
External B to C fault on Y side of the
D/Y30, transformer.
100MVA, 230/69kV
Id/Ir =0. 5
External B to C fault on Y side of the
D/Y30, transformer.
100MVA, 230/69kV
Id/Ir =0. 87
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• Adapt. 2nd
• Trad. 2nd
Per phase
2-out-of-3
Average
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The percent differential inhibiting function includes selection of 2-nd harmonic mode: Adaptive or Traditional 2-nd harmonic, and selection of the inhibiting method: Per-phase, Cross-Phase, or Averaging. This provides six combinations to be used in cases, where the levels of the 2-nd harmonic during transformer energization goes bellow the commonly used 20% setting or as defined by the user.
In addition to all these choices, provided are FlexLogic operands, which will change the meaning depend on the selected combination. For example the operand “XFMR 2ND HRMC INHT A” will have a flag 1, when “Per-phase” and “Traditional 2-nd harmonic” are selected when the 2-nd harmonic into phase A is above the 2-nd harmonic setting. The same operand will have a flag 1 if for example another inhibit modes are selected, and the conditions really persist as identified by the settings.
Adaptive 2-nd harmonic
uses both the magnitude and phase relation between the second harmonic and the fundamental frequency (60Hz) components
Traditional 2-nd harmonic
Uses only the magnitude of the 2-nd harmonic, without considering the phase angle with the fundamental component
UR T60: 87T – 2ND HARMONIC INHIBIT
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The T60 Percent differential protection, uses new approach of dealing with the 2-nd harmonic, which is believed makes better recognition between inrush and internal fault. In addition of monitoring the level of 2-nd harmonic into the energization waveform, the algorithm detects also the relation of the 2-nd harmonic phasor and the fundamental frequency phasor.
Per-phase
The 2-nd harmonic from an individual phase, blocks the operation of the differential protection for only that phase, if above the 2-nd harmonic setting
2-out-of-3
The detection of 2-nd harmonic on any two phases that is higher than the setting, blocks the differential protection on all three phases.
Adaptive Average 2nd harmonic inhibit
The averaged amount of 2-nd harmonic from the three phases, blocks the differential protection for all of them, if above the setting.
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Dynamic switching of the Average 2nd harmonic inhibit during energization:
If the differential current on one phase drops below 0.04pu earlier than the other two phases
During energization, the denominator is automatically decreased from 3 to 2.
If the differential currents on two of the phases drop below the cutoff value of 0.04pu, the denominator is decreased from 3 to 1.
%2nd harmonic =
1
2nd(phC)
When the differential current on all three phases is above 0.04pu during energization,
the denominator is equal 3.
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As it is known from the past, the classical method of blocking the operation of the biased differential element during transformer energization, was done by detecting the level of 2-nd harmonic content, where the two levels: the level of fundamental frequency signal, and the 2-nd harmonic signal are compared.
However, by examining the variation of the second harmonic level through the time the inrush waveform lasts, one can notice, that in many cases, the 2-nd harmonic goes bellow the specified commonly used 20% threshold. For the recent years however, the transformer producers, improved the quality of the transformer iron core, which made the transformer more susceptible of producing 2-nd harmonic way bellow the 20% threshold.
0
1
2
3
4
5
6
7
8
9
10
11
Fundamental
phasor
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The implementation of the relation detection, required estimation of the 2-nd harmonic phasor, which rotates twice as faster as the fundamental phasor. Th solution was to present it as shown in the formulae.
Operating foundations of the Adaptive 2nd harmonic inhibit:
if the second harmonic drops magnitude-wise below 20%, the phase angle of the complex second harmonic ratio is close to either +90 or
-90 degrees during inrush conditions
the phase angle may not display the 90-degree symmetry if the second harmonic ratio is above some 20%
if the second harmonic ratio falls bellow 20% making an angle of ± 90° with the fundamental current, the algorithm applies adaptive lenses, and time for which the 87T protection is inhibited.
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vs. complex second harmonic ratio
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The diagram here shows the time that is allowed for the second harmonic level to last bellow for example 20%. The maximum is 5 cycles.
The obtained characteristic has the following distinctive features:
If the angle of I2/I1 is close to 0 or 180 degrees, the inrush restraint is removed immediately regardless of the magnitude of the second harmonic
If the angle is close to 90 degrees, the delay before removing the restraint depends on the amount of the second harmonic: for low ratios of the second harmonic, the delay is very short, while for ratios close to 20% it rises to 5-6cycles. This is enough to prevent maloperation due to the second harmonic dropping bellow some 20% during inrush conditions.
-0.2-0.100.10.20.3
-0.25
-0.2
-0.15
-0.1
-0.05
0
0.05
0.1
0.15
0.2
0.25
I
2
/ I
1
(real)
I
2
/ I
1
(imaginary)
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Inrush current on transformer energization – phase C
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It was encountered a time of 74.7 ms = 4.5 cycles the second harmonic lasted bellow the 20% threshold in phase C.
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Another case of energization, shows lower than 20% second harmonic in phase A.
UR T60: 87T – ADAPTIVE 2ND HARMONIC INHIBIT EXAMPLES
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The level went down to 9.9%, and the time for getting around 2.11 cycles.
UR T60&T35 : OVERALL BENEFITS
Up to four restraints(T60) and up to six supported by UR T35
Improved transformer auto-configuration
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T60 Instantaneous Differential Protection
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UR T60: INSTANTANEOUS DIFFERENTIAL PROTECTION
The setting must be higher than the maximum differential current the relay may detect on through fault accounting for CT saturation
The setting must be higher than the maximum inrush current during energization
The setting must be lower, than the maximum internal fault current
87T/50 PICKUP SETTING:
Restricted Ground Fault (RGF) protection
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The T60 is equipped with number of Restricted Ground Fault elements(one per CT bank) any of which can be configured separately. The RGF elements are required for detecting transformer winding to ground faults, and apply to Wye connected windings with neutrals grounded through a resistor. It is not recommended applying the RGF protection on solidly grounded Wye windings, as the fault current is in non-linear relation to the distance of the fault from the winding neutral.
Low impedance ground differential protection
Adjustable pickup and slope settings to cope with unbalances during load and through fault currents
Configurable time delay – not needed after the RGF enhancements
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The RGF protection doesn’t have to be a fast one, as it is believed the winding to ground fault currents, are of small magnitude, which may not harm the transformer. The fault current is in linear relation to the distance of the fault from the neutral. The linearity is achieved by the value of the grounding resistor, which is comparable to the transformer leakage inductance, making the fault current in a straight line.
Zero sequence based restraint:
Negative sequence based restraint:
IR2 =3*| I2 | - in normal conditions
Positive sequence based restraint:
and |I1| > |I0|
Ground restraint current:
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The GF settings allow the user to enter values for the minimum PKP, the slope and pickup time delay. As it was mentioned in the previous notes, the RGF I to be used with a some time delay, to overcome the cases of external ground faults, and other external faults with CT saturation.
The ground differential current is a vectorial summation of the calculated from the phase CTs neutral current 3Io, and the measured on the winding neutral ground current. The slope is developed by using the ground differential current and the maximum phase current.
EXAMPLE:
Min PKP = 80A/1500 = 0.053 pu
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UR T60: RGF PROTECTION – SETTINGS CALCULATION
The slope setting for the RGF protection must be above the maximum expected ground differential/restraint ratio on through faults due to the CT saturation. A setting in the range from 40% to 70% is recommended. The graph shows the percent of CT saturation of the phase CT, and the actual ground differential/restraint ratio. For example, 80% CT saturation during external phase to ground fault results into 66.7% ratio. Therefore, a setting of 70% would be sufficient.
80% phase CT saturation
66.7% actual Igd/Igr ratio
I fault
Primary
Secondary
SETTINGS:
SECURITY
External single line to ground fault example and 80% ground CT saturation:
Phase currents
IA = 10 pu IR0 = abs(3*(2/3) – (-10)) = 12 pu Igd = 8pu
IB = 0 pu IR2 = 3*(1/3) = 10 pu Igr = 12 pu
IC = 0 pu IR1 = 0.0 pu Igd/Igr,% = 66.7%
IG = 2 pu
Phase currents
IA = 1.1 pu 0° I0 = 0.033 pu IR0 = abs(3*0.033 –(0.05) = 0.05
IB = 1 pu -120° I2 = 0.033 pu IR2 = 3*(0.033) = 0.1 pu
IC = 1 pu -240° I1 = 1.033 pu IR1 = 1.033/8 = 0.1292 pu
IG = 0.05 pu 0°
Igr = 0.1292pu
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The RGF protection uses new techniques for calculation of the restraint current, providing better security on external faults with or without saturation, and increased sensitivity on internal faults. Used as a restraint for that protection is the maximum of precalculated values based on zero, positive and negative sequence currents. The value based on Zero sequence current – Io is meant to provide maximum restraint during external ground faults, till the positive and negative components are used for being restraint current during symmetrical and unsymmetrical faults correspondingly.
CT SATURATION
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In cases of external ground faults and CT saturation, the restraint current would rise during this half cycle saturation free time, and than start to decay, during the saturation, such that it will reach 50% of its initial magnitude after 15.5 cycles, assuming the current from the saturated CT did not recover. The restraint current will again follow the maximum of the precalculated values once the current recovers from saturation.
TRANSFORMER ENERGIZATION
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The oscillography shows real transformer energization, where the CT on phase B started to saturate after almost 8 cycles of the energization. In the first 8 cycles, no ground differential was detected, as the calculated by the relay 3Io and the measured ground current match perfectly by magnitude, and were 180 degrees apart. However, during the CT saturation, this balance was broken, so that the differential current was built up. The relay however did not even pick up, due to the decaying restraint current, where the differential/restraint ratio did not exceed the slope setting.
Excel simulation tool for RGF protection tests
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The oscillography shows real transformer energization, where the CT on phase B started to saturate after almost 8 cycles of the energization. In the first 8 cycles, no ground differential was detected, as the calculated by the relay 3Io and the measured ground current match perfectly by magnitude, and were 180 degrees apart. However, during the CT saturation, this balance was broken, so that the differential current was built up. The relay however did not even pick up, due to the decaying restraint current, where the differential/restraint ratio did not exceed the slope setting.
UR T60: OVEREXCITATION(V/Hz) PROTECTION
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The over-excitation protection is one of the most important protections on the transformer, as it prevents damaging of the transformer due to exceeding the normal voltage, or lower than the normal frequency events. The flux in the transformer core is directly proportional to the voltage and inversely proportional to the frequency. When the V/Hz ratios are exceeded, saturation of the magnetic core of the transformer occurs. This causes excessive core flux resulting in a high interlamination core voltage which in return results in iron burning.
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The block diagram shows the how the V/Hz signal is derived, and compared to the setting under chosen inverse curve. Derived are also V/Hz FlexLogic operands that can be used for alarm blocking or tripping.
66.4 V / 60 Hz = 1 PU,
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The V/Hz unit value depends on the entered settings for the nominal voltage and frequency. For example 66.4 nominal secondary voltage and 60 Hz nominal system frequency will become 1 per unit value. Setting the pickup to 1.1 pu, will mean increased voltage to a value of 73 Volts, decreased to 54.5 Hz frequency, or combination of increased voltage and decreased frequency at the same time.
improved cooling reset time
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To deal better with the cooling characteristic of the protected transformer, machine, generator, available for setup are the three standard inverse curves plus the two UR FlexCurves. By setting up a FlexCurve, the user is given a tool to modify the heating/cooling characteristic in a way he/she want it.
UR T60: THERMAL PROTECTION
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The over-excitation protection is one of the most important protections on the transformer, as it prevents damaging of the transformer due to exceeding the normal voltage, or lower than the normal frequency events. The flux in the transformer core is directly proportional to the voltage and inversely proportional to the frequency. When the V/Hz ratios are exceeded, saturation of the magnetic core of the transformer occurs. This causes excessive core flux resulting in a high interlamination core voltage which in return results in iron burning.
SETTINGS:
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*
Hottest Spot Temperature
Time (min)
Expected Top Oil Temp
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
0
0
0
0
0.0
0.000
0
0
0.0
0.000
1
0.84
30
42
0.0
0.000
30
42
0.0
0.000
2
0.84
30
49
0.0
0.000
30
49
0.0
0.000
3
0.84
30
54
0.0
0.000
30
54
0.0
0.000
4
0.84
31
57
0.0
0.000
31
57
0.0
0.000
5
0.84
31
59
0.0
0.001
31
59
0.0
0.000
6
0.84
31
60
0.0
0.001
31
60
0.0
0.000
7
0.84
31
60
0.0
0.001
31
60
0.0
0.000
8
0.84
31
61
0.0
0.001
31
61
0.0
0.000
9
0.84
31
61
0.0
0.002
31
61
0.0
0.000
10
0.84
32
62
0.0
0.002
32
62
0.0
0.000
11
0.84
32
62
0.0
0.002
32
62
0.0
0.000
12
0.84
32
62
0.0
0.002
32
62
0.0
0.000
13
0.84
32
62
0.0
0.003
32
62
0.0
0.000
14
0.84
32
62
0.0
0.003
32
62
0.0
0.000
15
0.84
32
63
0.0
0.003
32
63
0.0
0.000
16
0.84
33
63
0.0
0.004
33
63
0.0
0.000
17
0.84
33
63
0.0
0.004
33
63
0.0
0.000
18
0.84
33
63
0.0
0.004
33
63
0.0
0.000
19
0.84
33
63
0.0
0.005
33
63
0.0
0.000
20
0.84
33
63
0.0
0.005
33
63
0.0
0.000
21
0.84
33
64
0.0
0.006
33
64
0.0
0.000
Actual LOL is read from data Logger and has a resolution of only 2 decimal places.
Table 49-10 4.1.1c
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
Time (min)
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
ExpectedFAA p.u
ExpectedXfmr LOL
ACTUAL FAA p.u
0
0.000
35
0.0
0
0
0
0
0.000
0
0.0
0.000
0
0
0
*Note: Read the Xfmr LOL values from the relay front panel. This value is rounded off in Datalogger and therefore not accurate.
1
0.837
127
0.0
0.000
127
0
0.000
1
0.600
56
0.0
0.000
56
0
0
2
0.837
161
0.4
0.006
161
0.3
0.007
2
0.600
75
0.0
0.000
75
0
0
3
0.837
173
0.9
0.021
174
0.9
0.021
3
0.600
88
0.0
0.000
89
0
0
4
0.837
177
1.2
0.040
178
1.2
0.042
4
0.600
98
0.0
0.000
98
0
0
5
0.837
179
1.3
0.062
180
1.4
0.066
5
0.600
105
0.0
0.000
105
0
0
6
0.837
180
1.4
0.086
181
1.4
0.091
6
0.600
110
0.0
0.000
111
0
0
7
0.837
180
1.4
0.109
181
1.4
0.115
7
0.600
114
0.0
0.000
114
0
0
8
0.837
180
1.4
0.133
181
1.5
0.141
8
0.600
116
0.0
0.000
117
0
0
9
0.837
180
1.4
0.157
181
1.5
0.166
9
0.600
118
0.0
0.000
119
0
0
10
0.837
180
1.4
0.180
181
1.5
0.190
10
0.600
119
0.0
0.000
121
0
0
11
0.837
180
1.4
0.204
181
1.5
0.216
11
1.167
193
0.3
0.005
195
0.2
0.006
*Note: If the fault current does not start at the same time as the element updates there will be difference between the expected and actual values.
12
0.837
180
1.4
0.228
181
1.5
0.214
12
1.167
246
10.7
0.183
248
11.6
0.207
13
0.837
180
1.4
0.251
181
1.5
0.241
13
1.167
284
93.6
1.742
283
88.8
1.713
14
0.837
180
1.4
0.275
181
1.5
0.267
14
0.300
219
1.9
1.773
218
1.6
1.713
15
0.837
180
1.4
0.299
181
1.5
0.291
15
0.300
172
0.1
1.774
171
0
1.713
16
0.837
180
1.4
0.322
181
1.5
0.316
16
0.300
138
0.0
1.774
138
0
1.713
17
0.837
180
1.4
0.346
181
1.5
0.342
17
0.300
114
0.0
1.774
114
0
1.713
18
0.837
180
1.4
0.370
181
1.5
0.367
18
0.300
97
0.0
1.774
97
0
1.713
19
0.837
180
1.4
0.393
181
1.5
0.393
19
0.300
85
0.0
1.774
84
0
1.713
20
0.837
180
1.4
0.417
181
1.5
0.417
20
0.300
76
0.0
1.774
75
0
1.713
21
0.300
70
0.00
1.774
69
0
1.713
22
0.300
65
0.00
1.774
65
0
1.713
23
0.300
62
0.00
1.774
61
0
1.713
24
0.300
59
0.00
1.774
59
0
1.713
DRY
T60 Benefits of Source configuration and some useful applications
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Fig. 1
Fig 1
Earth fault protection configuration for the application of Fig.2.
Source and protection
B. Restricted earth fault protection for Autotransformers
Consider an Autotransformer shown in Fig.2. The restricted earth fault protection can be achieved by comparing the neutral current in the sum of the H and X windings with the ground current measured at the neutral of the transformer.
It is assumed that the transformer relay uses F1, F5, and M1 CT banks, the sources are configured as in Fig.4. The transformer differential protection shall be configured as in Fig.4; the restricted earth fault protection shall be configured as in Fig.5.
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F1
F5
M1
M5
U1
U5
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The T35 relay can handle up to 6 sets of CTs and/or VTs from the system, and performing the differential transformer protection.
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The setup requires entering of the CT and VT ratios, source configuration, and winding configuration.
F1
F5
M1
M5
U1
U5
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It makes it easier when T35 is to be applied on autotransformers, as most of them have more than 3 CT set inputs.
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For providing biased differential protection on auto transformers, some rules apply:
The autotransformer power MVA, should be the same for each winding
The entered winding voltage should be the same
The “ Not within zone” setting for the grounding should be chosen, as to be provided per phase individual protection.
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Excel simulation tool for transformer differential protection tests
Website:
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This Excel spreadsheet was created to help the T60 design testing, and customers in performing some differential element tests. The simulation replicates the the real transformer setup, and percent differential settings. Different cases of operation/ no operation can be created by specifying magnitudes and angles of each transformer winding. The message for trip/no trip at the bottom is a replica of the operate and dropout flags of the element in the relay.
Example 1 :
Diagram 1
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The following pages, describe two examples of how one can test, a mixed type winding transformer, by using only 2 or 3 individually adjustable currents. The examples are based on distribution of the currents, during fault currents, and the values given in per unit winding rated current.
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The test are showing the the points from the characteristic, corresponding to 0 differential, PKP, slope 1, intermediate slope between Break 1 and Break 2, and slope 2
…example 1 results - continue
Diagram 2
Example 2 :
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….Example 2 results - continue
Min. PKP
S lope
IA
IB
IC
IG
Igd
Igr
50% of its initial magnitude after 15.5 cycles
SETTING
VOLTS/HZ 1 BLOCK:
F1
M1
F5
M5
F1
F5
M1
M4
H
X
Ib(f)=0
Ic(f)=0
A
B
C
A
B
C
Ia(f)=0
A
B
C
A
B
C

Documents

Reles de Proteccion T60 & T35