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© ABB Power Technology 1_114Q07- 1 -
Transformers Protection
Protections
© ABB Power Technology 1_114Q07- 2 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
© ABB Power Technology 1_114Q07- 3 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Introduction. Possible faults in a transformer
EXTERNAL
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External Short Circuits
INTERNAL
Overloads Overvoltages
Short circuits
between turns
between windings
Ground faults
Overtemperature
Overpressure
Miss of oil
Introduction. Transformers protections
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INTERNAL
ELECTRICAL
BUCHHOLZ (SPR)
THERMOMETER
THERMOSTAT
THERMAL IMAGE
PHASE
OIL LEVEL
NEUTRAL
PRESSURE RELIEF VALVE
DIFFERENTIAL RELAY
BUCHHOLZ-TAP CHANGER
THERMAL RELAY
TANK RELAY
FUSES
SURGE ARRESTERS
OVERCURRENT RELAYS
Magnetizing inrush When a transformer is first energized, a transient magnetizing or exciting inrush current may flow. This inrush current, which appears as an internal fault to the differentially connected relays, may reach instantaneous peaks of 8 to 30 times those for full load.
The factors controlling the duration and magnitude of the magnetizing inrush are:
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Size and location of the transformer bank
Size of the power system
Resistance in the power system from the source to the transformer bank
Type of iron used in the transformer core and its saturation density
Prior history, or residual flux level, of the bank
How the bank is energized
Initial inrush When the excitation of a transformer bank is removed, the magnetizing current goes to O.
The flux, following the hysteresis loop, then falls to some residual value φ R. If the transformer were reenergized at the instant the voltage waveform corresponds to the residual magnetic density within the core, there would be a smooth continuation of the previous operation with no magnetic transient.
In practice, however, the instant when switching takes place cannot be controlled and a magnetizing transient is practically unavoidable.
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Initial inrush
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If the circuit is re-energized at the instant the flux would normally be at its negative maximum value (-φ max) as the residual flux would have a positive value and since magnetic flux can neither be created nor destroyed instantly, the flux wave, instead of starting at its normal value (-φ max) and rising along the dotted line, will start with the residual value (φ R) and trance the curve (φ L).
Initial inrush
Curve φ t is a displaced sinusoid, regardless of the magnetic circuit's saturation characteristics.
Theoretically, the value of φ max is + (|φ R| + 2| φ max|).
In transformers designed for some normal, economical saturation density φ s, the crest of φ t will produce super saturation in the magnetic circuit.
The result will be a very large crest value in the magnetizing current.
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Initial inrush The residual flux φ R is the flux remaining in the core after the voltage is removed from the transformer bank.
The flux will decrease along the hysteresis loop to a value of φ R, where i = 0.
Because the flux in each of the three phases is 120° apart, one phase will have a positive φ R and the other two a negative -φ R, or viceversa.
As a result, the residual flux may either add to or subtract from the total flux, increasing or decreasing the inrush current.
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Initial inrush
For the first few cycles, the inrush current decays rapidly. Then, however, the current subsides very slowly, sometimes taking many seconds if the resistance is low.
The time constant of the circuit (L/R) is not, in fact, a constant: L varies as a result of transformer saturation. During the first few cycles, saturation is high and L is low. As the losses damp the circuit, the saturation drops and L increases. According to a 1951 AIEE report, time constants for inrush vary from 10 cycles for small units to as much as 1 min for large units.
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Initial inrush The resistance from the source to the bank determines the damping of the current wave.
Banks near a generator will have a longer inrush because the resistance is very low.
Likewise, large transformer units tend to have a long inrush as they represent a large L relative to the system resistance.
At remote substations, the inrush will not be nearly so severe, since the resistance in the connecting line will quickly damp the current.
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Initial inrush When there is more than one delta winding on a transformer bank, the inrush will he influenced by the coupling between the different voltage windings. Depending on the core construction, three-phase transformer units may be subject to interphase coupling that could also affect the inrush current.
Similar wave shapes would be encountered when energizing the wye winding of a wye-delta bank, or an autotransformer. Here, the singlephase shape would be distorted as a result of the interphase coupling produced by the delta winding (or tertiary).
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Initial inrush
Maximum inrush will not, of course, occur on every energization.
The probability of energizing at the worst condition is relatively low.
Energizing at maximum voltage will not produce an inrush with no residual.
In a three-phase bank, the inrush in each phase will vary appreciably.
The maximum inrush for a transformer bank can be calculated from the excitation curve if available, and Table shows a typical calculation of an inrush current (used phase A voltage as 0° reference).
Closing
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φ S
angle
Peak value of inrush current wave (p.u.) Ia
Ib
Ic
Ia-Ib
Ib-Ic
Ic-Ia
1.40
0°
5.60 -3.73
-3.73
8.33
-3.73 -8.33
1.40
30°
5.10 — 1.87 -5.10
5.96
5.10
1.15
0°
6.53 -4.67
1.15
30°
6.03 — 2.80 -6.03
-9.20
-4.67 10.20 -4.67 -10.20 7.83
6.03 -11.06
Initial inrush
From these calculated values it can be seen that:
The lower the value of the saturation density flux φ S, the higher the inrush peak value.
The maximum phase-current inrush occurs at the 0° closing angle (i.e., 0 voltage).
The maximum line-current inrush occurs at ± 30° closing angles.
Because of the delta connection of transformer winding or current transformers, the maximum line-current in-rush value should be considered when applying current to the differential relay. Closing
© ABB Power Technology 1_114Q07- 15 -
φ S
angle
Peak value of inrush current wave (p.u.) Ia
Ib
Ic
Ia-Ib
Ib-Ic
Ic-Ia
1.40
0°
5.60 -3.73
-3.73
8.33
-3.73 -8.33
1.40
30°
5.10 — 1.87 -5.10
5.96
5.10
1.15
0°
6.53 -4.67
1.15
30°
6.03 — 2.80 -6.03
-9.20
-4.67 10.20 -4.67 -10.20 7.83
6.03 -11.06
Sympathetic inrush When a bank is paralleled with a second energized bank, the energized bank can experience a sympathetic inrush.
The offset inrush current of the bank being energized will find a parallel path in the energized bank.
The dc component may saturate the transformer iron. creating an apparent inrush.
The magnitude of this inrush depends on the value of the transformer impedance relative to that of the rest of the system, which forms an additional parallel circuit.
Again, the sympathetic inrush will always be less than the initial inrush.
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Sympathetic inrush The total current at breaker C is the sum of the initial inrush of bank A and the sympathetic inrush of bank B.
Since this waveform looks like an offset fault current, it could cause misoperation if a common set of harmonic restraint differential relays were used for both banks.
Unit-type generator and transformer combinations have no initial inrush problem because the unit is brought up to full voltage gradually. Recovery and sympathetic inrush may be a problem, but as indicated above, these conditions are less severe than initial inrush.
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© ABB Power Technology 1_114Q07- 18 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Differential relaying for transformer protection
It compares the current entering the transformer with the current leaving the element.
If they are equal there is no fault inside the zone of protection
If they are not equal it means that a fault occurs between the two ends
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87 With internal fault Id > 0 ⇒ Trip With external fault Id = 0 ⇒ No trip
Differential relaying for transformer protection
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Alternatively one could form an algebraic sum of the two currents entering the protected element, which could be termed as differential current (Id), and use a level detector relay to detect the presence of a fault.
In general this principle is capable of detecting very small magnitudes of fault.
Its only drawback is that it requires currents from the extremities of a zone of protection
Differential relaying for transformer protection Differential relays are the principal form of fault protection for transformers rated at 10 MVA and above.
These relays, however, cannot be as sensitive as the differential relays used for generator protection.
Transformer protection is further complicated by a variety of equipment requiring special attention: multiple-winding transformer banks, zig-zag transformers, voltage regulators, transformers in unit systems, and three-phase trans-former banks with single-phase units.
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Differential relaying for transformer protection
Transformer differential relays are subject to several factors, not ordinarily present for generators or buses, that can cause miss-operation:
Different voltage levels, including taps, that result in different primary currents in the connecting circuits.
Possible mismatch of ratios among different current transformers.
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For units with ratio-changing taps, mismatch can also occur on the taps. Current transformer performance is different, particularly at high currents.
30° phase-angle shift introduced by transformer wye-delta connections.
Magnetizing inrush currents, which the differential relay sees as internal faults.
Differential relaying for transformer protection
Id
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To prevent miss-operation percentage characteristics are used, with line current restraint.
Operating zone
(I1 + I2)/2
Differential relaying for transformer protection Since the differential relays see the inrush current as an internal fault, some method of distinguishing between fault and inrush current is necessary.
Such methods include:
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A differential relay with reduced sensitivity to the inrush wave (such units have a higher pickup for the offset wave, plus time delay to override the high initial peaks).
A harmonic restraint or a supervisory unit used in con-junction with the differential relay
Desensitization of the differential relay during bank energization.
Differential relay for transformer protection Induction relays are relatively insensitive to the high percentage of harmonics contained in magnetizing inrush current.
The relay shown consists of a percentage differential unit and an indication contactor switch.
The percentage differential unit, an induction disc type, has an electromagnet with poles above and below the disc.
There are two restraint coils on the lower left-hand pole; the operating coil is wound on the lower right-hand pole.
Both the left- and right-hand poles have transformer winding, connected in parallel to supply current to the upper-pole windings.
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Differential relay for transformer protection The upper-pole current generates a flux in quadrature with the lowerpole resultant flux, and the two fluxes react to produce a torque on the disc.
Under normal load or in external fault, the currents in the two restraint windings flow in the same direction.
These restraining currents are equal (or effectively equal) if autobalance taps are used to compensate from mismatch in current transformer ratios - and if no significant current flows in the operating coil winding.
As a result, only contact-opening torque is produced.
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Differential relay for transformer protection If the taps are mismatched or the main current transformers saturate unequally on severe external faults, the effective difference between the currents in the two restraining windings must flow in the operating coil.
The operating coil current required to overcome the restraining torque and close the relay contacts is a function of the restraining current. For an internal fault, the restraining currents are opposite, and restraining torque tends to cancel out.
The more sensitive operating coil, however, is energized by the sum of the two currents. As a result, a large amount of contact-closing torque is produced.
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Differential relay for transformer protection In applying the relay, the current transformer ratio error should not exceed 10% during maximum symmetrical external fault current. The relay's 50% characteristic satisfactorily handles up to 35% of current mismatch, including the transformer tap changing on load and current transformer mismatch.
The relay's restraining windings have a continuous rating of 10 A; the operating winding has a continuous rating of 5 A. To prevent overloading the operating winding, however, no more than 5 A should be allowed in the untapped restraining winding.
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Variable-Percentage Transformer Differential Relay
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This type of relays have a variable-percentage characteristic:
Percentage is low on light faults, where the current transformer performance is good, and high on heavy faults, where current transformer saturation may occur.
The variable-percentage characteristic is obtained via a saturation transformer in the operating circuit.
This transformer also tends to shunt the dc component away from the operating coil.
Variable-Percentage Transformer Differential Relay The relay consists of an induction-type differential unit, a dc-indicating contactor switch, and an optional ac-indicating instantaneous trip unit.
The induction-type differential unit contains four electromagnets, operating on two discs fastened to a common shaft.
Of the electromagnets, one is the operating element and the other three are restraint elements. On the center leg of each restraint electromagnet are two primary coils and a secondary coil ; primary coils are energized from the secondaries of the current transformers connected to the bank to be protected.
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Variable-Percentage Transformer Differential Relay A 5-A current in the restraint coil will produce restraining torque. The same 5-A current flowing in two restraint coils of the same restraint electromagnet will have either additive or subtractive restraining effect, depending on the polarity of the connection (Figure c).
This relay is well suited to protect transformer banks not subject to severe magnetizing inrush, particularly if more than two restraining circuits are needed. The relay has no built-in taps and generally requires auxiliary current transformers for current matching. The operating time of the differential unit is two to six cycles; no setting is required.
The faster IIT unit is connected to the differential circuit. It is recommended for transformer protection in applications where internal fault current can exceed twice the maximum total current flowing through the differential zone for a symmetrical external fault. The IIT unit should be set at 50% external fault current or a value higher than transformer inrush current, whichever is greater.
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Harmonic restraint Transformer Differential Relay Since magnetizing inrush current has a high harmonic content, particularly the second harmonic, this second harmonic can be used to restrain and thus desensitize a relay during energization.
The method of harmonic restraint is not without its problems.
There must be enough restraint to avoid relay operation on inrush, without making the relay insensitive to internal faults that may also have some harmonic content.
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Harmonic restraint Transformer Differential Relay In the differential unit, (DU) air-gap transformers feed the restraint circuits, and a non-air-gap transformer energizes the operating coil circuit.
Since the rectified restraint outputs are connected in parallel, the relay restraint is proportional to the maximum restraining current in any restraint circuit.
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Harmonic restraint Transformer Differential Relay The percentage characteristic varies from around 20% on light faults, where current transformer performance is good, to approximately 60% on heavy fault, where current transformer saturation may occur.
This variable-percentage characteristic is obtained via the saturating transformer in the operating coil circuit.
The minimum pickup is the current that will just close the differential unit contacts, with the operating coil and one restraint coil energized.
The continuous rating of the relay is 10 to 22 A, depending on the relay tap used.
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Harmonic restraint Transformer Differential Relay The harmonic restraint unit (HRU) has a second-harmonic blocking filter in the operating coil circuit and a second-harmonic pass filter in the restraint coil circuit.
Thus, the predominant second-harmonic characteristic of an inrush current produces ample restraint with minimum operating energy.
The circuit is designed to hold open its contacts when the secondharmonic component is higher than 15% of the fundamental.
This degree of restraint in the HRU is adequate to prevent relay operation on practically all inrushes, even if the differential unit should operate.
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Harmonic restraint Transformer Differential Relay
For internal faults, ample operating energy is produced by the fundamental frequency and harmonic other than the second.
The second harmonic is at a minimum during a fault. Since the HRU will operate at the same pickup as the DU, the differential unit will operate sensitively on internal faults.
For external faults, the differential unit (DU) will restrain. The relay operating time is one cycle at 20 times tap value.
The instantaneous trip unit (IIT) is included to ensure high-speed operation on heavy internal faults, where current transformer saturation may delay HRU contact closing.
The IIT pickup is 10 times the relay tap value.
This setting will override the inrush peaks and maximum false differential current on external faults.
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Transformer Differential Relay Application
The following guidelines are designed to assist in selecting and applying relays for transformer protection.
When two or more relays appear to be equally suitable, engineering experience and economics will determine the final choice.
There is no clear-cut answer to the question of which relay or protective method to apply.
As a general rule, however, the induction-disk differential relays are used at substations remote from large generating sources where inrush is not a problem and the kVA size of the bank is relatively small.
The more complex and more expensive harmonic relays are used at generating stations and for large transformer units located close to generating sources, where a severe inrush is highly likely.
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Transformer Differential Relay Application
In general, the current transformers on the wye side of a wye-delta bank must be connected in delta, and the current transformers on the delta side connected in wye.
This arrangement (1) compensates for the 30° phase-angle shift introduced by the wye-delta bank and (2) blocks the zero sequence current from the differential circuit on external ground faults.
Transformer Differential Relay Application Zero sequence current will flow in the differential circuit for external ground faults on the wye side of a grounded wye-delta bank; if the current transformers were connected in wye, the relays would missoperate.
With the current transformers connected in delta, the zero sequence current circulates inside the current transformers, preventing relay miss-operation.
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Transformer Differential Relay Application
Relays should be connected to receive “in” and “out” currents that are in phase for a balanced load condition.
Relay taps or auxiliary current transformer ratios should be as close as possible to the current ratios for a balanced maximum load condition.
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When there are more than two windings, all combinations must be considered, two at a time.
When there are more than two winding, all combinations must he considered, two at a time, and based on the sane kVA capacity.
Only ground one point in the differential scheme, never do multiplepoint grounding.
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Transformer Differential Relay Application
The percentage of current mismatch should always be checked to ensure that the relay taps selected have an adequate safety margin.
When necessary, current mismatch values can be reduced by changing current transformer taps or adding auxiliary current transformers.
© ABB Power Technology 1_114Q07- 42 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Sudden-Pressure Relay (SPR) With the application of a gas-pressure relay, many transformers can be protected by a simple differential relay set insensitively in the inrush current.
The sudden-pressure relay (SPR), which operates on a rate of rise of gas in the transformer, can be applied to any trans-former with a sealed air or gas chamber above the oil level.
The relay is fastened to the tank or manhole cover, above the oil level. It will not operate on static pressure or pressure changes resulting from normal operation of the transformer.
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Sudden-Pressure Relay (SPR) The SPR relay is recommended for all units of 5000 kVA or more.
The SPR relay is far more sensitive to light internal faults than the differential relay. The differential relay, however, is still required for faults in the bushing and other areas outside the tank.
The SPR relay operating time varies from 1/2 cycle to 37 cycles, depending on the size of the fault.
In the past, large-magnitude through-fault conditions on power transformers have caused rate-of-change-of-pressure relays to occasionally operate falsely. There has been reluctance on the part of some users to connect these rate-ofchange-of-pressure relays to trip, and they have therefore used them for alarming only. Schemes have been devised to restrict tripping of the rate-ofchange-of-pressure device only to levels of current below which the transformer differential relay cannot operate.
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© ABB Power Technology 1_114Q07- 45 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Overcurrent and Backup Protection
© ABB Power Technology 1_114Q07- 46 -
To allow transformer overloading when necessary, the pickup value of phase overcurrent relays must be set above this overload current. An inverse-time characteristic relay usually provides the best coordination. Settings of 200 to 300% of the transformer's self-cooled rating are common, although higher values are some-times used. Fast operation is not possible, since the transformer relays must coordinate with all other relays they overreach.
50/51 t Curva trafo
Relé tiempo inverso
Relé tiempo independ.
t0
In
n*In
i
Overcurrent and Backup Protection Overcurrent relays cannot be used for primary protection without the risk of internal faults causing extensive damage to the transformer.
Fast operation on heavy internal faults is obtained by using instantaneous trip units in the overcurrent relays.
These units may be set at 125% of the maximum through fault, which is usually a low-side three-phase fault.
The setting should be above the inrush current. Often, instantaneous trip units cannot be used because the fault currents are too small.
An overcurrent relay set to protect the main windings of an autotransformer or three-winding transformer offers almost no protection to the tertiary windings, which have a much smaller kVA.
Also, these tertiary windings may carry very heavy currents during ground faults. In such cases, tertiary overcurrent protection must be provided.
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Overcurrent and Backup Protection A through fault external to a transformer results in an overload that can cause transformer failure if the fault is not cleared promptly.
It is widely recognized that damage to transformers from through faults is the results of thermal and mechanical effects.
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The thermal effect has been well understood for years.
The mechanical effect has recently gained increased recognition as a major concern of transformer failure.
This results from the cumulative nature of some of the mechanical effects, particularly insulation compression, insulation wear, and friction-induced displacement.
The damage that occurs as a result of these cumulative effects is a function of not only the magnitude and duration of through faults, but also the total number of such faults.
Overcurrent and Backup Protection
The transformer can be isolated from the fault before damage occurs by using fuses or overcurrent relays.
50/51N
50/51G
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2-3 50/51
Distance Relaying for Backup Protection Directional distance relaying can be used for transformer backup protection when the setting or coordination of the overcurrent relays is a problem.
The directional distance relays are connected to operate when the fault current flows toward the protected transformer.
They are set to reach into, but not beyond, the transformer.
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AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
© ABB Power Technology 1_114Q07- 52 -
Transformer Tank protection
This is a low cost protection against some of the internal faults of the transformer, which consists of an overcurrent relay which measures the current flow through the ground connection of the transformer tank.
It detects hence the ground faults of the transformer and bushings trough the metallic tank.
To achieve this the transformer must be completely isolated from ground (putting some isolating material under the transformer wheels), and a toroid current transformer is needed surrounding the only ground connection cable.
64
Transformer Tank protection
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To prevent incorrect tripping (because of possible faults in the connection cables to fans, etc) it is necessary to take some measure as the indicated in fig, and to coordinate with the neutral protection.
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AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Typical protective scheme for power transformers
Figure illustrates how a primary breaker can be used for transformer protection.
The basic protection is provided by the 87T transformer differential relays.
Device 50/51, an inverse-time relay with IIT unit, provides transformer primary winding backup protection for phase faults;
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either device 50G (with a zero sequence current transformer) or 50N/51N can be used as transformer primary winding backup for ground faults.
Typical protective scheme for power transformers Transformer overload, low-voltage bus, and feeder backup protection are provided by device 51 on the transformer secondary side.
Since the low-voltage side is medium-resistance-grounded, a ground relay (51G) should be used to trip breaker 52-1 for low-side ground faults and for resistor thermal protection.
Device 151G, which trips breaker 52-11, provides feeder ground backup, whereas device 63, such as a type SPR relay, offers highly sensitive protection for light faults.
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Typical protective scheme for power transformers The current transformer ratings in this scheme should be compatible with the transformer short-time overload capability: approximately 200% of transformer selfcooled rating for wye-connected current transformers and 350% ( · 200%) for delta-connected current transformers.
The neutral current transformer rating should be 50% of the maximum resistor current rating.
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Transformers Protection
Protections
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AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
© ABB Power Technology 1_114Q07- 3 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Introduction. Possible faults in a transformer
EXTERNAL
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External Short Circuits
INTERNAL
Overloads Overvoltages
Short circuits
between turns
between windings
Ground faults
Overtemperature
Overpressure
Miss of oil
Introduction. Transformers protections
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INTERNAL
ELECTRICAL
BUCHHOLZ (SPR)
THERMOMETER
THERMOSTAT
THERMAL IMAGE
PHASE
OIL LEVEL
NEUTRAL
PRESSURE RELIEF VALVE
DIFFERENTIAL RELAY
BUCHHOLZ-TAP CHANGER
THERMAL RELAY
TANK RELAY
FUSES
SURGE ARRESTERS
OVERCURRENT RELAYS
Magnetizing inrush When a transformer is first energized, a transient magnetizing or exciting inrush current may flow. This inrush current, which appears as an internal fault to the differentially connected relays, may reach instantaneous peaks of 8 to 30 times those for full load.
The factors controlling the duration and magnitude of the magnetizing inrush are:
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Size and location of the transformer bank
Size of the power system
Resistance in the power system from the source to the transformer bank
Type of iron used in the transformer core and its saturation density
Prior history, or residual flux level, of the bank
How the bank is energized
Initial inrush When the excitation of a transformer bank is removed, the magnetizing current goes to O.
The flux, following the hysteresis loop, then falls to some residual value φ R. If the transformer were reenergized at the instant the voltage waveform corresponds to the residual magnetic density within the core, there would be a smooth continuation of the previous operation with no magnetic transient.
In practice, however, the instant when switching takes place cannot be controlled and a magnetizing transient is practically unavoidable.
© ABB Power Technology 1_114Q07- 7 -
Initial inrush
© ABB Power Technology 1_114Q07- 8 -
If the circuit is re-energized at the instant the flux would normally be at its negative maximum value (-φ max) as the residual flux would have a positive value and since magnetic flux can neither be created nor destroyed instantly, the flux wave, instead of starting at its normal value (-φ max) and rising along the dotted line, will start with the residual value (φ R) and trance the curve (φ L).
Initial inrush
Curve φ t is a displaced sinusoid, regardless of the magnetic circuit's saturation characteristics.
Theoretically, the value of φ max is + (|φ R| + 2| φ max|).
In transformers designed for some normal, economical saturation density φ s, the crest of φ t will produce super saturation in the magnetic circuit.
The result will be a very large crest value in the magnetizing current.
© ABB Power Technology 1_114Q07- 9 -
Initial inrush The residual flux φ R is the flux remaining in the core after the voltage is removed from the transformer bank.
The flux will decrease along the hysteresis loop to a value of φ R, where i = 0.
Because the flux in each of the three phases is 120° apart, one phase will have a positive φ R and the other two a negative -φ R, or viceversa.
As a result, the residual flux may either add to or subtract from the total flux, increasing or decreasing the inrush current.
© ABB Power Technology 1_114Q07- 10 -
Initial inrush
For the first few cycles, the inrush current decays rapidly. Then, however, the current subsides very slowly, sometimes taking many seconds if the resistance is low.
The time constant of the circuit (L/R) is not, in fact, a constant: L varies as a result of transformer saturation. During the first few cycles, saturation is high and L is low. As the losses damp the circuit, the saturation drops and L increases. According to a 1951 AIEE report, time constants for inrush vary from 10 cycles for small units to as much as 1 min for large units.
© ABB Power Technology 1_114Q07- 11 -
Initial inrush The resistance from the source to the bank determines the damping of the current wave.
Banks near a generator will have a longer inrush because the resistance is very low.
Likewise, large transformer units tend to have a long inrush as they represent a large L relative to the system resistance.
At remote substations, the inrush will not be nearly so severe, since the resistance in the connecting line will quickly damp the current.
© ABB Power Technology 1_114Q07- 12 -
Initial inrush When there is more than one delta winding on a transformer bank, the inrush will he influenced by the coupling between the different voltage windings. Depending on the core construction, three-phase transformer units may be subject to interphase coupling that could also affect the inrush current.
Similar wave shapes would be encountered when energizing the wye winding of a wye-delta bank, or an autotransformer. Here, the singlephase shape would be distorted as a result of the interphase coupling produced by the delta winding (or tertiary).
© ABB Power Technology 1_114Q07- 13 -
Initial inrush
Maximum inrush will not, of course, occur on every energization.
The probability of energizing at the worst condition is relatively low.
Energizing at maximum voltage will not produce an inrush with no residual.
In a three-phase bank, the inrush in each phase will vary appreciably.
The maximum inrush for a transformer bank can be calculated from the excitation curve if available, and Table shows a typical calculation of an inrush current (used phase A voltage as 0° reference).
Closing
© ABB Power Technology 1_114Q07- 14 -
φ S
angle
Peak value of inrush current wave (p.u.) Ia
Ib
Ic
Ia-Ib
Ib-Ic
Ic-Ia
1.40
0°
5.60 -3.73
-3.73
8.33
-3.73 -8.33
1.40
30°
5.10 — 1.87 -5.10
5.96
5.10
1.15
0°
6.53 -4.67
1.15
30°
6.03 — 2.80 -6.03
-9.20
-4.67 10.20 -4.67 -10.20 7.83
6.03 -11.06
Initial inrush
From these calculated values it can be seen that:
The lower the value of the saturation density flux φ S, the higher the inrush peak value.
The maximum phase-current inrush occurs at the 0° closing angle (i.e., 0 voltage).
The maximum line-current inrush occurs at ± 30° closing angles.
Because of the delta connection of transformer winding or current transformers, the maximum line-current in-rush value should be considered when applying current to the differential relay. Closing
© ABB Power Technology 1_114Q07- 15 -
φ S
angle
Peak value of inrush current wave (p.u.) Ia
Ib
Ic
Ia-Ib
Ib-Ic
Ic-Ia
1.40
0°
5.60 -3.73
-3.73
8.33
-3.73 -8.33
1.40
30°
5.10 — 1.87 -5.10
5.96
5.10
1.15
0°
6.53 -4.67
1.15
30°
6.03 — 2.80 -6.03
-9.20
-4.67 10.20 -4.67 -10.20 7.83
6.03 -11.06
Sympathetic inrush When a bank is paralleled with a second energized bank, the energized bank can experience a sympathetic inrush.
The offset inrush current of the bank being energized will find a parallel path in the energized bank.
The dc component may saturate the transformer iron. creating an apparent inrush.
The magnitude of this inrush depends on the value of the transformer impedance relative to that of the rest of the system, which forms an additional parallel circuit.
Again, the sympathetic inrush will always be less than the initial inrush.
© ABB Power Technology 1_114Q07- 16 -
Sympathetic inrush The total current at breaker C is the sum of the initial inrush of bank A and the sympathetic inrush of bank B.
Since this waveform looks like an offset fault current, it could cause misoperation if a common set of harmonic restraint differential relays were used for both banks.
Unit-type generator and transformer combinations have no initial inrush problem because the unit is brought up to full voltage gradually. Recovery and sympathetic inrush may be a problem, but as indicated above, these conditions are less severe than initial inrush.
© ABB Power Technology 1_114Q07- 17 -
© ABB Power Technology 1_114Q07- 18 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Differential relaying for transformer protection
It compares the current entering the transformer with the current leaving the element.
If they are equal there is no fault inside the zone of protection
If they are not equal it means that a fault occurs between the two ends
© ABB Power Technology 1_114Q07- 19 -
87 With internal fault Id > 0 ⇒ Trip With external fault Id = 0 ⇒ No trip
Differential relaying for transformer protection
© ABB Power Technology 1_114Q07- 20 -
Alternatively one could form an algebraic sum of the two currents entering the protected element, which could be termed as differential current (Id), and use a level detector relay to detect the presence of a fault.
In general this principle is capable of detecting very small magnitudes of fault.
Its only drawback is that it requires currents from the extremities of a zone of protection
Differential relaying for transformer protection Differential relays are the principal form of fault protection for transformers rated at 10 MVA and above.
These relays, however, cannot be as sensitive as the differential relays used for generator protection.
Transformer protection is further complicated by a variety of equipment requiring special attention: multiple-winding transformer banks, zig-zag transformers, voltage regulators, transformers in unit systems, and three-phase trans-former banks with single-phase units.
© ABB Power Technology 1_114Q07- 21 -
Differential relaying for transformer protection
Transformer differential relays are subject to several factors, not ordinarily present for generators or buses, that can cause miss-operation:
Different voltage levels, including taps, that result in different primary currents in the connecting circuits.
Possible mismatch of ratios among different current transformers.
© ABB Power Technology 1_114Q07- 22 -
For units with ratio-changing taps, mismatch can also occur on the taps. Current transformer performance is different, particularly at high currents.
30° phase-angle shift introduced by transformer wye-delta connections.
Magnetizing inrush currents, which the differential relay sees as internal faults.
Differential relaying for transformer protection
Id
© ABB Power Technology 1_114Q07- 23 -
To prevent miss-operation percentage characteristics are used, with line current restraint.
Operating zone
(I1 + I2)/2
Differential relaying for transformer protection Since the differential relays see the inrush current as an internal fault, some method of distinguishing between fault and inrush current is necessary.
Such methods include:
© ABB Power Technology 1_114Q07- 24 -
A differential relay with reduced sensitivity to the inrush wave (such units have a higher pickup for the offset wave, plus time delay to override the high initial peaks).
A harmonic restraint or a supervisory unit used in con-junction with the differential relay
Desensitization of the differential relay during bank energization.
Differential relay for transformer protection Induction relays are relatively insensitive to the high percentage of harmonics contained in magnetizing inrush current.
The relay shown consists of a percentage differential unit and an indication contactor switch.
The percentage differential unit, an induction disc type, has an electromagnet with poles above and below the disc.
There are two restraint coils on the lower left-hand pole; the operating coil is wound on the lower right-hand pole.
Both the left- and right-hand poles have transformer winding, connected in parallel to supply current to the upper-pole windings.
© ABB Power Technology 1_114Q07- 25 -
Differential relay for transformer protection The upper-pole current generates a flux in quadrature with the lowerpole resultant flux, and the two fluxes react to produce a torque on the disc.
Under normal load or in external fault, the currents in the two restraint windings flow in the same direction.
These restraining currents are equal (or effectively equal) if autobalance taps are used to compensate from mismatch in current transformer ratios - and if no significant current flows in the operating coil winding.
As a result, only contact-opening torque is produced.
© ABB Power Technology 1_114Q07- 26 -
Differential relay for transformer protection If the taps are mismatched or the main current transformers saturate unequally on severe external faults, the effective difference between the currents in the two restraining windings must flow in the operating coil.
The operating coil current required to overcome the restraining torque and close the relay contacts is a function of the restraining current. For an internal fault, the restraining currents are opposite, and restraining torque tends to cancel out.
The more sensitive operating coil, however, is energized by the sum of the two currents. As a result, a large amount of contact-closing torque is produced.
© ABB Power Technology 1_114Q07- 27 -
Differential relay for transformer protection In applying the relay, the current transformer ratio error should not exceed 10% during maximum symmetrical external fault current. The relay's 50% characteristic satisfactorily handles up to 35% of current mismatch, including the transformer tap changing on load and current transformer mismatch.
The relay's restraining windings have a continuous rating of 10 A; the operating winding has a continuous rating of 5 A. To prevent overloading the operating winding, however, no more than 5 A should be allowed in the untapped restraining winding.
© ABB Power Technology 1_114Q07- 28 -
Variable-Percentage Transformer Differential Relay
© ABB Power Technology 1_114Q07- 29 -
This type of relays have a variable-percentage characteristic:
Percentage is low on light faults, where the current transformer performance is good, and high on heavy faults, where current transformer saturation may occur.
The variable-percentage characteristic is obtained via a saturation transformer in the operating circuit.
This transformer also tends to shunt the dc component away from the operating coil.
Variable-Percentage Transformer Differential Relay The relay consists of an induction-type differential unit, a dc-indicating contactor switch, and an optional ac-indicating instantaneous trip unit.
The induction-type differential unit contains four electromagnets, operating on two discs fastened to a common shaft.
Of the electromagnets, one is the operating element and the other three are restraint elements. On the center leg of each restraint electromagnet are two primary coils and a secondary coil ; primary coils are energized from the secondaries of the current transformers connected to the bank to be protected.
© ABB Power Technology 1_114Q07- 30 -
Variable-Percentage Transformer Differential Relay A 5-A current in the restraint coil will produce restraining torque. The same 5-A current flowing in two restraint coils of the same restraint electromagnet will have either additive or subtractive restraining effect, depending on the polarity of the connection (Figure c).
This relay is well suited to protect transformer banks not subject to severe magnetizing inrush, particularly if more than two restraining circuits are needed. The relay has no built-in taps and generally requires auxiliary current transformers for current matching. The operating time of the differential unit is two to six cycles; no setting is required.
The faster IIT unit is connected to the differential circuit. It is recommended for transformer protection in applications where internal fault current can exceed twice the maximum total current flowing through the differential zone for a symmetrical external fault. The IIT unit should be set at 50% external fault current or a value higher than transformer inrush current, whichever is greater.
© ABB Power Technology 1_114Q07- 31 -
Harmonic restraint Transformer Differential Relay Since magnetizing inrush current has a high harmonic content, particularly the second harmonic, this second harmonic can be used to restrain and thus desensitize a relay during energization.
The method of harmonic restraint is not without its problems.
There must be enough restraint to avoid relay operation on inrush, without making the relay insensitive to internal faults that may also have some harmonic content.
© ABB Power Technology 1_114Q07- 32 -
Harmonic restraint Transformer Differential Relay In the differential unit, (DU) air-gap transformers feed the restraint circuits, and a non-air-gap transformer energizes the operating coil circuit.
Since the rectified restraint outputs are connected in parallel, the relay restraint is proportional to the maximum restraining current in any restraint circuit.
© ABB Power Technology 1_114Q07- 33 -
Harmonic restraint Transformer Differential Relay The percentage characteristic varies from around 20% on light faults, where current transformer performance is good, to approximately 60% on heavy fault, where current transformer saturation may occur.
This variable-percentage characteristic is obtained via the saturating transformer in the operating coil circuit.
The minimum pickup is the current that will just close the differential unit contacts, with the operating coil and one restraint coil energized.
The continuous rating of the relay is 10 to 22 A, depending on the relay tap used.
© ABB Power Technology 1_114Q07- 34 -
Harmonic restraint Transformer Differential Relay The harmonic restraint unit (HRU) has a second-harmonic blocking filter in the operating coil circuit and a second-harmonic pass filter in the restraint coil circuit.
Thus, the predominant second-harmonic characteristic of an inrush current produces ample restraint with minimum operating energy.
The circuit is designed to hold open its contacts when the secondharmonic component is higher than 15% of the fundamental.
This degree of restraint in the HRU is adequate to prevent relay operation on practically all inrushes, even if the differential unit should operate.
© ABB Power Technology 1_114Q07- 35 -
Harmonic restraint Transformer Differential Relay
For internal faults, ample operating energy is produced by the fundamental frequency and harmonic other than the second.
The second harmonic is at a minimum during a fault. Since the HRU will operate at the same pickup as the DU, the differential unit will operate sensitively on internal faults.
For external faults, the differential unit (DU) will restrain. The relay operating time is one cycle at 20 times tap value.
The instantaneous trip unit (IIT) is included to ensure high-speed operation on heavy internal faults, where current transformer saturation may delay HRU contact closing.
The IIT pickup is 10 times the relay tap value.
This setting will override the inrush peaks and maximum false differential current on external faults.
© ABB Power Technology 1_114Q07- 36 -
Transformer Differential Relay Application
The following guidelines are designed to assist in selecting and applying relays for transformer protection.
When two or more relays appear to be equally suitable, engineering experience and economics will determine the final choice.
There is no clear-cut answer to the question of which relay or protective method to apply.
As a general rule, however, the induction-disk differential relays are used at substations remote from large generating sources where inrush is not a problem and the kVA size of the bank is relatively small.
The more complex and more expensive harmonic relays are used at generating stations and for large transformer units located close to generating sources, where a severe inrush is highly likely.
© ABB Power Technology 1_114Q07- 37 -
© ABB Power Technology 1_114Q07- 38 -
Transformer Differential Relay Application
In general, the current transformers on the wye side of a wye-delta bank must be connected in delta, and the current transformers on the delta side connected in wye.
This arrangement (1) compensates for the 30° phase-angle shift introduced by the wye-delta bank and (2) blocks the zero sequence current from the differential circuit on external ground faults.
Transformer Differential Relay Application Zero sequence current will flow in the differential circuit for external ground faults on the wye side of a grounded wye-delta bank; if the current transformers were connected in wye, the relays would missoperate.
With the current transformers connected in delta, the zero sequence current circulates inside the current transformers, preventing relay miss-operation.
© ABB Power Technology 1_114Q07- 39 -
Transformer Differential Relay Application
Relays should be connected to receive “in” and “out” currents that are in phase for a balanced load condition.
Relay taps or auxiliary current transformer ratios should be as close as possible to the current ratios for a balanced maximum load condition.
© ABB Power Technology 1_114Q07- 40 -
When there are more than two windings, all combinations must be considered, two at a time.
When there are more than two winding, all combinations must he considered, two at a time, and based on the sane kVA capacity.
Only ground one point in the differential scheme, never do multiplepoint grounding.
© ABB Power Technology 1_114Q07- 41 -
Transformer Differential Relay Application
The percentage of current mismatch should always be checked to ensure that the relay taps selected have an adequate safety margin.
When necessary, current mismatch values can be reduced by changing current transformer taps or adding auxiliary current transformers.
© ABB Power Technology 1_114Q07- 42 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Sudden-Pressure Relay (SPR) With the application of a gas-pressure relay, many transformers can be protected by a simple differential relay set insensitively in the inrush current.
The sudden-pressure relay (SPR), which operates on a rate of rise of gas in the transformer, can be applied to any trans-former with a sealed air or gas chamber above the oil level.
The relay is fastened to the tank or manhole cover, above the oil level. It will not operate on static pressure or pressure changes resulting from normal operation of the transformer.
© ABB Power Technology 1_114Q07- 43 -
Sudden-Pressure Relay (SPR) The SPR relay is recommended for all units of 5000 kVA or more.
The SPR relay is far more sensitive to light internal faults than the differential relay. The differential relay, however, is still required for faults in the bushing and other areas outside the tank.
The SPR relay operating time varies from 1/2 cycle to 37 cycles, depending on the size of the fault.
In the past, large-magnitude through-fault conditions on power transformers have caused rate-of-change-of-pressure relays to occasionally operate falsely. There has been reluctance on the part of some users to connect these rate-ofchange-of-pressure relays to trip, and they have therefore used them for alarming only. Schemes have been devised to restrict tripping of the rate-ofchange-of-pressure device only to levels of current below which the transformer differential relay cannot operate.
© ABB Power Technology 1_114Q07- 44 -
© ABB Power Technology 1_114Q07- 45 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Overcurrent and Backup Protection
© ABB Power Technology 1_114Q07- 46 -
To allow transformer overloading when necessary, the pickup value of phase overcurrent relays must be set above this overload current. An inverse-time characteristic relay usually provides the best coordination. Settings of 200 to 300% of the transformer's self-cooled rating are common, although higher values are some-times used. Fast operation is not possible, since the transformer relays must coordinate with all other relays they overreach.
50/51 t Curva trafo
Relé tiempo inverso
Relé tiempo independ.
t0
In
n*In
i
Overcurrent and Backup Protection Overcurrent relays cannot be used for primary protection without the risk of internal faults causing extensive damage to the transformer.
Fast operation on heavy internal faults is obtained by using instantaneous trip units in the overcurrent relays.
These units may be set at 125% of the maximum through fault, which is usually a low-side three-phase fault.
The setting should be above the inrush current. Often, instantaneous trip units cannot be used because the fault currents are too small.
An overcurrent relay set to protect the main windings of an autotransformer or three-winding transformer offers almost no protection to the tertiary windings, which have a much smaller kVA.
Also, these tertiary windings may carry very heavy currents during ground faults. In such cases, tertiary overcurrent protection must be provided.
© ABB Power Technology 1_114Q07- 47 -
Overcurrent and Backup Protection A through fault external to a transformer results in an overload that can cause transformer failure if the fault is not cleared promptly.
It is widely recognized that damage to transformers from through faults is the results of thermal and mechanical effects.
© ABB Power Technology 1_114Q07- 48 -
The thermal effect has been well understood for years.
The mechanical effect has recently gained increased recognition as a major concern of transformer failure.
This results from the cumulative nature of some of the mechanical effects, particularly insulation compression, insulation wear, and friction-induced displacement.
The damage that occurs as a result of these cumulative effects is a function of not only the magnitude and duration of through faults, but also the total number of such faults.
Overcurrent and Backup Protection
The transformer can be isolated from the fault before damage occurs by using fuses or overcurrent relays.
50/51N
50/51G
© ABB Power Technology 1_114Q07- 49 -
2-3 50/51
Distance Relaying for Backup Protection Directional distance relaying can be used for transformer backup protection when the setting or coordination of the overcurrent relays is a problem.
The directional distance relays are connected to operate when the fault current flows toward the protected transformer.
They are set to reach into, but not beyond, the transformer.
© ABB Power Technology 1_114Q07- 50 -
© ABB Power Technology 1_114Q07- 51 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
© ABB Power Technology 1_114Q07- 52 -
Transformer Tank protection
This is a low cost protection against some of the internal faults of the transformer, which consists of an overcurrent relay which measures the current flow through the ground connection of the transformer tank.
It detects hence the ground faults of the transformer and bushings trough the metallic tank.
To achieve this the transformer must be completely isolated from ground (putting some isolating material under the transformer wheels), and a toroid current transformer is needed surrounding the only ground connection cable.
64
Transformer Tank protection
© ABB Power Technology 1_114Q07- 53 -
To prevent incorrect tripping (because of possible faults in the connection cables to fans, etc) it is necessary to take some measure as the indicated in fig, and to coordinate with the neutral protection.
© ABB Power Technology 1_114Q07- 54 -
AGENDA
PRINCIPLES
LINES PROTECTION
TRANSFORMERS PROTECTION
INTRODUCTION
SELECTING A PROTECTIVE SYSTEM
Differential protection
Sudden pressure relay
Overcurrent protection
Transformer tank protection
Typical protective scheme for power transformers
STATION BUS PROTECTION
Typical protective scheme for power transformers
Figure illustrates how a primary breaker can be used for transformer protection.
The basic protection is provided by the 87T transformer differential relays.
Device 50/51, an inverse-time relay with IIT unit, provides transformer primary winding backup protection for phase faults;
© ABB Power Technology 1_114Q07- 55 -
either device 50G (with a zero sequence current transformer) or 50N/51N can be used as transformer primary winding backup for ground faults.
Typical protective scheme for power transformers Transformer overload, low-voltage bus, and feeder backup protection are provided by device 51 on the transformer secondary side.
Since the low-voltage side is medium-resistance-grounded, a ground relay (51G) should be used to trip breaker 52-1 for low-side ground faults and for resistor thermal protection.
Device 151G, which trips breaker 52-11, provides feeder ground backup, whereas device 63, such as a type SPR relay, offers highly sensitive protection for light faults.
© ABB Power Technology 1_114Q07- 56 -
Typical protective scheme for power transformers The current transformer ratings in this scheme should be compatible with the transformer short-time overload capability: approximately 200% of transformer selfcooled rating for wye-connected current transformers and 350% ( · 200%) for delta-connected current transformers.
The neutral current transformer rating should be 50% of the maximum resistor current rating.
© ABB Power Technology 1_114Q07- 57 -
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