Basic Protection Knowledge for Transformers

　　I. Transformer Faults

1. Internal Fault

Internal faults in transformers primarily include interphase short circuits in the windings, turn-to-turn short circuits in the windings, and ground faults in windings of neutral-point-grounded systems. These faults are highly detrimental: the high-temperature arc generated by the fault current can not only burn out the winding insulation and the core but also cause the insulation materials and transformer oil to decompose, producing large amounts of gas. This may lead to localized deformation or rupture of the transformer tank and, in severe cases, even a tank explosion. Therefore, when an internal fault occurs, the transformer must be promptly disconnected from the system. This point must be firmly remembered.

2. External Fault

External faults of transformers primarily include phase-to-phase and ground short circuits occurring at the transformer bushings and on the lead conductors. When such faults occur, the transformer should also be promptly disconnected to minimize the inrush of fault current and its resulting impact on the transformer.

II. Abnormal Operating Conditions of Transformers

The main manifestations of abnormal transformer operation are:

(1) Current caused by an external short circuit.

(2) Overload.

(3) Oil level reduction caused by oil leakage from the fuel tank.

(4) Overexcitation caused by factors such as an increase in the transformer neutral-point voltage, excessive external voltage, or a reduction in frequency.

III. Protective Devices to Be Installed on Transformers

(1) Gas protection that detects internal faults in the transformer oil tank and a drop in the oil level.

(2) Longitudinal differential protection or instantaneous overcurrent protection for interphase short circuits in transformer windings and leads, as well as for single-phase-to-ground short circuits in windings and leads of systems with directly grounded neutrals.

(3) Overcurrent protection (or overcurrent protection initiated by composite voltage, or negative-sequence overcurrent protection) that detects external interphase short circuits in the transformer and serves as backup for gas protection and differential protection (or current instantaneous tripping protection).

(4) Zero-sequence current protection for external and internal ground-faults in transformers within a directly grounded neutral system.

(5) Overload protection that reflects symmetrical overloads of the transformer.

(6) Protection against transformer overexcitation.

IV. Main Protection of Transformers

(1) Gas Protection

(1) Basic Operating Principle of Gas Protection

The protection that responds to the quantity of gas and the oil flow velocity during a fault is known as gas protection. When an internal fault occurs in a transformer, the localized high temperature at the fault point causes the transformer oil temperature to rise, leading to thermal expansion and the expulsion of air from the oil, thereby generating ascending gas. If an electric arc is generated at the fault location, the transformer oil and insulating materials will decompose, releasing large amounts of gas, which then flows from the oil tank into the conservator.

The more severe the fault, the greater the amount of gas generated and the faster the oil flow toward the conservator. Since the quantity of gas and the oil-flow velocity directly reflect the nature and severity of the transformer fault, when only a small amount of gas is produced and the oil-flow velocity is low, the light-gas relay operates to issue a signal; when the fault is severe and the oil-flow velocity is high, the heavy-gas protection operates instantaneously to trip the circuit breaker.

The gas relay is the primary component of gas protection; it is installed in the middle section of the connecting pipe between the transformer tank and the conservator, ensuring that any gas generated inside the tank must pass through the gas relay before flowing into the conservator. To facilitate the smooth flow of gas to the conservator, conventional transformers require both the tank and the connecting pipe to be installed with a specific slope: the tank should have a slope of 1% to 1.5%, while the connecting pipe should have a slope of 2% to 4%.

In the new-type transformer, gas-collection branch pipes are installed at locations prone to gas accumulation, such as the bushing riser. Each branch pipe is connected to a common gas-collection header, which in turn is linked to the connecting pipe at the inlet of the gas relay. In this arrangement, as long as the branch and connecting pipes are provided with a suitable slope, the gas can flow into the conservator; consequently, no specific slope requirement is imposed on the tank itself.

Currently, open-cup baffle-type gas relays are used domestically, and their operating principle is as follows:

1) During normal operation, the open cup is completely filled with oil. Since the torque generated by the self-weight of the open cup is less than the torque produced by the balance weight, the open cup is pushed upward, causing the reed contacts to open.

2) When a minor internal fault occurs in the transformer oil tank, a small amount of gas will accumulate at the top of the relay, causing the oil level inside the relay to drop and exposing the open cup above the oil surface. Since the torque generated by the combined weight of the open cup and the oil within it exceeds the torque produced by the balance weight, the open cup pivots downward. As the magnet mounted on the open cup descends with the cup and approaches the reed contact, the contact closes, thereby issuing a light-gas operation signal.

3) When a severe fault occurs inside the oil tank, a large volume of gas is generated, accompanied by an oil flow that strikes the baffle. When the oil flow velocity reaches the relay’s setpoint, the baffle is pushed to a specific position, bringing the magnet mounted on the baffle close to the reed switch contacts and causing them to close. This contact closure then triggers the circuit breaker to trip.

(2) Setting of gas protection

1) Setting of the light-gas protection

The operating threshold for the light-gas relay is expressed in terms of the gas volume. Typically, the gas-volume setting for light-gas protection ranges from 20 to 300 cm³; this setting can be adjusted by varying the length of the lever arm of the weighted pendulum.

2) Setting of the heavy-gas protection

The operating threshold for the heavy-gas protection is expressed in terms of oil-flow velocity. The general requirements for oil flow are as follows: 0.8–1.0 m/s for self-cooled transformers, 1.0–1.2 m/s for forced-oil-circulation transformers, and 1.2–1.3 m/s for transformers with a rating of 120 MVA or higher.

(3) Advantages and Disadvantages of Gas Protection

The primary advantages of gas protection are its simple structure and its ability to comprehensively detect all types of internal faults in the transformer oil tank. In particular, when a turn-to-turn short circuit occurs and only a small number of turns are shorted, although the fault current in the short-circuited loop can be very high—potentially leading to severe localized overheating—the resulting current change in the external circuit may be minimal, to the extent that even highly sensitive differential protection may fail to operate. Therefore, gas protection is of exceptional importance in detecting such faults. Moreover, gas protection is the sole protective measure against core burnout. Due to its simplicity, sensitivity, and cost-effectiveness, gas protection is widely employed; it shall be installed on oil-immersed transformers with a rating of 800 kVA and above, as well as on indoor oil-immersed transformers with a rating of 400 kVA and above.

The main drawback of gas protection is its inability to detect faults on the transformer bushings and lead-out lines. Therefore, gas protection alone cannot serve as the sole primary protection for a transformer; it must be used in conjunction with differential protection as the transformer’s primary protection scheme.

(2) Differential Protection

1. Basic Principle of Differential Protection

Transformer differential protection is based on the circulating current principle; it can accurately distinguish between internal and external faults of the transformer and instantly clear faults within the protected zone. Current transformers TA1 and TA2 are installed on both sides of the transformer, with their secondary windings connected in series according to the circulating current principle, and the differential relay is connected to the differential current circuit.

During normal operation or external faults, current flows on both sides of the transformer. If the transformation ratios of the two current transformers are properly selected, the secondary currents I12 and I22 will be equal in magnitude and in the same direction. However, in the differential circuit, I12 and I22 flow in opposite directions; therefore, the current in the differential relay KD equals the difference between the secondary currents of the two current transformers, which is zero. Consequently, the relay will not operate during normal operation or external faults.

When a fault occurs inside the transformer, the secondary currents Id12 and Id22 from the current transformers on both sides flow in the same direction in the differential circuit, resulting in a differential current equal to the sum of the two currents, which causes the differential relay to operate.

In practice, due to factors such as transformer inrush current, wiring configurations, and errors in current transformers, unbalanced currents flow through the differential relay. The larger the unbalanced current, the higher the operating current of the relay, thereby reducing the sensitivity of differential protection. Consequently, one of the primary challenges in differential protection is to implement various measures to mitigate the effects of unbalanced currents while, under conditions that ensure selectivity, also maintaining sufficient sensitivity and rapid operation in the event of internal faults.

2. Special Issues in Differential Protection

1) Influence of Excitation Current

During normal operation, the transformer’s excitation current flows only on the supply side and is reflected in the differential circuit via the current transformers, thereby generating unbalanced current. However, under normal conditions, the excitation current is very small—typically no more than 1% of the rated current—and during external faults, the excitation current decreases as the system voltage drops, further reducing its impact. Therefore, it is generally not taken into account during practical setting.

2) Influence of Inrush Current

When a transformer is energized under no-load conditions, a large inrush current may occur, with its magnitude potentially reaching 6 to 8 times the transformer’s rated current. This inrush current is transmitted from the transformer’s supply-side current transformer to the secondary side; if it flows into the differential protection circuit, it often results in false tripping of the differential protection.

Measures to prevent differential protection maloperation caused by inrush current:

(1) Differential fast-trip protection is employed. However, since differential fast-trip protection has an inherent operating time, the operating current does not need to be set above the maximum fault current; consequently, this scheme has low sensitivity and is suitable only for small transformers.

(2) A differential relay incorporating an intermediate-speed saturable current transformer is employed. The intermediate-speed saturable current transformer can suppress the propagation of inrush current, thereby preventing false tripping of the protection. However, since transient currents during internal short circuits also contain a DC component, the protection must operate with a time delay. Moreover, because one phase of the three-phase inrush current often lacks a DC component, the saturable current transformer for that phase becomes ineffective, necessitating an increase in the protection operating threshold and consequently reducing its sensitivity. Due to its slow operation and poor sensitivity, this approach is suitable only for medium- and small-sized transformers.

(3) Employ second-harmonic restraint. In inrush current, aside from the fundamental and non-periodic components, the second-harmonic current is the largest, which is the most distinctive characteristic of inrush current, since second harmonics are rarely present under other operating conditions. This constitutes the primary measure for preventing inrush current in differential protection schemes for large power transformers.

(4) Exploit the characteristic of a distinct discontinuity angle in the excitation inrush current waveform to distinguish and avoid misidentification as excitation inrush. Currently, two approaches are employed: one is to directly detect the magnitude of the discontinuity angle to determine whether the fault is an excitation inrush or an internal short circuit; the other is to compare the rates of change of the excitation inrush current and the secondary short-circuit current.

(5) Differential protection is separately installed on the windings of each voltage side of the transformer, thereby preventing inrush current from entering the differential circuit.

3) Effects of Phase Differences in Currents on Each Side of the Transformer

The transformer is typically connected in a Y–d11 configuration; consequently, the phase angles of the currents on the two sides of the transformer are not aligned. Under normal operating conditions, the line current on the delta side leads the corresponding star-side current by 30°. If current transformers on both sides are wired in the same configuration, the secondary currents will also be offset by 30°. Therefore, it is necessary to compensate for the unbalanced current caused by this phase difference between the two sides.

4) Influence of Different Errors in Current Transformers on Each Side

Due to the differing excitation characteristics of each current transformer and the varying secondary burdens, significant unbalanced currents can arise in the differential circuit.

5) Impact of the calculated transformation ratio of a current transformer differing from the standard selected transformation ratio

Such differences in transformation ratios can give rise to unbalanced currents; when these unbalanced currents exceed 5% of the rated load current, compensation measures shall be implemented. Common compensation methods include the use of an auxiliary autotransformer or the utilization of the balancing windings of a differential relay to achieve balance.

6) Effects of Transformer Voltage Regulation

During operation, transformers must be voltage-regulated in accordance with system voltage requirements, which essentially involves changing the transformer’s turns ratio and thereby generating unbalanced currents. The magnitude of these unbalanced currents is dependent on the range of voltage regulation. Since relay settings cannot be readjusted each time the transformer tap is changed during operation, the unbalanced currents caused by transformer voltage regulation must be accounted for and coordinated to avoid tripping during protection setting.