UNIQUE CHARACTERISTICS OF GROUND FAULTS

UNIQUE CHARACTERISTICS OF GROUND FAULTS

By Engr. Aneel Kumar   June 02, 2016   No comments:

It is assumed here that the transmission has multiple grounding points at wye connected transformer neutrals, located throughout the system. When this condition is satisfied, any arcing fault between a phase conductor and the ground will be supplied by zero-sequence currents originating in the neutral connection of the high-voltage transformer banks. We often refer to these neutral connections as the "sources" of ground current, since very little current would flow to the ground fault if there were no grounded neutrals to provide a complete circuit for the fault current. When there are multiple ground sources, the current flowing to the ground may be very large.

Any current flowing to the ground contains zero-sequence components and, under grounded conditions, a zero-sequence voltage will be measured at any nearby relay installation. Negative-sequence currents and voltages will also be observed, and these are sometimes used by the protective system. However, most ground relay systems depend on detecting zero-sequence currents, for this is a sure sign of an abnormal system condition. No significant zero-sequence currents flow during normal operation of the power system, with those that do appear being the result of the unbalance in the operating condition of the three phases. These unbalanced currents are very small compared to fault currents, so it is a good approximation to think of the normal power system as being free of zero-sequence voltages or currents. This is the first principle of ground fault relaying, namely, that a unique type of current exists during a ground fault and the relay needs only to be designed to detect the zero-sequence current in order to make positive identification of a ground fault.

Zero-sequence currents are confronted by zero-sequence impedances that depend on the structure of the power system. This structure does not change based on the loading of the power system, and changes only when switching occurs. Therefore, except for occasional switching, the zero-sequence impedances are almost constants. The zero-sequence impedance is affected by the generation and will change slightly as generators are added or removed. However, the line impedances are more important than the generator impedances for most fault currents. This situation is quite different from positive-sequence currents, which fluctuate with the loadings of the lines as they respond to system load and generation changes. This is the second principle of ground relaying, viz., that the impedance seen by the zero-sequence fault currents are nearly constant from maximum load to minimum load conditions.

Another characteristic of the zero-sequence network is the magnitude of the impedance of the transmission lines. Zero-sequence line impedance is two to six times greater than positive-sequence line impedance. This means that, over the length of a transmission line, there will be a large difference in impedance seen by the fault current as the fault is moved from one end of the line to the other. It should be noted that this may not be true if the line is mutually coupled with another nearby transmission line. There are two important points to observe here. First, there is a large difference in the fault current as the fault is moved from the relay location to the far end of the line. Second, the source impedances are usually small compared to the line impedance, hence the far-end fault currents are about the same at both ends.

Another requirement of ground faults is the need to determine the direction of the fault current. For a radial line, there is no problem in determining the direction of current flow, but this is not true in other parts of a power system. For this reason, many ground relays are directional relays. In order to get a sense of zero-sequence current direction, it is necessary to have a reference current or voltage against which the actual fault current can be compared.

This type of comparison is called polarization. By means of polarization, it is possible for the ground relay to determine if the fault is ahead or behind the relay location, giving the relay a measurement of the current direction as well as its magnitude.

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GROUND FAULT PROTECTION AND ITS IMPORTANCE

GROUND FAULT PROTECTION AND ITS IMPORTANCE

By Engr. Aneel Kumar   June 01, 2016   No comments:

An important aspect of transmission line protection is related to the fast detection and clearing of ground faults on transmission systems that have grounded neutrals. In the protection of transmission lines, ground faults are given special treatment. Ground faults are detected using different relays than those used for phase faults, although it is possible that phase relays may detect and properly clear ground faults. Ground relays, however, take advantage of unique features of the power system that make it possible to detect grounded conditions very quickly.

IMPORTANCE OF GROUND FAULT PROTECTION:

Most high-voltage and extra-high voltage transmission lines are grounded neutral transmission systems, either solidly grounded or grounded through a resistance or a reactance. It has been estimated that, on these high-voltage systems, over 90% of all transmission line faults are ground faults. It has been observed by one protection engineer that, on 500 kV transmission lines, one-line-to-ground faults "predominate to the extent that on many well designed circuits, no other type of fault has ever occurred, even after years of service". It may be noted that some faults involve phase-to-phase as well as ground short circuits, but the ground relays pick up these faults before the phase relays. On the system referenced, the ground relays are applied on the basis of two principles.

1. Install only those relays that are required to properly protect the line.
2. Provide redundancy in the form of two completely independent relay schemes at each line terminal.

The first principle refers to the dependability of the installed systems to properly perform correct detection and tripping to clear the fault, without unnecessary trips, and with all necessary speed. This means that the relays are not set to operate at the fastest possible speed, but as fast as is reasonably possible following detection and analysis of the observed system condition. The redundancy principle guards against the unobserved failure of one relay system by having a second system installed that is fully capable of performing the ground relaying function. These principles, or similar ones, are followed by many utilities.

Because of the high incidence of ground faults, it is important that transmission protection include a well-designed ground relaying system that embraces the two basic principles stated above.

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TYPES OF GROUND RELAYS

TYPES OF GROUND RELAYS

By Engr. Aneel Kumar   June 01, 2016   No comments:

There are three basic types of relays that are used for ground relaying; overcurrent relays, distance relays, and pilot relays. Ground relays are almost always completely independent of phase relays, even though any fault current, including ground fault current, will flow through one or more of the phase relays. The ground relays, however, can be provided with much greater sensitivity to the zero-sequence currents by using higher tap settings. This means that the ground relays will pick up much faster than phase relays for a fault involving the ground.

1) OVERCURRENT RELAYS:

Directional or non-directional overcurrent relays are widely used at most voltage levels because of their low cost and reliable service record. Many relay engineers prefer an overcurrent relay with an inverse or very inverse time-current characteristic. This means that the pickup will be very fast for close-in faults and delayed for faults at the end of the transmission line.

This delay makes coordination with adjacent lines relatively easy because of the rapid change in fault current for the more remote faults. The ground relay must coordinate with bus differential relays, as well as ground relays on any outgoing lines at the remote end.

In systems with multiple grounds, which is usually the case, the ground overcurrent relays will need to be directional relays. The ground relays in a looped system must be coordinated all around the loop in both directions, in exactly the same way that phase relays are coordinated. This is a cut and try process.

Instantaneous overcurrent relays are usually applied to supplement the ground fault protection when overcurrent relays are used. Instantaneous ground relays can reduce the fault clearing time to about one cycle in many cases, for faults on a large fraction of the line length.

2) DISTANCE RELAYS:

Directional ground distance relays are responsive to impedance or reactance between the relay and the fault. These relays, although more expensive than overcurrent relays, can provide almost instantaneous protection for most of the line length. For many years, distance relays were not widely used for ground protection due to the inherent problem of measuring zero-sequence impedance or reactance in the presence of a fault. Ground faults usually involve fault resistance of widely varying magnitude. This may prevent the relay from responding to a ground fault. Some relay engineers back up ground distance relays with overcurrent relays to make sure that all faults are recognized in a timely way. Many of the problems associated with ground distance relays have been solved by newer devices, making this a good alternative where overcurrent or directional overcurrent coordination is a problem.

3) PILOT RELAYS:

Pilot relaying is used for ground protection in special cases where the other methods are inadequate for reasons of security or dependability. Pilot relays use either directional comparison or phase comparison to determine if the fault is within the protected zone. This might be a good solution for a three-terminal line, for example, where other types of relays are difficult to coordinate. Pilot relaying is sometimes selected on the more important lines because of the high speed and security offered by the pilot schemes. Some engineers argue that pilot relays are not required for ground fault protection, but should be used where stability or other considerations make it necessary to have both terminals of the transmission line tripped at the same time.

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TYPES OF SUBSYNCHRONOUS RESONANCE INTERACTIONS

TYPES OF SUBSYNCHRONOUS RESONANCE INTERACTIONS

By Engr. Aneel Kumar   June 01, 2016   No comments:

There are several ways in which the system and the generator may interact with subsynchronous effects. A few of these interactions are basic in concept and have been given special names which are discussed here.

•Induction generator effect

• Torsional interaction

• Transient torque

1) INDUCTION GENERATOR EFFECT:

Induction generator effect (IGE) is caused by self-excitation of the electrical network. The resistance of the generator to subsynchronous current, viewed looking into the generator at the armature terminals, is a negative resistance over much of the subsynchronous frequency range. This is typical of any voltage source in any electric network. The network also presents-a resistance to these same currents that is a positive resistance. However, if the negative resistance of the generator is greater in magnitude than the positive resistance of the network at one of the network natural frequencies, growing subsynchronous currents can be expected. This is the condition known as the induction generator effect. Should this condition occur, the generator may experience subsynchronous torques at or near a natural shaft frequency, which may cause large and sustained oscillations that could be damaging to the shaft.

2) TORSIONAL INTERACTION:

Torsional interaction occurs when a generator is connected to a series compensated network, which has one or more natural frequencies that are synchronous frequency complements of one or more of the torsional natural modes of the turbine-generator shaft. When this happens, generator rotor oscillations will build up and this motion will induce armature voltage components at both subsynchronous and super-synchronous frequencies. Moreover, the induced subsynchronous frequency voltage is phased to sustain the subsynchronous torque. If this torque equals or exceeds the inherent mechanical damping of the rotating system, the system will become self-excited. This phenomenon is called torsional interaction (TI).

The network may be capable of many different subsynchronous natural frequencies, depending on the number of lines with series compensation and the degree of compensation installed on each line. Moreover, switching of the network lines can cause these natural frequencies, as viewed from the generator, to change. The engineer must evaluate the network frequencies under all possible switching conditions to determine all possible conditions that may be threatening to the generators. Another condition that can greatly increase the number of discrete network subsynchronous frequencies is the outage of series capacitor segments. The series compensation in high-voltage systems usually consists of several capacitor segments that are connected in series, with each series segment consisting of parallel capacitors as required to carry the line current. This permits individual segments to be removed from service for maintenance and still permit nearly normal loading of the lines. However, individual segments can fail, thereby changing the network natural frequencies and greatly increasing the number of possible frequencies that can be observed from an individual generator. This increases the work required to document and analyze the network frequencies as seen by each generating station.

Another possible source of subsynchronous currents is the presence in the network of HVDC converter stations. The controls of these converters are very fast in their control of the power, but the controls can have other modes of oscillation that may be close to a natural mode of oscillation of a nearby generator. Systems that include HVDC converters also must be carefully checked to see if these controls might induce subsynchronous currents in the generator stators, leading to torsional interaction.

3) TRANSIENT TORQUES:
Transient torques are torques that result from large system disturbances, such as faults. System disturbances cause sudden changes in the network, resulting in sudden changes in currents with components that oscillate at the natural frequencies of the network. In a transmission system without series capacitors, these transients are always de transients, which decay to zero with a time constant that depends on the ratio of inductance to resistance. For networks that contain series capacitors, the transient currents will contain one or more oscillatory frequencies that depend on the network capacitance as well as the inductance and resistance. In a simple radial R-L-C system, there will be only one such natural frequency. If any of these frequencies coincide with the complement of one of the natural modes of shaft oscillation, there can be peak torques that are quite large and these torques are directly proportional to the magnitude of the oscillating current. Currents due to short circuits, therefore, can produce very large shaft torques both when the fault is applied and also when it is cleared. In a real power system there may be many different subsynchronous frequencies involved and the analysis is quite complex.

Of the three different types of interactions described above, the first two, IGE and TI, may be considered as small disturbance conditions, at least initially. The third type, transient torque, is definitely not a small disturbance and nonlinearities of the system also enter into the analysis. From the viewpoint of analysis, it is important to note that the induction generator and torsional interaction effects may be analyzed using linear methods. Eigenvalue analysis is appropriate for the study of these problems and the results of eigenvalue studies give both the frequencies of oscillation and also the damping of each oscillatory mode. The other method used for linear analysis is called the frequency scan method, where the network seen by the generator is also modeled as a function of frequency and the frequency is varied over a wide range of subsynchronous values. This requires that the generator be represented as a tabulation of generator impedance as a function of subsynchronous frequency, which must be provided by the generator manufacturer. This is considered the best model of the generator performance at subsynchronous frequencies, and is often the preferred method of analysis, with eigenvalue analysis used as a complementary check on the frequency scan results.

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