CIRCUIT BREAKERS EQUIPPED WITH PARALLEL IMPEDANCE

Impedances in parallel with the arc may be either capacitors or resistors, or both, in various combinations. Although such impedances modify the shape of the specified inherent transient recovery voltage, the type and degree of modification in the synthetic test should be the same as in the direct test.

For example, the insertion of a resistor equal to the surge impedance of the line will reduce the line side rate-of-rise to half value. The effect is not as pronounced for a bus fault where a large number of lines are in parallel because their combined surge impedance is much lower than the resistance in parallel with the arc.

Where the shunt impedance is a resistor, particularly if the ohmic value of the resistor is low, the actual peak transient recovery voltage (TRV) in a synthetic test may not attain the value it would in a direct test because of the limited energy available from the voltage source.

Furthermore, the shunt resistor may cause a too rapid decay of the dc voltage following the TRV crest.

In some cases, to meet the TRV requirements of ANSI/IEEE C37.09-1979 [3], it may be possible

1) To adjust the parameters of the voltage circuit to provide the necessary additional energy absorbed by the shunt resistor

2) To switch over to an additional ac voltage source capable of maintaining voltage across the resistor.

An equivalent transient recovery voltage waveform across the terminals of the test circuit breaker can be produced by replacement of resistance at other appropriate places in test circuits.

LOW-SIDE BUS AND LINE-FAULT GROUND POTENTIAL RISE BASIC INFORMATION

Theoretically, LV faults can be handled in precisely the same manner as the HV faults. All differences between HV and LV side construction (transformer connections, line conductors, length, pole footing impedance, etc.) will reflect in the calculation of zero- and positive-sequence LV L-G and balanced fault currents.

As opposed to HV systems, which usually carry overhead ground wires, some LV lines, delta or wyeconnected, carry no neutrals. When neutrals are present on LV systems, LV bus fault calculations follow the same method, and LV line faults will be the same as HV line fault calculations.

When neutrals are not present on LV system, both LV bus and line-fault GPR can be calculated using the simplified method. For a LV bus fault, ZL will consist of the parallel combination of impedances-to-remote earth of all HV overhead ground wire-tower ladder networks only.

The rest of the method still applies.

For LV line faults, assuming a radial LV line, a single fault infeed can be assumed if no generation exists on the load side of the line. This assumption is correct for most cases, but it should be pointed out that, for instance, a large induction motor can become a zero-sequence current generator at the instant of the fault, due to the inertia of the rotor and the mechanical load.

If this can be neglected, the worst fault then occurs outside and near the station. The HV bus fault is modified by inserting, in series with Zs, the self-impedance of the faulted phase conductor, and inserting, in series with Za, a faulted pole footing impedance.

The methods described in this subclause should be used for hand calculation and estimation purposes only. For a more complicated network, that is, the network with a high number of ROWs, circuits, transformers, ground sources, and short lines such as could be found between generating and switching stations, hand calculations cannot be used for either exact or approximate solutions; a computer program shall be used.

In such a program, the theoretical approach should include the effect of other forms of grounding, such as rails, pipes, etc.; the effect of the length of lines; the effect of positive-sequence current phase shift in certain transformer windings; etc.

WORST FAULT LOCATION BASIC INFORMATION (GROUND POTENTIAL RISE CONSIDERATION

A complex power station may have a large number of rights-of-way (ROW) with multi circuit power lines on each ROW. These circuits may be operated at different voltage levels. A fault current study for an L-G fault at each transformer voltage level should be produced. Each fault current study should be examined as follows:

a) If the vectorial sum of all zero-sequence fault current contributions to the transformer bus fault from all transmission and distribution lines entering the station under study is greater than the sum of all current contributions from all grounded sources at that station (including generators, grounded transformers, shunt capacitors, etc.), then at the voltage level for which the fault current study is presently being examined, the bus fault will usually produce a worse GPR than the line fault.

b) If the reverse is true, that is, the vectorial sum of the line contributions is smaller than the local ground source current sum, the line fault will produce a greater GPR.

This is because the local ground current will return partially, in the case of the line fault, through the station ground impedance, adding to the GPR caused previously by the line current contribution.

In the bus fault case, the current merely circulates through the faulted transformer winding, the station ground bus, and the fault impedance.

Having determined the worst-fault location (bus versus out on the-line), to select that fault current study with the highest fault current is not appropriate.

Variances between grounding networks of lines with the various voltage levels may, for instance, cause the study showing lower zero-sequence fault currents to result in a GPR greater than that caused by the higher currents. Instead, all faults should be investigated for fault locations as determined above.

WORST FAULT TYPE BASIC INFORMATION (GROUND POTENTIAL RISE CONSIDERATION

Basically, three types of faults should be investigated:

a) Line-to-ground faults (L-G). These are predominant in terms of frequency of occurrence.  Zero sequence and positive-sequence currents will be required.

In practice, GPR is a function of zero sequence currents only, but positive-sequence currents are required to determine magnitudes of the individual zero-sequence currents ßowing in each phase of the faulted circuit.

b) Double line-to-ground faults (2L-G). These are statistically less frequent than L-G faults but could produce zero-sequence currents far exceeding those caused by L-G faults.

Theoretically, this is because of different connections of sequence networks during these faults. For an L-G fault, the positive-sequence, negative-sequence, and zero-sequence networks are connected in series and driven by the prefault voltage source; whereas, for a 2L-G fault, positive-sequence impedance is connected in series with the parallel combination of zero-sequence and negative-sequence impedances, with less overall impedance in the path of the fault current.

[For instance, many high MVA autotransformers may be added to power stations. These could have their primary-to-secondary, or primary-to-tertiary, zero-sequence reactance ratios so high that their primary current is small compared with the tertiary (ground) current.

In addition to this, if more such transformers are added to the station, the resulting tertiary currents will be very large due to further paralleling of reactances.]

c) Three-phase faults. These are statistically less frequent than L-G and 2L-G faults. Three-phase faults produce positive sequence currents, and detailed calculations are required to determine magnitudes of the individual zero-sequence currents ßowing in each phase of the faulted circuit.

If X1 and X0 are positive-sequence and zero-sequence reactances, respectively, of the system impedance at the point of fault and X1 is less than X0, the 2L-G fault will result in higher zero sequence fault currents, often twice as high as the L-G fault currents calculated at the same fault location.

The GPR produced by 2LG faults is not normally considered, due to its low probability. For an overview of the frequency of occurrence of different types of faults as a function of voltage levels on which they occur and other parameters.

POWER CIRCUIT BREAKER INTERRUPTION OF CAPACITIVE CURRENTS AND CLOSING ON FAULTS BASIC INFORMATION AND TUTORIALS

Capacitive currents occur during line drooping as well as during disconnecting unloaded cables or capacitor banks. Although, switching of capacitor banks is regarded as a special application, disconnecting of charged lines is a frequent switching operation.

Current chopping may occur at a low instantaneous current value during interruption of capacitive currents, but this does not lead to overvoltages. After interruption of current, the voltage at the line capacitance (L) remains at the peak value of the power frequency voltage, whereas the voltage on the source side (S) oscillates about the driving voltage.

The difference between the two voltages appears across the circuit breaker with an amplitude of more than double the rated voltage. If the circuit breaker cannot withstand this higher voltage restriking may occur.

Restriking is similar to closing transmission lines with trapped charge. After restiking, a transient current flows through the circuit breaker, which is of higher frequency than that of the system and which can again be interrupted during the reignition process.

After reextinction, the line is charged to the potential of the peak value of the equalizing process, whereas the circuit-breaker terminal on the source side (S) recovers to the system voltage. A very high differential voltage appears across the breaker, which may lead to renewed restriking and even switching failures.

Restrike-free interruption of capacitive currents is thus of the utmost importance. Basically, the same phenomenon occurs during disconnection of capacitor banks. To determine the voltage stresses of the circuit breaker, however, the grounding condition of the supply system and capacitor bank and the arrangement of the bank have to be taken into account.

Closing on a Fault.

This directs the stress onto the circuit breaker contact system, particularly as regards the electrodynamic and thermal forces. The current and voltage stress is different during closing on (a) symmetrical or (b) asymmetric short-circuit current.

The deciding factor is the moment of contact touch relative to the phase angle of system voltage. In case contact touch and consequently ignition of the arc occurs at the voltage maximum, the short circuit current will appear symmetrical.

The other extreme case takes place with the moment of closing at voltage zero. Here the asymmetrical short-circuit current contains the maximum dc component. A contact system designed for fast closing operation will be subjected to a shorter arcing time and consequently to reduced contact burning when closing on symmetrical currents. Fast operation is therefore not only important for opening but also for circuit breaker closing.

TERMINAL FAULT, SHORT LINE FAULT AND OUT OF PHASE SWITCHING INTERRUPTING CONDITIONS OF POWER CIRCUIT BREAKERS BASIC INFORMATION AND TUTORIALS

Terminal Fault.

After interruption of short-circuit current, the recovery voltage oscillates toward the service frequency driving voltage via an initial peak. The natural frequency is determined by the inductance and capacitance of the driving system.

The dc component of the short-circuit current depends on the time constants of the network components like generators, transformers, cables, and high-voltage lines and their reactances of the zero-sequence and the positive sequence networks.

The recovery voltage will accordingly vary depending on the location of the circuit breaker within the network.

Short-Line Fault.

In the case of a short-line fault, a section of line lies between the breaker and the fault location. After the short-circuit current has been interrupted, the oscillation at the line side (L) of the breaker assumes a superimposed “saw-tooth” shape.

The rate of rise of this line oscillation is directly proportional to the effective surge impedance and the time rate of change of current\ (di/dt) at current zero. The component on the supply side (S) basically exhibits the same waveform as a terminal fault.

The circuit breaker is stressed by the difference between these two voltages. Because of the high frequency of the line oscillation, the transient recovery voltage has a very steep initial rate of rise.

Since the initial rate of rise increases with increasing rate of current change, the limiting interrupting capability of many breaker designs is determined by the short-line fault.

Out-of-Phase Switching.

Two network systems with driving voltages E1 and E2 are connected via a high-voltage transmission line. Since the circuit is closed via the closed circuit breaker, the resulting driving voltage is equal to the sum of the two system voltages.

Driving voltage E2 may, for example, exceed voltage E1 by the voltage drop across the transmission line. After opening the breaker, the transient recovery voltages of the disconnected networks oscillate independently.

The circuit breaker is stressed by the difference of these two voltages. In the case of disconnection of long lines, the recovery voltage across the breaker could be increased because of the Ferranti effect, where the voltage of the receiving end can be up to 15% higher than the sending end if the line is lightly loaded.

SYNCHRONOUS GENERATORS SHORT-CIRCUIT RATIO (SCR)

The short-circuit ratio (SCR) of a generator is the inverse ratio of saturated direct axis reactance in per unit (P.U.):

SCR = 1/ Xd (sat)

The SCR has a direct impact on the static stability and on the leading (absorbed) reactive power capability of the SG. A larger SCR means a smaller xd(sat) and, almost inevitably, a larger airgap.

In turn, this requires more ampere-turns (magnetomotive force [mmf]) in the field winding to produce the same apparent power.

As the permissible temperature rise is limited by the SG insulation class (class B, in general, ΔT = 130°), more excitation mmf means a larger rotor volume and, thus, a larger SG.

Also, the SCR has an impact on SG efficiency. An increase of SCR from 0.4 to 0.5 tends to produce a 0.02 to 0.04% reduction in efficiency, while it increases the machine volume by 5 to 10%.

The impact of SCR on SG static stability may be illustrated by the expression of electromagnetic torque te P.U. in a lossless SG connected to a infinite power bus:

te = SCR x E0 x Vg x 1sin δ

The larger the SCR, the larger the torque for given no-load voltage (E0), terminal voltage V1, and power angle δ (between E0 and ΔV1 per phase). If the terminal voltage decreases, a larger SCR would lead to a smaller power angle δ increase for given torque (active power) and given field current.

If the transmission line reactance — including the generator step-up transformer — is xe, and V1 is now replaced by the infinite grid voltage Vg behind xe, the generator torque te′ is as follows:

te' = SCR x E0 x Vg x 1sin δ'/(1 + Xe/Xd)

The power angle δ′ is the angle between E0 of the generator and Vg of the infinite power grid. The impact of improvement of a larger SCR on maximum output is diminished as xe/xd increases.

Increasing SCR from 0.4 to 0.5 produces the same maximum output if the transmission line reactance ratio xe/xd increases from 0.17 to 0.345 at a leading power factor of 0.95 and 85% rated megawatt (MW) output.

Historically, the trend has been toward lower SCRs, from 0.8 to 1.0, 70 years ago, to 0.58 to 0.65 in the 1960s, and to 0.5 to 0.4 today. Modern — fast response — excitation systems compensate for the apparent loss of static stability grounds. The lower SCRs mean lower generator volumes, losses, and costs.