Compensating CT Ratio Mismatch | Differential Protection

 Compensating CT ratio mismatch is a very important step in configuring a differential protection. This may be achieved by specifically selecting the CT ratios or in modern relaying, configured through the relay software.

The concept of zero sequence currents was discussed including how they affect the performance of transformer differential protection and how to compensate for them. Zero sequence compensation is a form of phase compensation. While zero sequence compensation is very important in differential protection, compensating CT ratio mismatch through magnitude compensation or commonly known as tap compensation is equally important.

When applying any kind of protection scheme, power system parameters are measured using instrument transformers. Current transformers (CTs) are used in transformer differential protection. These CTs are selected based on the amount of current they are expected to measure up to certain value of current, during fault conditions, in which they can measure without loss of accuracy. In their application to transformer differential protection, CTs are usually selected based on the full load rating of circuit. Therefore, it is normal that CTs on both sides of the power transformer have different CT ratio. By having different CT ratio, measured values in the relay will not be equal and will yield an IOP not equal to zero.

Compensating CT ratio mismatch using TAP compensation is based on the concept of selecting CT ratio based on the power transformer turns ratio. Let IP and IS be the transformer primary current values at the transformer high and low side, respectively, I1 and I2 be the secondary currents measured by the relay, CTR1 and CTR2 the current transformer ratio, and N1 and N2, the transformer winding turns. To make I1 equal to I2 in all normal conditions, the ratio of CTR1 to CTR2 should be equal to the transformer turns ratio N2/N1. For delta connected CTs at the secondary side, CT2, since

In most cases, selecting standard CTRs based on the required conditions is very difficult if not impossible without making any compromise.

Compensating CT ratio mismatch for transformer differential protection using numerical relays is quite straightforward. Relay measured currents are expressed to their primary values by multiplying CTR1 and CTR2 to I1 and I2, respectively. The primary values are then expressed to their per unit values based on the power transformer MVA and kV ratings. This process allows the current values used in the calculation of IOP to be equal in magnitude during normal conditions.

To consider the CT connection in tap compensation, a constant is included in the tap equation as shown below,

Compensating CT ratio mismatch works with phase compensation to ensure the reliability of transformer differential protection.

Figure 2. Tap and Phase Compensation

While setting the relay is a straightforward process, it should be kept in mind that understanding the basic concepts are very vital in the practice of power system protection.

Vector Group of Transformer

The naming convention popularly known as Vector Group of Transformer was established by the International Electrotechnical Commission (IEC) through IEC 60076-1. This was done in order to create a notation for three-phase transformer winding configuration.

Vector Group of Transformer: Common Symbol Designation

Y or y – star winding

D or d – delta winding

N or n – neutral

0 to 12 – phase displacement in terms of clock position in multiples of 30°

Distance Relay Characteristics

Some numerical relays measure the absolute fault impedance and then determine whether operation is required according to impedance boundaries defined on the R/X diagram.

Traditional distance relays and numerical relays that emulate the impedance elements of traditional relays do not measure absolute impedance. They compare the measured fault voltage with a replica voltage derived from the fault current and the zone impedance setting to determine whether the fault is within zone or out-of-zone. Distance relay impedance comparators or algorithms which emulate traditional comparators are classified according to their polar characteristics, the number of signal inputs they have, and the method by which signal comparisons are made.

The common types compare either the relative amplitude or phase of two input quantities to obtain operating characteristics that are either straight lines or circles when plotted on an R/X diagram. At each stage of distance relay design evolution, the development of impedance operating characteristic shapes and sophistication has been governed by the technology available and the acceptable cost.

Since many traditional relays are still in service and since some numerical relays emulate the techniques of the traditional relays, a brief review of impedance comparators is justified.

Principle of Distance Relay

Since the impedance of a transmission line is proportional to its length, for distance measurement it is appropriate to use a relay capable of measuring the impedance of a line up to a predetermined point (the reach point).

Such a relay is described as a distance relay and is designed to operate only for faults occurring between the relay location and the selected reach point, thus giving discrimination for faults that may occur in different line sections.

The basic principle of distance protection involves the division of the voltage at the relaying point by the measured current. The apparent impedance so calculated is compared with the reach point impedance. If the measured impedance is less than the reach point impedance, it is assumed that a fault exists on the line between the relay and the reach point.

The reach point of a relay is the point along the line impedance locus that is intersected by the boundary characteristic of the relay.

Since this is dependent on the ratio of voltage and current and the phase angle between them, it may be plotted on an R/X diagram. The loci of power system impedances as seen by the relay during faults, power swings and load variations may be plotted on the same diagram and in this manner the performance of the relay in the presence of system faults and disturbances may be studied.

Distance Protection

Distance relays are one of the most important protection elements in a transmission line.

Distance relays characteristics may be Mho, Quadrilateral, Offset Mho, etc. In the case of the  quadrilateral characteristic or long reaching mho characteristics, additional care may be  required to remain secure during heavy load.

These  relays may sometimes be set based in percentages of the line impedances, for example a  typical setting for zone 1 is 80% of the impedance of the line in order to not reach the remote  end, the zone 2 can be set at 120% of the impedance of the line in order to dependably  overreach the line, Zone 3 sometimes are disabled or set to cover an adjacent line.

In the case of parallel lines, the mutual coupling of these lines can cause distance relays to  under reach and over reach. For this reason the relay setting must consider this effect, some  relays have algorithms to compensate, but it is necessary to use the current of the parallel line  which adds complexity to the installation.

In some countries there criteria that a distance protection can not reach fault in other voltage  levels, because fault clearing times in sub transmission levels may be slower than fault clearing  times at the transmission level.

The problem of combining fast fault clearance with selective tripping of plant is a key aim for the protection of power systems.

To meet these requirements, high-speed protection systems for transmission and primary distribution circuits that are suitable for use with the automatic recloser of circuit breakers are under continuous development and are very widely applied.