The Most Important Tests For Medium Voltage Metal-Enclosed Switchgear (You SHOULD Perform)

Electrical Switchgear Testing

The design of the insulation system for metal-enclosed switchgear is based upon life expectancy of about 30 years. However, environmental conditions such as dirt, moisture, and corrosive atmosphere can shorten the design life.

Moisture combined with dirt is the greatest deteriorating factor for insulation systems because of leakage and tracking, which will result in eventual failure. Therefore, it is important to maintain the switchgear insulation and to chart the condition of the primary insulation system by routine testing.

Also when testing circuit breakers, it is important to check the condition of the circuit breaker contacts and circuit breaker operating mechanism to assure that the circuit breaker is opening and closing as designed.

These tests are listed and discussed as follows:

1. Insulation resistance test
2. DC or AC hi-pot test
3. Power factor or dielectric loss test
4. Circuit breaker contact resistance test
5. Circuit breaker time–travel analysis test

1. Insulation Resistance Measurement Test

The insulation resistance measurement test may be conducted on all types of electrical switchgear using the insulation resistance megohmmeter commonly known as the MEGGER.

The Megger S1-5010 is shown in Figure 1 that may be used to perform this test.

The insulation resistance test consists of applying voltage (600–10,000 V DC) to the apparatus to determine the megohm value of resistance. This test does not indicate the quality of primary insulation.

Several factors should be remembered when performing this test:

The first is that this test can indicate low values of insulation resistance because of many parallel paths.

The connection diagram for making this test on a power circuit breaker is shown in Figure 2.

When performing insulation testing, it is recommended that auxiliary equipment, such as potential transformers and lightning arresters, be removed from the stationary switchgear.

Insulation resistance tests are made with the circuit breaker in open and closed position, whereas the insulation test for the switchgear bus is made with one phase to ground at a time, with the other two phases grounded.

The procedure for this test is as follows:

1. Circuit breaker open: Connect HV lead to pole 1. Ground all other poles. Repeat for poles 2 through 6, in turn, with other poles grounded.
2. Circuit breaker closed: Connect HV lead to pole 1 or 2, as convenient, with either pole of phase 2 and 3 grounded. Repeat for phases 2 and 3 with other phases grounded.
3. Stationary gear (buses): Connect HV lead to phase 1 with phases 2 and 3 grounded. Repeat the same for phases 2 and 3 with other phases grounded. Also, perform IR tests between phase 1 and 2 with phase 3 grounded, phase 2 and phase 3 with phase 1 grounded, and phase 3 and 1 with phase 2 grounded.

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2. High-Potential (Hi-pot) Test

DC Hi-Pot Test

The DC hi-pot test is normally not made for AC electrical switchgear and therefore may be considered only when AC hi-pot cannot be performed.

The hi-pot testing of switchgear involves testing of the circuit breakers and switchgear buses separately. This is a major test and determines the condition of the insulation of the switchgear assembly.

The corona and tracking are more pronounced in older equipment, and it is therefore recommended that DC hi-pot testing be avoided on such equipment. The test procedures for DC hi-pot testing are similar to those of AC hi-pot testing.

If DC hi-pot testing is to be performed, the DC voltage test values shown in Table 1 are recommended for various voltage-class equipment.

Table 1 – DC Hi-Pot Maintenance Test Values

The hi-pot test should be conducted under conditions similar to those of commercial testing.

The switchgear should be wiped, cleaned, and restored to good condition before the hi-pot test is conducted. Temperature and humidity readings should be recorded and the test reading corrected when conducting DC tests.

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AC Hi-Pot Test

This test should be conducted separately for circuit breakers and switchgear buses (stationary gear). It should be made only after the DC insulation resistance measurement test has been passed satisfactorily and all cleanup has been finished.

The AC test will stress the switchgear insulation similarly to the stresses found during operating conditions. The maintenance test voltages should be 75% of final factory test voltage.

These values are shown in Table 2.

Table 2 – Hi-Pot Test Values

Hi-pot tests are made with the circuit breaker in both open and closed positions. The hi-pot test should be the last test conducted after all repairs have been made, cleanup is finished, and the insulation resistance test has been successfully passed.

Procedures for the hi-pot test of the circuit breaker are as follows:

1. The test connection for the hi-pot test is as shown in Figure 3.
2. Circuit breaker in open position:
   Connect HV lead to pole 6. Ground all other poles. Repeat for poles 1 through 5, in turn, with all other poles grounded. Apply the desired high voltage in each case in
   accordance with Table 2.
3. Circuit breaker in closed position:
   Connect HV lead to pole 1 or 2 or phase 1 as convenient with either pole of phases 2 and 3 grounded. Repeat for test for phases 2 and 3 with other phases grounded.
4. Stationary gear (buses):
   Connect HV lead to phase 1 as convenient with phases 2 and 3 grounded. Apply the recommended voltage. Repeat the test for phases 2 and 3 with other phases grounded.

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3. Power Factor Testing

The power factor testing of an insulation system is useful in finding signs of insulation deterioration. The absolute values of power factor measured have little significance.

However, comparative analysis of values from year to year may very well show insulation deterioration. Therefore, when a power factor test is made, it should be made under the same conditions of temperature and humidity. If differences exist in the temperature and humidity from year to year, this should be taken into consideration when evaluating the test data.

A significant change, especially an increase in watts loss or percent of power factor indicates deterioration, which should be monitored.

As a general rule, a power factor below 1% indicates good insulation. Any value above 1% warrants investigation.

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4. Circuit Breaker Contact Resistance Measurement Test

Stationary and moving contacts are built from alloys that are formulated to endure the stresses of electrical arcing.

However, if contacts are not maintained on a regular basis, their electrical resistance due to repeated arcing builds up, resulting in a significant decrease in the contact’s ability to carry current. Excessive corrosion of contacts is detrimental to the breaker performance.

One way to check contacts is to apply DC and measure the contact resistance or voltage drop across the closed contacts.

The resistance value is usually measured in microohms (µΩ). The average resistance value for 15 kV class circuit breakers is approximately between 200 and 250µΩ. Several companies make good, reliable microohmmeters to perform this testing.

One such instrument is the Megger DLRO 200. It can generate test currents from 10 to 200 A and can measure resistances ranging from 0.1µΩ to 1 Ω.

The Megger DLRO 200 is shown in Figure 4.

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5. Circuit Breaker Time-Travel Analysis

This test is usually performed on MV and HV circuit breakers, usually 34 kV and above, to detect problems in the breaker operating mechanism.

This test can be conducted with a mechanical or electronic time–travel analyzer.

There are eight tests that are usually conducted on the breaker with the circuit breaker analyzer. These tests are:

1. Closing time and opening time,
2. Contact bounce,
3. Opening and closing synchronization,
4. Closing and opening speed (velocity and displacement),
5. Trip operation,
6. Trip-free operation,
7. Close operation, and
8. Trip-close operation.

1. Closing and opening time

In the example below, the closing time of the contacts is shown to be 31.4 ms (phase A), 30.2 ms (phase B), and 31.8 ms (phase C).

Also closing times of a breaker can be viewed in a graph form as displayed in Figure 5.

2. Contact bounce

If we expand the x-axis in Figure 5, we can actually view the contact bounce associated with the above breaker operation as shown in Figure 6.

It is clear to see that there is 0.8 ms bounce associated with the contact movement in phase C. These series of contact bounces can be compared with future tests to see if there is any degradation to the actual mechanism associated with breaker contacts.

3. Opening and closing synchronization

The breaker opening and synchronization can be viewed as a group, i.e., the operation of all three phases together for breaker open and close cycle.

The normal maximum time difference between all three phases should not be more than 2 ms for most breakers.

The synchronization of a breaker is defned as the time difference between the fastest and slowest phase (contact make and break) during the breaker open and close operation.

4. Total opening and closing speed

All breakers have specific speed, opening and closing times. Therefore, it is important that breakers operate within their opening and closing time.

For example, if a breaker is slow to open due to ageing or degradation, it may compromise the protection and coordination scheme of the protective relays, and thereby cause unwanted power interruption and equipment damage.

Further, all breakers have specified closing speed which is defined as the average speed calculated between two defined points on the motion curve as indicated below.

These two points will be specified by the breaker manufacturer and define where to set both points for accurate speed measurements.

For example, they will define the first point to be set to a distance above the open position and a distance below the upper point where the contact motion stops as indicated below.

5. Trip operation

The trip operation of a breaker is another name for an open operation. Most utility companies and plant owners want to perform a trip (or open) operation to monitor the speed of the opening mechanism and contacts to make sure there is enough energy in the spring mechanism to open under a fault condition.

The graph for a trip is similar to the one for a close operation, except the motion of the mechanism is going in the opposite direction, i.e., from closed contacts to fully open position as seen in Figure 7

6. Trip-free operation

This operation simulates the condition when an open breaker is closed into a fault and then it is tripped free by a protective relay.

This operation confirms whether a breaker, if closed into a fault, can clear it.

The graph for a trip-free operation is shown in Figure 8 below.

7. Close operation

This test is performed to verify a breaker’s closing mechanism. The graph for close operation of a breaker is shown in Figure 9 which is similar to the graph of Figure 5.

8. Trip-reclose operation

In this test, the reclose operation of the breaker is checked to assure that the breaker closing time is within specified limits after a trip operation. The reclose time is measured either in milliseconds or cycles.

The trip-reclose operation of the breaker is shown in Figure 10.

The problems usually detected with this test are faulty dashpots, faulty adjustments, weak accelerating springs, defective shock absorbers, buffers and closing mechanisms, or broken parts.

This test should be performed during acceptance tests and then during maintenance tests about every 3 years.

All three phases can be tested at the same time giving both individual phase timing and combined measurements for all three phases. The EGIL analyzer is shown in
video below.

Learn How to Conduct Circuit Breaker Testing

Circuit Breaker Timing Test

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Reference // Electrical Power Equipment Maintenance and Testing by Paul Gill