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Home / Technical Articles / On-load tests you MUST perform during the switchgear commissioning process

Introduction to On-load tests

On-load tests constitute the final activity in the commissioning process of low voltage or medium voltage switchgear. They are carried out immediately after the newly installed equipment is energized from the power system, and they are the definitive tests in verifying that the equipment has been correctly installed, and is satisfactory for commercial operation.

On-load tests you MUST perform during the substation commissioning process
On-load tests you MUST perform during the substation commissioning process (photo credit: elektrum-ng.ru)

Table of Contents:

  1. Preparation prior to energization
  2. Energization
  3. Soak test
  4. Energizing a radial circuit
  5. Phasing via phasing sticks
  6. Phasing via voltage transformers (VTs)
  7. Phasing of transformer supplies
  8. Absence of 3-phase voltage transformer (VT)
  9. Voltage-reference point
  10. Synchronising and paralleling supplies
  11. Metering
  12. Ratio and polarity of protection current transformers
  13. Voltage-transformer supplies
  14. Protection equipment
  15. Auxiliary supplies
  16. Load current
  17. Auto-switching and automatic-voltage-control tests
  18. Maintenance

1. Preparation prior to energization

Before energizing new equipment, the commissioning panel should prepare a switching procedure that takes full account of all safety, operational and technical requirements. The switching procedure should specify pre-energization checks and precautions, as follows:

Check #1 – All off-load-test documentation should be formally completed. Formal acknowledgement of this should be through the completion of stage 1 of the Acceptance Certificate or a similar type of document.

Check #2 – A final check should be made to ensure that all CT test links are in the service position.

Check #3 – Check that all alarms are reset.

Check #4 –  All safety documentation should be cancelled, all earth connections removed and all equipment left in the open or de-energized position. The latter point should be checked both visually and at all local and remote indication boards.

Check #5 – When entering service, all protection systems should be normal and in service. Auto-switching and automatic-voltage-control equipment should be switched out of service. Consideration should be given to the transformer tap position (usually left on nominal tap).

Check #6 – The identity and location of all personnel participating in the on-load tests should be clearly stated.

Figure 1 – Commissioning medium voltage switchgear

Commissioning substation and MV switchgear
Figure 1 – Commissioning substation and MV switchgear

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2. Energization

At the time of energizing a new circuit, neither the new circuit breaker nor its associated protection systems are fully proven. It is therefore usual to energize the new circuit from an already proven circuit.

This is often accomplished by using a bus-coupler or bus-section circuit breaker which is equipped with fast-operating non-unit protection (e.g. an instantaneous overcurrent and earth-fault relay), which should be set as sensitively as possible.

The switching sequence should consist of the following:

  1. Select the bus-section (or coupler) circuit and the circuit to be commissioned to the same busbar – initially with both circuit breakers open – and with no other circuits selected to that busbar.
  2. Close the bus-section circuit breaker to energize up to the circuit breaker associated with the circuit to be commissioned.
  3. Close the circuit breaker on the circuit to be commissioned to energize the circuit.
  4. Energization is now complete; soak tests and on-load tests can now commence.

When switching, to energize new equipment, the following should be adhered to:

  1. Ideally, all personnel should be at positions remote from the equipment to be energized, for safety reasons.
  2. The minimum number of personnel should be located in the control/ switching room. No one carrying out switching desires an audience, unless it’s a politician :)
  3. Personnel carrying out a switching instruction should read it twice.
    They must understand what is to be done, and what the implications will be. They should act slowly and deliberately. They should also consider in advance what will be heard or observed on energizing the equipment, e.g. transformer hum, voltages and currents appearing on instruments.
  4. Once energized, all high-voltage equipment (e.g. circuit breakers, disconnectors, tap changers) should be operated to prove satisfactory operation with the system voltage applied.

Suggested reading – Dos and don’ts in operating LV/MV equipment

Dos and don’ts in operating LV/MV circuit breakers, relays, disconnectors and fuses

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3. Soak test

Soak testing consists of leaving the new equipment energized from the system voltage for a period of time, before it is subject to load current This is to observe that the equipment suffers no distress when subject to the system voltage. A typical soak-test duration for a circuit breaker is about half an hour, and for a transformer, a minimum of two to three hours, to observe that there is no accumulation of gas in the Buchholz.

Note that there is a modern tendency to abbreviate the soak test to a brief visual inspection of the plant.

Suggested reading – Power transformers testing and commissioning at the site

Power transformers testing and commissioning at the site (instructions and precautions)

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4. Energizing a radial circuit

A typical example of a radial circuit is a 415 V distribution board. Once it has been energized, the only tests necessary are to check the magnitude of all voltages to the neutral and earth, and to each other, and their phase rotation.

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5. Phasing via phasing sticks

Figure 2 illustrates the case of a new 11 kV distribution circuit A which is to be commissioned onto the busbars at C. Before the remote-end circuit breaker associated with A can be closed, a phasing-check test is required. This can be accomplished with the use of phasing sticks.

These consist of two long insulated probes connected at the base by a conducting bond and fitted with an indicating voltmeter.

Figure 2 – Phasing out using phasing sticks

Phasing out using phasing sticks
Figure 2 – Phasing out using phasing sticks

An operator wearing insulated gloves holds the two sticks, and inserts one up each of the busbar and feeder spouts, respectively, of metal-clad circuit breakers, or across the feeder and busbar connections of open-terminal circuit breakers. Each phase is tested against the other phase. In-phase connections should result in zero volts on the voltmeter, while across-phase connections should indicate 11 kV.

Phasing sticks are generally available for voltages up to 36 kV. Note that they should be proved before and after use using a proving device.

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6. Phasing via voltage transformers (VTs)

With higher-voltage systems, it is necessary to carry out the phasing test with the use of voltage transformers. This consists of a two-stage process: first to prove the voltage transformer connected to the circuit whose phasing is to be proved, by phasing out against a supply whose phasing is already verified; and secondly to phase out to prove the phasing of the circuit under consideration.

Figure 3 – Phasing test via voltage transformers (VTs)

Phasing test via voltage transformers (VTs)
Figure 3 – Phasing test via voltage transformers (VTs)

Figure 3 gives an example for the instance of circuit A requiring to be commissioned:

Step #1 – Starting conditions are with circuit breakers A1 and A2 both open, and an existing circuit B energized and in service.

Step #2 – Circuit breaker A2 should be closed, thus energizing feeder A from feeder B.

Step #3 – Phasing tests should be carried out between the VTs on feeders A and B:

  1. Voltage magnitudes should be verified by measuring the voltage to earth (63.5 V) and between phases (110 V) at each VT box in turn.
  2. Voltage phase rotation should be verified by applying a phase-rotation meter to each VT box in turn.
  3. An insulated wire should then be run between the two VT boxes,
  4. At one end, a voltmeter should be connected between the wire and VT terminals in turn (preferably the VT connected to the in-service circuit to minimise the risk of causing a short circuit on that VT), and at the other end, the wire should be touched onto each VT terminal in turn. For correct phasing, the results matrix shown in Table 1 should then be obtained.

Table 1 – Phasing-test results

VT A
RYBN
VT BR011011063.5
Y110011063.5
B110110063.5
N63.563.563.50

The purpose of this test is to verify the voltage transformer connected to feeder A, by phasing against a known and proven source of supply (feeder B and the VT connected to B), prior to proving the phasing of the conductors connected to feeder A.

Step #4 – Circuit breaker A2 should now be opened and circuit breaker A1 closed. Phasing tests between the VTs on feeders A and B should then be carried out again, as described in Step #3 above. This test proves the phasing of feeder A’s conductors.

Circuit breaker A2 is now in a position to be closed.

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7. Phasing of transformer supplies

Figure 4 shows the instance of a transformer A which is to be commissioned. Transformer B is existing and in service. In brief:

  1. The Starting condition is with circuit breakers A1 & A2 open, and disconnector D open.
  2. Close A2 and phase out between the A- and B-circuit VTs, i.e. from a known supply to prove the A-circuit VT wiring
  3. Open A2, close disconnector D and circuit breaker A1, and phase out across the A- and B-circuit VTs. The phasing of transformer A is now verified.

Figure 4 – Phasing test to a VT on another circuit

Phasing test to a VT on another circuit
Figure 4 – Phasing test to a VT on another circuit

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8. Absence of 3-phase voltage transformer (VT)

The above phasing tests are dependent on a three-phase VT being installed on each circuit. Some circuits are equipped with either a single-phase VT or no VT. In such an instance, the phasing must be carried out by utilizing a three-phase VT on another circuit.

For example, with reference to above Figure 4, circuit A does not have a three-phase VT installed. Therefore, the three-phase VT on circuit C is utilized.

Assuming that VTs on feeders B and C have been previously phased out, the procedure is as follows:

  1. Open the bus-section circuit breaker, to ensure that feeders A and B do not become connected.
  2. Close circuit breakers Al, A2 and C1.
  3. Phase out between VTs on B and C feeders.

The author has experienced instances of a new substation being constructed where the incoming supply feeder was the only circuit equipped with a three-phase VT. Phasing out was carried out between the VT and a 415 V supply derived from another part of the power system.

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9. Voltage-reference point

The preceding sections on phasing tests have assumed that the three-phase VTs have their star points earthed, thus establishing a symmetrical and common reference point for the phasing test. It must be noted, however, that the earthing of the star point must not be assumed. Some VTs, particularly those on the 33 kV system, are often earthed via the yellow phase.

In some instances, it may therefore be necessary to carry out a phasing test between VTs with different earthing arrangements. When the results are interpreted, account must therefore be taken of the relative phase positions of the two VTs; see, for example, Figure 5.

Note that before phasing tests are begun it is imperative that each phase voltage of the VT is measured to earth and neutral to determine the earthing arrangement.

Figure 5 – Phasing for different VT-earthing arrangements

Phasing for different VT-earthing arrangements
Figure 5 – Phasing for different VT-earthing arrangements

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10. Synchronizing and paralleling supplies

Once the phasing tests have been carried out, the operator is in a position to close the circuit breaker, to parallel supplies. At the lower voltages, the circuit breaker would be closed manually from the control board (or in some instances at the circuit breaker itself.) At higher voltages, a synchronising scheme is usually employed.

Suggested reading – MV/HV switchgear (circuit breaker) switching capability and suitability for specific applications

MV/HV switchgear (circuit breaker) switching capability and suitability for specific applications

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11. Metering

It is necessary to prove polarity-conscious metering, i.e. the direction of flow of active and reactive power, during the on-load tests. Once proven, the metering may be utilized to assist in proving polarity-conscious protection. Figure 6 illustrates the metering convention.

Active power and lagging reactive power flowing out of the busbars are termed export quantities, and active power and lagging reactive power flowing into the busbars (the latter being equivalent to leading reactive power flowing out of the busbars) are termed import quantities.

Figure 6 – Metering convention

Metering convention
Figure 6 – Metering convention

Figures 7, 8, 9 and 10 illustrate methods for proving the metering by comparing the unproven metering with proven metering. Figure 7 shows ammeter and voltmeter connected directly to the CT and VT circuitry, to enable the active and reactive quantities to be calculated.

Figure 7 – Method of proving metering: From a known source of generation

Method of proving metering: From a known source of generation
Figure 7 – Method of proving metering: From a known source of generation

Figure 8 – Method of proving metering: Compare with local proved metering:

  • Meter A (proved) = PMW imported + QMVAR exported
  • Meter B (unproved) = PMW exported + QMVAR imported
Method of proving metering: Compare with local proved metering
Figure 8 – Method of proving metering: Compare with local proved metering

Figure 9 – Method of proving metering: Compare with remote proved metering:

  • Meter A (proved) = PMW imported + QMVAR exported
  • Meter B (unproved) = PMW exported + (Q+C) MVAR imported
Method of proving metering:  Compare with remote proved metering
Figure 9 – Method of proving metering:  Compare with remote proved metering

Figure 10 – Method of proving metering: Using a phase-angle meter, ammeter and voltmeter

Method of proving metering:  Using a phase-angle meter, ammeter and voltmeter
Figure 10 – Method of proving metering:  Using a phase-angle meter, ammeter and voltmeter

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12. Ratio and polarity of protection current transformers (CTs)

The current flowing in the secondary wiring of each CT can be measured with a miniature clip-on ammeter or, with some relays, by inserting a split plug directly into the relay. The measured current should be compared with that being indicated on the circuit metering (circuit ammeter), to prove the CT ratio.

Current-transformer polarity is usually verified by carrying out on-load polarity tests on the relay.

Suggested reading – What is polarity and why it’s important for transformers and protection relays

What is polarity and why it’s important for transformers and protection relays

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13. Voltage transformer supplies

Each item of protection and control equipment should be checked to ensure that it is connected to the correct VT phase. One method for achieving this is to run a cable, whose cores have been identified, from the VT terminal box to a terminal block in the relay room. Supplies from the terminal block to each relay can then be phased out.

A phase-rotation meter should be connected to at least one item of equipment to confirm correct voltage-phase rotation.

Complete Power Engineering Bundle (Six Courses)

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14. Protection equipment

The on-load tests carried out on protection equipment are required to prove the following:

Test #1 – that each relay is supplied from the correct ratio of CT. This is simply checked by measuring the current in each relay and comparing it with that indicated on the circuit metering. In effect, this test confirms the primary injection test.

Test #2 – that relays with directional features (e.g. distance protection, directional overcurrent) are looking in the correct direction.

This is accomplished by checking whether the relay is tending to operate or restrain when the current flow is in a known direction. This is also a check of correct CT polarity.

Test #3 – that unit protections are exhibiting balance and stability with the flow of load current. This, again, is also a check of CT polarity.

Test #4 – that, when the power system is used as the communication medium, such as with power-line-carrier systems, the magnitudes of the send and receive voltages are within acceptable limits.

With tests #2 and #3 above, it is usual with feeder protections to reverse the CT secondaries (or rotate the voltage phases) to prove that the relay tends to operate or restrain as appropriate with reversed CT polarity. The preceding chapters have discussed on-load tests for specific protection equipment.

Suggested reading – Primary injection testing of protection system for wiring errors between VTs / CTs and relays

Primary injection testing of protection system for wiring errors between VTs / CTs and relays

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15. Auxiliary supplies

Once the main power-system connections and protection and control supplies have been proved, any site auxiliary supplies fed from the commissioned equipment should be proved. This may require phasing out of low-voltage supplies, or observing the direction of rotation of transformer fans, pumps etc.

Suggested course – Learn to Read and Analyze CB Schematics & Control Wiring Diagrams

Learn to Read and Analyze Circuit Breaker Schematics and Control Wiring Diagrams

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16. Load current

When carrying out on-load tests, it is advantageous to have as much load current as possible. In some instances, the power system may require manual intervention to create load current. Examples of this include generators running out of merit, adjusting transformer taps to cause circulating currents, or switching circuits to transfer load.

Occasionally, it is just a matter of sitting it out until the peak daily load occurs. Long feeders which are lightly loaded can be problematic since the feeder capacitance current causes a mismatch of current in unit-protection CTs.

Where sufficient load current cannot be obtained to enable the on-load tests on unit-protection systems to be carried out, consideration should be given to injecting a current directly through the high-voltage circuit from a primary injection set, or from a 415 V supply. This consists of injecting current at one end of the circuit and connecting to earth at the other.

Usually, a current of about 200 A is sufficient. This method of on-load testing can be carried out only when the primary-system impedance is relatively low, and where induced voltages into the circuit in question do not constitute a safety hazard.

Suggested course – Power System Analysis Course: Load Flow and Short Circuits

Power System Analysis Course: Load Flow and Short Circuits

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17. Auto-switching and automatic-voltage-control tests

Finally, the auto-switching and automatic-voltage-control equipment should, in turn, be switched into service, and manually initiated tests carried out.

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18. Maintenance

It is not usual to repeat the on-load tests following maintenance. Some companies, however, check that currents and voltages are present at each protection relay following the return to service of a circuit after maintenance.

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Source: Power commissioning and maintenance by K. Harker

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author-pic

Edvard Csanyi

Electrical engineer, programmer and founder of EEP. Highly specialized for design of LV/MV switchgears and LV high power busbar trunking (<6300A) in power substations, commercial buildings and industry facilities. Professional in AutoCAD programming.

One Comment


  1. leenkw
    Nov 23, 2021

    good desciption

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