COMMISSIONING, MAINTENANCE AND REPAIR OF POWER TRANSFORMER BASIC INFORMATION

Commissioning

Small power transformers can be transported to site complete with oil, bushings, tap changers and cooling equipment. It is then a relatively simple matter to lift them onto a pole or plinth and connect them into the system.

Large transformers are subject to weight restrictions and size limitations. When they are moved by road or rail and it is necessary to remove the oil, bushings, cooling equipment and other accessories to meet these limitations. Very large transformers are usually carried on custom-built transporters.

Once a transformer of this size arrives on site, it must be lifted or jacked onto its plinth for re-erection. In some cases with restricted space it may be necessary to use special techniques, such as water skates to maneuver the transformer into position.

When the transformer has been erected and the oil filled and reprocessed, it is necessary to carry out commissioning tests to check that all electrical connections have been correctly made and that no deterioration has occurred in the insulation system.

These commissioning tests are selected from the routine tests and usually include winding resistance and ratio, magnetizing current at 440 V, and analysis of oil samples to establish breakdown strength, water content and total gas content. If oil samples indicate high water content then it may be necessary to dry the oil using methods addressed in the following section.

Maintenance

Transformers require little maintenance in service, apart from regular inspection and servicing of the OLTC mechanism. The diverter contacts experience significant wear due to arcing, and they must be replaced at regular intervals which are determined by the operating regime.

For furnace transformers it may be advisable to filter the oil regularly in a diverter compartment in order to remove carbon particles and maintain the electrical strength.

The usual method of protecting the oil breather system in small transformers is to use silicone gel breathers to dry incoming air; in larger transformers refrigerated breathers continuously dry the air in a conservator. Regular maintenance (at least once a month) is necessary to maintain a silica gel breather in efficient working order.

If oil samples indicate high water content then it may be necessary to dry the oil using a heating vacuum process. This also indicates high water content in the paper insulation and it may be necessary to redry the windings by applying a heating and vacuum cycle on site, or to return the transformer to the manufacturer for reprocessing or refurbishment.

An alternative procedure is to pass the oil continuously through a molecular sieve filter. Molecular sieves absorb up to 40 per cent of their weight of water.

Diagnostics and repair

In the event of a failure, the user must first decide whether to repair or replace the transformer. Where small transformers are involved, it is usually more economic to replace the unit. In order to reach a decision, it is usually necessary to carry out diagnostic tests to identify the number of faults and their location.

Diagnostic tests may include the surveillance tests, and it may also be decided to use acoustic location devices to identify a sparking site, low-voltage impulse tests to identify a winding fault and frequency response analysis of a winding to an applied square wave to detect winding conductor displacement.

If the fault is in a winding, it usually requires either replacement of the winding in a repair workshop or rewinding by the manufacturer, but many faults external to the windings, such as connection or core faults can be corrected on site.

Where a repair can be undertaken on site it is essential to maintain dry conditions in the transformer by continual purging using dry air. Any material taken into the tank must be fully processed and a careful log should be maintained of all materials taken into and brought out of the tank.

When a repair is completed, the transformer must be re-dried and re-impregnated, and the necessary tests carried out to verify that the transformer can be returned to service in good condition.

IN SERVICE TESTING OF POWER TRANSFORMERS BASIC INFORMATION

Two types of in-service testing are used. Surveillance testing involves periodic checks, and condition monitoring offers a continuous check on transformer performance.

(a) Surveillance testing – oil samples

When transformers are in operation, many users carry out surveillance testing to monitor operation. The most simple tests are carried out on oil samples taken on a regular basis.

Measurement of oil properties, such as breakdown voltage, water content, acidity, dielectric loss angle, volume resistivity and particle content all give valuable information on the state of the transformer.

DGA gives early warning of deterioration due to electrical or thermal causes, particularly sparking, arcing and service overheating.

Analysis of the oil by High-Performance Liquid Chromatography (HPLC) may detect the presence of furanes or furfuranes which will provide further information on moderate overheating of the insulation.

(b) On-line condition monitoring

Sensors can be built into the transformer so that parameters can be monitored on a continuous basis. The parameters which are typically monitored are winding temperature, tank temperature, water content, dissolved hydrogen, partial discharge activity, load current and voltage transients.

The data collection system may simply gather and analyse the information, or it may be arranged to operate alarms or actuate disconnections under specified conditions and limits which represent an emergency.

Whereas surveillance testing is carried out on some distribution transformers and almost all larger transformers, the high cost of on-line condition monitoring has limited the application to strategic transformers and those identified as problem units.

As the costs of simple monitoring equipment fall, the technique should become more applicable to substation transformers.

TRANSFOMER POWER FACTOR/ CAPACITANCE MEASUREMENT BASIC INFORMATION

Two methods are used to make power (dissipation) factor and capacitance measurements. The first is the grounded specimen test (GST), where current, watts, and capacitance of all leakage paths between the energized central conductor and all grounded parts are measured.

Measurements include the internal core insulation and oil as well as leakage paths over the insulator surfaces. The use of a guard circuit connection can be used to minimize the effects of the latter.

The second method is the ungrounded specimen test (UST), where the above quantities are measured between the energized center conductor and a designated ungrounded test electrode, usually the voltage or test tap.

The two advantages of the UST method are that the effects of unwanted leakage paths, for instance across the insulators, are minimized, and separate tests are possible while bushings are mounted in apparatus.

Standards recommend that power factor and capacitance measurements be made at the time of installation, a year after installation, and every three to five years thereafter. A significant increase in a bushing’s power factor indicates deterioration of some part of the insulating system.

It may mean that one of the insulators, most likely the air-end insulator, is dirty or wet, and excessive leakage currents are flowing along the insulator. A proper reading can be obtained by cleaning the insulator.

On the other hand, a significant increase of the power factor may also indicate deterioration within the bushing. An increase in the power factor across the C1 portion, i.e., from conductor to tap, typically indicates deterioration within the core.

An increase across the C2 portion of a bushing using a core, i.e., from tap to flange, typically indicates deterioration of that part of the core or the bushing oil. If power factor doubles from the reading immediately after initial installation, the rate of change of the increase should be monitored at more frequent intervals.

If it triples, then the bushing should be removed from service. An increase of bushing capacitance is also a very important indicator that something is wrong inside the bushing.

An excessive change, on the order of 2 to 5%, depending on the voltage class of the bushing, over its initial reading probably indicates that insulation between two or more grading elements has shorted out. Such a change in capacitance is indication that the bushing should be removed from service as soon as possible.

POWER TRANSFORMER THERMAL STABILITY TEST BASIC INFORMATION

Capacitive leakage currents in the insulating material within bushings cause dielectric losses. Dielectric losses within a bushing can be calculated by the following equation using data directly from the nameplate or test report:

Pd = 2 pi f C V2 tan ��

where

Pd = dielectric losses, W

f = applied frequency, Hz

C = capacitance of bushing (C1), F

V = operating voltage, rms V

tan �� = dissipation factor, p.u.

A bushing operating at rated voltage and current generates both ohmic and dielectric losses within the conductor and insulation, respectively. Since these losses, which both appear in the form of heat, are generated at different locations within the bushing, they are not directly additive.

However, heat generated in the conductor influences the quantity of heat that escapes from within the core. A significant amount of heat generated in the conductor will raise the conductor temperature and prevent losses from escaping from the inner surface of the core.

This causes the dielectric losses to escape from only the outer surface of the core, consequently raising the hottest-spot temperature within the core.

Most insulating materials display an increasing dissipation factor, tan ��, with higher temperatures, such that as the temperature rises, tan �� also rises, which in turn raises the temperature even more. If this cycle does not stabilize, then tan �� increases rapidly, and total failure of the insulation system ensues.

Bushing failures due to thermal instability have occurred both on the test floor and in service. One of the classic symptoms of a thermal-stability failure is the high internal pressure caused by the gases generated from the deteriorating insulation.

These high pressures cause an insulator, usually the outer one because of its larger size, either to lift off the flange or to explode. If the latter event occurs with a porcelain insulator, shards of porcelain saturated with oil become flaming projectiles, endangering the lives of personnel and causing damage to nearby substation equipment.

Note from Equation that the operating voltage, V, particularly influences the losses generated within the insulating material. It has been found from testing experience that thermal stability only becomes a factor at operating voltages 500 kV and above.

POWER TRANSFORMER DIELECTRIC TESTS TYPES BASIC INFORMATION

Low-Frequency Tests

There are two low-frequency tests:

1. Low-frequency wet-withstand voltage test

2. Low-frequency dry-withstand voltage test

Low-Frequency Wet-Withstand Voltage Test — The low-frequency wet-withstand voltage test is applied on bushings rated 242 kV and below while a waterfall at a particular precipitation rate and conductivity is applied. The values of precipitation rate, water resistivity, and the time of application vary in different countries.

American standard practice is a precipitation rate of 5 mm/min, a resistivity of 178 ohm-m, and a test duration of 10 sec, whereas European practice is 3 mm/min, 100 ohm��m, and 60 sec, respectively.

If the bushing flashes over externally during the test, it is allowed that the test be applied one additional time. If this attempt also flashes over, then the test fails and something must be done to modify the bushing design or test setup so that the capability can be established.

Low-Frequency Dry-Withstand Voltage Test — The low-frequency dry-withstand test was, until recently, made for a 1-min duration without the aid of partial-discharge measurements to detect incipient failures, but standards currently specify a one-hour duration for the design test, in addition to partial-discharge measurements.

The present test procedure is:

Partial discharge (either radio-influence voltage or apparent charge) shall be measured at 1.5 times the maximum line-ground voltage. Maximum limits for partial discharge vary for different bushing constructions and range from 10 to 100 ��V or pC.

A 1-min test at the dry-withstand level, approximately 1.7 times the maximum line-ground voltage, is applied. If an external flashover occurs, it is allowed to make another attempt, but if this one also fails, the bushing fails the test. No partial-discharge tests are required for this test.

Partial-discharge measurements are repeated every 5 min during the one-hour test duration at 1.5 times maximum line-ground voltage required for the design test. Routine tests specify only a measurement of partial discharge at 1.5 times maximum line-ground voltage, after which the test is considered complete.

Bushing standards were changed in the early 1990s to align with the transformer practice, which started to use the one-hour test with partial-discharge measurements in the late 1970s. Experience with this new approach has been good in that incipient failures were uncovered in the factory test laboratory, rather than in service, and it was decided to add this procedure to the bushing test procedure.

Also from a more practical standpoint, bushings are applied to every transformer, and transformer manufacturers require that these tests be applied to the bushings prior to application so as to reduce the number of bushing failures during the transformer tests.

FACTORY FIELD TEST OF POWER TRANSFORMER BASIC INFORMATION

There are a number of field tests that are considered good predictive maintenance practices and these should be performed periodically to spot trouble. These tests are also useful for diagnosing transformer trouble.

A Megger test consists of applying a high DC voltage, usually 1000 V, to each winding with the other windings grounded and to all windings connected in parallel. The Megger readings are in megohms and these must be temperature corrected for meaningful results.

The megger readings should be compared to earlier test results to detect any downward trend in resistance values. The voltage produced by a megger is high enough to cause insulation breakdown if there are gross faults, but is really not sensitive enough to detect minor problems in transformers in the higher voltage classes.

A Doble test is somewhat more sensitive than the Megger test. An AC voltage, up to 10 kV, is applied to the winding insulation and leakage current is measured. In addition to the leakage current, the power factor of the insulation is computed.

A high power factor indicates lossy insulation, which can mean imminent trouble. In addition to the winding insulation, the Doble test is used to measure the power factor of bushing insulation. When testing condenser type bushings, the capacitance tap is utilized.

The Doble test set is also used to measure the excitation current through the winding by applying an AC voltage across the winding. High power factor readings during this test can indicate flaws in the turn-to-turn insulation.

A TTR test can be used as a diagnostic test in the field. Always connect the TTR test set clamp leads to a secondary winding of the transformer under test. Connect the TTR test set clip leads to the primary winding that is on the same core leg as the secondary winding being tested, observing that the polarity of the red clip test lead matches the polarity of the red clamp test lead.

Set the ratio dials just above zero and give the generator wheel a half turn. The galvanometer should deflect to the left, indicating the ratio dials need to be raised. A deflection to the right means that the polarity of the test leads is incorrect.

This can be corrected by swapping the two clip test leads. After the correct polarity has been verified, slowly turn the generator and make the appropriate adjustments to the ratio dials in order to keep the galvanometer needle centered (zero current in the clip test leads). When the ratio dials are almost set to the right ratio, the generator can be cranked faster to get the proper voltage indication on the voltmeter (8 V).

If the voltmeter reads low voltage with the ammeter reading high current, this is usually an indication of shorted turns, either in the primary or in the secondary. A zero deflection on the galvanometer at every ratio settings indicates an open primary winding because no current can flow in the clip

test leads.

If the galvanometer deflection is always to the right and cannot be corrected by reversing the test leads, then this may indicate an open secondary winding and voltage cannot be generated in the primary winding.

RATIO TEST (TTR) OF POWER TRANSFORMER BASIC INFORMATION

This test determines the ratio (TTR) of the number of turns in the high-voltage winding to that in the low-voltage winding. The ratio test shall be made at rated or lower voltage and rated or higher frequency.

In the case of three phase transformers when each phase is independent and accessible, single phase power should be used, although three-phase power may be used when convenient. The tolerance for the ratio test is 0.5% of the winding voltages specified on the transformer nameplate.

The accepted methods for performing the ratio test are the voltmeter method, the comparison method, and the ratio bridge. With the voltmeter method, the primary winding is excited at rated frequency and the voltage at the primary and the open-circuit voltage of the secondary winding are measured.

The ratio is the primary voltage divided by the secondary voltage. The comparison method applies voltage simultaneously to the transformer under test and the open-circuit secondary voltages are measured and compared.

The ratio bridge method is the most accurate method and can easily determine the TTR to the very small tolerances required by the standard. The test apparatus is commonly referred to as a TTR Test Set.

One such test set is manufactured by the Biddle Company and has proven to be especially useful as a diagnostic test in the field, so its operation will be described in detail. This test set is shown in Figure 8.1.

FIGURE 8.1 Circuit diagram of a TTR test set.

The clamp test leads are connected to the secondary winding of the transformer under test and the clip leads are connected to the primary winding under test. The secondary winding of the transformer under test and the secondary of a calibrated reference transformer in the test set are both excited by the same 8 V source voltage from a hand-cranked generator. A voltmeter is used to verify that the correct voltage is being applied.

An ammeter measures the exciting current into the transformer under test. When the voltage developed across the primary of the transformer under test (1-2) is equal to the voltage developed across the primary of the calibrated reference transformer (2-3), then the voltage across the synchronous rectifier is zero and the galvanometer detector reads zero.

With more voltage developed across 1-2 than across 2-3, the galvanometer has a negative deflection. With less voltage developed across 1-2 than across 2-3, the galvanometer has a positive deflection. The ratio dials are used to adjust the ratio of the reference transformer.

A simplified equivalent circuit of the TTR test set is shown in Figure 8.2. The transformer under test is also shown. Note that the current through the detector, labeled ‘‘Det’’ in the figure, is zero when the voltages developed at the high-voltage terminals of the test-set transformer and the transformer under test are equal. This condition exists when the ratios of the test-set transformer and the transformer under test are equal.

MEASUREMENT OF TRANSFORMER NO LOAD LOSSES BASIC INFORMATION

Measuring no-load losses of a transformer when subjected to a sinusoidal voltage waveform can be achieved simply by using a wattmeter and a voltmeter; refer to Figure 1. Transformers may be subjected to a distorted sine-wave voltage.

In order to achieve the required measuring accuracy, the instrumentation used should accurately respond to the power frequency harmonics encountered in these measurements. Also, measured values need to be corrected to account for the effect of the voltage harmonics on the magnetic flux in the core and hence on both the hysteresis and eddy current loss components of iron losses.

The hysteresis loss component is a function of the maximum flux density in the core, practically independent of the waveform of the flux. The maximum flux density corresponds to the average value of the voltage (not the rms value), and, therefore, if the test voltage is adjusted to be the same as the average value of the desired sine wave of the voltage the hysteresis loss component will be equal to the desired sine wave value.

The average-voltage voltmeter method as illustrated in Figure 1 utilizes an averagevoltage responding voltmeter based on a full-wave rectification. These instruments are generally scaled to give the same indication as a rms voltmeter on a sine-wave voltage.

The figure shows the necessary equipment and connections when no instrument transformers are needed. As indicated in Figure 1, the voltmeters should be connected across the winding, the ammeter nearest to the supply, and wattmeter between the two; with its voltage coil on the winding side of the current coil.

The average-voltage responding voltmeter should be used to set the voltage.

NOTE

‘F’ is a frequency meter

‘A’ is an ammeter

‘W’ is a wattmeter

‘V’ is a true rms voltmeter

‘AV’ is an average-responding, rmscalibrated voltmeter

The eddy-current loss component of the core loss varies approximately with the square of the rms value of the core flux. When the test voltage is held at rated voltage with the average-voltage voltmeter, the actual rms value of the test voltage is generally not equal to the rated value.

The eddy-current loss in this case will be related to the correct eddy-current loss at rated voltage by a factor k given in Equation 8.2, Clause 8 of the IEEE Std. C57.12.90-1993 and C57.12.91-1979 Standard. This is only correct for a reasonably distorted voltage wave.

ON LOAD TAP CHANGER DESIGN TEST FOR MOTOR DRIVEN MECHANISM BASIC INFORMATION

Mechanical load test
If the LTC is operated by a separate motor-drive mechanism, the output shaft shall be loaded by the largest LTC for which it is designed or by an equivalent simulated load.

At such a load, 500 000 operations shall be performed at room temperature across the entire tap range. Additional cooling of the motor-drive is permissible during this test.

During this test, 10 000 operations shall be performed with the motor supply voltage at 85% of rated drive motor voltage. Also, 10 000 operations shall be performed at 110% of rated drive motor voltage. In addition, 100 operations shall be performed at a temperature of -25 °C.

The correct functioning of the tap position indicator, limit switches, restarting device, and operation counter shall be verified during this test. At the completion of this test, the LTC shall be operated manually, if applicable, through one cycle of operation.

The test shall be considered to be successful if there is no mechanical failure or any undue wear of the mechanical parts. Normal servicing according to the manufacturer's instruction book is permitted during the test. During this test, the heating system of the motor-drive mechanism shall be switched off.

Overrun test
It shall be demonstrated that, in the event of a failure of the electrical limit switches, the mechanical end stops will prevent operation beyond the end positions when a motorized tap-change is performed and that the motor-drive mechanism will not suffer either electrical or mechanical damage.

TESTING OF PHASE SHIFTING TRANSFORMERS BASIC AND TUTORIALS

Unless otherwise specified, all tests carried out at the factory should be made in accordance with IEEE Std C57.12.90-1993. Additional tests, particular to PSTs, are defined in 11.2, Special tests for PSTs.

Since the method of testing PSTs is dependent on the design, the testing methods will be mutually agreed upon by the user and manufacturer.

Resonant frequency and transient voltage tests
These tests are normally performed on the core and coil assembly in air. However, they can also be performed inside the tank filled with oil and fitted with temporary bushings to give access to required test points.

For a two-core design in one or more tanks, the windings must be interconnected as for impulse testing. These tests are intended to verify the transient voltages and natural frequencies at various points in the windings at all tap combinations and connections that can be compared and evaluated with studies.

Temperature tests and loss distribution
In most cases temporary bushings must be installed for connections to windings, which are not normally accessible, in order to determine the various resistances for the temperature tests and to determine the losses and the distribution of these losses.

The location of these temporary bushings depends on the design and winding configuration and is subject to agreement between user and manufacturer. For two-tank designs, the tanks may be separate to determine the losses in the various cores and windings and the temperature test.

This information will be provided by the manufacturer to the user during preliminary discussions.

Dielectric test
For dielectric tests each tank with its corresponding core and windings should be connected electrically and mechanically together as for the service condition. In most cases, temporary bushings must be installed on lower voltage windings in order to perform the IEEE standard low frequency induced test on the higher source and load side windings.

In very high voltage PSTs, it is sometimes necessary to install an auxiliary winding next to the core for shielding purposes. This auxiliary winding can then be used for performing the low-frequency induced test through the use of temporary bushings.

POLARITY TEST OF SINGLE PHASE TRANSFORMER BASIC AND TUTORIALS

SINGLE PHASE TRANSFORMER POLARITY TESTS BASIC INFORMATION

What Are The Polarity Tests Of Single Phase Transformers?

Polarity tests on single-phase transformers shall be made in accordance with one of the following methods:

a) Inductive kick

b) Alternating voltage

c) Comparison

d) Ratio bridge

Polarity by inductive kick

The polarity of transformers with leads arranged as shown in may be determined when making resistance measurements as follows:

a) With direct current passing through the high-voltage winding, connect a high-voltage direct-current voltmeter across the high-voltage winding terminals to obtain a small deflection of the pointer.

b) Transfer the two voltmeter leads directly across the transformer to the adjacent low-voltage leads, respectively.

NOTE—For example, in Figure 5, the voltmeter lead connected to H1 will be transferred to X2 as the adjacent lead,and that connected to H2to X1.

c) Break direct-current excitation, thereby inducing a voltage in the low-voltage winding (inductive kick), which will cause deflection in the voltmeter. The deflection is interpreted in d) and e) below.

d) When the pointer swings in the opposite direction (negative), the polarity is subtractive.

e) When the pointer swings in the same direction as before (positive), the polarity is additive.

Polarity by alternating-voltage test

For transformers having a ratio of transformation of 30 to 1 or less, the H1 lead shall be connected to the adjacent low-voltage lead (X1 in Figure 6).

Any convenient value of alternating voltage shall be applied to the full high-voltage winding and readings taken of the applied voltage and the voltage between the right-hand adjacent high-voltage and low-voltage leads.

When the latter reading is greater than the former, the polarity is additive. When the latter voltage reading is less than the former (indicating the approximate difference in voltage between the high-voltage and low-voltage windings), the polarity is subtractive.

Polarity by comparison

When a transformer of known polarity and of the same ratio as the unit under test is available, the polarity can be checked by comparison, as follows, similar to the comparison method used for the ratio test.

a) Connect the high-voltage windings of both transformers in parallel by connecting similarly marked

leads together.

b) Connect the low-voltage leads, X2, of both transformers together, leaving the X1 leads free.

c) With these connections, apply a reduced value of voltage to the high-voltage windings and measure the voltage between the two free leads.

A zero or negligible reading of the voltmeter will indicate that the relative polarities of both transformers are identical.

An alternative method of checking the polarity is to substitute a low-rated fuse or suitable lamps for the voltmeter. This procedure is recommended as a precautionary measure before connecting the voltmeter.

Polarity by ratio bridge

The ratio bridge can also be used to test polarity. A bridge using the basic circuit below may be used to measure ratio.

POWER TRANSFORMERS IN SERVICE TESTING BASIC AND TUTORIALS

POWER TRANSFORMERS IN SERVICE TESTING BASIC INFORMATION
What Is Power Transformer In Service Testing?

Two types of in-service testing are used. Surveillance testing involves periodic checks, and condition monitoring offers a continuous check on transformer performance.


(a) Surveillance testing – oil samples

When transformers are in operation, many users carry out surveillance testing to monitor operation. The most simple tests are carried out on oil samples taken on a regular basis.

Measurement of oil properties, such as breakdown voltage, water content, acidity, dielectric loss angle, volume resistivity and particle content all give valuable information on the state of the transformer. DGA gives early warning of deterioration due to electrical or thermal causes, particularly sparking, arcing and service overheating.

Analysis of the oil by High-Performance Liquid Chromatography (HPLC) may detect the presence of furanes or furfuranes which will provide further information on moderate overheating of the insulation.

(b) On-line condition monitoring

Sensors can be built into the transformer so that parameters can be monitored on a continuous basis. The parameters which are typically monitored are winding temperature, tank temperature, water content, dissolved hydrogen, partial discharge activity, load current and voltage transients.

The data collection system may simply gather and analyse the information, or it may be arranged to operate alarms or actuate disconnections under specified conditions and limits which represent an emergency.

Whereas surveillance testing is carried out on some distribution transformers and almost all larger transformers, the high cost of on-line condition monitoring has limited the application to strategic transformers and those identified as problem units.

As the costs of simple monitoring equipment fall, the technique should become more applicable to substation transformers.

TRANSFORMER OILS TESTING OF NEW OIL PROPERTIES BASICS AND TUTORIALS

TRANSFORMER OILS TESTING OF NEW OIL PROPERTIES BASIC INFORMATION

Testing Of Transformer Oil As Recommended In IEEE Std C57.106-2002

When mineral insulating oil specified to conform to ASTM D3487-00 is received, it should be tested to verify conformance with ASTM D3487-00. Testing of the oil for full conformance of all property requirements of ASTM D3487-00 is only justified under circumstances determined by the purchaser.

As a minimum, it is recommended that the purchaser require the supplier to provide a certified set of tests for the oil that demonstrate that the oil, as shipped, met or exceeded the property requirements of ASTM D3487-00.

For those circumstances where a full set of tests according to ASTM D3487-00 are not justified, it is recommended that, at a minimum, the tests shown in Table 1 of this guide be considered. The purchaser of the oil should conduct tests sufficient to satisfy concerns regarding conditions of shipment that might result in non conformance to ASTM D3487-00 property requirements.  

Table 1 lists several of the more important tests with values that should help in the decision regarding acceptance of the new mineral insulating oil.

Insulating oil is ordinarily shipped in three types of containers: drums or totes, tank trailers, and rail cars. Rail cars are usually under the control of the supplier and dedicated to insulating oil shipment, so they tend to be the cleanest.

Highway trailers are used to transport many different chemical products as well as insulating oil; these trailers are therefore subject to chemical contamination. Special cleaning and drying procedures may be necessary.

If problems are encountered, check the history of the shipping containers to see that they have been cared for properly. It is recommended that the purchaser require the delivery of oil in containers that are properly cleaned to guarantee delivery of oil conforming to ASTM D3487-00.

Drums and totes are the least desirable method of insulating oil transport but may be necessary for small purchases. Drums and totes should be stored under cover to prevent contamination by moisture.

Before processing, it is necessary to check the quality of the oil in each drum or tote or after blending the oil in a large tank. Each tank load or each shipping unit of oil as received at the customer’s site should undergo a check test to determine that the electrical characteristics have not been impaired during transit or storage.

Table 1 contains a list of recommended acceptance tests for shipments of mineral insulating oil as received from the supplier. Some users may not wish to perform all these tests; however, as a minimum, dielectric strength and dissipation factor (power factor) as listed in Table 1 should be performed.

It is satisfactory to accept oils that exhibit characteristics other than those described by the values in Table 1, providing that the users and the suppliers are in agreement.

POWER TRANSFORMER TEMPERATURE RISE TEST AT LOAD BEYOND NAMEPLATE RATING BASICS AND TUTORIALS

POWER TRANSFORMER TEMPERATURE RISE TEST AT LOAD BEYOND NAMEPLATE RATING BASIC INFORMATION

How To Conduct Temperature Rise Test For Power Transformer Beyond Nameplate Rating?

After completing the hot resistance tests data recorded during tests may be evaluated to determine preliminary exponents. The preliminary exponents may be used to evaluate whether an excessive top oil temperature or winding hottest spot temperature may occur during this test.

It is suggested that the winding hottest spot temperature be limited to 140 ˚C and top oil be limited to 110 ˚C, unless other values are agreed upon by the manufacturer and user. The top oil temperature and the measured rate of change of the oil level with temperature may be used to evaluate whether excessive oil levels may occur during this test.

If it becomes apparent that excessive values may be obtained, the load may be reduced from the 125% value, so the top oil temperature, winding hottest spot temperature, and oil level are limited to acceptable values.

After the evaluation of risk and the load beyond nameplate to be applied has been determined, proceed with the test as follows:

a) Short-circuit one or more windings, and circulate a constant current , at rated frequency, equal to

125% of rated current (1.25 x IR), plus additional current to produce losses equal to the rated no-load loss.

The current to be circulated may be determined using Equation (3). Continue applying this current until the top oil temperature does not vary by more than 2.5% or 1 ˚C, whichever is greater, in a time period of three consecutive hours.

b) Record all data listed in Clause 6 and Clause 7 after the top oil temperature rise has stabilized and

while is being applied:

c) Reduce the current to 125% of rated current ( ) and hold for a minimum time period of one hour. Calculate and record as measured current/ for later use in 9.8.5.

d) At the end of the one-hour period, while the current equal to 125% of rated ( ) is being applied, record all data.

e) Remove the load current, and measure a series of hot resistances of the windings at appropriate time intervals to determine the average winding temperatures using the cooling curve method in IEEE Std C57.12.90-1999. Only those windings found to be the hottest windings in item e) of 9.5 need be measured.