Parts Of Pad-Mounted Single-Phase Distribution Transformers

Single-phase pad mounted distribution transformers are used in underground distribution systems where it is preferable to have underground rather than overhead distribution. An example of a single-phase, pad mounted distribution transformer with its cover raised is shown in below.

Single-phase, pad-mounted transformers are manufactured with ratings from 10 to 167 kVA. All of these distribution transformers are oil-insulated, self-cooled, and made with loop or radial feed. They can meet or exceed ANSI and NEMA standards.

Pad-mounted distribution transformers are enclosed in steel tamper-resistant protective cases designed with low profiles. They are usually painted green to blend in

Submersible single-phase distribution transformers
Single-phase submersible underground transformers are enclosed in round vertical stainless steel tanks that are hermetically sealed for protection against repeated flooding and/or immersion. The terminals, ground pads, and nameplates are mounted on the covers for easy access from ground level.

These transformers are made in ratings of 25 to 167 kVA. Where submersible transformers are to be installed in a trench that is not subject to repeated flooding or immersion, they are enclosed in stainless steel tanks. Their terminals, ground pads, and nameplates are mounted on their covers.



Power transformer capacity is rated in kilovolt-amperes (kVA). The output rating for a transformer is determined by the maximum current that the transformer can withstand without exceeding its stated temperature limits.

Power in an AC circuit depends on the power factor of the load and the current, so if any AC electrical equipment is rated in kilowatts, a power factor must be included to make its power rating meaningful. To avoid this, transformers and most AC machines are rated in kVA, a unit that is independent of power factor.

In addition to its kVA rating, the nameplates of transformers typically include the manufacturer’s type and serial number, the voltage ratings of both high- and low voltage windings, the rated frequency, and the impedance drop expressed as a percentage of rated voltage. Some nameplates also include an electrical connection diagram.

Power transformers are generally defined as those used to transform higher power levels than distribution transformers (usually over 500 kVA or more than 67 kV). The kVA terminal voltages and currents of power transformers, defined in ANSI C57.12.80, are all based on the rated winding voltages at no-load conditions.

However, the actual primary voltage in service must be higher than the rated value by the amount
of regulation if the transformer is to deliver the rated voltage to the load on the secondary.

The efficiency of all power transformers is high, but efficiency is highest for large transformers operating at 50 to 100 percent of full load. However, some losses are present in all transformers. They are classified as copper or I2R losses and core losses.

Copper losses, also called load losses, are proportional to the load being supplied by the transformer. These losses can be calculated for a given load if the resistances of both windings are known. As in generators and motors, the core loss is due to eddy-current induction loss and hysteresis (molecular friction) loss, caused by the changing polarity of the applied AC.

If the cores are laminated from low-loss silicon steel, both eddy-current and hysteresis losses will be reduced. Nevertheless, well-designed transformers in all frequency and power ranges typically have efficiencies of 90 percent or more.




A three-phase overhead distribution transformer is shown in the figure below. Where pole mounted overhead distribution is used to supply three-phase power, three-phase transformers occupy less space than a bank of transformers, and they weigh less.

Moreover, the cost of installation and maintenance is lower for a three-phase overhead transformer than for a bank of three single-phase units.

Three-phase overhead transformers are made with ratings from 30 to 300 kVA. Primary voltages range from 4.16 to 34.5 kV, and secondary voltages range from 120 to 480 V.

The basic impulse level (BIL) ratings are 45 to 150 kV. They are available with wye, delta, or T–T connections. These transformers have four output connections, X0, X1, X2, and X3, and their cases are filled with electrical-grade mineral oil.

These transformers are manufactured in ratings from 45 to 7500 kVA with high-voltage ratings from 2.4 to 46 kV. The standard connections are delta–wye, grounded wye–wye, delta–delta, wye–wye, and wye delta.

The transformers are housed in steel cabinets with front-opening, three-point latching steel doors. As in the overhead transformers, the cases of pad-mounted transformers are filled with electrical-grade mineral oil.



For increasing voltage at the end of lines or to step up voltage where line extensions are being added to existing lines, such as from 6900 VAC to 7200 VAC. Cost per kva output is less than a two-winding transformer; losses are low, regulation is good, and exciting current is low. Voltage transformation greater than 3 to 1 is not recommended.

When the ratio of transformation from the primary to secondary voltage is small, the most economical way of stepping down the voltage is by using autotransformers as shown. For the application, it is necessary that the neutral of the auto transformer bank be connected to the system neutral. Brand circuits shall not be supplied by autotransformers.

Susceptive to burnouts if the system impedance is not great enough to limit the short-circuit current to 20 to 25 times the transformer-rated current. The primary neutral should be tied firmly to the system neutral; otherwise, excessive voltages may develop on the secondary side.

A considerable saving in cost may often be experienced by using autotransformers instead of two-winding transformers. When it is desired to affect a small change in voltage, or where both high and low voltages are low, there is usually no reason why an autotransformer cannot be used as successfully as a two-winding transformer.

Autotransformers should not, except under special conditions, be used where the difference between the high-voltage and low-voltage ratings is great. This is because the occurrence of grounds at certain points will subject the insulation on the low-voltage circuit to the same stress as the high-voltage circuit.

Autotransformers are rated on the basis of output KVA rather than the transformer KVA. Efficiencies, regulation and other electrical characteristics are also based on output rating.



For supplying three-phase, 240-volt loads with small amounts of 120/240-volt, single-phase load. No problem from third harmonic overvoltage or telephone interference. With a disabled unit, bank can be reconnected in open-delta for emergency service.

This connection is often used to supply a small single-phase lighting load and three-phase power load simultaneously. As shown is diagram, the mid-tap of the secondary of one transformer is grounded.

Thus, the small lighting load is connected across the transformer with the mid-tap and the ground wire common to both 120 volt circuits. The single-phase lighting load reduces the available three-phase capacity. This connection requires special watt-hour metering and is not available from all utilities.


The transformer with the mid-tap carries 2/3 of the 120/240-volt, single-phase load and 1/3 of the 240-volt, three-phase load. The other two units each carry 1/3 of both the 120/240- and 240-volt loads.

High circulating currents will result unless all units are connected on same regulating taps and have same voltage ratios. Bank rating is reduced unless matching impedance transformers are used. The secondary neutral bushing can be grounded on only one of the three transformers.

When three transformers are operated in a closed-delta bank, care should be taken to make certain the impedances of the three units are practically the same. Transformers having more than 10% difference in impedance rating should not be operated together in a closed-delta bank unless a reactor is used to increase the impedance of the unit having the lower impedance rating to a value equal to the other units.

If the voltage ratio of all three of the transformers is not the same, there will be a voltage tending to circulate current inside the delta. The current will be limited by the impedance of the three transformers considered as a series circuit.

It is a good practice, before applying voltage to three transformers in closed delta, to insert a fuse wire between the leads coming from the high-voltage bushings of two transformers closing the delta bank. The fuse wire should be of sufficient size to carry the exciting current of the transformers.

The use of this fuse wire offers a very simple means of making certain the transformers have the proper polarity.
This connection should not be used with CSP transformers if used to supply a combined three-phase and three-wire single-phase load due to unequal voltage division of single-phase load when the tapped transformer breaker is opened.

NEC 2002: 110.15 High-Leg Marking.
On a 4-wire, delta-connected system where the midpoint of one phase winding is grounded to supply lighting and similar loads, the conductor or busbar having the higher phase voltage to ground shall be durably and permanently marked by an outer finish that is orange in color or by other effective means. Such identification shall be placed at each point on the system where a connection is made if the grounded conductor is also present.

NEC 2002 Handbook:
Added for the 2002 Code, this section now contains a requirement that appeared in 384-3(e) of the 1999 NEC. This requirement was moved to Article 110, where the application becomes a more general requirement.

The high leg is common on a 240/120-volt 3-phase, 4-wire delta system. It is typically designated as “B phase.” The high-leg marking is required to be the color orange or other similar effective means and is intended to prevent problems due to the lack of complete standardization where metered and non-metered equipment are installed in the same installation. Electricians should always test each phase relative to ground with suitable equipment to determine exactly where the high leg is located in the system.

NEC 2002: 408.3 / Support and Arrangement of Busbars and Conductors / (E) Phase Arrangement
The phase arrangement on 3-phase buses shall be A, B, C from front to back, top to bottom, or left to right, as viewed from the front of the switchboard or panelboard.

The B phase shall be that phase having the higher voltage to ground on 3-phase, 4-wire, delta-connected systems. Other busbar arrangements shall be permitted for additions to existing installations and shall be marked.

Exception: Equipment within the same single section or multisection switchboard or panelboard as the meter on 3-phase, 4-wire, delta-connected systems shall be permitted to have the same phase configuration as the metering equipment.

FPN: See 110.15 for requirements on marking the busbar or phase conductor having the higher voltage to ground where supplied from a 4-wire, delta-connected system.

NEC 2002 Handbook:
The high leg is common on a 240/120-volt, 3-phase, 4-wire delta system. It is typically designated as “B phase.” Section 110.15 requires the high-leg marking to be the color orange or other similar effective means of identification. Electricians should always test each phase to ground with suitable equipment in order to know exactly where this high leg is located in the system.

The exception to 408.3(E) permits the phase leg having the higher voltage to ground to be located at the right-hand position (C phase), making it unnecessary to transpose the panelboard or switchboard busbar arrangement ahead of and beyond a metering compartment. The exception recognizes the fact that metering compartments have been standardized with the high leg at the right position (C phase) rather than in the center on B phase.

See also 110.15, 215.8, and 230.56 for further information on identifying conductors with the higher voltage to ground. Other busbar arrangements for making additions to existing installations are permitted by 408.3(E).



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.

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.



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.



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.



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 ��

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.



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.



How Transformer Tap Changer Control Works?

The tap-changing mechanism is usually motor-driven and can be controlled manually and automatically. In the automatic mode, the output voltage of the transformer is compared to a reference voltage and a raise/lower signal is sent to the tap changer motor when the output voltage falls outside a specified band, called a dead band.

The dead band must not be smaller than the voltage between taps; otherwise, it will ‘‘hunt’’ endlessly and burn up the tap changer. The dead band must not be too wide, however, because the purpose of voltage regulation will be defeated.

Ordinarily, the dead band is set to a voltage between two and three tap increments. With the tap voltage typically around 1% of the nominal secondary voltage, this provides regulation within a 2–3% range.

If two or more transformers with load tap changers are connected in parallel, then it is important that all transformers operate at the same transformer turns ratio; otherwise, excessive circulating KVAR results. The way this is implemented is to have the tap changer on one of the parallel transformers control voltage as the lead tap changer, with the other tap changers as the followers.

Circuitry is installed on the followers to sense the direction of reactive power flow through each transformer. If too much reactive power is flowing from the primary to the secondary, then its secondary taps are lowered.

If too much reactive power is flowing from the secondary to the primary, then secondary taps are raised. Appropriate dead bands are established to prevent the LTCs from hunting and to limit interactions among the tap changer controls.

One such control scheme, called a load-balancing method, is depicted in Figure 6.16 for three transformers with voltage regulators supplying a common load bus.

  FIGURE 6.16 A load-balancing control scheme for three parallel transformers with load tap changers.

If the three transformer impedances equal and if the transformers are set on the proper tap positions, the transformer secondary currents will all be in phase with the load current and there will be no current unbalance.

If one or more transformer is set on the wrong tap, circulating currents will flow in all three transformers. The principle of operation of the load-balancing method is to separate each of the transformer secondary currents into a load current component and a circulating-current component. The transformer secondary currents flow through current transformers, labeled CT 1, CT 2, and CT 3 in Figure 6.16.

The currents at the CT secondaries split into two paths at each of the CT secondary windings. Path 1 (to the right) goes through a set of auxiliary transformers, labeled CT 4, CT 5, and CT 6. The secondaries of the auxiliary CTs are connected in series, forcing the currents in all three primary windings equal one another, each being one-third of the total load current. By default, the unbalance-current components must flow in path 2 to the left.

Each of the circulating-current components (also called unbalanced current components) flows through an inductive reactance element, called a paralleling reactor. The paralleling reactors are labeled jX in Figure 6.16. In general, the unbalance-current components of the three transformers are unequal.

The voltages developed across the paralleling reactors are added to the sensed voltages at the secondary windings of the main transformers, which are used to control the movement of the tap changers.

If transformer 1 is on a higher tap position than transformer 2 or transformer 3, the unbalanced currents flowing through the parallel reactors increase the sensed voltage at transformer 1 and reduce the sensed voltages at transformers 2 and 3.

This causes transformer 1 to lower its taps and transformers 2 and 3 to raise their taps. If transformer 1 is on a lower tap position than transformers 2 and 3, the unbalanced currents flowing through the parallel reactors decrease the sensed voltage at transformer 1 and increase the sensed voltages at transformers 2 and 3. This causes transformer 1 to raise its taps and transformers 2 and 3 to lower their taps.



Various research organizations, such as Westinghouse Electric Corporation, Analytical Associates, Inc., that did extensive research in the 1970s quickly led to the widespread use of dissolved gas-in-oil analysis as a predictive maintenance tool [4]. There is also an extensive bibliography on this subject found in IEEE Std. C57.104–1991 [5].

The basic theory is straightforward: Transformer dielectric fluids are refined from petroleum and are very complex mixtures containing aromatic, naphthenic, and paraffinic hydrocarbons. At high temperatures, some of these molecules break down into hydrogen plus small hydrocarbon molecules such as, methane, ethane, ethylene, acetylene, propane, and propylene. This process is known as cracking.

The kraft paper materials that are used to insulate transformer windings are made up of cellulose. At high temperatures, cellulose oxidizes to form carbon dioxide (CO2), carbon monoxide (CO) and water (H2O). High concentrations of CO2 and or CO are indications of overheated windings.

All of the breakdown products are gases that dissolve readily in transformer oil in different concentrations, depending on the specific gas and the temperatures that produce them. By taking samples of transformer insulating oil, extracting the dissolved gases and doing a quantitative analysis of the various gases in the samples through gas chromatography, it is possible to infer the temperatures at the sites where these gases were produced.

At temperatures below 150°C, transformer oil starts breaking down into methane (CH4) and ethane (C2H6). At temperatures above 150°C, ethylene (C2H4) begins to be produced in large quantities while the concentration of ethane decreases.

At around 600°C, the ethylene production peaks while the concentration of methane continues to increase. Acetylene (C2H2) production starts at around 600°C and methane concentration peaks at 1000°C. Hydrogen (H2) production is not significant below 700°C and continues to increase along with acetylene at temperatures above 1400°C.

Therefore, the relative concentrations of the key gases change over a wide range of temperature. This is basis for the application of dissolved gas in-oil analysis for predictive and diagnostic use. An approximate formula uses the ratio of C2H4/C2H6 to derive the temperature of oil decomposition between 300°C and 800°C:

T(°C) = 100 C2H4/C2H6 + 150

The so-called Rogers ratio method takes the ratios of several key gases into account to develop a code that is supposed to give an indication of what is causing the evolution of gas. The codes for the four ratio method are given in Table 8.2. A fairly detailed diagnosis of transformer trouble can be derived from various combinations of codes, shown in Table 8.3.

The diagnoses shown above were derived from empirical observation. The problem with the four-ratio Rogers code is that a code generated from the gas concentrations will often not match any of the ‘‘known’’ diagnoses.

So like a rare disease with strange symptoms, many cases of transformer trouble cannot be diagnosed at all using this method. Another method, called the three-ratio method, sometimes works when the four-ratio method does not.

In the three-ratio method, the values of A, B, and C are given in Table 8.4 with the corresponding diagnoses for the various combinations given in Table 8.5. Not only are the ratios of the key gases important, but the total quantity of dissolved gas and the rate of increase are also important factors in making a diagnosis. One of the criteria for making a judgment call is the total combustible gas concentration. The combustible gases include H2, CH4,

C2H4, C2H6, C2H2, which are produced by oil decomposition, and CO, which is produced by cellulose decomposition. Each utility has a different philosophy and a different threshold for concern.

Table 8.6 gives one set of guidelines based on good utility practice that is useful for determining the overall health of a power transformer based on the total concentration of combustible gases.

It is generally accepted that if the rate of combustible gas generation exceeds 100 ppm per day on a continuing basis, or if the presence of C2H2 exceeds 20 ppm, then consideration should be given to taking the transformer out of service to perform additional tests and inspection.

IEEE Std. C57.104-1991 Table 3 also provides a set of actions based on the total dissolved combustible gas (TDCG) concentrations as well as the daily rate of TDCG production.

According to the IEEE Guide, a rate of 30 ppm per day is the threshold for considering removing the transformer from service. Oil samples are taken from the bottom drain valve in a sealed syringe to prevent the dissolved gases from escaping.

The samples are sent to a chemical laboratory where the dissolved gases are extracted from the sample under vacuum and analyzed using a gas chromatograph. The results are reported as ppm dissolved in oil.




The theoretically ideal conditions for paralleling transformers are:

1. Identical turn ratios and voltage ratings.

2. Equal percent impedances.

3. Equal ratios of resistance to reactance.

4. Same polarity.

5. Same phase angle shift.

6. Same phase rotation.

Single-Phase Transformers
For single-phase transformers, only the first four conditions apply, as there is no phase rotation or phase angle shift due to voltage transformation.

If the turns ratio are not same a circulating current will flow even at no load. If the percent impedance or the ratios of resistance to reactance are different there will be no circulating current at no load, but the division of load between the transformers when applied will no longer be proportional to their KVA ratings.

Three-Phase Transformers
The same conditions hold true for three phase transformers except that in this case the question of phase rotation and phase angle shift must be considered.

Phase Angle Shift
Certain transformer connections as the wye-delta or wye-zigzag produce a 30º shift between the line voltages on the primary side and those on the secondary side. Transformers with these connections cannot be paralleled with other transformers not having this shift such as wye-wye, delta-delta, zigzag-delta, or zigzag-zigzag.

Phase Rotation
Phase rotation refers to the order in which the terminal voltages reach their maximum values. In paralleling, those terminals whose voltage maximums occur simultaneously are paired.
Power Transformer Practice

The preceding discussion covered the theoretically ideal requirements for paralleling. In actual practice, good paralleling can be accomplished although the actual transformer conditions deviate by small percentages from the theoretical ones.

Good paralleling is considered attainable when the percentage impedances of two winding transformers are within 7.5% of each other. For multi-winding and auto-transformers, the generally accepted limit is 10%.

Furthermore, in power transformers of normal design the ratio of resistance to reactance is generally sufficiently small to make the requirement of equal ratios of negligible importance in paralleling.

When it is desired to parallel transformers having widely different impedances, reactors or auto-transformers having the proper ratio should be used. If a reactor is used it is placed in series with the transformer whose impedance is lower. It should have a value sufficient to bring the total effective percent impedance of the transformer plus the reactor up to the value of the percent impedance of the second transformer.

When an auto-transformer is used, the relative currents supplied by each transformer are determined by the ratio of the two sections of the auto-transformer. The auto-transformer adds a voltage to the voltage drop in the transformer with the lower impedances and subtracts a voltage from the voltage drop in the transformer with the higher impedance. Auto-transformers for use in paralleling power transformers are specially designed for each installation. The wiring diagram showing the method of connecting the auto-transformer is usually furnished.

In general, transformers built to the same manufacturing specifications as indicated by the nameplate may be operated in parallel.

Connecting transformers in parallel when the low voltage tension is comparatively low requires care that the corresponding connecting bars or conductors have approximately the same impedance. If they do not, the currents will not divide properly.

Information Courtesy of ABB Power Transformers
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