Protective Maintenance Of Power Transformers Tips and Tutorials

Protective Maintenance
This philosophy consists of performing preventive maintenance, predictive maintenance, and corrective maintenance. The preventive maintenance involves schedule maintenance and testing on a regular basis.

Predictive maintenance involves additional monitoring and testing, where as corrective maintenance involves repairing and restoring transformer integrity to its original condition when degraded conditions are discovered.

The objective of the protective maintenance of transformers is to control and prevent severe oil and winding (paper) insulation deterioration. Mineral oil and paper insulation of the winding are affected by moisture, oxygen, heat, and other catalytic agents such as copper, iron, electric stress, and so on.

The end result is that oxidation takes place in the oil which leads to sludging of the transformer. In sealed units ingress of moisture via atmosphere or seal leaks must be prevented.

Moisture will reduce the dielectric strength of both the oil and the winding insulation systems. In addition, excessive heating of the transformer will cause the paper (winding insulation) to decompose (accelerate aging) which in-turn produces moisture (i.e., break up of cellulose fi bres results in freeing hydrogen and oxygen atoms which combine to form H2O).

Increased moisture formed in the paper not only reduces the insulating strength of the paper but also, as temperature rises, the moisture will migrate from the paper insulation to the oil and decreasing its dielectric strength.

The first step is to build transformer designs to keep moisture and oxygen out of transformers. The next step is to operate transformers so that they are not operated beyond their temperature ratings and limits.

In addition to the above, the severity of deterioration should be controlled by monitoring and testing transformer insulation systems on periodic basis, and take corrective actions to restore transformer to its original condition.

This philosophy can be summarized by the following:

1. Control transformer heat
2. Inspect and maintain transformer auxiliary devices
3. Test and maintain transformer insulation systems
4. Maintain transformer bushing insulation
5. Maintain transformer protective coating



How To Contain Transformer Oils?

Oil containment
Even where the more traditional system of chippings and sump is used as a base for the transformer compound, consideration will need to be given to the possibility of loss of all the oil from the transformer tank and its cooler. Suitable provision must be made to ensure that this will not enter drains or water courses.

Such provision will normally be by means of a bund wall surrounding the transformer and its cooler which together with any sump must be capable of containing the total oil quantity in addition to the maximum likely rainfall over the area.

Since the bunded area will under normal operating conditions need provision for storm water drainage, then suitable oil interception arrangements must be made for separation and holding any oil released.

Segregation and separation

Where it is not economic to consider the type of elaborate measures described above, then other design features must be incorporated to allow for the possibility of fire. Such features involve segregation or separation of equipment.

Separation involves locating the transformer at a safe distance from its standby, where one is provided, or any other plant and equipment which must be protected from the fire hazard. A distance of 10 metres is usually considered to be sufficient.

This means that not only must the transformer be a minimum of 10 metres from its standby, but all connections and auxiliary cabling and services must be separated by at least this distance.

On most sites such an arrangement will be considered too demanding of space, so this leads alternatively to the use of a system of segregation, which relies on the use of fire-resistant barriers between duty and standby plant and all their associated auxiliaries.

The integrity of the barrier must be maintained regardless of how severe the fire on one transformer or of how long the fire persists. In addition the barrier must not be breached by an explosion in one of the transformers, so it will normally be necessary to construct it from reinforced concrete and of such an extent that flying debris from one transformer cannot impinge on any equipment, including bushings, cables, cooler and cooler pipework or switchgear associated with its standby.

Generally for access reasons transformers should be at least 1 metre from any wall but this space may need to be increased to allow for cooling air.



What Are The Harmonics And DC Effects Of Distribution Transformers?

Harmonics and DC Effects
Rectifier and discharge-lighting loads cause currents to flow in the distribution transformer that are not pure power-frequency sine waves. Using Fourier analysis, distorted load currents can be resolved into components that are integer multiples of the power frequency and thus are referred to as harmonics.

Distorted load currents are expected to be high in the 3rd, 5th, 7th, and sometimes the 11th and 13th harmonics, depending on the character of the load.

Odd-Ordered Harmonics
Load currents that contain the odd-numbered harmonics will increase both the eddy losses and other stray losses within a transformer. If the harmonics are substantial, then the transformer must be derated to prevent localized and general overheating.

ANSI standards suggest that any transformer with load current containing more than 5% total harmonic \ distortion should be loaded according to the appropriate ANSI guide (IEEE, 1998).

Even-Ordered Harmonics
Analysis of most harmonic currents will show very low amounts of even harmonics (2nd, 4th, 6th, etc.) Components that are even multiples of the fundamental frequency generally cause the waveform to be nonsymmetrical about the zero-current axis.

The current therefore has a zeroth harmonic or dc-offset component. The cause of a dc offset is usually found to be half-wave rectification due to a defective rectifier or other component.

The effect of a significant dc current offset is to drive the transformer core into saturation on alternate half-cycles. When the core saturates, exciting current can be extremely high, which can then burn out the primary winding in a very short time.

Transformers that are experiencing dc-offset problems are usually noticed because of objectionably loud noise coming from the core structure. Industry standards are not clear regarding the limits of dc offset on a transformer.

A recommended value is a dc current no larger than the normal exciting current, which is usually 1% or less of a winding’s rated current (Galloway, 1993).



Will A 60 Hz Transformers Work at 50 Hz? Answers and Links

Transformers rated below 1 KVA cab be used on 50 Hz service. Transformers 1 KVA and larger, rated at 60 Hz, should not be used on 50 Hz service due to the higher losses and resultant heat rise. Special designs are required for this service. However, any 50 Hz transformer will operate on a 60 Hz service.

Other Answers and Opinion on this query can be found below:

Can transformers be operated at various frequencies?
A 60 Hz design is normally smaller than a 50 Hz design. For kind information please DO NOT use 60 Hz rated transformers on 50 Hz service. Without exacting designs, higher losses and greater heat rise will result. Operating 60 Hz transformers at higher frequencies may simply give less voltage regulation.

Source: http://www.custompowertransformer.com/Faq.html

Can 60 Hz transformers be used on 50 Hz?
Yes. 60 Hz transformers can be used on 50 Hz if special precautions are taken. The change in frequency will impact the flux density of the transformer causing it to run hot, as if it were overloaded. To offset this effect, you must decrease the input voltage by approximately 17% (1/6th). This means that a transformer rated for a 480 Volt, 60 Hz input could run at 50 Hz but with a maximum input voltage of 398 volts.

Source: http://www.experts123.com/q/can-60-hz-transformers-be-used-on-50-hz.html

Can 60 Hz transformers be operated at 50 Hz?
Transformers 1 KVA and larger, rated at 60 Hz, should not be used on 50 Hz service due to higher losses and resultant heat rise. However, any 50 Hz transformer will operate on 60 Hz service.

Source: http://www.mgmtransformer.com/faq/can-60-hz-transformers-be-operated-at-50-hz/

You might ask, why is it that there is a variation in frequency?

History, politics, and science is the reason. To know what we mean, visit this site for a well thought answers. http://www.school-for-champions.com/science/ac_world_volt_freq.htm



What Are Good Practices In Storage Of Transformer Parts?

Utility companies have enormous amounts of money invested in transformers of all types, including distribution and power transformers. Utilities also have a long history and have developed methods, procedures, and philosophies that over time have proven very effective in prolonging equipment life.

These are collectively referred to as good utility practices and it is instructive to review these practices as applied to power transformers. In particular, this is one of the best practices in storage of transformer parts.

Bushings, radiators, or other accessories removed from transformers should be tagged by the person removing them to identify the transformer from which they are removed.

Storing Transformers

• Place transformers on sound footing in a safe or protected area.

• Seal all openings where accessories have been removed with steel shipping covers.

• Gaskets should be installed with cover plates.

• All sealed transformers should be purged and pressurized with dry nitrogen for short term storage less than 6 months.

• Refer to manufacturer’s instruction book for specific instructions on storing transformers in oil or nitrogen.

Storing Bushings

• Bushings should be left in transformer if possible.

• If removed, store bushings in a clean, dry place indoors, protected from damage. Oil-filled bushings can be stored in an open area protected from weather.

• Preferred storage of oil-filled bushings is vertical, but oil reservoirs must be elevated at least 10 in. above bottom bushing stud (or other height specified in instruction book).

Storing Radiators and Other Accessories

• All openings on detached radiators must be sealed from moisture and the radiators stored so water cannot stand around the sealed openings.

• Protect all accessories from damage, moisture, and foreign materials.



What Is The Health and Environmental Care Procedure For Transformer Oils?

Health issues
Users should obtain a Material Safety Data Sheet (MSDS) for each dielectric fluid in use. Where instructions differ from recommendations made here, the instructions of the manufacturer are to be followed.

Although there is no special risk involved in the normal handling of insulating fluids addressed in this guide, attention should be focused to the general need for personal hygiene or the practice of washing skin and clothing that may have come in contact with insulating oil. Personnel should avoid contact of the fluid with their eyes.

When dielectric liquids have to be disposed of, certain precautions are necessary to comply with local, state, and federal requirements in the United States. These oils are generally classified as special, regulated or hazardous waste depending upon the individual state.

The following procedures are not intended to supersede local, state, or federal regulations. Unless a PCB analysis has been performed, it is prudent to assume that the batch of oil contains PCBs and to act accordingly. The absence of PCBs in a volume of oil in or from a piece of equipment can be established only by analysis of that oil.

Leaks and spills
During equipment inspection or servicing, routine checks should be made of the equipment and surroundings for leaks. Areas to check and repair should include valves, bushings, gauges, tap changers, welds, sample ports, manhole covers, pipe fittings, pressure relief valves, etc. The user is referred to IEEE Std 980-1994.

New transformer oil as received from a refiner is very unlikely to contain PCBs. However, many older transformers and other pieces of electrical equipment in service are filled with mineral insulating oil that contains PCBs.

Since 1977, various federal, state, and local environmental regulations have governed the handling and processing of mineral oils containing PCBs. While these regulations can add substantially to the complexity of spill cleanup and disposal of oils, they should not be disregarded.

Minor spills
Minor spills, such as those occurring in the manufacture or repair of equipment, can be cleaned using absorbent rags or other materials.

Spills on soil
Soil acts as an absorbent and should not be allowed to become saturated with mineral insulating oil. Users should consult the applicable local, state, and federal guidelines in the United States for spills of mineral oil onto soil and the remedies available. Depending on state and local regulations, spills to soil may have to be reported to one or more regulatory agencies.

Spills on water
Because mineral insulating oils float on water, a spill can be contained by using floating booms or dikes. Section 311 of the Federal Water Pollution Control Act as amended, 33 U.S.C. 1251 et seq, also known as the Clean Water Act as found in Title 40 Code of Federal Regulations Part 110, imposes reporting requirements for petroleum oils that are spilled into navigable water ways.

The requirement to report is triggered by the appearance of a sheen on the surface of the water. If a sheen is noted, the U. S. Coast Guard must be notified, as well as the National Response Center.

Once the mineral oil has been concentrated, it can be removed from the surface of the water by systems that are normally used for petroleum spills. These include pumps, skimmers, physical absorbents, and fibers that are fabricated into floating ropes.

NOTE—If spilled mineral insulating oils are known or assumed to contain any concentration of PCBs, they must be treated as a PCB containing liquid. Also refer to the Spill Policy Guide of the Environmental Protection Agency (see PCBs 761.120, Title 40 Code of Federal Regulations Part 761).



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.



What Are The Inrush Current Consideration For Power Transformers?

Two distinctly different definitions for inrush current have been offered because one definition cannot serve all the purposes where inrush current is of interest.

Inrush Current:
is the maximum root-mean-square or average current value, determined for a specified interval, resulting from the excitation of the transformer with no connected load, and with essentially zero source impedance, and using the minimum primary turns tap available and its rated voltage.

Peak Inrush Current:
is the peak instantaneous current value resulting from the excitation of the transformer with no connected load, and with essentially zero source impedance, and using the minimum turns primary tap and rated voltage.

Magnetic and thermal cut-out devices usually are not responsive to one-half cycle of energy regardless of magnitude, hence two or more half cycles are needed to define the trip-out characteristics. Furthermore, these devices are not responsive to peak values, but rather to energy content. (I2 t) becomes the parameter of interest, using root-meansquare current values for fusing characteristics.

Relays and magnetic cut-outs are responsive to the average current value. Therefore, when inrush current is cited it should be made clear which of the two values (root mean square) (average) is indicated.

It should be noted that the inrush current of a transformer is seldom the same value as the steady-state exciting current, but is typically larger and decays to steady state after several cycles, depending on the condition of the core, the instantaneous value of applied voltage, etc.

It is important to consider this asymmetry of inrush current in the design and use of transformers and particularly in the specification of protective devices for the transformer. Maximum inrush current values occur when a transformer core that has an existing maximum residual flux is switched on at zero instantaneous voltage so the residual flux and the instantaneous magnetizing flux are additive.

Circuits are available using silicon controlled rectifier switching to cause this to happen deliberately. Alternately, random switch on twenty or more times will usually produce a near maximum value for a single-phase transformer.

It may take more times for a three-phase transformer unless all three lines are monitored. For the measurement of root-mean-square or average current it is necessary to use an adequate X-axis spread or chart speed so that curve area per cycle can be measured.

Peak inrush current values are of interest in connection with contact welding problems and with devices sensitive to instantaneous current magnitude. The measurement of true inrush current with any degree of accuracy can be very difficult because of the usual nonavailability of zero source impedance power lines for larger systems.

This problem can best be circumvented when the installed source capacity is known and specified in terms of impedance and phase angle, and rated capacity.

These values can then be used in test or computation to determine the installed inrush characteristics of a system which, of course, is the final value of interest. When inrush current values are presented for conditions other than essentially zero source impedance, the actual source impedance values applicable to the data should also be given.



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.



What Are Transformer Bushing? Functions Of Transformer Bushing?

Bushings may be classified generally by design as follows:
a) Condenser type
1) Oil-impregnated paper insulation, with interspersed conducting (condenser) layers or oil impregnated paper insulation, continuously wound with interleaved lined paper layers
2) Resin-bonded paper insulation, with interspersed conducting (condenser layers)

b) Noncondenser type
1) Solid core or alternate layers of solid and liquid insulation
2) Solid mass of homogeneous insulating material (e.g., solid porcelain)
3) Gas filled

For outdoor bushings, the primary insulation is contained in a weatherproof housing, usually porcelain. The space between the primary insulation and the weathershed is generally filled with an insulating oil or compound (also, plastic and foam).

Some of the solid homogenous types may use oil to fill the space between the conductor and the inner wall of the weathershed. Bushings may also use gas such as SF6 as an insulating medium between the center conductor and outer weathershed.

Bushings may be further classified generally as being equipped or not equipped with a potential tap or power-factor test tap or electrode. Note Potential taps are sometimes also referred to as capacitance or voltage taps.)

The bushing, without a potential tap or power-factor tap, is a two-terminal device that is generally tested overall (center conductor to range) by the GST method. If the bushing is installed in an apparatus, such as a circuit breaker, the overall GST measurement will include all connected and energized insulating components between the conductor and ground.

A condenser bushing is essentially a series of concentric capacitors between the center conductor and the ground sleeve or mounting range. A conducting layer near the ground sleeve may be tapped and brought out to a tap terminal to provide a three-terminal specimen.

The tapped bushing is essentially a voltage divider and, in higher voltage designs, the tap potential may be utilized to supply a bushing potential device for relay and other purposes. In this design the potential tap also acts as a low-voltage power-factor test terminal for the main bushing insulation, C1.

Modern bushings rated above 69 kV are usually equipped with potential taps. (In some rare instances 69 kV bushings were equipped with potential taps.) Bushings rated 69 kV and below may be equipped with power factor taps.

In the power-factor tap design, the ground layer of the bushing core is tapped and terminated in a miniature bushing on the main bushing mounting range. The tap is connected to the grounded mounting range by a screw cap on the miniature bushing housing.

With the grounding cap removed, the tap terminal is available as a low-voltage terminal for a UST measurement on the main bushing insulation, C1, conductor to tapped layer.



What Are Transformer Losses Components?

Transformer Losses is a natural occurrence in the Power System Cycle. Below are the different components of the Transformer Losses.

No-Load Loss and Exciting Current
When alternating voltage is applied to a transformer winding, an alternating magnetic flux is induced in the core. The alternating flux produces hysteresis and eddy currents within the electrical steel, causing heat to be generated in the core. Heating of the core due to applied voltage is called no-load loss.

Other names are iron loss or core loss. The term “no-load” is descriptive because the core is heated regardless of the amount of load on the transformer. If the applied voltage is varied, the no-load loss is very roughly proportional to the square of the peak voltage, as long as the core is not taken into saturation.

The current that flows when a winding is energized is called the “exciting current” or “magnetizing current,” consisting of a real component and a reactive component. The real component delivers power for no-load losses in the core.

The reactive current delivers no power but represents energy momentarily stored in the winding inductance. Typically, the exciting current of a distribution transformer is less than 0.5% of the rated current of the winding that is being energized.

Load Loss
A transformer supplying load has current flowing in both the primary and secondary windings that will produce heat in those windings. Load loss is divided into two parts, I2R loss and stray losses.

I2R Loss
Each transformer winding has an electrical resistance that produces heat when load current flows. Resistance of a winding is measured by passing dc current through the winding to eliminate inductive effects.

Stray Losses
When alternating current is used to measure the losses in a winding, the result is always greater than the I2R measured with dc current. The difference between dc and ac losses in a winding is called “stray loss.”

One portion of stray loss is called “eddy loss” and is created by eddy currents circulating in the winding conductors. The other portion is generated outside of the windings, in frame members, tank walls, bushing flanges, etc.

Although these are due to eddy currents also, they are often referred to as “other strays.” The generation of stray losses is sometimes called “skin effect” because induced eddy currents tend to flow close to the surfaces of the conductors.

Stray losses are proportionally greater in larger transformers because their higher currents require larger conductors. Stray losses tend to be proportional to current frequency, so they can increase dramatically when loads with high-harmonic currents are served. The effects can be reduced by subdividing large conductors and by using stainless steel or other nonferrous materials for frame parts and bushing plates.

Harmonics and DC Effects
Rectifier and discharge-lighting loads cause currents to flow in the distribution transformer that are not pure power-frequency sine waves. Using Fourier analysis, distorted load currents can be resolved into components that are integer multiples of the power frequency and thus are referred to as harmonics. Distorted load currents are expected to be high in the 3rd, 5th, 7th, and sometimes the 11th and 13th harmonics, depending on the character of the load.

Odd-Ordered Harmonics
Load currents that contain the odd-numbered harmonics will increase both the eddy losses and other stray losses within a transformer. If the harmonics are substantial, then the transformer must be derated to prevent localized and general overheating.

ANSI standards suggest that any transformer with load current containing more than 5% total harmonic distortion should be loaded according to the appropriate ANSI guide (IEEE, 1998).

Even-Ordered Harmonics
Analysis of most harmonic currents will show very low amounts of even harmonics (2nd, 4th, 6th, etc.) Components that are even multiples of the fundamental frequency generally cause the waveform to be nonsymmetrical about the zero-current axis.

The current therefore has a zeroth harmonic or dc-offset component. The cause of a dc offset is usually found to be half-wave rectification due to a defective rectifier or other component. The effect of a significant dc current offset is to drive the transformer core into saturation on alternate half-cycles.

When the core saturates, exciting current can be extremely high, which can then burn out the primary winding in a very short time. Transformers that are experiencing dc-offset problems are usually noticed because of objectionably loud noise coming from the core structure.

Industry standards are not clear regarding the limits of dc offset on a transformer. A recommended value is a dc current no larger than the normal exciting current, which is usually 1% or less of a winding’s rated current (Galloway, 1993).



How To Match Transformers For Banking and Parallel Operation?

The following rules must be obeyed in order to successfully connect two or more transformers in parallel with each other:

1. The turns ratios of all of the transformers must be nearly equal.
2. The phase angle displacements of all of the transformers must be identical.
3. The series impedances of all transformers must be nearly equal, when expressed as ‘‘%Z’’ using the transformer impedance base.

The first two rules are required so that the open-circuit secondary voltages of the transformers are closely matched in order to avoid excessive circulating currents when the parallel connections are made.

The last rule is based on the fact that for a given voltage rating and %Z, the ohmic impedance of a transformer is inversely proportional to its KVA rating. When transformers having the same %Z are connected in parallel, the load currents will split in proportion to the KVA ratings of the units.

Therefore, transformers with different KVA ratings can be successfully operated in parallel as long as their %Z values are all approximately the same.

(This example is based on an actual event.)
Two three-phase 10,000 KVA 66,000Δ-12,470Y volt transformers were in parallel operation in a substation. The primaries of the two transformers are connected to a 66 kV transmission line through a single air break switch.

This switch is designed to interrupt magnetizing current only, which is less than 1 A. The transformers were being removed from service and the secondary loads had been removed. A switchman then started to open the air break switch, expecting to see a small arc as the magnetizing current was interrupted.

Instead, there was a loud ‘‘bang’’ and there was a ball of flame where the air break switch contacts had vaporized. Something was obviously wrong.

Upon closer inspection, it was revealed that the two transformers had been set on widely different taps: The first transformer was on the 62,700 V primary tap and the second transformer was on the 69,300 V primary tap.

Both transformers had a 7% impedance. Because the turns ratios were unequal, a circulating current was set up even without any secondary load. The opencircuit secondary voltage difference, assuming 66 kV at the transformer primaries, is calculated below.

ΔEs = 66,000 x ( 12,470/ 62,700 - 12,470/69,300 ) V = 1250 V = 0.10 per unit

The per-unit circulating current in the secondary loop is equal to ΔEs divided by the sum of the per-unit impedances of the two transformers:

Ic = 0.10/ 0.14 = 0.714 per unit

Converting Ic into amperes:
Ic = 0.714 x 10,000 KVA/(12.47 kV 1.732) = 331 A per phase

Since Ic flows in a loop in the secondary circuit, the current out of the secondary of the first transformer equals the current into the secondary of the second transformer. But since the turns ratios are not equal, Ic does not get transformed into equal and opposite currents at the primaries.

Primary current of first transformer
65.8 A per phase
Primary current of second transformer
59.6 A per phase
The net current through the air break switch, IAB, is the difference in the primary currents:
IAB 65.8 A per phase 59.6 A per phase 6.2 A per phase

The current through the air break switch supplies the I2c Xs reactive losses of both transformers and therefore lags the primary voltage by 90°. The resulting current exceeded the interrupting rating of the switch, causing it to fail.



What Are The Effects Of Short Circuits On Transformers?

Transformers are susceptible to damage by secondary short-circuit currents having magnitudes that can be many times rated load current. The damage results from the following effects:

• The I 2R losses in the winding conductors are increased by the square of the current. This increases the temperature rise of the windings.

Because protective devices limit the duration of short circuits (as opposed to overloads), the temperature rise of the winding can be calculated by dividing the total energy released by the I 2R losses by the thermal capacity of the conductor.

• The short-circuit currents exclude flux in the core and increase stray flux around the core. This stray flux induces currents in metallic parts other than the winding conductors, which can be damaged thermally.

• A short circuit applied to the secondary circuit of an autotransformer can substantially increase the voltage across the series winding and across the common winding through induction.

This not only presents the possibility of damaging the winding insulation by overvoltage, but will also drive the core into saturation and significantly increase core losses with potential damaging effects from temperature.

• Bushings and tap changers have current ratings that are usually only marginally greater than the rated load of the transformer.

Since fault currents are many times rated currents and these components have short thermal time constants, they can be seriously overloaded and thermally damaged.

• Stray flux in the vicinity of current-carrying conductors produces mechanical forces on the conductors. When a short circuit is applied to a transformer, there is a significant increase in stray flux, resulting in greater mechanical forces on the windings, leads, bushings, and all other current-carrying components.

These components, especially the windings, must be braced to withstand these forces.

A good transformer design must take all of the above effects into account to minimize the risk of damage and assure a long service life.



What Is The Equivalent Circuit Of A Three Winding Transformer?

Various forms of a three-winding transformer equivalent circuit have been proposed, but the simplest and most useful is the so-called T equivalent circuit, shown in Figure 4.9.

The magnetizing branch is omitted in the T equivalent since the magnetizing impedance is normally much greater than the series impedances. If voltages and impedances are expressed in per unit values, then the ideal transformers can sometimes be omitted also; however, in some cases 1:1 ideal transformers are retained so that the connections to the primary, secondary and tertiary circuits can be properly represented by the equivalent circuit.

In a three-winding transformer, eddy-current losses occur in each winding from stray flux produced by the other two windings, even if the third winding is not carrying any load. Therefore, each series resistance element in the T equivalent circuit of a three-winding transformer represent eddy-current losses produced by currents in other windings.

Hence, a series resistance does not belong to any particular winding but is distributed among all three widings. To derive the series impedance values in the T equivalent circuit, impedance measurements are made of each pair of windings taken two at a time.

One winding is short-circuited with voltage applied to the other winding while the third winding is open-circuited. The current is measured through the winding with the applied voltage. The impedance is equal to the applied voltage divided by that current.

The test setup to measure the impedance between the H and X windings of a single-phase three-winding transformer is shown in Figure 4.10.

The test for a three-phase, three-winding transformer is similar except that three-phase voltages are used. There are three sets of measurements taken. 

The first set of measurements applies a three-phase voltage to the H1, H2, and H3 terminals with the X1, X2, and X3 terminals shorted together and the Y1, Y2, and Y3 terminals open. 

The second set of measurements applies a three-phase voltage to the H1, H2, and H3 terminals with the Y1, Y2, and Y3 terminals shorted together and the X1, X2, and X3 terminals open. 

Finally, a three-phase voltage is applied to the X1, X2 and X3 terminals with the Y1, Y2, and Y3 terminals shorted together with the H1, H2, and H3 terminals open. The ZHX, ZHY, and ZXY impedance values are determined by dividing the voltages by the currents in each test. 


What Is Three Winding Transformer?

The three-winding transformer is a subset of multiwinding transformers. In addition to the usual primary and secondary windings, a third tertiary winding is added to each phase. Having three winding can serve several purposes:

• Three windings allow connecting three systems together where each system has a different operating voltage.

• Three windings provide electrical isolation between dual input circuits or dual output circuits having the same operating voltage.

• If the third winding is Δ-connected, this can stabilize voltages, supply third harmonic currents to magnetize the transformer core, filter third harmonics from the system, and provide grounding bank action when the primary and secondary windings are both Y-connected.

Sometimes a tertiary winding may serve more than one function at the same time. For example, a 13.8 kV Δ-connected tertiary winding on a 230 kV– 69 kV Grd.Y-Grd.Y transformer helps to stabilize the primary and secondary voltages, provides grounding bank action to partially shield the primary circuit from secondary ground currents, and provides 13.8 kV supply voltage to a station-service auxiliary transformer.

(Note: When a group of windings are connected in parallel to increase the current capability of a secondary winding, the parallel group is considered one winding and not several separate windings. Using multiple sets of low-voltage windings in parallel is common in large generator step-up transformers; however, these are still considered two winding transformers.)

Sometimes a tertiary winding is intended only to magnetically interact with the primary and secondary windings so it may not have any external terminal connections. In these cases, the tertiary winding is said to be an imbedded tertiary.

Imbedded tertiary windings are found only in three-phase transformers and are always Δ-connected. One corner of the Δ-connected imbedded tertiary winding is sometimes grounded internally to limit capacitively coupled voltages.

For single-phase transformers, the standard labels for the tertiary bushings are Y1 and Y2. For three-phase transformers, the standard labels for the tertiary bushings are (Y0), Y1, Y2, Y3.



What Are The Advantages And Disadvantages Of Autotransformer Connection?

Summarizing the advantages of the autotransformer connection:

 • There are considerable savings in size and weight.

• There are decreased losses for a given KVA capacity.

• Using an autotransformer connection provides an opportunity for achieving lower series impedances and better regulation.

Summarizing the disadvantages of the autotransformer connection:

• The autotransformer connection is not available with certain threephase connections.

• Higher (and possibly more damaging) short-circuit currents can result from a lower series impedance.

• Short circuits can impress voltages significantly higher than operating voltages across the windings of an autotransformer.

• For the same voltage surge at the line terminals, the impressed and induced voltages are greater for an autotransformer than for a two winding transformer.

In many instances, the advantages of the autotransformer connection outweigh its disadvantages.

For example, when very large MVA capability is required and where a Grd.Y-Grd.Y connection is suitable, an autotransformer is usually the design of choice.

Because an autotransformer cannot provide a Δ-Y connection, autotransformers are not suitable for use as generator step-up transformers.



What Are The Effects Of Poor Power Quality To Transformers?

Presence of harmonic current increases the core losses, copper losses, and stray-flux losses in a transformer. These losses consist of ‘no load losses’ and ‘load losses’. No load loss is affected mainly by voltage harmonics, although the increase of this loss with harmonics is small. It consists of two components: hysteresis loss (due to non-linearity of the transformers) and eddy current loss (varies in proportion to the square of frequency).

The load losses of a transformer vary with the square of load current and increase sharply at high harmonic frequencies. They consist of three components:

• Resistive losses in the winding conductors and leads
• Eddy current losses in the winding conductors
• Eddy current losses in the tanks and structural steelwork

Eddy current losses are of large concern when harmonic current is present in the network. These losses increase approximately with the square of frequency. Total eddy current losses are normally about 10% of the losses at full load. Equation (1) gives total load losses (PT) of a transformer when harmonics are present in the network [Hulshorst & Groeman, 2002].

PCU = total copper loss
PWE = eddy current losses at 50Hz (full load)
PCE1 = additional eddy current losses at 50Hz (full load)
PSE1 = stray losses in construction parts at 50Hz (full load)
In = rms current (per unit) at harmonic ‘n’
IL = total rms value of the load current (per unit)
I1 = fundamental component of load current (per unit) at 50Hz frequency
n = harmonic number

Other concern is the presence of ‘triple-n’ harmonics. In a network, mainly the LV nonlinear loads produce harmonics. With a MV/LV transformer of Δ/Y configuration, ‘triple-n’ currents circulate in the closed delta winding. Only the ‘non triple-n’ harmonics pass to the upstream network. 

When supplying non-linear loads, transformers are vulnerable to overheating. To minimize the risk of premature failure of transformers, they can either be de-rated or use as ‘K-rated’ transformer which are designed to operate with low losses at harmonic frequencies. Increased loading can cause overstressing of transformer and the chance of its premature failure. 

This effect is usually expressed in terms of ‘loss of lifetime’. The hot-spot temperature is used for evaluation of a relative value for the rate of thermal ageing as shown in Fig. 4.

 It is taken as unity for a hot-spot temperature of 98oC with the assumption of an ambient temperature of 20oC and hot-spot temperature rise of 78oC. Equation (2) shows the calculation of relative ageing rate (V) as a function of hot-spot temperature θh [Najdenkoski et al., 2007].




What Are Buchholz Relay? How Buccholz Relay Works?

The Buchholz Relay (Gas Relay) is designed to protect equipments submerged in insulating liquid, by means of supervision of the oil abse nce or abnormal flow, and abnormal gassing caused by the equipment. Buchholz relay is usually fitted on transformers provided with an expansion tank for the insulating liquid.

Buchholz Relay
Buchholz relay is capable to accurately detect, for example, the following problems: Leakage of insulating liquid, short - circuit inside the equipment causing a great displacement of insulating liquid, inside gassing due to intermittent or continuous failures occurring inside the equipment.

Buchholz relay is usually installed between the main tank and the oil expansion tank of the transformer.

Buchholz relay housing is made of cast iron, having two flanged openings and two sight glasses showing a graduated scale of gas volume. There are two inside floats, being that the upper float is fo rced to move downwards (this also happens in case of oil leakage).

On the other hand, in case an excessive gassing causes an oil ci rculation through the relay, the lower float reacts, even before the gas reaches the relay. In both cases, the floats make contacts when they are displaced.

The Buchholz Relay has a device for the inside float testing and locking. To check for proper operation of the relay contacts, when it is installed in the transformer, proceed as follows:

· Connect an Ohmmeter to terminal s + C - D. It should indicate an open circuit.

· Remove the testing device plug and introduce it upside down into the device, lowering it as much as possible in all of its length. The Ohmmeter should indicate a closed circuit.

· Connect an Ohmmeter to terminals + A - B. It should indicate an open circuit.

· Remove the testing device plug and introduce it upside down into the device, lowering it as much as possible in all of its length. The Ohmmeter should indicate a closed circuit.

Before supplying po wer to the transformer, the following items should be checked:

· Remove the lid of the relay -testing device.

· Remove the float -locking pin from the inside of the testing device. Both floats should be free to move.

· Replace the cover of the relay -testing device.

· Purge the air from the relay by means of the 1/8” air valve located on the relay lid.

· Check the relay for possible leakage that might have occurred during the installation on the transformer and fix it.

· Check the relay for proper fitting wi th regards to the oil float direction, which arrow should be pointing towards the transformer’s oil expansion tank.

If the alarm sounds without turning off the transformer, it is necessary to turn it off immediately and then test the gas removed from the inside of the relay. In this case, the origin of the failure can be assessed according to the gas testing result, i.e.:

· Combustible gas (contents of acetylene): In this case there must be a failure to be repaired on the electrical part;

· Non-combustible gas (without acetylene) : in this case, it means there is pure air. The transformer can be turned on again without danger after the air is bled out from the relay. When the alarm sounds repeatedly, it indicates that air is penetrating into the transformer. Tur n it off and repair the failure.

· No gassing (the gas level inside the relay is getting lower and an amount of air is being drawn through the open valve), in this case, the oil level is too low, possibly due to a leakage. Top up with oil until the control level and carry out the air tightness essay.

The transformer is turned off without a previous alarm. In this case, the transformer must have been thermally overloaded. Turn it on again after a considerable time interval for cooling. The failure can be found atcthe short-circuit contact in the protection relay system.

The alarm sounds and the transformer is shutdown immediately before or after the alarm sounds. In this case, one of the above mentioned failures must be the cause. Make the gas testing and proceed as described above.

Float locking device for transport purpose and testing of contacts : After installing the relay, remove the insert used to lock the floats.

Operation: To test the contacts, press the internal part with the lid pin. The contacts should actuate automatically. If everything is properly working, close the device again in order to prevent any leakage. Now the relay is ready to be put in operation.

NOTE: The insert is used for transport purposes only.



What Is Scott Transformer Connection? how Scott Transformer Connection Works?

In order to overcome the disadvantage of the T connection, the Scott connection uses two single-phase transformers of a special design to transform three phase voltages and currents into two-phase voltages and currents.

The first transformer, called the ‘‘main,’’ has a center-tapped primary winding connected to the three-phase circuit with the secondary winding connected to the two-phase circuit. It is vital that the two halves of the center-tapped primary winding are wound around the same core leg so that the ampere-turns of the two halves cancel out each other. The ends of the center-tapped main primary winding are connected to two of the phases of the three-phase circuit.

The second transformer, called the ‘‘teaser,’’ has one end of its primary winding connected to the third phase of the three-phase circuit and the other end connected to the center tap of the primary winding of the main. The Scott connection requires no primary neutral connection, so zero-sequence currents are blocked.

The secondary windings of both the main and teaser transformers are connected to the two-phase circuit. The Scott connection is shown in Figure 2.18 for a two-phase, five-wire circuit, where both secondary windings are center-tapped and the center taps are connected to the neutral of the five wire circuit. Three-wire and four-wire configurations are also possible.

If the main transformer has a turns ratio of 1: 1, then the teaser transformer requires a turns ratio of 0.866:1 for balanced operation. The principle of operation of the Scott connection can be most easily seen by first applying a current to the teaser secondary windings, and then applying a current to the main secondary winding, calculating the primary currents separately and superimposing the results.

Apply a 1.0 per unit load connected between phase 1 and phase 3 of the secondary:

Secondary current from the teaser winding into phase 1 1.0∠90°
Secondary current from the teaser winding into phase 3 1.0∠90°
Primary current from A phase into the teaser winding 1.1547∠90°
Primary current from B phase into the main winding 0.5774∠90°
Primary current from C phase into the main winding 0.5774∠90°

The reason that the primary current from A phase into the teaser winding is 1.1547 per unit is due to 0.866:1 turns ratio of the teaser, transforming 1/0.866 1.1547 times the secondary current. This current must split in half at the center tap of the main primary winding because both halves of the main primary winding are wound on the same core and the total ampere-turns of the main winding must equal zero.

Apply a 1.0 per unit load connected between phase 2 and phase 4 of the secondary:

Secondary current from the main winding into phase 2 1.0∠0°
Secondary current from the main winding into phase 4 1.0∠0°
Primary current from B phase into the main winding 1.0∠0°
Primary current from C phase into the main winding 1.0∠0°
Primary current from A phase into the teaser winding 0

Superimpose the two sets of primary currents:

I a 1.1547∠90° 0 1.1547∠90°
I b 0.5774∠90° 1.0∠0° 1.1547∠ 30°
I c 0.5774∠90° 1.0∠0° 1.1547∠210°

Notice that the primary three-phase currents are balanced; i.e., the phase currents have the same magnitude and their phase angles are 120° apart. The apparent power supplied by the main transformer is greater than the apparent power supplied by the teaser transformer.

This is easily verified by observing that the primary currents in both transformers have the same magnitude; however, the primary voltage of the teaser transformer is only 86.6% as great as the primary voltage of the main transformer.

Therefore, the teaser transforms only 86.6% of the apparent power transformed by the main. We also observe that while the total real power delivered to the two phase load is equal to the total real power supplied from the three-phase system, the total apparent power transformed by both transformers is greater than the total apparent power delivered to the two-phase load.

Using the numerical example above, the total load is 2.0 per unit. The apparent power transformed by the teaser is 0.866 I a 1.0 per unit, and the apparent power transformed by the main is 1.0 I b 1.1547 per unit for a total of 2.1547 per unit of apparent power transformed.

The additional 0.1547 per unit of apparent power is due to parasitic reactive power flowing between the two halves of the primary winding in the main transformer. Single-phase transformers used in the Scott connection are specialty items that are virtually impossible to buy ‘‘off the shelf ’’ nowadays.



How To Transform Three Phase Voltages Into Two Phase Voltages?

Occasionally, although rarely, one still may encounter a two-phase power system that is supplied by a three-phase source. Two-phase systems can have three-wire, four-wire, or five-wire circuits.

Note that a two-phase system is not merely two-thirds of a three-phase system. Balanced three-wire, two-phase circuits have two phase wires, both carrying approximately the same amount of current, with a neutral wire carrying 1.414 times the currents in the phase wires. The phase-to-neutral voltages are 90° out of phase with each other.

Four-wire circuits are essentially just two ungrounded single-phase circuits that are electrically 90° out of phase with each other. Five-wire circuits have four phase wires plus a neutral; the four phase wires are 90° out of phase with each other.

The easiest way to transform three-phase voltages into two-phase voltages is with two conventional single-phase transformers. The first transformer is connected phase-to-neutral on the primary (three-phase) side and the second transformer is connected between the other two phases on the primary side.

The secondary windings of the two transformers are then connected to the two-phase circuit. The phase-to-neutral primary voltage is 90° out of phase with the phase-to-phase primary voltage, producing a two-phase voltage across the secondary windings.

This simple connection, called the T connection, is shown in Figure 2.17. The main advantage of the T connection is that it uses transformers with standard primary and secondary voltages.

The disadvantage of the T connection is that a balanced two-phase load still produces unbalanced three-phase currents; i.e., the phase currents in the three phase system do not have equal magnitudes, their phase angles are not 120° apart, and there is a considerable amount of neutral current that must be returned to the source.



What Are Single Phase Pad Mounted Transformers?

Single-phase pad-mounted transformers are usually applied to serve residential subdivisions. Most single phase transformers are manufactured as clamshell, dead-front, loop-type with an internal 200-A primary bus designed to allow the primary to loop through and continue on to feed the next transformer.

These are detailed in the IEEE Standard C57.12.25 (ANSI, 1990). The standard assumes that the residential subdivision is served by a one-wire primary extension. It details two terminal arrangements for loopfeed systems: Type 1 (Figure 2.2.26) and Type 2 (Figure 2.2.27).

Type 1
Type 2
Both have two primary bushings and three secondary bushings. The primary is always on the left facing the transformer bushings with the cabinet hood open, and the secondary is on the right. There is no barrier or division between the primary and secondary.

In the Type 1 units, both primary and secondary cables rise directly up from the pad. In Type 2 units, the primary rises from the right and crosses the secondary cables that rise from the left. Type 2 units can be shorter than the Type 1 units, since the crossed cable configuration gives enough free cable length to operate the elbow without requiring the bushing to be placed as high.

Although not detailed in the national standard, there are units built with four and with six primary bushings. The four-bushing unit is used for single-phase lines, with the transformers connected phase-to-phase. The six-primary-bushing units are used to supply single-phase loads from three-phase taps.

Terminating all of the phases in the transformer allows all of the phases to be sectionalized at the same location. The internal single-phase transformer can be connected either phase-to-phase or phase-to-ground.

The six-bushing units also allow the construction of duplex pad-mounted units that can be used to supply small three-phase loads along with the normal single-phase residential load. In those cases, the service voltage is four-wire, three-phase, 120/240 V.

Cabinets for single-phase transformers are typically built in the clamshell configuration with one large door that swings up. Older units were manufactured with two doors, similar to the three-phase cabinets.

New installations are almost universally dead front; however, live-front units are still purchased for replacements. These units are also built with clamshell cabinets but have an internal box shaped insulating barrier constructed around the primary connections.



What Is The Importance of Power Transformer Impact Recorders During Transport?

There are two types of impact recorders:

· Impact Indicator – is used in all power transformers that are equal or higher than 30MVA and/or of a voltage class equal or higher than 230kV for the domestic market. When the transformer is to be exported, such impact indicator is used in all power transformers that are equal or higher than 5MVA. Four (4) pieces are used, which are fixed to the tank sidewalls.

· Three-dimensional Impact Recorder – is used only when required by the customer and/or by an insurance Company. This reco rder is fixed to the main transformer lid, by means of fastening screws, the nearest possible to its geometrical center. The recorder is turned on before the transformer is loaded by Manufacturer and should remain turned on until the unit is unloaded.

They are intended to indicate whether chocks and vibrations have occurred in th e traver se, longitudinal and vertical directions during the transport, loading and unloading processes. The magnitude of vibration and chocks is recorded in terms of “g” (Multiples of gr avity acceleration), accord ing to TABLE 1.


The ranges of the impact indicator are analyzed after the transformer is unloaded and should be sent back to Manufacturer transformadores. If they have proven to be out of the limits, the Technical Assistance Department will take all necessary steps.

However, if the recommended acceleration limits have been exceeded, it doesn’t mean that damages have occurred to the transformer. If such excess occurs, our technical department should carry out a deeper analysis of the occurrence, defining whether or not an internal assessment or eventually the adoption of another specific action is necessary.

It is necessary to take in account that not only the maximum value is imp ortant, but how many times such value has been reached during the transport.

The following procedures should be followed to turn off and remove the impact recorder:

· Remove the weatherproof protection;
· Check the box sealing for integrity. If damages are found, please report them immediately to Manufacturer
· Remove the box lid. In case of rain, do not allow the penetration of any kind of humidity to the inside of the recorder;
· Turn off the recorder;
· Mark the point where the transport process has been ended;
· Turn the recorder on;
· Close t he box lid;
· Unload the Transforme r;
· Remove the box lid;
· Turn off the recorder;
· Mark the point where the unloading process has been ended;
· Remove the impact recorder’s base from the unit;
· Replace the lid of the recorder box;
· Close the box with the supplied seal and send the impact recorder containing the roll of records to the sales department of Manufacturer, preferably using the same transporting company for return.

IMPORTANT: In case the transport and unloading work is carried out by the same Company, it is not necessary to turn off the recorder and switch its position between one and another operation.



How To Know The Polarity Of Single Phase Transformers?

Single-Phase Polarity
The polarity of a transformer can either be additive or subtractive. These terms describe the voltage that may appear on adjacent terminals if the remaining terminals are jumpered together.

The origin of the polarity concept is obscure, but apparently, early transformers having lower primary voltages and smaller kVA sizes were first built with additive polarity. When the range of kVAs and voltages was extended, a decision was made to switch to subtractive polarity so that voltages between adjacent bushings could never be higher than the primary voltage already present.

Thus the transformers built to ANSI standards today are additive if the voltage is 8660 or below and the kVA is 200 or less; otherwise they are subtractive.

This differentiation is strictly a U.S. phenomenon. Distribution transformers built to Canadian standards are all additive, and those built to Mexican standards are all subtractive. Although the technical definition of polarity involves the relative position of primary and secondary bushings, the position of primary bushings is always the same according to standards.

Therefore, when facing the secondary bushings of an additive transformer, the X1 bushing is located to the right (of X3), while for a subtractive transformer, X1 is farthest to the left.

To complicate this definition, a single-phase pad-mounted transformer built to ANSI standard Type 2 will always have the X2 mid-tap bushing on the lowest right-hand side of the lowvoltage slant pattern.

Polarity has nothing to do with the internal construction of the transformer windings but only with the routing of leads to the bushings. Polarity only becomes important when transformers are being paralleled or banked. Single-phase polarity is illustrated in Figure 2.2.11.

FIGURE 2.2.11 Single-phase polarity. (Adapted from IEEE C57.12.90-1999. The IEEE disclaims any responsibility or liability resulting from the placement and use in the described manner.



What Is The Contribution Of Distribution Transformers On Ferroresonance?

Ferroresonance is an overvoltage phenomenon that occurs when charging current for a long underground cable or other capacitive reactance saturates the core of a transformer.

Such a resonance can result in voltages as high as five times the rated system voltage, damaging lightning arresters and other equipment and possibly even the transformer itself.

When ferroresonance is occurring, the transformer is likely to produce loud squeals and groans, and the noise has been likened to the sound of steel roofing being dragged across a concrete surface.

A typical ferroresonance situation is shown in Figure 2.2.10 and consists of long underground cables feeding a transformer with a delta-connected primary.

FIGURE 2.2.10 is a typical ferroresonance situation. (From IEEE C57.105-1978, IEEE Guide for Application of Transformer Connections in Three-Phase Distribution Systems, copyright 1978 by the Institute of Electrical and Electronics Engineers, Inc. The IEEE disclaims any responsibility or liability resulting from the placement and use in the described manner. Information is reprinted with the permission of the IEEE.)

The transformer is unloaded or very lightly loaded and switching or fusing for the circuit operates one phase at a time.

Ferroresonance can occur when energizing the transformer as the first switch is closed, or it can occur if one or more distant fuses open and the load is very light. Ferroresonance is more likely to occur on systems with higher primary voltage and has been observed even when there is no cable present.

All of the contributing factors — delta or wye connection, cable length, voltage, load, single-phase switching —must be considered together. Attempts to set precise limits for prevention of the phenomenon have been frustrating.

For more on ferroresonance click the link.



What Is Zigzag Transformer? What Is Zigzag Connection Of Transformers?

The zigzag connection is also called the interconnected star connection. This connection has some of the features of the Y and the Δ connections, combining the advantages of both. The zigzag connection is a three-phase connection and is constructed as shown in Figure 2.14.

There are three pairs of windings, each having a 1:1 turns ratio. The left-hand set of windings shown in the
figure is a conventional Y connection, a′-b′-c′, with the neutral N brought out.

The open ends of the Y are electrically connected to the right-hand set of windings as follows: a′ connects to the right-hand winding paired with to the b′-N winding, b′ connects to the right-hand winding paired to c′-N winding, and c′ connects to the right-hand winding paired to the a′-N winding.

The opposite ends of the right-hand windings are brought out as the phase terminals a, b, and c. The vector diagram shown on the right of Figure 2.14 makes it is obvious why this is called a zigzag connection. It operates on the following principle:

If three currents, equal in magnitude and phase, are applied to the three terminals, the ampere-turns of the a′-N winding cancel the ampere-turns of the c′- c winding, the ampere-turns of the b′-N winding cancel the ampere turns of the a′-a winding, and the ampere-turns of the c′-N winding cancel the ampere turns of the b′-b winding. Therefore, the transformer allows the three in-phase currents to easily flow to neutral.

If three currents, equal in magnitude but 120° out of phase with each other, are applied to the three terminals, the ampere-turns in the windings cannot cancel and the transformer restricts the current flow to the negligible level of magnetizing current.

Therefore, the zigzag winding provides an easy path for in-phase currents but does not allow the flow of currents that are 120° out of phase with each other.

The ability to provide a path for in-phase currents enables us to use the zigzag connection as a grounding bank, which is one of the main applications for this connection. If a zigzag winding is used as a secondary winding with a Δ winding used as a primary winding, the Δ-zigzag connection is created, as show nin Figure 2.15.

AΔ-zigzag transformer is technically not a two-winding transformer but rather a three-winding transformer because three separate windings are wound around each core leg.  Since two of the sets of windings are interconnected, we treat the Δ-zigzag as if it were a two-winding transformer.

As usual, the sets of windings that are magnetically linked on common core legs are drawn in parallel to each other, as shown in Figure 2.15.

The Δ-zigzag connection provides the same advantages as the Δ-Y connection, like third harmonic suppression and ground current isolation. One added advantage is that there is no phase angle displacement between the primary and the secondary circuits with this connection; therefore, the Δ-zigzag connection can be used in the same manner as Y-Y and Δ-Δ transformers without introducing any phase shifts in the circuits.



What Are The Insulating Liquids Of Power Transformers?

Insulating Liquids
Dielectric liquids of various types are used as an insulating medium as well as a means of cooling liquid-filled transformers. Common insulating liquids include the following:

Mineral oil. A mineral oil-filled transformer is generally the smallest, lightest, and most economical transformer available. Mineral oil has excellent properties for use in transformers, but it has the inherent weakness of being flammable. Its use, therefore, is restricted to outdoor installations or when the transformer is installed within a vault if used indoors.

Silicone. A wide variety of synthetic polymer chemicals are referred to by the generic term silicone. Silicone transformer liquids are actually known chemically as polydimethylsiloxane (PDMS). PDMS is a water-clear, odorless, chemically stable, nontoxic liquid.

High-molecular-weight hydrocarbon (HMWH). HMWH is another high-firepoint dielectric that is widely used as a transformer liquid. It has similar values for dielectric strength and dielectric constant, power factor, and thermal conductivity as mineral oil.

There are no established standards for testing the fire safety of transformers. Factory Mutual Research (FM) and Underwriters Laboratories (UL) both have different criteria for listing transformer liquids. Fire properties of dielectric fluids are typically classified by the following characteristics.

• Flash point: the temperature at which vapors from a liquid surface will ignite in the presence of a flame.
• Fire point: the temperature at the surface of a liquid that will sustain a fire.
• Flame spread: a series of consecutive ignitions.
• Ease of ignition: how readily the liquid will generate and maintain a flammable fuel/vapor mixture at the surface.
• Heat release rate: the product of vaporization rate and the heat of combustion of the fluid. The higher this rate in a large-scale fire, the higher the degree of fire hazard.

Selection of the dielectric liquid depends on the transformer application. Normally, the choice is mineral oil if the device is to be located outdoors.

The National Electrical Code (NEC) does, however, specify certain limitations regarding the use of oil filled transformers in particular outdoor locations. The selection of less-flammable liquids (PDMS and HMWH) often depends upon personal preference, the liquid used in other transformers on the site, or the transformer manufacturer's recommendation.
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