BASIC LOADING OF POWER TRANSFORMER BASIC INFORMATION

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Basic Conditions
1. The basic loading of a transformer for normal life expectancy is continuous loading at rated output when operated under normal service conditions.

It is assumed that operation under these conditions is equivalent to operation in a continuous ambient temperature of 30 C for cooling air or 25 C for cooling water.

Normal life expectancy will result from operating with a continuous hottest-spot conductor temperature of 110 C (or equivalent variable temperature with 120 C maximum) in any 24-h period.

2. The hottest-spot conductor temperature determines loss of life due to loading. This temperature cannot be directly measured on commercial designs because of voltage hazard when placing a temperature detector at the proper location.

The hottest-spot allowances are based on tests of laboratory models.

3. The hottest-spot temperature at rated load is usually taken as the sum of the average winding temperature and a 15 C allowance2 for hottest spot.

For mineral oil-immersed transformers operating continuously under the foregoing conditions with normal life expectancy, this temperature has been assumed to be a maximum of 110 C.

INSULATION CLASSES OF POWER TRANSFORMER BASIC INFORMATION AND TUTORIALS

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The type of insulation used in dry-type–transformer design and construction has a definite bearing on the size and operating temperature of the unit. Currently four classes of insulation, each having a separate NEMA specification and temperature limit, are being used.

A look at these will facilitate selection of the proper unit to meet prescribed installation and operating conditions.

1. Class 130 insulation-system transformers. When properly applied and loaded in an ambient not over 40 C, these transformers will operate at not more than a 60 C temperature rise on the winding.

These units can be used as control-type transformers when higher temperatures might affect other temperature-sensitive devices in the enclosure or as distribution transformers in locations (textile mills, sawmills, etc.) where combustible flyings might be present in the surrounding atmosphere.

2. Class 150 insulation-system transformers. These units have a higher-temperature insulating system and are physically smaller and about half the weight of Class A units of corresponding rated capacities. When properly loaded to rated kilovolt-amperes and installed in an ambient not over 40 C,

Class 150 units will operate at a maximum 80 C rise on the winding. For years dry-type distribution transformers have been of the Class 150 type.

3. Class 200 insulation-system transformers. These units also have a high-temperature insulating system and, when properly loaded and applied in an ambient not over 40 C, will operate at no more than 130 C rise on the winding.

The units are smaller in size than similarly rated Class 150 units and currently are available from a number of manufacturers in ratings of 25 kVA and lower, both single- and three-phase design. One manufacturer designs in-wall, flush-mounted dry-type transformers as Class 200 units.

4. Class 220 insulation-system transformers. These units are insulated with a high temperature system of glass, silicone, and asbestos components and are probably the most compact ones available.

When properly loaded and applied in an ambient not over 40 C, Class 220 transformers will operate at a maximum 150 C rise on the winding. This class of insulation is used primarily in designs in which the core and coil are completely enclosed in a ventilated housing.

Generally, this stipulation covers units with ratings of 30 kVA and larger. Some experts recommend that the hottest spot on the metal enclosure be limited to a maximum rise of 40 C above a 40 C ambient. It should be noted that Class 150 insulation is being replaced with Class 200 or 220 insulation in transformers of recent design.

Another significant factor which concerns all dry-type transformers is that they should never be overloaded. The way to avoid this is to size the primary or secondary overcurrent device as close as possible to the full-load primary or secondary current for other than motor loads.

If close overcurrent protection has not been provided, loads should be checked periodically. Overloading a transformer causes excessive temperature, which, in turn, produces overheating. This results in rapid deterioration of the insulation and will cause complete failure of the transformer coils.

OIL IMMERSED TRANSFORMER INSULATION VALUE BASIC AND TUTORIALS

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(Standard Handbook for Electrical Engineers), is depended on very largely to help insulate the transformer; this is done by providing liberal oil ducts between coils and between groups of coils, in addition to the solid insulation. The oil ducts thus serve the double purpose of insulating and cooling the windings.

Since the oil is a very important part of the insulation, every effort is made in modern transformers to preserve both its insulating and cooling qualities. Oxidation and moisture are the chief causes of deterioration.

Oil takes into solution about 15 percent by volume of whatever gas is in contact with it. In the open-type transformer, oil rapidly darkens, owing to the effects of oxygen in solution in the oil and the oxygen in contact with the top surface of the hot oil.

1. Expansion tank (or conservator). One of the first devices used to reduce oxidation was the expansion tank (or conservator), which consisted of a small tank mounted above and connected with the main tank by means of a constricted connection so that the small tank could act as a reservoir to take up the expansion and contraction of the oil due to temperature changes and reduce the oil surface exposed to air.

2. Inertaire transformer. This transformer has the space above the oil in the tank filled with a cushion of inert gas which is mostly nitrogen. The nitrogen atmosphere is initially blown in from a cylinder of compressed nitrogen and is thereafter maintained by passing the inbreathing air through materials which remove the moisture and the oxygen, permitting dry nitrogen to pass into the case.

A breathing regulator, which consists of a mercury U tube with unequal legs, allows inbreathing of nitrogen when the pressure in the case is only slightly below atmospheric, but prevents outbreathing unless the pressure in the case becomes 5 psi (34,474 Pa) higher than atmospheric pressure.

The elimination of oxygen from within the transformer case eliminates the oxidation of the oil and prevents fire and secondary explosion within the case.

TYPES OF POWER TRANSFORMER FAULTS & MECHANICAL PROTECTION BASICS

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POWER TRANSFORMER FAULTS
Any number of conditions have been the reason for an electrical transformer failure. Statistics show that winding failures most frequently cause transformer faults (ANSI=IEEE, 1985).

Insulation deterioration, often the result of moisture, overheating, vibration, voltage surges, and mechanical stress created during transformer through faults, is the major reason for winding failure.

Voltage regulating load tap changers, when supplied, rank as the second most likely cause of a transformer fault. Tap changer failures can be caused by a malfunction of the mechanical switching mechanism, high resistance load contacts, insulation tracking, overheating, or contamination of the insulating oil.

Transformer bushings are the third most likely cause of failure. General aging, contamination, cracking, internal moisture, and loss of oil can all cause a bushing to fail. Two other possible reasons are vandalism and animals that externally flash over the bushing.

Transformer core problems have been attributed to core insulation failure, an open ground strap, or shorted laminations.

Other miscellaneous failures have been caused by current transformers, oil leakage due to inadequate tank welds, oil contamination from metal particles, overloads, and overvoltage.


There are two generally accepted methods used to detect transformer faults using mechanical methods. These detection methods provide sensitive fault detection and compliment protection provided by differential or overcurrent relays.

Accumulated Gases:
The first method accumulates gases created as a by product of insulating oil decomposition created from excessive heating within the transformer. The source of heat comes from either the electrical arcing or a hot area in the core steel.

This relay is designed for conservator tank transformers and will capture gas as it rises in the oil. The relay, sometimes referred to as a Buchholz relay, is sensitive enough to detect very small faults.

Pressure Relays: 
The second method relies on the transformer internal pressure rise that results from a fault. One design is applicable to gas-cushioned transformers and is located in the gas space above the oil.

The other design is mounted well below minimum liquid level and responds to changes in oil pressure. Both designs employ an equalizing system that compensates for pressure changes due to temperature (ANSI=IEEE, 1985).

DISTRIBUTION TRANSFORMER TYPES BASIC AND TUTORIALS

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Distribution transformers may be installed on poles, on the ground on pads, and under the ground directly or in manholes and vaults. The transformers used in these types of installations differ mainly in their packaging, as the internal operating features are very much the same.

Overhead Transformers
The overhead type of distribution transformer is mounted directly on a pole by means of two lugs, welded to the transformer tank, that engage two bolts on the pole, as shown in Figure 11-2a; this is known as direct mounting, in contrast to older methods in which the transformer was bolted to a pair of hanger irons that were hung over a cross arm.


Figure 11-2a. Direct pole mounting of a transformer (Courtesy Westinghouse Electric Co.)


Where more than one transformer is required, as in power banks, the transformer lugs engage studs on a bracket which is bolted, like a collar, around the pole; the units form a cluster around the pole, from which the term cluster mounting is derived; see Figure 11-2b.


Figure 11-2b. Cluster mounting of transformers. (Courtesy Long Island Lighting Co.)


Where the load (weight) of the transformer or transformers may be too great for the pole, they may be placed on a platform erected between two or more poles in a structure, or they may be placed on a protected ground-level pad.

Pad-Mounted Transformers
Transformers may be mounted on concrete pads at, or slightly below, ground level within an enclosure or compartment that may be locked for protection. These are generally installed as part of so-called underground residential distribution (URD) systems.

The transformers may have their energized terminals exposed when the compartment is open, or the terminals may be mounted behind an insulating barrier and connections from the cables made through bayonet-type connections on insulated elbows which are plugged into jacks connected to the terminals; these units are referred to as dead-front units and provide an additional margin of safety.

Underground Transformers
In the underground type of transformer, also called the subway type, the tank is not only hermetically sealed for water tightness, but its walls, bottom, and cover are made thicker to withstand higher internal and external pressures; the cover is bolted to the tank (with intervening gaskets) by a relatively large number of bolts, and in some instances, welding is used. These units are designed to operate completely submerged in water.

In larger units, where cooling of the tank itself is not sufficient, radiator fins are welded to the tank to provide additional cooling surface, or pipes are welded to the tank for the circulation of oil through them; in the latter case, the additional surface of the pipes as well as the circulating oil is useful for cooling.

Connections to the supply cables are made by means of watertight wiped joints between a fluid-tight bushing and the cable sheath. Another means provides for the making of connections in a chamber attached to the transformer tank in which the primary-voltage transformer windings are brought out in fluid-tight bushings.

In some units, this chamber also houses high-voltage disconnecting and grounding switches. Where these units supply low-voltage secondary networks, they also house the network protector in another watertight compartment, usually situated at the opposite end of the transformer tank from the primary connection and switch chamber.

BOOSTER TRANSFORMERS CONNECTION & OPERATION BASIC AND TUTORIALS

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Ordinary distributing transformers applied as illustrated (Fig. 1) are used when it is necessary to raise, by a fixed percentage, the voltage delivered by a line, as it is when transformer ratios do not give quite the right voltage or when line drop is excessive.

Fig. 1 Boosting transformers.

A booster raises the voltage of any primary circuit in which it may be inserted by the amount of the secondary voltage of the booster (see Fig.1).

EXAMPLE
On a long single-phase 2080-V lighting branch so heavily loaded that the pressure drops more than the amount for which the normal regulation of the feeder will compensate, a 110-V transformer inserted in the line as a booster will raise the pressure of the primary branch on the load side of the booster by 110 V.

This raises the secondary pressure 5.5 percent on all the transformers beyond the booster. With 440-V service supplied by star-connected 230-V transformers, a 10 percent booster in each phase raises the normal pressure of 230/400 V to 253/440 V.

The connections for a simple booster are shown in Fig. 1, I, the line pressure being raised from 2080 to 2184 V, or 5 percent. The connection at II is that for an augmented booster in which the line pressure is raised from 2080 to 2190 V, because the primary of the booster is connected across the line on the far side and the booster is boosted as well as the line.

This gives an increase of 5.5 percent in the line pressure. Figure 1, II, shows a 10 percent simple booster and IV an augmented 11.1 percent booster.

The transformers shown in Fig.1 have a 10:1 or 20:1 ratio, and the percentages shown apply only to transformers of this ratio. If boosters having a ratio of 2080 to 115/230 are used, the percentages are increased by about 10 percent. Figure 1, I, would then become 5.5 percent; II, 6.05 percent; III, 11.1 percent; and IV, 12.2 percent.

DELTA, STAR, AND OPEN DELTA TRANSFORMER CONNECTION COMPARISON

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The choice between the methods would be governed largely by the service requirements. When the three transformers are delta-connected, one can be removed without interrupting the performance of the circuit, the two remaining transformers in a manner acting in series to carry the load of the missing transformer.

The desire to obtain immunity from a shutdown due to the disabling of one transformer has led to the extensive use of the delta connection of transformers, especially on the low-potential delivery side. It is to be noted that if one transformer is crippled, the other two will be subjected to greatly increased losses.

Thus, if three delta-connected transformers are equally loaded until each carries 100 A, there will be 173 A in each external circuit wire. If one transformer is now removed and 173 A continues to be supplied to each external circuit wire, each of the remaining transformers must carry 173 A, since it is now in series with an external circuit.

Therefore, each transformer must now show 3 times as much copper loss as when all three transformers were active, or the total copper loss is now increased to a value of 6 relative to its former value of 3. An open-delta installation is made frequently when considerable future increase in load is expected.

The increase can be accommodated by adding the third transformer to the bank at a later date and thus increasing the capacity of the load that can be carried by about 75 percent.

A change from delta to Y in the secondary circuit alters the ratio of the transmission emf to the receiver emf from 1 to 1.73 .

On account of this fact, when the emf of the transmission circuit is so high that the successful insulation of transformer coils becomes of constructive and pecuniary importance, the three-phase line sides of the transformers are connected in “star” and the neutral is grounded.

The windings of most transformers operating on systems of 100,000 V or more are star-connected.


Comparative cost of transformers for different grouping for three-phase service. 
The accompanying table shows the costs of the single-phase transformers, of proper capacities for either a delta or an open-delta grouping, and of a three-phase transformer to serve a 75-kVA installation. The relative costs will be the same for the present date.


CONSTANT CURRENT TRANSFORMER BASIC OPERATION TUTORIALS

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The operation of low-voltage lamps in parallel on a constant-voltage system necessitates a prohibitive expenditure for conducting material when the area to be lighted is extensive and the lamps are widely separated. For such service it is the common practice to operate the lamps, which are connected in series, with a constant current.

The constant-current transformer is a special form of transformer which converts alternating current at a constant voltage to a constant (alternating) current with a voltage varying with the load. It consists of a primary coil upon which the constant voltage is impressed, a secondary coil (or coils) movable with respect to the primary, and a core of low magnetic reluctance.

It depends for its regulation upon the magnetic leakage between the primary and secondary coils. Consider first the primary coil; with the constant emf impressed upon this coil the total magnetism within the coil will be practically constant under all conditions.

The emf generated in the secondary will depend upon the strength of the field which it surrounds. In all types of stationary transformers the secondary current is opposite in general time direction to the primary, so that there is not only a repulsive thrust between the two coils but also a considerable tendency for the magnetic lines from the primary to be forced out into space without penetrating the secondary.

In the ordinary constant-voltage transformer the repelling action between the two currents is prevented from producing motion of the coils by the rigid mechanical construction, while the proximity of the primary and secondary coils limits the magnetic leakage.

In the constant-current transformer, however, the repelling action is utilized to adjust the relative positions of the primary and secondary coils; when the coils are widely separated, the paths for the leakage lines are increased and the lines which the secondary surrounds are fewer than when the coils are quite close together.

The counterweights mechanically attached to the movable coil (or coils) are so arranged that when the desired current exists in the secondary coil (independent of its position along the core), the weights are just balanced. An increase in the current increases the repulsion and causes the coils to separate.

With any current less than normal, the repelling force diminishes, and the primary and secondary coils approach each other, thereby restoring the current to normal. The primary can be wound for any reasonable voltage (say, as high as 10,000 V), while the secondary can be wound for the voltage required for operating the number of lamps in the circuit—from 15 to 200 or more lamps.

THREE PHASE TRANSFORMER APPLICATION BASIC AND TUTORIALS

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For central stations of medium size, three-phase transformers are rarely superior to single-phase, except when the large sizes can be applied, in which case the transformers are normally installed in substations or central stations.

The chief reason for this is the nonflexibility of a three-phase transformer. It is usually purchased for a particular size and type of load, and if that load should be changed, the transformer, representing a comparatively heavy investment, remains on the hands of the central station, whereas a single-phase transformer of one-third the size could usually be adapted for some other service.

This feature becomes of less importance as the central station increases its size, and three-phase transformers for purely power service are now being used by a considerable number of the large central stations in the United States.

The three-phase transformer costs less to install, and the connections are simpler, points that are of importance in connection with outdoor installations. The fact that a failure of a three-phase transformer would interrupt service more than the failure of one single-phase transformer in a bank of three is of little importance because of the comparatively few failures of modern transformers.

On the other hand, especially for 2200-V service, the single-phase transformer has been carried to a high degree of perfection and is manufactured in much larger quantities, so that better performance is usual and in some cases initial cost is lower.

Three-phase distribution transformers are used extensively in underground city network service on account of the smaller space required by them in the manhole, their higher efficiency, and their lower initial cost.

For overhead service for pole or platform mounting, three single-phase units are more common on account of the ease of handling and mounting the smaller-sized units.

POWER TRANSFORMER INSULATION CLASS SYSTEM BASIC AND TUTORIALS

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The type of insulation used in dry-type–transformer design and construction has a definite bearing on the size and operating temperature of the unit. Currently four classes of insulation, each having a separate NEMA specification and temperature limit, are being used.

A look at these will facilitate selection of the proper unit to meet prescribed installation and operating conditions.

1. Class 130 insulation-system transformers. When properly applied and loaded in an ambient not over 40 C, these transformers will operate at not more than a 60 C temperature rise on the winding.

These units can be used as control-type transformers when higher temperatures might affect other temperature-sensitive devices in the enclosure or as distribution transformers in locations (textile mills, sawmills, etc.) where combustible flyings might be present in the surrounding atmosphere.

2. Class 150 insulation-system transformers. These units have a higher-temperature insulating system and are physically smaller and about half the weight of Class A units of corresponding rated capacities.

When properly loaded to rated kilovolt-amperes and installed in an ambient not over 40 C, Class 150 units will operate at a maximum 80 C rise on the winding. For years dry-type distribution transformers have been of the Class 150 type.

3. Class 200 insulation-system transformers. These units also have a high-temperature insulating system and, when properly loaded and applied in an ambient not over 40 C, will operate at no more than 130 C rise on the winding.

The units are smaller in size than similarly rated Class 150 units and currently are available from a number of manufacturers in ratings of 25 kVA and lower, both single- and three-phase design. One manufacturer designs in-wall, flush-mounted dry-type transformers as Class 200 units.

4. Class 220 insulation-system transformers. These units are insulated with a high temperature system of glass, silicone, and asbestos components and are probably the most compact ones available. When properly loaded and applied in an ambient not over 40 C, Class 220 transformers will operate at a maximum 150 C rise on the winding.

This class of insulation is used primarily in designs in which the core and coil are completely enclosed in a ventilated housing. Generally, this stipulation covers units with ratings of 30 kVA and larger. Some experts recommend that the hottest spot on the metal enclosure be limited to a maximum rise of 40 C above a 40 C ambient.

It should be noted that Class 150 insulation is being replaced with Class 200 or 220 insulation in transformers of recent design.

Another significant factor which concerns all dry-type transformers is that they should never be overloaded. The way to avoid this is to size the primary or secondary overcurrent device as close as possible to the full load primary or secondary current for other than motor loads.

If close overcurrent protection has not been provided, loads should be checked periodically. Overloading a transformer causes excessive temperature, which, in turn, produces overheating. This results in rapid deterioration of the insulation and will cause complete failure of the transformer coils.

TRANSFORMER CLASSIFICATION BASIC AND TUTORIALS

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Transformers may be classified into the following:


1. According to method of cooling
a. Self-air–cooled (dry type)
b. Air-blast–cooled (dry type)
c. Liquid-immersed, self-cooled
d. Oil-immersed, combination self-cooled and air-blast
e. Oil-immersed, water-cooled
f. Oil-immersed, forced-oil–cooled
g. Oil-immersed, combination self-cooled and water-cooled

2. According to insulation between windings
a. Windings insulated from each other
b. Autotransformers

3. According to number of phases
a. Single-phase
b. Polyphase

4. According to method of mounting
a. Pole and platform
b. Subway
c. Vault
d. Special

5. According to purpose
a. Constant-voltage
b. Variable-voltage
c. Current
d. Constant-current

6. According to service
a. Large power
b. Distribution
c. Small power
d. Sign lighting
e. Control and signaling
f. Gaseous-discharge lamp transformers
g. Bell ringing
h. Instrument
i. Constant-current
j. Series transformers for street lighting

CALCULATING TRANSFORMER LOSS OF LIFE BASIC AND TUTORIALS

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Industry standards also address the loss of life of a transformer due to temperature and aging. The relation of insulation aging to time and temperature follows the well-known Arrhenius chemical reaction rate model.

The adaptation used in the IEEE standard [3] has the following form. Per unit life = Ae^[B/(θH 273)] where θH winding hot-spot temperature in °C, and A and B are constants.

The meaning of per unit life is illustrated as follows: If per unit life = 2, then the transformer would be expected to last twice the ‘‘normal’’ life. If per unit life = 0.5, then the transformer would be expected to last only half the ‘‘normal’’ life. Normal life for most transformers is considered to be around 30 to 40 years.

The constants A and B depend on the types of material used to insulate the windings. Since cellulose in the form of kraft paper is the most common insulation material, these constants have been worked out empirically:

Per unit life = 9.8 10 18e15000/(θH 273) (3.14.2)

The winding hot-spot design temperature to attain a normal life is 110°C. This is based on an assumed ambient temperature of 30° plus the 65°C average winding temperature gradient over ambient plus a 15°C allowance for the hotspot gradient over the average winding temperature.

Using θH = 110°C yields a per unit life = 1. The aging acceleration factor FAA is the ratio of the per unit life at the design temperature of 110°C divided by the per unit life at some operating temperature θH. The constant A then divides out:

FAA = e15000/383 15000/(θH 273) = e39.16 15000/(θH 273)


To calculate the equivalent aging of the transformer FEQA with a varying hot-spot temperature such as occurs for a cycling load or a seasonal ambient temperature, FAA is integrated over time and the integral is divided by the total time to obtain the average.

The per unit life and FAA are plotted vs. hot-spot temperature in the chart shown in Figure below.


The per unit life and the aging acceleration factor as a function of
the hot-spot temperature.


It should be stressed that most transformer failures are random events that occur for various reasons besides insulation loss of life. Therefore, the formula for per unit life cannot be used as a predictive model to determine when a given transformer will ultimately fail.

However, it is indeed certain that overloading a transformer will shorten its life, so it is a good practice from a reliability standpoint to keep the loading within the transformer’s thermal capability.

DIFFERENT TYPES OF TRANSFORMER PROTECTION BASIC INFORMATION

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The protection of the transformer is as important a part of the application as the rating values on the transformer. Entire texts are devoted to the subject of transformer protection.

When investigating a failure, one should collect all the protection-scheme application and confirm that the operation of any tripping function was correct.

Surge Arresters
Surge arrester protective level must be coordinated with the BIL of the transformer. Their purpose, to state what may seem obvious, is to protect the transformer from impulse voltages and high-frequency transients.

Surge arresters do not eliminate voltage transients. They clip the voltages to a level that the transformer insulation system is designed to tolerate. However, repeated impulse voltages can have a harmful effect on the transformer insulation.

Overcurrent Protection
Overcurrent devices must adequately protect the transformer from short circuits. Properly applied, the time–current characteristic of the device should coordinate with that of the transformer.

These characteristics are described in IEEE C57.109-1993, Guide for Liquid-Immersed Transformer Through-Fault Duration. Overcurrent devices may be as simple as power fuses or more complex overcurrent relays.

Modern overcurrent relays contain recording capability that may contain valuable information on the fault being investigated.

Differential Protection
Differential relays, if applied, should be coordinated with the short-circuit current available, the transformer turns ratio and connection, and the current transformers employed in the differential scheme.

If differential relays have operated correctly, a fault occurred within the protected zone. One must determine if the protected zone includes only the transformer, or if other devices, such as buswork or circuit breakers, might have faulted.

ADVANCED VOLTAGE AND CURRENT TRANSDUCERS BASIC INFORMATION

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Advanced state-of-the-art loss measuring systems utilize a number of voltage and current sensors that have very low or zero phase angle error. Modern Voltage sensors utilize standard compressed gas capacitors connected with various active feedback circuits to minize the phase angle error of the voltage.

Although the compressed gas capacitors are known for stability and extremely low loss, the electronics associated with the divider must be designed to limit drift to acceptable levels in order to meet the accuracy requirements of the standards.

Also, sensing of the current for accurate scaling for transformer loss testing can be done by utilizing one of the following concepts:

a) Zero flux passive design current transformers
b) Two-stage current transformers
c) Amplifier-aided two stage current transformers.

These current transformers operate on the principle of reducing the flux in the active core of the CT to or near zero; thereby reducing the phase angle error associated with the flux into CT core. The use of high accuracy solid state transducers combined with digital readout can improve overall measurement accuracies due to the following factors:

a) Random error due to the limited resolution of analog instruments is virtually eliminated by the use of digital instruments.

b) Technology, such as solid state time division multiplier techniques for measurement of power, can improve accuracy over conventional electrodynamometer type wattmeters.

The accuracy is also improved because of reduced burden on the instrument transformers and reduction in internal phase shifts. Compensation for lead losses can be designed into these devices.

c) Judicious use of electronic circuits, aided by operational amplifiers, can ensure operation of transducers in their optimal operating ranges. This minimizes the error that is dependent upon the input magnitude as a percent of full scale.

d) Computing circuits for summing and averaging of three-phase measurements can be included in the system design to minimize calculation errors. Errors due to incorrect signs and errors due to selfheating are also minimized by these circuits.

MEASUREMENT OF TRANSFORMER NO LOAD LOSSES BASIC INFORMATION

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

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

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

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

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

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





NOTE
‘F’ is a frequency meter
‘A’ is an ammeter
‘W’ is a wattmeter
‘V’ is a true rms voltmeter
‘AV’ is an average-responding, rmscalibrated voltmeter

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

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

ANGULAR DISPLACEMENT OF THREE PHASE TRANSFORMERS BASIC AND TUTORIALS

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Angular displacement is defined as the phase angle in degrees between the line-to-neutral voltage of the reference-identified high-voltage terminal and the line-to-neutral voltage of the corresponding identified low-voltage terminal.


The angle is positive when the low-voltage terminal lags the high-voltage terminal. The convention for the direction of rotation of the voltage phasors is taken as counterclockwise.

Since the bulk of the electric power generated and transmitted is three-phase, the grouping of transformers for three-phase transformations is of the greatest interest. Connection of three-phase transformers or three single phase transformers in a three-phase bank can create angular displacement between the primary and secondary terminals.

The standard angular displacement for two-winding transformers is shown in Figure above. The references for the angular displacement are shown as dashed lines.

The angular displacement is the angle between the lines drawn from the neutral to H1 and from the neutral to X1 in a clockwise direction from H1 to X1.

The angular displacement between the primary and secondary terminals can be changed from 0 to 330 degrees in 30deg steps simply by altering the three-phase connections of the transformer.

Therefore, selecting the appropriate three-phase transformer connections will permit connection of systems with different angular displacements.

Figure shows angular displacement for common double-wound three-phase transformers. Multicircuit and autotransformers are similarly connected.

TRANSFORMER BUSHINGS FOR SPECIAL APPLICATIONS

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High-Altitude Applications
Bushings intended for application at altitudes higher than 1000 m suffer from lower air density along the outer insulator. Standards specify that, when indicated, the minimum insulation necessary at the required altitude can be determined by dividing the standard insulation length at 1000 m by the correction factor given in Table 3.2.2.

For instance, suppose that the required length of the air insulator on a bushing is 2.5 m at 1000-m altitude. Further, suppose that this bushing is to be applied at 3000 m. Hence, the air insulator must be at least 2.5/0.8 = 3.125 m in length.

The air insulator on the bushing designed for 1000 m must be replaced with a 3.125-m-long insulator, but the remainder of the bushing, i.e., the central core and the oil insulator, will remain the same as the standard bushing because these parts are not affected by air insulation. These rules do not apply to altitudes higher than 4500 m.

Highly Contaminated Environments
Insulators exposed to pollution must have adequate creep distance, measured along the external contour of the insulator, to withstand the detrimental insulating effects of contamination on the insulator surface. Figure 3.2.2 shows the undulations on the weather sheds, and additional creep distance is obtained by adding undulations or increasing their depth. Recommendations for creep distance are shown in

Table 3.2.3 according to four different classifications of contamination. For example, a 345-kV bushing has a maximum line-to-ground voltage of 220 kV, so that the minimum creep is 220 X 28 = 6160 mm for a light contamination level and 220 X 44 = 9680 mm for a heavy contamination level. The term ESDD (equivalent salt-density deposit) used in Table 3.2.3 is

TABLE 3.2.2 Dielectric-Strength Correction Factors for Altitudes
Greater than 1000 m
Altitude, m Altitude Correction Factor for Dielectric Strength
1000 1.00
1200 0.98
1500 0.95
1800 0.92
2100 0.89
2400 0.86
2700 0.83
3000 0.80
3600 0.75
4200 0.70
4500 0.67
Source: ANSI/IEEE, 1997 [1]. With permission.

TABLE 3.2.3 Recommended Creep Distances for Four Contamination Levels
Contamination Level
Equivalent Salt-Deposit
Density (ESDD), mg/cm2
Recommended Minimum Creep
Distance, mm/kV
Light 0.03–0.08 28
Medium 0.08–0.25 35
Heavy 0.25–0.6 44
Extra heavy above 0.6 54
Source: IEEE Std. C57.19.100-1995 (R1997) [8]. With permission.

the conductivity of the water-soluble deposits on the insulator surface. It is expressed in terms of the density of sodium chloride deposited on the insulator surface that will produce the same conductivity.

Following are typical environments for the four contamination levels listed:

Light-contamination areas include areas without industry and with low-density emission-producing residential heating systems, and areas with some industrial areas or residential density but with frequent winds and/or precipitation. These areas are not exposed to sea winds or located near the sea.

Medium-contamination areas include areas with industries not producing highly polluted smoke and/ or with average density of emission-producing residential heating systems, areas with high industrial and/or residential density but subject to frequent winds and/or precipitation, and areas exposed to sea winds but not located near the sea coast.

Heavy-contamination areas include those areas with high industrial density and large city suburbs with high density emission-producing residential heating systems, and areas close to the sea or exposed to strong sea winds.

Extra-heavy-contamination areas include those areas subject to industrial smoke producing thick, conductive deposits and small coastal areas exposed to very strong and polluting sea winds.

POWER TRANSFORMER WATER IN OIL ANALYSIS BASIC AND TUTORIALS

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There is an old expression, ‘‘Oil and water do not mix.’’ Thus, oil is not usually thought of as having a great affinity for water, and in fact it doesn’t. However, the kraft paper insulation found in most power transformers has a tremendous affinity for water.

In fact, cellulose is often used as a drying agent or desiccant. If there is moisture present in the transformer, it will usually wind up in the kraft paper insulation. Moisture not only weakens the insulating properties of the kraft paper, it also accelerates the rate of aging.

Therefore, in order to prolong the life of a transformer, moisture must be monitored. Since samples of the insulation cannot be taken while the transformer is in service, water-in-oil analysis is used to monitor the moisture content of the kraft paper as a surrogate.

There is a known equilibrium between moisture concentrations in the kraft paper versus the moisture concentrations in the oil based on the temperature of the paper and oil. The equilibrium is expressed by the so-called Piper chart, shown in Figure below.


Notice that as the temperature increases, water is driven from the paper into the oil. At elevated temperatures the oil is able to dissolve more water than at lower temperatures. The relationship can be expressed by the following equation.
T = 31.52 - 26.605 Ln pct + 17.524 Ln ppm

where
T =  temperature (°C)
pct  =  % water in paper
ppm = ppm water in oil

When doing a water-in-oil analysis, a syringe sample of oil is taken from the drain valve. Care must be exercised so that the oil is not exposed to the atmosphere. (Any exposure to the atmosphere will cause the oil to quickly reach equilibrium with the air.

Since ambient air usually contains quite a bit of moisture, this will generally immediately saturate the oil with water and produce a meaningless analysis.) The oil temperature is recorded at the time the sample is taken and the sample is then sent to a chemical laboratory to analyze the ppm water in oil.

From the ppm in the oil sample and the temperature of the oil, the Piper chart can be used to get an approximate indication of the percent moisture in the kraft paper.

Note that the temperature of the oil/paper interface has a significant effect on the equilibrium moisture concentration, but the temperatures of the oil and the paper vary depending on location. We would then expect the equilibrium moisture concentration to vary as well, which it does.

Generally, the insulation near the hottest spot will have less percent moisture than insulation exposed to cooler oil at the bottom of the transformer. An ‘‘average’’ value of the percent moisture concentration could be calculated from an ‘‘average’’ temperature; however, this may result in a misleading assessment of the transformer’s state because of the wide variation in moisture concentrations.

A conservative assessment would base the percent moisture on the oil temperature at the bottom of the tank. According to the Transformer Maintenance Institute, 2% is the absolute upper limit for acceptability for percent moisture in kraft paper.

Generally, if the percent moisture is less than 1%, the transformer is considered ‘‘dry.’’ There is also an equilibrium equation between vapor pressure of water in air (humidity) and % water in paper.

T = 40.17 + 22.285 Ln pct + 14.056 Ln vap (8.8.2)
where vap vapor pressure, mmHg.

Since the dew point of air is related to the vapor pressure, a dew-point measurement of the space inside a transformer before oil filling is a very good indication of the amount of water locked in the paper. This will determine whether oil filling should proceed or further drying is necessary.
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