Distribution Transformers

Authored by: Dudley L. Galloway , Dan Mulkey , Alan L. Wilks

Electric Power Transformer Engineering

Print publication date:  May  2012
Online publication date:  May  2012

Print ISBN: 9781439856291
eBook ISBN: 9781439856369

10.1201/b12110-4

Abstract

In 1886, George Westinghouse built the first long-distance ac (alternating current) electric lighting system in Great Barrington, Massachusetts. The power source was a 25 hp steam engine driving an alternator with an output of 500 V and 12 A. In the middle of town, 4000 ft away, transformers were used to reduce the voltage to serve light bulbs located in nearby stores and offices (Powel, 1997).

3.1.1  Long-Distance Power

In 1886, George Westinghouse built the first long-distance ac (alternating current) electric lighting system in Great Barrington, Massachusetts. The power source was a 25 hp steam engine driving an alternator with an output of 500 V and 12 A. In the middle of town, 4000 ft away, transformers were used to reduce the voltage to serve light bulbs located in nearby stores and offices (Powel, 1997).

3.1.2  First Transformers

Westinghouse realized that electric power could only be delivered over distances by transmitting at a higher voltage and then reducing the voltage at the location of the load. He purchased U.S. patent rights to the transformer developed by Gaulard and Gibbs, shown in Figure 3.1a. William Stanley, Westinghouse's electrical expert, designed and built the transformers to reduce the voltage from 500 to 100 V on the Great Barrington system. The Stanley transformer is shown in Figure 3.1b.

3.1.3  What Is a Distribution Transformer?

Just like the transformers in the Great Barrington system, any transformer that takes voltage from a primary distribution circuit and “steps down” or reduces it to a secondary distribution circuit or a consumer's service circuit is a distribution transformer. Many industry standards tend to limit this definition by kVA rating (e.g., 500 kVA and smaller for single-phase and 5000 kVA and smaller for three-phase), distribution transformers can have lower ratings and can have ratings of 5000 kVA or even higher.

Figure 3.1   (a) Gaulard and Gibbs transformer and (b) William Stanley's early transformer. (By permission of ABB Inc., Raleigh, NC.)

3.2.1  Early Transformer Materials

From the pictures in Figure 3.1, the Gaulard–Gibbs transformer seems to have used a coil of many turns of iron wire to create a ferromagnetic loop. The Stanley model, however, appears to have used flat sheets of iron, stacked together and clamped with wooden blocks and steel bolts. Winding conductors were most likely made of copper from the very beginning. Several methods of insulating the conductor were used in the early days. Varnish dipping was often used and is still used for some applications today. Paper-tape wrapping of conductors has been used extensively, but this has now been almost completely replaced by other methods.

3.2.2  Oil Immersion

In 1887, the year after Stanley designed and built the first transformers in the United States, Elihu Thompson patented the idea of using mineral oil as a transformer cooling and insulating medium (Myers et al., 1981). Although materials have improved dramatically, the basic concept of an oil-immersed cellulosic insulating system has changed very little in well over a century.

3.2.3  Core Improvements

The major improvement in core materials was the introduction of silicon steel in 1932. Over the years, the performance of electrical steels has been improved by grain orientation (1933) and continued improvement in the steel chemistry and insulating properties of surface coatings. The thinner and more effective the insulating coatings are, the more efficient a particular core material will be. The thinner the laminations of electrical steel, the lower the losses in the core due to circulating currents. Mass production of distribution transformers has made it feasible to replace stacked cores with wound cores. C-cores were first used in distribution transformers around 1940. A C-core is made from a continuous strip of steel, wrapped and formed into a rectangular shape, and then annealed and bonded together. The core is then sawn in half to form two C-shaped sections that are machine faced and reassembled around the coil. In the mid-1950s, various manufacturers developed wound cores that were die formed into a rectangular shape and then annealed to relieve their mechanical stresses. The cores of most distribution transformers made today are made with wound cores (originally patented in 1933). Typically, the individual layers are cut, with each turn slightly lapping over itself. This allows the core to be disassembled and put back together around the coil structures while allowing a minimum of energy loss in the completed core. Electrical steel manufacturers now produce stock for wound cores that is from 0.35 to 0.18 mm thick in various grades. In the early 1980s, rapid increases in the cost of energy prompted the introduction of amorphous core steel. Amorphous metal is cooled down from the liquid state so rapidly that there is no time to organize into a crystalline structure. Thus it forms the metal equivalent of glass and is often referred to as metal glass or “met-glass.” Amorphous core steel is usually 0.025 mm thick and offers another choice in the marketplace for transformer users that have very high energy costs.

3.2.4  Winding Materials

Conductors for low-voltage windings were originally made from small rectangular copper bars, referred to as “strap.” Higher ratings could require as many as 16 of these strap conductors in parallel to make one winding having the needed cross section. A substantial improvement was gained by using copper strip, which could be much thinner than strap but with the same width as the coil itself. In the early 1960s, instability in the copper market encouraged the use of aluminum strip conductor. The use of aluminum round wire in the primary windings followed in the early 1970s (Palmer, 1983) as a direct result of advanced methods in terminating aluminum wire. Today, both aluminum and copper conductors are used in distribution transformers, and the choice is largely dictated by economics. Round wire separated by paper insulation between layers has several disadvantages. The wire tends to “gutter,” that is, to fall into the troughs in the layer below. Also, the contact between the wire and paper occurs only along two lines on either side of the conductor. This is a significant disadvantage when an adhesive is used to bind the wire and paper together. To prevent these problems, manufacturers often flatten the wire into an oval or rectangular shape in the process of winding the coil. This allows more conductor to be wound into a given size of coil and improves the mechanical and electrical integrity of the coil (Figure 3.4).

3.2.5  Conductor Insulation

The most common insulation today for high-voltage windings is an enamel coating on the wire, with thermally upgraded kraft paper used between layers. Low-voltage strip can be bare with paper insulation between layers. The use of paper wrapping on strap conductor is slowly being replaced by synthetic polymer coatings or wrapping with synthetic cloth. For special applications, synthetic paper such as DuPont's Nomex*

Nomex is a registered trademark of E.I. du Pont de Nemours & Co., Wilmington, DE.

can be used in place of kraft paper to permit higher continuous operating temperatures within the transformer coils.

In 1958, manufacturers introduced insulating paper that was chemically treated to resist breakdown due to thermal aging. At the same time, testing programs throughout the industry were showing that the estimates of transformer life being used at the time were extremely conservative. By the early 1960s, citing the functional-life testing results, the industry began to change the standard average winding-temperature rise for distribution transformers, first to a dual rating of 55°C/65°C and then to a single 65°C rating as is currently used in IEEE C57.91. In some parts of the world, the distribution transformer standard remains at 55°C rise for devices using non-upgraded paper.

3.2.6  Conductor Joining

The introduction of aluminum wire, strap, and strip conductors and enamel coatings presented a number of challenges to distribution transformer manufacturers. Aluminum spontaneously forms an insulating oxide coating when exposed to air. This oxide coating must be removed or avoided whenever an electrical connection is desired. Also, electrical-conductor grades of aluminum are quite soft and are subject to cold flow and differential expansion problems when mechanical clamping is attempted. Some methods of splicing aluminum wires include soldering or crimping with special crimps that penetrate enamel and oxide coatings and seal out oxygen at the contact areas. Aluminum strap or strip conductors can be TIG (tungsten inert gas) welded. Aluminum strip can also be cold welded or crimped to other copper or aluminum connectors. Bolted connections can be made to soft aluminum if the joint area is properly cleaned. “Belleville” spring washers and proper torquing are used to control the clamping forces and contain the metal that wants to flow out of the joint. Aluminum joining problems are sometimes mitigated by using hard alloy tabs with tin plating to make bolted joints using standard hardware.

3.2.7.1  Mineral Oil

Mineral oil surrounding a transformer core–coil assembly enhances the dielectric strength of the winding and prevents oxidation of the core. Dielectric improvement occurs because oil has a greater electrical withstand than air and because the dielectric constant of oil, 2.2, is closer to that of the insulation. As a result, the stress on the insulation is lessened when oil replaces air in a dielectric system. Oil also picks up heat while it is in contact with the conductors and carries the heat out to the tank surface by self-convection. Thus a transformer immersed in oil can have smaller electrical clearances and smaller conductors for the same voltage and kVA ratings.

Beginning about 1932, a class of liquids called askarels or polychlorinated biphenyls (PCBs) was used as a substitute for mineral oil where flammability was a major concern. Askarel-filled transformers could be placed inside or next to a building where only dry types were used previously. Although these coolants were considered nonflammable, when used in electrical equipment they could decompose when exposed to electric arcs or fires to form hydrochloric acid and toxic furans and dioxins. The compounds were further undesirable because of their persistence in the environment and their ability to accumulate in higher animals, including humans. Testing by the U.S. Environmental Protection Agency has shown that PCBs can cause cancer in animals and cause other noncancerous health effects. Studies in humans provide supportive evidence for potential carcinogenic and noncarcinogenic effects of PCBs (http://www.epa.gov). The use of askarels in new transformers was outlawed in 1977 (Claiborne, 1999). Work still continues to retire and properly dispose of transformers containing askarels or askarel-contaminated mineral oil. IEEE C57.12.00 requires transformer manufacturers to state on the nameplate that new equipment left the factory with less than 2 ppm PCBs in the oil.

3.2.7.3  High-Temperature Hydrocarbons

Among the coolants used to take the place of askarels in distribution transformers are high-temperature hydrocarbons (HTHCs), also called high-molecular-weight hydrocarbons. These coolants are classified by the National Electric Code as “less flammable” if they have a fire point above 300°C. The disadvantages of HTHCs include increased cost and a diminished cooling capacity from the higher viscosity that accompanies the higher molecular weight.

3.2.7.4  Silicones

Another coolant that meets the National Electric Code requirements for a less-flammable liquid is a silicone, chemically known as polydimethylsiloxane. Silicones are only occasionally used because they exhibit biological persistence if spilled and are more expensive than mineral oil or HTHCs.

3.2.7.5  Halogenated Fluids

Mixtures of tetrachloroethane and mineral oil were tried as an oil substitute for a few years. This and other chlorine-based compounds are no longer used because of a lack of biodegradability, the tendency to produce toxic by-products, and possible effects on the Earth's ozone layer.

3.2.7.6  Natural Esters

Natural ester insulating fluids, particularly Cooper Power System's Envirotemp FR3 and ABB's BIOTEMP®, have become mainstream. Originating from vegetable seed, these fluids are renewable and biodegradable. In comparison to mineral oil, natural ester insulating fluids provide many improved characteristics. They are rated as a “less flammable fluid” per the NEC, providing increased fire safety from superior flash and fire resistance. They also provide high-temperature operating capability, and they are biodegradable. A few utilities and manufacturers are starting to design and operate natural ester insulated transformers at 75°C rise, marking the first major innovation since the adoption of upgraded kraft paper and the resulting shift from 55°C to 65°C operating temperature.

Figure 3.2   Typical three-phase pad-mounted distribution transformer. (By permission of ABB Inc., Jefferson City, MO.)

3.2.8  Tank and Cabinet Materials

A distribution transformer is expected to operate satisfactorily for 30 years in an outdoor environment while extremes of loading work to weaken the insulation systems inside the transformer. This high expectation demands the best in state-of-the-art design, metal processing, and coating technologies. A typical three-phase pad-mounted transformer is illustrated in Figure 3.2.

A suite of “enclosure integrity” standards has been developed to foster the ability of these transformers to withstand the environments in which they operate:

• IEEE C57.12.28, Standard for Pad-Mounted Equipment—Enclosure Integrity
• IEEE C57.12.29, Standard for Pad-Mounted Equipment—Enclosure Integrity for Coastal Environments
• IEEE C57.12.30, Standard for Pole-Mounted Equipment—Enclosure Integrity for Coastal Environments
• IEEE C57.12.31, Standard for Pole-Mounted Equipment—Enclosure Integrity
• IEEE C57.12.32, Standard for Submersible Equipment—Enclosure Integrity

3.2.8.1  Mild Steel

Most overhead and pad-mounted transformers have their tank and cabinet parts made from mild carbon steel. In recent years, major manufacturers have started using coatings applied by electrophoretic methods (aqueous deposition) and by powder coating. These new methods have largely replaced the traditional flow-coating and solvent-spray application methods.

3.2.8.2  Stainless Steel

Since the mid-1960s and continuing through the 1990s, single-phase submersibles were almost exclusively made using AISI 400-series stainless steel. These grades of stainless steel were selected for their good welding properties and their tendency to resist pit corrosion. Lately, both 400-series and 304L (low-carbon chromium–nickel) stainless steel have been used for transformer tanks and cabinets. While 304L is more expensive than 400, it is available in larger sheets. This made it feasible to build three-phase submersibles and pad mounts in stainless steel.

Utilities specify stainless steel tanks and cabinets for pad mounts and pole types where severe environments justify the added cost. Transformer users with severe coastal environments have observed that pad mounts show the worst corrosion damage where the cabinet sill and lower areas of the tank contact the pad. This is easily explained by the tendency for moisture, leaves, grass clippings, lawn chemicals, etc., to collect on the pad surface. Higher areas of a tank and cabinet are warmed and dried by the operating transformer, but the lowest areas in contact with the pad remain cool. Also, the sill and tank surfaces in contact with the pad are most likely to have the paint scratched. To address this, manufacturers sometimes offer hybrid transformers, where the cabinet sill, hood, or the tank base may be selectively made from stainless steel.

Figure 3.3   Single-phase transformer with composite hood. (By permission of ABB Inc., Jefferson City, MO.)

3.2.8.3  Composites

There have been many attempts to conquer the corrosion tendencies of transformers by replacing metal structures with reinforced plastics. One of the more successful was a one-piece composite hood for single-phase pad-mounted transformers (Figure 3.3). However the major disadvantage of composites is the high cost of the mold and the extremely limited ability to make structural modifications. Metal cabinets, on the other hand, are infinitely and easily variable over large ranges.

3.2.9  Modern Processing

Today's distribution transformers almost universally use thermally upgraded kraft insulating paper that has a diamond pattern of epoxy adhesive on each side. Each finished coil is heated before assembly. The heating drives out any moisture that might have been absorbed in the insulation. Bringing the entire coil to the elevated temperature also causes the epoxy adhesive to bond and cure, making the coil into a solid mass. Thus it is more capable of sustaining the high thermal and mechanical stresses that the transformer encounters under short-circuit current conditions. Sometimes the application of heat is combined with clamping of the coil sides to ensure intimate contact of the epoxy-coated paper with the conductors as the epoxy cures. Another way to improve adhesive bonding in the high-voltage winding is to flatten round wire as the coil is wound. This produces two flat sides, hence more surface area, to contact adhesive on the layer paper above and below the conductor. It also improves the space factor of the conductor cross section, permitting more actual conductor to fit within the same core window. Flattened conductor is less likely to “gutter” or fall into the spaces in the previous layer, damaging the layer insulation. Figure 3.4 shows a cross section of enameled round wire after flattening.

Figure 3.4   Cross section of enameled round wire after flattening. (By permission of ABB Inc., Jefferson City, MO.)

3.2.9.2  Vacuum Processing

With the coil still warm from the bonding process, transformers are held at a high vacuum while oil flows into the tank. The combination of heat and vacuum assures that all moisture and all air bubbles have been removed from the coil, providing electrical integrity and a long service life. Factory processing with heat and vacuum is impossible to duplicate in the field or in most service facilities. Transformers, if opened, should be exposed to the atmosphere for minimal amounts of time, and oil levels should never be taken down below the tops of the coils. All efforts must be taken to keep air bubbles out of the insulation structure.

3.3.1  Liquid-Filled vs. Dry Type

The vast majority of distribution transformers on utility systems today are liquid filled. Liquid-filled transformers offer the advantages of smaller size, lower cost, and greater overload capabilities compared with dry types of the same rating.

3.3.2  Stacked vs. Wound Cores

Stacked-core construction favors the manufacturer who makes a small quantity of widely varying special designs in its facility. A manufacturer who builds large quantities of identical designs will benefit from the automated fabrication and processing of wound cores. Figure 3.5 shows three-phase stacked and wound cores.

Figure 3.5   Three- and four-legged stacked cores and five-legged wound core. (From IEEE C57.105-1978, IEEE Guide for Application of Transformer Connections in Three-Phase Distribution Systems, Copyright 1978, Institute of Electrical and Electronics Engineers, Inc., Piscataway, NJ. Reprinted with the permission of the IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in the described manner.)

Figure 3.6   Core-form construction. (From IEEE C57.105-1978, IEEE Guide for Application of Transformer Connections in Three-Phase Distribution Systems, Copyright 1978, Institute of Electrical and Electronics Engineers, Inc., Piscataway, NJ. Reprinted with the permission of the IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in the described manner.)

3.3.3  Single-Phase

The vast majority of distribution transformers used in North America are single-phase transformers serving single-phase, 120/240 V, residential load. Single-phase transformers can also be connected into banks comprised of two or three separate units. Each unit in a bank has the same voltage ratings but need not have the same kVA rating. These banks can then serve three-phase load.

3.3.3.1  Core-Form Construction

A single core loop linking two identical winding coils is referred to as core-form construction. This is illustrated in Figure 3.6.

3.3.3.2  Shell-Form Construction

A single winding structure linking two core loops is referred to as shell-form construction. This is illustrated in Figure 3.7.

3.3.3.3  Winding Configuration

Most distribution transformers for residential service are built as a shell form, where the secondary winding is split into two sections with the primary winding in between. This so-called LO-HI-LO configuration results in lower impedance than if the secondary winding is contiguous. The LO-HI configuration is used where higher impedance is desired and especially on higher-kVA ratings where higher impedances are mandated by standards to limit short-circuit current. Core-form transformers are always built LO-HI because the two coils must always carry the same currents. A 120/240 V service using core-form in the LO-HI-LO configuration would need eight interconnected coil sections. This is considered too complicated to be commercially practical. LO-HI-LO and LO-HI configurations are illustrated in Figure 3.8.

3.3.4  Three-Phase

Most distribution transformers built and used outside North America are three-phase, even for residential service. In North America, three-phase transformers serve agricultural, commercial, and industrial loads. They are also used to supply large residential complexes, such as condominiums and high-rise buildings. A relatively new application for three-phase transformers is in “wind farms” where transformers are used to step up the voltage from wind turbines (around 600 V) to a distribution voltage (typically 19,920 V). All three-phase distribution transformers are said to be of core-form construction, although the definitions outlined earlier do not hold. Three-phase transformers have one coaxial coil for each phase encircling a vertical leg of the core structure. Stacked cores have three or possibly four vertical legs, while wound cores have a total of four loops creating five legs or vertical paths: three down through the center of the three coils and one on the end of each outside coil. The use of three vs. four or five legs in the core structure has a bearing on which electrical connections and loads can be used by a particular transformer. The advantage of three-phase electrical systems in general is the economy gained by having the phases share common conductors and other components. This is especially true of three-phase transformers using common core structures. See Figure 3.5.

Figure 3.7   Shell-form construction. (From IEEE C57.105-1978, IEEE Guide for Application of Transformer Connections in Three-Phase Distribution Systems, Copyright 1978, Institute of Electrical and Electronics Engineers, Inc., Piscataway, NJ. Reprinted with the permission of the IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in the described manner.)

Figure 3.8   LO-HI-LO and LO-HI configurations. (By permission of ABB Inc., Jefferson City, MO.)

3.3.5  Duplex and Triplex Construction

Occasionally, utilities will require a single tank that contains two completely separate core–coil assemblies. Such a design is sometimes called a duplex and can have any size combination of single-phase core–coil assemblies inside. The effect is the same as constructing a two-unit bank with the advantage of having only one tank to place. Duplexes are particularly useful in serving a small three-phase load in combination with single-phase load, such as a sewer lift pump and multiple residential houses. Similarly, a utility may request a triplex transformer with three completely separate and distinct core structures (of the same kVA rating) mounted inside one tank.

3.3.6  Serving Single- and Three-Phase Loads

The utility engineer has a number of transformer configurations to choose from, and it is important to match the transformer to the load being served. Small single-phase loads are easily served by a single-phase transformer. A large single-phase load may be best served by a three-phase transformer with the single-phase load balanced among the three phases. Add a little three-phase load, and the best bet is a bank of two transformers or a duplex. Increase the three-phase load and retain the single-phase load, and the best bank is a bank of three transformers. A balanced three-phase load is best served by a three-phase transformer, with each phase's coil identically loaded (ABB, 1995).

Another driver is the service voltage. Single-phase transformers commonly serve 120/240 V load, and banks of two or three single-phase transformers serve a mixture of 120/240 V single-phase and 240 V three-phase loads. These transformers are commonly available through 500 kVA. Three-phase 120/208 V can be served by a bank of three single-phase transformers or a three-phase transformer. Dense clusters of single-phase residential load can be served at 120/208 V using a three-phase transformer. The 120/208 V secondary is available through 1000 kVA. For larger loads, 277/480 V is commonly used, and while usually served from a three-phase transformer can also be supplied by a bank of appropriately rated single-phase transformers. Even larger loads are served using 2400, 4160, or 2400/4160 V from a three-phase transformer, utilizing what in older areas is a primary voltage as a service voltage.

3.4.1  Single-Phase Primary Connections

Single-phase transformers have a single primary winding and have either two insulated terminations or one insulated and one grounded termination.

3.4.1.1  Grounded Wye Connection

Single-phase transformers that must have one side of the primary grounded are only provided with one primary connection bushing. The primary circuit is completed by grounding the transformer tank to the grounded system neutral. Thus, it is imperative that proper grounding procedure be followed when the transformer is installed so that the tank never becomes “hot.” Since one end of the primary winding is always grounded, the manufacturer can economize the design and grade the high-voltage insulation. Grading provides less insulation at the end of the winding closest to ground. A transformer with graded insulation usually cannot be converted to operate phase-to-phase. The primary-voltage designation on the nameplate of a graded insulation transformer will include the letters, “GRDY,” as in “12470 GRDY/7200,” indicating that it must be connected phase-to-ground on a grounded wye system.

3.4.1.2  Fully Insulated Connection

Single-phase transformers supplied with fully insulated (not graded) coils and two separate primary connection bushings may be connected phase-to-phase on a three-phase system or phase-to-ground on a grounded wye system. The primary voltage designation on the nameplate of a fully insulated transformer will look like 7200/12470Y, where 7200 is the coil voltage. If the primary voltage shows only the coil voltage, as in 2400, then the bushings can sustain only a limited voltage from the system ground, and the transformer must be connected phase-to-phase.

Figure 3.9   Single-phase secondary connections. (By permission of ABB Inc., Jefferson City, MO.)

3.4.2  Single-Phase Secondary Connections

Single-phase distribution transformers usually have two, three, or four secondary bushings, and the most common voltage ratings are 240 and 480, with and without a mid-tap connection. Figure 3.9 shows various single-phase secondary connections.

3.4.2.1  Two Secondary Bushings

A transformer with two bushings can supply only a single voltage to the load.

3.4.2.2  Three Secondary Bushings

A transformer with three bushings supplies a single voltage with a tap at the midpoint of that voltage. This is the common three-wire residential service used in North America. For example, a 120/240 V secondary can supply load at either 120 or 240 V as long as neither 120 V coil section is overloaded. Transformers with handholes or removable covers can be internally reconnected from three to two bushings in order to serve full kVA from the parallel connection of coil sections. These are designated 120/240 or 240/480 V, with the smaller value first. Most pad-mounted distribution transformers are permanently and completely sealed and therefore cannot be reconnected from three to two bushings. The secondary voltage for permanently sealed transformers with three bushings is 240/120 or 480/240 V.

3.4.2.3  Four Secondary Bushings

Secondaries with four bushings can be connected together external to the transformer to create a mid-tap connection with one bushing in common, or a two-bushing connection where the internal coil sections are paralleled. The four-bushing secondary will be designated as 120/240 or 240/480 V, indicating that a full kVA load can be served at the lower voltage. The distinction between 120/240 and 240/120 V must be carefully followed when transformers are being specified.

3.4.3  Three-Phase Connections

When discussing three-phase distribution transformer connections, it is well to remember that this can refer to a single three-phase transformer or two or three single-phase transformers interconnected to create a three-phase bank. For either an integrated transformer or a bank, the primary or secondary can be wired in either delta or wye connection. The wye connections can be either grounded or ungrounded. However, not all combinations will operate satisfactorily, depending on the transformer construction, characteristics of the load, and the source system. Detailed information on three-phase connections can be found in IEEE C57.105 or in the ABB Distribution Transformer Guide (ABB, 1995). Some connections that are of special concern are listed as follows.

3.4.3.1  Ungrounded Wye–Grounded Wye

A wye–wye connection where the primary neutral is left floating produces an unstable neutral where high third-harmonic voltages are likely to appear. In some Asian systems, the primary neutral is stabilized by using a three-legged core and by limiting current unbalance on the feeder at the substation.

3.4.3.2  Grounded Wye–Delta

This connection is called a grounding transformer. Unbalanced primary voltages will create high currents in the delta circuit. Unless the transformer is specifically designed to handle these circulating currents, the secondary windings can be overloaded and burn out. Unless its use is intended to be as a grounding transformer, the use of the ungrounded wye–delta is suggested instead.

3.4.3.3  Grounded Wye–Grounded Wye

A grounded wye–wye connection will sustain unbalanced voltages, but it must use a four- or five-legged core to provide a return path for zero-sequence flux.

3.4.3.4  Three-Phase Secondary Connections–Delta

Three-phase transformers or banks with delta secondaries will have simple nameplate designations such as 240 or 480. If one winding has a mid-tap, say for lighting, then the nameplate will say 240/120 or 480/240, similar to a single-phase transformer with a center tap. Delta secondaries can be grounded at the mid-tap or any corner.

3.4.3.5  Three-Phase Secondary Connections–Wye

Popular voltages for wye secondaries are 208Y/120, 480Y/277, and 600Y/347.

3.4.4  Open-Delta Connections

Two single-phase transformers and duplex transformers can be connected into a bank having either an open-wye or open-delta primary along with an open-delta secondary. Such banks are usually used to serve loads that are predominantly single-phase in conjunction with some three-phase load. The secondary leg serving the single-phase load usually has a mid-tap, which is grounded.

3.4.5  Other Connections

For details on other connections such as T-T and zigzag, consult IEEE C57.12.80, IEEE C57.105, or the ABB Distribution Transformer Guide (ABB, 1995).

3.4.6  Preferred Connections

In the earliest days of electric utility systems, it was found that induction motors drew currents that exhibited a substantial third-harmonic component. In addition, transformers on the system that were operating close to the saturation point of their cores had third harmonics in the exciting current. One way to keep these harmonic currents from spreading over an entire system was to use delta-connected windings in transformers. Third-harmonic currents add up in phase in a delta loop and flow around the loop, dissipating themselves as heat in the windings but minimizing the harmonic voltage distortion that might be seen elsewhere on the utility's system. With the advent of suburban underground systems in the 1960s, it was found that a transformer with a delta-connected primary was more prone to ferroresonance problems because of higher capacitance between buried primary cables and ground. An acceptable preventive was to go to grounded-wye–grounded-wye transformers on all but the heaviest industrial applications.

3.5  Operational Concerns

Even with the best engineering practices, abnormal situations can arise that may produce damage to equipment and compromise the continuity of the delivery of quality power from the utility.

3.5.1  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, potentially 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 3.10 and consists of long underground cables feeding a transformer with a delta-connected primary. 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 or second switch is closed, or it can occur if one or two phases open and the load is very light. Ferroresonance will disappear as soon as all three phases are closed or opened. Ferroresonance is more likely to occur on systems with higher primary voltage. Occasionally it has been observed even when there is no cable present. All of these factors—delta or wye connection, cable length, voltage, load, single-phase switching—affect ferroresonance. Attempts to set precise limits for prevention of the phenomenon have been frustrating.

Figure 3.10   Typical ferroresonance situation. (From IEEE C57.105-1978, IEEE Guide for Application of Transformer Connections in Three-Phase Distribution Systems, Copyright 1978, Institute of Electrical and Electronics Engineers, Inc., Piscataway, NJ. Reprinted with the permission of the IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in the described manner.)

3.5.2  Tank Heating

Another phenomenon that can occur on three-phase transformers because of the common core structure between phases is tank heating. Wye–wye-connected transformers that are built on four- or five-legged cores are likely to saturate the return legs when zero-sequence voltage exceeds about 33% of the normal line-to-neutral voltage. This can happen, for example, if two phases of an overhead line wrap together and are energized by a single electrical phase. When the return legs are saturated, magnetic flux is then forced out of the core and finds a return path through the tank walls. Eddy currents produced by magnetic flux in the ferromagnetic tank steel will produce tremendous localized heating, occasionally burning the tank paint and boiling the oil inside. For most utilities, the probability of this happening is so low that it is not economically feasible to take steps to prevent it. A few, with a higher level of concern, purchase only triplex transformers, having three separate core–coil assemblies in one tank.

3.5.3  Polarity and Angular Displacement

The phase relationship of single-phase transformer voltages is described as “polarity.” The term for voltage phasing on three-phase transformers is “angular displacement.”

3.5.3.2  Three-Phase Angular Displacement

The phase relation of voltage between H1 and X1 bushings on a three-phase distribution transformer is referred to as angular displacement. IEEE standards require that wye–wye and delta–delta transformers have 0° displacement. Wye–delta and delta–wye transformers will have X1 lagging H1 by 30°. This difference in angular displacement means that care must be taken when the secondaries of three-phase transformers are paralleled. Sometimes the phase difference is used to advantage, such as when supplying power to 12-pulse rectifiers or other specialized loads. European standards permit a wide variety of displacements, the most common being Dy11. This IEC designation is interpreted as delta primary–wye secondary, with X1 lagging H1 by 11° × 30° = 330°, or leading by 30°. The angular displacement of Dy11 differs from the IEEE angular displacement by 60°. Three-phase angular displacement is illustrated in Figure 3.12.

Figure 3.11   Single-phase polarity. (Reprinted from IEEE C57.12.90-1999, IEEE Standard Test Code for Liquid-Immersed Distribution, Power, and Regulating Transformers, Copyright 1999, Institute of Electrical and Electronics Engineers, Inc. With permission.)

Figure 3.12   Three-phase angular displacement. (From IEEE C57.105-1978, IEEE Guide for Application of Transformer Connections in Three-Phase Distribution Systems, Copyright 1978, Institute of Electrical and Electronics Engineers, Inc., Piscataway, NJ. Reprinted with the permission of the IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in the described manner.)

3.6  Transformer Locations

With electric wires being strung at the tops of poles to keep them out of the reach of the general public, it is obvious that transformers would be hung on the same poles, as close as possible to the high-voltage source conductors. Larger units were often placed on overhead platforms in alleyways, or alongside buildings, or on ground-level pads protected by fencing. While overhead construction is still the most economical choice in rural areas, it has the disadvantage of susceptibility to ice and wind storms. Also the public no longer perceives overhead wiring as a sign of progress, instead considering it an eyesore that should be eliminated from view. In some areas, this has lead to most new construction being underground, rather than overhead.

3.6.2  Underground

Larger cities with concentrated commercial loads and tall buildings have had underground primary cables and transformers installed in below-grade ventilated vaults since the early part of the twentieth century. By connecting many transformers into a secondary network, service to highly concentrated loads can be maintained even though a single transformer may fail. In a secondary network, temporary overloads can be shared among all the connected transformers.

The use of underground distribution for light industrial, commercial, and residential service became popular in the 1960s, with the emphasis on beautification that promoted fences around scrap yards and the elimination of overhead electric and telephone lines. The most common construction method for residential electric services is underground primary cables feeding a transformer placed on a pad at ground level. The problems of heat dissipation and corrosion are only slightly more severe than for overheads, but they are substantially reduced compared with transformers confined in below-grade ventilated vaults. Since pad mounts are intended to be placed in locations that are frequented by the general public, the operating utility has to be concerned about security of the locked cabinet covering the primary and secondary connections to the transformer. The industry has established standards for security against unauthorized entry and vandalism of the cabinet and for locking provisions; see IEEE C57.12.28 and IEEE C57.12.29. Another concern is the minimization of sharp corners or edges that may be hazardous to children at play and that also has been addressed by standards. The fact that pad-mounted transformers can operate with surface temperatures near the boiling point of water is a further concern that is voiced from time to time. One argument used to minimize the danger of burns is to point out that it is no more hazardous to touch a hot transformer than it is to touch the hood of an automobile on a sunny day. From a scientific standpoint, research has shown that people will pull away after touching a hot object in a much shorter time than it takes to sustain a burn injury. The point above which persons might be burned is about 150°C (Hayman et al., 1973). See Section 3.8 for a detailed description of underground transformers.

3.6.3  Directly Buried

Through the years, attempts have been made to place distribution transformers directly in the ground without a means of ventilation. A directly buried installation may be desirable because it is completely out of sight and cannot be damaged by windstorms, trucks and automobiles, or lawn mowers. There are three major challenges when directly buried installations are considered: the limited operational accessibility, a corrosive environment, and the challenge of dissipating heat from the transformer. The overall experience has been that heat from a buried transformer tends to dry out earth that surrounds it, causing the earth to shrink and create gaps in the heat-conduction paths to the ambient soil. If a site is found that is always moist, then heat conduction may be assured, but corrosion of the tank or of cable shields is still a major concern. Advances in encapsulation materials and techniques have fostered development of a solid-insulation distribution transformer that can be installed in a ventilated vault or directly buried using thermal backfill materials while maintaining loadability comparable with overhead or pad-mounted transformers. For further information, see Section 3.8.5.3.

3.6.4  Interior Installations

Building codes may completely prohibit the installation of a distribution transformer containing mineral oil inside an occupied building or it may only require that the room be built to a 3 h fire rating. Other options available include use of a dry-type transformer or the replacement of mineral oil with a less-flammable coolant. See Section 3.2.7 regarding coolants.

Overhead transformers are self-cooled, liquid-filled, sealed units designed for step-down operation from overhead primary wires. These are the most prevalent type of distribution transformer in North America. They are available in both single- and three-phase designs. These transformers are detailed in IEEE C57.12.20. The coating requirements are detailed in IEEE C57.12.30 for normal and IEEE C57.12.31 for coastal areas. The tanks of overhead transformers used in North America are usually round though some three-phase are made in rectangular tanks. The singe-phase transformers may have one or two primary bushings and usually have three or four secondary bushings. Three-phase overhead transformers have three primary bushings and three or four secondary bushings.

3.8  Underground Distribution Transformers

Underground transformers are self-cooled, liquid-filled, sealed units designed for step-down operation from an underground primary-cable supply. They are available in both single- and three-phase designs. Underground transformers can be separated into three subgroups: those designed for installation in room-like vaults, those designed for installation in surface-operable enclosures, and those designed for installation on a pad at ground level.

3.8.1  Vault Installations

The vault provides the required ventilation, access for operation, maintenance, and replacement, while at the same time providing protection against unauthorized entry. Vaults used for transformer installations are large enough to allow personnel to enter the enclosure, typically through a manhole and down a ladder. Vaults are typically rated as “confined spaces” and have special operating practices to deal with the increased work hazard. Vaults have been used for many decades, and it is not uncommon to find installations that date back to the early part of the twentieth century when only paper-and-lead-insulated primary cable was available. Transformers for vault installations are typically designed for radial application and have a separate fuse installation on their source side.

Vaults can incorporate many features:

• Removable top sections for transformer replacement
• Automatic sump pumps to keep water levels down
• Chimneys to increase natural air flow
• Forced-air circulation

Transformers for vault installation are manufactured as either subway transformers or as vault-type transformers, which, according to IEEE C57.12.40, are defined as follows:

• Vault-type transformers are suitable for occasional submerged operation.
• Subway transformers are suitable for frequent or continuous submerged operation.

From the definitions, the vault-type transformer should only be used when a sump pump is installed, while the subway-type could be installed without a sump pump. The principal distinction between vault-type and subway transformers is their corrosion resistance. For example, the network transformer standard, IEEE C57.12.40, requires increased corrosion of subway transformers in comparison to vault-type transformers. In utility application, vault and subway types may be installed in the same type of enclosure, and the use of a sump pump is predicated more on the need for quick access for operations than it is on whether the transformer is a vault or subway type.

Figure 3.13   Network transformer with protector. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

3.8.1.1.1  Network Transformers

As defined in IEEE C57.12.80, network transformers (see Figure 3.13) are designed for use in vaults to feed a variable-capacity system of interconnected secondaries. Typically they are three-phase transformers that are designed to connect through a network protector to a secondary network system. Network transformers are usually applied to serve loads in the downtown areas of a major city. National standard IEEE C57.12.40 provides details for network transformers. The standard kVA ratings are 300, 500, 750, 1000, 1500, 2000, and 2500 kVA. The primary voltages range from 2,400 to 34,500 V. The secondary voltages are 216Y/125 or 480Y/277.

Network transformers are built as either vault type or subway type. They typically incorporate a primary switch with open, closed, and ground positions. Primary cable entrances are made by one of the following methods:

1. Wiping sleeves or entrance fittings for connecting to lead cables—either one three-conductor or three single-conductor fittings or sleeves
2. Bushing wells or integral bushings for connecting to plastic cables—three wells or three bushings

3.8.1.1.2  Network Protectors

Although not a transformer, the network protector is associated with the network transformer. The protector is an automatic switch that connects and disconnects the transformer from the secondary network being served. The protector connects the transformer when power flows from the primary circuit into the secondary network, and it disconnects on reverse power flow from the secondary to the primary. The protector is described in IEEE C57.12.44. The protector is typically mounted on the secondary throat of the network transformer, as shown in Figure 3.13.

3.8.1.1.3  Single-Phase Subway or Vault Types

These are round single-phase transformers designed to be installed in a vault and capable of being banked together to provide three-phase service (Figure 3.14). These can be manufactured as either subway-type or vault-type transformers. They are typically applied to serve small- to medium-sized commercial three-phase loads or mixed residential and small commercial loads. The standard kVA ratings are 25, 37.5, 50, 75, 100, 167, and 250 kVA. Primary voltages range from 2,400 to 34,500 V, with the secondary voltage usually being 120/240. Four secondary bushings allow the secondary windings to be connected in parallel for wye connections or in series for delta connections. The secondary can be either insulated cables or spades. The units are designed to fit through the utilities standard manhole diameter. They are not specifically covered by a national standard; however, they are very similar to the units in IEEE C57.12.23. Units with three primary bushings or wells, and with an internal primary fuse (Figure 3.15), allow for connection in closed-delta, wye, or open-wye banks. They can also be used for single-phase phase-to-ground connections.

Figure 3.14   Single-phase subway. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Figure 3.15   Three-bushing subway. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Units with two primary bushings or wells and with two internal primary fuses (Figure 3.16) allow for connection in an open-delta or an open-wye bank. This construction also allows for single-phase line-to-line connections.

3.8.1.1.4  Three-Phase Subway or Vault Types

These are rectangular-shaped three-phase transformers that can be manufactured as either subway type or vault type. Figure 3.17 depicts a three-phase vault-type transformer. These are usually used to supply large three-phase commercial loads. Typically they have primary-bushing well terminations on one of the small sides and the secondary bushings with spades on the opposite end. These are also designed for radial installation and require external fusing. They can be manufactured in any of the standard three-phase kVA sizes and voltages. They are not detailed in a national standard.

Figure 3.16   Two-bushing subway. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Figure 3.17   Three-phase vault. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

3.8.2  Surface-Operable Installations

Surface-operable installations are designed to be hot-stick operable by a person standing at ground level at the edge of the enclosure. The enclosure has grade-level covers that can be removed to gain access to the equipment. The subsurface enclosure provides the required ventilation as well as access for operation, maintenance, and replacement, while at the same time providing protection against unauthorized entry. The enclosures typically are just large enough to accommodate the largest size of transformer and allow for proper cable bending. Transformers for installation in surface-operable enclosures are manufactured as submersible transformers, which are defined in IEEE C57.12.80 as “so constructed as to be successfully operable when submerged in water under predetermined conditions of pressure and time.” These transformers are designed for loop application and thus require internal protection. Submersible transformers are designed to be connected to an underground distribution system that utilizes 200 A class equipment. The primary is most often #2 or 1/0 cables with 200 A elbows. While larger cables such as 4/0 can be used with the 200 A elbows, it is not recommended. The extra stiffness of 4/0 cable makes it very difficult to avoid putting strain on the elbow–bushing interface, which may lead to early failure. The operating points of the transformer are arranged on or near the transformer cover. There are three typical variations of submersible transformers.

Figure 3.18   Single-phase round. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

3.8.2.1  Single-Phase Round Submersible

Single-phase round transformers (Figure 3.18) have been used since the early 1960s. These transformers are typically applied to serve residential single-phase loads. These units are covered by IEEE C57.12.23. They are manufactured in the normal single-phase kVA ratings of 25, 37.5, 50, 75, 100, and 167 kVA. Primary voltages are available from 2,400 through 24,940 GrdY/14,400, and the secondary is 240/120 V. They are designed for loop-feed operation with a 200 A internal bus connecting the two bushings. Three low-voltage cable leads are provided through 100 kVA, while the 167 kVA size has six. They commonly come in two versions—a two-primary-bushing unit (Figure 3.19) and a four-primary-bushing unit (Figure 3.20)—although only the first is detailed in the standard. The two-bushing unit is for phase-to-ground-connected transformers, while the four-bushing unit is for phase-to-phase-connected transformers. As these are designed for application where the primary continues after feeding through the transformer, the transformers require internal protection.

Figure 3.19   Two-primary bushing. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Figure 3.20   Four-primary bushing. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Protection options include

• Dry-well current-limiting fuse with an interlocked switch to prevent the fuse from being removed while energized
• Submersible bayonet fuse with backup, under-oil, partial-range current-limiting (PRCL) fuses, or with backup internal nonreplaceable primary-expulsion fuse elements
• Secondary circuit breaker and an internal, replaceable, primary-expulsion fuse element

These units are designed for installation in a 42 or 48 in. diameter round enclosure. Enclosures have been made of fiberglass or concrete. Installations have been made with and without a solid bottom. Those without a solid bottom simply rest on a gravel base.

3.8.2.2  Single-Phase Horizontal Submersible

Functionally, single-phase horizontal submersible transformers are the same as the round single-phase. However, they are designed to be installed in a rectangular enclosure, as shown in Figure 3.21. Three low-voltage cable leads are provided through 100 kVA, while the 167 kVA size has six. They are manufactured in both four-primary-bushing designs (Figure 3.22) and in six-primary-bushing designs (Figure 3.23). As well as the normal single-phase versions, there is also a duplex version. This is used to supply four-wire, three-phase, 120/240 V services from two core-coil assemblies connected as open-delta on the secondary side. The primary can be either open-delta or open-wye. Horizontal transformers also have been in use since the early 1960s. These units are not specifically covered by a national standard. The enclosures used have included treated plywood, fiberglass, and concrete. The plywood and fiberglass enclosures are typically bottomless, with the transformer resting on a gravel base.

3.8.2.3  Three-Phase Submersible

The three-phase surface-operable units are detailed in IEEE C57.12.24. Typical application for these transformers is to serve three-phase commercial loads from loop-feed primary underground cables. Primary voltages are available from 2,400 through 34,500 V. The standard three-phase kVA ratings from 75 to 1000 kVA are available with secondary voltage of 208Y/120 V. With a 480Y/277 V secondary, the available sizes are 75–2500 kVA. Figure 3.24 depicts a three-phase submersible.

Figure 3.21   Four-bushing horizontal installed. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Figure 3.22   Four-bushing horizontal. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Figure 3.23   Six-bushing horizontal. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Figure 3.24   Three-phase submersible. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Protection options include

• Dry-well current-limiting fuses with an interlocked switch to prevent the fuses from being removed while energized
• Submersible bayonet fuses with backup, under-oil, PRCL fuses, or with backup internal nonreplaceable primary-expulsion fuse elements

These are commonly installed in concrete rectangular boxes with removable cover sections.

3.8.3.1  Tank Material

The substrate and coating should meet the requirements detailed in IEEE C57.12.32. The transformers can be constructed out of 400-series or 300-series stainless steels or out of mild carbon steel. In general, 300-series stainless steel outperforms 400-series stainless steel, which significantly outperforms mild carbon steel. Most of the small units are manufactured out of 400-series stainless steel since it is significantly less expensive than 300-series. Stainless steels from the 400-series with a good coating have been found to give satisfactory field performance. Stainless steel in the 400-series is not available in sheets large enough to make many of the three-phase transformers. That leaves the choice of mild steel or 300-series stainless. This was cost prohibitive in the past, but more recently, the cost differential has decreased leading some utilities to use nothing but stainless steel in their subsurface units.

3.8.3.2  Temperature Rating

By the IEEE standards, the kVA ratings are based on not exceeding an average winding-temperature rise of 55°C and a hottest-spot temperature rise of 70°C. However, they are constructed with the same 65°C rise insulation systems used in overhead and pad-mounted transformers. This gives a 10°C cushion to account for possible obstruction and reduced ventilation. Utilities commonly restrict loading on underground units to a lower limit than they do with pad-mounted or overhead units.

3.8.3.3  Siting

Subsurface units should not be installed if any of the following conditions apply:

• Soil is severely corrosive.
• Heavy soil erosion occurs.
• High water table causes repeated flooding of the enclosures.
• Heavy snowfall occurs.
• Severe mosquito problem exists.

3.8.3.4  Maintenance

Maintenance mainly consists of keeping the air vents free of foreign material, sump pumps operating and removing whatever has been dumped or washed into the enclosure or vault. Dirt allowed to stay packed against the tank can lead to accelerated anaerobic corrosion, resulting in tank puncture and loss of mineral oil.

3.8.4  Transformers inside Buildings

Utility transformers are sometimes installed in a room inside a building. This, of course, requires a specially designed room to limit exposure to fire and access by unauthorized personnel and to provide sufficient ventilation. Both mineral-oil-filled units and units with one of the less-flammable insulating oils are used in these installations. See Section 3.2.7 regarding coolants. These installations are typically made with transformers designed for vault installation, pad-mounted transformers, or with dry-type transformers.

3.8.5.1  Water Pumping

Pumping of water from subsurface enclosures has been increasingly regulated. In some areas, water with any oily residue or turbidity must be collected for hazardous-waste disposal. Subsurface and vault enclosures are often subject to runoff water from streets. This water can include oily residue from vehicles. So even without a leak from the equipment, water collected in the enclosure may be judged a hazardous waste.

Figure 3.25   Solid-insulation distribution transformer. (By permission of ABB Inc., Montreal, Quebec, Canada.)

3.8.5.2  West Nile Virus

Subsurface enclosures can provide breeding grounds for mosquitoes. With the spread of the West Nile virus, this can be a concern with local governmental agencies.

3.8.5.3  Solid Insulation

Transformers with solid insulation are commercially available for subsurface distribution applications (see Figure 3.25) with ratings up 167 kVA single-phase and 500 kVA three-phase. The total encapsulation of what is essentially a dry-type transformer allows it to be applied in a subsurface environment (direct buried or in a subsurface vault). The solid insulation distribution transformer addresses problems often associated with underground and direct buried transformers. See Sections 3.6.2 and 3.6.3. Such installations can be out of sight, below grade, and not subject to corrosion and contamination.

Pad-mounted transformers are the most commonly used type of transformer for serving loads from underground-distribution systems. They offer many advantages over subsurface, vault, or subway transformers. Some of these are listed as follows:

• Installation: less expensive to purchase and easier to install.
• Maintenance: easier to maintain.
• Operability: easier to find, less time to open and operate.

Many users and suppliers break distribution transformers into just two major categories—overhead and underground, with pad-mounted transformers included in the underground category. The IEEE standards, however, divide distribution transformers into three categories—overhead, underground, and pad mounted.

Pad-mounted transformers are manufactured as either of the following:

• Single-phase or three-phase units: single-phase units are designed to transform only one phase. Three-phase units transform all three phases. Most three-phase transformers use one three-, four-, or five-legged core structure, although duplex or triplex construction is used on occasion.
• Loop or radial units: loop-style units have the capability of terminating two primary conductors per phase. Radial-style units can only terminate one primary cable per phase. At a radial-style unit, the primary must end, but from a loop style, it can continue to serve other units.
• Live-front or dead-front units: live-front units have the primary cables terminated in a stress cone supported by a bushing. Thus the primary has exposed energized metal, or “live” parts. Dead-front units use primary cables that are terminated with high-voltage separable insulated connectors. Thus the primary has all “dead” parts—no exposed metal energized at primary voltages.

Single-phase pad-mounted transformers are usually applied to serve residential loads. 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 to feed the next transformer. These are detailed in the IEEE C57.12.38. The standard assumes that the residential subdivision is served by a one-wire primary extension. It details two terminal arrangements for loop-feed systems: Type 1, the straight feed, shown in Figure 3.26, and Type 2, the cross-feed, shown in Figure 3.27. Both have two primary bushings and three secondary bushings. The primary is always on the left, when 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 primary elbow terminations 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. Four-bushing units are required for single-phase lines on systems without a neutral conductor where transformers are 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.

Figure 3.26   Typical Type 1 loop-feed system. (By permission of ABB Inc., Raleigh, NC.)

Figure 3.27   Typical Type 2 loop-feed system. (By permission of ABB Inc., Raleigh, NC.)

Figure 3.28   Single-phase live front. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Cabinets for single-phase transformers are typically built in the clamshell configuration with one large door that swings up, as shown in Figures 3.26 and 3.27. Older units were manufactured with two doors, similar to the three-phase cabinets. New installations are almost universally dead front; however, live-front units (see Figure 3.28) 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.

Three-phase pad-mounted transformers are typically applied to serve commercial and industrial three-phase loads from underground distribution systems. Both the live-front and the dead-front pad-mounted transformers are detailed in IEEE C57.12.34.

3.9.2.1  Live Front

Live-front transformers are specified as radial units and thus do not come with any fuse protection. See Figure 3.29. The primary compartment is on the left and the secondary compartment is on the right, with a rigid barrier separating them. The secondary door must be opened before the primary door can be opened. Stress-cone-terminated primary cables rise vertically and connect to the terminals on the end of the high-voltage bushings. Secondary cables rise vertically and are terminated on spades connected to the secondary bushings. Units with a secondary of 208Y/120 V are available up to 1000 kVA. Units with a secondary of 480Y/277 V are available up to 2500 kVA.

Figure 3.29   Radial-style live front. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Figure 3.30   Loop-style live front. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Although not detailed in a national standard, there are many similar types available. A loop-style live front (Figure 3.30) can be constructed by adding fuses mounted below the primary bushings. Two primary cables are then both connected to the bottom of the fuse. The loop is then made at the terminal of the high-voltage bushing, external to the transformer but within its primary compartment.

Both radial- and loop-feed dead-front pad-mounted transformers are detailed in the standard. Radial-style units have three primary bushings arranged horizontally, as seen in Figure 3.31. Loop-style units have six primary bushings arranged in a V pattern, as seen in Figures 3.32 and 3.33. In both, the primary compartment is on the left, and the secondary compartment is on the right, often with a rigid barrier between them. The secondary door must be opened before the primary door can be opened. The primary cables are terminated with separable insulated high-voltage connectors, commonly referred to as 200 A elbows, specified in IEEE 386. These plug onto the primary bushings, which can be either bushing wells with an insert or integral bushings. Many users prefer bushing wells with inserts as many elbow failures also damage the bushing. With inserts, both the insert and elbow can easily be replaced. Units with a secondary of 208Y/120 V are available up to 1000 kVA. Units with a secondary of 480Y/277 V are available up to 3750 kVA.

Figure 3.31   Radial-style dead front. (By permission of Pacific Gas and Electric Company, San Francisco, CA.)

Figure 3.32   Small loop-style dead front. (By permission of ABB Inc., Raleigh, NC.)

Figure 3.33   Large loop-style dead front. (By permission of ABB Inc., Raleigh, NC.)

In addition to what is shown in the national standards, there are other variations available. The smallest size in the national standards is the 75 kVA unit. However, 45 kVA units are also manufactured in the normal secondary voltages. Units with higher secondary voltages, such as 2400 and 4160Y/2400, are manufactured in larger kVA sizes. There is also a style being produced that is a cross between single- and three-phase units. A small three-phase transformer is placed in a six-bushing loop-style clamshell cabinet, as seen in Figure 3.34. These are available from 45 to 150 kVA in both 208Y/120 and 480Y/277 V secondaries.

Figure 3.34   Mini three-phase in clamshell cabinet. (By permission of ABB Inc., Raleigh, NC.)

3.9.3.1  Protection

Most distribution transformers include some kind of primary overcurrent protection. For a detailed discussion, see Section 3.14.

3.9.3.2  Primary Conductor

Pad-mounted transformers are designed to be connected to an underground distribution system that utilizes 200 A class equipment. The primary is most often #2 or 1/0 cables with 200 A elbows or stress cones. It is recommended that larger cables such as 4/0 not be used with the 200 A elbows. The extra stiffness of 4/0 cable makes it very difficult to avoid putting strain on the elbow–bushing interface which can lead to premature elbow failures.

Pads are made out of various materials. The most common is concrete, which can be either poured in place or precast. Concrete is suitable for any size pad. Pads for single-phase transformers are also commonly made out of fiberglass or polymer concrete.

3.9.3.4  Enclosure

There are two national standards that specify the requirements for enclosure integrity for pad-mounted equipment: IEEE C57.12.28 for normal environments and IEEE C57.12.29 for coastal environments. The tank and cabinet of pad-mounted transformers are commonly manufactured out of mild carbon steel. When applied in corrosive areas, such as near the ocean, they are commonly made out of 300- or 400-series stainless steel. In general, 300-series stainless steel will outperform 400-series stainless steel, which significantly outperforms mild carbon steel in corrosive applications.

Figure 3.35   Tilting pad-mount transformer (a) Side view and (b) Front view.

3.9.3.5  Maintenance

Maintenance mainly consists of keeping the enclosure rust-free and in good repair so that it remains tamper resistant, that is, capable of being closed and locked so that it resists unauthorized entry.

3.9.3.6  Temperature Rating

The normal temperature ratings are used. The kVA ratings are based on not exceeding an average winding-temperature rise of 65°C and a hottest-spot temperature rise of 80°C over a daily average ambient of 30°C.

3.9.3.7  Tilting

Pad-mounted transformers are initially installed level; however, they can tilt after installation due to soil movement. Figure 3.35 shows a pad-mounted transformer as found in the field. The question that arises is when does this need to be corrected? The answer is not simple. A stable tilt may require no action, while an increasing tilt will require action at some point. If strain is being placed on a bushing by stretched cables, then action is needed. Internally, the core/coil assembly needs to remain under oil as does any operable component such as switches and fuses. Unfortunately, it is not easy task to determine the allowed maximum angle of tilt.

3.10.1  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.

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.

3.10.2.1  I2 R Loss

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

3.10.2.2  Stray Losses

When ac is used to measure the losses in a winding, the result is always greater than the I2R measured with dc. 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.

3.10.3  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 high in the 3rd, 5th, 7th, and sometimes the 11th and 13th harmonics, depending on the character of the load.

3.10.3.1  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. Transformers with load current containing more than 5% total harmonic distortion should be loaded according to IEEE C57.110.

3.10.3.2  Even-Ordered Harmonics

Analysis of most harmonic currents will show very low amounts of even harmonics (second, fourth, sixth, 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 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 no larger than the normal exciting current, which is usually 1% or less of a winding's rated current (Galloway, 1993).

3.11  Transformer Performance Model

A simple model will be developed to help explain performance characteristics of a distribution transformer, namely, impedance, short-circuit current, regulation, and efficiency.

3.11.1  Schematic

A simple two-winding transformer is shown in the schematic diagram of Figure 3.36. A primary winding of Np turns is on one side of a ferromagnetic core loop, and a similar coil having Ns turns is on the other. Both coils are wound in the same direction with the starts of the coils at H1 and X1, respectively. When an alternating voltage Vp is applied from H2 to H1, an alternating magnetizing flux φm flows around the closed core loop. A secondary voltage Vs = Vp × Ns/Np is induced in the secondary winding and appears from X2 to X1 and very nearly in phase with Vp. With no load connected to X1−X2, Ip consists of only a small current called the magnetizing current. When load is applied, current Is flows out of terminal X1 and results in a current Ip = Is × Ns/Np flowing into H1 in addition to magnetizing current. The ampere-turns of flux due to current Ip × Np cancels the ampere-turns of flux due to current Is × Ns, so only the magnetizing flux exists in the core for all the time the transformer is operating normally.

3.11.2  Complete Equivalent Circuit

Figure 3.37 shows a complete equivalent circuit of the transformer. An ideal transformer is inserted to represent the current- and voltage-transformation ratios. A parallel resistance and inductance representing the magnetizing impedance are placed across the primary of the ideal transformer. Resistance and inductance of the two windings are placed in the H1 and X1 legs, respectively.

3.11.3  Simplified Model

To create a simplified model, the magnetizing impedance has been removed, acknowledging that no-load loss is still generated and magnetizing current still flows, but it is so small that it can be ignored when compared with the rated currents. The R and X values in either winding can be translated to the other side by using percent values or by converting ohmic values with a factor equal to the turns ratio squared (Np/Ns)2. To convert losses or ohmic values of R and X to percent, use Equation 3.1 or 3.2:

Figure 3.36   Two-winding transformer schematic. (By permission of ABB Inc., Jefferson City, MO.)

Figure 3.37   Complete transformer equivalent circuit. (By permission of ABB Inc., Jefferson City, MO.)

3.1 $% R = load loss 10 kVA = Ω ( R ) kVA kV 2$
3.2 $% X = AW 10 kVA = Ω ( L ) kVA kV 2$

where AW is apparent watts, or the scalar product of applied voltage and exciting current in units of amperes. Once the resistances and inductances are translated to the same side of the transformer, the ideal transformer can be eliminated and the percent values of R and X combined. The result is the simple model shown in Figure 3.38. A load, having power factor cos θ, may be present at the secondary.

3.11.4  Impedance

The values of %R and %X form the legs of what is known as the “impedance triangle.” The hypotenuse of the triangle is called the transformer's impedance and can be calculated using Equation 3.3:

3.3 $% Z = % R 2 + % X 2$

A transformer's impedance is sometimes called “impedance volts” because it can be measured by shorting the secondary terminals and applying sufficient voltage to the primary so that rated current flows in each winding. The ratio of applied voltage to rated voltage, times 100, is equal to the percent impedance.

Figure 3.38   Simplified transformer model. (By permission of ABB Inc., Jefferson City, MO.)

3.11.5  Short-Circuit Current

If the load (right) side of the model of Figure 3.38 is shorted and rated voltage from an infinite source is applied to the left side, the current ISC will be limited only by the transformer impedance:

3.4 $I SC = 100 × I R % Z$

For example, if the rated current, IR, is 100 A and the impedance is 2.0%, the short-circuit current will be 100 × 100/2 = 5000 A.

3.11.6  Percent Regulation

When a transformer is energized with no load, the secondary voltage will be exactly the primary voltage divided by the turns ratio (Np/Ns). When the transformer is loaded, the secondary voltage will be diminished by an amount determined by the transformer impedance and the power factor of the load. This change in voltage is called regulation and is actually defined as the rise in voltage when the load is removed. One result of the definition of regulation is that it is always a positive number. The primary voltage is assumed to be held constant at the rated value during this process. The exact calculation of percent regulation is given in Equation 3.5:

3.5 $% r e g = ( L 2 ⋅ ( % R 2 + % X 2 ) + 200 ⋅ L ⋅ ( % X ⋅ sin ⁡ θ + % R ⋅ cos ⁡ θ ) + 10 , 000 ) 0.5 − 100$

where

• cos θ is the power factor of the load
• L is per unit load on the transformer

The most significant portion of this equation is the cross products, and since %X predominates over %R in the transformer impedance and cos θ predominates over sin θ for most loads, the percent regulation is usually less than the impedance (at L = 1). When the power factor of the load is unity, then sin θ is zero and regulation is much less than the transformer impedance. A much simpler form of the regulation calculation is given in Equation 3.6. For typical values, the result is the same as the exact calculation out to the fourth significant digit or so:

3.6 $% r e g ≅ L ⋅ ( % R * cos ⁡ θ + % X * sin ⁡ θ + ( % X * cos ⁡ θ − % R * sin ⁡ θ ) 2 200 )$

3.11.7  Percent Efficiency

As with any other energy conversion device, the efficiency of a transformer is the ratio of energy delivered to the load divided by the total energy drawn from the source. Percent efficiency is expressed as follows:

3.7 $%Efficiency = L ⋅ kVA ⋅ c o s θ ⋅ 10 5 L ⋅ kVA ⋅ c o s θ ⋅ 10 3 + NL + L 2 ⋅ LL$

3.12.1  Temperature Limits

According to IEEE standards, modern distribution transformers are to operate at a maximum 65°C average winding rise over a 30°C ambient air temperature at rated kVA. One exception to this is submersible or vault-type distribution transformers, where a 55°C rise over a 40°C ambient is specified. The bulk oil temperature near the top of the tank is called the “top oil temperature,” which cannot be more than 65°C over ambient and will typically be about 55°C over ambient, 10°C less than the average winding rise.

3.12.2  Hottest-Spot Rise

The location in the transformer windings that has the highest temperature is called the “hottest spot.” Standards require that the hottest-spot temperature not exceed 80°C rise over a 30°C ambient, or 110°C. These are steady-state temperatures at rated kVA. The hottest spot is of great interest because, presumably, this is where the greatest thermal degradation of the transformer's insulation system will take place. For calculation of thermal transients, the top-oil rise over ambient air and the hottest-spot rise over top oil are the parameters used.

If all distribution loads were constant, then determining the proper loading of transformers would be a simple task. Loads on transformers, however, vary through the hours of a day, the days of a week, and through the seasons of the year. Insulation aging is a highly nonlinear function of temperature that accumulates over time. The best use of a transformer, then, is to balance brief periods of hottest-spot temperatures slightly above 110°C with extended periods at hottest spots well below 110°C. Methods for calculating the transformer loss-of-life for a given daily cycle are found in the IEEE C57.91 Guide for Loading Mineral-Oil-Immersed Transformers. Parameters needed to make this calculation are the no-load and load losses, the top-oil rise, the hottest-spot rise, and the thermal time constant.

3.12.4  Thermal Time Constant

Liquid-filled distribution transformers can sustain substantial short-time overloads because the mass of oil, steel, and conductor takes time to come up to a steady-state operating temperature. Time constant values can vary from 2 to 6 h, mainly due to the differences in oil volume vs. tank surface for different products.

3.13.1  Design Tests

Tests that manufacturers perform on prototypes or production samples are referred to as “design tests.” These tests may include sound-level tests, temperature-rise tests, and short-circuit-current withstand tests. The purpose of a design test is to establish a design limit that can be applied by calculation to every transformer built. In particular, short-circuit tests are destructive and may result in some invisible damage to the sample, even if the test is passed successfully. The IEEE standard calls for a transformer to sustain six tests, four with symmetrical fault currents and two with asymmetrical currents. One of the symmetrical shots is to be of long duration, up to 2 s, depending on the impedance for lower ratings. The remaining five shots are to be 0.25 s in duration. The long-shot duration for distribution transformers 750 kVA and above is 1 s. The design passes the short-circuit test if the transformer sustains no internal or external damage (as determined by visual inspection) and minimal impedance changes. The tested transformer also has to pass production dielectric tests and experience no more than a 25% change in exciting current (Bean et al., 1959).

3.13.2  Production Tests

Production tests are given to and passed by each transformer made. Tests to determine ratio, polarity or phase displacement, iron loss, load loss, and impedance are done to verify that the nameplate information is correct. Dielectric tests specified by industry standards are intended to prove that the transformer is capable of sustaining unusual but anticipated electrical stresses that may be encountered in service. Production dielectric tests may include applied voltage, induced voltage, and impulse tests.

3.13.2.1  Applied-Voltage Test

Standards require application of a voltage of (very roughly) twice the normal line-to-line voltage to each entire winding for 1 min. This checks the ability of one phase to withstand voltage it may encounter when another phase is faulted to ground and transients are reflected and doubled.

3.13.2.2  Induced-Voltage Test

The original applied-voltage test is now supplemented with an induced-voltage test. Voltage at higher frequency (usually 400 Hz) is applied at twice the rated value of the winding. This induces the higher voltage in each winding simultaneously without saturating the core. If a winding is permanently grounded on one end, the applied-voltage test cannot be performed. In this case, many IEEE product standards specify that the induced primary test voltage be raised to 1000 plus 3.46 times the rated winding voltage (Bean et al., 1959).

3.13.2.3  Impulse Test

Distribution lines are routinely disturbed by voltage surges caused by lightning strokes and switching transients. A standard 1.2 × 50 μs impulse wave with a peak equal to the BIL (basic impulse insulation level) of the primary system (60–150 kV) is applied to verify that each transformer will withstand these surges when in service.

3.14  Transformer Protection

Distribution transformers require some fusing or other protective devices to prevent premature failure while in service. Circuit breakers at the substation or fusing at feeder taps or riser poles may afford some protection for individual transformers, but the most effective protection will be at, near, or within each transformer. Transformers that are supplied with their own protective device(s) are called “self-protected.” Transformers that do not come with any protective device are called “conventional.”

3.14.1  Goals of Protection

Transformer-protection devices that limit excessive currents or prevent excessive voltages are intended to achieve the following:

• Minimize damage to the transformer due to overloads
• Prevent transformer damage caused by secondary short circuits
• Prevent damage caused by faults within the transformer
• Minimize the possibility of damage to other property or injury to personnel
• Limit the extent or duration of service interruptions or disturbances on the remainder of the system

The selection of protection methods and equipment is an economic decision and may not always succeed in complete achievement of all of the goals listed. For example, the presence of a primary fuse may not prevent longtime overloads that could cause transformer burnout.

3.14.2  Conventional Transformers

Overhead conventional transformers usually are installed with fused cutouts in the primary leads supplying the transformer. Pad-mount or submersible transformers may have fuses installed on a nearby pole or in a separate pad-mounted cabinet or submersible enclosure.

3.14.3  Internal Protection

When protection means are located within the transformer, the device can react to oil temperature as well as primary current. The most common internal protective devices are described in the following.

Distribution transformers that have no other protection are often supplied with a small high-voltage-expulsion fuse. The protective link is sized to melt at from 6 to 10 times the rated current of the transformer. Thus it will not protect against longtime overloads but will permit short-time overloads that may occur during inrush or cold-load-pickup phenomena. For this reason, they are often referred to as fault-sensing links. Depending on the system voltage, protective links can safely interrupt faults of 1000–3000 A.

High-voltage fuses made from a low-melting-point tin alloy melt at 145°C and thus protect a transformer by detecting the combination of overload current and high oil temperature. A eutectic link, therefore, prevents longtime overloads but allows high inrush and cold-load-pickup currents. A similar device called a “dual element” fuse uses two sections of conductor that respond separately to current and oil temperature with slightly better coordination characteristics.

3.14.3.3  Current-Limiting Fuses

Current-limiting fuses can be used if the fault current available on the primary system exceeds the interrupting ratings of protective links. Current-limiting fuses can typically interrupt 40,000–50,000 A faults and do so in less than one-half of a cycle. The interruption of a high-current internal fault in such a short time will prevent severe damage to the transformer and avoid damage to surrounding property or hazard to personnel that might otherwise occur. Full-range current-limiting fuses can be installed in small air switches or in dry-well canisters that extend within a transformer tank. Current-limiting fuses cannot prevent longtime overloads, but they can open on a secondary short circuit, so the fuse must be easily replaceable. Current-limiting fuses are considerably larger than expulsion fuses.

3.14.3.4  Bayonets

Pad mounts and submersibles may use a primary link (expulsion fuse) that is mounted internally in the transformer oil but that can be withdrawn for inspection of the fuse element or to interrupt the primary feed. This device is called a bayonet and consists of a probe with a cartridge on the end that contains the replaceable fuse element. Fuses for bayonets may be either fault sensing or dual sensing.

3.14.3.5  Combination of Bayonet and Partial-Range Current-Limiting Fuses

The most common method of protection for pad-mounted distribution transformers is the coordinated combination of a bayonet fuse (usually dual sensing) and a PRCL fuse. The PRCL only responds to a high fault current, while the bayonet fuse is only capable of interrupting low fault currents. These fuses must be coordinated in such a way that any secondary fault will melt the bayonet fuse. Fault currents above the bolted secondary fault level are assumed to be due to internal faults. Thus the PRCL, which is mounted inside the tank, will operate only when the transformer has failed and must be removed from service.

3.14.4  Coordination of Protection

As applied to overcurrent protection for distribution transformers, the term coordination means two things:

1. A fuse must be appropriately sized for the transformer. A fuse that is too large will not prevent short-circuit currents that can damage the transformer coils. A fuse that is too small may open due to normal inrush currents when the transformer is energized or may open due to short-time overload currents that the transformer is capable of handling.
2. Transformer protection must fit appropriately with other protection means located upstream, downstream, or within the transformer. For example, a secondary oil circuit breaker should be coordinated with a primary fuse so that any short circuit on the transformer secondary will open the breaker before the primary fuse melts.

Where two fuses are used to protect a transformer, there are two methods of achieving coordination of the pair: “matched melt” and “time–current-curve crossover coordination” (TCCCC).

3.14.4.1  Matched Melt

An example of matched-melt coordination is where a cutout with an expulsion fuse and a backup current-limiting fuse are used to protect an overhead transformer. The two fuses are sized so that the expulsion fuse always melts before or at the same time as the current-limiting fuse. This permits the current-limiting fuse to help clear the fault if necessary, and the cutout provides a visible indication that the fault has occurred.

3.14.4.2  TCCCC Coordination of Bayonet and Partial-Range Current-Limiting Fuses

TCCCC is much more common for pad-mounted and self-protected transformers, where the fuses are not visible. The TCCCC method is described as follows.

3.14.4.2.1  Fuse Curves

The main tool used for coordination is a graph of time vs. current for each fuse or breaker, as seen in Figure 3.39. The graph is displayed as a log–log plot and has two curves for any particular fuse. The first curve is called the minimum-melt curve, and this represents time–current points where the fuse element just starts to melt. The other curve is a plot of points at longer times (to the right of the minimum-melt curve). The latter curve is called the maximum-clear or sometimes the average-clear curve. The maximum-clear curve is where the fuse can be considered open and capable of sustaining full operating voltage across the fuse without danger of restrike. Even if a fuse has melted due to a fault, the fault current continues to flow until the maximum-clear time has passed. For expulsion fuses, there is a maximum interrupting rating that must not be exceeded unless a current-limiting or other backup fuse is present. For PRCL fuses, there is a minimum interrupting current. Above that minimum current, clearing occurs in about 0.25 cycles, so the maximum-clear curve is not actually needed for most cases.

Figure 3.39   TCCCC. (By permission of ABB Inc., Jefferson City, MO.)

3.14.4.2.2  Transformer Characteristics

Each transformer has characteristics that are represented on the time–current curve to aid in the coordination process:

1. Rated current = primary current at rated kVA.
2. Bolted fault current (ISC) = short-circuit current in the primary with secondary shorted.
• Inrush values are taken as 25 times rated current at 0.01 s and 12 times rated current at 0.1 s.
• Cold-load-pickup values are presumed to be six times rated current at 1 s and three times rated current at 10 s.
4. Through-fault duration or short-circuit withstand established by IEEE C57.109. For most transformers, the curve is the plot of values for I2t = 1250 or 50 times rated current at 0.5 s, 25 times rated current at 2 s, and 11.2 times rated current at 10 s. Values longer than 10 s are usually ignored.

3.14.4.2.3  Fuse Coordination Steps

Select an expulsion fuse such that

• The minimum-melt curve falls entirely to the right of the inrush–cold-load-pickup curve; for most fuses, the minimum-melt curve will always be to the right of 300% of rated load, even for very long times
• The maximum-clear curve will fall entirely to the left of the through-fault-duration curve at 10 s and below

Select a PRCL fuse such that its minimum-melt curve

• Crosses the expulsion-fuse maximum-clear curve to the right of the bolted fault line, preferably with a minimum 25% safety margin
• Crosses the expulsion-fuse maximum-clear curve at a current higher than the PRCL minimum interrupting rating
• Crosses the expulsion-fuse maximum-clear curve at a current below the maximum interrupting rating of the expulsion fuse; it is not a critical issue if this criterion is not met, since the PRCL will quickly clear the fault anyway

There are additional considerations, such as checking for a longtime recross of the two fuse characteristics or checking for a recross at a “knee” in the curves, as might occur with a dual-sensing fuse or a low-voltage circuit breaker with a high-current magnetic trip.

3.14.4.3  Low-Voltage Oil-Breaker Coordination

The coordination of an oil breaker with an expulsion fuse is slightly different than the previous example. The oil-breaker current duty is translated to the high-voltage side and is sized in a manner similar to the expulsion fuse in the previous example. The expulsion fuse is then selected to coordinate with the breaker so that the minimum melt falls entirely to the right of the breaker's maximum clear for all currents less than the bolted fault current. This ensures that the breaker will protect against all secondary faults and that the internal expulsion fuse will only open on an internal fault, where current is not limited by the transformer impedance.

3.14.5  Internal Secondary Circuit Breakers

Secondary breakers that are installed in the oil of a transformer can protect against overloads that might otherwise cause thermal damage to the conductor-insulation system. Some breakers also have magnetically actuated trip mechanisms that rapidly interrupt the secondary load in case of a secondary fault. When properly applied, secondary breakers should limit the top-oil temperature of a transformer to about 110°C during a typical residential load cycle. Breakers can have an emergency position, which allows the transformer to temporarily supply a higher load, allowing time to replace the unit with one having a higher kVA capacity. The secondary oil breaker is also handy to disconnect load from a transformer without touching the primary connections.

3.14.6  CSP®**CSP is a registered trademark of ABB Inc., Raleigh, NC. Transformers

Overhead transformers that are built with the combination of secondary breaker, primary protective link, and external lightning arrester are referred to generically as CSPs (completely self-protected transformers). This protection package is expected to prevent failures caused by excessive loads and external voltage surges, and to protect the system from internal faults. The protective link is often mounted inside the high-voltage bushing insulator, as seen in Figure 3.40.

Figure 3.40   Cutaway showing CSP components. (By permission of ABB Inc., Jefferson City, MO.)

3.14.7  Protection Philosophy

CSP transformers are still in use, especially in rural areas, but the trend is away from secondary breakers to prevent transformer burnouts. Continued growth of residential load is no longer a foregone conclusion. Furthermore, utilities are becoming more sophisticated in their initial transformer sizing and are using computerized billing data to detect a transformer that is being overloaded. Experience shows that modern distribution transformers can sustain more temporary overload than a breaker would allow. Most utilities would rather have service to their customers maintained than to trip a breaker unnecessarily.

3.14.8  Lightning Arresters

Overhead transformers can be supplied with primary lightning arresters mounted nearby on the pole structure, on the transformer itself, directly adjacent to the primary bushing, or within the tank. Pad-mounted transformers can have arresters too, especially those at the end of a radial line, and they can be inside the tank, plugged into dead-front bushings, or at a nearby riser pole, where primary lines transition from overhead to underground.

3.15.1  Historical Perspective

Serious consideration of the economics of transformer ownership did not begin until the oil embargo of the early 1970s. With large increases in the cost of all fuels, utilities could no longer just pass along these increases to their customers without demonstrating fiscal responsibility by controlling losses on their distribution systems.

3.15.2  Evaluation Methodology

An understanding soon developed that the total cost of owning a transformer consisted of two major parts, the purchase price and the cost of supplying thermal losses of the transformer over an assumed life, which might be 20–30 years. To be consistent, the future costs of losses have to be brought back to the present so that the two costs are both on a present-worth basis. The calculation methodologies were published first by Edison Electric Institute and then in IEEE C57.120, Loss Evaluation Guide for Power Transformers and Reactors. The essential part of the evaluation method is the derivation of A and B factors, which are the utility's present-worth costs for supplying no-load and load losses, respectively, in the transformer as measured in dollars per watt.

3.15.3  Evaluation Formula

In its simplest form, the IEEE loss evaluation guide expresses the present value of the total owning cost of purchasing and operating a transformer as follows:

3.8 $TOC = Transformer cost + A × no load loss + B × load loss$

where

• A is the loss-evaluation factor for no-load loss (dollars per watt)
• B is the loss-evaluation factor for load loss (dollars per watt)

The guide develops in detail the calculation of A and B factors from utility operating parameters as shown in Equations 3.9 and 3.10, respectively:

3.9 $A = SC + EC × HPY FCR × 1000$
3.10 $B = [ ( SC × RF ) + ( EC × LSF × HPY ) ] × ( PL ) 2 FCR × 1000$

where

• SC = GC + TD
• SC is the avoided cost of system capacity
• GC is the avoided cost of generation capacity
• TD is the avoided cost of transmission and distribution capacity
• EC is the avoided cost of energy
• HPY is the hours per year
• FCR is the levelized fixed-charge rate
• RF is the peak responsibility factor
• LSF is the transformer loss factor
• PL is the equivalent annual peak load

With the implementation of the U.S. Department of Energy (DOE) efficiency requirements (see Section 3.15.4) and deregulation, many electric utilities in the United States have now chosen to neglect elements of system cost that may no longer apply or to abandon entirely the consideration of the effects of transformer losses on the efficiency of their distribution system.

3.15.4  U.S. Department of Energy Efficiency Regulations

The DOE determined that energy efficiency conservation standards were necessary for distribution transformers, both liquid filled and dry type. According to DOE, this will result in significant conservation of energy. The details of the standard is found in 10 CFR Part 431, Paragraph 431.196 (Federal Register 72FR58190, dated October 12, 2007) with the Test Procedures defined in 10 CFR Part 431, Subpart K, Appendix A (Federal Register 71FR24972, dated April 27, 2006).

The regulations require all distribution transformers manufactured for use in the United States on or after January 1, 2010, must meet the minimum efficiency standards outlined in Tables 3.1 and 3.2. This also applies to all transformers imported into the United States on or after January 1, 2010. Although there are some exclusions, it basically encompasses most distribution transformers, single- and three-phase.

Table 3.1   Minimum Efficiency for Liquid-Immersed Distribution Transformers

Single-Phase (kVA)

Three-Phase (kVA)

Efficiency (%)

15

98.36

10

30

98.62

15

45

98.76

25

75

98.91

37.5

112.5

99.01

50

150

99.08

75

225

99.17

100

300

99.23

167

500

99.25

250

750

99.32

333

1000

99.36

500

1500

99.42

667

2000

99.46

833

2500

99.49

Table 3.2   Minimum Efficiency for Medium-Voltage Dry-Type Distribution Transformers

BIL

20–45 kV

46–95 kV

≥96 kV

Single-Phase (kVA)

Three-Phase (kVA)

Efficiency (%)

Efficiency (%)

Efficiency (%)

15

97.50

97.18

30

97.90

97.63

15

45

98.10

97.86

25

75

98.33

98.12

37.5

112.5

98.49

98.30

50

150

98.60

98.42

75

225

98.73

98.57

98.53

100

300

98.82

98.67

98.63

167

500

98.96

98.83

98.80

250

750

99.07

98.95

98.91

333

1000

99.14

99.03

98.99

500

1500

99.22

99.12

99.09

667

2000

99.27

99.18

99.15

833

2500

99.31

99.23

99.20

The DOE efficiency is calculated by the methods shown in the earlier Section 3.11.7, using a 50% load.

The DOE will be reviewing the existing efficiency levels on a periodic basis, which may result in some changes. All documents and updates may be found at the following website: http://www1.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html

References

ABB, Distribution Transformer Guide, Distribution Transformer Division, ABB Power T&D Co., Raleigh, NC, 1995, pp. 40–70.
Bean, R.L., Chackan, N.Jr., Moore, H.R., and Wentz, E.C., Transformers for the Electric Power Industry, Westinghouse Electric Corp. Power Transformer Division, McGraw-Hill, New York, 1959, pp. 338–340.
Claiborne, C.C., ABB Electric Systems Technology Institute, Raleigh, NC, personal communication, 1999.
Galloway, D.L., Harmonic and DC currents in distribution transformers, presented at 46th Annual Power Distribution Conference, Austin, TX, 1993.
Hayman, J.L., E.I. du Pont de Nemours & Co., Letter to Betty Jane Palmer, Westinghouse Electric Corp., Jefferson City, MO, October 11, 1973.
IEEE C57.12.00-2010, Standard General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2010.
IEEE C57.12.20-2005, IEEE Standard for Overhead Type Distribution Transformers, 500 kVA and Smaller: High Voltage, 34500 volts and below; Low Voltage, 7970/13800Y volts and below, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2005.
IEEE C57.12.23-2009, Standard for Underground-Type, Self-Cooled, Single-Phase Distribution Transformers with Separable, Insulated High-Voltage Connectors; High Voltage 25 kV and below and Low Voltage 600 V and below, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2009.
IEEE C57.12.24-2000, Underground-Type Three-Phase Distribution Transformers: 2500 KVA and Smaller; High-Voltage, 34,500 GrdY/19,920 volts and below; Low Voltage, 480 volts and below—Requirements, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2000.
IEEE C57.12.28-2005, Standard for Pad-Mounted Equipment—Enclosure Integrity, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2005.
IEEE C57.12.29-2005, Standard for Pad-Mounted Equipment—Enclosure Integrity for Coastal Environments, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2005.
IEEE C57.12.30-2010, Standard for Pole-Mounted Equipment—Enclosure Integrity for Coastal Environments, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2010.
IEEE C57.12.31-2010, Standard for Pole-Mounted Equipment—Enclosure Integrity, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2010.
IEEE C57.12.32-2002, Standard for Submersible Equipment—Enclosure Integrity, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2002.
IEEE C57.12.34-2010, Standard Requirements for Pad-Mounted, Compartmental-Type, Self-Cooled, Three-Phase Distribution Transformers, 2500 KVA and Smaller–High-Voltage: 34,500 GrdY/19,920 volts and below; Low Voltage: 480 volts and below.
IEEE C57.12.38-2009, Standard for Pad-Mounted-Type, Self-Cooled, Single-Phase Distribution Transformers; High Voltage 34,500 GrdY/19,920 V and below; Low Voltage, 240/120 V; 167 KVA and Smaller, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2009.
IEEE C57.12.40-2006, Standard for Requirements for Secondary Network Transformers, Subway and Vault Types (Liquid Immersed), Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2006.
IEEE C57.12.44-2005, Standard Requirements for Secondary Network Protectors, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2005.
IEEE C57.12.80-2010, Standard Terminology for Power and Distribution Transformers, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 2010.
IEEE C57.91-1995, Guide for Loading Mineral-Oil-Immersed Transformers, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 1995, p. iii.
IEEE C57.105-1978, Guide for Application of Transformer Connections in Three-Phase Distribution System, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 1978.
IEEE C57.109-1993, IEEE Guide for Liquid-Immersed Transformers Through-Fault-Current Duration.
IEEE C57.110-1998, Recommended Practice for Establishing Transformer Capability when Supplying Nonsinusoidal Load Currents, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 1998.
IEEE C57.120-1991, Loss Evaluation Guide for Power Transformers and Reactors, Institute of Electrical and Electronics Engineers, Piscataway, NJ, 1991.
IEEE 386-2006, Standard for Separable Insulated Connector Systems for Power Distribution Systems above 600 V.
Myers, S.D., Kelly, J.J., and Parrish, R.H., A Guide to Transformer Maintenance, footnote 12, Transformer Maintenance Division, S.D. Myers, Akron, OH, 1981.
Palmer, B.J., History of distribution transformer core/coil design, Distribution Transformer Engineering Report No. 83-17, Westinghouse Electric, Jefferson City, MO, 1983.
Powel, C.A., General considerations of transmission, in Electrical Transmission and Distribution Reference Book, ABB Power T&D Co., Raleigh, NC, 1997, p. 1.
U.S. Department of Energy, 10 CFR Part 431, Paragraph 431.196. Federal Register 72FR58190, dated October 12, 2007.

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