Electrical and Energy

The time you spend in selecting a transformer seems to be in direct proportion to the size of the unit. All too often, small transformers are selected with just a cursory look at the connected loads, and frequently a decision is made to choose one with the next larger kVA rating than the anticipated load. Conversely, large transformers, such as those used in electric utility applications, are closely evaluated because they represent large investments.

Most transformers used in commercial and industrial facilities fall in the middle ground, and they usually have ratings between 250kVA and 1000kVA. On larger projects, they can go up to 10MVA. Because these transformers represent the majority, you should evaluate them carefully before choosing a unit for a specific project and/or application.

There are three main parameters in choosing a transformer:

* That it has enough capacity to handle the expected loads (as well as a certain amount of overload);

* That consideration be given to possibly increasing the capacity to handle potential load growth; and

* That the funds allocated for its purchase be based on a certain life expectancy (with consideration to an optimal decision on initial, operational, and installation costs.)

Both capacity and cost relate to a number of factors that you should evaluate. These include:

* Application of the unit;

* Choice of insulation type (liquid-filled or dry type);

* Choice of winding material (copper or aluminum);

* Possible use of low-loss core material;

* Regulation (voltage stability);

* Life expectancy;

* Any overloading requirements;

* Basic insulation level (BIL);

* Temperature considerations;

* Losses (both no-load and operating losses);

* Any non-linear load demand;

* Shielding; and

* Accessories.

The type of load and the transformer's placement are two key considerations that must be understood. For example, if the unit will be used for heavy welding service, such as in an automotive plant, very rigid construction will be called for because the coils will experience very frequent short-circuit-type loads; thus, good short-term overload capability may be required.

You'll find that sizing a transformer for a particular application with regard to the unit's life expectancy requires a good understanding of its insulation characteristics and the winding temperature due to loading. This, in turn, requires a careful analysis of the load profile (covering amplitude, duration, and the extent of linear and non-linear loads).

The standard parameters for transformers operating under normal conditions include:

* Nominal values of input voltage and frequency;

* Approximately sinusoidal input voltage;

* Load current with a harmonic factor not exceeding 0.05 p.u.;

* Installation at an altitude of less than 1000 m (3300 ft);

* No damaging fumes, dust, vapors, etc. in installed environment;

* An ambient temperature that does not exceed 30 [degrees] C as a daily average or 40 [degrees] C at any time, and which does not fall below - 20 [degrees] C; and

* Overloads within acceptable levels of ANSI/IEEE loading guidelines (dry or liquid).

If some of the above conditions can't be met in a particular application, then you should work closely with the manufacturer so that the selected transformer's operating characteristics and/or size will compensate for the particular situation. For example, if the ambient temperature will exceed standard conditions or if the unit will be installed at a high elevation, then an appropriate solution might be to specify a transformer that's rated higher than what the load requires, in effect under utilizing the unit to compensate for the local conditions.

Information on the pros and cons of the available types of transformers frequently varies depending upon which manufacturer you're talking to and what literature you're reading. Nevertheless, there are certain performance and application characteristics that are almost universally accepted.

Basically, there are two distinct types of transformers: Liquid insulated and cooled (liquid-filled type) and nonliquid insulated, air or air/gas cooled (dry type). Also, there are subcategories of each main type.

Liquid-filled. For liquid-filled transformers, the cooling medium can be conventional mineral oil. There are also wet-type transformers using less flammable liquids, such as high fire point hydrocarbons and silicones.

Liquid-filled transformers are normally more efficient than dry-types, and they usually have a longer life expectancy. Also, liquid is a more efficient cooling medium in reducing hot spot temperatures in the coils. In addition, liquid-filled units have a better overload capability.

There are some drawbacks, however. For example, fire prevention is more important with liquid-type units because of the use of a liquid cooling medium that may catch fire. (Dry-type transformers can catch fire, too.) It's even possible for an improperly protected wet-type transformer to explode. And, depending on the application, liquid-filled transformers may require a containment trough for protection against possible leaks of the fluid.

Because of the above reasons, and because of the ratings, indoor-installed distribution transformers of 600V and below usually are dry-types.

Arguably, when choosing transformers, the changeover point between dry-types and wet-types is between 500kVA to about 2.5MVA, with dry-types used for the lower ratings and wet-types for the higher ratings. Important factors when choosing what type to use include where the transformer will be installed, such as inside an office building or outside, servicing an industrial load. Dry-type transformers with ratings exceeding 5MVA are available, but the vast majority of the higher-capacity transformers are liquid-filled. For outdoor applications, wet-type transformers are the predominate choice.

Dry-type. Dry-type transformers come in enclosures that have louvers or are sealed. Here, subcategories include different methods of insulation such as conventional varnish, vacuum pressure impregnated (VPI) varnish, epoxy resin, or cast resin insulation systems.

The insulation system for liquid-filled distribution transformers is typically composed of enameled wire, cellulose paper impregnated with a dielectric liquid, and the liquid itself. The dielectric grade paper most often used is derived from sulfate (kraft) wood pulp from softwoods. With the introduction of dicydianamid to the paper making process, the standard temperature winding rise is now 65 [degrees] C.

The ambient temperature base in the United States is a 30 [degrees] C average over a 24-hr period with a 40 [degrees] C maximum. The present allowable hot spot temperature (the difference between the average winding temperature rise and the hottest spot in the windings) is 15 [degrees] C. Thus, the permitted operating hot spot temperature, based on an average ambient temperature of 30 [degrees] C, is 110 [degrees] C.

New synthetic insulating materials are leading to even higher permitted hot spots. These materials include polyester, fiber glass, and more commonly, aramid paper. "Aramid paper" is a term applied generically for wholly aromatic polymide paper. To keep costs reasonable while still achieving gains in acceptable hot spot temperature limits, both aramid and thermally upgraded kraft paper are used together in a hybrid insulation system. As of this writing, new type liquid-filled transformers, called High Temperature Transformers (HTTs) are being built using this technology. The temperature rise of HTTs is an average winding rise of 115 [degrees] C over a 30 [degrees] C average ambient. Factoring in the temperature difference (20 [degrees] C) between the average winding temperature (145 [degrees] C) and the hot spot temperature, the maximum temperature (165 [degrees] C) will be at a level that is higher than the fire point of conventional transformer oil (mineral oil). For this reason, it's recommended that fire-resistant fluids be used for HTTs.

The process of proper impregnation of the paper with a liquid is a standard manufacturing operation. The core/coil assembly is mounted in the tank, lead assemblies attached, and the filling process begins. A partial vacuum is produced while the secondary leads circulate current to heat the coils and drive out any excess moisture. Later, while still under vacuum, heated degassified and filtered dielectric liquid is introduced. After filling and additional vacuum time, the tank cover is sealed in place. The head space between the liquid surface and the tank cover, which allows for the expansion and contraction due to thermal cycling, can be specified to be dry nitrogen gas in larger units.

For liquid-filled transformers containing more than 660 gal, the Environmental Protection Agency (EPA) requires some type of containment be used to control possible leaks of the liquid. Environmentally unfriendly fluids, such as polychlorinated biphenyls (PCBs) and chlorofluorocarbons (CFCs), have been banned or are severely restricted, replaced for the most part by nontoxic, nonbioaccumulating, and nonozone depleting fluids, such as fire-resistant silicones and fire-resistant hydrocarbons. These fluids are not covered by the Resource Conservation and Recovery Act (RCRA); however, they are covered by the Clean Water Act (CWA).

Some transformer liquids (known as nonflammable-type fluids) are covered under both the RCRA and the CWA, and certain requirements may be called for regarding special handling, spill reporting, disposal procedures, and record keeping. These fluids also require provisions for special transformer venting. As such, the above factors can have an effect on installation costs, long-term operating costs, and maintenance procedures.

The selection of which liquid dielectric coolant to use is driven primarily by economics and codes. Conventional mineral oil is most often specified as it is very economical and, unless it's subject to unusual service, maintains acceptable performance for decades.

As it's possible that a high-energy arc can occur in a transformer, fire safety becomes an important issue. When conventional mineral oil is restricted (usually due to fire code requirements), less-flammable fluids often are used. The most popular are fire-resistant hydrocarbons (also known as high-molecular weight hydrocarbons) and 50 cSt (a viscosity measurement unit) silicone fluids. Other fluids include high fire point polyol esters and polyalpha olefins. In addition to safety considerations, you should also evaluate performance factors for liquid-filled transformers in regard to dielectric strength and heat transfer capabilities of the fluid. The fire resistant hydrocarbon fluids have been widely used in power-class transformations though 60MVA and have over a 500kV BIL.

At one time, askarel fluid, a generic term for a group of certain fire-resistant electrical insulating liquids, including often used PCBs, represented the standard for fire safety in liquid dielectrics. But, PCBs were banned because of toxicity and environmental concerns.

Dry-type transformers can have their windings insulated various ways. A basic method is to preheat the conductor coils and then, when heated, dip them in varnish at an elevated temperature. The coils are then baked to cure the varnish. This process is an open-wound method and helps ensure penetration of the varnish. Cooling ducts in the windings provide an efficient and economical way to remove the heat produced by the electrical losses of the transformer by allowing air to flow through the duct openings. This dry-type insulation system operates satisfactorily in most ambient conditions found in commercial buildings and many industrial facilities.

When greater mechanical strength of the windings and increased resistance to corona (electrical discharges caused by the field intensity exceeding the dielectric strength of the insulation) is called for, VPI of the varnish forces the insulation (varnish) into the coils by using both vacuum and pressure. Sometimes, for additional protection against the environment (when the ambient air can be somewhat harmful), the end coils are also sealed with an epoxy resin mixture.

A cast coil insulation system, another version of the dry-type transformer, is used when additional coil strength and protection are advisable. This type of insulation is used for transformers located in harsh environments such as cement and chemical plants and outdoor installations where moisture, salt spray, corrosive fumes, dust, and metal particles can destroy other types of dry-type transformers. These cast coil units are better able to withstand heavy power surges, such as frequent but brief overloads experienced by transformers serving transit systems and various industrial machinery. Cast coil units also are being used where previously only liquid-filled units were available for harsh environments: They can have the same high levels of BIL while still providing ample protection of the coils and the leads going to the terminals.

Unlike open-wound or VPI transformers, cast coil units have their windings completely cast in solid epoxy. The coils are placed into molds and cast, usually under vacuum. The epoxy is a special type that keeps the coils protected from corrosive atmospheres and moisture as well as keeping the coils secure from the high mechanical forces associated with power surges and short circuits. Mineral fillers and glass fibers are added to the pure epoxy to give it greater strength. Flexibilizers are also added to improve its ability to expand and contract with the coil conductors for proper operation of the transformer under various load conditions.

Different manufacturers use different epoxy filling material and in different amounts. Important factors that manufacturers must consider when choosing filler material and the proportion to use include:

* Temperature rating of the transformer;

* Mechanical strength of the coils;

* Dielectric strength of the insulation;

* Expansion rate of the conductors under various loadings; and

* Resistance to thermal shock of the insulation system.

Cast coil transformers consist of separately wound and cast high- and low-voltage coils. During manufacture, the high voltage coil winding wires are placed in a certain pattern using preinsulated wire. The completely wound coil is then placed in a mold designed to form a heavy coating of epoxy around the coil. After vacuum filling of the epoxy, the mold is placed in an oven for a number of hours to allow the epoxy to cure and achieve full hardness and strength.

There are two types of low-voltage windings available, both of which provide protection from hostile environments. One type is vacuum cast like the high-voltage winding. The other type uses a "nonvacuum" technique of epoxy application to achieve strength. Sheet insulation, such as Nomex or fiberglass, is impregnated with uncured epoxy, then interleaved on the heavy low-voltage conductors to literally "wind-in" the epoxy. During oven curing of the low-voltage coil, the epoxy flows onto the conductor and cures into a solid cylinder of great strength. These "non-vacuum" coils are then fully sealed by pouring epoxy into the "margins" or ends of the windings. Both procedures provide good protection from hostile environments.

Because of the additional materials and procedures associated with manufacturing cast coil transformers, they cost more. However, cast coil transformers are designed to operate with lower losses, require less maintenance than regular types, and effectively operate in environments that may cause early failure with conventional dry-types. Also, cast coil transformers, if operated properly, will normally have a longer life expectancy than other dry-type transformers.

A transformer's coils can be wound with either copper or aluminum conductors. For equivalent electrical and mechanical performance, aluminum-wound transformers usually cost less than copper-wound units. Because copper is a better conductor, a copper-wound transformer can be at times slightly smaller than its aluminum counterpart, for transformers with equivalent electrical ratings, because the copper conductor windings will be smaller. However, most manufacturers supply aluminum and copper transformers in the same enclosure size.

Aluminum-wound transformers are by far the majority choice in the United States. With both materials, the winding process and the application of insulation are the same. Connections to the terminals are welded or brazed. Coils made of copper wires have slightly higher mechanical strength.

You should determine the transformer manufacturer's experience in building its products and that the firm has a proven record in using both types of conductors. This is especially true of manufacturers of dry-type units.

Choice of metal is critical for transformer cores, and it's important that good quality magnetic steel be used. There are many grades of steel that can be used for a transformer core. Each grade has an effect on efficiency on a per-pound basis. The choice depends on how you evaluate nonload losses and total owning costs.

Almost all transformer manufacturers today use steel in their cores that provides low losses due to the effects of magnetic hysteresis and eddy currents. To achieve these objectives, high permeability, cold-rolled, grain-oriented, silicon steel is almost always used. Construction of the core utilizes step lap mitered joints and the laminations are carefully stacked.

A new type of liquid-filled transformer introduced commercially in 1986 uses ultra low-loss cores made from amorphous metal; the core losses are between 60% to 70% lower than those for transformers using silicon steel. To date, these transformers have been designed for distribution operation primarily by electric utilities and use wound-cut cores of amorphous metal. Their ratings range from 10kVA through 2500kVA. The reason utilities purchase them, even though they are more expensive than silicon steel core transformers, is because of their high efficiency. U.S. utilities placed more than 400,000 amorphous steel core transformers in operation through 1995. The use of amorphous core liquid-filled transformers is now being expanded for use in power applications for industrial and commercial installations. This is especially true in other countries such as Japan.

Amorphous metal is a new class of material having no crystalline formation. Conventional metals possess crystalline structures in which the atoms form an orderly, repeated, three-dimensional array. Amorphous metals are characterized by a random arrangement of their atoms (because the atomic structure resembles that of glass, the material is sometimes referred to as glassy metal). This atomic structure, along with the difference in the composition and thickness of the metal, accounts for the very low hysteresis and eddy current losses in the new material.

Cost and manufacturing technique are the major obstacles for bringing to the market a broad assortment of amorphous core transformers. The price of these units typically ranges from 15% to 40% higher than that of silicon steel core transformers. To a degree, the price differential is dependent upon which grade of silicon steel the comparison is being made. (The more energy efficient the grade of steel used in the transformer core, the higher the price of the steel.)

At present, amorphous cores are not being applied in dry-type transformers. However, there is continuous developmental work being done on amorphous core transformers, and the use of this special metal in dry-type transformers may become a practical reality sometime in the future.

If you're considering the use of an amorphous core transformer, you should determine the economic tradeoff; in other words, the price of the unit versus the cost of losses. Losses are especially important when transformers are lightly loaded, such as during the hours from about 9 p.m. to 6 a.m. When lightly loaded, the core loss becomes the largest component of a transformer's total losses. Thus, the cost of electric power at the location where such a transformer is contemplated is a very important factor in carrying out the economic analyses.

Different manufacturers have different capabilities for producing amorphous cores, and recently, some have made substantial advances in making these cores for transformers. The technical difficulties of constructing a core using amorphous steel have restricted the size of transformers using this material. The metal is not easily workable, being very hard and difficult to cut, thin and flimsy, and difficult to obtain in large sheets. However, development of these types of transformers continues; you can expect units larger than 2500kVA being made in the future.

For harsh environments, whether indoor or outdoor, it's critical that a transformer's core/coil, leads, and accessories be adequately protected.

In the United States, almost all liquid-filled transformers are of sealed-type construction, automatically providing protection for the internal components. External connections can be made with "dead front" connectors that shield the leads. For high corrosive conditions, stainless steel tanks can be employed.

Dry-type transformers are available for either indoor or outdoor installation. Cooling ducts in the windings allow heat to be dissipated into the air. Dry-types can operate indoors under almost all ambient conditions found in commercial buildings and light manufacturing facilities.

For outdoor operations, a dry-type transformer's enclosure will usually have louvers for ventilation. But, these transformers can be affected by hostile environments (dirt, moisture, corrosive fumes, conductive dust, etc.) because the windings are exposed to the air. However, a dry-type can be built using a sealed tank to provide protection from harmful environments. These units operate in their own atmosphere of nonflammable dielectric gas.

Other approaches to building dry-type transformers for harsh environments include cast coil units, cast resin units, and vacuum pressure encapsulated (VPE) units, sometimes using a silicone varnish. Unless the dry-type units are completely sealed, the core/coil and lead assemblies should be periodically cleaned, even in nonharsh environments, to prevent dust and other contaminant buildup over time.

Dry-type transformers normally use insulators made from fiber glass reinforced polyester molding compounds. These insulators are available up to a rating of 15kV and are intended to be used indoors or within a moisture-proof enclosure. Liquid-filled transformers employ insulators made of porcelain. These are available in voltage ratings exceeding 500kV. Porcelain insulators are track resistant, suitable for outdoor use, and are easy to clean.

High-voltage porcelain insulators contain oil impregnated paper insulation, which acts as capacitive voltage dividers to provide uniform voltage gradients. Power factor tests must be performed at specific intervals to verify the condition of these insulators.

The difference between the secondary's no-load voltage and full-load voltage is a measure of the transformer's regulation. This can be determined by using the following equation:

Regulation (%) = (100)([V.sub.nl] - [V.sub.fl]) / ([V.sub.fl]),

where [V.sub.nl] is the no-load voltage and [V.sub.fl] is the full-load voltage. Poor regulation means that as the load increases, the voltage at the secondary terminals drops substantially. This voltage drop is due to resistance in the windings and leakage reactance between the windings. However, good regulation may offer some other problems.

Voltage regulation and efficiency are improved with low impedance but the potential for serious damage also goes up. Sometimes manufacturers, in order to meet demands for good regulation, design transformers with leakage reactance as low as 2%. A transformer so designed is liable to be severely damaged if a short circuit occurs on the transformer's secondary, especially if the total power on the system is large (a stiff source with low impedance).

The mechanical stresses in a transformer vary approximately as the square of the current. Stresses in a transformer resulting from a short circuit could be approximately six times as great in a transformer having 2% impedance as they would be in one having 5% impedance (where reactance is the major component of the impedance voltage drop).

Of course, a good circuit protection scheme can address this problem. Short circuit integrity is readily available if you wish to include in your transformer specifications that it follow the ANSI/IEEE Guide for Short Circuit Testing; C57.12.90-1993 for wet units and C57.12.91-1995 for dry units.

Even with good regulation, the secondary voltage of a transformer can change if the incoming voltage changes. Transformers, when connected to a utility system, are dependent upon utility voltage; when utility operations change or new loads are connected to their lines, the incoming voltage to your facility may decrease, or even perhaps increase.

To compensate for such voltage changes, transformers are often built with load tap changers (LTCs), or sometimes, no-load tap changers (NLTCs). (LTCs operate with the load connected, whereas NLTCs must have the load disconnected.) These devices consist of taps or leads connected to either the primary or secondary coils at different locations to supply a constant voltage from the secondary coils to the load under varying conditions.

Tap changers connected to the primary coils change the connections from the incoming line to various leads going to the coils. When tap changers are connected to the secondary coils, the changing of connections is made from the coils to the output conductors.

Tap changers can be operated by either manual switching or by automatic means. Transformers with tap changers usually have a tap position indicator to allow you to know what taps are being used.

There's a common presumption that the useful life of a transformer is the useful life of the insulating system, and that the life of the insulation is related to the temperature being experienced. You should recognize that the temperature of the windings vary; there are so-called hot-spots usually at an accepted maximum 30 [degrees] C above average coil winding temperature for dry-type transformers. The hot-spot temperature is the sum of the maximum ambient temperature, the average winding temperature rise (where the winding refers to the conductor), and the winding gradient temperature (the gradient being the differential between the average winding temperature rise and the highest temperature of the winding).

The nameplate kVA rating of a transformer represents the amount of kVA loading that will result in the rated temperature rise when the unit is operated under normal service conditions. When operating under these conditions (including the accepted hot-spot temperature with the correct class of insulation materials), you should achieve a "normal" life expectancy for the transformer.

Information on dry-type transformer loading from ANSI/IEEE C57.96-1989 indicates that you can have a 20-yr life expectancy for the insulation system in a transformer. However, due to degradation of the insulation, a transformer might fail before an elapse of 20 yrs. For dry-type transformers having a 220 [degrees] C insulating system and a winding hot-spot temperature of 220 [degrees] C, and with no unusual operating conditions present, the 20-yr life expectancy is a reasonable time frame. (The 220 [degrees] C represents a transformer used in a location with a 40 [degrees] C [104 [degrees] F] maximum ambient temperature, an average 150 [degrees] C rise in the conductor windings, and a 30 [degrees] C gradient temperature.)

Most 150 [degrees] C rise dry-type transformers are built with 220 [degrees] C insulation systems. Operating such a transformer at rated kVA on a continuous basis with a 30 [degrees] C average ambient should equate to a "normal" useful life. (Note: 40 [degrees] C maximum ambient in any 24-hr period with 30 [degrees] C as the 24-hr average is considered a standard ambient.)

When based solely on thermal factors, the life of a transformer increases appreciably if the operating temperature is lower than the maximum temperature rating of the insulation. However, you should recognize that the life expectancy of transformers operating at varying temperatures is not accurately known. Fluctuating load conditions and changes in ambient temperature make it difficult, if not impossible, to arrive at such definitive information.

For effective operation of an electrical system, transformers are sometimes overloaded to meet operating conditions. As such, it's important that you have an understanding with the transformer manufacturer as to what overloading the unit can withstand without causing problems.

The main problem is heat dissipation. If a transformer is overloaded by a certain factor, say 20% beyond kVA rating for a certain period of time, depending upon that period of time, it's probable that any heat developed in the coils will be transferred easily to the outside of the transformer tank. Therefore, there's a reasonable chance that the overloading will not cause a problem. However, when longer time periods are involved, heat will start to build up internally within the transformer, possibly causing serious problems.

An effective way of removing this heat is to use built-in fans; this way, the load capability can be increased without increasing the kVA rating of the transformer.

Dry-type transformers typically have a fan-cooled rating that is 1.33 times the self-cooled rating. Some transformer designs can provide ratings of 1.4 to 1.5 times self-cooled units. If you have such requirements, you should prepare a carefully written specification.

Liquid-filled transformers, because of their double heat-transfer requirement (core/coil-to-liquid and liquid-to-air), have a lower forced air rating. Usually, the increased rating is 1.15 times the self-cooled rating for small units and 1.25 times self-cooled rating for larger "small power transformers." When above 10MVA, the ratio may be as high as 1.67 to 1.

You should recognize two distinct factors when forced cooling is used. First, the concept is used to obtain a higher transformer capacity; but when doing so, losses are increased substantially. A dry-type transformer operating at 133% of its self-cooled rating will have conductor losses of nearly 1.8 times the losses at the self-cooled rating. And, there will be some losses in the form of power to operate the fan motors. The normal no-load losses remain constant regardless of the load. The other liability is that when additional equipment is used, such as fans, the chance of something malfunctioning increases.

The insulation level of a transformer is based on its basic impulse level (BIL). The BIL can vary for a given system voltage, depending upon the amount of exposure to system overvoltages a transformer might be expected to encounter over its life cycle. ANSI/IEEE Standards C57.12.00-1993 and C57.12.01-1989 indicate the BILs that may be specified for a given system voltage. You should base your selection on prior knowledge with similar systems, or on a system study such as performed by a qualified engineering firms or by selecting the highest BIL available for the system's voltage.

If the electrical system in question includes solid-state controls, you should approach the selection of BIL very carefully. These controls, which when operating chop the current, may cause voltage transients.

Liquid-type transformers use insulation based on a cellulose/fluid system. The fluid serves as both an insulating and cooling medium. Forms are used (which are rectangular or cylindrical shaped) when constructing the windings and spacers are used between layers of the windings. The spacing is necessary to allow the fluid to flow and cool the windings and the core.

For cooling, fluid flows in the transformer through ducts and around the coil ends within a sealed tank that encompasses the core and coils. Removal of the heat in the fluid takes place in external tubes, usually elliptical in design, welded to the outside tank walls.

When transformer ratings begin to exceed 5MVA, additional heat-transfer is required. Here, radiators are used; they consist of headers extending from the transformer tank on the bottom and top, with rows of tubes connected between the two headers. The transformer fluid, acting as a cooling medium, transfers the heat picked up from the core and coils and dissipates it to the air via the tubes.

The paper insulation used today in liquid-filled transformers is thermally upgraded, allowing a 65 [degrees] C average winding temperature rise as standard. Until the '60s, 55 [degrees] C rise was the standard.

Sometimes, transformer specifications are written for a 55 [degrees]/65 [degrees] C rise. This provides an increase in the operating capacity by 12% since the kVA specified is based on the old 55 [degrees] C rise basis but the paper supplied is thermally upgraded kraft type.

For both wet- and dry-type units, a key factor in transformer design is the amount of temperature rise that the insulation can withstand. Lower temperature rise ratings of transformers can be achieved in two ways: By increasing the conductor size of the winding (which reduces the resistance and therefore the heating) or by derating a larger, higher temperature rise transformer. Be careful when using the latter method; since the percent impedance of a transformer is based on the higher rating, the let-through fault current and startup inrush current will be proportionately higher than the rating at which it is being applied. Consequently, downstream equipment may need to have a higher withstand and interrupting rating, and the primary breaker may need to have a higher trip setting in order to hold in on startup.

The lower temperature rise transformers are physically larger and, therefore, will require more floor space. On the plus side, a lower temperature rise transformer will have a longer life expectancy. The latest energy codes recommend selecting transformers to optimize the combination of no-load, part-load, and full-load losses without compromising the operational and reliability requirements of the electrical system.

Dry-type transformers are available in three general classes of insulation. The main features of insulation are to provide dielectric strength and to be able to withstand certain thermal limits. Insulation classes are 220 [degrees] C (Class H), 185 [degrees] C (Class F), and 150 [degrees] C (Class B). Temperature rise ratings are based on full-load rise over ambient (usually 40 [degrees] C above ambient) and are 150 [degrees] C (available only with Class H insulation), 115 [degrees] C (available with Class H and Class F insulation) and 80 [degrees] C (available with Class H, F, and B insulation). A 30 [degrees] C winding hot spot allowance is provided for each class.

The lower temperature rise transformers are more efficient, particularly at loadings of 50% and higher. Full load losses for 115 [degrees] C transformers are about 30% less than those of 150 [degrees] C transformers. And 80 [degrees] C transformers have losses that are about 15% less than 115 [degrees] C transformers and 40% less than 150 [degrees] C transformers. Full load losses for 150 [degrees] C transformers range from about 4% to 5% for 30 kVA and smaller to 2% for 500 kVA and larger.

When operated continuously at 65% or more of full load, the 115 [degrees] C transformer will pay for itself over the 150 [degrees] C transformer in 2 yrs or less (1 year if operated at 90% of full load). The 80 [degrees] C transformer requires operation at 75% or more of full load for a 2-yr payback, and at 100% load to payback in 1 yr over the 150 [degrees] C transformer. If operated continuously at 80% or more of full load, the 80 [degrees] C transformer will have a payback over the 115 [degrees] C transformer in 2 yrs or less (1.25 years at 100% loading).

You should note that at loadings below 50% of full load, there is essentially no payback for either the 115 [degrees] C or the 80 [degrees] C transformer over the 150 [degrees] C transformer. Also, at loadings below 40%, the lower temperature rise transformers become less efficient than the 150 [degrees] C transformers. Thus, not only is there no payback, but also the annual operating cost is higher.

Because the cost of owning a transformer involves both fixed and operating costs, and because the cost of electric power is constantly on the rise, the cost of energy lost over a period of time due to a transformer's losses can substantially exceed the purchase price of a unit. As such, it's important that you evaluate transformer no-load and load losses carefully.

No-load losses consist of hysteresis and eddy currents in the core, copper loss due to no-load current in the primary winding, and dielectric loss. The core losses are the most important.

Load losses include FR loss in the windings, FR losses due to current supplying the losses, eddy current loss in the conductors due to leakage in the field, and stray losses in the transformer's structural steel. Specifying higher efficiency requires larger conductors for the coils to reduce FR losses. This means added cost, but the payback may be significant.

Some transformers (liquid- and dry-type) are now being offered with what is called a k-factor rating. This is a measure of the transformer's ability to withstand the heating effects of nonsinusoidal harmonic currents produced by much of today's electronic equipment and certain electrical equipment. Because of the problems created by harmonics, ANSI/IEEE, in the late 1980s, formulated the C57.110-1986 standard, Recommended Practice for Establishing Transformer Capability When Supplying Nonsinusoidal Load Currents. It applies to transformers up to 50MVA maximum nameplate rating when these units are subject to nonsinusoidal load currents having a harmonic factor exceeding 0.05 per-unit (pu), the percent value of the base unit. (Harmonic factor is defined as the ratio of the effective value of all the harmonics to the effective value of the fundamental 60-Hz frequency.)

In December, 1990, UL announced listings for dry-type general purpose and power transformers affected by nonsinusoidal currents in accordance to the above ANSI/IEEE C57.110-1986. The "listing investigation" is directed to submitting transformers for testing to certain factors relating to rms current at certain harmonic orders in a specified way that correlates with heating losses. The factors involved in the tests are collectively called the k-factor.

Transformers meeting k-factor requirements also address the need for providing for high neutral currents. Because the neutral current may be considerably greater than the phase current, the neutral terminal of the transformer is sometimes doubled in size for additional customer neutral cables. It's important that you recognize the impact caused by harmonic currents.

Oversized primary conductors are used to compensate for circulating harmonic currents. The secondary is also given special consideration. As the frequency increases to 180 Hz (as in the case with the 3rd harmonic), and greater, the skin effect (where current begins to travel more on the circumference of the conductor) becomes more pronounced. To compensate for this, the windings are composed of several smaller sizes of conductor, with the circumference of the total conductors being greater. The transformer design also incorporates a reduction in core flux to compensate for harmonic voltage distortion.

For help in determining what k-factor to use when you specify a transformer while designing an electrical system for a facility, identify what harmonic producing equipment is going into the system. Then, obtain information on the harmonic spectrum and the associated amplitudes produce by the offending apparatus from the manufacturer of the equipment.

Cautionary note: Be careful when using k-rated transformers having abnormally low impedance, particularly those units with ratings of k-20 and higher. Such low impedance transformers can actually increase harmonics neutral current problems and even cause some loads to malfunction or cause damage to equipment! Use of abnormally low impedance transformers will act to significantly increase the neutral current and, therefore, negate some of the benefits of doubling the neutral conductors. It's important that isolation transformers be used for high harmonic loads having normal (3% to 6%) impedance. Some highly knowledgeably engineers believe that it's wrong to specify transformers with ratings k-20 and higher for commercial office loads. If the harmonics are of such high magnitude and it's believed a transformer with a rating of k-20 or higher should be used, then careful attention should be given to make sure that the impedance of the unit be at least 3%.

Depending upon the loads being served, the ability of a transformer to attenuate electrical noise and transients would be a helpful attribute. While what is commonly referred to as "dirty power" possibly can't be stopped at the source causing the noise, corrective measures can be taken, including the application of a shield between the primary and secondary of a transformer. This type of construction is usually considered when a distribution transformer is serving solid-state devices such as computers and peripheral equipment.

There are two types of noise and voltage transients: common mode noise and transients and normal or transverse mode noise and transients. Common mode power aberrations are disturbances between the primary lines and the ground (phase-to-ground); transverse mode power aberrations are line-to-line disturbances. It is important to recognize this difference because an electrostatic shield will not reduce transverse disturbances. However, transverse disturbances are slightly reduced by a transformer's impedance, and this is true whether or not a transformer has a shield.

To substantially reduce transverse mode power aberrations, surge suppressors are used to handle the transients, and filters are used to handle the noise. Some literature show voltage sine curves with disturbances imposed on the curve as well as clean voltage sine curves, and information is included to the effect that an electrostatic shield is responsible for reducing or eliminating the disturbances. This is incorrect because the voltage sine curve portrays line-to-line characteristics, and shielding has no effect upon such disturbances.

An electrostatic shield is a grounded metal barrier between the primary and secondary that filters common mode noise, thus delivering cleaner power and reducing the spikes caused by common mode voltage transients. The shield takes most of the energy from the voltage spike and delivers it to the ground. A number of authorities agree that transformers built to deliver a 60 decibel (dB) (a 1000-to-1 ratio) reduction in common mode disturbances (noise and voltage transients) will help solve or prevent such power aberrations from causing problems. Some transformers are built with the ability to provide a 100 dB (100,000-to-1 ratio) attenuation, and even larger ratios. If poor power quality may be a problem on a system where you plan to install a transformer, get information on the unit's attenuation ratio and verify that the power problem stems from common mode disturbances.

An example of the effect of attenuation would be a lightning strike that induces a 1000V spike on a power line connected to the primary of a transformer. A shield would take most of this energy to ground, and if the attenuation is 60 dB (1000-to-1 ratio), an approximate a IV "bump" will be passed to the secondary and onto the feeder or branch circuit. A number of loads can take a "bump" of this magnitude without damage. If there's a branch circuit and another shielded transformer ahead of a load, the "bump" will be further reduced by the second transformer. This type of reduction is caused by an effect called transformer cascading.

Locating a transformer indoors, on the rooftop, or adjacent to a building in order to minimize the distance between the unit and the principal load results in reducing energy loss and voltage reduction. It also reduces the cost of secondary cable.

On the other hand, such placements of high-voltage equipment require closer consideration of electrical and fire safety issues. These conflicting goals can be satisfied by using transformers permitted by Code and insurance companies.

When liquid-filled transformers are preferred, less-flammable liquids are widely recognized for indoor and close building proximity installations. Wet-type transformers using less-flammable, or high fire point liquids, have been recognized by the NEC since 1978 for indoor installation without the need for vault protection unless the voltage exceeds 35kV. Based on this type of transformer's excellent fire safety record, Code and insurance restrictions have become minimal. Conventional mineral oil units are allowed indoors, but only if they are installed in a special 3-hr-rated vault (with a few exceptions) per the construction requirements of NEC Article 450, Part C. There's a requirement for liquid containment when wet-type transformers are used, regardless of the type fluid employed.

When dry-type units are preferred, they have fewer code restrictions. Obviously, these types of transformers do not need liquid containment. Per the requirements listed in NEC Sec. 450-21, there are minimum clearances that you must observe, and units over 112.5kVA require installation in a transformer room of fire-resistant construction, unless they are covered by one of two listed exceptions. As with liquid units, dry transformers exceeding 35kV must also be located in a 3-hr-rated vault.

A liquid-filled transformer may experience leakage around gaskets and fittings; however, if the installation was carried out correctly, this should not be a problem. Major maintenance procedures may require inspection of internal components, meaning that the coolant will have to be drained. Coils in liquid-type units are much easier to repair than coils in dry-type transformers. Cast coils are not repairable; they must be replaced.

Accessories are usually an added cost, and sometimes they are installed while the transformer is being bulk. Therefore, you should have some knowledge of accessories and incorporate in the transformer specification those accessories that, when installed, would be beneficial to the transformer's performance. Some of the accessories available include the following:

* Stainless steel tank and cabinet for extra corrosion protection (liquid-filled only);

* Special paint/finishes for corrosive atmospheres and ultraviolet light (liquid-filled only);

* Weather shields for outdoor units, protective provisions for humid environments, and rodent guards (dry-type only);

* Temperature monitors. There are a number of options available from simple thermometers to more extensive single- or 3-phase temperature monitoring as well as options for contacts to initiate alarms and/or trip circuits as well as starting cooling fans;

* Space heaters to prevent condensation during prolonged shutdown (usually with thermostats);

* Optional location of openings for primary and secondary leads;

* Special bushings for connecting primary to right-angle feeders;

* Loadbreak switches installed in transformer cabinet or a closely coupled cabinet;

* Tap changing control apparatus (usually a nonload device that can change the output voltage by about 5%);

* Internal circuit protection devices to open primary line when there-are short circuits and severe overloads;

* Equipment such as liquid level gauges, drain valves, radiator guards, sampling devices, and pressure relief valves (for liquid-filled transformers only);

* Internal lightning arresters;

* Internal surge arresters for protection against line or switching surges;

* Provisions for current and potential transformers and metering;

* Future fan provision for such installation at a later date;

* Key interlocks or padlocks to coordinate opening of enclosure panels with operation of HV switch;

* Provisions for ground fault detection;

* Installation of small control power transformers in cabinet to operate various 120/240V accessories for medium-voltage transformers; and

* Seismic bracing for units installed at locations subject to earthquakes.

A recent project with one of the utility's major industrial customers is a prime example of how the use of select power quality indices in a predictive/preventive maintenance program (PPM), coupled with the use of digital metering with power quality recording capabilities, can help industrial facilities develop an effective power quality maintenance program. The intent of this particular program was to remotely retrieve and automatically compile indices to provide reporting based on threshold events and provide histogram trending to be used to determine operational limits.

The most difficult part of implementing this program was to establish limits for trended indices, because there is very little published information on acceptable power quality operating limits for equipment, making this task more of an art than a science. The equipment manufacturers' task of testing the effects of a boundless number of index variations on their equipment is understandably impractical.

The approach of this power quality maintenance program somewhat follows a typical yearly doctor's exam. In my case, the doctor checks my blood pressure against my historical trend data and tells me it's above average published levels. Because it's always been in this range, however, it's considered normal for me. So pending any apparent abnormalities, I'm basically good until next year.

With this type of thinking in mind, we established initial limits for this program based on a number of standards and guidelines, such as IEEE 1159, CSA CAN-3-C235, ANSI/NEMA MG1, ITIC curves, electric utility power quality limits, and the operating history of the monitored distribution equipment. After initially applying these limits — if no power quality abnormalities were apparent with the trended indices — the benchmarked limits were adjusted as required to minimize event reporting.

Differentiating between acceptable and abnormal power quality events did require a degree of experience for expedient analysis. However, as per typical troubleshooting approaches, the investigations were all based on event timing to narrow in on offending equipment or processes. The program used feeder and equipment recorders that had the functionality to trend maximum, minimum, and average power quality indices, such as harmonics, unbalance, sags, and surges. The recorders were networked together and downloaded remotely. A database program was developed that performed statistical calculations, graphing, and exception event reporting on the available data.

Having a full array of indices is beneficial; however, any number available will fit the trending requirement. In this case, our team was fortunate enough to have facilities that placed permanent recorders with power quality capability throughout the plant at all levels of distribution as well as at some critical pieces of equipment. We used the following indices as prime indicators of distribution performance:

Voltage variation (average, minimum, maximum) — This index (Figure-1) was trended, typical electric utility planning limits of ±5% were applied for voltages greater than 1,000V, and CSA CAN-3-C235 Preferred Voltage Levels for AC Systems, 0 to 50,000V, Electric Power Transmission and Distribution was applied for voltages less than 1,000V. These limits were never adjusted any tighter than the initial values.

Current (average, minimum, and maximum) — This index was not used for alarming but trended to support comparative analysis.

Sag (if available) — This index was extremely crucial to capture, as it is quite often the leading culprit of lost production. IEEE Standard 1159, “Recommended Practice for Monitoring Electric Power Quality,” was used to define the sag level, and these events were loosely compared with the ITIC curve. However, the facility's immunity threshold to sag events was the ultimate limit.

Voltage unbalance (average) — Average voltage variation was trended, and typical limits of between 1% to 2% were used while respecting ANSI/NEMA MG1 Motors and Generators standard. This limit was never adjusted any tighter than the initial values.

Current unbalance (average) — This index was not used for alarming, but trended to support comparative analysis.

Voltage total harmonic distortion (average) — This index (Figure-2) was trended, and a typical IEEE 519 planning limit of 5% of the average fundamental voltage was applied. This limit was lowered as we became more confident with the trended bandwidth variability, with the overall intent of minimizing event reporting.

Voltage individual harmonic distortion (average 2nd through 15th) — This index was trended, and typical IEEE 519 planning limits of 3% of the average fundamental voltage were applied. These limits were lowered as we became more confident with the trended bandwidth variability, with the overall intent of minimizing event reporting.

Current total demand distortion (average) — This index (Figure-3) was trended, and typical IEEE 519 planning limits were applied based on the short circuit over maximum demand loading ratio (Isc/Il). Within the facility, transformer nameplate kVA was used for both the maximum demand loading (Il) and for normalizing. This limit was lowered as we became more confident with the trended bandwidth, with the overall intent of minimizing event reporting.

Current individual demand distortion (average 2nd through 15th) — This index was trended, and typical IEEE 519 planning limits were applied based on the short circuit over maximum demand loading ratio (Isc/Il). Within the facility, transformer nameplate kVA was used for both the maximum demand loading (Il) and for normalizing. These limits were lowered as we became more confident with the trended bandwidth variability, with the overall intent of minimizing event reporting.

Power [average - energy (W), demand charge (VA) and reactive energy (var)] — These indices were not used for alarming but trended to support comparative analysis.

A customized, off-the-shelf database program was configured as a preliminary platform to perform three major routines: statistical calculations, exception event reporting, and graphing of the recorded indices. The statistical analysis toolbox simply used minimum, maximum, average, percentile, and standard deviation to help weight the selected limits — no statistical expertise was required. The statistical analysis toolbox was applied during the early stages of the program. Once a confident operating bandwidth was evident, the limits were adjusted on an as-needed basis to minimize reporting.

The exception event reporting toolbox identified indices outside of limits, logging events by magnitude and date of incident. The exception event reporting toolbox was continually used to report on out of limit events. Any automatic reporting period or report can be generated from printed report to e-mail notification. The graphing toolbox allowed the graphing of selected indices for comparative analysis.

Interestingly enough, the initial success of this program has been to immediately identify suspect equipment operation and improperly configured metering as opposed to the intent of trending and identifying progressive equipment failure. Typical power quality equipment issues ranged from high harmonic distortion due to capacitor resonance, voltage unbalance due to failed power factor correction stages, high even harmonic current due to faulty rectifier bridges, and multiple sags due to equipment starts. Typical metering configuration issues ranged from incorrect ratios, time stamps, inconsistent trigger settings, and mislabeled equipment. Longer term trending identified electric utility seasonal system feeder configuration changes that were otherwise thought to be constant. These different system feeder configurations changed the applied harmonic voltage spectrum and the facility resonance points.

This program successfully demonstrated a proactive approach to reduce facility downtime while effectively minimizing the resources required to assess the unrelenting amount of data produced by the recorders. Not only did the continuous monitoring strategy benchmark electrical feeder power quality characteristics and report only when limits were exceeded, but it also successfully demonstrated that a power quality maintenance program can be implemented without considerable power quality expertise.

Welcome to the first in a series of articles focusing on electrical calculation basics. This month, we'll discuss the most fundamental of calculations — those for current (I) and kilowatts (kW). We'll also show you how you can do these calculations “in your head,” with very reasonable accuracy, through the use of constants.

You may ask, “What exactly is a constant?” An example of a constant with which you're very much familiar is pi (π), which is derived by dividing a circle's circumference by its diameter. No matter what the circumference and diameter of the respective circle, their ratio is always pi. You can use constants that apply to specific single- and 3-phase voltages to calculate current (I) and kilowatts (kW). Let's see how to do this.

Basic electrical theory tells us that for a single-phase system,

kW = (V × I × PF) ÷ 1,000.

For the sake of simplicity, let's assume the power factor (PF) is unity. Therefore, the above equation becomes

kW = (V × I) ÷ 1,000.

Solving for I, the equation becomes

I = 1,000kW ÷ V (Equation 1)

Now, if we look at the “1,000 ÷ V” portion of this equation, you can see that by inserting the respective single-phase voltage for “V” and dividing it into the “1,000,” you get a specific number (or constant) you can use to multiply “kW” to get the current draw of that load at the respective voltage.

For example, the constant for the 120V calculation is 8.33 (1,000 ÷ 120). Using this constant, Equation 1 becomes

I = 8.33kW.

So, if you have a 10kW load, you can calculate the current draw to be 83.3A (10 × 8.33). If you have a piece of equipment that draws 80A, then you can calculate the relative size of the required power source, which is 10kW (80 ÷ 8.33).

By using this same procedure but inserting the respective single-phase voltage, you get the following single-phase constants, as shown in Table 1.

For 3-phase systems, we use the following equation:

kW = (V × I × PF × 1.732) ÷ 1,000.

Again, assuming unity PF and solving this equation for “I,” you get:

I = 1,000kW ÷ 1.732V.

Now, if you look at the “1,000 4 1.732V” portion of this equation, you can see that by inserting the respective 3-phase voltage for “V” and multiplying it by 1.732, you can then divide that quantity into the “1,000” to get a specific number (or constant) you can use to multiply “kW” to get the current draw of that 3-phase load at the respective 3-phase voltage. Table 2 lists each 3-phase constant for the respective 3-phase voltage obtained from the above calculation.

The quint essential protective device is the fuse. When the current through a fuse exceeds a certain threshold, the fuse element melts, producing an arc across the resulting gap that is then extinguished, interrupting the circuit. Given that fuses can be built as the weak point of a system, fuses are ideal for protecting circuitry from damage. Fuses however have two problems: First, after they have functioned, fuses must be replaced as they cannot be reset. This can prove inconvenient if the fuse is at a remote site or a spare fuse is not on hand. And second, fuses are typically inadequate as the sole safety device in most power systems as they allow current flows well in excess of that that would prove lethal to a human or animal.

The first problem is resolved by the use of circuit breakers - devices that can be reset after they have broken current flow. In modern systems that use less than about 10 kW, miniature circuit breakers are typically used. These devices combine the mechanism that initiates the trip (by sensing excess current) as well as the mechanism that breaks the current flow in a single unit. Some miniature circuit breakers operate solely on the basis of electromagnetism. In these miniature circuit breakers, the current is run through a solenoid, and, in the event of excess current flow, the magnetic pull of the solenoid is sufficient to force open the circuit breaker's contacts (often indirectly through a tripping mechanism). A better design however arises by inserting a bimetallic strip before the solenoid - this means that instead of always producing a magnetic force, the solenoid only produces a magnetic force when the current is strong enough to deform the bimetallic strip and complete the solenoid's circuit.

In higher powered applications, the protective relays that detect a fault and initiate a trip are separate from the circuit breaker. Early relays worked based upon electromagnetic principles similar to those mentioned in the previous paragraph, modern relays are application-specific computers that determine whether to trip based upon readings from the power system. Different relays will initiate trips depending upon different protection schemes. For example, an overcurrent relay might initiate a trip if the current on any phase exceeds a certain threshold where as a set of differential relays might initiate a trip if the sum of currents between them indicates there may be current leaking to earth. The circuit breakers in higher powered applications are different too. Air is typically no longer sufficient to quell the arc that forms when the contacts are forced open so a variety of techniques are used. The most popular technique at the moment is to keep the chamber enclosing the contacts flooded with sulfur hexafluoride (SF6) - a non-toxic gas that has superb arc-quelling properties.

The second problem, the inadequacy of fuses to act as the sole safety device in most power systems, is probably best resolved by the use of residual current devices (RCDs). In any properly functioning electrical appliance the current flowing into the appliance on the active line should equal the current flowing out of the appliance on the neutral line. A residual current device works by monitoring the active and neutral lines and tripping the active line if it notices a difference. Residual current devices require a separate neutral line for each phase and to be able to trip within a time frame before harm occurs. This is typically not a problem in most residential applications where standard wiring provides an active and neutral line for each appliance (that's why your power plugs always have at least two tongs) and the voltages are relatively low however these issues do limit the effectiveness of RCDs in other applications such as industry. Even with the installation of an RCD, exposure to electricity can still prove lethal.

In large electric power systems, Supervisory Control And Data Acquisition (SCADA) is used for tasks such as switching on generators, controlling generator output and switching in or out system elements for maintenance. The first supervisory control systems implemented consisted of a panel of lamps and switches at a central console near the controlled plant. The lamps provided feedback on the state of plant (the data acquisition function) and the switches allowed adjustments to the plant to be made (the supervisory control function). Today, SCADA systems are much more sophisticated and, due to advances in communication systems, the consoles controlling the plant no longer need to be near the plant itself. Instead in today's power systems, it is increasingly common for plant to be controlled from a central remote site with equipment similar to (if not identical to) a desktop computer. The ability to control such plant through computers has increased the need for security and already there have been reports of cyber-attacks on such systems causing significant disruptions to power systems.