Sizing and Selecting a Transformer

· Transformer size is determined by the kVA of the load.

· Load voltage, or secondary voltage, is the voltage needed to operate the load.

· Line voltage, or primary voltage, is the voltage from the source.

· Single-Phase has two lines of AC power.

· Three-Phase has three lines of AC power, with each line 120 degrees out of phase with the other two.

· KVA is kilovolt ampere or thousand volt ampere. This is how transformers are rated.

To determine the size of the transformer you need, determine the following requirements for your transformer:

1.     Load Voltage

2.     Load Current/Amps

3.     Line Voltage

Next, determine if your application is single-phase or three-phase, and use the corresponding formula at the right.

The KVA of the transformer should be equal to or greater than the KVA of the load to handle present requirements and to account for future expansion.

As a service to you, we offer a transformer specifier to help you find your transformers quickly and easily.

Installation

Carefully inspect the transformer before signing the delivery receipt. Any damage should be noted on the receipt and a claim placed against the transportation company. Protective greaseplaced on terminal connections should not be removed. The grease is a protective coating that prevents the oxidation of the conductor. Bolt the terminal connector firmly to the bus bar, allowing the protective film to be forced out.

Safety

Transformers are provided with access covers to facilitate installation and service. They must be kept securely in place at all times when the transformer is operating.

CAUTION: Normal operating voltages can be extremely hazardous. Only qualified personnel should install, inspect or service transformers. Disconnect the power before opening the cover or touching any internal parts.

Storage

Transformers should be stored in a warm, dry location of uniform temperature and in their original packing. If the transformer has been unpacked, all ventilating openings should be covered to keep out dust. Outdoor storage should be avoided, but if this is not possible, the transformer must be protected against moisture and contaminants.

Condensation and moisture can be reduced with heaters. If the transformer has been subjected to moisture, it should be baked out before energizing. This is especially important in transformers of 5 KV or higher.

Taps

If the transformer comes supplied with taps, they will generally have a full capacity rating. A common tap arrangement is two 2.5% taps above (FCAN) and four 2.5% taps below (FCBN) nominal voltage. Transformers are shipped with the taps connected for nominal voltage, that is, 480 volts for a 480 volt transformer. The installing electrician must change the taps if the supply voltage differs from the nominal voltage rating.

Connections and Circuits

The transformer should be connected only as described on the nameplate or the wiring diagram inside the wiring compartment cover, or as otherwise specifically authorized by Jefferson Electric. Transformers without terminal boards, usually the smaller size transformers, provide leads for connections.

IMPORTANT: Any unused taps or leads must be insulated from each other and taped encapsulated transformers, 2 KVA and smaller, have their turns ratio compensated for losses so that their open circuit voltage is somewhat higher than the load voltage. Machine tool transformers are compensated up to 5 KVA. Using transformers in the reverse direction from which it is designed would result in lower than expected output voltage.

Mounting and Spacing

Dry-type transformers depend on air for cooling, and must be placed so that room air can circulate freely around them. Cabinet style transformers must be mounted so that air can pass freely through the ventilation openings. The transformer space should be kept clear.

Transformers should be spaced at least six inches apart. Transformers rated 30 KVA and larger should be kept at least six inches from walls and ceilings.

Transformers should never be mounted near heat-generating equipment or near heat-sensitive equipment. Transformers should never be placed in a room with hazardous processes, or where flammable gasses or combustible materials are present. Particular care must be taken when mounting in unventilated plenums or in closets with no ventilation. In areas without free moving air, ambient temperatures can rise above acceptable limits, causing the transformer to overheat.

Maintenance

Periodic inspection of the transformer should be made, depending on conditions. In most clean, dry installations, once a year is usually sufficient. After disconnecting the transformer from the power, the cover should be removed and any dirt cleaned out. Screens covering the ventilating openings should be cleaned.

Inspect for loose connections, terminal and splice conditions and for signs of overheating, rust or deteriorating paint.

NEMA Transformer Enclosure Definitions
Type 1	General purpose - indoor.
Type 2	Drip-proof - indoor.
Type 3	Wind blown dust and water - indoor/outdoor.
Type 3R	Rainproof and sleet/ice resistant - outdoor. Meets above type requirements.
Type 3S	Dust-tight, rain-tight, and sleet/ice proof - outdoor.
Type 4	Water-tight and dust-tight - indoor/outdoor.
Type 4X	Water-tight, dust-tight and corrosion resistant - indoor.
Type 5	Dust-tight - indoor.
Type 6	Submersible, water-tight, dust-tight and sleet/ice resistant - indoor/outdoor.
Type 7	Class I, Group (S) A,B,C and/or D - indoor hazardous locations - air-break equipment.
Type 8	Class I, Group (S) A,B,C and/or D - indoor hazardous locations.
Type 9	Class II, Group (S) E,F and/or D - indoor hazardous locations - air-break equipment.
Type 10	Bureau of Mines.
Type 11	Drip-proof and corrosion resistant.
Type 12	Industrial use dust-tight and drip-tight - indoor.
Type 13	Oil-tight and dust-tight - indoor.
Source: NEMA Pub. No. ST20.

Recommended Copper Wire & Transformer Size
Single-Phase Motors - 230 Volts
HP	Transformer KVA	Distance - Motor to Transformer in Feet
		100	150	200	300	500
11/2	3	10	8	8	6	4
2	3	10	8	8	6	4
3	5	8	8	6	4	2
5	71/2	6	4	4	2	0
71/2	10	6	4	3	1	0
Source: EASA Handbook

Recommended Copper Wire & Transformer Size
Three-Phase Motors -230 & 460 Volts
HP	Volts	Transformer KVA	Distance - Motor to Transformer in Feet
			100	150	200	300	500
11/2	230	3	12	12	12	12	10
11/2	460	3	12	12	12	12	12
2	230	3	12	12	12	10	8
2	460	3	12	12	12	12	12
3	230	5	12	10	10	8	6
3	460	5	12	12	12	12	10
5	230	71/2	10	8	8	6	4
5	460	71/2	12	12	12	10	8
71/2	230	10	8	6	6	4	2
71/2	460	10	12	12	12	10	8
10	230	15	6	4	4	4	1
10	460	15	12	12	12	10	8
15	230	20	4	4	4	2	0
15	460	20	12	10	10	8	6
20	230	*	4	2	2	1	000
20	460	*	10	8	8	6	4
25	230	*	2	2	2	0	000
25	460	*	8	8	6	6	4
30	230	*	2	1	1	00	0000
30	460	*	8	6	6	4	2
40	230	*	1	0	00	0000	300
40	460	*	6	6	4	2	0
50	230	*	1	0	00	0000	300
50	460	*	4	4	2	2	0
60	230	*	1	00	000	250	500
60	460	*	4	2	2	0	00
75	230	*	0	000	0000	300	500
75	460	*	4	2	0	00	000
* Consult Local Power Company Source: EASA Handbook

Protective Equipment

The importance of protecting your power delivery system cannot be overstated. The system must be protected against short circuits, surges caused by lightning, switching and overheating. Equipment is available to provide this protection, but it must also be adequately sized and properly installed. Failure to do so could damage the transformer and invalidate its warranty.

Protective equipment includes circuit breakers and fuses.

The selection and placement of protective equipment within the system is the responsibility of the end user.

Circuit Breakers

When any component of a circuit fails, there is nothing to limit current flow except the resistance of the circuit conductors and the resistance of the fault itself. The currents in these situations can be extremely large and destructive, making it imperative to interrupt the circuit as quickly as possible.

Circuit breakers are designed to react to a fault by making a physical separation in the currentcarrying or conducting element by inserting an insulating medium. Breakers come in different types, depending on the insulating medium used. While the most common insulation is oil, air is used in some 600 Volt class circuits. For higher voltages and larger capacities, the insulating medium might be a vacuum or and inert gas such as sulphur hexafluoride.

Specifications for a circuit breaker will depend on the operating voltage of the circuit, the normal operating or maximum load current, and the maximum abnormal or fault current to be interrupted. Circuit breakers are rated in KVA or MVA and express the ability of the breaker to withstand short circuit forces.

Circuit breakers must withstand large inrush currents that result when voltage is initially switched on. These currents can be 20 to 30 times the rated transformer current even with no-load. Therefore, breakers must have built-in time delay for the first 5 to 10 cycles to avoid tripping under "turn-on" currents.

Fuses

The most common protective device in use, the fuse is basically a circuit breaker that works only once and then must be replaced. When current exceeds the predetermined current value, a fusible link melts, opening the circuit. When voltage is initially switched on, a large inrush current results, being greatest in the first half-cycle of operation, or approximately .01 second. This current becomes less severe over the next few cycles, or approximately .1 second until the transformer is operating normally. Because of inrush current, fuses are often selected to withstand as much as 25 times primary rated current for .01 second, and 12 times primary rated current for .1 second.

Fuse Selection

The tables provide guidance for selecting fuses when the maximum voltage in the circuit is 600 Volts or less. These tables are included in Article 450-3 of the National Electrical Code covering over-current protection of transformers. If primary protection only is required, use Table 1. If both primary and secondary protection are required, refer to Table 2.

IMPORTANT: These tables are to be used as a guide only. The final determination of application is the responsibility of the end user.

Table 1 - Primary Fuse Only
Transformer Primary Amperes	Maximum Primary Fuse % Rating
9 or More	125*
2 or 9	167
Less than 2	300
* If 125% does not correspond to a standard ampere rating, the next higher standard rating described in NEC Article 240-6 shall be permitted.

Table 2 - Primary and Secondary Fuses
Transformer Secondary Amperes	Maximum % Rating
	Primary Fuse	Secondary Fuse
9 or More	250	125*
Less than 9	250	167
* If 125% does not correspond to a standard ampere rating, the next higher standard rating described in NEC Article 240-6 shall be permitted.

Primary Fuse Selection

Primary fuse selection is made according to rated primary current (Ipri). To determine Ipri, the transformer rating (VA or KVA) and primary voltage (Vpri) must be known as well as whether the transformer is single- or three-phase. With this information, use the appropriate formula to determine Ipri.

Once Ipri is known, select fuses according to Table 1 or 2 above.

Secondary Fuse Selection

Secondary fuse selection is made according to rated secondary current (Isec). To determine Isec, the transformer rating (VA or KVA) and secondary voltage (Vsec) must be known as well as whether the transformer is single- or three-phase. With this information, use the appropriate formula to determine Isec.

Once Isec is known, select fuses according to Table 2 above.

Insulation & Temperature

All Jefferson Electric transformers are designed and manufactured with the best quality insulation available. There are classes of insulation systems for different temperatures as defined by NEMA and ANSI. Insulation classes are rated in °C rise above a specific ambient of 40°C maximum. A transformer having a specific class of insulation, for example Class 220, can have an average winding temperature rise of 150°C with a maximum hot spot temperature rise of 180°C. If the room ambient temperature is 40°C, then the total temperature of the hottest spot would be 220°C. Jefferson Electric transformers are designed to operate at rated load and voltage in maximum room ambient temperatures of 40°C, average room ambient temperature not to exceed 30°C, and at altitudes not to exceed 3300 feet in accordance with NEMA standards.

Insulating Classifications

The designations for insulation systems are numerical classifications based on temperature ratings. Transformer ratings are based on temperature rise. The accompanying table shows the designations.

Transformer and Insulation Systems Ratings
Insulation Rating	Transformer Rating	Max. Ambient Temperature	Hot Spot Allowance
Class 105	55°C Rise	40°C	10°C
Class 150	80°C Rise	40°C	30°C
Class 180	115°C Rise	40°C	30°C
Class 220	150°C Rise	40°C	30°C

Overloads

Overloads exceeding the maximum allowable insulation temperature can be tolerated, provided the overload is of short duration and is preceded and followed by a period of operation at less than rated KVA (refer to ANSI C57.96-1989, Tables 5,6,7). Overloading should be avoided unless approval is obtained from the Jefferson Electric engineering department.

High Ambient Temperatures

Ambient temperatures above 30°C average over a 24-hour period and 40°C maximum require either a larger KVA rating or a special low temperature rise transformer. A 150°C rise air cooled transformer can also be derated using the formula of .4% KVA reduction for each degree centigrade above 30°C ambient temperature.

Altitude Correction

For transformers above 3300 feet, reduce the KVA rating .3% for each 330 feet above 3300 feet.

Transformer Sound

Transformers, like other electromagnetic devices, produce a "hum" caused by the alternating flux in the transformer core. This "hum", known as magnetostriction, is primarily produced at a fundamental frequency of twice the applied frequency. The relative loudness depends on the construction of the transformer, the manner of installation and the ambient sound level at the site. The sound produced by a transformer has a fundamental frequency of 120 Hz, accompanied by harmonics of 240, 360, 480, 600, etc.

Controlling Transformer Sound

Sound control becomes more important as power demands increase and transformers are placed closer to their loads. Planning of transformer placement and specification is especially important in designing high rise apartments, hospitals and office buildings.

Proper installation can significantly reduce transformer noise. For a quiet installation:

·         Consult your architect about the location of the transformer while the building is being designed.

·         Install the transformer as far as possible from areas where the sound could be objectionable.

·         Avoid placing near multiple reflective surfaces such as in a corner, near a ceiling or floor, or in a hallway.

·         Place sound-dampening pads between the transformer and the mounting surface. (Pads may be neoprene with sandwiched cork material or spring loaded with a rubber base.)

·         Use flexible conduit couplings between the transformer and the wiring system. Mount the transformer on walls or structural members sufficient to support its weight.

·         To avoid amplifying the sound, mount the transformer on a surface with as large a mass as possible.

·         Judge transformer sound only when the building is finished, occupied and functioning.

Sound Testing Standards

NEMA ST 1-4 (ANSI-C89.1) section 2.7 covers "Audible Sound Level Test." For a thorough understanding of these tests it should be read in its entirety.

Briefly, the transformer is tested at its rated frequency and voltage under no-load conditions in a room which is 10 feet larger on all sides than the transformer. The ambient sound level of the room must be at least 5 db, and preferably 10 db, below the ambient level plus the transformer level. Five sound readings are taken with an approved sound meter one foot from each side of the transformer enclosure and one foot above the enclosure. The sound rating is the average of these five readings.

For three-phase transformers, the NEMA maximum allowable averages of the readings in decibels are shown in the chart below.

Transformer NEMA Maximum Three-Phase db Ratings
KVA Rating	600V Class	5KV Class
0 - 9	40	45
10 - 50	45	50
51 - 150	50	55
151 - 300	55	58
301 - 500	60	60
501 - 700	62	-
701 - 1000	64	-

Troubleshooting Guide

Hot transformer
Possible Cause	Suggested Remedy
High ambient temperature	Improve ventilation or relocate unit to cooler location.
Overload	Reduce load; reduce amperes by improving power factor with capacitors; check for circulating currents for paralleled transformers - different ratios or impedances; check for open phase in delta bank.
High voltage	Change circuit voltage, taps.
Insufficient cooling	If other than naturally cooled, check fans, pumps, valves and other units in cooling systems.
Winding failure - incipient fault	See "No voltage - unsteady voltage" below.
Short-circuited core	Test for exciting current and no-load loss; if high, inspect core, remove and repair; check core bolt, clamps and tighten; check insulation between laminations; if welded together, return to factory for repair or replacement.
High harmonic loads	Measure neutral current - replace with K-rated transformer

Noisy transformer
Possible Cause	Suggested Remedy
Overload	See "Hot transformer" above.
Metal part ungrounded, loose connection	Determine part and reason; check clamps, cores and parts normally grounded for loose or broken connections, missing bolts or nuts, etc.; tighten loose clamps, bolts, nuts; replace missing ones.
External parts and accessories in resonant vibration	Tighten items as above; in some cases, loosen to relieve pressure causing resonance and install shims.
Incipient fault - core or winding	See above under "Hot transformer."

No voltage - unsteady voltage
Possible Cause	Suggested Remedy
Winding failure - lightning; overload; short-circuit from foreign object or low strength dielectric	Check winding; remove foreign object or damaged material; repair or replace parts of insulation materials.

Rust and paint deterioration
Possible Cause	Suggested Remedy
Weather, pollution, corrosive or salt atmosphere; overloads	Remove rust and deteriorated paint; clean surfaces; repaint with proper paints and sufficient coatings.
Excessive heating discoloration	If excessive heating discoloration occurs, check sizing, input voltage, or loading amps.

Hot neutral line
Possible Cause	Suggested Remedy
Overload	Too small neutral conductor: replace. Severe unbalance between phase: rebalance and equalize loads.
One leg of wye bank open	Check associated fuse. If blown, remove cause and replace. Check for open circuit in winding of transformer in bank. Measure odd harmonic amps with RMS meter.

Voltage unbalanced
Possible Cause	Suggested Remedy
Open neutral unbalanced loads	Check neutral connections. See "Hot neutral line" above.

Voltages high and unbalanced
Possible Cause	Suggested Remedy
Open neutral on wye bank ground in winding of one transformer in wye	Check neutral connections and load balance. Check values of voltages between phases and phase-to-ground voltages. Vector should indicate source of trouble.

No voltage - one phase of delta connected bank
Possible Cause	Suggested Remedy
Grounds on two legs of delta (delta collapse - loads "single phasing")	Remove grounds from at least one leg of delta source.

Overloads on two delta bank
Possible Cause	Suggested Remedy
Open in third transformer of bank; operating in open delta	Check fuses on supply to their bank; check winding of transformers in third transformer for continuity.

Low voltage on two phases of delta
Possible Cause	Suggested Remedy
Open in one phase of delta supply; two transformers now connected across one same phase	Check fuse on supply; check supply circuit back to source for open circuit.

Frequently Asked Questions

Single and Three Phase Transformer Questions

Can I connect a single-phase transformer to a three-phase source?

Yes, and the transformer output will be single-phase. Simply connect any two wires from a 3- or 4-wire source to the transformer's two primary leads. Three single-phase transformers can be used for three-phase applications. They can be used in delta-connected primary and wye or delta-connected secondary. To avoid an unstable secondary voltage, NEVER connect wye primary to delta secondary.

Can I use a transformer to change three-phase to single-phase?

It is not possible for a transformer to present a balanced load to the supply and deliver a single-phase output. Changing three-phase to two-phase, and vice-versa, can be done using special circuitry with standard dual-wound transformers.

Temperature and Heat Related Transformer Questions

Can Transformers be used in parallel?

It is very common for transformers to be placed in parallel service. To provide maximum efficiency and voltage, impedance values must match closely for each transformer involved. A failure to match voltage and impedances will cause unbalanced loading for the transformers and may lead to "overheating" or premature failure.

What is meant by a transformer's temperature rise?

A transformer's rated tempature rise (degrees Celsius) is the avarage temperature of the transformer's windings over an ambient temperature of 40 °C.

Why is the transformer case hot?

Transformers are designed to operate at a specific load. As transformers are overloaded, losses generated increases which reults in a potential case for heating. If a transformer is properly sized for a specific application, no excessive heating should be present.

How do I know when the temperature rise is too high?

Touch is a poor indicator of proper transformer opertaing temperature. Properly designed transformers can reach 50 °C (112 °F) above ambient temperature. In an ambient temperature of 20 °(60 °F) the total temperature can reach 70 °C (190 °F), which is too hot to touch. Thermometers are the best way to determine the temperature.

Do I need special transformers for high ambient temeratures?

If you have an immediate need that cannot wait for a custom-built transformer, you can de-rate a standard transformer. For each 10 °C above 30°C, de-rate the maximum loading by 4% (30°C = 100% ; 40 °C = 96%; 50 °C = 92% ; 60 °C = 88% ).

Reverse Transformer Questions

What about transformers in reverse?

Transformers connected in reverse, to proper input voltages, will provide correct nameplate voltage output, albeit reversed. However, for transformers rated 2 KVA and below, the output voltage would be less than the nameplate rating, since smaller KVA transformers have a greater turns ratio compensation on their low voltage windings.

CAUTION: When reverse connecting a delta-wye transformer, a wye primary will be created. Wye primaries may cause problems and are not recommended. If a wye primary must be used, do not connect the neutral.

Why do you not recommend reverse connecting a delta-wye transformer?

You can reverse wire the delta-wye, the primary wye is connected without using the neutral (X0) and it turns into a delta-delta.

What would happen if you connected the neutral on the wye primaries if reverse connected? Would this short, overheat?

The problem is that you could get a fault current on the neutral which may not trip the breaker in case of a problem.

Type of Transformers Questions

What is an isolating transformer?

An isolating transformer has the primary and secondary windings connected magnetically, but not electrically. Also referred to as an "insulating" transformer.

What is a non-linear (K-factor) transformer?

A transformer that is designed to handle the odd harmonic current loads caused by much of today's modern office equipment. A non-linear transformer has a K-factor rating that is an index of its ability to supply harmonic content in its load current while remaining within its operating temperature limit.

What is a drive isolation transformer?

A drive isolation transformer is designed for use with motor drives. It must isolate the motor from the line and handle the overcurrent mode during motor startup. It is important to heed the drive manufacturer's recommendations for transformer KVA.

What is a buck boost transformer?

Buck-boost transformers are single-phase isolated distribution transformers having four windings instead of two. They can be connected as an autotransformer to buck (reduce) or boost (raise) the line voltage from 5 - 20%. Typical reduced secondary voltages are 12, 16, 24, 32, or 48 volts. Commonly found raised secondary voltages are 208 to 230 or 240 volts.

Copper and Aluminum Transformer Questions

What are the differences between copper and aluminum windings?

We design our copper and aluminum units to meet the same specifications. Aluminum coils need to use larger wires, but the user does not see any difference. The copper coils are physically smaller, but we put them in the same enclosure as the Aluminum, so the user will not see any difference. The terminals are the same, so the user will not see any difference. Most wiring lugs are tin-plated so there is no problem connecting the transformer to aluminum or copper wires.

Copper has better conductivity but less life expectancy, correct?

Conductivity is addressed in the design by using larger wire in aluminum units. There is no difference in life expectancy for copper.

Anything else?

The only real difference is that Copper costs more.

Voltage and Electrical Load Transformer Questions

How do I determine the electrical load?

Obtain the following standard nameplate or instruction manual data for the equipment (the load) to be powered: :

·         Voltage required by the equipment

·         Amperes or KVA capacity required by the equipment

·         Required frequency of source voltage in Hz (cycles per second)

·         Determine whether the load is designed to operate on a single- or three-phase supply (see Page 4 for additional information)

·         Others to order

What is the supply voltage?

The supply voltage may be higher or lower than the voltage required by the load. However, the frequency of the two may not differ.

If your load ratings are not expressed in KVA, use the load voltage and amperage to determine the KVA.

For single-phase: VA = volts x amperes KVA = VA/1000

For three-phase: VA = volts x amperes x 1.73 KVA = VA/1000

Once you have a KVA rating, then select a transformer from the charts in the appropriate section of this catalog by matching the primary and secondary voltages determined above.

What is voltage regulation in a transformer?

The voltage difference between loaded and unloaded output. To provide the proper secondary load voltage, extra primary windings cause the no-load secondary voltage to be 3-5% higher than the load voltage. Also known as "compensated windings."

What will happen if transformers are operated at non-nameplate voltages?

A transformer is designed using specific ratios that relate to the rated KVA, primary voltage and secondary voltage proportionally. Operating a transformer above or below the nominally designed primary voltage will reflect a proportional increase or decrease in secondary output levels. Extreme caution must be observed when overvoltage levels exist. Excessive input voltage will cause higher core losses, increased noise and elevated temperatures. Overvoltages for any extended period of time have a significant effect on insulation breakdown and transformer failures. Transformers can be specifically designed for extreme voltage conditions if initial specifications state those requirements.

Miscellaneous Transformer Questions

Are your transformers used in residential applications?

Yes

Are there additional standards required for residential applications (building codes, etc.)?

We meet the general NEC requirements as far as residential applications, but there could be specific local code requirements.

What is the general life expectancy of your transformers under normal use?

20-40 years for typical use.

What type of terminations are provided on Jefferson Electric transformers?

Jefferson Electric dry type transformers are provided with the following primary and secondary terminations:

·         Encapsulated wire leads

·         Ventilated terminals

·         Machine Tool Terminals

·         Control leads

·         Others to order

Can transformers be operated at different frequencies?

A 60 Hz design is physically smaller than a 50 Hz design. DO NOT use 60 Hz rated transformers on 50 Hz service. Without special designs, higher losses and greater heat rise will result. Operating 60 Hz transformers at higher frequencies may simply provide less voltage regulation.

What would be the result of overloading dry type transformers?

All Jefferson Electric transformers are designed to accommodate short periods of overloading. As the overload becomes excessive and the duration increases, the transformer will experience a percent loss of life. Prolonged overloading generates excessive heating which results in insulation deterioration and ultimately transformer failure. Contact your Jefferson Electric application engineer to determine loading for your unique application.

Can I achieve specific sound levels in a transformer?

Whenever noise is a concern, but before selecting a transformer, assure yourself that the sound levels represented have been measured in accordance with the NEMA standards. If your requirement is lower than that available from the manufacturer’s standard product, request a specific sound level on your RFQ or bid. (See Transformer Sound Page 99.)

Energy Efficiency Transformer Questions

Why do the energy efficiency ratings only apply to ventilated transformers?

This is what the government says. The law targets the "Distribution" transformers which are the most common and are typically oversized which results in the "wasted" electricity of powering a large unit 24/7.

Are the TP-1 Energy Efficiency ratings exceeded?

We need to meet the ratings, so some may be exceeded slightly. We see no reason to provide a higher level of efficiency since this adds to the cost of the units. It is very expensive to get the next 1% of efficiency and we are already over 97 to 98% depending on the size of the unit.

Are these transformers more efficient than any of our competitors?

Everyone needs to meet the same requirements.

Can you provide any efficiency information, now that you have obtained the Canadian High Efficiency Approval? For example, different loading conditions besides 35% load.

35% was chosen as the test requirements for the new law. There are calculators on the web to check the energy usage and cost savings for switching to a TP-1 transformer, but no one really cares anymore since you must choose the TP-1 units today. Also, to use the calculators, you need to know the specific core loss and coil loss for each model of transformer and this is not typically available.

Do you have any examples that may show cost savings of this transformer?

Our TP-1 whitepaper shows a typical ROI of 5 years to recover the cost on installing a new TP-1 transformer, but most users will not change a transformer.

 Reducing Distribution Losses Without Breaking the Bank

By Steve Eckles, El Paso Electric Co.

With increasing concerns about energy efficiency, distribution loss reduction is again assuming a role of prominence in the utility industry. For most North American utilities, the 1 percent or 2 percent of additional peak capacity that could be derived through loss reduction would provide significant savings.

Besides the financial implications, low-loss design also improves reliability, lessens power quality concerns, and better accommodates customer load growth. And, there’s an environmental twist to lowering distribution losses: Lowering distribution losses reduces the amount of pollutants and greenhouse gasses from hydro-carbon based power plants.

Utilities can reduce distribution losses by concentrating on the design and operation of the distribution system. However, some of these loss-reduction measures require financial commitment, forcing energy-conscious utilities to balance loss savings with capital investment.

Distribution Loss Modeling and Reduction Strategies

Distribution technical losses, i.e. losses resulting from operational inefficiencies, are generally divided into two types: load and no-load. For simplicity of modeling, both load and no-load real power losses in a distribution system can be modeled as resistors R_L and R_NL in a shunt circuit as shown in Figure 1.

Load losses represented by R_L vary quadratically with system load. They are also referred to as resistive, conductor, copper, or I²R losses. Constant no-load losses, represented by R_NL, are driven by the presence or application of AC voltage. The amount of load has no appreciable effect on no-load losses. The vast majority of these losses are from distribution transformer excitation. Underground cable dielectric losses are also a small component of no-load losses.

In a well-run, highly capitalized distribution system, losses are approximately 3 percent to 5 percent. In neglected systems with poor planning criteria and design standards, losses may increase to 5 percent to 7 percent or higher. Peak losses occur during peak load when generation pricing is at its highest and distribution equipment thermal capacity is often stressed.

Main Causes of Distribution Losses

Physicists may study phenomena such as dielectric and induction losses, but the most consequential distribution losses are due to resistive copper losses and transformer excitation.

Conductor power losses result from electron flow (current) through resistance in primary, secondary, and transformer conductors regardless of conductor material (e.g. copper, aluminum, aluminum-alloy, etc.). Feeder voltage, conductor length and size, power factor, load factor, loading, and phase current balance all determine copper losses.

The conductor current contribution to technical power losses is higher than that for conductor resistance as shown in the resistive power loss equation P_loss = I² x R, where: P_loss is power loss in watts; I is current measured in amperes, and R is resistance measured in ohms.

Conductor heating is proportional to the square of the current; therefore, conductor power losses will double if the current increases by only 41 percent as represented in Figure 2, next page.

Benefits of Higher Primary Operating Voltage

To minimize copper power loss is to minimize circuit resistance and current. As is evident by the current squared term in the resistive power loss equation (P_loss = I²R), reducing conductor current results in dramatic savings. This equation reveals that two half-loaded feeders each have one-fourth the copper losses of one fully loaded feeder, given all the feeders are the same length and use the same conductor size. This suggests that copper losses could be halved by building double-circuit distribution primary; however, capital costs would drastically increase.

Therefore, the recommended design practice to economically decrease conductor losses through current reduction is toincrease primary voltage. Apparent power (kVA) in a conductor is proportional to voltage and current (kVA = kV x I); doubling primary operating voltage will cut the conductor current in half for the same feeder power flow. Hence, by the resistive power loss equation, the resulting copper loss is 25 percent that of the original voltage using the same feeder conductor and length (see Figure 3). Increased costs for higher voltage class insulation are relatively small compared to total feeder costs. Additionally, the rated feeder power capacity also doubles when doubling the voltage. It is beyond the scope of this article to delve into voltage drop and power flow equations and calculations; however, simple power flow programs show that doubling operating voltage will not only reduce power loss but will also enable more customers to be served on longer feeders with less power loss and less percentage voltage drop. This results in lower overall capital and operating costs.

The second variable in the resistive power equation, conductor resistance, is inversely proportional to its cross-sectional area. Hence, larger diameter conductors produce less loss than smaller conductors of the same material for the same current. Voltage drop will also be less with larger diameter conductors; however, construction costs are higher. Larger overhead conductor often brings with it the added expense of stronger poles, cross-arms, or shorter span lengths (more poles per mile). The additional cost makes it hard to justify larger distribution conductor on the basis of lowering power losses. More capacity and less voltage drop are better drivers for larger conductor.

Legacy 4160-Volt Systems

Many utilities have pockets of 4160 voltage systems in older parts of town surrounded by higher voltage feeders. At this lower voltage, more conductor current flows for the same power delivered, resulting in higher I²R losses. Conversely, converting old 4160-volt feeders to higher voltage is capital-intensive and often not economically justifiable unless the line is already in poor condition and needs major improvements. If parts of the 4160-volt primary are in relatively good condition, installing multiple step-down power transformers at the periphery of the 4160-volt area will reduce copper losses by injecting load current at more points (i.e., reducing overall conductor current and the distance traveled by the current to serve the load).

Reactive Power Compensation

Both customer inductive loads and current through inductive utility conductors require that reactive power be supplied to the distribution system. This reactive power current lags the real power current by 90 degrees (4.2 ms in 60 Hz systems, 5 ms in 50 Hz systems). A feeder with 113 amps of current at a lagging power factor of 85 percent has 53 amps of inductive current added vectorally at 90 degrees to 100 amps of real power current. Both real power and inductive current are supplied from utility generation through transmission lines, substation transformers, and finally distribution feeders unless other sources of reactive power are added. Fortunately, shunt (phase-to-ground) distribution capacitors economically supply inductive current. Adding feeder capacitors to supply the 53 amps of inductive current reduces total feeder current to its real power component of 100 amps. The 13 percent feeder current reduction translates into approximately 28 percent lower I²R losses. Additionally, reducing total current frees up system capacity and reduces feeder voltage drop resulting in a “flatter” feeder voltage profile.

Installing multiple step-down power transformers at the periphery of the 4160-volt area will reduce copper losses by injecting load current at more points.

A number of utilities have adopted the “two-thirds rule,” or some variant, for distribution capacitor placement. It calls for installing a quantity of capacitive volt-amperes reactive (VARs) equal to two-thirds of the total feeder peak inductive VARs at a distance of two-thirds of the overall feeder length from the substation. The rule works best for a feeder of constant load that is uniformly distributed along the feeder’s length. These two conditions are more theoretical than realistic and are mostly found in textbooks and technical papers.

Feeder reactive power varies with load throughout the day and throughout the year. If reactive power compensation were only supplied with fixed capacitor banks, it would likely result in over-compensation (too much capacitive current) during light feeder loading and under-compensation (not enough capacitive current) during peak load. This increases total current-leading to increased I²R loss-and possible over-voltage (steady-state capacitive current raises voltage over conductor inductance) during light feeder loading.

By using a combination of fixed (left) and switched (right) capacitor banks, reactive power compensation will better track load and minimize losses.

Placing fixed capacitors according to the two-thirds rule (or a similar variation) can be performed relatively quickly with minimal engineering time and will likely produce immediate power and energy savings. However, it does not meet full reactive power compensation (i.e. unity power factor where real power current equals total current) to produce the least feeder I²R losses at peak. By using a combination of fixed and switched capacitor banks, reactive power compensation will better track the load and minimize losses. This has proven to be economical and well worth the extra effort.

To save the most energy annually through capacitive reactive power compensation, the amount of fixed capacitance (VARs) should approximately equal the feeder’s reactive power requirements at minimum annual load. Switched capacitor banks should then be added to the fixed capacitor banks on the feeder until the total peak feeder reactive power requirements are met. Modeling distribution feeders in a power flow computer program will yield the most economical fixed and switched capacitor placement. Without the luxury of power flow modeling, capacitor bank placement can be determined by placing capacitors near concentrated or lumped feeder loads using an 85 percent load power factor approximation. It is worth noting that capacitor bank current can flow both downstream and upstream of the bank itself-ideally half going each way. Hence, capacitors should rarely be placed close to the feeder breaker unless a fair amount of load is concentrated there. Likewise, it is best not to place capacitors at the end of distribution feeders unless load or voltage needs dictate it. Low-voltage concerns during contingency backfeeding may also call for capacitors near the feeder breaker.

Capacitors may be switched according to a variety of factors, so selecting a capacitor switching method warrants a more detailed discussion. Switching determination methods (i.e. trip or close decisions) include: VAR requirements, voltage, ambient temperature and time-of-day. Switching on reactive power requirements with voltage override is best for reducing power losses while maintaining proper operating voltage. The simplest way to switch by VAR requirements is installing a local switch controller that uses a single-phase voltage transformer and a single-phase current transformer (CT) to determine the power factor and current magnitude immediately downstream of the capacitor bank and closes it on adjustable settings. The same local capacitor controller can house voltage override controls to close the capacitor bank for low voltage and trip it for high voltage.

Unfortunately, it can be difficult and time-consuming to evaluate whether local capacitor bank switch controllers are working properly after several years of service. Receiving a graph of a feeder’s VARs (reactive power) over time should show capacitors switching on and off as needed. If VAR information is available from SCADA to a local control center, it may prove more economical to employ a more widespread approach of switching feeder capacitors remotely based on feeder VAR data. A limited number of software and hardware companies (such as Cannon Technologies and RCCS) offer systems that initiate capacitor switching commands based on feeder SCADA.

For simplicity, signals can be sent one-way via utility radio, local paging, and cellular control channel (such as Telemetric). Software monitors feeder VAR response after a switching command is sent to confirm capacitor operation and logs suspected switching failures. Capacitor control receivers may be equipped with voltage override. Software allows adjustments in feeder VAR requirements and also permits capacitor banks to be manually switched to respond to abnormal feeder voltage or transmission system needs. Operating one distribution capacitor may be imperceptible on the transmission system, but a global command to switch all distribution capacitors on or off should be evident. For wide-scale implementation, SCADA VAR control capacitor switching is recommended due to its response to reactive power compensation needs with the flexibility of global or individual capacitor manual override. Using such a system, one utility reports replacing all fixed capacitors with switched ones to automatically flag cases of blown fuses as the software systematically cycles capacitors during early morning hours to test them.

Transformer Sizing and Selection

Typically, distribution transformers use copper conductor windings to induce a magnetic field into a grain-oriented silicon steel core to step feeder voltage down for customer use. Therefore, transformers have both load loss and no-load core loss. As in other conductors, transformer copper losses vary with load based on the resistive power loss equation (P_loss= I²R). For some utilities, economic transformer loading means loading distribution transformers to capacity-or slightly above capacity for a short time-in an effort to minimize capital costs and still maintain long transformer life. However, since peak generation is usually the most expensive, total cost of ownership (TCO) studies should take into account the cost of peak transformer losses. Increasing distribution transformer capacity during peak by one size will often result in lower total peak power dissipation-more so if it is over-loaded.

Transformer no-load excitation loss, also known as core or iron loss, occurs from a changing magnetic field in the transformer core whenever it is energized. Core loss varies slightly with voltage but is essentially considered constant. Fixed iron loss depends on transformer core design and steel lamination molecular structure. Improved manufacturing of steel cores and introducing amorphous metals (such as metallic glass) have reduced core losses. Through faster material cooling, mass-produced metallic glass (or MetGlass ) ribbons were developed by Allied Signal (now Honeywell) in the 1990s that reduced core loss by 60 percent compared to conventional grain-oriented silicon steel cores. Copper losses can be slightly higher in metallic glass core transformers but overall loss at rated capacity is less.

Utilities must determine if reduced energy losses more than offset the price premium for more efficient transformers. In general, early transformer replacement programs are not economically warranted.

Feeder Phase Current and Load Balancing

Once a distribution system has been built, some of the easiest loss savings comes from balancing current along three-phase circuits. Feeder phase balancing also tends to balance voltage drop among phases giving three-phase customers less voltage unbalance. Amperage magnitude at the substation doesn’t guarantee load is balanced throughout the feeder length. Feeder phase unbalance may vary during the day and with different seasons. Feeders are usually considered “balanced” when phase current magnitudes are within 10 percent (based on the average current among phases). That is: [(highest phase current - lowest phase current)/average phase current]< 0.1.

Similarly, balancing load among distribution feeders will also lower losses assuming similar conductor resistance. This may require installing additional switches between feeders to allow for appropriate load transfer.

Load Factor Effect on Losses

Typical customer power consumption varies throughout the day and over seasons. Residential customers generally draw their highest power demand in the evening hours when they arrive home from work and school and activate the heating or cooling system, turn on lights, and prepare dinner. Conversely, commercial customer load profiles generally peak in the early afternoon. Because current level (hence, load) is the primary driver in distribution power losses, keeping power consumption more level throughout the day will lower peak power loss and overall energy losses. Ideally, peaks should be “shaved” to fill in troughs. A common measurement of load variation is “load factor.” It ranges between zero and one and is defined as the ratio of average load in a specified time period to peak load during that time period. For example, over a 30-day month (720 hours) peak feeder power supplied is 10 MW. If the feeder supplied a total energy of 5,000 MWh, the load factor for that month is 0.69 (5,000 MWh/(10MW x 720 hours).

Lower power and energy losses are achieved by raising the load factor, which, evens out feeder demand variation throughout the feeder. Increasing the load factor has been met with limited success by offering customers “time-of-use” rates. That is, companies use pricing power to influence consumers to shift electric-intensive activities (such as, electric water and space heating, air conditioning, irrigating, and pool filter pumping) to off-peak times. With financial incentives, some electric customers are also allowing utilities to interrupt large electric loads remotely through radio frequency or powerline carrier during periods of peak use.

Utilities can try to design in higher load factors by running the same feeders through residential and commercial areas.

Conclusion

With increased concern for generation and transmission efficiencies, utilities will find an increasingly compelling business case to adopt distribution loss reduction strategies. The core of these strategies involve reduction in both circuit current and resistance. Distribution feeder design philosophy may be adapted to reduce feeder current by using higher operating voltage and a higher quantity of feeders that are shorter in length. In addition, modifying standards to specify larger conductor sizes will reduce resistance. Current may also be reduced in existing feeders by adding fixed and switched shunt capacitor banks.

Increasing new transformer sizes may reduce peak power loss but may result in higher annual energy loss due to increases in no-load losses. Some utilities may benefit by paying more up front for higher-efficiency transformers and recapture those costs through loss savings over the next 20-plus years. Balancing current on existing feeder phases and redistributing load among feeders will also improve economic operation of existing systems.

Distribution loss reduction takes some engineering analysis, but it will pay off for years to come.

Steve Eckles has been a distribution engineer for 14 years at El Paso Electric Company and is a licensed PE in New Mexico and Texas.

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