Magnetism and Electromagnetism

Magnetism

The principles of magnetism play an important role in the operation of an AC motor. Therefore, in order to understand motors, you must understand magnets. To begin with, all magnets have two characteristics. They attract iron and steel objects, and they interact with other magnets. This later fact is illustrated by the way a compass needle aligns itself with the Earth’s magnetic field (Picture 1).

Picture 1: Magnetism

Magnetic Lines of Flux

The force that attracts an iron or steel object has continuous magnetic field lines, called lines of flux, that run through the magnet, exit the north pole, and return through the south pole. Although these lines of flux are invisible, the effects of magnetic fields can be made visible. For example, when a sheet of paper is placed on a magnet and iron filings are loosely scattered over the paper, the filings arrange themselves along the invisible lines of flux (Picture 2).

Picture 2: Magnetic Lines of Flux

Unlike Poles Attract

The polarities of magnetic fields affect the interaction between magnets. For example, when the opposite poles of two magnets are brought within range of each other, the lines of flux combine and pull the magnets together (Picture 3).

Picture 3: Unlike Poles Attract

Like Poles Repel

However, when like poles of two magnets are brought within range of each other, their lines of flux push the magnets apart (Picture 4). In summary, unlike poles attract and like poles repel. The attracting and repelling action of the magnetic fields is essential to the operation of AC motors, but AC motors use electromagnetism.

Picture 4: Like Poles Repel

Electromagnetism

When current flows through a conductor, it produces a magnetic field around the conductor. The strength of the magnetic field is proportional to the amount of current (Picture 5).

Picture 5: Electromagnetism

Left-Hand Rule for Conductors

The left-hand rule for conductors (Picture 6) demonstrates the relationship between the flow of electrons and the direction of the magnetic field created by this current. If a current carrying conductor is grasped with the left hand with the thumb pointing in the direction of electron flow, the fingers point in the direction of the magnetic lines of flux. The following illustration on Picture 7 shows that, when the electron flow is away from the viewer (as indicated by the plus sign), the lines of flux flow in a counterclockwise direction around the conductor. When the electron flow reverses and current flow is towards the viewer (as indicated by the dot), the lines of flux flow in a clockwise direction.

Picture 6: The left-hand rule for conductors

Picture 7: Magnetic flux direction

Electromagnet

An electromagnet can be made by winding a conductor into a coil and applying a DC voltage. The lines of flux, formed by current flow through the conductor, combine to produce a larger and stronger magnetic field. The center of the coil is known as the core. This simple electromagnet has an air core (Picture 8).

Picture 8: Electromagnet with air core

Adding an Iron Core

Iron conducts magnetic flux more easily than air. When an insulated conductor is wound around an iron core, a stronger magnetic field is produced for the same level of current (Picture 9).

Picture 9: Electromagnet with iron core

Number of Turns

The strength of the magnetic field created by the electromagnet can be increased further by increasing the number of turns in the coil. The greater the number of turns the stronger the magnetic field for the same level of current (Picture 10).

Picture 10: Magnetic field and number of turns

Changing Polarity

The magnetic field of an electromagnet has the same characteristics as a natural magnet, including a north and south pole. However, when the direction of current flow through the electromagnet changes, the polarity of the electromagnet changes. The polarity of an electromagnet connected to an AC source changes at the frequency of the AC source. This is demonstrated in the following illustration on Picture 11.

Picture 11: Changing polarity on electromagnet


At time 1, there is no current flow, and no magnetic field is produced. At time 2, current is flowing in a positive direction, and a magnetic field builds up around the electromagnet. Note that the south pole is on the top and the north pole is on the bottom. At time 3, current flow is at its peak positive value, and the strength of the electromagnetic field has also peaked. At time 4, current flow decreases, and the magnetic field begins to collapse.
At time 5, no current is flowing and no magnetic field is produced. At time 6, current is increasing in the negative direction. Note that the polarity of the electromagnetic field has changed. The north pole is now on the top, and the south pole is on the bottom. The negative half of the cycle continues through times 7 and 8, returning to zero at time 9. For a 60 Hz AC power supply, this process repeats 60 times a second.

Induced Voltage

In the previous examples, the coil was directly connected to a power supply. However, a voltage can be induced across a conductor by merely moving it through a magnetic field. This same effect is caused when a stationary conductor encounters a changing magnetic field. This electrical principle is critical to the operation of AC induction motors. In the following illustration on Picture 12, an electromagnet is connected to an AC power source. Another electromagnet is placed above it. The second electromagnet is in a separate circuit and there is no physical connection between the two circuits.

Picture 12: Induced voltage in electromagnets


This illustration (Picture 12) shows the build up of magnetic flux during the first quarter of the AC waveform. At time 1, voltage and current are zero in both circuits. At time 2, voltage and current are increasing in the bottom circuit. As magnetic field builds up in the bottom electromagnet, lines of flux from its magnetic field cut across the top electromagnet and induce a voltage across the electromagnet. This causes current to flow through the ammeter. At time 3, current flow has reached its peak in both circuits. As in the previous example, the magnetic field around each coil expands and collapses in each half cycle, and reverses polarity from one half cycle to another.

Electromagnetic Attraction

Note, however, that the polarity of the magnetic field induced in the top electromagnet is opposite the polarity of the magnetic field in the bottom electromagnet. Because opposite poles attract, the two electromagnets attract each other whenever flux has built up. If it were possible to move the bottom electromagnet, and the magnetic field was strong enough, the top electromagnet would be pulled along with it (Picture 13).

Picture 13: Electromagnetic Attraction

AC Motor Construction

Three-phase AC induction motors are commonly used in industrial applications. This type of motor has three main parts: rotor, stator and enclosure (Picture 1). The stator and rotor do the work, and the enclosure protects the stator and rotor.

Picture 1: Main parts of AC motor: rotor, stator and enclosure

Stator Core

The stator is the stationary part of the motor’s electromagnetic circuit. The stator core is made up of many thin metal sheets, called laminations (Picture 2). Laminations are used to reduce energy loses that would result if a solid core were used.

Picture 2: Stator Lamination

Stator Windings

Stator laminations are stacked together forming a hollow cylinder. Coils of insulated wire are inserted into slots of the stator core. When the assembled motor is in operation, the stator windings (Picture 3 and Picture 4) are connected directly to the power source. Each grouping of coils, together with the steel core it surrounds, becomes an electromagnet when current is applied. Electromagnetism is the basic principle behind motor operation.

Picture 3: Stator Windings (Partially completed)

Picture 4: Stator Windings (Completed)

Rotor Construction

The rotor is the rotating part of the motor’s electromagnetic circuit (Picture 5). The most common type of rotor used in a three-phase induction motor is a squirrel cage rotor. The squirrel cage rotor is so called because its construction is reminiscent of the rotating exercise wheels found in some pet cages. A squirrel cage rotor core is made by stacking thin steel laminations to form a cylinder.

Picture 5: Rotor

Rather than using coils of wire as conductors, conductor bars are die cast into the slots evenly spaced around the cylinder. Most squirrel cage rotors are made by die casting aluminum to form the conductor bars. Manufacturers also makes motors with diecast copper rotor conductors. These motor exceed NEMA Premium efficiency standards. After die casting, rotor conductor bars are mechanically and electrically connected with end rings. The rotor is then pressed onto a steel shaft to form a rotor assembly (Picture 6).

Picture 6: Cutaway View of Rotor

Enclosure

The enclosure consists of a frame (or yoke) and two end brackets (or bearing housings). The stator is mounted inside the frame. The rotor fits inside the stator with a slight air gap separating it from the stator. There is no direct physical connection between the rotor and the stator (Picture 7).

Picture 7: Partially Assembled Motor


The enclosure protects the internal parts of the motor from water and other environmental elements. The degree of protection depends upon the type of enclosure. Bearings, mounted on the shaft, support the rotor and allow it to turn. Some motors, like the one shown in the following illustration, use a fan, also mounted on the rotor shaft, to cool the motor when the shaft is rotating (Picture 8).

Picture 8: Cutaway View of Motor

AC Motors

AC motors are used worldwide in many applications to transform electrical energy into mechanical energy. There are many types of AC motors, but the most common type of motor used in industrial applications are three-phase AC induction motors. An AC motor of this type may be part of a pump or fan or connected to some other form of mechanical equipment such as a winder, conveyor, or mixer (Picture 1).

Picture 1: Winder, Pump, Conveyor

Force and Motion

Before discussing AC motors it is necessary to understand some of the basic terminology associated with motor operation. Many of these terms are familiar to us in some other context.

Force

In simple terms, a force is a push or a pull. Force may be caused by electromagnetism, gravity, or a combination of physical means.
Net force is the vector sum of all forces that act on an object, including friction and gravity. When forces are applied in the same direction, they are added. For example, if two 10 pound forces are applied in the same direction the net force would be 20 pounds. If 10 pounds of force is applied in one direction and 5 pounds of force is applied in the opposite direction, the net force would be 5 pounds and the object would move in the direction of the greater force. If 10 pounds of force is applied equally in both directions, the net force would be zero and the object would not move (Picture 2).

Picture 2: Net force

Torque

Torque is a twisting or turning force that causes an object to rotate. For example, a force applied to the end of a lever causes a turning effect or torque at the pivot point. Torque (τ) is the product of force and radius (lever distance):

τ = Force x Radius

In the English system of measurements, torque is measured in pound-feet (lb-ft) or pound-inches (lb-in). For example, if 10 lbs of force is applied to a lever foot long, the resulting torque is 10 lb-ft. An increase in force or radius results in a corresponding increase in torque. Increasing the radius to two feet, for example, results in 20 lb-ft of torque (Picture 3).

Picture 3: Torque

Speed

An object in motion takes time to travel any distance. Speed is the ratio of the distance traveled and the time it takes to travel:

Speed = Distance / Time

Linear speed is the rate at which an object travels a specified distance. Linear speed is expressed in units of distance divided by units of time, for example, miles per hour or meters per second (m/s). Therefore, if it take 2 seconds to travel 40 meters, the speed is 20 m/s.

Angular (Rotational) Speed

The angular speed of a rotating object determines how long it takes for an object to rotate a specified angular distance. Angular speed is often expressed in revolutions per minute (RPM). For example, an object that makes 10 complete revolutions in one minute, has a speed of 10 RPM.

Acceleration

An object can change speed. An increase in speed is called acceleration. Acceleration occurs only when there is a change in the force acting upon the object. An object can also change from a higher to a lower speed. This is known as deceleration (negative acceleration). A rotating object, for example, can accelerate from 0 RPM to 20 RPM, or decelerate from 20 RPM to 0 RPM.

Inertia

Mechanical systems are subject to the law of inertia. The law of inertia states that an object will tend to remain in its current state of rest or motion unless acted upon by an external force. This property of resistance to acceleration/deceleration is referred to as the moment of inertia. The English system unit of measurement for inertia is pound-feet squared (lb-ft^2). For example, consider a machine that unwinds a large roll of paper (Picture 4). If the roll is not moving, it takes a force to overcome inertia and start the roll in motion. Once moving, it takes a force in the reverse direction to bring the roll to a stop.

Picture 4: Inertia - Paper roller

Any system in motion has losses that drain energy from the system. The law of inertia is still valid, however, because the system will remain in motion at constant speed if energy is added to the system to compensate for the losses.

Friction

Friction occurs when objects contact one another. As we all know, when we try to move one object across the surface of another object, friction increases the force we must apply. Friction is one of the most significant causes of energy loss in a machine.

Work

Whenever a force causes motion, work is accomplished. Work can be calculated simply by multiplying the force that causes the motion times the distance the force is applied:

Work = Force x Distance

Since work is the product of force times the distance applied, work can be expressed in any compound unit of force times distance. For example, in physics, work is commonly expressed in joules. 1 joule is equal to 1 Newton-meter, a force of 1 Newton for a distance of 1 meter. In the English system of measurements, work is often expressed in foot-pounds (ft-lb), where 1 ft-lb equals 1 foot times 1 pound.

Power

Another often used quantity is power. Power is the rate of doing work or the amount of work done in a period of time:

Power = (Force x Distance) / Time = Work / Time

Horsepower

Power can be expressed in foot-pounds per second, but is often expressed in horsepower. This unit was defined in the 18-th century by James Watt. Watt sold steam engines and was asked how many horses one steam engine would replace. He had horses walk around a wheel that would lift a weight (Picture 5). He found that a horse would average about 550 foot-pounds of work per second. Therefore, one horsepower is equal to 550 foot-pounds per second or 33000 foot-pounds per minute.

Picture 5: Horsepower

When applying the concept of horsepower to motors, it is useful to determine the amount of horsepower for a given amount of torque and speed. When torque is expressed in lb-ft and speed is expressed in RPM, the following formula can be used to calculate horsepower (HP):

Power[HP] = Torque[lb-ft] x Speed[RPM] / 5252

Note that an increase in torque, speed, or both increases horsepower.

Horsepower and Kilowatts

AC motors manufactured in the United States are generally rated in horsepower, but motors manufactured in many other countries are generally rated in kilowatts (kW). Fortunately it is easy to convert between these units.

Power[kW] = 0.746 x Power[HP]

For example, a motor rated for 25 HP is equivalent to a motor rated for 18.65 kW. Kilowatts can be converted to horsepower with the following formula:

Power[HP] = 1.34 x Power[kW]

Impact of leading Power Factor loads on Synchronous Alternators

Many electrical loads incorporate elements that can impose a leading power factor on the power source. While these loads are typically not a problem for utility power sources, leading power factor can cause generator set failures or the failure of certain loads to operate properly on a generator set. This article briefly explains the phenomena, and what can be done to address problems when leading power factor loads are present.

The problems seen when attempting to operate generator sets with leading power factor loads may seem mysterious, but in reality, they are not too much different from another energy absorption problem: the limited ability of a generator set to absorb real kW power from loads some elevator drives, and in crane applications. A generator is physically unable to absorb more than a very small amount of real (kW) or reactive (kVAR) power. While the reverse kW power produced by a dropping load in a crane application drove the engine into over-speed conditions when it exceeded the ability of the engine to absorb it, the reverse kVAR load presented by leading power factor devices will drive the alternator into over voltage conditions.
Over the past years, generator set manufacturers have evolved their equipment designs to include use of digital automatic voltage regulator (AVR) equipment, separate excitation systems, and PWM-type control architecture to enable the generator set to produce and stable output voltage and successfully operate non-linear loads. At the same time, manufacturers of equipment that has non-linear load characteristics have begun to commonly employ filters to limit harmonic current distortion induced on the power supply. Capacitive elements are also applied in facilities to improve the power factor when operating on the utility source to avoid higher energy charges. While filters provide positive impacts on the overall power system, they can be very disruptive to generator operation.

Picture 1: Example - no load field required is 17 A, while full load is approximately 38 A


The generator set AVR monitors generator output voltage and controls alternator field strength to maintain constant output voltage. Relatively low AVR output is required to maintain generator voltage at no load. In the Picture 1 shown the no load exciter field current required is less than half the full load level. Filter equipment is often sized for operation at the expected maximum load on the UPS or motor load. At light loads there may be excess filter capacitance, causing a leading power factor. Since rectifiers are commonly designed to ramp on from zero load to minimize load transients, leading power factor loads may be imposed on the system until inductive loads are added to the system or the load factor of the nonlinear load increases.
A utility supply simply absorbs the reactive power output because it is extremely large relative to the filter system and it has many loads that can consume this energy. With a generator set, however, the rising voltage from the leading power factor causes the voltage regulator to turn down and reduce alternator field strength. If the AVR turns all the way off it looses control of system voltage, which can result in sudden large increases in system voltage. The increase in voltage can result in damage to loads, or can cause the loads to fail to operate on the generator set. A UPS is designed to recognize high voltage as an abnormal and undesirable condition, so it can immediately switch off its rectifier. When it does that, the high voltage condition is immediately relieved (because the filter is disconnected from the generator set) and voltage returns to normal. To the observer, the generator will seem to be unable to pick up the system loads.

Paralleling problems

Generator sets that are using in isolated bus paralleling systems have particular issues with leading power factor loads. When loads are applied to a parallel generator bus, the total load on the system can be many times larger than the capacity of a single generator set. The generator sets close to the bus one at a time, so that if high loads (either leading or lagging) are applied before genset capacity is available, the generator bus can fail. With leading power factor loads, the failure mode will be due to either an over voltage condition or reverse kVAR shutdown. due to either an over-voltage condition or due to reverse kVAR shutdown.
Further, there is a tendency, particularly in data center applications, to group UPS loads together on a common bus. This concentrates the leading power factor load on one bus, so that if a large group of UPS load is applied to the first generator set available, it can easily be driven into an excess reverse var condition, which will result in over-voltage and shutdown. If multiple generator sets are on the bus and a large reverse var load is applied to the genset bus, the var load sharing control system can be disrupted, because not all load sharing control systems include logic for reverse kVAR load sharing. If reverse kVAR load sharing is not in the logic for the control system the system will typically cause one or more generator sets to exceed their reverse power limits, which can cause pole slipping.
Generator sets in a paralleling system are maintained in synchronism by their magnetic fields. When a leading power factor load is applied, the voltage of the genset or genset bus rises, and the voltage regulation system of each generator set reduces exciter power, reducing the strength of the magnetic field. If the field is switched off in an attempt to reduce voltage to an acceptable level, the generator set may slip a pole, which results in potentially catastrophic alternator damage.
The reverse kVAR limit of the aggregated generators is the sum of the reverse var limits of each generator. However, the reverse var settings may not be able to take advantage of all the capability of the alternators due to limitations in the VAR load sharing system.

Solutions

What can be done about this? First, we need to understand how much reactive power can be absorbed by the generator without negative impact. The ability of an alternator to absorb power is described by a reactive capability curve. Picture 2 shows a typical generator capability curve describing the capability of a machine to produce and absorb power. In this curve the kVAR produced or absorbed is on the X-axis (positive to the right). The Y-axis shows kW (positive going up). kVAR and kW are shown as per unit quantities based on the rating of the alternator (not necessarily the generator set, which may have a lower rating.
The normal operating range of a generator set is between zero and 100 percent of the kW rating of the alternator (positive) and between 0.8 and 1.0 power factor (green area on curve). The black lines on the curves show the operating range of a specific alternator when operating outside of normal range. Notice that as power factor drops, the machine must be de-rated to prevent overheating. On the left quadrant, you can see that near-normal output (yellow area) can be achieved with some leading power factor load, in this case, down to about 0.97 power factor, leading. At that point, the ability to absorb additional kVAR quickly drops to near zero (red area), indicating that the AVR is “turning off” and any level of reverse kVAR greater than the level shown will cause the machine to lose control of voltage. In other words, if the machine is rated for operation at 1000 kVA and 0.8 power factor (600 kVAR rated), with a reverse kVAR level of 0.2 per unit (rated), you will exceed the machine’s capabilities. So, with more than 120 kVAR reverse reactive power and leading power factor lower than 0.97 (for most people a surprisingly low level) we have a problem.

The ability of a generator set to absorb reactive power is defined by a reverse kVAR limit, not a specific power factor.

Picture 2: Alternator capability curve (Green area is normal operating range of a typical synchronous machine, yellow is abnormal but not damaging, and operating in red regional will cause damage or misoperation)


The solution to this problem on this specific machine involves avoiding excess reverse kVAR levels through proper system design and operation:

• Modify the sequence of operation for the facility so that loads that require reactive power are present on the bus when the UPS ramps on to the generator. The reactive power produced by the filters will be consumed by the system loads, and the loss of voltage control is avoided. This requires a re-thinking of operating sequences in some cases because:
1) perhaps mechanical loads rather than UPS will need to go on the generator first, or
2) loads will be required to be broken into smaller blocks of UPS and mechanical loads, rather than larger isolated buses of each.

• Turn off the filters when operating on the generator set or reduce the magnitude of filtering provided. If the generator is provided with modern digital excitation control, the filters won’t be needed to maintain stable generator operation, but may still be required to properly serve other loads.


The actual limits of reverse kVAR can vary considerably from machine to machine, both within a specific manufacturer’s product line, and between equipment from
different suppliers. A good rule of thumb for equipment is that it can absorb about 20% of its rated kVAR output in reverse kVAR without losing control of voltage. However, since this characteristic is not universal, it is advisable for a system designer to specify the reverse kVAR limit used in his design, or the magnitude of the reverse kVAR load that is expected. Note that this is not specified as a leading power factor limit, but rather as a maximum magnitude of reverse kVAR.
Alternators are physically limited in their ability to both produce and absorb power. When a leading power factor load is applied to an alternator at a site, misoperation of the generator, over-voltage, load misoperation, and alternator damage can occur. There is very little that the alternator supplier can do to resolve problems at a specific site other than to help a system designer understand the nature of the problem and the limits of the machine as installed. Most of the solution will come from changes in the system sequence of operation, or hardware changes that prevent disruptive reverse var conditions from affecting the generator set.

Conclusions and recommendations

>> Synchronous alternators have limited ability to absorb kVAR from load devices, and exceeding this limit will result in generator set shutdown.
>> Paralleling operations require careful consideration of the loading sequence to prevent reverse var conditions that can damage the generator set.
>> Consider modifying system sequence of operation or limiting filter operation until adequate loads are in place to prevent reverse kVAR conditions on the genset.
>> Specify the magnitude of reverse kVAR the genset must be able to absorb, not the power factor alone.
>> In single generator applications protective devices can be set to the limits of the alternator. In paralleling applications both alternator limits and Var load share limits must be considered.



Source: White paper By Gary Olson, Power Systems Development

Estimate of Paper Deterioration

Estimate of Paper Deterioration (Online)

The two methods below should be used together:

CO2 and CO Accumulated Total Gas Values

IEEE Standard C57.104™ Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers, gives status conditions, based on accumulated values of CO2 and CO. Accumulated dissolved gas levels provide four status conditions: normal operation, modest concern (investigate), major concern (more investigation), and imminent risk (nearing failure). The CO2 and CO levels in ppm for each status are given in table shown on Picture 1.

CO2 /CO Ratio

The CO2/CO ratio should also be analyzed in conjunction with the CO2 and CO accumulated values.

Picture 1: Paper Status Conditions Using CO2 and CO


CAUTION: The status from table on Picture 1 should be at least in Condition 2 or 3 from one or both gases before a detailed investigation is begun. There is no need to look at the ratios, unless a substantial amount of these gases have already been generated. If the transformer is relatively new, CO2 and other atmospheric gases (N2, O2, and even some CO) may be migrating out of the paper into the oil because the paper was stored in air prior to transformer assembly. If the paper was stored in a polluted city atmosphere, a considerable amount of CO may show up in the DGA. This may look like the transformer has a problem and is generating a lot of CO. However, if the transformer has a real problem, H2 and perhaps other heat gases (CH4, C2H6, C2H4) should also be increasing.

Estimate of Paper Deterioration (Offline During Internal Inspection)

Degree of Polymerization (DP)

Do not open a transformer for the sole purpose of doing this test. Perform this test only if the unit is being opened for other reasons. One of the most dependable means of determining paper deterioration and remaining life is the DP test of the cellulose. The cellulose molecule is made up of a long chain of glucose rings which form the mechanical strength of the molecule and the paper. DP is the average number of these rings in the molecule. As paper ages or deteriorates from heat, acids, oxygen, and water, the number of these rings decreases. When the insulation is new, the DP is typically between 1,000 and 1,400. As paper deteriorates, bonds between the rings begin to break. When the DP reaches around 200, the insulation has reached the end of life. All mechanical strength of the insulation has been lost; the transformer must be replaced.


Process

When doing an internal inspection, or if the transformer is opened and oil is fully or partially drained for any reason on a service-aged transformer, perform a DP test. Remove a sample of the paper insulation about 1 centimeter square from a convenient location near the top of the center phase with a pair of tweezers. In general, in a three-phase transformer, the hottest most thermally aged paper will be at the top of the center phase. If it is not possible to take a sample from the center phase, take a sample from the top of one of the other phases. Send this sample to an oil testing laboratory for the DP test. Analyze results of the DP test with table shown on Picture 2 taken from EPRI’s Guidelines for the Life Extension of Substations (2002 Update, chapter 3). Table on Picture 2 has been developed by EPRI to estimate remaining life.

Picture 2: DP Values for Estimating Remaining Paper Life

Internal Inspection

If an internal inspection is absolutely necessary, it must be completed by an experienced person who knows exactly what to look for and where to look. Many times, more damage is done by opening a transformer and doing an internal inspection than what is gained. There are very few reasons for an internal inspection, some are shown below:

♦ Extensive testing shows serious problems.
♦ Unexplained relay operation takes the transformer offline, and testing is inconclusive.
♦ Acetylene is being generated in the DGA (indicates active internal arcing).
♦ Ethylene and ethane are being generated in sufficient quantities to cause grave concern. This generally indicates a bad connection on a bushing bottom or tap changer, circulating currents, additional core ground, or static discharges.
♦ A core ground must be repaired, or an additional core ground has developed which must be removed.
♦ Vibration and ultrasonic analysis indicate loose windings that are generating gases from heat caused by friction of the vibrating coils. Loose wedges must be located and replaced.
♦ CO2/CO ratio are very low (around 2 or 3), indicating severe paper deterioration from overheating. Cooling must be checked carefully before opening the transformer.
♦ Furans are high, indicating excessive aging rate - a DP test must be completed.
♦ The metal particle count is above 5,000 in 10 milliliters of oil taken specifically for detecting metal particle count.

NOTE: If a service-aged transformer is opened for any reason, a sample of the paper should be taken for DP analysis. If possible, take the paper sample from the top of the center phase winding because this will be near the hot spot. If it is not possible to get a paper sample from the top of B phase, take a sample from the top of one of the other windings.

Transformer Borescope

A new technology has been developed for internal transformer inspections using a specifically designed borescope. The borescope can be used with oil inside the transformer. Core, windings, connections, etc., can be examined and photographed. If it is necessary to go inside the transformer for repairs, workers will possibly know exactly what is defective and exactly what must be done. This technology, used properly, can save generating time and repair dollars.

Ultrasonic and Sonic Fault Detection, Vibration Analysis and Turns Ratio Test

Ultrasonic and Sonic Fault Detection

This test should be performed when hydrogen is increasing markedly in the DGA. High hydrogen generation indicates partial discharge occurring inside the transformer. Other gases such as methane, ethane, and ethylene may also be increasing. Acetylene may also be present, if arcing is occurring, and may also be increasing. Ultrasonic contact (in contact with the tank) fault detection can detect partial discharge (corona) and full discharge (arcing) inside the transformer. This test can also detect loose parts inside the transformer. Partial discharges emit energy in the order of 20 kHz to 200 kHz. These frequencies are above levels that can be audibly detected. The test equipment receives the signals and converts them electronically into audible signals. Headphones are provided to eliminate spurious noise from the power plant and other sources. The equipment logs data for future reference. A baseline test should be conducted and compared with future test data. This test method has some limitations. If a partial discharge is located deep within the windings, external detectors may not be sensitive enough to detect and locate the problem. However, partial discharges most often occur near the top of the transformer in areas of high-voltage stress which can readily be located by this method. These defects can sometimes be easily remedied, extending transformer service life.

Process

Magnetic piezoelectric crystal transducers, sized and tuned to the appropriate frequencies, are placed on the outside of the tank, and signals are recorded. If discharges are detected, the location is triangulated so that, during an internal inspection, the inspector will know the general area to search for a problem. Likewise, sonic (audible ranges) fault detection can find mechanical problems, such as noisy bearings in pumps or fans, nitrogen leaks, loose shields, or other loose parts inside the transformer tank, etc. See also IEEE 62-1995™.

Vibration Analysis

Vibration analysis by itself cannot predict many faults associated with transformers, but it is another useful tool to help determine transformer condition. Vibration can result from loose transformer core segments, loose windings, shield problems, loose parts, or bad bearings on oil cooling pumps or fans. Exercise extreme care in evaluating the source of vibration. Many times, a loose panel cover, door, or bolts/screws lying in control panels, or loose on the outside have been misdiagnosed as problems inside the tank. There are several instruments available from various manufacturers, and the technology is advancing quickly. Every transformer is different, therefore, to detect this, baseline vibration tests should be run and data recorded for comparison with future tests.

Process

For a normal transformer in good condition, vibration data is normally two times line frequency (120 Hz) and also appears as multiples of two times line frequency; that is, four times 60 (240 Hz), six times 60 (360 Hz), etc. The 120 Hz is always the largest and has an amplitude of less than 0.5 inch per second (ips) and greater than 0.1 ips. The next peak of interest is the four times line frequency or 240 Hz. The amplitude of this peak should not exceed 0.5 ips. None of the remaining harmonic peaks should exceed 0.15 ips in amplitude.

Turns Ratio Test

This test only needs to be performed if a problem is suspected from the DGA, Doble testing, or relay operation. The turns ratio test detects shorted turns, which indicate insulation failure by determining if the correct turns ratio exists. Shorted turns may result from short circuits or dielectric (insulation) failures.

Process

Measurements are taken by applying a known low voltage across one winding and measuring the induced-voltage on the corresponding winding. The low voltage is normally applied across a high-voltage winding so that the induced-voltage is lower, reducing hazards while performing the test. The voltage ratio obtained by the test is compared to the nameplate voltage ratio. The ratio obtained from the field test should agree with the factory within 0.5%. New transformers of good quality normally compare to the nameplate within 0.1%.
For three-phase delta/wye or wye/delta connected transformers, a three-phase equivalency test should be performed. The test is performed and calculated across corresponding single windings. Look at the nameplate phasor diagram to find out what winding on the primary corresponds to a particular winding on the secondary. Calculate the ratio of each three-phase winding based on the line to neutral voltage of the wye winding. Divide the line-to-line winding voltage by 1.732 to obtain the correct line-to-neutral voltage. Check the tap changer position to make sure it is set at the position where the nameplate voltage is based. Otherwise, the turns ratio test information cannot be compared with the nameplate. Nameplate information for Reclamation transformers is normally based on the tap three position of the tap changer. See the manufacturer’s instruction manual for the specific turns ratio tester for details. See IEEE 62-1995™.

Visual Inspection of Transformers

Visual inspection of the transformer exterior reveals important condition information. For example, valves positioned incorrectly, plugged radiators, stuck temperature indicator and level gauges, and noisy oil pumps or fans. Oil leaks can often be seen which indicate a potential for oil contamination, loss of insulation, or environmental problems. Physical inspection requires staff experienced in these techniques. There are several required physical inspections that will not be covered here because they were addressed previously. Be sure to inspect the following: winding temperature indicators, pressure relief devices, sudden pressure relay, conservator bladder, conservator breather, and bladder failure relay.

Oil Leaks

Check the entire transformer for oil leaks. Leaks develop due to gaskets wearing out, ultraviolet exposure, taking a “set,” or from expansion and contraction, especially after transformers have cooled, due to thermal shrinkage of gaskets and flanges. Many leaks can be repaired by applying an epoxy or other patch. Flange leaks may be stopped with these methods, using rubberized epoxy forced into the flange under pressure. Very small leaks in welds and tanks may be stopped by peening with a ball-peen hammer, cleaning with the proper solvent, and applying a “patch” of the correct epoxy. Experienced leak mitigation contractors whose work is guaranteed may also be employed. Some leaks may have to be welded. Welding may be performed with oil in the transformer if an experienced, qualified, and knowledgeable welder is available. If welding with oil in the tank is the method chosen, oil samples must be taken for DGA, both before and after welding. Welding may cause gases to appear in the DGA and it must be determined what gases are attributed to welding and which ones to transformer operation.

Oil Pumps

If the transformer has oil pumps, check the flow indicators and pump isolation valves to ensure that oil is circulating properly. Pump motor(s) may also have reversed rotation, and flow indicators may still show that oil is flowing. To ensure motors are turning in the proper direction, use an ammeter to check the motor current. Compare results with the full-load-current indicated on the motor nameplate. If the motor is reversed, the current will be much less than the nameplate full-load-current. Check oil pumps with a vibration analyzer if they develop unusual noises. Have the DGA lab check for dissolved metals in the oil and run a metal particle count for metals, if the bearings are suspect. This should be performed as soon as a bearing becomes suspect. Bad oil pump bearings can put enough metal particles into the oil to threaten transformer insulation and cause flashover inside the tank, resulting in an explosive catastrophic failure of the transformer tank.

Fans and Radiators

Inspect all isolation valves at the tops and bottoms of radiators to ensure they are open. Inspect cooling fans and radiators for cleanliness and fans for proper rotation. Check for dirty or damaged fan blades or partially blocked radiators. Fans are much more efficient if the blades are clean and rotating in cool air. Normally, fans blow cool air through the radiators, they should not be pulling air through. Check to see if fans are reversed electrically (i.e., pulling air first through the radiators and then through the fan blades). This means that the blades are rotating in warm air after it passes through the radiator, which is much less efficient. Place a hand on the radiator opposite the fans, air should be coming out of the radiator against your hand. Watch the blades as they rotate slowly when they are starting or stopping to determine which way they should be rotating and correct the rotation if necessary. See IEEE 62-1995™. Also inspect radiators and fans with an infrared camera.

Age

Transformer age is an important factor to consider when identifying candidates for replacement or rehabilitation. Age is one indicator of remaining life and upgrade potential to current state-of-the art materials. During transformer life, structural strength and insulating properties of materials used for support and electrical insulation (especially paper) deteriorate. Although actual service life varies widely depending on the manufacturer, design, quality of assembly, materials used, maintenance, and operating conditions, the expected life of a transformer is about 40 years.

Infrared Temperature Analysis

Infrared analysis should be conducted annually while equipment is energized and under full load, if possible. IR analysis should also be conducted after any maintenance or testing to see if connections that were broken were re-made properly. Also, if IR is performed during factory heat run, the results can be used as a baseline for later comparison.

IR for Transformer Tanks

Unusually high external temperatures or unusual thermal patterns of transformer tanks indicate problems inside the transformer, such as low oil level, circulating stray currents, blocked cooling, loose shields, tap changer problems, etc. Infrared scanning and analysis is required annually for trending purposes by National Fire Protection Association. See also IEEE 62-1995™. Abnormally high temperatures can damage or destroy transformer insulation and, thus, reduce life expectancy. Thermal patterns of transformer tanks and radiators should be cooler at the bottom and gradually warmer ascending to the top. See Picture 1 for a normal pattern; the red spot at the top is normal showing a “hot spot” top of B phase, about 110 degrees Fahrenheit (°F). Any departure from this pattern means a probable problem which must be investigated. An IR inspection can find over-heating conditions or incorrect thermal patterns. IR scanning and analysis requires trained staff, experienced in these techniques.

Picture 1: Normal Transformer IR Pattern

IR for Surge Arresters

Surge arresters should be included when infrared scanning energized transformers. Look for unusual thermal patterns on the surface of lightning arresters (see the arrester IR image in Picture 2). Note that the yellow in the top right of the image is a reflection not associated with the arrester. A temperature profile of the arrester is shown as black lines. Note the hot spot (yellow) about a third of the way down from the top. This indicates that immediate de-energization and replacement must be undertaken. Catastrophic failure is imminent which can destroy nearby equipment and be hazardous to workers. Also compare thermal patterns to sister units or earlier scans of the same arrester. Scan all high-voltage connections and compare them to nearby connections for unusual temperatures.

Picture 2: IR Image of Defective Arrester

IR for Bushings

IR scans of bushings can show low oil levels which would call for immediate de-energization and replacement. This generally means that the seal in the bushing bottom has failed, leaking oil into the transformer. The top seal has probably also failed, allowing air and up the bushing. Another reason a bushing can exhibit a high oil level is that the top seal is leaking, allowing water to enter. The water migrates to the bushing bottom, displacing the oil upward. Remember, over 90% of bushing failures are attributed to water entrance through the top seal. Bushings commonly fail catastrophically, many times destroying the host transformer or breaker and nearby equipment and causing hazards to workers. Picture 3 shows low-oil level in a high-voltage transformer bushing. Compare previous IR scans of the same bushing with the current scan. Doble hot-collar testing possibly may show this problem. However, Doble tests are run infrequently, and the transformer has to be out of service, under clearance, and both primary and secondary conductors removed, while an IR scan easily can be performed at any time.

Picture 3: IR Image of Defective Bushing

IR for Radiators and Cooling Systems

Examine radiators with an IR camera and compare them with each other. A cool radiator or segment indicates that a valve is closed or the radiator or segment is plugged. The IR image (Picture 4) shows that the cold left radiator section is valved off or plugged. If visual inspection shows the valves are open, the radiator or segment must be isolated, drained, removed, and the blockage cleared. Do not allow a transformer to operate with reduced cooling which drastically shortens transformer life. Remember, an increased operating temperature of only 8 to 10 °C will reduce transformer life by one-half. IR scan all cooling systems, including heat exchangers, fans, pumps, motors, etc. Check inside control panels for overloaded wiring, loose connections, and overheated relays. Look for unusual thermal patterns and compare similar equipment.

Picture 4: IR Image Showing Blocked Radiators

Corona Scope Scan

With the transformer energized, scan the bushings and surge arresters and all high-voltage connections for unusual corona patterns. Corona should be visible only at the top of bushings and arresters, and corona at connections should be similar to sister connections. As a bushing deteriorates due to physical defects, the corona pattern will grow progressively larger. When the corona pattern reaches a grounded surface (i.e., the tank or structure), a flashover will occur, destroying the bushing or arrester and, perhaps, the transformer. The corona scope will reveal this problem long before a flashover.