Power Factor

The power factor of an AC electric power system is defined as the ratio of the real power flowing to the load to the apparent power in the circuit and is a dimensionless number between 0 and 1.Real power is the capacity of the circuit for performing work in a particular time. Apparent power is the product of the current and voltage of the circuit.

AC power flow has the three components: real power (also known as active power) (P), measured in watts (W); apparent power (S), measured in volt-amperes (VA); and reactive power (Q), measured in reactive volt-amperes (var).

A high power factor is generally desirable in a transmission system to reduce transmission losses and improve voltage regulation at the load. It is often desirable to adjust the power factor of a system to near 1.0.

 

The complex power is the vector sum of real and reactive power. The apparent power is the magnitude of the complex power.
  Real power (P)
  Reactive power (Q)
  Complex power (S)
  Apparent Power (|S|)
  Phase of Current (φ)

Why is the rating of transformers given in kVA and not in kW?

kVA is the unit for apparent power. Apparent power consists of active and reactive power. Active power is the share of the apparent power which transmits energy from the source (generator) to the user. Reactive power is the share of the apparent power which represents a useless oscillation of energy from the source to the user and back again. It occurs when on account of some »inertia« in the system there is a phase shift between voltage and current. This means that the current does not change polarity synchronous with the voltage. But the heat generated in a winding as well as the eddy current losses generated in a transformer core depend on the current only, regardless of whether it aligns with the voltage or not. Therefore the heat is always proportional to the square of the current amplitude, irrespective of the phase angle (the shift between voltage and current). So a transformer has to be rated (and selected) by apparent power.

Special care has to be taken if the load current of a transformer includes any higher frequencies such as harmonics. Then the transformer may even overheat although the TRMS load current, measured correctly with a TRMS meter, does not exceed the current rating! Why is this? It is because the copper loss includes a share of about 5% to 10% of so-called supplementary losses. These arise from eddy currents in mechanical, electrically conductive parts made of ferromagnetic materials and especially in the low voltage windings with their large cross sections. The magnetic stray fields originating from a lack of magnetic coupling between the HV and LV windings (main stray canal) induce something that could be called an “eddy voltage” inside the conductors, which drives an eddy current flowing around in a circle across the conductor, perpendicular to the main load current. Now the amplitude of this “eddy voltage” is proportional to the rate of change of the magnetic field strength. The rate of change of the magnetic field strength is proportional to both the amplitude and the frequency of the current. So the eddy current increases proportionally to the load current and proportionally to the operating frequency, for the limitation to the eddy current is Ohm’s Law. The supplementary power loss caused by the eddy current is eddy current times “eddy voltage”. Hence, the supplementary losses increase by the square of the load current, which excites the magnetic stray field, and by the square of the frequency, while the “main copper loss” increases only by the square of the load current amplitude. Therefore the transformer runs hotter when the load current has the same amplitude but is superimposed by higher frequency constituents above the rated frequency. This additional heat loss is difficult to quantify, especially as the transformer’s stray reactance limits the passage of higher frequency currents to some extent, but in an extreme case it may drive the supplementary loss up from 10% to 80% of the copper loss. This means that the transformer may run some 70% hotter (of temperature rise above ambient) than specified for rated (sinusoidal) current. Since the ohmic heat loss, however, depends on the square of the current, it is enough to limit the load current to some 65% of its rating to avoid overheating.

Duty Cycle

In a periodic event, duty cycle is the ratio of the duration of the event to the total period.

duty cycle D = \frac{\tau}{\Tau} \,

where

τ is the duration that the function is active
Τ is the period of the function.

A motor runs for one out of 100 seconds, or 1/100 of the time, and therefore its duty cycle is 1/100, or 1 percent.

How to choose a Transformer

When choosing a transformer, there are two primary concerns: the load and the application. Several factors must be evaluated carefully while making the choice, to ensure that the needs of both primary concerns are met. To use a cliche, it is typically a ‘no-brainer’ to choose smaller transformers. A unit with a kVA rating that is larger from the anticipated load can quickly be picked up. But if you are selecting a large unit for an electrical utility system, to be part of a large distribution network, you are typically making a much larger investment; thus the evaluation process is much more detailed and elaborate. With over 90 years of experience in this industry, Pacific Crest Transformers has put together a quick checklist to help you make your choice judiciously.

Top Questions
There are three major questions that influence your choice:

  • Does the chosen unit have enough capacity to handle the expected load, as well as a certain amount of overload?
  • Can the capacity of the unit be augmented to keep up with possible increase in load?
  • What is the life expectancy of the unit? What are the initial, installation, operational, and maintenance costs?

To Select the Right Transformer, First determine:

  • Primary voltage, which is the available voltage
  • Secondary voltage required by load equipment
  • Frequency (in Hz) and phase (single or three-phase ? for the secondary voltage as well)
  • kVA load; with possible future increases factored in
  • Is the transformer to be used indoors or outdoors?
  • Is the transformer to be floor or wall-mounted?
  • Is an auto transformer or a double-wound transformer required?

Evaluation Factors

The cost and capacity of the transformer typically relate to a set of evaluation factors:

1. Application of the Unit

Transformer requirements clearly change based on the application.

For example: in the steel industry, a large amount of uninterrupted power is required for the functioning of metallurgical and other processes.Thus, load losses should be minimized – which means a particular type of transformer construction that minimizes copper losses is better suited. In wind energy applications, output power varies a great extent at different instances; transformers used here should be able to withstand surges without failure. In smelting, power transformers that can supply constant, correct energy are vital; in the automotive industry, good short-term overload capacity is a necessary attribute. Textile industries, using motors of various voltage specifications, will need intermittent or tap-changing transformers; the horticulture industry requires high-performance units that suit variable loading applications with accurate voltage.

These examples serve to underline that type of load (amplitude, duration, and the extent of non-linear and linear loads) and placement are key considerations. If standard parameters do not serve your specific application, then working with a manufacturer that can customize the operating characteristics, size and other attributes to your needs will be necessary. Pacific Crest regularly builds custom transformers for unique applications.

2. Insulation Type (Liquid-Filled or Dry Type)

While there is still debate on the relative advantages of the available types of transformers, there are some performance characteristics that have been accepted:

  • Liquid-filled transformers are more efficient, have greater overload capability and longer life expectancy.
  • Liquid-filled units are better at reducing hot-spot coil temperatures, but have higher risk of flammability than dry types.
  • Unlike dry type units, liquid-filled transformers sometimes require containment troughs to guard against fluid leaks.

Dry type units are usually used for lower ratings (the changeover point being 500kVA to 2.5MVA). Placement is also a crucial consideration here; will the unit be indoors serving an office building/apartment, or outdoors serving an industrial load? Higher-capacity transformers, used outdoors, are almost always liquid-filled; lower capacity, indoor units are typically dry types. Dry types typically come in enclosures with louvers, or sealed; varnish, vacuum pressure impregnated (VPI) varnish, epoxy resin or cast resin are the different types of insulation used.

Liquid-filled types: choice of filler material
The choice of filler material is usually based on factors that include temperature rating of the transformer, mechanical strength of the coils, dielectric strength of the insulation, expansion rate of the conductors under various loads, and resistance to thermal shock of the insulation system.

Liquid-filled types: temperature considerations
Using fluid both as an insulating and a cooling medium, liquid-filled transformers have rectangular or cylindrical forms when constructing the windings. Spacers are utilized between the layers of windings to allow the fluid to flow and cool the windings and core. Within the sealed tank that holds both core and coils, the fluid flows through ducts and around coil ends, with the main heat exchange taking place in external elliptical tubes. For transformers rated over 5 MVA, radiators (headers on the top and bottom) are used for additional heat transfer. Modern paper insulation in liquid-filled units allows a 650C average winding temperature rise.

Dry type: temperature considerations
Dry type insulation provides dielectric strength and ability to withstand thermal limits. Temperature rise ratings are typically 1500C, 1150C, and 800C, based on the class of insulation used .

Dry Type Units: Insulation Classes

  • Class H – 2200C (with 300C winding hot spot allowance)
  • Class F – 1850C (with 300C winding hot spot allowance)
  • Class B – 1500C (with 300C winding hot spot allowance)

3. Choice of Winding Material
Transformers use copper or aluminum for windings, with aluminum-wound units typically being more cost-effective. Copper-wound transformers, however, are smaller – copper is a better conductor – and copper contributes to greater mechanical strength of the coil. It is important to work with a manufacturer that has the capability and experience to work with either material to suit your specific requirement.

4. Use of Low-Loss Core Material
Core choice is a crucial consideration, and core losses should be determined properly. Losses that occur in the core are due to hysteresis and eddy currents. High quality magnetic steel should be used so that hysteresis losses are reduced; laminated cores are chosen to minimize eddy current losses.

5. Protection from Harsh Conditions
It is very important that transformer core, coils, leads and accessories are properly protected, especially when used in harsh environments. Liquid-filled transformers should be of sealed-type construction, automatically providing protection for the internal components. For highly corrosive conditions, stainless steel tanks can be employed. Some approaches to building dry-type transformers for harsh environments include cast coil units, cast resin units, and vacuum pressure encapsulated (VPE) units, sometimes using a silicone varnish. Unless the dry-type units are completely sealed, the core/coil and lead assemblies should be periodically cleaned, even in non-harsh environments, to prevent dust and other contaminant buildup over time.

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

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

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

where  is the no-load voltage and   is the full-load voltage.

Poor regulation means that as the load increases, the voltage at the secondary terminals drops substantially.

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

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

 9. Life Expectancy
It is commonly held that the useful life of a transformer is the useful life of the insulation system. Insulation life is directly proportional to the temperatures being experienced by the insulation across operation. Winding temperatures vary, and hot spots at a maximum of 30˚C above average coil winding temperature are usually acceptable for dry-type transformers. Hot spot temperatures are estimated by calculating the sum of the maximum ambient temperature, the average winding temperature rise, and the winding gradient.

 Transformers typically have a ‘nameplate’ kVA rating, and this represents the amount of kVA loading that will result in the rated temperature rise under standard operating conditions. When used in these ‘standard operating conditions’, including the accepted hot-spot temperature with the correct insulation class, a ‘normal’ transformer life expectancy can be estimated.

 10. Overloading
Operating conditions can sometimes necessitate overloading of a transformer; and what this overloading means to the unit, in terms of what it can withstand without developing problems or faults is an important consideration. A primary issue is heat and its dissipation.

 For example, if a transformer is overloaded to a factor of 20% above its rated kVA for a certain period of time, any heat developed in the coils may be easily transferred to the outside of the transformer tank depending on the period of overload. If this heat transfer occurs, then the chances of a fault occurring are small; but there is clearly a time period beyond which the transformer cannot continue to be in the overloaded condition; heat can start to build up internally within the unit and cause serious problems, leading eventually to a fault and a possible power outage. Heat dissipation issues are often addressed with built-in fans, thus augmenting the load capability of the transformer as well.

 11. Insulation Level
The insulation level of a transformer is based on its basic impulse level (BIL). The BIL can vary for a given system voltage, depending upon the amount of exposure to system over voltages a transformer might be expected to encounter over its lifecycle. If the electrical system in question includes solid-state controls, the selection of BIL should be done very carefully. These controls when operating chop the current, and may cause voltage transients.

 12. Shielding
A transformer’s ability to attenuate electrical noise and transients is an important consideration, especially when dealing with particular types of load. The application of a shield between the primary and secondary coils of a distribution transformer is often accomplished when solid state equipment such as computers and peripherals are being served.

 13. Placing Transformers Near the Load
Minimizing the distance between the unit and the principal load is clearly beneficial in several ways – apart from reducing energy loss and voltage drops, it also brings down the cost of secondary cabling. The downside here is that any placement of high-voltage equipment requires very close scrutiny of electrical and fire safety issues. A suitable balance can be achieved by using units that are pre-approved or permitted by insurance companies.

 14. Accessories
An added cost, accessories are installed when required. Examples include stainless steel tanks and cabinets for extra corrosion protection, special paint/finishes for corrosive atmospheres and ultraviolet light, weather shields for outdoor units, protective provisions for humid environments; rodent guards, temperature monitors, space heaters to prevent condensation during prolonged shutdown, optional location of openings for primary and secondary leads, tap changing control apparatus, and more. 

Transformer Faults and Detection

In order to maximize the lifetime and efficacy of a transformer, it is important to be aware of possible faults that may occur and to know how to catch them early. Regular monitoring and maintenance can make it possible to detect new flaws before much damage has been done.

The four main types of transformer faults are:

  1. Arcing, or high current break down
  2. Low energy sparking, or partial discharges
  3. Localized overheating, or hot spots
  4. General overheating due to inadequate cooling or sustained overloading

These faults can all lead to the thermal degradation of the oil and paper insulation within the transformer. One way to detect them is by evaluating the quantities of hydrocarbon gases, hydrogen and oxides of carbon present in the transformer.  Different gases can serve as markers for different types of faults. For instance,

  • Large quantities of hydrogen and acetylene (C2H2) can indicate heavy current arcing. Oxides of carbon may also be found if the arcing involves paper insulation.
  • The presence of hydrogen and lower order hydrocarbons can be a sign of partial discharge
  • Significant amounts of methane and ethane may mean localized heating or hot spots.
  • CO and CO2 may evolve if the paper insulation overheats; which can be a result of prolonged overloading or impaired heat transfer.

Techniques for finding faults:

  • Buchholz Relay safety device
  • Dissolved gas analysis
  • Tests to detect oil contaminants and oil quality

Techniques to detect transformer faults include the Buchholz Relay safety device, dissolved gas analysis (DGA) tests and a range of tests for detecting the presence of contaminants in the oil, as well as for measuring indicators of oil quality such as electric strength and resistivity.

  • Buchholz RelayA Buchholz Relay is also called a gas detection relay.  It is a safety device generally mounted at the middle of the pipe connecting the transformer tank to the conservator. A Buchholz Relay may be used to detect both minor and major faults in the transformer.

    This device functions by detecting the volume of gas produced in the transformer tank.  Minor faults produce gas that accumulates over time within the relay chamber. Once the volume of gas produced exceeds a certain level, the float will lower and close the contact, setting off an alarm.

    Major faults can cause the sudden production of a large quantity of gas.  In this case, the abrupt rise in pressure within the tank will cause oil to flow into the conservator.  Once this is detected the float will lower to close the contact, which causes the circuit breaker to trip or sets off the alarm.

  • Dissolved gas analysis (DGA)Dissolved gas analysis, or DGA, is a test used as a diagnostic and maintenance tool for machinery. Under normal conditions, the dielectric fluid present in a transformer will not decompose at a rapid rate. However, thermal and electrical faults can accelerate the decomposition of dielectric fluid and solid insulation. Gases produced by this process are all of low molecular weight, and include hydrogen, methane, ethane, acetylene, carbon monoxide and carbon dioxide. These gases will dissolve in the dielectric fluid. Analyzing the specific proportions of each gas will help in identifying faults.  Faults detected in such a way may include processes such as corona, sparking, overheating and arcing. Abnormal functioning within a transformer can be caught early by studying the gases that accumulate within it.  If the right countermeasures are taken early on, damage to equipment can be minimized.
  • Other oil tests

    Other oil tests used to detect faults include acidity tests, electric strength tests, fiber estimation tests, color tests, water content tests, Polychlorinated Biphenyl Analysis (PCB) tests, furfuraldehyde analysis tests, metal in oil analysis tests and resistivity tests.

    • Acidity test: The acidity of transformer fluid should be monitored regularly. High acidities can hasten the degradation of paper insulation and cause steel tanks to corrode.
    • Electric Strength: The electric strength of an insulating fluid is its capacity to withstand electrical stress without failing. The lower the dielectric strength of a fluid, the less it will be able to insulate. Transformer failure can result if the dielectric strength drops too low.
    • Fiber estimation: If fibers or other contaminants are present in a transformer’s oil, they may reduce the oil’s electric strength.   Wet fibers in particular can be drawn into an electrical field, resulting in arcing.  Passing polarized light through an oil sample can make fibers and other sediments visible, making it possible to estimate the fiber content of the sample. Sampling should be done carefully, since both fibers and moisture may be picked up during the process of sampling itself.
    • Color: Obvious changes in oil color (for instance, light oil abruptly growing dark) may indicate deeper changes within the oil itself that need to be examined further.
    • PCB Test: A Polychlorinated Biphenyl Analysis (PCB) test calculates the concentration or presence of polychlorinated biphenyl within the oil.  Capillary column chromatography can be used for this process. While the presence of PCBs is not an indication of oil quality, PCBS are a banned substance, no longer allowed in new liquid filled transformers.
    • Metal in oil analysis:  The concentrations of various metals in a transformer’s oil can be calculated by using methods such as atomic absorption spectroscopy (AA) and inductive coupled plasma spectrometry (ICP).
    • Furfuraldehyde Analysis: The concentration of furfuraldehyde in an oil sample can be used as a measure of paper degradation. Furfuraldehyde is one of the byproducts of paper degrading and growing weaker, a process which sets a natural limit on a transformer’s life.  Monitoring its concentration levels can help determine the remaining service life of a transformer.
    • Moisture: Excess moisture in the oil can cause the oil’s electric strength to plummet, leading to transformer failure.  It is therefore very important to monitor moisture levels in the transformer.
    • Resistivity Test: High resistivity indicates low levels of free ions and ion-forming particles, as well as low levels of conductive contaminants. Resistivity tests are generally carried out at ambient temperature. It can also be useful, however, to carry out tests at much higher temperatures, the results of which can be compared to results at ambient temperature.

ONAN or ONAF, What is the difference?

One characteristic of all transformers, regardless of size, style, or construction, is that when energized, they create losses in the circuit. 

Some of these losses are from energizing the core and creating a magnet field, and some losses are resistive losses (I²R) from load currents flowing in the conductors of windings. 

Both types manifest themselves in the form of heat, and heat is the number one enemy of insulation material. 

The task for transformer designers is thus to allow transformers to dissipate excess heat and thereby ensure longer insulation life. 

For air cooled transformers this is accomplished by providing adequate ventilation and cooling ducts in the coils. Where there is not enough air flow, fans are added to increase heat transfer away from magnetic elements and vulnerable dialectic insulating components. 

For liquid filled transformers the approach is similar. Cooling ducts in the coils must be in sufficient number and size to allow dielectric fluid to flow through the coils to remove heat. This fluid can move by simple convection, or it can be “force cooled” by pumping fluid. Additionally, the tank surface must be large enough to transfer heat away from the fluid by a combination of conduction, convection, and radiation. As transformers get larger, tank surface area becomes a constraint, and external radiators are added to increase the surface area for heat transfer. To maximize this process, cooling fans can be added to expedite the heat removal through radiators. 

How do transformer manufacturers indicate information on transformer rating plates?

For dry type transformers which are air cooled, ANSI/IEEE Standard C57.12.01 provide the following designations:

  1. Ventilated self-cooled class : Class AA
  2. Ventilated forced-air-cooled class : Class AFA
  3. Ventilated self-cooled / forced-air-cooled class : Class AA/FA
  4. Non-Ventilated self-cooled class : Class ANV
  5. Sealed –self-cooled class : Class GA

Liquid filled transformers offer a few more options for cooling. ANSI/IEE Standard C57.12.00 defines a 4 digit code to describe the cooling attributes of the transformer. 

The first letter designates the internal cooling medium in contact with the windings.

  • O= mineral oil or synthetic insulation fluid with a fire point ≤ 300°C
  • K = insulating fluid with a fire point > 300°C
  • L = insulating liquid with no me3asurable fire point.

 The second letter designates the circulation mechanism for internal cooling medium

  • N = Natural convection flow through cooling equipment and in windings
  • F = Forced circulation through cooling equipment and natural convention flow in the windings (also called “directed flow”)
  • D = Forced circulation through cooling equipment, directed from the cooling equipment into at least the main windings

 The third letter designates external cooling medium

  • A = Air
  • W = Water

 The fourth letter designates the circulation mechanism for the external cooling medium.

  • N = Natural convection
  • F = Forced circulation (Fans (air cooling) , pumps (water cooling))

 For example: ONAN designates an oil filled unit that has natural convection flow in the tank and utilizes natural air convection cooling externally.

 If this transformer has fans added for forced air externally, the designation would be ONAF.

 A transformer that has natural convection cooling as a base rating and an elevated rating when fans were added later, would be designated as ONAN/ONAF.

 High fire point fluids use the designation of “K” for fluid type. Thus a naturally cooled high fire point fluid would be KNAN and the same unit with fans would be KNAF.

Transformer Protection

Transformers of varied sizes and configurations are at the heart of all power systems. As a critical and an expensive component of the power systems, transformers play an important role in power delivery and the integrity of the power system network as a whole. Transformers, however, have operating limits beyond which the transformer loss of life can occur. If subjected to adverse conditions there can be a heavy damage to the system and system equipment, besides intolerable interruption of service to the customers. Since the lead time for repair and replacement of transformers is usually very long, limiting the damage to faulted transformers is the foremost objective of transformer protection.

 Economic impact of a transformer failure

  • The direct economic impact of repairing or replacing the transformer.
  • The indirect economic impact due to production loss.

Operating conditions like transformer overload, through faults, etc often result in transformer failure, highlighting a need for transformer protection functions, such as over excitation protection and temperature-based protection. Extended functioning of the transformer under abnormal condition such as faults or overloads can compromise the life of the transformer. Adequate protection should be provided for quicker isolation of the transformer under such conditions. The type of protection used should reduce the disconnection time for faults within the transformer and minimize the risk of catastrophic breakdown to simplify eventual repair.

 Transformer Failure

 The risk of a transformer failure is two-dimensional: the frequency of failure, and the severity of failure. Most often transformer failures are a result of “insulation failure“. This category includes inadequate or defective installation, insulation deterioration, and short circuits, as opposed to exterior surges such as lightning and line faults.

 Failures in transformers can be classified into

  • Winding failures resulting from short circuits (turn-turn faults, phase-phase faults, phase-ground, open winding)
  • Core faults (core insulation failure, shorted laminations)
  • Terminal failures (open leads, loose connections, short circuits)
  • On-load tap changer failures (mechanical, electrical, short circuit, overheating)
  • Abnormal operating conditions (overfluxing, overloading, overvoltage)
  • External faults

 

Other causes of transformer failure may include,

 Overloading - Transformers that experience a sustained loading that exceeds the nameplate capacity often face failure due to overloading.

 Line Surge - Failure caused by switching surges, voltage spikes, line faults/flashovers, and other T&D abnormalities suggests that more attention should be given to surge protection, or the adequacy of coil clamping and short circuit strength.

 Loose Connections - Loose connections, improper mating of dissimilar metals, improper torquing of bolted connections etc can also lead to failures in transformers.

 Oil Contamination - Oil contamination resulting in sludging, carbon tracking and humidity in the oil can often result in transformer failure.

 Design/Manufacturing Errors – This includes conditions such as: loose or unsupported leads, loose blocking, poor brazing, inadequate core insulation, inferior short circuit strength, and foreign objects left in the tank.

 Improper Maintenance/Operation - Inadequate or improper maintenance and operation are a major cause of transformer failures. It includes disconnected or improperly set controls, loss of coolant, accumulation of dirt & oil, and corrosion.

 External Factors – Several external factors like floods, fire explosions, lightening and moisture can be established as the causes of the failure as well.

 Transformers Protection Best Practices

 Transformer failures and safety hazards can be avoided or minimized by ensuring that the conductors and equipment are properly sized, protected and adequately grounded. Incorrect installation of transformers can result in fires from improper protection, as well as electric shock from inadequate grounding.

  • Once the transformer is placed, the tank must be permanently grounded with a correctly sized and properly installed permanent ground.
  • Access should be restricted to the transformer liquid-filled compartment in conditions of excessive humidity or rain.
    • Dry air should be continuously pumped into the gas space if humidity exceeds 70%.
    • Transformer should be given protection against rain such that no water gets inside.
  • All equipment used in the handling of the fluid (hoses, pumps, etc.) should be clean and dry. If the insulating liquid for inspection is drawn out, its level should not go below the top of windings.
  • Sufficient gas pressure must be maintained to allow a positive pressure of 1 psi to 2 psi at all times (even at low ambient temperature) when liquid-filled transformers are stored outside.
  • Final inspection of the transformer is essential before it is energized. All electrical connections, bushings, draw lead connections should be checked.
  • Upon loading the transformer should be kept under observation during the first few hours of operation. All temperatures and pressures should be checked in the transformer tank during the first week of operation.
  • Surge arresters must be installed and connected to the transformer bushing / terminals with the shortest possible leads to protect the equipment from line switching surges and lightning.

 

Electrical Substation components

A substation is a high-voltage electric facility containing equipment to regulate and distribute electrical energy. While some substations are small with little more than a transformer and associated switches, other substations are large and complex.

Functions of a substation include receiving power from a generating facility, regulating distribution, stepping voltage up and down, limiting power surges, and converting power from direct current to alternating current or vice versa.

Components in an electric substation

Many electrical components work together in a substation to carry out its functions, these include

Lightning Arresters – protect a substation from voltage surges and are installed on power poles, towers, transformers and circuit breakers to protect them from damage during electrical storms. Lightning Arresters look similar to standoff insulators and bushings, but their unique characteristics is that they have earthing terminals at the bottom where a large ground cable is connected and runs down the structure that connects to the station ground.

Switches – measure, regulate, and switch electrical transmissions within the substation as necessary. Switchers turn circuits on and off the grid.

Distribution Bus – is an array of switches that direct power out of the substation. Distribution buses are usually pyramid-shaped or rectangular.

Circuit Breakers – there are two forms of open circuit breakers, namely, dead tank and live tank. The form of circuit breaker influences the way in which the circuit breaker is accommodated, this may be as a ground mounting and plinth mounting, retractable circuit breaker and suspended circuit breakers.

Current Transformers – may be accommodated in one of six manners, namely

*Installed over circuit breaker bushings or on pedestals
*In separate post type housings
*Installed over moving bushings of some types of insulators
*Installed over power transformer or reactor bushings
*Installed over wall or roof bushings
*Installed over cables
 
In all except in separate post type housing, the current transformer occupies incidental space and does not affect the size of the layout. Installation of current transformers over isolator bushings, or bushings through walls or roofs, is usually confined to indoor substations.

Isolators – are essentially off load devices although they are capable of dealing with small charging currents of busbars and connections. The design of isolators is closely related to the design of substations. Isolator design is considered in the following aspects, namely space factor, insulation security, standardisation, ease of maintenance and cost.

Some types of isolators include horizontal isolation, vertical isolation and moving bushing.

Conductor Systems – The most suitable material for a conductor system is copper or aluminium. Steel may be used but has limitations due to poor conductivity and high susceptibility to corrosion. An ideal conductor may be flat surfaced, stranded or tubular.

An ideal conductor should fulfil the following requirements:

*Capable of carrying specified load currents and short time currents
*Able to withstand forces on it due to its situation. These forces comprise self weight, and weight of other conductors and equipment, short circuit forces and atmospheric forces such as wind and ice loading
*Corona free at rated voltage
*Have minimum number of joints
*Need minimum number of supporting insulators
*Be cost effective

Insulation – insulation security is of high importance in a well designed substation. Extensive research is done on improving flashover characteristics. Increased creepage length, resistance glazing, insulation greasing and line washing have been used with varying degrees of success.

A standoff insulator is required to keep high voltage overhead conductors in position and at a certain distance from conductors in other phases or neighbouring equipment. It also insulates between a conductor and ground. An insulator is always mounted on an earthed support and contains a porcelain section that is mounted between a base plate and a top mounting plate. The base plate is fixed on the grounded support and the top mounting plate is equipped with bus support hardware, on which the overhead conductor is clamped.

Power Transformers – Transformers are large, box-shaped structures connected to multiple wires and are usually the largest single item in a substation. Transformers are usually located on one side of a substation, and the connection to switchgear is by bare conductors. Because of the large quantity of oil, it is essential to take precaution against fire hazards. Hence, a transformer is usually located around a sump used to collect excess oil.

Power from a generating station is sent at a much higher voltage than required for home appliances. Step-down transformers decrease voltage of transmission lines en route to neighbourhoods. Auto transformers can offer advantage of smaller physical size and reduced losses.

Overhead Line Terminations – there are two methods used to terminate overhead lines at a substation, namely, tensioning conductors to substation structures or buildings and tensioning conductors to ground winches. The choice is influenced by the height of towers and the proximity to the substation.

Bushings – This is the component that allows electricity to enter electrical equipments safely, preventing it from shorting to another phase. There are different types of bushings, namely oil filled, gas filled and dry solid porcelain. Unique characteristics of bushings are that the porcelain section is between an oil expansion chamber and a mounting flange.

Buchholz Relay

A Buchholz relay is a gas and oil operated device installed in the pipework between the top of the transformer main tank and the conservator.  A second relay is sometimes used for the tapchanger selector chamber.  The function of the relay is to detect an abnormal condition within the tank and send an alarm or trip signal.  Under normal conditions the relay is completely full of oil.  Operation occurs when floats are displaced by an accumulation of gas, or a flap is moved by a surge of oil.  Almost all large oil-filled transformers are equipped with a Buchholz relay, first developed by Max Buchholz in 1921.

General Arrangement

A – Gas Collector Chamber

 

B – Upper Float
C – Lower Float
D – Oil Surge Detector 

 

Conditions Detected
A Buchholz relay will detect:

 *Gas produced within the transformer
 *An oil surge from the tank to the conservator
 *A complete loss of oil from the conservator (very low oil level)

Fault conditions within a transformer produce gases such as carbon monoxide, hydrogen and a range of hydrocarbons .  A small fault produces a small volume of gas that is deliberately trapped in the gas collection chamber (A) built into the relay.  Typically, as the oil is displaced a float (B) falls and a switch operates – normally to send an alarm.  A large fault produces a large volume of gas which drives a surge of oil towards the conservator.  This surge moves a flap (D) in the relay to operate a switch and send a trip signal.  A severe reduction in the oil level will also result in a float falling.  Where two floats are available these are normally arranged in two stages, alarm (B) followed by trip (C).

 Gas and Oil Flows

Buchholz relays are equipped with a number of gas and oil inputs and outputs, including test and sampling facilities.

 

 

 

 

 

 

 

Gas sampling – a graduated sight glass provides an indication of the volume of gas that has accumulated, typically 100-400cm3.  After an alarm or trip signal has been received this must be collected and analysed before the transformer is returned to service.  Gas collection can be done at the relay, or at ground level if suitable arrangements exist.  Clearly the latter is a safer and more convenient option.

Functional Tests – a test petcock enables dry air to be admitted into the relay to check correct operation.  A trickle of air is equivalent to a gradual accumulation of gas.  A blast simulates an oil surge.  These tests are sometimes referred to as ‘blowing the Buchholz’.  On completion it is important that the relay is bled to remove the air that has been introduced.

Draining – a valve in the bottom of the relay enables an oil sample to be taken or the relay to be drained.  As with gas sampling, this facility can be brought down to ground level for enhanced operator safety and convenience.

 

3 Phase Transformer

Single Phase vs. Three Phase Power Systems

Single-phase meaning (2) power lines as an input source; therefore, only (1) primary and (1)secondary winding is required to accomplish the voltage transformation. However, most power is distributed in the form of three-phase A.C. Therefore, before proceeding any further you should understand what is meant by three-phase power. Basically, the power company generators produce electricity by rotating (3) coils or windings through a magnetic field within the generator . These coils or windings are spaced120 degrees apart. As they rotate through the magnetic field they generate power which is then sent out on three (3) lines as in three-phase power. Three-Phase transformers must have (3) coils or windings connected in the proper sequence in order to match the incoming power and therefore transform the power company voltage to the level of voltage we need and maintain the proper phasing or polarity. 
Three phase electricity powers large industrial loads more efficiently than single-phase electricity. When single-phase electricity is needed, It is available between any two phases of a three-phase system, or in some systems , between one of the phases and ground. By the use of three conductors a three-phase system can provide 173% more power than the two conductors of a single-phase system. Three-phase power allows heavy duty industrial equipment to operate more smoothly and efficiently. Three-phase power can be transmitted over long distances with smaller conductor size. 

In a three-phase transformer, there is a three-legged iron core as shown below. Each leg has a respective primary and secondary winding.The three primary windings (P1, P2, P3) will be connected at the factory to provide the proper sequence (or correct polarity) required and will be in a configuration known as Delta. The three secondary windings (S1, S2, S3) will also be connected at the factory to provide the proper sequence (or correct polarity) required. However, the secondary windings, depending on our voltage requirements, will be in either ?Delta? or a ?Wye? configuration.

Delta and Wye Connections
In a three-phase transformer, there is a three-legged iron core as shown below. Each leg has a respective primary and secondary winding.
 
 
Winding Combination
 
As can be seen, the three-phase transformer actually has 6 windings (or coils) 3 primary and 3 secondary. These 6 windings will be pre-connected at the factory in one of two configurations:Configuration 1. Three primary Windings in Delta and Three Secondary Windings in Wye .
 
Note: These are the designations which are marked on the leads or terminal boards provided for customer connections and they will be located in the transformer wiring compartment.
In both single and three-phase transformers, the high voltage terminals are designated with an “h” and the low voltage with an “X”
 

Configuration 2. Three Primary Windings in Delta and Three Secondary Windings in Delta.

Note: These are the designations which are marked on the leads or terminal boards provided for the customer connections and they will be located in the transforming wiring compartment.
In both single and three-phase transformers, the high voltage terminals are designated with an “H” and the low voltage with an “X”.