Power Transformer

Power Transformer INTRODUCTION Transformer is a vital link in a power system which has made possible the power generated at low voltages (6600 to 22000 volts) to be stepped up to extra high voltages for transmission over long distances and then transformed to low voltages for utilization at proper load centers. With this tool in hands it has become possible to harness the energy resources at far off places from the load centers and connect the same through long extra high voltage transmission lines working on high efficiencies. At that, it may be said to be the simplest equipment with no motive parts. Nevertheless it has its own problems associated with insulation, dimensions and weights because of demands for ever rising voltages and capacities. In its simplest form a Transformer consists of a laminated iron core about which are wound two or more sets of windings. Voltage is applied to one set of windings, called the primary, which builds up a magnetic flux through the iron. This flux induces a counter electromotive force in the primary winding thereby limiting the current drawn from the supply. This is called the no load current and consists of two componentsone in phase with the voltage which accounts for the iron losses due to eddy currents and hysteresis, and the other 90° behind the voltage which magnetizes the core. This flux induces an electro-motive force in the secondary winding too. When load is connected across this winding, current flows in the secondary circuit. This produces a demagnetising effect, to counter balance this the primary winding draws more current from the supply so that IP.NP = IS.NS Where Ip and Np are the current and number of turns in the primary while IS and NS are the current and number of turns in the secondary respectively. The ratio of turns in the primary and secondary windings depends on the ratio of voltages on the Primary and secondary sides. The magnetic core is built up of laminations of high grade silicon or other sheet steel which are insulated from each other by varnish or through a coating of iron oxide. The core can be constructed in different ways relative to the windings.

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CONSTRUCTION 1- Transformer Core Construction in which the iron circuit is surrounded by windings and forms a low reluctance path for the magnetic flux set up by the voltage impressed on the primary. Fig (1), Fig. (6) and Fig. (7) Shows the core type

Fig (1) core type The core of shell type is sh own Fig.(2), Fig.(3), Fig.(4), and Fig.(5), in which The winding is surrounded by the iron Circuit Consisting of two or more paths through which the flux divides. This arrangement affords somewhat Better protection to coils under short circuit conditions.

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In actual construction there are Variations from This simple construction but these can be designed With such proportions as to give similar electrical characteristics.

Fig (2) shell type

Fig.(3) Single phase Transformer Fig. (4) Single phase Transformer .

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Fig. (5) 3- phase Transformer Shell type

Fig. (6) 3- phase Transformer core type

Fig. (7) Cross section of a three-phase Distribution Transformer (Core Type) Three-phase Transformers usually employ three-leg core. Where Transformers to be transported by rail are large capacity, five-leg core is used to curtail them to within the height limitation for transport. Even among thermal/nuclear power station Transformers, which are usually transported by ship and freed from restrictions on in-land transport, gigantic

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Transformers of the 1000 MVA class employ five-leg core to prevent leakage flux, minimize vibration, increase tank strength, and effectively use space inside the tank. Regarding single-phase Transformers, two-leg core is well known. Practically, however, three leg cores is used, four-leg core and five-leg core are used in large capacity Transformers. The sectional areas of the yoke and side leg are 50 % of that of the main leg; thus, the core height can be reduced to a large extent compared with the two leg core. For core material, high-grade, grain oriented silicon steel strip is used. Connected by a core leg tie plate fore and hind clamps by connecting bars. As a result, the core is so constructed that the actual silicon strip is held in a sturdy frame consisting of clamps and tie plates, which resists both mechanical force during hoisting the core-and-coil assembly and short circuits, keeping the silicon steel strip protected from such force. In large-capacity Transformers, which are likely to invite increased leakage flux, nonmagnetic steel is used or slits are provided in steel members to reduce the width for preventing stray loss from increasing on metal parts used to clamp the core and for preventing local overheat. The core interior is provided with many cooling oil ducts parallel to the lamination to which a part of the oil flow forced by an oil pump is introduced to achieve forced cooling. When erecting a core after assembling, a special device shown in Fig. (8) Is used so that no strain due to bending or slip is produced on the silicon steel plate.

Fig (8)

Fig (9) The steel strip surface is subjected to inorganic insulation treatment. All cores employ miter-joint core construction. Yokes are jointed at an angle of 45° to utilize the magnetic flux directional characteristic of steel strip. A computer-controlled automatic machine cuts grain-oriented silicon steel strip with high accuracy and free of burrs, so that magnetic characteristics of the grain-oriented silicon steel remains unimpaired. Silicon steel strips are stacked in a circle-section. Each core leg is fitted with tie plates

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on its front and rear side, with resin-impregnated glass tape wound around the outer circumference. Sturdy clamps applied to front and rear side of the upper and lower yokes are bound together with glass tape. And then, the resin undergoes heating for hardening to tighten the band so that the core is evenly clamped Fig. (9). Also, upper and lower clamps are connected by a core leg tie plate; fore and hind clamps by connecting bars. As a result, the core is so constructed that the actual silicon strip is held in a sturdy frame consisting of clamps and tie plates, which resists both mechanical force during hoisting the core-and-coil assembly and short circuits, keeping the silicon steel strip protected from such force. In large-capacity Transformers, which are likely to invite increased leakage flux, nonmagnetic steel is used or slits are provided in steel members to reduce the width for preventing stray loss from increasing on metal parts used to clamp the core and for preventing local overheat. The core interior is provided with many cooling oil ducts parallel to the lamination to which a part of the oil flow forced by an oil pump is introduced to achieve forced cooling. When erecting a core after assembling, a special device shown in Fig. (8) Is used so that no strain due to bending or slip is produced on the silicon steel plate. 2 - Winding Various windings are used as shown below. According to the purpose of use, the optimum winding is selected so as to utilize their individual features. 1 - Helical Disk Winding (Interleaved disk winding) In Helical disk winding, electrically isolated turns are brought in contact with each other as shown in Fig. (10) Thus, this type of winding is also termed "interleaved disk winding." Since conductors 1 - 4 and conductors 9 - 12 assume a shape similar to a wound capacitor, it is known that these conductors have very large capacitance. This capacitance acts as series capacitance of the winding to highly improve the voltage distribution for surge. Unlike cylindrical windings, Helical disk winding requires no shield on the winding outermost side, resulting in smaller coil outside diameter and thus reducing Transformer dimension. Comparatively small in winding width and large in space between windings, the construction of this type of winding is appropriate for the winding, which faces to an inner winding of relatively high voltage. Thus, general EHV or UHV substation Transformers employ Helical disk winding to utilize its features mentioned above. 2 - Continuous Disk Winding This is the most general type applicable to windings of a wide range of voltage and current Fig. (11). this type is applied to windings ranging from BI L of 350kV to BI L of 1550kV. Rectangular wire is used where current is relatively small, while transposed cable Fig. (12) is applied to large current. When voltage is relatively low, a Transformer of 100MVA

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or more capacity handles a large current exceeding 1000A. In this case, the advantage of transposed cable may be fully utilized.

Fig. (10)

Fig. (11). Continuous Disk Winding

Fig. (12) Transposed conductor construction Diagram Further, since the number of turns is reduced, even conventional continuous disk construction is satisfactory in voltage distribution, thereby ensuring adequate dielectric characteristics. Also, whenever necessary, potential distribution is improved by inserting a shield between turns. 3 - Helical windings For windings of low voltage (20kV or below) and large current, a helical coil is used which consists of a large number of parallel conductors piled in the radial Direction and wound. Adequate transposition is necessary to equalize the share of current among these parallel conductors. Fig (12) illustrates the transposing procedure for double helical coil. Each conductor is transposed at intervals of a fixed number of turns in the order shown in the figure, and as a result the location of each conductor opposed to the high

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voltage winding is equalized from the view point of magnetic field between the start and the end of winding turn.

Fig. (13) double helical coil 3 - Tank. The tank has two main parts: a –The tank is manufactured by forming and welding steel plate to be used as a container for holding the core and coil assembly together with insulating oil. The base and the shroud, over which a cover is sometimes bolted. These parts are manufactured in steel plates assembled together via weld beads. The tank is provided internally with devices usually made of wood for fixing the magnetic circuit and the windings. In addition, the tank is designed to withstand a total vacuum during the treatment process. Sealing between the base and shroud is provided by weld beads. The other openings are sealed with oil-resistant synthetic rubber joints, whose compression is limited by steel stops. Finally the tank is designed to withstand the application of the internal overpressure specified, without permanent deformation.

Fig (14) Power Transformer 30 MVA 132 / 11 KV

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b - Conservator The tank is equipped with an expansion reservoir (conservator) which allows for the expansion of the oil during operation. The conservator is designed to hold a total vacuum and may be equipped with a rubber membrane preventing direct contact between the oil and the air.

Fig. (15)

Fig. (16) 4 - Handling devices: Various parts of the tank are provided with the following arrangements for handling the Transformer. - Four locations (under the base) intended to accommodate bidirectional roller boxes for displacement on rails. - Four pull rings (on two sides of the base) - Four jacking pads (under the base) - Tank Earthing terminals: The tank is provided with Earthing terminals for Earthing the various metal parts of the Transformer at one point. The magnetic circuit is earthed via a special external terminal. 5 - Valves: The Transformers are provided with sealed valves, sealing joints, locking devices and position indicators. The Transformers usually include: 163

- Two isolating valves for the "Buchholz" relay. - One drainage and filtering valve located below the tank. - One isolating valve per radiator or per cooler. - One conservator drainage and filtering valve. And when there is an on-load adjuster: - Two isolating valves for the protection relay. - One refilling valve for the on-load tap-changer. - One drain plug for the tap-changer compartment. 6 - Connection Systems Mostly Transformers have top-mounted HV and LV bushings according to DIN or IEC in their standard version. Besides the open bushing arrangement for direct Connection of bare or insulated wires, three basic insulated termination systems is available. Fully enclosed terminal box for cables Fig. (17&18) Available for either HV or LV side, or for both. Horizontally split design in degree of protection IP 44 or IP 54. (Totally enclosed and fully protected against contact's With live parts, plus protection against drip, splash, or spray water.) Cable installation through split cable glands and removable plates facing diagonally downwards. Optional conduit hubs suitable for single-core or three-phase cables with solid dielectric insulation, with or without stress cones. Multiple cables per phase are terminated on auxiliary bus structures attached to the bushings removal of Transformer by simply bending back the cables.

Fig. (17)

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Fig. (18) HV Side 300 KV

Fig. (19) LV Side (11KV) connection terminal 3-cable for each phase 7 - The dehydrating breather The dehydrating breather is provided at the entrance of the conservator of oil immersed equipment such as Transformers and reactors. The conservator governs the breathing action of the oil system on forming to the temperature change of the equipment, and the dehydrating breather removes the moisture and dust in the air inhaled and prevents the deterioration of the Transformer oil due to moisture absorption. Construction and Operation See Fig. (20) The dehydrating breather uses silica - gel as the desiccating Agent and is provided with an oil pot at the bottom to filtrate the inhaled air. The specifications of the dehydrating breather are shown in Table (1) and the operation of the component parts in Table (2).

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Fig. (20) Dehydrating breather 166

1. Case 2. Peep window 3. Flange 4. Oil pot 5. Oil pot holder 6. Breathing pipe 7.Filter 8. silica-gel 9.Absorbent 10. Oil (Transformer oil) 11. Wing nut 12.Cover 13. Suppression screw 14. Set screw 15. Oil level line (Red

Table - 1 Type

Weight of desiccating agent

FP4.5A

4.5 kg

Desiccating agent

Material --- Silica-gel (Main component SiO2) Shape, Size --- spherical, approx. Ø4 – Ø5 Mixed ratio --- white silica-gel 75% blue silica-gel 25%

Table - 2 Item Silica-gel Blue silica-gel

Oil pot

Oil and filter

absorbent

Action Removes moisture in the air inhaled by the Transformer Or reactor. In addition to the removal of moisture, indicates the Extent of moisture absorption by discoloration. (Dry condition) (Wet condition ) Blue ------ Light purple ----- Light pink Removes moisture and dust in the air inhaled by: the Transformer or reactor. In addition, while it is not performing breathing action, it seals the desiccating agent from the outer air to prevent unnecessary moisture Absorption of the desiccating agent. Absorbs dust and deteriorated matter in the oil pot, to Maintain the oil pot in a good operating condition.

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Bushing Having manufactured various types of bushings ranging from 6kV-class to 800kVclass, Toshiba has accumulated many years of splendid actual results in their operation. Plain-type Bushing Applicable to 24 kV-classes or below, this type of bushing is available in a standard series up to 25,000A rated current. Consisting of a single porcelain tube through which passes a central conductor, this bushing is of simplified construction and small mounting dimensions; especially, this type proves to be advantageous when used as an opening of equipment to be placed in a bus duct Fig. (21).

Fig. (21) 24 KV Bushing Oil-impregnated, Paper-insulated Condenser Bushing

Fig. (22) 800 KV bushing The oil-impregnated, paper insulated condenser bushing, mainly consisting of a condenser cone of oil-impregnated insulating paper, is used

For high-voltage application (Fig. 22&23). This bushing, of enclosed construction, offers the Following features: • High reliability and easy maintenance.

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• Partial discharge free at test voltage. • Provided with test tapping for measuring electrostatic capacity and tan δ. • Provided with voltage tapping for connecting an instrument Transformer if required.

Fig. (23) Bushing type GOEK 1425 for direct connection of 420 KV Power Transformer to gas insulated Switchgear or high voltage cable

Fig. (24) Cut away view of Transformer bushing type GOE Construction of Cable Connection and GIS Connection Cable Connection In urban-district substations connected with power cables and thermal power stations suffered from salt-pollution, cable direct-coupled construction is used in which a Transformer is direct-coupled with the power cable in an oil chamber. Indirect connection system in which, with a cable connecting chamber attached to the Transformer tank, a coil terminal is connected to the cable head through an oil-oil bushing in the cable connection chamber. Construction of the connection chamber can be divided into sections. Cable connections and oil filling can be separately performed upon completion of the tank assembling.

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Fig. (26) Indirect Cable Connection GIS (Gas Insulated Switchgear) Connection There is an increasing demand for GIS in substations from the standpoint of site-acquisition difficulties and environmental harmony. In keeping with this tendency, GIS connection-type Transformers are ever-increasing in their applications. The SF6 gas bus is connected directly with the Transformer coil terminal through an oil-gas bushing. Oil-gas bushing support is composed of a Transformer-side flange and an SF6 gas bus-side flange, permitting the oil side and the gas side to be completely separated from each other.

Fig. (27) Direct GIS Connection

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Buchholz Relays The following protective devices are used so that, upon a fault development inside a Transformer, an alarm is set off or the Transformer is disconnected from the circuit. In the event of a fault, oil or insulations decomposes by heat, producing gas or developing an impulse oil flow. To detect these phenomena, a Buchholz relay is installed. Buchholz Relay The Buchholz relay is installed at the middle of the connection pipe between the Transformer tank and the conservator. There are a 1st stage contact and a 2nd stage contact as shown in Fig. (28). the 1st stage contact is used to detect minor faults. When gas produced in the tank due to a minor fault surfaces to accumulate in the relay chamber within a certain amount (0.3Q-0.35Q) or above, the float lowers and closes the contact, thereby actuating the alarm device.

Fig. (28). Buchholz Relay

The 2nd stage contact is used to detect major faults. In the event of a major fault, abrupt gas production causes pressure in the tank to flow oil into the conservator. In 171

this case, the float is lowered to close the contact, thereby causing the Circuit Breaker to trip or actuating the alarm device. Temperature Measuring Device Liquid Temperature Indicator (like BM SERIES Type) is used to measure oil temperature as a standard practice. With its temperature detector installed on the tank cover and with its indicating part installed at any position easy to observe on the front of the Transformer, the dial temperature detector is used to measure maximum oil temperature. The indicating part, provided with an alarm contact and a maximum temperature pointer, is of airtight construction with moisture absorbent contained therein; thus, there is no possibility of the glass interior collecting moisture whereby it would be difficult to observe the indicator Fig. (30&31). Further, during remote measurement and recording of the oil temperatures, on request a search coil can be installed which is fine copper wire wound on a bobbin used to measure temperature through changes in its resistance. Winding Temperature Indicator Relay (BM SERIES) The winding temperature indicator relay is a conventional oil temperature indicator supplemented with an electrical heating element. The relay measures the temperature of the hottest part of the Transformer winding. If specified, the relay can be fitted with a precision potentiometer with the same characteristics as the search coil for remote indication.

Fig. (29) Construction of Winding Temperature Indicator Relay

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Fig (30) Oil Temperature Indicator

Fig. (31) Winding Temperature Indicator The temperature sensing system is filled with a liquid, which changes in volume with varying temperature. The sensing bulb placed in a thermometer well in the Transformer tank cover senses the maximum oil temperature. The heating elements with a matching resistance is fed with current from the Transformer associated with the loaded winding of the Transformer and compensate the indicator so that a temperature increase of the heating element is thereby proportional to a temperature increase of the winding-over-the maximum- oil temperature. Therefore, the measuring bellows react to both the temperature increase of the winding-over-the-maximum-oil temperature and maximum oil temperature. In this way the instrument indicates the temperature in the hottest part of the Transformer winding. The matching resistance of the heating element is preset at the factory.

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Pressure Relief Device When the gauge pressure in the tank reaches abnormally To 0.35-0.7 kg/cm.sq. The pressure relief device starts automatically to discharge the oil. When the pressure in the tank has dropped beyond the limit through discharging, the device is automatically reset to prevent more oil than required from being discharged.

Fig. (32) Pressure Relief Device Cooling System METHODS OF COOLING The kinds of cooling medium and their symbols adopted by I.S. 2026 (Part 11)-1977 are: (a) Mineral oil or equivalent flammable insulating liquid O (b) Non flammable synthetic insulating liquid L (c) Gas G (d) Water W

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(e) Air A The kids of circulation for the cooling medium and their symbols are: (a) Natural N (b) Forced (Oil not directed) F (c) Forced (Oil directed) D Each cooling method of Transformer is identified by four symbols. The first letter represents the kind of cooling medium in contact with winding, the second letter represents the kind of circulation for the cooling medium, the third letter represents the cooling medium that is in contact with the external cooling system and fourth symbol represents the kind of circulation for the external medium. Thus oil immersed Transformer with natural oil circulation and forced air external cooling is designated ONAF. For oil immersed Transformers the cooling systems normally adopted are: 1- Oil Immersed Natural cooled – Type ONAN. Fig. (33 & 34) In this case the core and winding assembly is immersed in oil. Cooling is obtained by the circulation of oil under natural thermal head only. In large Transformers the surface area of the tank alone is not adequate for dissipation of the heat produced by the losses. Additional surface is obtained with the provision of radiators. 2. Oil Immersed Air Blast - Type ONAF Fig. (35 & 36) In this case circulation of air is obtained by fans. It becomes possible to reduce the size of the Transformer for the same rating and consequently save in cost.

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Fig. (33) Oil Immersed Natural cooled ONAN

Fig. (34) Oil Immersed Natural cooled ONAN

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Fig. (35) Oil Immersed Air Blast - Type ONAF

Fig. (36) Oil Immersed Air Blast - Type ONAF 3. Oil Immersed Water Cooled - Type ONWN In this case internal cooling coil is employed through which the water is allowed to flow. Apparently this system of cooling assumes free supply of water. Except at hydropower stations this would off-set the saving in cost when special means have to be provided for adequate supply of water. The circulation of oil is only by convection currents. This type of cooling was employed in older designs but has been almost abandoned in favor of the Type OFWF discussed later. 4. Forced Oil Air Blast Cooled - Type OFAF Fig. (37) In this system of cooling also circulation of oil is forced by a pump. In addition fans are added to radiators for forced blast of air. 5. Forced Oil Natural Air Cooled - Type OFAN Fig. (38) In this method of cooling, pump is employed in the oil circuit for better circulation of oil.

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Fig. (37) Forced-oil, Forced-air-cooled - Type OFAF

Fig. (38) Forced Oil Natural Air Cooled - Type OFAN 6. Forced Oil Water Cooled - Type OFWF In this type of cooling a pump is added in the oil circuit for forced circulation of oil, through a separate heat exchanger in which water is allowed to flow. 7. Forced Directed Oil and Forced Air Cooling -ODAF. 178

It should be remembered that Transformers cooling type OFAF and OFWF will not carry any load if air and water supply respectively is removed. It is quite common to select Transformers with two systems of Cooling e.g., ONAN/ONAF or ONAN/OFAF or sometimes three systems e.g., ONAN/ONAF/ OFAF. These determine the type of cooling upto certain loading. As soon as the load exceeds a preset value, the fans/pumps are Switched on. The rating of a Transformer with ONAN/ONAF cooling may be written, say, as 45/60 MVA. This means that so long as the load is below 45 MVA, the fans will not be working. These are Switched on automatically when the load on the Transformer exceeds 45 MVA. Type of cooling has a bearing on the cost of the Transformer. It shall be appreciated that the ONAN cooling has the advantage of being the simplest with no. fans or pumps and hence no auxiliary motors. On smaller units say up to 10 MVA, saving in price in changing from ONAN cooling to other forms of cooling is negligible. On bigger units not only there is a saving in price but also the reduced weights and dimensions, with other systems of cooling of Transformers, render the transport easy and decrease the cost of Foundations etc. Site conditions sometimes influence the preferred cooling arrangement. For example the advantage of reduced price, dimensions and weight in case of type OFWF can be fully realised only where water supply is readily available. Where special arrangements have to be made for water supply and disposal of the water, the installation costs for OFWF Transformers may increase. INSULATING OIL (SPECIFICATIONS AND DEHYDRATION AT SITE) In Transformers, the insulating oil provides an insulation medium as well as a heat transferring medium that carries away heat produced in the windings and iron core. Since the electric strength and the life of a Transformer depend chiefly upon the quality of the insulating oil, it is very important to use a high quality insulating oil. The insulating oil used for Transformers should generally meet the following requirements: (a) Provide a high electric strength. (b) Permit good transfer of heat. (c) Have low specific gravity-In oil of low specific gravity particles which have become suspended in the oil will settle down on the bottom of the tank more readily and at a faster rate, a property aiding the oil in retaining its homogeneity. (d) Have a low viscosity- Oil with low viscosity, i.e., having greater fluidity, will cool Transformers at a much better rate. (e) Have low pour point- Oil with low pour point will cease to flow only at low temperatures. (f) Have a high flash point. The flash point characterizes its tendency to evaporate. The lower the flash point

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the greater the oil will tend to vaporize. When oil vaporizes, it loses in volume, its viscosity rises, and an explosive mixture may be formed with the air above the oil. (g) Not attack insulating materials and structural materials. (h) Have chemical stability to ensure life long service. Various national and international specifications have been issued on insulating oils for Transformers to meet the above requirements. The specifications for insulating oil stipulated in Indian Standard 335: 1983 are given below. 1 2 3 4 5 6

7

8 9

10

11 12

characteristic Appearance Density at 29.5°C, Max Interfacial tension at 270°C, Min. Flash point Min. Pour Point Max. Corrosive Sulphur (in terms of classification of copper strip). Electric strength (breakdown voltage) Min. (a) New unfiltered oil (b) After filtration Dielectric dissipation factor (tan δ) at 90 °C Max. Specific resistance (resistivity): (a) At 9 0 °C Min. (b) at 2 7 0 °C Min. Oxidation stability. (a) Neutralization value, after oxidation Max. (b) Total sludge, after oxidation, Max. Presence of oxidation inhibitor Water content, Max.

Requirement The oil shall be clear and transparent and free from suspended matter or sediments. 0.89 g/cm3 0.04 N/m. 104 °C - 9 °C Non-corrosive.

30 kV (rms) 60 kV (rms). 0.002 35 X

1012

1500 X

Ω / cm 1012

Ω / cm

0.4 mg KOH/g 0.10 percent by weight

The oil shall not contain antioxidant additives. 15 ppm

Gases analysis The analysis of gases dissolved in oil has proved to be a highly practical method for the field monitoring of power Transformers. This method is very sensitive and gives an early warning of incipient faults. It is indeed possible to determine from an oil sample of about one litre the presence of certain gases down to a quantity of a few mm3 , i.e., a gas volume corresponding to about 1 millionth of the volume of the liquid (ppm). The gases (with the exception of N2 and O2) dissolved in the oil are derived from the degradation of oil and cellulose molecules that takes place under the influence of thermal and electrical stresses. Different stress modes, e.g., normal operating

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temperatures, hot spots with different high temperatures, partial discharges and flashovers, produce different compositions of the gases dissolved in the oil. The relative distribution of the gases is therefore used to evaluate the origin of the gas production and the rate at which the gases are formed to assess the intensity and propagation of the gassing. Both these kinds of information together provide the necessary basis for the evaluation of any fault and the necessary remedial action. This method of monitoring power Transformers has been studied intensively and work is going on in international and national organizations such as CIGRE, IEC and IEEE. APPLICATION. The frequency with which oil samples are taken depends primarily on the size of the Transformer and the impact of any Transformer failure on the network. Some typical cases where gas analysis is particularly desirable are listed in the following: 1 - When a defect is suspected (e.g., abnormal noise). 2 - When a Buchholz (gas-collecting) relay or pressure monitor gives a signal. 3 - Directly after and within a few weeks after a heavy short circuit 4 - In connection with the commissioning of Transformers that are of significant importance to the network, followed by a further test some months later. Different routines for sampling intervals have been developed by different utilities and in different countries. One sampling per year appears to be customary for large power Transformers (Rated >= 300 MVA >= 220 kV). The routine that has been used over a long period of time of checking the state of the oil every other year by measuring the breakdown strength, the tan value, the neutralization coefficient and other physical quantities is not replaced by the gas analysis. Extraction and analysis To be able to carry out a gas analysis, the gases dissolved in the oil must be extracted and accumulated. The oil sample to be degassed is sucked into a pre-evacuated degassing column. A low pressure is maintained by a vacuum pump. To assure effective degassing (> 99 per cent), the oil is allowed to run slowly over a series of rings which enlarge its surfaces. An oil pump provides the necessary circulation. The gas extracted by the vacuum pump is accumulated in a vessel. Any water that may have been present in the oil is removed by freezing in a cooling trap to ensure that the water will not disturb the vacuum pumping. The volumes of the gas and the oil sample are determined to permit calculation of the total gas content in the oil. The accumulated gas is injected by means of a syringe into the gas chromatograph, which analyses the gas sample. The result is plotted on a recorder in the form of a chromatogram. Using calibration gases it is possible to identify the different peaks on a chromatogram. Recalculation of the height of a peak to the content of this gas is done by comparison with chromatogram deflections from calibration gases. With the composition of the gas mixture and the total gas content in the oil sample known; the content (in ppm) of the individual gases in the oil is obtained. The following gases are analyzed: 1 - CARBON MONOXIDE CO

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2 - CARBON DIOXIDE 3 - HYDROGEN 4 - ETHANE 5 - ETHENE 6 - ACETYLENE 7 - METHANE 8 - PROPANE

CO2 H2 C2H6 C2H4 C2H2 CH4 C3H6

The detection limits depend partly on the total gas content; for hydrocarbons (except methane) the limit lies below 0,5 ppm, for hydrogen, methane and carbon monoxide about 5 ppm and for carbon dioxide about 2 ppm. This high sensitivity is necessary in those cases where it is desired to determine a trend in the gas evolution at short sampling intervals, e.g., during a heat run test or when oil samples are taken at intervals of only a few days. Identification of faults. The fault types that can and should be identified are corona, electrical discharges, excessively hot metal surfaces and fast degradation of cellulose. It is possible to obtain an idea of the type of fault by using a diagnosis scheme. A number of different schemes of this type have been prepared. To avoid having to deal with the contents of the individual gases, one frequently uses quotients between different gases. Some schemes give an appearance of great precision, but certain care should be observed when making assessments, until all factors influencing the gassing rate are known. GAS ANALYSIS OF TRANSFORMER Type Of Gas Caused By CARBON MONOXIDE, AGEING CO CARBON DIOXIDE, CO2 HYDROGEN, ELECTRIC ARCS H2 ACETYLENE, C2H2 ETHANE, LOCAL C2H6 OVERHEATING ETHENE, C2H4 PROPANE, C3H6 HYDROGEN, H2 CORONA METHANE, CH4 Gas concentration limits used in the Interpretation of DGA data A statistical survey concerning gas concentrations in Transformer Oil using the results of that survey the following limits have been set: 182

H2 CH4 C2H6 C2H4 C2H2 CO CO2

Threshold Limit 20 10 10 20 1 300 5000

Warning Limit 200 50 50 200 3 1000 20000

Fault Limit 400 100 100 400 10

Unit ppm ppm ppm ppm ppm ppm ppm

The limits above are for a Transformer which are open with a breather and have no OLTC or has a separate conservator for the OLTC. If the Transformer tank and the OLTC have a common conservator the warning and fault limits are 30 ppm and 100 ppm respectively for C2H2 Standard IEC 60475 Method of sampling liquid dielectrics IEC 60422 Supervision and maintenance guide for mineral Insulating oils in electrical equipment IEC 60567 Guide for the sampling of gases and of oil from oil filled electrical equipment and for the analysis of free and dissolved gases IEC 60599 Mineral oil-impregnated electrical equipment in Service -Guide to the interpretation of dissolved and Free gases analysis IEC 60296 Specification for unused mineral insulating oils for Transformers and Switchgear ASTM Dl 17-96 Standard guide for sampling, test methods, Specifications, and guide for electrical insulating oils Of petroleum origin ASTM D923-97 Standard practices for sampling electrical insulating liquids ASTM D3613-98 Standard test methods of sampling electrical Insulting oils for gas analysis and determination of Water content ASTM D36 12-98 Standard test method for analysis of gases dissolved In electrical insulating oil by gas chromatography ASTM D3487-88(1993) Standard specification for mineral insulating oil Used in electrical apparatus

PARALLEL OPERATION OF THREE-PHASE TRANSFORMERS

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Ideal parallel operation between Transformers occurs when (1) there are no circulating currents on open circuit, and (2) the load division between the Transformers is proportional to their kVA ratings. These requirements necessitate that any - two or more three phase Transformers, which are desired to be operated in parallel, should possess: 1) The same no load ratio of transformation; 2) The same percentage impedance; 3) The same resistance to reactance ratio; 4) The same polarity; 5) The same phase rotation; 6) The same inherent phase-angle displacement between primary and secondary terminals. The above conditions are characteristic of all three phase Transformers whether two winding or three winding. With three winding Transformers, however, the following additional requirement must also be satisfied before the Transformers can be designed suitable for parallel operation. 7) The same power ratio between the corresponding windings. The first four conditions need no explanation being the same as in single phase Transformers. The fifth condition of phase rotation is also a simple requirement. It assumes that the standard direction of phase rotation is anti-clockwise. In case of any difference in the phase rotation it can be set right by simply interchanging two leads either on primary or secondary. It is the intention here to discuss the last two i.e., sixth and seventh conditions in detail. Connections of Phase Windings The star, delta or zigzag connection of a set of windings of a three phase Transformer or of windings of the same voltage of single phase Transformers, forming a three phase bank are indicated by letters Y, D or Z for the high voltage winding and y, d or z for the intermediate and low voltage windings. If the neutral point of a star or zigzag connected winding is brought out, the indications are Y N or Z N and y n and z n respectively. Phase Displacement between Windings The vector for the high voltage winding is taken as the reference vector. Displacement of the vectors of other windings from the reference vector, with anticlockwise rotation, is represented by the use of clock hour figure. IS: 2026 (Part 1V)-1977 gives 26 sets of connections star-star, star-delta, and star zigzag, delta-delta, delta star, delta-zigzag, zigzag star, zigzag-delta. Displacement of the low voltage winding vector varies from zero to -330° in steps of -30°, depending on the method of connections. Hardly any power system adopts such a large variants of connections. Some of the commonly used connections with phase displacement of 0, -300, -180" and -330° (clock-hour setting 0, 1, 6 and 11) are shown in Table ( below) Symbol for the high voltage winding comes first, followed by the symbols of windings in diminishing sequence of voltage. For example a 220/66/11 kV Transformer connected star, star and delta and vectors of 66 and 11 kV windings having phase displacement of 0° and -330° with the reference (220 kV) vector will be represented As Yy0 - Yd11.

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If a pair of three phase Transformers have the same phase displacement between high voltage and low voltage windings and possess similar characteristics (Such as no load ratio of transformation phase rotation, percentage impedance) these can be paralleled with each other by connecting together terminals which correspond physically and alphabetically. Thus taking the case of two three phase Transformers having vector symbols Dd0 and Yy0, these can be put into parallel operation by connecting H.V terminals U1, V1 and W1 of one Transformer to HV terminals U1, V1 and W1 of the other Transformer. Similarly, low voltage terminals U1V1 and of one Transformer should be connected to U1, V1 and W1 terminals of the second Transformer. Sometimes it may be required to operate a three-phase Transformer belonging to one group with another three-phase Transformer belonging to a different group. This is possible with suitable changes in external connections. For example, let us consider a three-phase Transformer with vector symbol Dy1 and see how this can be operated in parallel with a three-phase Transformer of similar characteristics but having vector symbol Yd11. Referring to Table (below) the phasor diagrams of the induced voltages in the h-v and l-v windings of the two Transformers, with the phase sequence of the supply connected to terminals U,V, W of the two being RYB in the anti-clockwise direction are as shown in Figs. (39a) and (39b) respectively.

Fig. (39) Example of parallel operation of Transformers of groups 3 and 4 (Transformers having symbols Dy 1 and Yd 11 operating in parallel

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It may be seen from these diagrams that the phase displacement between the induced voltages in the h-v and l-v windings is -30° in the first Transformer and it is -330° in the second Transformer. However, for the successful parallel operation of these Transformers, the phase displacement must be the same in the two. This can be achieved by interchanging externally two of the h-v connections of the incoming Transformer to the supply, i.e., by connecting 1V to bus B and 1W to bus Y as shown in Fig. (39c) by full lines instead of Connecting 1V to bus Y and 1W to bus B as shown in Fig (39b) by dotted lines.

Vector Group This results in the reversal from anticlockwise direction to clockwise direction of the phase rotation of the induced voltages as shown by arrows in Fig. (39c) and therefore results in a phase displacement of -30° between the induced voltages in the h-v and lv windings [see Fig. (39c)].

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The change in two of external it-v connections of the second Transformer thus brings it -30°. The secondary voltages of this Transformer, however, have a phase rotation reversed with respect to that of the secondary voltages of the first Transformer. This can be set right by changing again the two corresponding l-v external connections, i.e., by connecting 2V to bus b and 2W to busy as shown in Fig. (39c) instead of connecting 2V to busy and 2W to bus b as shown in Fig. (39b). Thus Transformers connected in accordance with clock hour No. 1 and 11 can be operated in parallel with one another by interchanging two of the external h-v and also the corresponding l-v connections of one Transformer. Transformers connected in accordance with clock hour No. 0 and 6 however, cannot be operated in parallel with one another without altering the internal connections of one of them as change of external connections only brings about change in phase rotation. The general principle applying to the parallel operation of a three winding Transformer with another three winding Transformer are the same as those for the paralleling of two winding Transformers. However, to obtain the same percentage impedance. Between the three pairs of windings of the two (or more) Transformers (being paralleled) it is imperative that the power ratio of the corresponding windings of the Transformers should be the same, i.e.

( PH )1 ( PM )1 ( PL)1 = = ( PH ) 2 ( PM ) 2 ( PL) 2 Where (PH)1 and (PH)2 represent the powers of the h-v windings (say primary), (PM)1 and (PM)2 represent the powers of the medium voltage windings (say secondary) and (PL)1 and (PL)2 represent the powers of the low voltage windings (say tertiary) of the two Transformers labeled 1 and 2. This is proved below. Fig. (40) Shows two 3 winding Transformers (represented by their equivalent circuits) connected in parallel. The currents flowing in the various circuits and windings are shown in the figure.

Fig (40) Shows two 3 winding Transformers (represented)

( ZH )1 ( ZM )1 ( ZL )1 = = ( ZH ) 2 ( ZM ) 2 ( ZL ) 2

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Thus the power ratios of the corresponding windings are similar. This as is evident also fulfils the second condition of same percentage impedance. When Transformers which do not fulfilling this condition are paralleled the operation may be satisfactory without fulfilling the ideal conditions so long as the loads to be carried do not overload either Transformer. Therefore, when new three-phase 3 winding Transformers are to be purchased for parallel operation with existing three-phase 3-winding Transformers the purchase order must specify the power ratings of the various windings of the existing Transformers along with other specifications and indicate that the power ratios of the corresponding windings of the various Transformers must be identical failing which it will be impossible to design Transformers with same percentage impedances for the corresponding windings. Tap Changer The method to change the ratio of Transformers by means of taps on the winding is as old as the Transformer itself. From a very early stage, Transformers with a turn ratio changeable within certain limits have been used for electrical power transmission, since this is the simplest method to control the voltage level as well as the reactive and active power in electrical networks.

Tap-changer with single phase transformer

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At the beginning of the development it was sufficient to have tappings connected to bushings outside the Transformer tank, which were connected according to the necessity of the network. A more comfortable way was to connect the tappings to tap Switches today called "off-circuit" or "no-load tap changers" - which could only be actuated when the Transformer was de-energized. Obviously, this simple device only permitted occasional corrections of the Transformer ratio. It was not possible to control voltage drops caused by load changes in the network. At that stage these parameters could only be controlled at the generating plant. To solve this problem, Switching devices were needed which permitted the change of the turn ratio of Transformers under load condition, i.e. Without interrupting the load current such Switching devices - today called "on-load taps changers" (OLTC) – were introduced to Transformers more than 70 years ago. The demand for (OLTCs) came an urgent necessity in the 1920ies, then power consumption took a sharp upward trend, which required the interconnection and expansion of the electrical networks. The very rapid development brought, within a few years, solutions which were quite satisfactory in regards to operating safety and efficiency. The development of (OLTCs) was accelerated over the years due to the steady increase of the transmission voltage and power. The introduction of OLTCs improved the operating efficiency of electrical systems considerably and this technique found acceptance worldwide. In other industrialized countries the situation is comparable. In general the percentage of Transformers equipped with OLTCs is increasing with the increase of the load density and interconnection of electrical networks. In addition. OLTCs applied in industrial process Transformers as regulating units in the chemical and metallurgical industry is another important field of application. These range from some hundred to around 300,000 operations per year while the rated currents range from approximately 50 to 3000 Amps. Today's state of the art OLTC has reached such a high level of reliability that it is safe to state that its mechanical life expectancy is equivalent to that of the Transformer. Exceptions may be applications in industrial process Transformers. However, even on such applications experience shows that with proper maintenance several million operations can be obtained. Table below shows a survey of the typical number of operations for various applications. Transformer No of operation data Power Power Voltage Current OLTC Per Transformer ring ring ring Year MVA KV A Min Mean Max Generator 100 110 100 - 500 3000 10000 -1300 765 2000 Interconnection 200 110 300 - 300 5000 25000 -1500 765 3000 Distribution 15 - 400 60 - 525 50 - 1600 2000 7000 20000 189

Electrolysis Chemistry Arc furnace

10 - 300 20 - 110 50 - 3000 1000 30000 150000 0 1.5 - 80 20 - 110 50 - 1000 1000 20000 70000 2.5 - 20 - 230 50 - 1000 2000 50000 300000 150 0

The problem to be solved when changing taps under load is how to connect the tappings of the Transformer winding successively to the same output terminal without interrupting the load current. During the load transfer operation between to adjacent taps, both taps must be temporarily connected to the output terminal. To avoid a short circuit of the winding transition impedances, which can be reactors or resistors? Are inserted. Two basic principles have been invented and are still used today - the slow motion reactor Switching principle and the high speed resistor Switching principle. Today both principles have been developed into reliable OLTCs. The reactor type OLTC has its development origin in the USA, hut also in Germany inventions were applied for a patent in 1905 and 1906. Because of the fact that the reactor Switching principle causes a 90 degree phase shift between the Switched current and the recovery voltage arising at the Switching distance, the reactor type OLTC is less suitable for large step voltages. In addition to this the costs of transition reactors increase considerably with higher step voltages. Thus the reactor Switching principle over the years has lost the remarkable importance it had in the beginning of the OLTC development. In the late 1940 is many OLTC manufacturers abandoned the production of OLTCs with this Switching principle. However, in the USA the reactor principle is still used in a large scale and reactor type OLTCs are still under production. The high-speed resistor type OLTC has its origin in the invention of Dr. Jansen of a diverter Switch and a tap selector. Which were patented in 1926. The transition impedance is been carried out with ohmic resistor with this principle the current Switched and the recovery voltage are in phase. This lightens the quenching of the arc in the current zero. The transition resistors hake to be dimensioned only for a short-time loading which enables an economic use of OLTCs in case of higher step voltages and power. Though the reactor principle has also proven itself, its application is limited to loner voltages, whereas the resistor principle dominates in the high voltage field or in special applications like HVDC - Transformers, Phase-Shifting Transformers or EHVTransformers. The reactor principle OLTC in these fields can only be applied by mean of booster Transformers. Which make its application more difficult in regards to transport weight, transport size and profile and overall economic considerations compared to the resistance principle OLTC. DESIGN CONCEPTS OF ON-LOAD TAP-CHANGERS With an on-load tap-changer the Transformer voltage ratio can be varied in steps by adding or subtracting turns. For this purpose a Transformer is furnished with a tapped winding and these taps are connected to terminals on the tap-changer. The tap-changer provides two basic functions.

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Fig (2) Basic connection of a star-point linear regulation The first is to “select” a Transformer tapping connection in an open-circuit condition, the second is to “divert” or “transfer” power to that selected tapping without interrupting the through-current. The simplest type OLTC, the selector Switch, combines these two functions into one device. Whereas separate selectors and diverter or transfer Switches are used for higher power requirements. Various tapping winding configurations are possible. The selection function can be without change-over selector (linear). Or with change-over selector (reversing or coarse / fine). A basic connection of a star-point linear regulation is given in Fig (2). The mechanical configuration of the tap selector can be designed as a single or double multiway selector. The transfer of the load current from the connected to the preselected trip is either achieved by means of resistor transition or the alternative method. Mainly used in the USA, reactor transition. In service, the diverter or transfer Switch is required to make and break current at a recovery voltage whose value is in the same order as the voltage between two taps. The power transfer function can be symmetrical or asymmetrical. The former providing similar Switching conditions for advanced or retard power flow from the Transformer. The action of the diverter or transfer Switch can be rotary or oscillatory. All designs of tap-changers maintain direct mechanical synchronism between the tap selector, change-over selector and the diverter or transfer Switch. The transfer of electrical power involves arcing in the oil and therefore contamination of the insulating oil (the exception are OLTCs that use vacuum interrupters as Switching devices). Therefore, the Switching devices are located in their own Switching compartment to separate the contaminated oil from the oil in the transformer main tank. To fulfill this requirement several designs have been developed. Selector Switches are designed for operation within an enclosure inside the Transformer tank (in-tank type) or externally in a separate oil-tilled housing bolted to the outside of the main Transformer tank (compartment type). HIGH-SPEED RESISTOR TYPE OLTC

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The high-speed resistor type OLTC is designed either as a tap selector and a diverter Switch, or as a selector Switch combining the functions of the tap selector and diverter Switch into one device.

Fig (3) Principle scheme of a selector Switch type OLTC The latter is economical to manufacture, but certain inherent limitations reduce the possible applications to small and medium size Transformers with highest voltages of equipment of 132 kV and rated-through currents in the range of 500 A to 600 A.

Fig (4) Principle scheme of a-tap selector and diverter Switch type OLTC This type can only be built in one enclosure as mentioned above and, therefore, the arc products are in contact not only with wearing mechanical parts, but also with insulation subject to high voltages. The selector Switch principle is represented in Fig. (3) The OLTC comprising a tap selector and a diverter Switch lends itself for any application up to the highest Transformer rating. Line-end applications with highest voltages for equipment of 362 kV and rated through-currents of 4500 A have been realized. Figure (4) shows an OLTC comprising a tap selector and diverter Switch. With the tap selector-diverter Switch concept the tap-change is affected in two steps. The tap adjacent to the one in

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service is pre-selected load free by the tap selector. Thereafter the

Fig (4) Switching sequence for tap-changer on Switching from position 6 to position 5. a) Position 6. Selector contact V lies on tap 6 and selector contact H on tap 7. The main contact x carries the load current. b) Selector contact H has moved in the no-current state from tap 7 to tap 5. c) The main contact X has opened. The load current passes through the resistor Ry and the resistor contact y. d) The resistor contact u has closed. The load current is shared between Ry and Ru The circulating current is limited by the resistance of Ry + Ru. e) The resistor contact y has opened. The load current passes through Ru and contact u f) The main contact V has closed, resistor Ru. Has been short-circuited and the load current passes through the main contact V. The tap-changer is now in position 5.

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Fig (45) Three-phase tap-changer type UCBRN 380/600, neutral point design for 21 position with plus/minus Switching

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Fig. (46) Motor-drive mechanism type BUE for UC tap-changer Testing Tap-changers undergo type tests according to the international standards for on-load tap-changers, IEC 214 the first edition of which was published in 1966 and the most recent one in 1976. The tests on the tap-changer itself comprise: 1- Temperature rise of contacts at 1.2 times the maximum rated through-current. 2- Switching tests. 3- Short-circuit current tests. 4- Temperature rise of transition resistors. 5- Mechanical tests. 6- Dielectric tests. And for the motor-drive mechanism: 1- Mechanical load test. 2- Overrun test. 3- Degree of protection of motor-drive cubicle. SF6 Transformer Introduction Demand for effective space utilization is becoming increasingly stronger as a result of grade advancement of commercial/industrial activities and urban life styles. Concurrently, city construction facilities including buildings, underground shopping areas, traffic systems, and public structures are becoming larger in size and gaining in the degree of complications. Since such facilities immensely contribute to improving the efficiency of urban activities, the current trend indicates the possibility of further expansion in the future. On the other hand, accidents involving outbreaks of extensive fire and other troubles are occasionally occurring in these large-sized urban facilities, resulting in the creation of public voices demanding improved fire or accident

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preventive measures.

These construction facilities of cities represent high-valued social assets. However, since a great number of citizens utilize such .facilities day after day, it is quite essential to provide effective means to eliminate outbreaks of fire. To achieve this purpose, it is important to install modern fire-fighting systems capable of coping with various causes of fire. At the same time, Basically it is most important to eliminate the possible causes of fire. The SF6 gas-insulated Transformers are designed to ideally satisfy Non flammability-ensuring plans of power reception and transformation systems installed in these urban facilities. Since no oil for insulation is used, these Transformers can completely free structures or adjacent rivers from oil contamination during new installation work or system operation. In other words, the SF6 gas-insulated Transformers qualify themselves as truly "non flammability-ensuring equipment" usable for power systems required to prevent fires or accidents and eliminate pollution.

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Features The SF6 gas-insulated Transformers offer excellent insulation and cooling characteristics and thermal stability. Additionally, these Transformers possess the following features resulting from containing the active parts in a tank sealed with nonflammable, harmless, and odorless SF6 gas. 1. High-level stability Even should the actual Transformer develop an accident, or should a fire break out on the installation environment, combustion or an explosion will not occur. Since all live parts are housed in grounded metal cases, maintenance and inspection can be achieved easily and safely. 2. Outstanding accident preventive characteristics Nonflammable structure employing no insulation oil contributes to minimizing the scope of associated accident-preventive facilities such as fireproof walls, fire-fighting equipment, or oil tanks. 3. Compactness of substation By directly coupling with gas-insulated Switchgear, substation space can be minimized as the result of compact facilities. 4. Simplified maintenance and long service life Because the Transformers are completely sealed in housing cases, no contact exists with exterior atmospheric air, thereby eliminating problems of degradation or contamination triggered by moisture or dust accumulation. Constant enveloping of components with inactive, dry SF6 gas results in minimizing aging deterioration of insulating materials and prolonging Transformer service life. 5. Easy, clean installation SF6 gas can be quickly sealed into the Transformer tank from a cylinder. Installation work never contaminates surrounding areas, and ensures maintenance of a clean environment. 6. Ideal for high voltage systems By increasing the seal pressure, SF6 gas Transformers offer insulation performance comparable to that of oil-insulated types, being ideal for high voltages of 22 kV to 154 kV. Applications The SF6 gas-insulated Transformers are suitable for the following applications: 197

•

•

•

Locations where safety against fire is essential Buildings such as hotels, department stores, schools, and hospitals Underground shopping areas, underground substations Sites close to residential areas, factories, chemical plants Locations where prevention of environment pollution is specifically demanded Water supply source zones, residential quarters, seaside areas Water treatment stations Locations where exposure exists to high-level moisture or dust accumulation Inside tunnels, industrial zones

Specifications and Ratings The SF6 gas-insulated Transformers are manufactured under the following standard specifications. Table 1 Standard specifications

NOTES: 1. Mounting of on-load tap-changer is possible. The voltage adjusting range in this case is ±10 % of the rated voltage. 2. As for codes affixed to the primary tap voltage, F indicates full-capacity taps and R indicates rated taps. 3. Consultation regarding ratings other than the above is accepted. Quality specifications The following specifications are provided to ensure safe operation of gas-insulated Transformers. • Withstand voltage during zero gas gauge pressure No problem is caused by operation under normal operating voltage. • Permissible load under zero gas gauge pressure No problem is caused by 50 % load continuous operation. • Permissible load under 1-series operation when 2-series coolers are provided No problem is caused by 75 % load continuous operation.

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External Dimensions and Weight Figures below show external dimensions and weight. Since external dimensions are subject to change without notice, please obtain final confirmation from approval drawings. Also,

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Natural-cooled type

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Natural-cooled type

NOTE: In case of 72.5 kV, GIS direct-coupling type, X size (up to bushing Terminal end) becomes "the value in the above Table + 600 mm."

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Forced-gas-circulated, natural-air-cooled type SF6 gas-insulated Transformer

Forced-gas-circulated, forced-air-cooled type

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Accessories SF6 gas temperature indicator (dial thermometer) Measures temperature of SF6 gas sealed in Transformer tanks. Gas temperature is measured by the heat sensing probe of a thermometer inserted into the protective cylinder provided in the tank or on the cover. Since this protective cylinder maintains air tightness of the gas, the temperature indicator itself can be removed. The temperature indicator is provided with alarm contacts and a pointer for indicating maximum temperature.

Dial thermometer SF6 gas pressure gauge (compound gauge) This gauge is used to measure the pressure of SF6 gas sealed in the Transformer tank. The gauge is a compound type that measures both positive and negative pressure, cm 2

capable of measuring the positive pressure up to 3.0 kg / and the negative pressure up to 760 mmHg. Generally, only the positive pressure is indicated during operation. Since vacuum suction is conducted when sealing SF6 into the tank, the graduations for negative pressure are provided for use during this gas sealing. The pressure gauge is provided with alarm contacts that actuate at the upper limit of normal pressure during operation.

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Pressure gauge (compound gauge) Temperature compensating pressure Switch Leakage is detected of SF6 gas sealed in the Transformer tank. Pressure in the Transformer tank is compared with pressure in the reference pressure chamber inserted into the protective cylinder provided in the tank or on the cover. Therefore, regardless of temperatures in the Transformer, SF6 gas leakage is accurately detected and the alarm contacts are actuated.

Temperature compensating pressure switch SF6 Gas Properties Introduction SF6 is a combination of sulfur and fluorine its first synthesis was realized in 1900 by French researchers of the Pharmaceutical Faculty of Paris. It was used for the first time as insulating material, In the United States about 1935. In 1953, the Americans discovered its properties for extinguishing the electric arc. This aptitude is quite remarkable. 204

Physical properties It is about five times heavier than air, and has a density of 6.1 4kg / m3. It is colorless, odorless and non-toxic. Tests have been carried out replacing the nitrogen content of air by SF6 (the gaseous mixture consisted of 79 % SF6 and 24 % oxygen): five mice were then immersed in this atmosphere for 24 hours, without feeling any ill effects. It is a gas which the speed of sound propagation is about three times less than in air, at atmospheric pressure. The interruption of the arc will therefore be less loud in SF6 than in air. The dielectric strength of SF6 in on average 2.5 times that of air, and, by increasing pressure, it can be seen that the dielectric strength also increases and than around 3.5 bar of relative pressure, SF6 has the same strength as fresh oil. The principal characteristics of the gas are as follows: Molar mass 146.078 Critical temperature 45.55°C Critical pressure 37.59 bars In short, SF6 at atmospheric pressure is a heavier gas than air, it becomes liquid at 63.2°C and in which noise propagates badly. SF6 on the market SF6 which is delivered in cylinders in liquid phase, contains impurities (within limits imposed by IEC standards No. 376) Carbon tetra fluoride (CF4) 0.03 % Oxygen + nitrogen (air) 0.03 % Water 15 ppm C02 traces HF 0.3 ppm SF6 is therefore 99.99 % pur. Chemical properties SF6 is a synthetic gas which is obtained as we have just explained by combination of six atoms of fluorine with one atom of sulfur:

S 2 + 6 F 2 → 2SF 6 + 524 Kcal You can see therefore that this reaction is accompanied by an important release of heat. This approximately similar to coal combustion. Given that the energy released during synthesis is the same as is needed in order to dissociate the final element, it can immediately be seen that: - SF6 is a stable gas

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- 524 k. calories are necessary for molecular breakdown, we can there fore already expect that it will be a powerful cooling agent:

6 F 2 → S 2 + 2 SF 6 + 524 Kcal

The dissociation products before interruption of the arc At normal temperature, the gas is stable, and does not react with its environment. In contact with the parts where electric currents circulate, the gas is heated to temperatures of around four hundred degrees SF6 gives the following decomposition products: Thionyl fluoride SOF2 Sulfur fluoride SO2F2 Sulfur tetra fluoride SF4 Sulfur deca fluoride S2F10 Thionyl tetra fluoride SOF4 SF6 also reacts with the materials that are found in its environment: With water (impurity in the gas), it gives hydrofluoric acid HF, With air dioxide (impurity in the gas), it gives sulfur dioxide SO2, With carbon dioxide (impurity in the gas), it gives carbon tetra fluoride CF4, With the araldite casings which are high in silicon dioxide, it gives silicon tetra fluoride SF4. The dissociation products after interruption of an arc. An electric are develops high temperatures which can reach 15000 °C. At these temperatures, many dissociation products that we have previously studied disappear. It is thus that, besides the impurities of the gas (water, air, carbon, and dioxide), there only remain: Sulfur fluoride SO2F2 Carbon tetra fluoride CF4 Silicon tetra fluoride SIF4 Sulfurous anhydride SO2. You can therefore see that a large number of products have been dissociated by the electric arc. The importance of the remaining products may be lessened by adding a powder (alumina silicate). All these gases are heavier than air, and May, under certain conditions is poisonous. SF6 Safety precautions: Today there is no known dielectric and breaking agent combined better than SF6 gas. Initial state In its initial state, before it has undergone thermal stress (usually the electric arc); SF6 is perfectly safe in normal conditions: - It is non-toxic, - It is uninflammable, - It will not explode. This does not mean that no precautions need to be taken: because of its lack of oxygen, this gas will not support life. However, the concentration of SF6 would have to be high, since the International electro technical Commission (IEC) has shown that five mice left for 24 hours in an atmosphere of 79 % SF6 and 21 % oxygen will not only remain alive but will show no signs of abnormal behavior.

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Man dies when the oxygen level of the gas he is breathing falls below 12 %. Precautions and hygiene The first recommendation is not to smoke when SF6 gas is around. The heat given off by the cigarette may decompose the gas. Your cigarette would then take on a very strange taste also avoid operating combustion engines in this gas. When the work positions are indoors, have ventilation and / or a system for detecting this halogen placed at the lowest points of the installations. Remember that SF6 is a very heavy gas. This device will warn you any gas leaks. Post-breaking state As we seen at the beginning of this Chapter, the heat from the arc modifies the SF6.This creates gaseous and solid decomposition products. It is these products that need to be spoken about. Certain of these gases are medically defined as being violent irritants of the mucous membranes and of the lungs. In extreme cases, they may cause pulmonary edema. The solid decomposition products (whitish powder) an aggressive when the react with the humidity of the mucous membranes and of the hands. Following this rather unpleasant description of the SF6 after breaking we may reassure ourselves on two counts: - For reasons of quantity - For reasons of probability. Quantity. The volume of decomposed is microscopic. This means that dangerous thresholds are rarely reached, thanks in part to the molecular sieve which regenerates the decomposition products to form pure SF6. This sieve is present in all extinguishing chambers. Regeneration time is short, but depends on the number of ampere being broken. The presence of hydrogen sulphide, noticeable through its sickening smell, makes an excellent alarm signal. The smell detection threshold is ten times lower than the toxic threshold (1 ppm is detected by smell). Probability. In normal operation, electric Switchgear using SF6 has a leak rate guaranteed to be less than 1 % of the mass per year. This makes any danger impossible in normal operation. The abnormal situation is the risk of an appliance exploding. This is fortunately extremely infrequent. And if by chance such an incident accrued, the putrid smell would make us aware of it immediately. Precaution and hygiene. If you were to find yourself in contact with decomposed SF6 gas, you must leave your post and ensure that the gas is eliminated by means of powerful ventilation. Once the polluted gas has disappeared (when the smell becomes bearable) you are still in contact with solid decomposition products. Operations on the equipment must be carried out with a gas mask, gloves and appropriate clothing. All this - together with the powders themselves - shall be sent to a factory for dealing with dangerous products.

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Any damage to the hands caused by these powders can be neutralized by limewater. Conclusion It is important to point out that sulfur hexafluoride does not bring about an increase in the risks entailed in the work stations. This lack of specific danger is furthermore confirmed by the fact that we have not had to record any accident since 1960, the year in which SF6 was first used as a breaking agent. As a matter of interest SF6 does not harm the ozone layer. This is partly due to its weight. The electric arc The creation of an arc Everyone has noticed that, when placing one’s hand near to a television screen, one feels a force which attracts. There exists, in fact, in this apparatus, what one calls an electric field. The latter is the source of an electric current, for it is this that displaces the electrons in the conductors. An electric field appears at the separation of the live contacts. Such a field of a very great intensity will draw electrons at the hot points of contacts. The electric arc has been born. If its own energy is not sufficient, the arc will extinguish rapidly itself. If, on the other hand, it is crossed by a strong current, it draws throughout its own energy, which ensures the survival of the arc. The electric arc: We have seen that the electric field was at the origin of the displacement of electrons. When the contacts separate, the electric field draws electrons to the hot points. These electrons are going to circulate in surroundings which are not conductive, which one calls dielectric, and will cause the temperature of the surroundings to increase, if they are in sufficient number. All bodies, under the influence of temperature, end up by reaching their threshold of ionic dissociation. At this moment, it parts with electrons, and becomes conductive. These electrons themselves, and for the same reasons, will create others. We have an avalanche, that is to say, creation of electrons, which will accelerate. One can reach temperature of 15000 °C. The value of the thermal power can be 10MW. The electric arc is thus going to follow the variations of alternating current, and thus, at regular intervals, the arc will disappear and reappear immediately, if the electrons have not been eliminated because in this case, the surroundings remain conductive. In order to eliminate these electrons, one could: - Rid oneself of them by some physical means, like blow-out for example, - use dielectric with a very high speed of recuperation (the case of SF6) - use a process to reduce the temperature of the element (decompression, blowout, etc.) Out-off a current If we perfect a system which allows cooling the arc (turning arc, magnetic blow-out, mechanical or thermodynamic blow-out, etc ...). One can well understand that the arc increasing to temperatures of 1500°C. Under the effect of current passing through it, will see a temperature decrease as soon as the alternating current starts its descent towards 0. The temperature will decrease all the more rapidly as:

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- SF6 has two states of conduction, and appearance of the resistive arc will bring about a fall in the intensity, and thus its temperature, - SF6, as we have seen in its physical properties, is a gas which Absorbs large quantities of energy when it dissociates. The blow out of the arc will thus (mean) evacuate a large quantity of energy. This lowering of temperature will make the ionic recombination of the bodies and the dielectric will recover its insulating properties which thus ensure interruption of the current. Lastly the hydrofluoric acids attack all metals giving metallic fluorides which are all very hydroscopic insulating powders.

Fig (1) Disruptive voltage versus pressure

Fig (2) SF6 absolute pressure versus temperature with constant volume mass (density)

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Electrical Substations Electrical Network comprises the following regions: 1 - Generating Stations. 2 - Transmission Systems. 3 - Distribution Systems. 4 - Load Points. www.sayedsaad.com Functions of a Substation 1 - Supply of required electrical power. 2 - Maximum possible coverage of the supply network. 3 - Maximum security of supply. 4 - Shortest possible fault-duration. 5 - Optimum efficiency of plants and the network. 6 - Supply of electrical power within targeted frequency limits, (49.5 Hz and 50.5 Hz). 7 - Supply of electrical power within specified voltage limits. 8 - Supply of electrical energy to the consumers at the lowest cost. www.sayedsaad.com Substation Layouts 1. Switching requirements for normal operation. 2. Switching requirements during abnormal operations, such as short circuits and overloads. 3. Degree of flexibility in operations, simplicity. 4. Freedom from total shutdown and permissible period of shutdown. 5. Maintenance requirements, space for approaching various 6. Safety of personnel. 7. Protective zones, main protection, back-up protection 8. Bypass facilities. 9. Technical requirements such as ratings, clearances, Earthing lightning protection, Noise, radio interference, etc. 10. Provision for extensions, space requirement. 11. Economic considerations, availability, foreign exchange involvement, cost of the equipment. 12. Requirements of network monitoring, power line communication, data collection, Data transmission etc. 13. Compatibility with ambient conditions. 14. Environmental aspects, audible noise, RI, TI etc. 15. Long service life, Quality, Reliability, and Aesthetics. www.sayedsaad.com Essential Features for substation 1 - Outdoor Switchyard having any one of the above. 2 - Bus-Bar schemes. 3 - High voltage Switchgear. Medium voltage Switchgear, Low voltage Switchgear and control room. 4 - Office building.

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5 - Roads and rail track for transporting equipment. 6 - Incoming line towers and outgoing line towers/cables. 7 - Store. 8 - Maintenance workshop (if required). 9 - Auxiliary power supply Low voltage AC. 10 - Battery room and low voltage DC. Supply system. 11 - Fire fighting system. 12 - Cooling water system; drinking water system, etc. 13 - Station Earthing system. 14 - Lighting protection system, overhead shielding. 15 - Drainage system. 16 - Substation lighting system etc. 17 - Fence and gates, Security system etc. www.sayedsaad.com SF6 Gas Insulated Substations (GIS) 1. Introduction SF6 Gas Insulated Substations (GIS) are preferred for voltage ratings of 72.5 kV, 145 kV, 300 kV and 420 kV and above. In such a substation, the various equipments like Circuit Breakers, Bus-Bars. Isolators, Load Break Switches, Current Transformers, Voltage Transformers Earthing Switches, etc. are housed in metal enclosed modules filled with SF6 gas. The SF6 gas provides the phase to ground insulation. As the dielectric strength of SF6 gas provides the phase to ground insulation. As the dielectric strength of SF6 gas is higher than air, the clearances required are smaller. Hence, the overall size of each equipment and the complete substation is reduced to about 10 % of conventional Air-insulated substations. As a rule GIS are installed indoor. However outdoor GIS have also been installed earlier.

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High voltage Gas Insulated Switch gear Type B95 Double Bus-Bar (make Alostom) www.sayedsaad.com

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Single line diagram High voltage Gas Insulated Switch gear Type B95 Double Bus-Bar (make Alostom) 1 – Circuit Breaker . 2 – Spring Mechanism . 3 – Disconnected . www.sayedsaad.com 4 – Slow Earthing Switch 5 – Make Proof Earthing Switch. 6 – Current Transformer. 7 – Voltage Transformer. 8 – HV cable connection. www.sayedsaad.com The various modules of GIS are factory assembled and are filled with SF6 gas at a pressure of about 3 kg/cm2. Thereafter, they a taken to site for final assembly. Such substations are compact and can be installed conveniently on any floor of a multistoried building or in an underground substation. As the units are factory assembled, the installation time is substantially reduced. Such installations are preferred in cosmopolitan cities, industrial townships, etc., where cost of land is very high and higher cost of SF6 insulated Switchgear (GIs) is justified by saving due to reduction in floor area requirement. They are also preferred in heavily polluted areas where dust, chemical fumes and salt layers can cause frequent flashovers in conventional outdoor air-insulated substations

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GIS bay single Bus-Bar Make Mitsubishi 1- Circuit Breaker 2- Disconnector Switch (GL-Type) 3- Disconnector Switch (GR-Type) 4- Earthing Switch (GRE-Type) 5- 3-ph. Bus-Bar. 6- Current Transformer. 7- Base. www.sayedsaad.com 8- Voltage Transformer. The SF6 Gas Insulated Substations (GIs) contains the same Components as in the conventional outdoor substations. All the live parts are enclosed in metal housings filled with SF6 gas. The live parts and supported on at resin insulators. Some of the insulators are designed as barriers between neighboring modules such that the gas does not pass through them. www.sayedsaad.com The entire installation is sub-divided into compartments which are gas tight with respect to each other. Thereby the gas monitoring system of each compartment can be independent and simpler. The enclosures are of non-magnetic material such as aluminum or stainless steel and are earthed. Static O-seals placed between machined flanges provide the gas tightness. The O-rings are placed in the grooves' such that after assembly, the O-rings are squeezed by about 20 %. Quality of material and dimension of grooves and O-seals are important to ensure gas-tight performance. The GIs has gas-monitoring system. The gas density in each compartment is monitored. If pressure drops slightly, the gas is automatically tapped up with further gas leakage, the low-pressure alarm is sounded or automatic tripping or lock-out occurs www.sayedsaad.com Advantages of GIs and Application Aspects: 1- Compactness. The space occupied by SF6 installation is only about 8 to 10 % of that a conventional outdoor substation. High cost is partly compensated by saving in cost of space. A typical 214

420/525 kV SF6 GIs requires only 920 m2 site area against 30.000 m2 for a conventional air insulated substation. 2 - Choice of Mounting Site. Modular SF6 GIS can be tailor made to Suit the particular site requirements. This results is saving of otherwise Expensive civil-foundation work. SF6 GIS can be suitably mounted indoor on any floor or basement and SF6 Insulated Cables (GIC) can be taken through walls and terminated through SF6 bushing or power cables. 3 - Reduced Installation Time. The principle of building block construction (modular construction) reduces the installation time to a few weeks. Each conventional substation requires several months for installation. In SF6 substations, the time-consuming high cost galvanized steel structures are eliminated. Heavy foundations for galvanized steel structures, www.sayedsaad.com Equipment support structures etc are eliminated. This results in economy and reduced project execution time. Modules are factory assembled, tested and dispatched with nominal SF6 gas. Site erection time is reduced to final assembly of modules. www.sayedsaad.com 4 - Protection from pollution. The external moisture. Atmospheric Pollution, snow dust etc. have little influence on SF6 insulated substation. However, to facilitate installation and maintenance, the substations are generally housed inside a small building. 5- Increased Safety. www.sayedsaad.com As the enclosures are at earth potential there is no possibility of accidental contact by service personnel to live parts. 6 - Explosion-proof and Fire-proof installation. Oil Circuit Breakers and oil filled equipment are prone to explosion. SF6 breakers and SF6 filled equipment are explosion proof and fire-proof.. www.sayedsaad.com Summary of Merits of SF6 GIS Safe Reliable Space saving Economical Maintenance free

Operating personnel are protected by the earthed metal enclosures The complete enclosure of all live parts guards against any Impairment of the insulation system. SF6 Switchgear installations take up only 1/10 of the space Required for conventional installations. High flexibility and application versatility provide novel, and economic overall concepts. An extremely careful selection of materials. an expedient design and a high standard of manufacturing quality assure Long service life with practically no maintenance requirement.

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Low weight

Low weight due to aluminum enclosure, correspondingly Low cost foundations and buildings.

Quick site assembly ensured by extensive Shop assembled preassembly and Testing of complete feeders or large units in the factory. Disadvantages of GIS: www.sayedsaad.com 1- High cost compared to conventional outdoor substation. 2 - Excessive damage in case of internal fault. Long outage periods as Repair of damaged part at site may be difficult. 3 - Requirement of cleanliness is very stringent. Dust or moisture can cause internal flashovers. www.sayedsaad.com 4 - Such substations are generally in door. They need a separate building. This is generally not required for conventional outdoor substations. 5 - Procurement of gas and supply of gas to site is problematic. Adequate stock of gas must be maintained. 6 - Project needs almost total imports including SF6 Gas. Spares conventional substation is totally indigenous up to 400 kV. Configuration of GIS: www.sayedsaad.com The GIS installations are assembled from a variety of standard modules. Which are joined together by flange connections and plug contacts on the Conductors. So as to easily permit subsequent disassembly of individual components. Gas-tight barrier insulators in the Switchgear sections prevent neighboring Switchgear parts from being affected by overhauls. Any maintenance and overhaul work on Switch contacts can be done without removing the enclosure. With GIS installations, all basic substation Bus-Bar schemes used, in conventional plant constructions can be realized. Installations with single or multiple Bus-Bar-also alternatively with a bypass bus-can be made with the standard modules, including Bus-Bar sectionalizing with disconnects and Breakers, and Bus-Bar coupling. The two-breaker. One and-a-half circuit breaker and ring-bus systems can also be realized economically. www.sayedsaad.com The essential parts of a GIS are: 1 - Conductors which conduct the main circuit current and transfer power these are of copper or aluminum tubes. www.sayedsaad.com 2 - Conductors need insulation above grounded enclosures. Conductors also need phase to phase insulation, In SF6 GIS these insulation requirements are met by cast resin insulators and SF6 gas insulation. 3 - Gas filled modules have nonmagnetic enclosures. Enclosures are of aluminum alloy or stainless steel. Adjacent modules are joined by means of multi-bolts tightened on flanges. Suitable neoprene rubber “O” ring gaskets are provided for ensuring Gas-tight sealing joints. www.sayedsaad.com 4 - Various circuit components in main circuit are: CB, Isolator, Earthing Switches for conductors, CTs, VTs, cable-ends, Bushing-ends and Bus-Bars. Each of these main components has its own gas -filled metal enclosed module. 5 - Gas filling, monitoring system. www.sayedsaad.com 6 - Auxiliary LV DC and LV AC supply system, control, protection and Monitoring system. This is air-insulated like in conventional sub-station. 216

The Bus-Bars are conducting bars to which various incoming and outgoing bays are connected. In SF6 GIS the Bus-Bars are laid l longitudinally in GIS hall. www.sayedsaad.com The bays are connected to Bus-Bars cross-wise. Bus-Bars are either with a three-phase enclosure or single phase enclosure. Alternatives of Enclosures, Single three phase and three single enclosures

Three phase Single Enclosures Three phase and three single enclosures The following alternatives are available to the designers for configuration of GIs. 1. Separate enclosure for each phase. This alternative was used for Components and Bus-Bars in early GIs. Now it is used only for EHV and UHV, GIS. The GIS above 420 kV are generally with separate enclosure for each phase. 2. Separate enclosure for components and a common single enclosure For three phase enclosure for Bus-Bars. www.sayedsaad.com This alternative is more widely used now for all GIS 3. Common single enclosure for all three phases for components and For Bus-Bars. The per cent trend is to use single three phase modules for components and Bus-Bars for all GIS. The GIS developed during 1980’s are with this philosophy. www.sayedsaad.com Design Aspects The SF6 insulated Switchgear contains the same components as a conventional outdoor substation. Fig (1) illustrates the construction of typical bay.

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Fig (1) Section of a 145 KV SF6 GIS with duplicate bus-bar 1 – 3- phase Bus enclosure. 2 – Isolator. 3 – Earthing Switch. 4 – C.B puffer type. 5 – CT's www.sayedsaad.com 6 – Line Isolator. 7 – VT. www.sayedsaad.com 8 – High Speed Earthing Switch. 9 – Cable sealing End. 10 – Operating mechanism (cabinet). 11 – Conductor tube. 12 – Epoxy partition fig. (2). All the live parts are enclosed in metal housing filled with SF6 gas. Live parts are supported on cast resin insulators. Some of the insulators are designed as barriers between neighboring modules such that the gas does not pass through them. The entire installation is sub-divided into compartments, which are gas tight with respect to each other. Thereby the gas monitoring system of each compartment can be independent and simple The enclosures are of nonmagnetic material such as aluminum or stainless steel and are earthed. The gas tightness is provided by static O-seals placed between machined flanges. The O-rings are placed in the grooves such that after assembly, the O-rings get squeezed by about 20 %. Quality of material and dimension of groove are important. Aluminum or stainless steel enclosures surround all live parts. Enclosures are earthed. Pressurized SF6 gas provides internal insulation between conductors and metallic enclosures. Fig (2) below. High grade insulators of Epoxy partition resin give support to active parts inside the enclosures and are also used as barriers between adjacent gas filled compartments.

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Fig(2) Epoxy partition resin Individual compartments (modules) are connected by silver plated Plug contacts for current conduction. Flanges of enclosures are bolted. Control cabinet installed near the bay contains instruments, relays, auxiliary Switches, control wiring etc. for local control, indication, alarm etc. www.sayedsaad.com GIS is installed on self supporting steel structures fixed on t he floor. Expansion bellows (Bellows compensators)

Expansion Bellows

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Expansion Bellows Variations in length due to temperature changes and dimensional differences due to assembly tolerances are resolved by making use of the wide range of bellows, which take up axial or lateral tolerances. These bellows are self compensated or compensated in compression by tie-rods Bellow compensators permit absorption of manufacturing tolerances in Bellow Compensators also permit absorption of vibrations caused by length of enclosures Bus-Bars, Transformers, reactors. Conductors are usually of aluminum alloy tubes. The conductors are plugged to silver plated finger contact assembly mounted on support insulators. These sliding contacts permit tubular conductors to expand axially with temperature rise without any additional stress on support insulators. www.sayedsaad.com The enclosures are of welded aluminum or stainless steel plates to which cast aluminum or stainless steel flanges are welded. Metallic connections between adjacent enclosures are ensured to permit circulation of full return current. The induced currents circulate in enclosures and provide magnetic field of [heir own such that. www.sayedsaad.com - Outside the enclosures the magnetic field of enclosures opposes the magnetic field of conductor currents. - Inside the enclosures, the magnetic field of enclosure currents adds to that of conductor current resulting in centralizing force on conductor. The conductor tends to remain along the central axis of enclosure. www.sayedsaad.com

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Cable connection All cables, irrespective of their type of insulation (oil impregnated paper or XLPE) and section, can be connected. The cable sealing end is fixed inside the SF6 gas Filled compartment, in accordance with the IEC 859 standard commonly used. Isolation of the Switchgear from the high voltage cables during dielectric testing is achieved by removing the contact (1) and the conductor (2).Safety is fully ensured by earthing of the cable Side through access (3), in parallel with closing of the cable earth Switch.

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Connection to Transformer 1 - Removable contact's 2 - Removable conductor.

Cable connection box 1 – Removable contact's 2 – Removabl conductor.

3 - Access for Earthing rod. 4 - Gas tight bushing. 5 - High voltage.

3 – Expansion bellows 4 – Bushing.

Compartments of SF6 Gas Insulated Switchgear Bus-Bar . Circuit Breaker.

‫قضبان التوزيع الرئيسية‬ ‫قاطع الدائرة‬

Bulk Oil Circuit Breaker Small Oil Volume Breaker Vacuum Circuit Breaker SF6 Circuit Breaker Air Blast Circuit Breaker Current Transformer. Voltage Transformer.

‫محول تيار‬ ‫محول جهد‬ 222

Earth Switch. Isolator (Disconnector Switch). Cable End ‫طرف توصيل الكابل‬

‫سكينة تأريض‬ ‫سكينة عزل‬

Bus-Bar Modules The Bus-Bar modules are either with single phase or three phase enclosure. Threephase enclosures are compact and have lesser eddy current losses. Single phase BusBars are necessary to suit other components having single phase enclosures. The three Bus-Bars are conveniently staggered by a distance equal to centre spacing. The diameter of enclosure depends on rated voltage and internal clearance requirements. The main conductors are aluminum or copper tubes. The contact areas are silver plated. There is a provision of expansion joints which permits axial elongation at higher temperatures. The tubular conductors are supported on epoxy resin cast insulators Fig (13) the shape of insulators is such that the field distribution is uniform. The dimensions of conductor tubing depend upon the mechanical strength corresponding to short circuits forces. The size so obtained is generally adequate for carrying normal current without excessive temperature rise.

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Bus-Bar dismantling principle 1 - Bus-Bar Disconnector 2 - Removable contact 3 - Bellows 4 - Bus-Bar conductor Modular components fitted in Bus-Bar lengths and bays. Depending upon particular local requirements, the following standard elements are included in the assembly Fig. below. (a) Lateral mounting unit. (b) Axial length compensator (for Bus-Bars of straight length) (c) Parallel compensator (for joint between Bus-Bars at an angle) (d) Bellow compensator

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Axial length compensator (for Bus-Bars of straight length)

1- L - unit (9o° junction)

2 - Four-way junction unit

3- T-unit with flange for Earthing switch

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4 - Angle unit (120° to 180° jaunaion ) Circuit Breaker The Circuit Breakers are automatic Switches which can interrupt fault currents. The part of the Circuit Breakers connected in one phase is called the pole. A Circuit Breaker suitable for three phase system is called a ‘triple-pole Circuit Breaker. Each pole of the Circuit Breaker comprises one or more interrupter or arc-extinguishing chambers. www.sayedsaad.com The interrupters are mounted on support insulators. The interrupter encloses a set of fixed and moving contact's The moving contacts can be drawn apart by means of the operating links of the operating mechanism. The operating mechanism of the Circuit Breaker gives the necessary energy for opening and closing of contacts of the Circuit Breakers. www.sayedsaad.com The arc produced by the separation of current carrying contacts is interrupted by a suitable medium and by adopting suitable techniques for arc extinction. The Circuit Breaker can be classified on the basis of the arc extinction medium. www.sayedsaad.com The Fault Clearing Process During the normal operating condition the Circuit Breaker can be opened or closed by a station operator for the purpose of Switching and maintenance. During the abnormal or faulty conditions the relays sense the fault and close the trip circuit of the Circuit Breaker. Thereafter the Circuit Breaker opens. The Circuit Breaker has two working positions, open and closed. These correspond to open Circuit Breaker contacts and closed Circuit Breaker contacts respectively. The operation of automatic opening and closing the contacts is achieved by means of the operating mechanism of the Circuit Breaker. As the relay contacts close, the trip circuit is closed and the operating mechanism of the Circuit Breaker starts the opening operation.

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The contacts of the Circuit Breaker open and an arc is draw between them. The arc is extinguished at some natural current zero of a.c. wave. The process of current interruption is completed when the arc is extinguished and the current reaches final zero value. The fault is said to be cleared. www.sayedsaad.com The process of fault clearing has the following sequence: 1- Fault Occurs. As the fault occurs, the fault impedance being low, the currents increase and the relay gets actuated. The moving part of the relay move because of the increase in the operating torque. The relay takes some time to close its contacts. 2 - Relay contacts close the trip circuit of the Circuit Breaker closes and trip coil is energized. 3 - The operating mechanism starts operating for the opening operation. The Circuit Breaker contacts separate. 4 - Arc is drawn between the breaker contacts. The arc is extinguished in the Circuit Breaker by suitable techniques. The current reaches final zero as the arc is extinguished and does not restrict again. www.sayedsaad.com The Trip-Circuit Fig (1) below illustrates the basic connections of the Circuit Breaker control for the

opening operation STANDARD RATINGS OF CIRCUIT BREAKERS AND THEIR SELECTION The characteristics of a Circuit Breaker including its operating devices and auxiliary equipment that are used to determine the rating are: (a) Rated characteristics to be given for all Circuit Breakers. 1. Rated voltage. 2. Rated insulation level. 3. Rated frequency. 4. rated current. 5. Rated short Circuit Breaking current. 6. Rated transient recovery voltage for terminal faults. 227

7. Rated short circuit making current. 8. Rated operating sequence. 9. Rated short time current. www.sayedsaad.com (b) Rated characteristics to be given in the Specific cases given below: 1 - Rated characteristics for short line faults for three pole Circuit Breakers rated at 72.5 kV and above, more than 12.5 kA rated short circuit breaking current and designed for direct connection to overhead transmission lines. 2 - Rated line charging breaking current, for three pole Circuit Breakers rated at 72.5 kV and above and intended for Switching over- head transmission lines. 3 - Rated supply voltage of closing and opening devices, where applicable. 4 - Rated supply frequency of closing and opening devices, where applicable. 5 - Rated pressure of compressed gas supply for operation and Interruption, where applicable. (c) Optional rated characteristics: 1. Rated out of phase breaking current. 2. Rated line charging breaking current, for three pole Circuit Breakers rated at less than 72.5 kV and for single pole Circuit Breakers. 3. Rated cable charging breaking current. 4. Rated single capacitor bank breaking current. 5. Rated small inductive breaking current. 6. Rated supply voltage of auxiliary circuits. 7. Rated supply frequency of auxiliary circuits The type of the Circuit Breaker The type of the Circuit Breaker is usually identified according to the medium of arc extinction. The classification of the Circuit Breakers based on the medium of arc extinction is as follows: www.sayedsaad.com (1) Air break' Circuit Breaker. (Miniature Circuit Breaker). (2) Oil Circuit Breaker (tank type of bulk oil) (3) Minimum oil Circuit Breaker. (4) Air blast Circuit Breaker. (5) Vacuum Circuit Breaker. (6) Sulphur hexafluoride Circuit Breaker. (Single pressure or Double Pressure). Type 1 – Air break Circuit Breaker 2 – Miniature CB. 3 – Tank Type oil CB. 4 – Minimum Oil CB. 5 – Air Blast CB.

Medium Air at atmospheric pressure Air at atmospheric pressure Dielectric oil Dielectric oil Compressed Air (20 – 40 ) bar 228

Voltage, Breaking Capacity (430 – 600) V– (5-15)MVA (3.6-12) KV - 500 MVA (430-600 ) V (3.6 – 12) KV (3.6 - 145 )KV 245 KV, 35000 MVA up to 1100 KV, 50000 MVA

6 – SF6 CB.

SF6 Gas

7 – Vacuum CB. 8 – H.V.DC CB.

Vacuum Vacuum , SF6 Gas

12 KV, 1000 MVA 36 KV , 2000 MVA 145 KV, 7500 MVA 245 KV , 10000 MVA 36 KV, 750 MVA 500 KV DC

Bulk Oil Type Breaker In Bulk Oil Circuit Breaker oil serves a two-fold purpose, i.e., as means of extinguishing the arc and also for providing insulation between the live parts and the metallic tank. This is the oldest amongst the three types having been developed towards close of the nineteenth century. www.sayedsaad.com In its simplest form the process of separating the current carrying contacts was carried out under oil with no special control over the resulting arc other than the increase in length caused by the moving contact's As the power systems began to develop resulting in higher voltages and higher fault levels, plain break type breaker could no longer keep pace with the requirements. Various methods of controlling the breaking process were investigated and developed. www.sayedsaad.com This led to the development of controlled break oil Circuit Breaker. This employed pressure chamber and is still widely used because it is relatively cheap to make and gives greatly improved performance in terms of final extinction, gap length and arcing time, as against the plain break oil Circuit Breaker. Various designs exist according to the preferences and requirements of individual manufacturers and designations such as ‘Cross Jet Type’, ‘Explosion Pot’ and ‘Baffle pot’, etc. www.sayedsaad.com Many oil Circuit Breakers feature special arc control devices most of which are based on the simple pressure chamber principle but incorporate certain modifications aimed at improving the breaking capacity. Depending on the working principle of these special pressure chambers the breakers are designated as: impulse oil Circuit Breakers deign grid breakers, breakers with double arc pressure chambers and axial jet pressure chamber oil Circuit Breakers. www.sayedsaad.com For general illustration, a view of the contact actuating mechanism of 33 kV, type OKM, bulk oil breaker manufactured by M/s English Electric Co. is shown in Fig (1) The contacts are actuated by a lever assembly L housed within the top-plate and connected to the lifting bridge N by links M. The beam lever assembly is pivoted on a shaft H fixed in bearings in the top-plate and is operated by a tie rod G connected by an adjustable coupling J to the vertical pullrod K from the Circuit Breaker operating mechanism. An oil seal F is fitted to prevent leakage from top-plate and an indicator arm is operated by a pin E on the driven end of the beam lever. The lifting bridge N which carries the lift rods Q and moving contacts R moves vertically on guide I, rods 229

D fixed in the top-plate, At the top end of each guide rod and fastened to the top plate by clips A is an accelerating spring C. www.sayedsaad.com These springs are compressed by the lifting bridge during the closing stroke and provide a throw off force when the breaker is tripped open. The mechanism is prevented from over traveling the closed position by adjustable stops B in the topplate. At the lower end of each guide rod is an oil dashpot assembly P. www.sayedsaad.com These oil buffers arrest the downward or contact opening movement. The working part of the breaker is cylindrical chamber known as an interrupter pot. The view of the interrupter is shown in Fig (2) the interrupter pot is screwed and locked on to an interrupter top block. The interior of the chamber is fitted with insulating dividing plates which form labyrinths and oil flow passages. Assembled in the top of the chamber is the fixed spring loaded cluster type contact, the fingers of which are arranged in a circular formation to engage with the moving contact which is of the solid rod of candle type. Alternate cluster fingers are extended to form arcing contacts. These parts carry the arc current and protect the normal current carrying parts from burning. The moving contacts are clamped by pinch bolts at each end of a cross bar which is bolted to the lift rod. The separation of the contacts and drawing out of the arc take place in the interrupter pot which almost completely restricts the movement of the oil within it. www.sayedsaad.com The internal space available for gas is thus little more than that swept out by the moving contact, and a pressure is set up which depends upon the rate of gas production and its rate of flow through the vents. www.sayedsaad.com The pressure rise and the condition resulting there from are believed to play a large part in giving this type of oil Circuit Breaker a very much higher breaking capacity than the plain break type.

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Fig (1)www.sayedsaad.com

Fig (2)www.sayedsaad.com

Small Oil Volume Breaker

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As the system voltages and fault levels increased the Bulk Oil Breakers required huge quantities of insulating oil and became unwieldy in size and weight. This added enormously to the cost of a power system. Simultaneously improvements were made in the technique of ceramics. The function of oil as insulating medium in the Bulk Oil Breakers was transferred to the porcelain containers. Only a small quantity of oil was used to perform its functions as arc quenching medium. This led to the development of small oil volume or low oil content breakers in the continent of Europe. Like the Bulk Oil Breakers these have also since then passed through many stages of development with varying designs of the arcing chambers. Today the small oil volume breakers are available for voltages up to 36 kV and the fault levels associated therewith. Contrary to the operation of the impulse type Circuit Breaker, such as air blast Circuit Breaker, in which arc extinction and dielectric recovery are affected by means of an external quenching medium, the process of arc extinction in the small oil volume Circuit Breaker is of internal thermo- dynamic origin. During the tripping operation an arc strikes in oil between the moving contact and the fixed contact's This arc is elongated vertically in the explosion pot until the distance traveled is sufficient to withstand the voltage between contacts. The increase in internal pressure due to the Splitting up and vaporization of oil by the arc creates a rapid movement of the extinguishing medium round the arc This self-quenching effect causes a rapid cooling of the ionized column along its whole Length due to partition of the explosion pot and the dielectric recovery is sufficiently rapid. To prevent the arc restricting after a natural Passage Through zero. The electric arc itself has, therefore, Supplied the necessary energy for its own extinction. There are now numerous manufacturers of small oil volume breakers However, to illustrate the principles of working, the sectional view of working portion of 170 kV 3500 MVA. Breakers of

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Fig (4) M/s Delle France have been shown in Fig. (4) the most important part of the breaker is its extinguishing chamber. This takes the form of an insulating cylinder containing oil, in the axis of which moves the contact rod and within which breaking occurs. The arcing chamber is supported at its base by a casing enclosing a mechanism whose function is to move the contact rod According to the impulses given by the control mechanism. In the on position, the current flows from the Upper current terminal (1) to the contact fingers, (2) Follows the movable contact rod (7) and reaches the current terminal (10) across the lower contact fingers (8). At the beginning of the stroke and before breaking, the contact rod strongly pulled down. Wards by the tripping springs, starts a high speed opening motion. Then, an arc strikes between the contact rod tips (6) and the stationary Arcing ring (3) protecting the upper contact fingers. At this moment gases escape without hindrance towards top of the apparatus. The contact rod rapidly reaches a very high linear speed; it moves the arc downwards and forces it to enter the explosion pot (5) where it is maintained rectilinear and is elongated in a direction opposite to the release of gases towards fresh oil. Since the arc is as short as possible the arc voltage is minimized and the 233

energy dissipated is reduced. Still, since the gases can no longer develop freely, they generate a considerable pressure in the explosion pot (5), thus producing a violent upward axial blast of oil vapor, exhausting the highly ionized gaseous mass. The optimum distance is thus obtained, the jet of oil causes the dielectric strength to be rapidly increased, and at the following current zero, the arc is impeded from restricting and the breaking is thus achieved. The explosion pot (5) is intended to withstand high pressures. It is partitioned into several components by means of discs whose function is to retain a certain quantity of fresh oil while the first break is proceeding; this allows a second break to occur with complete safety at the full short circuit current. The low oil content Circuit Breakers require separate current Transformers of wound type. Still at all voltages from 33 kV and above the costs of these breakers inclusive of current Transformers compete favorably with that of the Bulk Oil Breakers. In addition there are certain other advantages which may be summed up as under: (I) Light and reduced size rendering transport (ii) Simple construction making erection easy. (iii) Quick and simple maintenance.www.sayedsaad.com One of the limitations put forward against this class of breakers is frequent maintenance, owing to reduced quantity of oil and consequent liability to quick carbonization, on circuits susceptible to frequent trappings because of too many faults. Interruptions on lines carried on pin insulators are rather too many on account of poor workmanship, inadequate and improper maintenance. www.sayedsaad.com However, for this reason alone, it may not be worthwhile to reject these breakers unless the difference in cost with Bulk Oil Breakers is meager. For this very reason doubt was expressed about the ability of these breakers for rapid reclosing duty. However, low oil content breakers have been designed and constructed for rapid reclosing duties by established makers of this class of breakers. Rated breaking capacities in general are covered securely by a circuit breaking of any design but, depending on the arc extinguishing principles employed, difficulties are sometimes encountered in performing certain specific duties. The situations where the small oil volume breakers are, presently, considered at disadvantage are: (I) Switch unloaded lines. (II) Evolving faults. www.sayedsaad.com (III) Out of phase disconnection. www.sayedsaad.com The small oil volume breakers have distinct advantage over the air blast breakers under the following conditions: 1 - Kilometric faults. This is because the oil Circuit Breakers are much less sensitive to the natural frequency of the restricting voltage. 2. Disconnection of Transformers on load.

234

The current chopping phenomenon which causes over voltages, before natural zero, is not serious in this class of breakers as the arc extinguishing Energy is always proportional to the broken current. Restricting voltage

1 – Circuit Breaker pole 2 – Mechanism housing 2a – cover of mechanism housing 3 – Pole head 4 – Pole cylinder 5 – Crank housing 6 – Upper main terminal 13 – Bottom main terminal 22 – Vent housing 23 – 0il level indicator 39a – square on charging shaft 47 – Spring condition indicator 82 – off push - button 88 – on push – button 235

98 – Circuit Breaker indicator 99 – Operation counter 119 – Lifting hole for transport

www.sayedsaad.com Fig (5) Small Oil Volume Breaker type OD4 makes BBC Vacuum Circuit Breaker Sectional view of a Vacuum Circuit Breaker, marketed by M/s Driescher Picnicker Madras is shown is Fig. (6) the most important part is the vacuum interrupter, blown up view of which is given in Fig. (7) When the contacts separate, the current to be interrupted initiates a metal vapor arc discharge and flows through this plasma until the next current zero. www.sayedsaad.com The arc is then extinguished and the conductive metal vapor condenses on the metal surfaces within a matter of microseconds. As a result, the dielectric strength in the break builds up very rapidly. The self generated field causes the arc root to travel, thereby preventing local overheating when large currents are being interrupted. Certain minimum current is necessary to maintain the metal vapor arc discharge. www.sayedsaad.com Current of a lesser value is chopped prior to current zero, causing unduly high voltages, as may happen during interruption of no load magnetizing currents of unloaded Transformers. The rapid build up of the dielectric strength in the break enables the arc to be safely extinguished even if contact separation occurs immediately prior to current zero the maximum arcing time for the last pole to clear is stated to be 15 ms. Further the arc voltage developed in vacuum interrupter is low (say between 20 to 200 V) due to high conductivity of metal vapor plasma. For there reasons the arc energy developed in the break is very small. High Switching life is claimed on this account. Performance is claimed to be immune to pollution because of interrupters being hermetically sealed.

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The manufacturing range of M/s Driescher Panicker covers Vacuum Circuit Breakers up to rated voltage of 36 kV. Vacuum Circuit Breakers are specially suited in industrial applications, where the Switching frequency is high combined with high degree of pollution. www.sayedsaad.com

Fig (6) 1 - Vacuum Interrupter 2 - Terminal 3 - Flexible connection . 4 - Support insulators. 5 - Operating rod. 6 - Tie bar. www.sayedsaad.com 7 - Common operating shifts . 8 - operating corn . 9 - Locking cam. 10 - Making spring . 11 - Breaking spring. 12 - Loading spring. 13 - Main link.

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Fig (7)

1- cast resin post insulator 2- upper connection 3- upper contact support 4- 5- fastening nuts 6- Rear pull strap 7- Front pull strap 8- vacuum Switching chamber 9- contact Switch with toroidal contact Lower contact support Consisting of :10.1 transmission lever 10.2 burn-off indicator 10.3 actuation crank

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10.4 actuation lever 10.5 telescope rod with contact spring 11 hook stick Fig (8) Construction of the Switch pole type VA, VXC

Current Transformer Current Transformers comprise air insulated cores mounted inside a cylindrical enclosure. The central main conductor forms the primary winding a second cylindrical enclosure, Between the cores and the conductor, separates the cores from the SF6 thus preventing any risk of leakage from the LV terminals. www.sayedsaad.com The number and ratings of the cores are adapted according to customer requirements. Current Transformers can be installed on either or both sides of the circuit-breakers and at the ends of outgoing circuits.

Current Transformer (Make ABB) 1 - Gas tight enclosure 2 - Terminal box 3 - Secondary winding www.sayedsaad.com

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Current Transformer (Make Alostom) 1- Main conductor. 2- Secondary winding. 3- Shunt Insulating . Voltage Transformer Voltage Transformers are induction type and are contained in their own SF6 compartment, separated from the other parts of the installation. The active portion consists of a rectangular core, upon which are placed the secondary windings and the high voltage winding. Provision is made for up to two secondary windings for measurement and an additional open delta winding for earth fault detection. A synthetic film separates the different wraps of the windings. The Transformers can be installed Any where on the substation. Voltage Transformer Module For rated voltage up to 145 kV inductive Transformer with cast resin coil For rated voltage of 245 kV inductive VT with SF6 gas as main insulation. For 300 kV and above, Capacitive Voltage Transformers are preferred Inductive type Voltage Transformer. The single-pole inductive type Voltage Transformers (Fig. 1) can be mounted either vertical or horizontal. They are connected to the Switchgear with the standardized connecting flange via a barrier insulator. The primary winding is insulated with SF6 gas and connected to the HV. by a flexible connection. The primary winding (2) surround the core on which the secondary windings (1) are also wound. The connection between the secondary winding and the terminals in the external terminal box is made through a gas tight multiple bushing. The Transformers are equipped with two metering windings and one tertiary winding for earth-fault protection. Capacitor Voltage Transformer In Switchgear for voltage above 300 kV, Capacitor Voltage Transformers are also employed. Two systems are available: - Transformers with high capacitance connected to an intermediate Transformer. The oil-insulated capacitor of conventional design is accommodated in an enclosure filled with SF6 gas. The high-voltage connection to the GIS is made through a barrier insulator. The low-voltage choke and the intermediate Voltage Transformer are housed separately in a cabinet on the earth potential side.

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- Transformers with a low capacitance accommodated in the current Transformer or in a separate housing, connected to an electronic

1 - Secondary winding 2 - Primary winding 3 - Terminal box 4 - Support insulator 5 - Filling valve 6 - Safety diaphragm 7 - Density Switch

(Fig. 1) Voltage Transformer (Make ABB)

Earthing Switch Earthing Switch is necessary to earth the conducting parts before maintenance and also to provide deliberate short-current while testing. There can be three types of Earthing witches in metal-clad Switches manually operated automatic high speed Earthing Switch, protective Earthing Switch for Earthing the installation. There are several versions of Earthing Switches for following applications 1 - Maintenance Earthing Switches. These are single pole or three pole units; manually operating mechanism with a provision of filling motor mechanism. 2 - High Speed Earthing Switches. These are operated by spring energy. Spring is charged by motor-mechanism

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Fig (1)

Fig (2) the one pole Earthing Switch Closed position

Earthing Switch: 1- Moving contact 2- Operating lever 3- Position indicator

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Open position

The earth Switch is mounted direct on the enclosure Fig. (1) Earthing Switch has to satisfy various requirements. For Earthing isolated sections of Switchgear for protection of personal during maintenance and over-hauls or erection, the maintenance Earthing Switches are employed. For Earthing higher capacitances (cables, overhead line etc.) high speed Earthing Switch are employed. Depending on the substation scheme, the Bus-Bars may be earthed either by maintenance or high-speed Earthing Switches. Special high speed Earthing Switches with interrupting capability are also available. These are suitable for interrupting capacitive and inductive currents from parallel overhead lines. In certain cases, Earthing Switches are fitted to the enclosure with interposed insulation. This enables various tests to be performed on the Switchgear or item of equipment, such as testing the current Transformer of measuring the operating time of breakers, without having to open the enclosure. During normal operation the insulation is bypassed by a short-circuit-proof link. To check whether a point to be earthed really is dead, the Earthing Switch can be equipped with a capacitive tap for connecting a voltage test unit. This additional safety device reduces the risk of closing onto a live conductor. Disconnector switch Isolating Switches are normally Switched only when not on load but they may also interrupt the no load current of small Transformers as well as disconnect short pieces of overhead lines or cables.

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Disconnector Switch. 1 - Support insulator 2 - Fixed contact 3 - Moving contact 4 - Coupling contact 5 - Moving earthing contact 6 - Drive insulator 7 - Arcing contact The BS: 3078-1959 on isolators distinguishes between “off load” and “on load” isolator as under: 1 - Off Load Isolator is an isolator which is operated in a circuit either when the isolator is already disconnected from all sources of supply or when the isolator is already disconnected from the supply and the current may be due to capacitance currents of bushings, Bus-Bar connections, and very short lengths of cable. 2 - On Load Isolator is an isolator which is operated in a circuit where there is a parallel path of low impedance so that no significant change in the voltage across the terminals of each pole occurs when it is operated.

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Disconnector: 1- supporting insulator 2- fixed contact 3- moving contact 4- earthing Switch 5- driving insulator To ensure that the off load isolators are not operated inadvertently under load it is necessary that the isolators are suitably interlocked with the connected breakers. Isolating Switches can broadly be divided into the three categories given ahead. a) Bus isolator. b) Line isolator. c) Transformer isolating. RATINGS AND THEIR SELECTION An isolator may be constructed single pole or three poles and shall be rated in terms of: 1 - Voltage. The rated voltage of an isolator or an earthing Switch shall be one of the highest system voltages, given below: 3, 6, 7.2, 12, 24, 36, 72.5, 123, 145, 245, 300 and 420 kV. 2 - Insulation level. The rated insulation level should be selected from standard Tables according To IS: 9921 3 - Frequency Rated frequency should be 50 Hz in Kuwait. 4 - Normal current (for Disconnector only) The rated normal current of an isolator or an earthing Switch should have one of the following Standard values: 200 A, 400 A, 630 A (alternatively 800 Amps), 1250 A, 1600 A, 2000 A, 2500 A, 3150 A, 5000 A and 4000 A. 5 - Short time withstand current

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The rated short-time withstands current of a Disconnector or earthing Switch should have one of the following values: 8, 10, 12.5, 16, 20, 25, 31.5, 40, 50, 63, 80 or 100 KA. 6 - Duration of short circuit The short time current rating of an isolator, unless directly associated with and protected by a fuse or by a Circuit Breaker fitted with series releases or current Transformer operated releases when it need not be assigned a short time rating, should not be less than the short circuit current at the point of installation or the corresponding ratings of the associated Circuit Breaker. The rated maximum duration of short circuit is one second. For short circuit duration greater than one second, the relation between current (I) and time (t), unless otherwise specified, shall be assumed to be in accordance with the formula: I2X

t = constant 7 - Peak withstand current The rated peak withstand current of a Disconnector or earthing Switch is that peak current which it shall be able to carry in the closed position without material deterioration. It shall have a value 2.5 times the rated short time withstand current. 8 - Short circuit making current (for earthing Switches only) The earthing Switches to which a rated short circuit making current has been assigned shall be capable of making at any applied voltage, upto and including that corresponding to their rated voltage, any current upto and including their short circuit making current. 9 - Contact zone Divided frame Disconnector and earthing Switches shall be able to operate within the limits of their rated contact zone. For examples of rated contact zones, the reader may refer to IS: 9921 (Part II)-1982. 10 - Mechanical terminal load Disconnector and Earthing Switches should be able to close and open whilst subject to their rated mechanical terminal loads, where assigned, plus wind loads acting on the equipment itself. 11 - Supply voltage closing and opening devices (where these operating devices are supplied separately) of auxiliary circuits, peak power And total duration of operations. The rated supply voltage shall preferably be one of the standard values given below: DC. Volts AC. volts 24 110 Single phase 48 240 Single phase 110 240 /415 three phases 220 The operating device shall be capable of closing and opening the isolator at any value of the supply voltage between 85 percent and 110 percent of the rated voltage. 12 - Supply frequency of closing and opening devices and of auxiliary circuits. The rated supply frequency of an operating device or an auxiliary circuit is the frequency at which the conditions of operation and heating are determined. 13 - Pressure of compressed gas supply for operation.

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The rated pressure should correspond to the operating pressure of the associated air blast Circuit Breakers, if installed and preferably have one of the following standard values: 500, 1000, 1600, 2000 or 3900 kPa. The pneumatic operating device shall be capable of closing and opening the isolator when the air pressure is between 85 percent and 105 percent of the rated supply pressure. TESTS 1. Type Tests laid down in IS: 9921(part 4)-1985 A) Normal Type Tests - Dielectric Tests Comprising Of. 1 - Lightning Impulse Voltage Tests 2 - Switching Impulse Voltage Tests for rated 3 - Power Frequency Voltage Tests. 4 - Artificial Pollution Tests. 5 - Partial Discharge Tests. 6- Tests on Auxiliary and Control Circuits. B) Routine Tests The following shall comprise routine tests: 1- Power Frequency Voltage Test, 2-Voltage Test on Auxiliary Equipment. 3- Operation test 4- Measurement of the Resistance of the Main Circuit. Cable connection All cables, irrespective of their type of insulation (oil impregnated paper or XLPE) and section, can be connected. The cable sealing end is fixed inside the SF6 gas Filled compartment, in accordance with the IEC 859 standard commonly used. Isolation of the Switchgear from the high voltage cables during dielectric testing is achieved by removing the contact (1) and the conductor (2).Safety is fully ensured by earthing of the cable Side through access (3), in parallel with closing of the cable earth Switch.

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Connection to Transformer 1 – Removable contact's 2 – Removable conductor. 3 – Expansion bellows. 4 – Bushing.

Cable connection box 1 - Removable contact's 2 - Removable conductor. 3 - Access for Earthing rod. 4 - Gas tight bushing. 5 - High voltage

SF6 Gas Insulated Switchgear (GIs) Types of Bays SF6 Gas Insulated Switchgear. 1 – Feeder Bay. ‫خلية مغذى‬ 2 – Transformer Bay. ‫ خلية محول‬www.sayedsaad.com 3 – Bus section Bay. ‫خلية رابط قضبان طولى‬ 4 – Bus coupler Bay. ‫خلية رابط قضبان عرضى‬ www.sayedsaad.com Drawing Component of SF6 Gas Insulated Feeder bay 1 – High Speed Earth Switche (Line Earth Switch). ‫سكينة تأريض مغذى‬ 2 – Isolator for Voltage Transformer. ‫سكينة محول جهد‬ 3 – Voltage Transformer. ‫ محول جهد‬www.sayedsaad.com 4 – Line Isolator. (Disconnector Switch) ‫سكينة عزل المغذى‬ 5 – Maintenance Earth Switches. ‫سكينة تأريض‬ 6 – CT's For Bus-Bar protection. ‫محول تيار لحماية البسبار‬ 7 – Circuit Breaker. ‫ قاطع الدائرة‬www.sayedsaad.com 8 – CT's For Line protection and metering. ‫محول تيار المغذى و أجهزة القياس‬ 9 – Maintenance Earth Switches. ‫سكينة تأريض‬ 248

10 – Bus-Bar Isolator ‫سكينة عزل البسبار‬ www.sayedsaad.com

Drawing ‫ خلية مغذى‬Feeder Bay

Component of SF6 Gas Insulated Transformer bay 1 – Bus-Bar Isolator. (Disconnector Switch) ‫سكينة عزل البسبار‬ 2 – Maintenance Earth Switches. ‫سكينة تأريض‬ 3 – CT's For Transformer protection. ‫محول تيار لجهزة وقاية المحول‬ 4 – Circuit Breaker. ‫ قاطع الدائرة‬www.sayedsaad.com 5 – CT's for Bus-Bar protection and metering. ‫محول تيار لحماية البسبار و أجهزة القياس‬ 6 – Maintenance Earth Switches. ‫سكينة تأريض‬ 7 – Transformer Isolator. ‫سكينة عزل المحول‬

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8 – Maintenance Earth Switches. (Transformer E.S) ‫سكينة تأريض المحول‬ Drawing ‫ خلية محول‬Transformer Bay

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Component of SF6 Gas Insulated Bus section bay 1 – Bus-Bar Isolator. (Disconnector Switch) ‫سكينة عزل البسبار‬ 2 – Maintenance Earth Switches. ‫سكينة تأريض‬ 3 – CT's For Bus-Bar protection and metering. ‫محول تيار لحماية البسبار و أجهزة القياس‬ 4 – Circuit Breaker. ‫قاطع الدائرة‬ 5 – Maintenance Earth Switches. ‫سكينة تأريض‬ www.sayedsaad.com Drawing ‫ خلية رابط قضبان طولى‬Bus Section bay

Component of SF6 Gas Insulated Bus coupler bay 1 – Bus-Bar Isolator. (Disconnector Switch) ‫سكينة عزل البسبار‬ 2 – Maintenance Earth Switches. ‫سكينة تأريض‬ 3 – CT's For Bus-Bar protection and metering. ‫محول تيار لحماية البسبار و أجهزة القياس‬ 4 – Circuit Breaker. ‫قاطع الدائرة‬ 6 – Maintenance Earth Switches. ‫سكينة تأريض‬ 7 – Bus-Bar Isolator. ‫سكينة عزل البسبار‬ Drawing ‫ خلية رابط قضبان‬Bus coupler bay

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Important considerations when design protection system Important considerations when design protection system 1. Types of fault and abnormal Conditions to be protected against 2. Quantities available for measurement 3. Types of protection available 4. Speed 5. Fault position discrimination 6. Dependability / reliability 7. Security / stability 8. Overlap of protections 9. Phase discrimination / selectivity 10. CT’s and VT’s ratio required 11. Auxiliary supplies 12. Back-up protection 13. Cost 14. Duplication of protection Types of protection A - Fuses For LV Systems, Distribution Feeders and Transformers, VT’s, Auxiliary Supplies B - Over current and earth fault Widely used in All Power Systems 1. Non-Directional 2. Directional C - DIFFERENTIAL For feeders, Bus-bars, Transformers, Generators etc 1. High Impedance 2. Low Impedance 3. Restricted E/F 4. Biased

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5. Pilot Wire D - Distance For transmission and sub-transmission lines and distribution feeders, also used as back-up protection for transformers and generators without signaling with signaling to provide unit protection e.g.: 1. 2. 3. 4. 5. 6. 7. 8.

Time-stepped distance protection Permissive underreach protection (PUP) Permissive overreach protection (POP) Unblocking overreach protection (UOP) Blocking overreach protection (BOP) Power swing blocking Phase comparison for transmission lines Directional comparison for transmission lines

E - Miscellaneous: 1. Under and over voltage 2. Under and over frequency 3. A special relay for generators, transformers, motors etc. 4. Control relays: auto-reclose, tap change control, etc. 5. tripping and auxiliary relays Speed Fast operation: minimizes damage and danger Very fast operation: minimizes system instability discrimination and security can be costly to achieve. Examples: 1. differential protection 2. differential protection with digital signaling 3. distance protection with signaling 4. directional comparison with signaling Fault position discrimination Power system divided into protected zones must isolate only the faulty equipment or section Dependability / reliability Protection must operate when required to Failure to operate can be extremely damaging and disruptive Faults are rare. Protection must operate even after years of inactivity Improved by use of: 1. Back-up Protection and 2. duplicate Protection Security / Stability Protection must not operate when not required to e.g. due to: 1. Load Switching 2. Faults on other parts of the system 3. Recoverable Power Swings

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Overlap of protections 1. No blind spots 2. Where possible use overlapping CTs Phase discrimination / selectivity Correct indication of phases involved in the fault Important for Single Phase Tripping and auto-Reclosing applications Current and voltage transformers These are an essential part of the Protection Scheme. They must be suitably specified to meet the requirements of the protective relays. 1A and 5A secondary current ratings, Saturation of current transformers during heavy fault conditions should not exceed the limits laid down by the relay manufacturer. Current transformers for fast operating protections must allow for any offset in the current waveform. Output rating under fault conditions must allow for maximum transient offset. This is a function of the system X/R ratio. Current Transformer Standards/Classes: British Standards: 10P, 5P, X IEC: 10P, SP, TPX, TPY, TPZ American: C, T. Location of CTs should, if possible, provide for overlap of protections. Correct connection of CTs to the protection is important. In particular for directional, distance, phase comparison and differential protections. VT’s may be Electromagnetic or Capacitor types. Busbar VT’s: Special consideration needed when used for Line Protection. Auxiliary supplies Required for: 1. Tripping circuit breakers 2. Closing circuit breakers 3. Protection and trip relays • AC. auxiliary supplies are only used on LV and MV systems. • DC. auxiliary supplies are more secure than ac supplies. • Separately fused supplies used for each protection. • Duplicate batteries are occasionally provided for extra security. • Modern protection relays need a continuous auxiliary supply. • During operation, they draw a large current which increases due to operation of output elements. Relays are given a rated auxiliary voltage and an operative auxiliary voltage range. the rated value is marked on the relay. Refer to relay documentation for details of operative range. it is important to make sure that the range of voltages which can appear at the relay auxiliary supply terminals is within the operative range. IEC recommended values (IEC 255-6): Rated battery voltages: 12, 24, 48, 60, 11 0, 125, 220, 250, 440 Preferred operative range of relays: 80 to 10% of voltage rated AC. component ripple in the dc supply: <10% of voltage rated

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COST The cost of protection is equivalent to insurance policy against damage to plant, and loss of supply and customer goodwill. Acceptable cost is based on a balance of economics and technical factors. Cost of protection should be balanced against the cost of potential hazards there is an economic limit on what can be spent. Minimum cost: Must ensure that all faulty equipment is isolated by protection Other factors: 1. Speed 2. Security/Stability 3. Sensitivity: Degree of risk in allowing a low level fault to develop into a more severe fault 4. Reliability Total cost should take account of: 1. Relays, schemes and associated panels and panel wiring 2. Setting studies 3. Commissioning 4. CT’s and VT’s 5. Maintenance and repairs to relays 6. Damage repair if protection fails to operate 7. Lost revenue if protection operates unnecessarily Distribution systems 1. Large number of switching and distribution points, transformers and feeders. 2. Economics often overrides technical issues 3. Protection may be the minimum consistent with - statutory safety regulations 4. Speed less important than on transmission systems 5. Back-up protection can be simple and is often inherent in the main protection. 6. Although important, the consequences of maloperation or failure to operate are less serious than for transmission systems. Transmission systems 1. Emphasis is on technical considerations rather than economics 2. Economics cannot be ignored but is of secondary importance compared with the need for highly reliable, fully discriminative high speed protection 3. Higher protection costs justifiable by high capital cost of power system elements protected. 4. Risk of security of supply should be reduced to the lowest practical levels 5. High speed protection requires unit protection 6. Duplicate protections used to improve reliability 7. Single phase tripping and auto-reclose may be required to maintain system stability

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Basic of protection system Introduction The purpose of an electrical power generation system is to distribute energy to a multiplicity of points for diverse applications. The system should be designed and managed to deliver this energy to the utilization points with both reliability and economy. As these two requirements are largely opposed, it is instructive to look at the relationship between the reliability of a system and its cost and value to the consumer, which is shown in Figure 1.

Figure 1 Relationship between reliability of supply, its cost and value to the consumer. It is important to realize that the system is viable only between the cross-over points A and B. The diagram illustrates the significance of reliability in system design, and the necessity of achieving sufficient reliability. On the other hand, high reliability should not be pursued as an end in itself, regardless of cost, but should rather be balanced against economy, taking all factors into account. Security of supply can be bettered by improving plant design, increasing the spare capacity margin and arranging alternative circuits to supply loads. Subdivision of the system into zones, each controlled by switchgear in association with protective gear, provides flexibility during normal operation and ensures a minimum of dislocation following a breakdown.

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The greatest threat to a secure supply is the shunt fault or short circuit, which imposes a sudden and sometimes violent change on system operation. The large current which then flows, accompanied by the localized release of a considerable quantity of energy, can cause fire at the fault location, and mechanical damage throughout the system, particularly to machine and transformer windings. Rapid isolation of the fault by the nearest switch-gear will minimize the damage and disruption caused to the system. A power system represents a very large capital investment. To maximize the return on this outlay, the system must be loaded as much as possible. For this reason it is necessary not only to provide a supply of energy which is attractive to prospective users by operating the system within the range AB (Figure 1.1), but also to keep the system in full operation as far as possible continuously, so that it may give the best service to the consumer, and earn the most. Revenue for the supply authority. Absolute freedom from failure of the plant and system network cannot be guaranteed. The risk of a fault occurring, however slight for each item, is multiplied by the number of such items which are closely associated in an extensive system, as any fault produces repercussions throughout the net-work. When the system is large, the chance of a fault occurring and the disturbance that a fault would bring are both so great that without equipment to remove faults the system will become, in practical terms, inoperable. The object of the system will be defeated if adequate provision for fault clearance is not made. Nor is the installation of switchgear alone sufficient; discriminative protective gear, designed according to the characteristics and requirements of the power system, must be provided to control the switchgear. A system is not properly designed and managed if it is not adequately protected. This is the measure of the importance of protective systems in modern practice and of the responsibility vested in the protection engineer.

Fundamentals of protection practice This is a collective term which covers all the equipment used for detecting, locating and initiating the removal of a fault from the power system. Relays are extensively used for major protective functions, But the term also covers directacting A.C. trips and fuses. In addition to relays the term includes all accessories such as current and voltage transformers, shunts, D.C. and A.C. wiring and any other devices relating to the protective relays. In general, the main switchgear, although fundamentally protective in its function, is excluded from the term 'protective gear', as are also common services, 257

such as the station battery and any other equipment required to secure operation of the circuit breaker. In order to fulfil the requirements of discriminative protection with the optimum speed for the many different configurations, operating conditions and construction features of power systems, it has been necessary to develop many types of relay which respond to various functions of the power system quantities. For example, observation simply of the magnitude of the fault current suffices in some cases but measurement of power or impedance may be necessary in others. Relays frequently measure complex functions of the system quantities, which are only readily expressible by mathematical or graphical means. In many cases it is not feasible to protect against all hazards with any one relay. Use is then made of a combination of different types of relay which individually protect against different risks. Each individual protective arrangement is known as a 'protection system'; while the whole coordinated combination of relays is called a 'protection scheme'. Reliability The need for a high degree of reliability is discussed in Section 1. Incorrect operation can be attributed to one of the following classifications: a. b. c. d.

Incorrect design. Incorrect installation. Deterioration. Protection performance

1. Design This is of the highest importance. The nature of the power system condition which is being guarded against must be thoroughly understood in order to make an adequate design. Comprehensive testing is just as important, and this testing should cover all aspects of the protection, as well as reproducing operational and environmental conditions as closely as possible. For many protective systems, it is necessary to test the complete assembly of relays, current transformers and other ancillary items, and the tests must simulate fault conditions realistically. 2.

Installation. The need for correct installation of protective equipment is obvious, but the complexity of the interconnections of many systems and their relation-ship to the remainder of the station may make. Difficult the checking of such correctness. Testing is therefore necessary; since it will be difficult to reproduce all fault conditions correctly, these tests must be directed to proving the installation. This is the function of site testing, which should be limited to such simple and direct tests as will prove the correctness of the connections and freedom from damage of the equipment. No attempt should be made to 'type test' the equipment or to establish complex aspects of its technical performance; 258

3. Deterioration in service. After a piece of equipment has been installed in perfect condition, deterioration may take place which, in time, could interfere with correct functioning. For example, contacts may become rough or burnt owing to frequent operation, or tarnished owing to atmospheric contamination; coils and other circuits may be open-circuited, auxiliary components may fail, and mechanical parts may become clogged with dirt or corroded to an extent that may interfere with movement. One of the particular difficulties of protective relays is that the time between operations may be measured in years, during which period defects may have developed unnoticed until revealed by the failure of the protection to respond to a power system fault. For this reason, relays should be given simple basic tests at suitable intervals in order to check that their ability to operate has not deteriorated. Testing should be carried out without disturbing permanent connections. This can be achieved by the provision of test blocks or switches. Draw-out relays inherently provide this facility; a test plug can be inserted between the relay and case contacts giving access to all relay input circuits for injection. When temporary disconnection of panel wiring is necessary, mistakes in correct restoration of connections can be avoided by using identity tags on leads and terminals, clip-on leads for injection supplies, and easily visible double-ended clip-on leads where 'jumper connections' are required. The quality of testing personnel is an essential feature when assessing reliability and considering means for improvement. Staff must be technically competent and adequately trained, as well as self-disciplined to proceed in a deliberate manner, in which each step taken and quantity measured is checked before final acceptance. Important circuits which are especially vulnerable can be provided with continuous electrical super-vision; such arrangements are commonly applied to circuit breaker trip circuits and to pilot circuits. 4. Protection performance The performance of the protection applied to large power systems is frequently assessed numerically. For this purpose each system fault is classed as an incident and those which are cleared by the tripping of the correct circuit breakers and only those are classed as 'correct'. The percentage of correct clearances can then be determined. This principle of assessment gives an accurate evaluation of the protection of the system as a whole, but it is severe in its judgment of relay performance, in that many relays are called into operation for each system fault, and all must behave correctly for a correct clearance to be recorded. On this basis, a performance of 94 % is obtainable by standard techniques. Complete reliability is unlikely ever to be achieved by further improvements in construction. A very big step, however, can be taken by providing duplication of equipment or 'redundancy'. Two complete sets of equipment are provided, and arranged so that either by itself can carry out the required function. If the risk of

259

an equipment failing is x/unit, the resultant risk, allowing for redundancy, is x2. Where x is small the resultant risk (x2) may be negligible. It has long been the practice to apply duplicate protective systems to busbars, both being required to operate to complete a tripping operation, that is, a 'two-out-of-two' arrangement. In other cases, important circuits have been provided with duplicate main protection schemes, either being able to trip independently, that is, a 'one-out-of-two' arrangement. The former arrangement guards against unwanted operation, the latter against failure to operate. These two features can be obtained together by adopting a 'two-out-ofthree' arrangement in which three basic systems are used and are interconnected so that the operation of any two will complete the tripping function. Such schemes have already been used to a limited extent and application of the principle will undoubtedly increase. Probability theory suggests that if a power network were protected throughout on this basis, a protection performance of 99.98 % should be attainable. This performance figure requires that the separate protection systems be completely independent; any common factors, such as, for instance, common current transformers or tripping batteries, will reduce the overall performance to a certain extent. Selectivity. Protection is arranged in zones, which should cover the power system completely, leaving no part unprotected. When a fault occurs the protection is required to select and trip only the nearest circuit breakers. This property of selective tripping is also called 'discrimination' and is achieved by two general methods: 1. Time graded systems. Protective systems in successive zones are arranged to operate in times which are graded through the sequence of equipments so that upon the occurrence of a fault, although a number of protective equipments respond, only those relevant to the faulty zone complete the tripping function. The others make incomplete operations and then reset. 2. Unit systems. It is possible to design protective systems which respond only to fault conditions lying within a clearly defined zone. This 'unit protection' or 'restricted Protection' can be applied throughout a power system and, since it does not involve time grading, can be relatively fast in operation. Unit protection is usually achieved by means of a comparison of quantities at the boundaries of the zone. Certain protective systems derive their 'restricted' property from the configuration of the power system and may also be classed as unit protection. Whichever method is used, it must be kept in mind that selectivity is not merely a matter of relay design.

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It is a function of the correct co-ordination of current transformers and relays with a suitable choice of relay settings, taking into account the possible range of such variables as fault currents, maximum load current, system impedances and so on, where appropriate. Zones of protection Ideally, the zones of protection should overlap across the circuit breaker as shown in Figure 2, the circuit breaker being included in both zones.

Figure 2. Location of current transformers on both sides of the circuit breaker. For practical physical reasons, this ideal is not always achieved, accommodation for current trans-formers being in some cases available only on one side of the circuit breakers, as in Figure 3. This leaves a section between the current transformers and the circuit breaker A within which a fault is not cleared by the operation of the protection that responds. In Figure 3 a fault at F would cause the bus-bar protection to operate and open the circuit breaker but the fault would continue to be fed through the feeder.

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Figure 3 Location of current transformers on circuit side of the circuit breaker. The feeder protection, if of the unit type, would not operate, since the fault is outside its zone. This problem is dealt. With by some form of zone extension, to operate when opening the circuit breaker does not fully interrupt the flow of fault current. A time delay is incurred in fault clearance, although by restricting this operation to occasions when the bus-bar protection is operated the time delay can be reduced.

Figure 4 Overlapping zones of protection systems. The point of connection of the protection with the power system usually defines the zone and corresponds to the location of the current transformers. The protection may be of the unit type, in which case the boundary will be a clearly

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defined and closed loop. Figure 4 illustrates a typical arrangement of overlapping zones. Alternatively, the zone may be unrestricted; the start will be defined but the extent will depend on measurement of the system quantities and will therefore be subject to variation, owing to changes in system conditions and measurement errors. Stability. This term, applied to protection as distinct from power networks, refers to the ability of the system to remain inert to all load conditions and faults external to the relevant zone. It is essentially a term which is applicable to unit systems; the term 'discrimination' is the equivalent expression applicable to non-unit systems. Speed. The function of automatic protection is to isolate faults from the power system in a very much shorter time than could be achieved manually, even with a great deal of personal supervision. The object is to safeguard continuity of supply by removing each disturbance before it leads to widespread loss of synchronism, which would necessitate the shutting down of plant. Loading the system produces phase displacements between the voltages at different points and therefore increases the probability that synchronism will be lost when the system is disturbed by a fault. The shorter the time a fault is allowed to remain in the system, the greater can be the loading of the system. Figure 1.5 shows typical relations between system loading and fault clearance times for various types of fault. It will be noted that phase faults have a more marked effect on the stability of the system than does a simple earth fault and therefore require faster clearance. It is not enough to maintain stability; unnecessary consequential damage must also be avoided. The destructive power of a fault arc carrying a high current is very great; it can burn through copper conductors or weld together core laminations in a transformer or machine in a very short time. Even away from the fault arc itself, heavy fault currents can cause damage to plant if they continue for more than a few seconds

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Figure 5 Typical values of power that can be transmitted as a function of fault clearance time. It will be seen that protective gear must operate as quickly as possible; speed, however, must be weighed against economy. For this reason, distribution circuits for which the requirements for fast operation are not very severe are usually protected by time-graded systems, but generating plant and EHV systems require protective gear of the highest attainable speed; the only limiting factor will be the necessity for correct operation. Sensitivity Sensitivity is a term frequently used when referring to the minimum operating current of a complete protective system. A protective system is said to be sensitive if the primary operating current is low. When the term is applied to an individual relay, it does not refer to a current or voltage setting but to the volt-ampere consumption at the minimum operating current. A given type of relay element can usually be wound for a wide range of setting currents; the coil will have an impedance which is inversely proportional to the square of the setting current value, so that the volt-ampere product at any setting is constant. This is the true measure of the input requirements of the relay, and so also of the sensitivity. Relay power factor has some significance in the matter of transient performance. For D.C. relays the VA input also represents power consumption, and the burden is therefore frequently quoted in watts. Primary and back-up protection The reliability of a power system has been discussed in earlier sections. Many factors may cause protection failure and there is always some possibility of a circuit breaker failure. For this reason, it is usual to supplement primary protection with other systems to 'back-up' the operation of the main system and 264

ensure that nothing can prevent the clearance of a fault from the system. Back-up protection may be obtained automatically as an inherent feature of the main protection scheme, or separately by means of additional equipment. Time graded schemes such as over current or distance protection schemes are examples of those providing inherent back-up protection; the faulty section is normally isolated discriminatively by the time grading, but if the appropriate relay fails or the circuit breaker fails to trip, the next relay in the grading sequence will complete its operation and trip the associated circuit breaker, thereby interrupting the fault circuit one section further back. In this way complete back-up cover is obtained; one more section is isolated than is desirable but this is inevitable in the event of the failure of a circuit breaker. Where the system interconnection is more complex, the above operation will be repeated so that all parallel infeeds are tripped. If the power system is protected mainly by unit schemes, automatic back-up protection is not obtained, and it is then normal to supplement the main protection with time graded over current protection, which will provide local back-up cover if the main protective relays have failed, and will trip further back in the event of circuit breaker failure. Such back-up protection is inherently slower than the main protection and, depending on the power system configuration, may be less discriminative. For the most important circuits the performance may not be good enough, even as a backup protection, or, in some cases, not even possible, owing to the effect of multiple infeeds. In these cases duplicate high speed protective systems may be installed. These provide excellent mutual back-up cover against failure of the protective equipment, but either no remote back-up protection against circuit breaker failure or, at best, time delayed cover. Breaker fail protection can be obtained by checking that fault current ceases within a brief time interval from the operation of the main protection. If this does not occur, all other connections to the bus bar section are interrupted, the condition being necessarily treated as a bus bar fault. This provides the required back-up protection with the minimum of time delay, and confines the tripping operation to the one station, as compared with the alternative of tripping the remote ends of all the relevant circuits. The extent and type of back-up protection which is applied will naturally be related to the failure risks and relative economic importance of the system. For distribution systems where fault clearance Times are not critical, time delayed remote back-up protection is adequate but for EHV systems, where system stability is at risk unless a fault is cleared quickly, local back-up, as described above, should be chosen. Ideal back-up protection would be completely independent of the main protection. Current trans-formers, voltage transformers, auxiliary tripping relays, trip coils and D.C. supplies would be duplicated. This ideal is rarely attained in practice. The following compromises are typical:

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a. Separate current transformers (cores and secondary windings only) are used for each protective system, as this involves little extra cost or accommodation compared with the use of common current transformers which would have to be larger because of the combined burden. b. Common voltage transformers are used because duplication would involve a considerable increase in cost, because of the voltage transformers them-selves, and also because of the increased accommodation which would have to be provided. Since security of the VT output is vital, it is desirable that the supply to each protection should be separately fused and also continuously supervised by a relay which will give an alarm on failure of the supply and, where appropriate, prevent an unwanted operation of the protection. c. Trip supplies to the two protections should be separately fused. Duplication of tripping batteries and of tripping coils on circuit breakers is sometimes provided. Trip circuits should be continuously supervised. d. It is desirable that the main and back-up protections (or duplicate main protections) should operate on different principles, so that unusual events that may cause failure of the one will be less likely to affect the other.

Definitions and Terminology 1. All-or-nothing relay A relay which is not designed to have any specified accuracy as to its operating value. 2. Auxiliary relay. An all-or-nothing relay used to supplement the performance of another relay, by modifying contact performance for example, or by introducing time delays. 3. Back-up protection. A protective system intended to supplement the main protection in case the latter should be in-effective, or to deal with faults in those parts of the power system that are not readily included in the operating zones of the main protection. 4. Biased relay. A relay in which the characteristics are modified by the introduction of some quantity other than the actuating quantity, and which is usually in opposition to the actuating quantity. 5. Burden. The loading imposed by the circuits of the relay on the energizing power source or sources, expressed as the product of voltage and current (volt-amperes, or watts if D.C) for a given condition, which may be either at 'setting' or at rated current or voltage.

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The rated output of measuring transformers, expressed in VA, is always at rated current or voltage and it is important, in assessing the burden imposed by a relay, to ensure that the value of burden at rated current is used. 6. Characteristic angle. The phase angle at which the performance of the relay is declared. It is usually the angle at which maximum sensitivity occurs. 7. Characteristic curve. The curve showing the operating value of the characteristic quantity corresponding to various values or combinations of the energizing quantities. 8. Characteristic quantity. A quantity, the value of which characterizes the operation of the relay, e.g. current for an over current relay, voltage for a voltage relay, phase angle for a directional relay, time for an independent time delay relay, impedance for an impedance relay. 9. Characteristic impedance ratio (C.I. R.) The maximum value of the System Impedance Ratio up to which the relay performance remains within the prescribed limits of accuracy. 10. Check protective system. An auxiliary protective system intended to prevent tripping due to inadvertent operation of the main protective system. 11. Conjunctive test. A test on a protective system including all relevant components and ancillary equipment appropriately interconnected. The test may be parametric or specific. a. Parametric conjunctive test. A test to ascertain the range of values that may be assigned to each parameter when considered in combination with other parameters, while still complying with the relevant performance requirements. b. Specific conjunctive test. A test to prove the performance for a particular application, for which definite values are assigned to each of the parameters. 12. Dependent time delay relay. A time delay relay in which the time delay varies with the value of the energizing quantity. 13. Discrimination. The quality whereby a protective system distinguishes between those conditions for which it is intended to operate and those for which it shall not operate. 14. Drop-out. A relay drops out when it moves from the energized position to the un-energized position.

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15. Drop-out / pick ratio. The ratio of the limiting values of the characteristic quantity at which the relay resets and operates. This value is sometimes called the differential of the relay. 16. Earth fault protective system. A protective system which is designed to respond only to faults to earth. 17. Earthing transformer. A three-phase transformer intended essentially to provide a neutral point to a power system for the purpose of Earthing. 18. Effective range The range of values of the characteristic quantity or quantities, or of the energizing quantities to which the relay will respond and satisfy the requirements concerning it, in particular those concerning precision. 19. Effective setting The 'setting' of a protective system including the effects of current transformers. The effective setting can be expressed in terms of primary current or secondary current from the current transformers and is so designated as appropriate. 20. Electrical relay A device designed to produce sudden predetermined changes in one or more electrical circuits after the appearance of certain conditions in the electrical circuit or circuits controlling it. NOTE: The term 'relay' includes all the ancillary equipment calibrated with the device. 21. Energizing quantity. The electrical quantity, either current or voltage, which alone or in combination with other energizing quantities, must be applied to the relay to cause it to function. 22. Independent time delay relay. A time delay relay in which the time delay is independent of the energizing quantity. 21. Instantaneous relay. A relay which operates and resets with no intentional time delay. NOTE: All relays require some time to operate; it is possible, within the above definition, to discuss the operating time characteristics of an instantaneous relay. 22. Inverse time delay relay. A dependent time delay relay having an operating time which is an inverse function of the electrical characteristic quantity. 23. Inverse time delay relay with definite minimum (I.D. M . T.) A relay in which the time delay varies inversely with the characteristic quantity up to a certain value, after which the time delay becomes substantially independent.

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24. Knee-point e.m.f. That sinusoidal e.m.f. applied to the secondary terminals of a current transformer, which, when increased by 10 %, causes the exciting current to increase by 50%. 25. Main protection. The protective system which is normally expected to operate in response to a fault in the protected zone. 26. Measuring relay. A relay intended to operate with a specified accuracy at one or more values of its characteristic quantity. 27. Notching relay. A relay which switches in response to a specific number of applied impulses. 28. Operating time. With a relay de-energized and in its initial condition, the time which elapses between the application of a characteristic quantity and the instant when the relay operates. 29. Operating time characteristic. The curve depicting the relationship between different values of the characteristic quantity applied to a relay and the corresponding values of operating time. 30. Operating value. The limiting value of the characteristic quantity at which the relay actually operates. 31. Overshoot time. The extent to which the condition that leads to final operation is advanced after the removal of the energizing quantity, expressed as time at the rate of progress of the said condition appropriate to the value of the energizing quantity that was initially applied. 32. Pick-up. A relay is said to 'pick-up' when it changes from the un-energized position to the energized position. 33. Pilot channel. A means of interconnection between relaying points for the purpose of protection. 34. Protected zone. The portion of a power system protected by a given protective system or a part of that protective system. 35. Protective gear. The apparatus, including protective relays, trans-formers and ancillary equipment, for use in a protective system.

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36. Protective relay. A relay designed to initiate disconnection of a part of an electrical installation or to operate a warning signal, in the case of a fault or other abnormal condition in the installation. A protective relay may include more than one unit electrical relay and accessories. 37. Protective scheme. The coordinated arrangements for the protection of one or more elements of a power system. A protective scheme may comprise several protective systems. 38. Protective system. A combination of protective gear designed to secure, under predetermined conditions, usually abnormal, the disconnection of an element of a power system, or to give an alarm signal, or both. 39. Rating. The nominal value of an energizing quantity which appears in the designation of a relay. The nominal value usually corresponds to the CT and VT secondary ratings. 40. Resetting value. The limiting value of the characteristic quantity at which the relay returns to its initial position. 41. Residua/ current. The algebraic sum, in a multi-phase system, of all the line currents. 42. Residua/ voltage. The algebraic sum, in a multi-phase system, of all the line-to-earth voltages. 43. Setting. The limiting value of a 'characteristic' or 'energizing' quantity at which the relay is designed to operate under specified conditions. Such values are usually marked on the relay and may be expressed as direct values, percentages of rated values, or multiples. 44. Stability. The quality whereby a protective system remains inoperative under all conditions other than those for which it is specifically designed to operate. 45. Stability limits. The R.M.S. value of the symmetrical component of the through fault current up to which the protective system remains stable. 46. Starting relay. A unit relay which responds to abnormal conditions and initiates the operation of other elements of the protective system. 47. System impedance ratio (S./.R.).

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The ratio of the power system source impedance to the impedance of the protected zone. 48. Through fault current. The current flowing through a protected zone to a fault beyond that zone. 49. Time delay. A delay intentionally introduced into the operation of a relay system. 50. Time delay relay. A relay having an intentional delaying device. 51. Unit electrical relay. A single relay which can be used alone or in combinations with others. 52. Unit protection. A protection system which is designed to operate only for abnormal conditions within a clearly defined zone of the power system. 53. Unrestricted protection. A protection system which has no clearly defined zone of operation and which achieves selective operation only by time grading. Fault Definitions and: For the purpose of this International Standard, the following definitions, some of them based on IEC 60050(191), IEC 60050(212) and IEC 60050(604) apply: 1- Fault An unplanned occurrence or defect in an item which may result in one or more failures of the item itself or of other associated equipment [IEC 604-02-011 NOTE - In electrical equipment, a fault may or may not result in damage to the insulation and failure of the equipment. 2- Non-damage fault A fault which does not involve repair or replacement action at the point of the fault NOTE - Typical examples are self-extinguishing arcs in switching equipment or general overheating without paper carbonization. [IEC 604-02-091 3- Damage fault A fault which involves repair or replacement action at the point of the fault [IEC 604-02-08, modified] 4- Incident An event related to an internal fault which temporarily or permanently disturbs the normal operation of an equipment [IEV 604-02-03, modified]

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NOTE - Typical examples are gas alarms, equipment tripping or equipment leakage. 5- Failure The termination of the ability of an item to perform a required function [IEC 191-04-01] NOTE - In the electrical equipment, failure will result from a damage fault or incident necessitating outage, repair or replacement of the equipment, such as internal breakdown, rupture of tank, fire or explosion. 6- Electrical fault a partial or disruptive discharge through the insulation. 7- Partial discharge A discharge which only partially bridges the insulation between conductors. It may occur inside the insulation or adjacent to a conductor [IEC 212-01-34, modified] NOTE 1 - Corona is a form of partial discharge that occurs in gaseous media around conductors which are remote from solid or liquid insulation. This term is not to be used as a general term for all forms of partial discharges. NOTE 2 - X-wax is a solid material which is formed from mineral insulating oil as a result of electrical discharges and which consists of polymerized fragments of the molecules of the original liquid [IEV 212-07-24, modified]. Comparable products may be formed from other liquids under similar conditions. NOTE 3 - Sparking of low energy, for example because of metals or floating potentials, is sometimes described as Partial discharge but should rather be considered as a discharge of low energy. 8- Discharge (disruptive) . The passage of an arc following the breakdown of the insulation [IEC 604-03-38, modified] NOTE 1 - Discharges are often described as arcing, breakdown or short circuits. The more specific following terms are also used: - spark over (discharge through the oil); - puncture (discharge through the solid insulation); - Flashover (discharge at the surface of the solid insulation); - tracking (the progressive degradation of the surface of solid insulation by local Discharges to form conducting or partially conducting paths); - sparking discharges which, in the conventions of physics, are local Dielectric breakdowns of high ionization density or small arcs.

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NOTE 2 - Depending on the amount of energy contained in the discharge, it will be described as a discharge of low or high energy, based on the extent of damage observed on the equipment . 9- Thermal fault Excessive temperature rise in the insulation NOTE - Typical causes are - Insufficient cooling, - Excessive currents circulating in adjacent metal parts (as a result of bad Contacts, eddy currents, stray losses or leakage flux), - Excessive currents circulating through the insulation (as a result of high Dielectric losses), leading to a thermal runaway, - overheating of internal winding or bushing connection lead. 10- Typical values of gas concentrations. gas concentrations normally found in the equipment in service which have no symptoms of failure, and which are over passed by only an arbitrary percentage of higher gas contents, for example 10 % . NOTE 1 - Typical values will differ in different types of equipment and in different networks, depending on operating practices (load levels, climate, etc.). NOTE 2 - Typical values, in many countries and by many users, are quoted as "normal values", but this term has not been used here to avoid possible misinterpretations.

LIST OF DEVICE NUMBERS 2 Time delay starting or closing relay. 3 Checking or interlocking relay 21 Distance relay 25 Synchronizing or synchronism check relay 27 Under voltage relay 30 Annunciator relay 32 Directional power relay 273

37 Undercurrent or under power relay 40 Field failure relay 46 Reverse phase or phase balance current relay 49 Machine or transformer thermal relay 50 Instantaneous over current or rate-of-rise relay 51 A.c. time over current relay 52 A.c. circuit breaker 52a Circuit breaker auxiliary switch—normally open 52b Circuit breaker auxiliary switch—normally closed 55 Power factor relay 56 Field_application relay 59 Over voltage relay 60 Voltage or current balance relay 64 Earth fault protective relay 67 A.c. directional over current relay 68 Blocking relay 74 Alarm relay 76 D.c. over current relay 78 Phase angle measuring or out-of-step protective relay 79 A.c. reclosing relay 81 Frequency relay 83 Automatic selective control or transfer relay 85 Carrier or pilot wire receive relay 86 Locking-out relay 87 Differential protective relay 94 auxiliary tripping relay For Detail about LIST OF DEVICE NUMBERS Click Here Relay contact systems Relay contact systems a.

Self-reset. The contacts remain operated only while the controlling quantity is applied, returning to their original condition when it is removed. b.

Hand or electrical reset. These contacts remain in the operated position after the controlling quantity is removed. They can be reset either by hand or by an auxiliary electromagnetic element. The majority of protective relay elements have self-reset contact systems, which, if it is so desired, can be made to give hand reset output contacts by the use of auxiliary elements. Hand or electrically reset relays are used when it is necessary to maintain a signal or a lock-out condition. Contacts are shown on diagrams in the position corresponding to the un-operated or de-energized condition regardless of the continuous service condition of the equipment. For example, a voltage

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supervising relay, which is continually picked-up, would still be shown in the deenergized condition. A 'make' contact is one that closes when the relay picks up, whereas a 'break' contact is one that is closed when the relay is un-energized and opens when the relay picks up. Examples of these conventions and variations are shown in Figure 6.

Figure 6 indications of contacts on diagrams. A protective relay is usually required to trip a circuit breaker, the tripping mechanism of which may be a solenoid with a plunger acting directly on the mechanism latch or, in the case of air-blast or pneumatically operated breakers, an electrically operated valve. The relay may energize the tripping coil directly, or, according to the coil rating, and the number of circuits to be energized, may do so through the agency of another multi-channel auxiliary relay. The power required by the trip coil of the circuit breaker may range from up to 50 watts, for a small 'distribution' circuit breaker, to 3000 watts for a large extra-high-voltage circuit breaker. The basic trip circuit is simple, being made up of a hand-trip control switch and the contacts of the protective relays in parallel to energize the trip coil from a battery, through a normally open auxiliary switch operated by the circuit breaker. This auxiliary switch is needed to open the trip circuit when the circuit breaker opens, since the protective relay contacts will usually be quite incapable of performing the interrupting duty. The auxiliary switch will be adjusted to close as early as possible in the closing stroke, to make the protection effective in case the breaker is being closed on to a fault. Protective relays are precise measuring devices, the contacts of which should not be expected to perform large making and breaking duties. Attracted armature relays, which combine many of the characteristics of measuring devices and contactors, Occupy an intermediate position and according to their design and consequent closeness to one or other category, may have an appreciable contact capacity. Most other types of relay develop an effort which is independent of the position of the moving system. 275

At setting, the electromechanical effort is absorbed by the controlling force, the margin for operating the contacts being negligibly small. Not only does this limit the 'making' capacity of the contacts, but if more than one contact pair is fitted any slight misalignment may result in only one contact being closed at the minimum operating value, there being insufficient force to compress the spring of the first contact to make, by the small amount required to permit closure of the second. For this reason, the provision of multiple contacts on such elements is undesirable. Although two contacts can be fitted, care must be taken in their alignment, and a small tolerance in the closing value of operating current may have to be allowed between them. These effects can be reduced by providing a small amount of 'run-in' to contact make in the relay behavior, by special shaping of the active parts. For the above reasons it is often better to use inter-posing contactor type elements which do not have the same limitations, although some measuring relay elements are capable of tripping the smaller types of circuit breaker directly. These may be small attracted armature type elements fitted in the same case as the measuring relay. In general, static relays have discrete measuring and tripping circuits, or modules. The functioning of the measuring modules will not react on the tripping modules. Such a relay is equivalent to a sensitive electromechanical relay with a tripping contactor, so that the number or rating of outputs has no more significance than the fact that they have been provided. For larger switchgear installations the tripping power requirement of each circuit breaker is considerable, and, further, two or more breakers may have to be tripped by one protective system. There may also be remote signaling requirements, interlocking with other functions (for example auto-reclosing arrangements), and other control functions to be performed. These various operations are carried out by multi-contact tripping relays, which are energized by the protection relays and provide the necessary number of adequately rated output contacts. Operation indicators. As a guide for power system operation staff, protective systems are invariably provided with indicating devices. In British practice these are called 'flags', whereas in America they are known as 'targets'. Not every component relay will have one, as indicators are arranged to operate only if a trip operation is initiated. Indicators, with very few exceptions, are bi-stable devices, and may be either mechanically or electrically operated. A mechanical indicator consists of a small shutter which is Released by the protective relay movement to expose the indicator pattern, which, on GEC Measurements relays, consists of a red diagonal stripe on a white background. Electrical indicators may be simple attracted armature elements either with or without contacts. Operation of the armature releases a shutter to expose an indicator as above. An alternative type consists of a small cylindrical permanent magnet magnetized across a diameter, and lying between the poles of an electromagnet. The magnet, which is free to rotate, lines up its magnetic axis with the electromagnet poles, but can be made to reverse its orientation by the application of a field. The edge of the magnet is colored to give the indication.

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Relay tripping circuits. Auxiliary contactors can be used to supplement protective relays in a number of ways: a. Series sealing. b. Shunt reinforcing. c. Shunt reinforcement with sealing. These are illustrated in Figure 7. When such auxiliary elements are fitted, they can conveniently carry the operation indicator, avoiding the need for indicators on the measuring elements. Electrically operated indicators avoid imposing an additional friction load on the measuring element, which would be a serious handicap for certain types. Another advantage is that the indicator can operate only after the main contacts have closed.

Figure 7 Typical relay tripping circuits. With indicators operated directly by the measuring elements, care must be taken to line up their operation with the closure of the main contacts. The indicator must have operated by the time the contacts make, but must not have done so more than marginally earlier. This is to stop indication occurring when the tripping operation has not been completed. Ta.

Series sealing. The coil of the series contactor carries the trip current initiated by the protective relay, and the contactor closes a contact in parallel with the protective relay contact. This closure relieves the protective relay contact of further duty and keeps the tripping circuit securely closed, even if chatter occurs at the main contact.

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Nothing is added to the total tripping time, and the indicator does not operate until current is actually flowing through the trip coil. The main disadvantage of this method is that such series elements must have their coils matched with the trip circuit with which they are associated. The coils of these contactors must be of low impedance, with about 5 % of the trip supply voltage being dropped across them. When used in association with high speed trip relays, which usually interrupt their own coil current, the auxiliary elements must be fast enough to operate and release the flag before their coil current is cut off. This may pose a problem in design if a variable number of auxiliary elements (for different phases and so on) may be required to operate in parallel to energize a common tripping relay. b.

Shunt reinforcing. Here the sensitive contacts are arranged to trip the circuit breaker and simultaneously to energize the auxiliary unit, which then reinforces the contact which is energizing the trip coil. It should be noted that two contacts are required on the protective relay, since it is not permissible to energize the trip coil and the reinforcing contactor in parallel. If this were done, and more than one protective relay were connected to trip the same circuit breaker, all the auxiliary relays would be energized in parallel for each relay operation and the indication would be confused. The duplicate main contacts are frequently provided As a three point arrangement to reduce the number of contact fingers.

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Figure 8 Examples of trip circuit supervision. c.

Shunt reinforcement with sealing. This is a development of the shunt reinforcing circuit to make it applicable to relays with low torque movements or where there is a possibility of contact bounce for any other reason. Using the shunt reinforcing system under these circumstances would result in chattering on the auxiliary unit, and the possible burning out of the contacts not only of the sensitive element but also of the auxiliary unit. The chattering would only end when the circuit breaker had finally tripped. It will be seen that the effect of bounce is countered by means of a further contact on the auxiliary unit connected as a retaining contact. This means that provision must be made for releasing the sealing circuit when tripping is complete; this is a disadvantage, because it is sometimes inconvenient to find a suitable contact to use for this purpose. Supervision of trip circuits. The trip circuit extends beyond the relay enclosure and passes through more components, such as fuses, links, relay contacts, auxiliary switch contacts and so on, and in some cases through a considerable amount of circuit wiring with intermediate terminal boards.

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These complications, coupled with the importance of the circuit, have directed attention to its supervision. The simplest arrangement contains a healthy trip lamp, as shown in Figure 8(a). The resistance in series with the lamp prevents the breaker being tripped by an internal short circuit caused by failure of the lamp. This provides supervision while the circuit breaker is closed; a simple extension gives pre-closing supervision. Figure 1.8(b) shows how, by the addition of a normally closed auxiliary switch and a resistance unit, supervision can be obtained while the breaker is both open and closed. I n either case, the addition of a normally open push-button contact in series with the lamp will make the supervision indication available only when required. Schemes using a lamp to indicate continuity are suitable for locally controlled installations, but when control is exercised from a distance it is necessary to use a relay system. Figure 8(c) illustrates such a scheme, which is applicable wherever a remote signal is required. With the circuit healthy either or both of relays A and B are operated and energize relay C. Both A and B must reset to allow C to drop-off. Relays A and C are timedelayed by copper slugs to prevent spurious alarms during tripping or closing operations. The resistors are mounted separately from the relays and their values are chosen such that if any one component is inadvertently short-circuited, a tripping operation will not take place. The alarm supply should be independent of the tripping supply so that indication will be obtained in the event of the failure of the tripping battery. Classification and function of relays A protection relay is a device that senses any change in the signal which it is receiving, usually from a current and/or voltage source. If the magnitude of the incoming signal is outside a preset range, the relay will operate, generally to close or open electrical contacts to initiate some further operation, for example the tripping of a circuit breaker. 3.1 Classification: Protection relays can be classified in accordance with the function which they carry out, their construction, the incoming signal and the type of functioning. 3.1.1 General function: Auxiliary. Protection. Monitoring. Control. 3.1.2 Construction: Electromagnetic. Solid state. Microprocessor. Computerized. 280

Nonelectric (thermal, pressure ......etc.). 3.1.3 Incoming signal: Current. Voltage. Frequency. Temperature. Pressure. Velocity. Others. 3.1.4 Type of protection Over current. Directional over current. Distance. Over voltage. Differential. Reverse power. Other.

Figure 1 Armature-type relay In some cases a letter is added to the number associated with the protection in order to specify its place of location, for example G for generator, Τ for transformer etc. Nonelectric relays are outside the scope of this book and therefore are not referred to. 3.2 Electromagnetic relays Electromagnetic relays are constructed with electrical, magnetic and mechanical components, have an operating coil and various contacts and are very robust and reliable. The construction characteristics can be classified in three groups, as detailed below. 3 . 2 . 1 Attraction relays

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Attraction relays can be supplied by AC or DC, and operate by the movement of a piece of metal when it is attracted by the magnetic field produced by a coil. There are two main types of relay in this class. The attracted armature relay, which is shown in figure 1, consists of a bar or plate of metal which pivots when it is attr acted towards the coil. The armature carries the moving part of the contact, which is closed or opened according to the design when the armature is attracted to the coil. The other type is the piston or solenoid relay, illustrated in Figure 2, in which α bar or piston is attracted axially within the field of the solenoid. In this case, the piston also carries the operating contacts. It can be shown that the force of attraction is equal to K1I2 - K2, where Κ1 depends upon the number of turns on the operating solenoid, the air gap, the effective area and the reluctance of the magnetic circuit, among other factors. K2 is the restraining force, usually produced by a spring. When the relay is balanced, the resultant force is zero and therefore Κ112 = K2, So that

I =

K 2 / K 1 =constant.

In order to control the value at which the relay starts to operate, the restraining tension of the spring or the resistance of the solenoid circuit can be varied, thus modifying the restricting force. Attraction relays effectively have no time delay and, for that reason, are widely used when instantaneous operations are required. 3 . 2 . 2 Relays with moveable coils This type of relay consists of a rotating movement with a small coil suspended or pivoted with the freedom to rotate between the poles of a permanent magnet. The coil is restrained by two springs which also serve as connections to carry the current to the coil. The torque produced in the coil is given by: T = B.l.a.N.i Where: T= torque B = flux density L =length of the coil a = diameter of the coil N = number of turns on the coil i = current flowing through the coil

282

Figure 2 Solenoid-type relay

Figure 3 Inverse time characteristic From the above equation it will be noted that the torque developed is proportional to the current. The speed of movement is controlled by the damping action, which is proportional to the torque. It thus follows that the relay has an inverse time characteristic similar to that illustrated in Figure 3. The relay can be designed so that the coil makes a large angular movement, for example 80º. 3 . 2 . 3 Induction relays An induction relay works only with alternating current. It consists of an electromagnetic system which operates on a moving conductor, generally in the form of a disc or cup, and functions through the interaction of electromagnetic fluxes with the parasitic Fault currents which are induced in the rotor by these fluxes. These two fluxes, which are mutually displaced both in angle and in position, produce a torque that can be expressed by T= Κ1.Φ1.Φ2 .sin θ,

283

Where Φ1 and Φ2 are the interacting fluxes and θ is the phase angle between Φ1 and Φ2. It should be noted that the torque is a maximum when the fluxes are out of phase by 90º, and zero when they are in phase.

Figure 4 Electromagnetic forces in induction relays It can be shown that Φ1= Φ1sin ωt, and Φ2= Φ2 sin (ωt+ θ ) , where θ is the angle by which Φ2 leads Φ1. Then:

iΦ 1 α

dΦ 1 α Φ 1 cos ω t dt

And

iΦ1 α

dΦ1 α Φ1 cos ( ωt + θ ) dt

Figure 4 shows the interrelationship between the currents and the opposing forces. Thus: F = ( F 1 - F 2 ) α (Φ2 iΦ1+ Φ1 iΦ2 ) ∴

F α Φ2 Φ1 sin θ α T

Induction relays can be grouped into three classes as set out below. Shaded-pole relay In this case a portion of the electromagnetic section is short-circuited by means of a copper ring or coil. This creates a flux in the area influenced by the short circuited section (the so-called shaded section) which lags the flux in the nonshaded section, see Figure 5.

284

Figure 5 Shaded-pole relay

Figure 6 Wattmetric-type relay In its more common form, this type of relay uses an arrangement of coils above and below the disc with the upper and lower coils fed by different values or, in some cases, with just one supply for the top coil, which induces an out-of-phase flux in the lower coil because of the air gap. Figure 6 illust r ates a typical arrangement. Cup-type relay This type of relay has a cylinder similar to a cu which can rotate in the annular air gap between the poles of the coils, and has a fixed central core, see Figure 7. The operation of this relay is very similar to that

285

Figure 7Cup-type relay Of an induction motor with salient poles for the windings of the stator. Configurations with four or eight poles spaced symmetrically around the circumference of the cup are often used. The movement of the cylinder is limited to a small amount by the contact and the stops. Α special spring provides the restraining torque. The torque is a function of the product of the two currents through the coils and the cosine of the angle between them. The torque equation is T= ( KI1I2 cos (θ12 – Φ) – Ks ), Where K, .Κs and Φ are design constants, Ι1 and I2 are the currents through the two coils and θ12 is the angle between I1 and I2. In the first two types of relay mentioned above, which are provided with a disc, the inertia of the disc provides the time-delay characteristic. The time delay can be increased by the addition of a permanent magnet. The cup-type relay has a small inertia and is therefore principally used when high speed operation is required, for example in instantaneous units.

Calculation of short circuit current The current that flows through an element of a power system is a parameter which can be used to detect faults, given the large increase in current flow when a short circuit occurs. For this reason a review of the concepts and procedures for calculating fault currents will be made in this chapter, together with some calculations illustrating the methods used. Although the use of these short-circuit calculations in relation to protection settings will be-considered in detail, it is important to bear in mind that these calculations are also required for other applications, for example calculating the substation Earthing 286

grid, the selection of conductor sizes and for the specifications of equipment such as power-circuit breakers. 1 Mathematical derivation of fault currents The treatment of electrical faults should be carried out as a function of time, t = 0+

from the start of the event at time until stable conditions are reached, and therefore it is necessary to use differential equations when calculating these currents. In order to illustrate the transient nature of the current, consider an RL circuit as a simplified equivalent of the circuits in electricitydistribution networks. This simplification is important because all the system equipment must be modeled in some way in order to quantify the transient values which can occur during the fault condition. For the circuit shown in Figure 1, the mathematical expression which defines the behaviour of the current is: e(t) = L di + Ri(t)

2.1

Vmax Sin( ωt + α ) R

Figure 1 RL, circuit for transient analysis study This is a differential equation with constant coefficients, of which the solution is in two parts:

ia ( t ) : ih ( t ) + i p ( t ) Where: ih(t) Is the solution of the homogeneous equation corresponding to the transient period and ip(t) is the solution to the particular equation corresponding to the steady-state period. By the use of differential equation theory, which will not be discussed in detail here, the complete solution can be determined and expressed iii the following form:

i (t ) =

Vmax ( Sin (ω t + α ) − Sin(α − Φ).e −( R / L ) ) Z

287

2.2

Where: Z =

R 2 + ω2 L2

α = the closing angle which defines the point on the source sinusoidal voltage when the fault occurs and Φ= tan −1 (ωL / R )

It can be seen that, in eqn. 2.2, the first term varies sinusoidally, while the second term decreases exponentially with a time constant of L/R. The latter term can be recognised as the DC component of the current, and has an initial maximum π value when α , and zero value when Φ=α, see Figure 2. It is impossible to predict at what point the fault will be applied on the sinusoidal cycle and therefore what magnitude the DC component will reach. If the tripping of the circuit, owing to a fault, takes place when the sinusoidal component is at its negative peak, the DC component reaches its theoretical maximum value half a cycle later. − Φ =± / 2

Figure 2 Variation of fault current with time a (α–Φ) =0 b (α–Φ)=π/2 288

An approximate formula for calculating the effective value of the total asymmetric current, including the AC and DC components, with acceptable accuracy can be obtained from the following expression:

I rms.asym =

2 2 I rms + I DC

2.3

The fault current which results when an alternator is short circuited can easily be analysed since this is similar to the case which has already been analysed, i.e. when voltage is, applied to an RL circuit. The reduction in current from its value at the onset, owing to the gradual decrease in the magnetic flux caused by the reduction of the e.m.f. of the induction current, can be seen in Figure 3. This effect is known as armature reaction. The physical situation that is presented to a generator, and which makes the calculations quite difficult, can be interpreted as a reactance which varies with time. Notwithstanding this, in the majority of practical applications it is possible to take account of the variation of reactance in only three stages without producing significant errors. In Figure 4 it will be noted that the variation of current with time, 1(t), comes close to the three discrete levels of current, I", 1 ' and I, the subtransient, transient and steady-state currents, respectively. The corresponding values of direct axis reactance are denoted by

X d" , X d'

and Xd,

Figure 3 Transient short-circuit currents in a synchronous generator

289

Figure 4 Variation of current with time during a fault

Figure 5 Variation of generator reactance with time during a fault And the typical variation with, time for each of these is illustrated in Figure 5. To sum up, when calculating short-circuit currents it is necessary to take into account two factors which could result in the currents varying with time: the presence of the DC component; the behaviour of the generator under short circuit conditions. In studies of electrical protection some adjustment has to be made to the values of instantaneous short circuit current calculated using subtransient reactance's which result in higher values of current. Time delay units can be set using the same values but, in some cases, short-circuit values based on the transient reactance are used, depending on the operating speed of the protection relays. Transient reactance values are generally used in stability studies. Of necessity, switchgear specifications require reliable calculations of the short-circuit levels which can be present on the electrical network. Taking into account the rapid drop of the short-circuit current due to the armature reaction of the synchronous machines, and the fact that extinction of an electrical arc is never achieved instantaneously, ANSI Standards C37.010 and C37.5 recommend using different values of subtransient reactance when calculating the so-called momentary and interrupting duties of switchgear.

290

Asymmetrical or symmetrical r.m.s. values can be defined depending on whether or not the DC component is included. The peak values are obtained by multiplying the R.M.S. values by

2

.

The asymmetrical values are calculated as the square root of the sum of the squares of the DC component and the r.m.s. value of the AC current, i.e.:

= (0.9 2V / X d" ) 2 + (0.9V / X d" ) 2 I rms =

2 2 I DC + I AC

2.4

The momentary current is used when specifying the closing current of switchgear. Typically, the AC and DC components decay to 90% of their initial values after the first half cycle. From this, the value of the r.m.s. current would then be: 2 I rms .asym .clo sin g =

2 I DC + I AC .rms . sys

= (0.9 2V / X d" ) 2 + (0.9V / X d" ) 2

=1.56V / X d" =1.56 I rms.sym

2.5

Usually, a factor of 1.6 is used by manufacturers and in international standards so that, in general, this value should be used when carrying out similar calculations. The peak value is obtained by arithmetically adding together the AC and DC components. It should be noted that, in this case, the AC component is multiplied by a factor of

2

Thus:

I peak = I Dc + I AC = (0.9

2 V / X d" ) + (0.9

= 2.55 I rms.sym

2 V / X d" )

2.6

When considering the specification for the switchgear-opening cur-rent, the so-called r.m.s. value of interrupting current is used in which, again, the AC and DC components are taken into account, and therefore: Replacing the DC component by its exponential expression gives:

291

2 2 I rms I DC + I Ac.rms . int .asym. int = 2 I rms .sym.int = ( 2 I rms. sym.int e −( R / L ) ) 2 + I rms . sym. int

= I rms .sym.int

2e −2 ( r / l ) t +1

2.7

I rms . asym. int / I rms . sys . int

The expression ( ) has been drawn for different Values of X/R, and for different switchgear contact-separation times, in ANSI Standard C37.5–1979. The multiplying factor graphs are reproduced in Figure 6

Figure 6 Multiplying factors for three-p hase and line-to-earth faults (total current rating basis) (from. IEEE Standard C37.5-1979; reproduced by permission of the IEEE)

NOTE: Fed predominantly through two or more transformations or with external reactance in series equal to or above 1.5 times generator subtransient reactance 292

As an illust r ation of the validity of the curves for any situation, Consider a circuit breaker with a total contact-separation time of two c yc l e s o n e cycle due to the relay and one related to the operation of the breaker mechanism. If the frequency, f is 60 Hz and the ratio X/R With this arrangement, voltage values of any three-phase system, Va Vb and Vc can be represented thus: Va =Vao + Va1 + Va2 Vb =Vbo + Vb1 + Vb2 Vc =Vco + Vc1 + Vc2 It can be demonstrated that: V b= V ao+a 2V a1+aV a2 V c= V ao+aV a1+ a 2V a2 where a is a so called operator which gives a phase shift of 120° clockwise and a multiplication of unit magnitude, i.e. a=1 °, 2 and a similarly gives a phase shift of 240°, i.e. a 2=1 Therefore, the following matrix relationship can be established: ∠120

∠240°

Va  1 1 1  Va 0  V  = 1 a a 2  × V    a1   b  Vc  1 a 2 a  Va 2  Inverting the matrix of coefficients:

1 1 1  V a  Va 0  V  = 1 1 a a 2  × V    b  a1  3  1 a 2 a  Vc  Va 2    From the above matrix it can be deduced that:

293

1 Va 0 = (Va + Vb + Vc ) 3 1 Va1 = (Va + aVb + a 2Vc ) 3 1 Va 2 = (Va + a 2Vb + aVc ) 3 The foregoing procedure can also be applied directly to currents, and gives:

I a = I a 0 + I a1 + I a 2 I b = I a 0 + a 2 I a1 + aI a 2 I b = I a 0 + a I a1 + a 2 I a 2 Therefore:

1 I a0 = (I a + Ib + Ic ) 3 1 I a1 = ( I a + aI b + a 2 I c ) 3 1 I a 2 = ( I a + a 2 I b + aI c ) 3 In three-phase systems, the neutral current is equal to In = (Ia + Ib + Ic) and, therefore, l n= 3 I 0 By way of illustration, a three-phase unbalanced system is shown in Figure 8 together with the associated symmetrical components.

294

295

2.1 Importance and construction of sequence networks The impedance of a circuit in which only positive-sequence currents are circulating is called the positive-sequence impedance and, similarly, those in which only negative and zero-sequence currents flow are called the negative and zero-sequence impedances. These sequence impedances are designated Z1, Z2 and Z0, respectively, and are used in calculations involving symmetrical components. Since generators are designed to supply balanced voltages, the generated voltages are of positive sequence only. Therefore, the positive-sequence network is composed of an e.m.f source in series with the positive-sequence impedance. The negative and zero-sequence net-works do not contain e.m.f but only include impedances to the flow of negative and zerosequence currents, respectively. The positive- and negative-sequence impedances of overhead-line circuits are identical, as are those of cables, being independent of the phase if the applied voltages are balanced. The zero-sequence impedances of lines different from the positive and negative-sequence impedances since the magnetic field creating the positive and negative-sequence currents is different from that for the zero-sequence currents. The following ratios may be used in the absence of detailed information. For a single-circuit line, Zo/Z1 = 2 when no earth wire is present and 3.5 with an earth wire. For a double-circuit line Zo/Z1 = 5.5. For underground cables Zo/Z1 can be taken as 1 to 1.25 for single core, and 3 to 5 for three-core cables: For transformers, the positive and negative-sequence impedances are equal because in static circuits these impedances are independent of the phase order, provided that the applied voltages are balanced. The zero-sequence impedance is either the same as the other two impedances, or infinite, depending on the transformer connections. The resistance of the windings is much smaller and can generally be neglected in short-circuit calculations. When modelling small generators and motors it may be necessary to take resistance into account. However, for most studies only the reactance's of synchronous machines are used. Three values of positive reactance are normally quoted-subt r ansient, transient and synchronous reactance, denoted by X", Xd' and Xd. In fault studies the subtransient and transient reactance of generators grid motors must be included as appropriate, depending on the machine characteristics and fault clearance time. Table 1 Typical per-unit reactance for three -phase synchronous machines Type of machine

X d"

X d'

Xd

X2

X0

Turbine

2 pole

0.09

0.15

1.20

0.09

0.03

generator

4 pole

0.14

0.22

1.70

0.14

0.07

0.20

0.30

1.25

0.20

0.18

0.28

0.30

1.20

0.35

0.12

Salient with pole dampers generator without

296

dampers X"= subtransient reactance; X'd =transient reactance; Xd=synchronous reactance X.2=negative sequence reactance; X0=zero sequence reactance

The subtransient reactance is the reactance applicable at the onset of the fault occurrence. Within 0.1 sec. the fault level falls to a value determined by the transient reactance and then decays exponentially to a steady-state value determined by the synchronous reactance. Typical per-unit reactance's for three phase synchronous machines are given in Table 1. In connecting sequence networks together, the reference busbar for the positiveand negative-sequence networks is the generator neutral which, in these networks, is at earth potential so that only zero-sequence currents flow through the impedances between neutral and earth. The reference busbar for zero-sequence networks is the earth point of the generator. The current which flows in the impedance between the neutral and earth are three times the zero-sequence current. Figure 2.9 illustrates the sequence networks for a generator. The zero sequence networks carries only zero-sequence current in one phase which has an impedance of Zo = 3Ζn + Zeo The voltage and current components for each phase are obtained from the equations given for the sequence networks. The equations for the components of voltage, corresponding to the phase of the system, are obtained from the point an on phase a relative to the reference bus bar, and can be deduced from Figure 2.9 as follows:

Va1 = E a − I a1 Z 1 Va 2 = − I a 2 Z 2 Va 0 = − I a 0 Z 0 Where Εa = no load voltage to earth of the positive-sequence network Z1 = positive-sequence impedance of the generator Z2 = negative-sequence impedance of the generator Zo= zero-sequence impedance of the generator (Zeo) plus three times the impedance to earth The above equations can be applied to any generator which carries unbalanced currents and are the starting point for calculations for any type of fault. The same approach can be used with equivalent power systems or applied to loaded

297

generators, Ea then being the voltage behind the reactance before the fault occurs. 2.2.2 Calculation of asymmetrical faults using symmetrical components The positive, negative and zero-sequence network, carrying currents I1, I2 and Io respectively, are connected together in a particular arrangement to represent a given unbalanced fault condition. Consequently, in order to calculate fault 1 levels using the method of symmetrical components, it is essential to determine the individual sequence impedances and combine these to make up the correct sequence networks. Then, for each .type of fault, the appropriate combination of sequence networks is formed in order to obtain the relationships between fault currents and voltages.

Phase-to-earth fault The conditions for a solid fault from line a to earth are represented by the equations Ib=0, Ic =0 and V a =0,

298

Single phase fault connected to earth

As in the previous equations, it can easily be deduced that I a1 = Ia2 = I ao = E a / (Z 1 +Z 2 + Z o ). Therefore, the sequence networks will be connected in series, as indicated in Figure 2.10a. The current and voltage conditions are the same when considering an open-circuit fault in phases b and c, and thus the treatment and connection of the sequence networks will be similar. Phase-to-Phase fault The conditions for a solid fault between lines h and c are represented by the equations

I a = 0, I b = –I c and V b = V c . Equally, it can be shown that I ao = 0 and I a1 = E a /(Z 1 +Z 2 ) = Ia2 . For this case, with no zero-sequence current, the zero-sequence network is not involved and the overall sequence network is composed of the positive- and negative-sequence networks in parallel as indicated in Figure 2.10b. Phase-to-Phase-to-earth fault

The conditions for a fault between lines b and c and earth are represented by the equations 1a = 0 and Vb=Vc =0. From these equations it can be proved that:

299

I a1 =

Ea ZoZ2 Z1 + Zo + Z2

The three sequence networks are connected in parallel as shown in Figure 2.10c. 2.3 Equivalent impedances for a power system. When it is necessary to study the effect of any change on the power system, the system must first of all be represented by its corresponding sequence impedances. The equivalent positive- and negative-sequence impedances can be calculated directly from: Z= V2/P Where: Z = Equivalent positive and negative-sequence impedances V =nominal phase-to-phase voltage P = three-phase short circuit power The equivalent zero-sequence of a system can be derived from the expressions of sequence components referred to for a single-phase fault, i.e. Ia1=Ia2=Ia3 = VLN/ (Z1 + Z2 + Z0) Where: VLN = the line-to-neutral voltage. For lines and cables the positive and negative ímpedances are equal. Thus, on the basis that the generator ímpedances are not significant in most distribution-network fault studies, it may be assumed that overall Ζ2 = Z1 which simplifies the calculations. Thus, the above formula reduces to Ia = 3I0 = 3 VLN / (2Z1 + Zo), Where VLN = line-to-neutral voltage and Zo= (3VLN / Ia) - 2Z1 3 Supplying the current and voltage signals to protection systems In the presence of a fault the current transformers (CTs) circulate current proportional to the fault current to the protection equipment without distinguishing between the vectorial magnitudes of the Sequence components.

300

Figure 10 Connection of sequence networks for a3ymmetrical faults a Phase-to-earth fault b Phase-to-phase fault c Double phase-to-earth fault Therefore, in the majority of cases, the relays operate on the basis of the corresponding values of fault current and / or voltages, regardless of the values of the sequence components. It is very important to emphasise that, given this, the advantage of using symmetrical components is that they facilitate the calculation of fault levels even though the relays in the majority of cases do not distinguish between the various values of the symmetrical components.

301

Figure 11a Currents and voltages for various types of faults

302

Figure 11b Currents and voltages for various types of faults a Sequence currents for different types of fault b Sequence voltages for different types of fault In Figure 11a & b the positive and negative sequence values of current and voltage for different faults are shown together with the summated values of current and voltage. Relays usually only operate using the summated values in the right-hand columns. However, relays are available which can operate with specific values of some of the sequence components.

303

In these cases there must be methods for obtaining these components, and this is achieved by using filters which produce the mathematical operations of the resultant equations to resolve the matrix for voltages and for currents. Although these filters can be constructed for electromagnetic elements, the growth of electronics has led to their being used increasingly in logic circuits. Among the relays which require this type of filter in order to operate are those used ιn negative-sequence and earth-fault protection. Current and voltage transformers Current or voltage instrument transformers are necessary for isolating the protection, control and measurement equipment from the high voltages of a power system, and for supplying the equipment with the appropriate values of current and voltage - generally these are 1A or 5Α for the current coils, and 120 V for the voltage coils. The behaviour of current and voltage transformers during and after the occurrence of a fault is critical in electrical protection since errors in the signal from a transformer can cause maloperation of the relays. In addition, factors such as the transient period and saturation must be taken into account when selecting the appropriate transformer. When only voltage or current magnitudes are required to operate a relay then the relative direction of the current flow in the transformer windings is not important. However, the polarity must be kept in mind when the relays compare the sum or difference of the currents. 1- Voltage transformers: With voltage transformers (VTs) it is essential that the voltage from the secondary winding should be as near as possible proportional to the primary voltage. In order to achieve this, VTs are designed in such a way that the voltage drops in the windings are small and the flux density in the core is well below the saturation value so that the magnetization current is small; in this way magnetization impedance is obtained which is practically constant over the required voltage range. The secondary voltage of a VT is usually 110 or 120 V with corresponding line-to-neutral values. The majority of protection relays have nominal voltages of 110 or 63.5 V, depending on whether their connection is lineto-line or line-to-neutral.

304

Figure 1 Voltage transformer equivalent circuits

Figure 2 Vector diagram for voltage transformer 1.1 Equivalent circuits VTs can be considered as small power transformers so that their equivalent circuit is the same as that for power transformers, as shown in Figure 1a. The magnetization branch can be ignored and the equivalent circuit then reduces to that shown in Fig 1b. The vector diagram for a VT is given in Figure.2, with the length of the voltage drops increased for clarity. The secondary voltage Vs lags the voltage Vp/n and is smaller in magnitude. In spite of this, the nominal maximum errors are relatively small. VTs have an excellent transient behaviour and accurately reproduce abrupt changes in. the primary voltage. 1.2 Errors When used for measurement instr uments, for example for billing and control purposes, the accuracy of a VT is important, especially for those values close to the nominal system voltage.

305

Notwithstanding this, although the precision requirements of a VT for protection applications are not so high at nominal voltages, owing to the problems of having to cope with a variety of different relays, secondary wiring burdens and the uncertainty of system parameters, errors should he contained within narrow limits over a wide range of possible voltages under fault conditions. This range should be between 5 and 173% of the nominal primary voltage for VTs connected between line and earth. Referring to the circuit in Figure 1a, errors in a VT are clue to differences in magnitude and phase between Vp/n, and Vs. These consist of the errors under open-circuit conditions when the load impedance Ζ B is infinite, caused by the drop in voltage from the circulation of the magnetization current through the primary winding, and errors due to voltage drops as a result of the load current IL flowing through both windings. Errors in magnitude can be calculated from Error V T = {(n Vs - Vp) / Vp} x 100%. If the error is positive, then the secondary voltage exceeds the nominal value. 1.3 Burden The standard burden for voltage transformer is usually expressed in voltamperes (VΑ) at a specified power factor. Table 1 gives standard burdens based on ANSI Standard C57.1 3. Voltage transformers are specified in IEC publication 1 8 6 Α by the precision class, and the value of volt-amperes (VΑ). The allowable error limits corresponding to different class values are shown in Table 2, where Vn is the nominal voltage. The phase error is considered positive when the secondary voltage leads the primary voltage. The voltage error is the percentage difference between the voltage at the secondary terminals, V2, multiplied by the nominal transformation ratio, and the primary voltages V1. 1.4 Selection of VTs Voltage transformers are connected between phases, or between phase and earth. The connection between phase and earth is normally used with groups of three single-phase units connected in star at substations operating with voltages at about 34.5 kV or higher, or when it is necessary to measure the voltage and power factor of each phase separately. The nominal primary voltage of a VT is generally chosen with the higher nominal insulation voltage (kV) and the nearest service voltage in mind. The nominal secondary voltages are generally standardized at 110 and 120 V. In order to select the nominal power of a VT, it is usual to acid together all the nominal VΑ loadings of the apparatus connected to Table 1 Standard burdens for voltage Transformer Standard burden

design

Voltamperes

power factor

Characteristics for 120 V and 60 Hz resistance( Ω )

inductance (H)

impedance (Ω)

306

Characteristics for 69.3 V and 60 Hz resistance (Ω)

inductance (H)

impedance (Ω)

W

12.5

0.10

115.2

3.040

1152

38.4

1.010

384

Χ

25.0

0.70

403.2

1.090

575

134.4

0.364

192

Υ

75.0

0.85

163.2

0.268

192

54.4

0.089

64

Ζ ΖΖ

200.0 400.0

0.85 0.85

61.2 31.2

0.101 0.0403

72 36

20.4 10.2

0.034 0.0168

24 12

Μ

35.0

0.20

82.3

1.070

411

27.4

0.356

137

Table 2 Voltage transformers error limits Class

0.1 0.2 0.5 1.0

0.1 0.2 0.5 1.0 0.1 0.2 0.5 1.0

Primary voltage

Voltage error (±%)

Phase error (±min)

0.1 0.2 0.5 1.0

0.5 10.0 20.0 40.0

0.5 Vn

1.0 1.0 1.0 2.0

40.0 40.0 40.0 80.0

Vn

0.2 2.0 2.0 3.0

80.0 80.0 80.0 120.0

0.8 Vn , 1.0 Vn and 1.2 Vn

Vn = nominal voltage The VT secondary winding. In addition, it is important to take account of the voltage drops in the secondary wiring, especially if the distance between the transformers and the relays is large. 1 .5 C a p a c i t o r v o l t a g e t r a n s f o rm e r s In general, the size of an inductive VT is proportional to its nominal voltage and, for this reason, the cost increases in a similar manner to that of a high voltage transformer. One alternative, and a more economic solution, is to use a capacitor voltage transformer. This device is effectively a capacitance voltage divider, and is similar to a resistive divider in that the output voltage at the point of connection is affected by the load - in fact the two parts of the divider taken together can be considered as the source impedance which produces a drop in voltage when the load is connected.

307

Figure 4 Capacitor VT equivalent circuit The capacitor divider differs from the inductive divider in that the equivalent impedance of the source is capacitive and the .fact that this impedance can be compensated for by connecting a reactance in series at the point of connection. With an ideal reactance there are no regulation problems - however, in an actual situation on a network, some resistance is always present. The divider can reduce the voltage to a value which enables errors to be kept within normally acceptable limits. For improved accuracy a high voltage capacitor is used in order to obtain a bigger voltage at the point of connection, which can be reduced to a standard voltage using a relatively inexpensive trans-former as shown in Figure 3. Α simplified equivalent circuit of a capacitor VT is shown in Figure 4 in which Vi is equal to the nominal primary voltage, C is the numerically equivalent impedance equal to ( C1 + C2 ), L is the resonance inductance, Ri represents the resistance of the primary winding of transformer Τ plus the losses in C and L, and Ze is the magnetization impedance of transformer Τ. Referred to the inter-mediate voltage, the resistance of the secondary circuit and the load impedance are Rs'

represented by and voltage and current.

Z B'

respectively, while

308

Vs'

and

Is'

represent the secondary

Figure 5 Capacitor VT vector diagram It can be seen that, with the exception of C, the circuit in Figure 4.4 is the same as the equivalent circuit of a power transformer. Therefore, at the system frequency when C and L are resonating and canceling out each other, under stable system conditions the capacitor VT acts like a conventional transformer. Ri and R's are not large and, in addition, Ie is small compared to I' s , so that the vector difference between Vi and V's which constitutes the error in the capacitor VT, is very small. This is illustrated in the vector diagram shown in Figure 4.5 which is drawn for a power factor close to unity. The voltage error is the difference in magnitude between Vi and V's, whereas the phase error is indicated by the angle θ. From the diagram it can be seen that, for frequencies different from the resonant frequency, the values of EL and EC predominate, causing serious errors in magnitude and phase. Capacitor VTs display better transient behaviour than electro-magnetic VTs as the inductive and capacitive reactance in series are large in relation to the load impedance referred to the secondary voltage, and thus, when the primary voltage collapses, the secondary voltage is maintained for some milliseconds because of the combination of the series and parallel resonant circuits represented by L, C and the transformer T. 2 Current transformers Although the performance required from a current transformer (CT) varies with the type of protection, high grade CTs must always be used. Good quality CTs are more reliable and result in less application problems and, in general, provide better protection.

309

Figure 6 Current transformer equivalent circuits The quality of CTs is very important for differential protection schemes where the operation of the relays is directly related to the accuracy of the CTs under fault conditions as well as under normal load conditions. CTs can become saturated at high current values caused by nearby faults; to avoid this, care should be taken to ensure that under the most critical faults the CT operates on the linear portion of the magnetization curve. In all these cases the CT should be a ble to supply sufficient current so that the relay operates satisfactorily. 2.1 Equivalent circuit An approximate equivalent circuit for a CT is given in Figure 4.6a, Where n2ZH represents the primary impedance ZH referred to the secondary side, and the secondary impedance is, ZL, Rm and Xm represent the losses and the excitation of the core. The circuit in Figure 4.6a can be reduced to the arrangement shown in figure 4.6b where ZH can be ignored, since it does not influence either the current IH/n or the voltage across Xm. The current flowing through Xm is the excitation current Ιe. The vector diagram, with the voltage drops exaggerated for clarity, is shown in Figure 4.7. In general, ZL, is resistive and Ιe lags Vs by 90°, so that Ie is the principal source of error. Note that the net effect of Ie is to make I lag and be much smaller than ΙH /n, the primary current referred to the secondary side.

310

Figure 7 Vector diagram for the CT equivalent circuit 2.2 Errors The causes of errors in a CT are quite different to those associated with VTs. In effect, the primary impedance of a CT does not have the same influence On the accuracy of the equipment it only adds an impedance in series with the line, which can be ignored. The errors are principally due to the current which circulates through the magnetizing branch. The magnitude error is the difference in magnitude between ΙH / n and IL and is equal to Ir the component of Ie in line with k (see Figure 7). The phase error, represented by θ, is related to Iq the component of Ie which is in quadrature with IL. The values of the magnitude and phase errors depend on the relative displacement between Ie and IL, but neither of them can exceed the vectorial error it should be noted that a moderate inductive load, with Ie and IL approximately in phase, has a small phase error and the excitation component results almost entirely in an error in the magnitude. 2.3 AC saturation CΤ errors result from excitation current, so much so that, in order to check if a CT is functioning correctly, it is essential to measure or calculate the excitation curve. The magnetization current of a CT depends on the cross section and length of the magnetic circuit, the number of turns in the windings, and the magnetic characteristics of the material. Thus, for a given CT, and referring to the equivalent circuit of Figure 4.6b, it can be seen that the voltage across the magnetization impedance, Es, is directly proportional to the secondary current. From this it can be concluded that, when the primary current and therefore the secondary current is increased, these currents reach a point where the core commences to saturate and the magnetization current becomes sufficiently high to produce an excessive error. When investigating the behaviour of a CT, the excitation current should he measured at various values of voltage the so-called secondary injection test. Usually, it is more convenient to apply a variable voltage to the secondary winding, leaving the primary winding open-circuited. Figure 4.8a shows the typical relationship between the secondary voltage and the excitation current determined in this way. In European standards the point Κp on the curve is called the saturation or knee point and is defined as the point at which an increase in the excitation voltage of ten per cent produces an increase of 50 % in the excitation current. This point is referred to in the ANSI / IEEE standards as the intersection of the excitation curves with a 45°

311

tangent line, as indicated in Figure 4.8b. The European knee point is at a higher voltage than the ANSI/IEEE Knee point. 2.4 Burden The burden of a CT is the value in ohms-of the impedance on the secondary side of the CT due to the relays and the connections between the CT and the relays. By way of example, the standard burdens for CTs with a nominal secondary current of 5 A are shown in Table 3, based on ANSI Standard C57.13. IEC Standard Publication 185(1987) specifies CTs by the class of accuracy followed by the letter Μ or P, which denotes whether the transformer is suitable for measurement or protection purposes, respectively. The current and phase-error limits for measurement and protection CTs are given in Tables 4a and 4.4b. The phase error is considered positive when the secondary current leads the primary current. The current error is the percentage deviation of the secondary current, multiplied by the nominal transformation ratio, from the primary current, i.e. {(CTR x Ι2) – I1} ÷ I1 (%), where I1 = primary current (A), I2 = secondary current (A) and CTR = current transformer transformation ratio. Those CT classes marked with `ext' denote wide range (extended) current transformers with a rated continuous current of 1.2 or 2 times the nameplate current rating. 2.5 Selection of CTs When selecting a CT, it is important to ensure that the fault level and normal load conditions do not result in saturation of the core and that CT magnetization curves

Figure 8a CT magnetization curves

312

Figure 8b CT magnetization curves a Defining the knee point in a CT excitation curve according to European standards b Typical excitation curves for a multi ratio class C CT (From IEEE Standard C57.13-1978; reproduced by permission of the IEEE). Table 4.3 Standard burdens for protection CTs with 5 Α secondary current Designation Resista nce Inductance Impedance (Ω)

(mH)

Voltamps

(Ω)

Power factor

(at 5 A) B-1

0.5

2.3

1.0

25

0.5

B-2

1.0

4.6

2.0

50

0.5

B-4

2.0

9.2

4.0

100

0.5

313

4.0

B-8

18.4

8.0

200

0.5

The errors do not exceed acceptable limits. These factors can be assessed from: formulae; CT magnetization curves; CT classes of accuracy. The first two meth ods provide precise facts for the selection of the CT. The third only provides a qualitative estimation. The secondary voltage Ε in Figure 4.6U has to be determined for all three methods. If the impedance of the magnetic circuit, Xm is high, this can be removed from the equivalent circuit with little error' giving Es=Vs and thus: Vs=IL (ZL+ZC+ZB)

IL

(1)

Where Vs = r.m.s. voltage induced in the secondary winding =maximum secondary current in amperes; this can be determined by dividing the maximum Fault current on the system by the transformer turns ratio selected ZB = e x t e r n a l impedance connected ZL = impedance of the secondary winding ZC =impedance of the connecting wiring Use of the formula This method utilizes the fundamental transformer equation: Vs = 4.44.f. Α. N. Bmax.1 0 -8 V (2) Where f =frequency in Hz, Α =cross-sectional area of core (cm 2) Ν =number of turns Bmax =flux density (lines/cm2) Table 4α Error limits for measurement current transformers Class % current error at the given proportion  of rated current shown below

2 1.2 1 0.50 0.20 .0* .00

% phase error at the given proportion of the  rated  current shown below

2.0*

0.10 0.05

1.2

1. 0

0.5

0. 2

0.1

0.05

0.1

0.1 0.1

0.2

0.25

5

5

8

10

0.2

0.2 0.2

0.35

0.50

10

1 0

1 5

20

0.5

0.5 0.5

0.75

1.00

30

3 0

4 5

60

1.0

1.0 1.0

1.5

2.00

60

6 0

-

9 0

12 0

-

3.0

3.0

12

-

12

-

-

-

3.0

-

-

-

-

_

314

0 -

5

8

10

15

0.75 10

-

1 0

1 5

20

30

1.5 30

-

3 0

4 5

60

90

0.1

0.1

0.1

0.2

0.25

0.4

0.2

0.2

0.2

0.35

0.50

0.5

0.5

0.75

1.00

1.0

1.0

1.5

2.00

-

-

ext

0.5 ext

1.0

0

5

60

-

60

-

90

120

-

120

-

-

120

-

-

-

ext

3.0

3.0

-

-

3.0

-

ext

Table 4b Error limits for protection current transformers

+/- percentage Current ratio error

Accuracy Class % Current 0.1 0.2 0.5 1.0

5 0.4 0.75 1.5 3

+/- Phase error (minutes)

20 100 120 5 20 100 120 0.2 0.35 0.75 1.5

0.1 0.2 0.5 1.0

0.1 0.2 0.5 1.0

15 30 90 180

8 5 5 15 10 10 45 30 30 90 60 60

Total error for nominal error limit current and nominal load is five per cent for 5P and 5Ρ ext CTs and ten per cent for 10P and 10P ext CTs. The cross-sectional area of metal and the saturation flux density are sometimes difficult to obtain. The latter can be taken as equal to 100 000 lines/Cm2, which is a typical value for modern transformers. To use the formula, V is determined from eqn. 4.1 and Bmax. is then calculated using eqn. 2. If Bmax. Exceeds the saturation density, there could be appreciable errors in the secondary current and the CT selected would not be appropriate. Example 1. Assume that a CT with a ratio of 2000/5 is available, having a steel core of high permeability, a cross-sectional area of 3.25 In cm2 and a secondary winding with a resistance of 0.31 Ω. The impedance of the relays, including connections, is 2 Ω. Determine whether the CT would be saturated by a fault of 35 000 A at 50 Hz. Solution If the CT is not saturated, then the secondary current, IL, is 35 000x 5/2000=87.5 A. N= 2000/5 = 400 turns And Vs=87.5x (0.31+2) =202.1 V. Using eqn. 4.2, Bmax, can now be calculated: Bmax = 202.1X108/4.44X50X3.25X400=70 030 lines/ cm2 Since the transformer in this example has a steel core of high permeability, this relatively low value of flux density should not result in saturation. Using the magnetization curve

315

Typical CT excitation curves which are supplied by manufacturers state the r.m.s. current obtained on applying an r.m.s. voltage to the secondary winding, with the primary winding open-circuited. The curves give the magnitude of the excitation current required order to obtain a specific secondary voltage. The method consists of producing a curve which shows the relationship between the primary and secondary currents for one tap and specified load conditions, such as shown in Figure 4.9. Starting with any value of secondary current, and with the help of the magnetisation curves, the value of the corresponding primary current can be determined. The process is summarized in the following steps: (a) Assume a value for IL. (b) Calculate Vs in accordance with eqn. 4.1. (c) Locate the value of Vs on the curve for the tap selected, and find the associated value of the magnetization current, Ie. (d) Calculate I H / n (=IL + Ie) and multiply this value by n to refer it to the primary side of the CT. (e) This provides one point on the curve of IL against IH, and the process is then repeated to obtain other values of IL and the resultant values of IH. By joining the points together the curve of IL against IH is obtained.

Figure 4.9 using the magnetization curve a - assume a value for IL. b - Vs = I L ( Z L + Z C + Z B ) c - find I e from the curve d - IH=n(I1,+ I e ) e - draw the point on the curve 316

This method incurs an error in calculating I H /n by adding I e and IL together arithmetically and not vectorially, which implies not taking account of the load angle and the magnetizations branch of the equivalent circuit. However, this error is not great and the simplification snakes it easier to carry out the calculations. After construction, the curve should be checked to confirm that the maximum primary fault current is within the transformer saturation zone. If not, then it will be necessary to repeat the process, changing the tap until the fault current is within the linear part of the characteristic. In practice it is not necessary to draw the complete curve because it is sufficient to take the known fault current and refer to the secondary winding, assuming that there is no saturation for the tap selected. This converted value can be taken as IL initially for the process described earlier. If the tap is found to be suitable after finishing the calculations, then a value of IH can be obtained which is closer to the fault current. Accuracy classes established by the ANSI standards The ANSI accuracy class of a CT (Standard C57.13) is described by two symbols — a letter and a nominal voltage; these define the capability of the CT. C indicates that the transformation ratio can be calculated, and T indicates that the transformation ratio can be determined by means of tests. The classification C includes those CTs with uniformly distributed windings and other CTs with a dispersion flux which has a negligible effect on the ratio, within defined limits. The classification T includes those CTs with a dispersion flux which considerably affects the transformation ratio. For example, with a CT of class C—100 the ratio can be calculated, and the error should not exceed ten per cent if the secondary current does not go outside the range of 1 to 20 times the nominal current and if the load does not exceed 1Ω (1Ω x 5 Ax 20=100 V) at a minimum power factor of 0.5. These accuracy classes are only applicable for complete windings. When considering a winding provided with taps, each tap will have a voltage capacity proportionally smaller, and in consequence it can only feed a portion of the load without exceeding the ten per cent error limit. The permissible load is defined as ZB= (NP Vc) / 100, where ZB, is the permissible load for a given tap of the CT, NP, is the fraction of the total number of turns being used and Vc is the ANSI voltage capacity for the complete CT. 2.6 DC saturation Up to now, the behavior of a CT has been discussed in terms of a steady state, without considering the DC transient component of the DC saturation is particularly significant in complex protection schemes since, in the case of external faults, high fault currents circulate through the CTs. If saturation occurs in different CTs associated with a particular relay arrangement, this could result in the circulation of unbalanced secondary currents which would cause the system to malfunction. 2.7 Precautions when working with CTs Working with CTs associated with energized network circuits can be extremely hazardous. In particular, opening the secondary circuit of a CT could result in

317

dangerous over voltages which might harm operational staff or lead to equipment being damaged, because the current transformers are designed to be used in power circuits which have impedance much greater than their own. As a consequence, when secondary circuits are left open, the equivalent primarycircuit impedance is almost unaffected but a high voltage will be developed by the primary current passing through the magnetizing impedance Thus, secondary circuits associated with CTs must always he kept in a closed condition or shortcircuited in order to prevent these adverse situations occurring. To illustrate this, an example is given next using typical data for a CT and a 13.2 kV feeder. Choice of CT’s Primary rating The c. t. primary rating is usually chosen to be equal to or greater than the normal full load current o f the protected circuit. Standard primary ratings are given in B.S. 3938:1973. Generally speaking, the maximum ratio of CT’s is usually limited to about 3000/1. This is due to (I) limitation of size of CT’s and more importantly (II) the fact that the open circuit volts would be dangerously high for large CT’s Primary ratings, such as those encountered on large turbo alternators, e.g. 5,000 amperes. It is standard practice in such applications to use a cascade arrangement of say 5,000/20A together with 20/1A interposing auxiliary CT’s Instantaneous over current relays Class P method of specification will a suffice. A secondary accuracy limit current greatly in excess of the value t o cause relay operation serves no useful purpose and a rated accuracy limit of 5 will usually be adequate. When such relays are set to operate at high values of over current, say from 5 to 15 times the rated current o f the transformer, the accuracy limit factor must be at least as high as the value of the setting current used in order to ensure fast relay operation. Rated outputs higher than 15VA and rated accuracy limit factors higher than 10 are not recommended for general purposes. It is possible, however, to combine a higher rated accuracy limit factor with a lower rated output and vice versa. But when the product of these two exceeds 150 the resulting current transformer may be uneconomical, and/or of unduly large dimensions. Over current relays with Inverse and Definite Minimum Time (IDMT) lag characteristic In general, for both directional and non-directional relays class 10P current transformers should be used Earth fault relays with inverse time characteristic (1) Schemes in which phase fault current stability and accurate time grading are not required. Class 10P current transformers are generally recommended in which the product of rated output and rated accuracy limit fact or approaches 150 provided that the earth fault

318

relay is not set below 20% of the rated current of the associated current transformer and that the burden of the relay at its setting current does not exceed 4VA. (2) Schemes in which phase fault stability and/or where time grading is critical. Class 5P current transformers in which the product of rated output and accuracy limit factor approaches 150 should be used. They are in general suitable for ensuring phase fault stability up to 10 times the rated primary current and for maintaining time grading of the earth f a u l t relays, up to current values of the order of 10 times the earth fault setting provided t h a t the phase burden effectively imposed on each current transformer does not exceed 50% of it s rated burden. The rated accuracy limit factor is not less than 10 the earth fault relay is not set below 30 % The burden of the relay at its setting does not exceed 4VA The use of a higher relay setting the use of an earth fault relay having a burden of less than 4VA at its setting The use of current transformers having a product of rated output and rated accuracy factor in excess of 150. Class “X” Current Transformer Protection current transformers specified in terms of complying with Class ' X I Specification is generally applicable to unit systems where balancing of outputs from each end of the protected plant is vital. This balance, or stability during through fault conditions, is essentially of a transient nature and thus the extent of the unsaturated (or linear) zone is of paramount importance. Hence a statement of knee point voltage is the parameter of prime importance and it is normal to derive, from heavy current test results, a formula stating the lowest permissible value of VK if stable operation is to be guaranteed, e.g. Vk = K In (RCT + 2RL + R0) Where K - Is a constant found by realistic heavy current tests? In - rated current of C.T. and relay RCT - secondary winding resistance of the line current transformers RL - lead burden (route length) in ohms Ro - any other resistance (or impedance) in circuit Protection Scheme 1 - Feeders Protection Schemes. 2 - Transformers Protection Schemes. 3 - Bus Bar Protection Schemes. 4 - Generators Protection Schemes. Types and voltage level of Feeders A – O. H. T. Lines • 500 KV O. H. T Line • 400 KV O. H. T Line

319

• 275 KV O. H. T Line • 220 KV O. H. T Line • 132 KV O. H. T Line • 66 KV O. H. T Line • 33 KV O. H. T Line • 22 KV O. H. T Line • 11 KV O. H. T Line B – U. G. Cables • 275 KV U. G. Cable • 220 KV U. G. Cable • 132 KV U. G. Cable • 66 KV U. G. Cable • 33 KV U. G. Cable • 11 KV U. G. Cable 500, 400, 275 and 220 KV O.H.T. Lines Protection Schemes • Main (A) Protection: Distance Protection Permissive Over Reach Scheme. (POTT) • Main (B) Protection: Distance Protection Permissive Under Reach Scheme. (PUTT) • Backup Protection: 1. I.D.M.T Directional O/C & E/F Relay. 2. Circuit Breaker Fail to Tripe. 3. Inter Trip. 4. SF6 Pressure Low Trip 5. Cable Oil Pressure Low Trip (For Cable Tail ) Drawing : single Line diagram for protection scheme Click Here 132 and 66 KV O.H.T. Lines Protection Schemes • Main Protection: Distance Protection Permissive Under Reach Scheme. (PUTT) • Back up Protection: 1. I.D.M.T Directional O/C & E/F Relay. 2. Circuit Breaker Fail To Tripe. 3. Inter Trip. 4. SF6 Pressure Low Trip 5. Cable Oil Pressure Low Trip (For Cable Tail) Drawing : single Line diagram for protection scheme Click Here 33 and 22 KV O.H.T. Lines Protection Schemes • I.D.M.T Direction O/C & EF Relay • I.D.M.T Non Direction O/C & EF Relay 11 KV O.H.T. Lines Protection Schemes • I.D.M.T Direction O/C & EF Relay 320

275, 220 U.G.C. Line Protection Scheme • Main (A) Protection: Differential Protection (Solkor – R) • Main (B) Protection: Distance Protection Permissive Over Reach Scheme. (POTT) With Carrier Signal through Pilot Cable • Back up Protection: 1. I.D.M.T Directional O/C & E/F Relay. 2. Circuit Breaker Fail to Tripe 3. Inter Trip. 4. SF6 Pressure Low Trip 5. Cable Oil Pressure Low Trip 132, and 66 KV U.G.C. Line Protection Scheme • Main Protection: Differential Protection (Solkor – R) • Back up Protection: 1. I.D.M.T Directional O/C & E/F Relay. 2. Circuit Breaker Fail to Tripe. 3. Inter Trip (Through Pilot Cable). 4. SF6 Pressure Low Trip 5. Cable Oil Pressure Low Trip 33, 22 KV U.G.C. Line Protection Scheme • Main Protection: Differential Protection (Solkor – R) • Back up Protection: • I.D.M.T Directional O/C & E/F Relay. • I.D.M.T Non Directional O/C & E/F Relay. • Cable Oil Pressure Low Trip. 11 KV U.G.C. Line Protection Scheme • Main Protection: Differential Protection (Solkor – R) • Back up Protection: • I.D.M.T Non Directional O/C & E/F Relay. Example for 300 KV feeder protection scheme

321

Example for 132 KV feeder protection scheme

322

• • • •

Transformers Protection Schemes Some types of power transformers 300 MVA. 3 Winding Power Transformer 275 KV / 132 KV / 33 KV. (Y.Y.Δ). 75 MVA. & 45 MVA. 2 Winding Power Transformer 1 32 KV / 33 KV. 30 MVA 2 Winding Power Transformer 132 KV / 11 KV. 20 MVA & 15 MVA 2 Winding Power Transformer 33 KV / 11 KV. 323

Drawing : single Line diagram for protection scheme Click Here 300 MVA 3 Winding Power Transformer Protection Scheme. • Main (A&B) Protection: 1. Differential Protection. 2. Restricted Earth Fault Protection. (both at 275 kv and 132 kv) side neutral of the star winding. • BackupProtection: 1. C.B Fail to trip. 2. I.D.M.T Non Direction O/C & E/F relay on 300 KV side 3. I.D.M.T Direction O/C & E/F relay on 132 KV side 4. Inter Trip (through pilot cable). 5. Buchhols Trip. 6. Tap Changer Buchhols Trip. 7. Oil Temperature Trip. 8. Winding Temperature Trip. 9. Cable oil pressure Low Trip. (for cable tails ) 10. SF6 pressure Low Trip. 75, 45 And 30 MVA- 2 Winding Power Transformer Protection Scheme. • Main (A) Protection: 1. Differential Protection. 2. Restricted Earth Fault Protection. (At the neutral of the LV. Winding). • Backup Protection: 1. Stand-By Earth Fault relay at the neutral of LV. Winding. 2. C.B Fail to trip. (For 132 KV. C.B only) 3. I.D.M.T Non Direction O/C & E/F relay on 132 KV side 4. Inter Trip (through pilot cable). 5. Buchhols Trip. 6. Tap Changer Buchhols Trip. 7. Winding Temperature Trip. 8. Cable oil pressure Low Trip. (For cable tails) 20 & 15 MVA- 33 / 11 KV, 2 Winding Power Transformer Protection Scheme. • Main (A) Protection: 1. Differential Protection. 2. Restricted Earth Fault Protection. (At the neutral of the LV. Winding). •

Backup Protection: 1. Stand-By Earth Fault relay at the neutral of LV. Winding. 2. I.D.M.T Non Direction O/C & E/F relay on 33 KV side 3. Inter Trip (through pilot cable). 4. Buchhols Trip.

324

Example for 132 KV Transformer protection scheme

Bus-Bar Protection Schemes Bus-Bar Protection Schemes. • 500, 400, 275, 220 and 132 KV. Bus-Bar Protection Scheme. - Differential Protection For each section of bus-bar.

325

- SF6 Pressure low Trip. • 66 and 33 KV. Bus-Bar Protection Scheme. - Differential Protection For each section of bus-bar or Arc protection or Micro switch protection. SF6 Pressure low Trip. •

22 and 11 KV BUS-Bar Protection Scheme. - Arc protection or Micro switches protection.

•

500, 400, 275, and 220 KV BB section & BB couplers protection scheme. - I.D.M.T Non Directional O/C & E/F Relay. - C.B Fail to Trip. - SF6 Pressure Trip. - Inter Trip (through pilot cable).

•

132 KV BB section & BB couplers protection scheme. - I.D.M.T Non Directional O/C & E/F Relay. - C.B Fail to Trip.

•

33 KV BB section & BB couplers protection scheme. - I.D.M.T Non Directional O/C & E/F Relay.

•

11 KV BB section & BB couplers protection scheme. - I.D.M.T Non Directional O/C & E/F Relay.

Shunt Reactor Protection Scheme. 275 &132 KV. Shunt Reactor Protection Scheme. • I.D.M.T Non Direction O/C & E/F relay. • Inter Trip (through pilot cable – SHR connected through cable C.B. “for 132 kV only”). • Buchhols Trip. • Oil Temperature Trip. • Winding Temperature Trip. • Cable oil pressure Low Trip. (For cable tails) • SF6 pressure Low Trip. • C.B Fail to trip. (For 132 KV. C.B only). 33 KV. Shunt Reactor Protection Scheme for both connected to 33 KV Bus-Bar or to tertiary of 300 MVA Transformer. • • • •

I.D.M.T Non Direction O/C & E/F relay. Buchhols Trip. Oil Temperature Trip. Winding Temperature Trip.

326

Over-current and Earth Fault Protection Introduction As the fault impedance is less than load impedance, the fault current is more than load current. If a short circuit occurs the circuit impedance is reduced to a low value and therefore a fault is accompanied by large current. Over-current protection is that protection in which the relay picks up when the magnitude of current exceeds the pickup level. The basic element in Over-current protection is an Over-current relay. The Over-current relays are connected to the system, normally by means of CT's. Over-current relaying has following types: 1. High speed Over-current protection. 2. Definite time Over-current protection. 3. Inverse minimum time Over-current protection. 4. Directional Over-current protection (of above types). Over-current protection includes the protection from overloads. This is most widely used protection. Overloading of a machine or equipment generally) means the machine is taking more current than its rated current. Hence with overloading, there is an associated temperature rise. The permissible temperature rise has a limit based on insulation class and material problems. Over-current protection of overloads is generally provided by thermal relays. Over-current protection includes short-circuit protection. Short circuits a be phase faults, earth faults or winding faults. Short-circuit currents are generally several times (5 to 20) full load current. Hence fast fault clearance is always desirable on short-circuits. When a machine is protected by differential protection, the over-current is provided in addition as a back-up and in some cases to protect the machine from sustained through fault. Several protective devices are used for over-current protection these include: 1. Fuses 2. Circuit-breakers fitted with overloaded coils or tripped by overcurrent relays. 3. Series connected trip coils operating switching devices. 4. Over-current relays in conjunction with current transformers. The primary requirements of over-current protection are: • The protection should not operate for starting currents, permissible over-current, and current surges. To achieve this, the time delay is provided (in case of inverse relays). If time delay cannot be permitted, high-set instantaneous relaying is used. • The protection should be coordinated with neighboring overcurrent protections so as to discriminate. 327

Applications of Over-current Protection Over-current protection has a wide range of applications. It can be applied where there is an abrupt difference between fault current within the protected section and that outside the protected section and these magnitudes are almost constant. The over-current protection is provided for the following: Motor Protection Over-current protection is the basic type of protection used against overloads and short-circuits in stator windings of motors. Inverse time and instantaneous phase and ground over-current relays can be employed for motors above 1200 H.P. For small/medium size motors where cost of CT's and protective relays is not economically justified, thermal relays and HRC fuses are employed, thermal relays used for overload protection and HRC fuses for short-circuit protection. Transformer Protection Transformers are provided with over-current protection against faults, only, when the cost of differential relaying cannot be justified. However, over-current relays are provided in addition to differential relays to take care of through faults. Temperature indicators and alarms are always provided for large transformers. Small transformers below 500 kVA installed in distribution system are generally protected by drop-out fuses, as the cost of relays plus circuit-breakers is not generally justified Line Protection. The lines (feeders) can be protected by (1) Instantaneous over-current relays. (2) Inverse time over-current relays. (3) Directional over-current relay. Lines can be protected by impedance or carrier current protection also. Protection of Utility Equipment The furnaces, industrial installations commercial, industrial and domestic equipment are all provided with over-current protection. Relays used in Over-current Protection The choice of relay for over-current protection depends upon the Time / current characteristic and other features desired. The following relays are used. 1. For instantaneous over-current protection. Attracted armature type, moving iron type, permanent magnet moving coil type and static. 2. For inverse time characteristic. Electromagnetic induction type, permanent magnet moving coil type and static. 3. Directional over-current protection. Double actuating quantity induction relay with directional feature. 4. Static over-current relays. 5. HRC fuses, drop out fuses, etc. are used in low voltage medium voltage and high voltage distribution systems, generally up to 11 kV.

328

6.

Thermal relays are used widely for over-current protection.

Not: Now Digital Numerical Relay you can used for all types Characteristics of relay units for over current protection There is a wide variety of relay-units. These are classified according to their type and characteristics. The major characteristic includes: 1. Definite characteristic 2. Inverse characteristic 3. Extremely Inverse 4. Very Inverse In definite characteristic, the time of operation is almost definite i.e. I0 * T = K Where: I = Current in relay coil T = Relay lime K = Constant. In inverse characteristic, time is inversely proportional to current i.e. I1 * T = K In more inverse characteristic In * T = K Where n can be between 2 to 8 the choice depends on discrimination desired. Instantaneous relays are those which have no intentional time lag sod which operate in less than 0.1 second, usually less than 0.08 second. As suck they are not instantaneous in real sense. The relays which are not instantaneous are called Time Delay Relay'. Such relays are provided with delaying means such as drag magnet, dash poss. bellows, escape mechanisms, back-stop arrangement, etc. The operating time of a relay for a particular setting and magnitude actuating quantity can be known from the characteristics supplied by the manufacturer. The typical characteristics are shown in (Fig. 1) An inverse curve is one in which the operating time; becomes less as the magnitude of the actuating quantity is increased. However for higher magnitudes of actuating quantity the time is constant. Definite time curve is one in which operating time is little affected by magnitude of actuating current. However even definite time relay has a characteristic which is slightly inverse The characteristic with definite minimum time and of inverse type is also called Inverse Definite Minimum Time (IDMT) characteristics (Fig.1).

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(Fig.1) Inverse Definite Minimum Time (IDMT) characteristics Principle of trip circuit Referring to (Fig. 2) the three current transformers and relay coils connected in star and the star point is earthed. When short circuit occurs in the protected zone the secondary current of CT's increases. These current flows through relay coils and the relay picks-up, the relay contacts close, thereby the trip circuit is closed and the circuit breaker-operates The over-current protection scheme with three over-current relays (Fig. 2) responds to phase faults and earth faults including single-phase to earth fault. Therefore such schemes are used with solidly earthed systems where phase to phase and phase to earth faults are likely to occur. For proper functioning of over-current and earth fault protection, the choice of CT's and polarity connections should be correct.

330

Fig.2) Over Current protection with three phase OC relays Methods of CT Connections in Over-current Protection of 3-Phase Circuits Connection Scheme with Three Over-current Relays Over-current protection can be achieved by means of three over-current relays or by two over-current relays (See Table 1). Table 1

Fig

Description

Note

1

One OC with one For balanced CT for over load load only. protection.

2

Two OC relays with two CT's for phase to phase fault protection.

331

3

Three OC relays with three CT's for phase to phase fault protection.

4

Three OC relays EF setting less with three CT's than phase for phase to fault setting phase fault protection and phase to earth fault. Two OC and one EF relays for phase to phase and phase to earth fault protection

5

EF current > two time pickup phase current

Earth-Fault Protection When the fault current flows through earth return path, the fault is called Earth Fault. Other faults which do not involve earth are called phase faults. Since earth faults are relatively frequent, earth fault protection is necessary in most cases. When separate earth fault protection is not economical, the phase relays sense the earth fault currents. However such protection lacks sensitivity. Hence separate earth fault protection is generally provided. Earth fault protection senses earth fault current. Following are the method of earth fault protection. Connections of CT's for Earth-fault Protection 1. Residually connected Earth-fault Relay Referring to Fig. 3 In absence of earth-fault the vector sum of three line currents is zero. Hence the vector sum of three secondary currents is also zero. IR+I Y +I B =0 The sum (IR+I Y +I B ) is called residual current The earth-fault relay is connected such that the residual current flows through it (Figs.3 and Fig. 4), in the absence of earth-fault, Therefore, the residually connected earth-fault relay does not operate. However, in presence of earth fault the conditions is disturbed and (IR+I Y +I B ) is no more zero. Hence flows through the earth-fault relay. If 332

the residual current is above the pick-up value, the earth-fault relay operates. In the scheme discussed here the earth-fault at any location near or away from the location of CT's can cause the residual current flow. Hence the protected zone is not definite. Such protection is called unrestricted earth-fault protection

(Fig.3) Earth-fault Relay connected in Residual Circuit.

(Fig.4) Earth fault protection combined with phase fault protection

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2. Earth-fault Relay connected in Neutral to Earth Circuit (Fig. 5). Another method of connecting an earth-fault relay is illustrated in Fig 5. The relay is connected to secondary of a CT whose primary is connected in neutral to earth connection. Such protection can be provided at various voltage levels by connecting earth-fault relay in the neutral-to-earth connection of that voltage level. The fault current finds the return path through the earth and then flows through the neutralto-earth connected. The magnitude of earth fault current is dependent on type of earthing (resistance, reactance or solid) and location of fault. In this type of protection, The zone of protection cannot be accurately defined. The protected area is not restricted to the transformer/generator winding alone. The relay senses the earth faults beyond the transformer/generator winding hence such protection is called unrestricted earth-fault protection. The earth-fault protection by relay in neutral to earth circuit depends upon the type of neutral Earthing. In case of large generators, voltage transformer is connected between neutral and earth

(Fig. 5) Earth-fault protection by earth-fault-relay connected in neutral-to-earth circuit. Combined Earth-fault and Phase-fault Protection It is convenient to incorporate phase-fault relays and earth-fault relay in a combined phase-fault and earth-fault protection. (Fig. 4) The increase in current of phase causes corresponding increase in respective secondary currents. The secondary current flows through respective relay-units Very often only two-phase relays are provided instead of three, because in case of phase faults current in any at least two phases must increase. Hence two relay-units are enough. Earth-fault Protection with Core Balance Current Transformers. (Zero Sequence CT)

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In this type of protection (Fig. 6) a single ring shaped core of magnetic material, encircles the conductors of all the three phases. A secondary coil is connected to a relay unit. The cross-section of ring-core is

(Fig.6) Principle of core-balance CT for earth fault protection Ample, so that saturation is not a problem. During no-earth-fault condition, the components of fluxes due to the fields of three conductors are balanced and the secondary current is negligible. During earth faults, such a balance is disturbed and current is induced in the secondary. Core-balance protection can be conveniently used for protection of low-voltage and medium voltage systems. The burden of relays and exciting current are deciding factors. Very large crosssection of core is necessary for sensitivity less than 10 A. This form of protection is likely to be more popular with static relays due to the fewer burdens of the latter. Instantaneous relay unit is generally used with core balance schemes. Theory of Core Balance CT . Let Ia, Ib and I c , be the three line currents and Φa, Φb and Φc be corresponding components of magnetic flux in the core. Assuming linearity, we get resultant flux Φ as, Φ=k (Ia + Ib + I c ) where k is a constant Φ = K * Ia. Referring to theory of symmetrical components (Ia + Ib + I c )= 3 I c= I n Where, Io is zero sequence current and In, is current in neutral to ground circuit. During normal condition, when earth fault is absent, (Ia + Ib + Ic) = 0 Hence Φr = 0 and relay does not operate During earth fault the earth fault current flows through return neutral path. For example for single line ground fault, If = 3Iao = In

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Hence the zero-sequence component of I o produces the resultant flux Φr in the core. Hence core balance current transformer is also called as zero sequence current transformers (ZSCT). Application for Core Balance CT's with Cable Termination Joints The termination of a three core cable into three separate lines or bus-bars is through cable terminal box. Ref. (Fig. 7), the Core Balance Protection is used along with the cable box and should be installed before making the cable joint. The induced current flowing through cable sheath of normal healthy cable needs particular attention with respect to the core balance protection. The sheath currents (Ish) flow through the sheath to the cover of cable-box and then to earth through the earthing connection between cable-box. For eliminating the error due to sheath current (Ish) the earthing lead between the cable-box and the earth should be taken through the core of the core balance protection. Thereby the error due to sheath currents is eliminated. The cable box should be insulated from earth. 1. Cable terminal box 2. Sheath of 3 core cable connection to (1) 3. Insulator support for 1 4. Earthing connection passing through 5 5. Core balance CT

Fig (7) Mounting of Core Balance CT with Cable Terminal Box Frame-leakage Protection The metal-clad switchgear can be provided with frame leakage protection. The switchgear is lightly y insulated from the earth. The metal-frame-work or enclosure of the switchgear is earthed with a primary of a CT in between (Fig. 8).

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The concrete foundation of the switchgear and the cable-boxes and other conduits are slightly insulated from earth, the resistance to earth being about 12 ohms. In the event of an earth fault within the switchgear, the earth-fault current finds the' path through the neutral connection. While doing so, it is sensed by the earth fault relay.

Metal clad switchgear Earthing bus Earth fault current EF Relay

Earth

(Fig. 8) Principle of

frame-leakage protection of metal-clad-switchgear Circulating current differential protection also responds to earth-faults within its protected zone. Earth-fault protection can be achieved by following methods: 1. 2. 3. 4. 5. 6.

Residually connected relay. Relay connected in neutral-to-ground circuit. Core-balance-scheme. Frame leakage method. Distance relays arranged for detecting earth faults on lines. Circulating current differential protection.

Directional Over-current Protection The over-current protection can be given directional feature by adding directional element in the protection system. Directional over-current protection responds to over-currents for a particular direction flow. If power flow is in the opposite direction, the directional over-current protection remains un-operative. Directional over-current protection comprises over-current relay and power directional relay- in a single relay casing. The power directional relay does not measure the power but is arranged to respond to the direction of power flow. Directional operation of relay is used where the selectivity can be achieved by directional relaying. The directional relay recognizes the direction in which fault occurs, relative to the location of the relay. It is set such that it actuates for faults occurring in one direction only. It does not act for faults occurring in the other direction. Consider a feeder AC (Fig. 9) passing through sub-section B. The circuit breaker CB3 is provided with a directional 337

B

A

C

CB1

CB2

CB3

R

R

R

CB4

R

(Fig. 9) Principle of directional protection Relay `R' which will trip the breaker CB3 if fault power flow in direction C alone. Therefore for faults in feeder AB, the circuit breaker CB3 does not trip unnecessarily. However for faults in feeder BC the circuit-breaker CB3 trips Because it's protective relaying is set with a directional feature to act in direction AC Another interesting example of directional protection is that of reverse power protection of generator (Fig. 10). If the prime mover fails, the generator continues to run as a motor and takes power from bus-bars. Directional of flow For tripping CB

R

(Fig. 10) Reverse powers protection against motoring action of a generator Directional power protection operates in accordance with the direction of power flow. Reverse power protection operates when the power direction is reversed in relation to the normal working direction. Reverse power relay is different in construction than directional over-current relay. In directional over-current relay, the directional element does not measure the magnitude of power. It senses only direction of power flow. However, in Reverse Power Relays, the directional element measures magnitude and direction of power flow. Relay connections of Single Phase Directional Over-current Relay : The current coils in the directional over-current relay are normally connected to a secondary of line CT. The voltage coil of directional element is connected to a line VT, having phase to phase output (of 110 V). There are four common methods of connecting the relay depending upon phase angle between current in the current coil and voltage applied to the voltage coil.

338

339

Fig.11 Numerical Over current, and Overload Protection Relay 3-Phase Directional over current relays When fault current can flow in both directions through the relay location, it is necessary to make the response of the relay directional by the introduction of directional control elements. These are basically power measuring devices in which the system voltage is used as a reference for establishing the relative direction or phase of the fault current. Although power measuring devices in principle, they are not arranged to respond to the actual system power for a number of reasons: 1.

The power system, apart from loads, is reactive so that the fault power factor is usually low. A relay

V a , Vb and Vc. Normal system voltages Vb 1 and V c 1 Voltages at fault location on faulted phases Vb 2 and V c 2 Voltages remote from fault location Fig.12 Phase voltages for a B-C fault

Responding purely to the active component would not develop a high torque and might be much slower and less decisive than it could be. 1. The system voltage must collapse at the point of short circuit. When the fault is single-phase, it is the particular voltage across the shortcircuited points which are reduced. So a B—C phase fault will cause the B and C phase voltage vectors to move together, the locus of their ends being the original line be for a homogeneous system, as shown in (Fig.12) At the point of fault the vectors will coincide, leaving zero voltage across the fault, but the fault voltage to earth will be half the initial phase to neutral voltage. At other points in the system the vector displacement will be less, but relays located at such points will receive voltages which are unbalanced in their value and phase position. 340

The effect of the large unbalance in currents and voltages is to make the torques developed by the different phase elements vary widely and even differ in sign if the quantities applied to the relay are not chosen carefully. To this end, each phase of the relay is polarized with a voltage which will not be reduced excessively except by close three-phase faults, and which will remain in a satisfactory relationship to the current under all conditions. Relay connections This is the arrangement whereby suitable current and voltage quantities are applied to the relay. The various connections are dependent on the phase angle, at unity system power factor, by which the current and voltage applied to the relay are displaced. Relay maximum torque The maximum torque angle (MTA) is defined as the angle by which the current applied to the relay must be displaced from the voltage applied to the relay to produce maximum torque. Although the relay element may be inherently wattmetric, its characteristic can be varied by the addition of phase shifting components to give maximum torque at the required phase angle. A number of different connections have been used and these are discussed below. Examination of the suitability of each arrangement involves determining the limiting conditions of the voltage and current applied to each phase element of the relay, for all fault conditions, taking into account the possible range of source and line impedances. 30° relay connection (0° MTA) The A phase relay is supplied with current la and voltage V ac. In this case, the flux due to the voltage coil lags the applied Vac voltage by 90°, so the maximum torque occurs when the current lags the system phase to neutral voltage by 30°. For unity power factor and 0.5 lagging power factor the maximum torque available is 0.866 of maximum. Also, the potential coil voltage lags the current in the current coil by 30° and gives a tripping zone from 60° leading to 120° lagging currents, as shown in (Fig. 13a). The most satisfactory maximum torque angle for this connection, that ensures correct operation when used for the protection of plain feeders, is 0°, and it can be shown that a directional element having this connection and 0° MTA will provide correct discrimination for all types of faults, when applied to plain feeders If applied to transformer feeders, however, there is a danger that at least one of the three phase relays will operate for faults in the reverse direction; for this reason a directional element having this connection should never be used to protect transformer feeders. This connection has been used widely in the past, and it is satisfactory under all conditions for plain feeders provided that three phase elements are employed. When only two phase elements and an earth fault element are

341

used there is a probability of failure to operate for one condition. An interphase short circuit causes two elements to be energized but for low power factors one will receive inputs which, although correct, will produce only a poor torque. In particular a B—C fault will strongly energize the B element with lb current and Vba voltage, but the C element will receive Ic and the collapsed Vcb voltage, which quantities have a large relative phase displacement, as shown in (Fig. 13b). This is satisfactory provided that three phase elements are used, but in the case of a two phase and one earth fault element relay, with the B phase element omitted, operation will depend upon the C element, which may fail to operate if the fault is close to the relaying point.

A phase element connected l a Va c B phase element connected l b Vb a C phase element connected Ic Vcb (a) Characteristic and inputs for phase A element

(b) B-C Fault with voltage distortion (Fig. 13) Vector diagrams for the 30° connection

342

60° No. 1 connection (0° MTA) The A phase relay is supplied with lab current and Vac voltage. In this case, the flux due to the voltage coil lags the applied voltage to the relay by 90°, so maximum torque is produced when the current lags the system phase to neutral voltage by 60°. This connection, which uses Vac voltage with delta current produced by adding phase A and phase B currents at unity power factor, gives a current leading the voltage Vac by 60°, and provides a correct directional tripping zone over a current range of 30° leading to 150° lagging. The torque at unity power factor is 0.5 of maximum torque and at zero power factor lagging 0.866; see (Fig.14). It has been proved that the most suitable maximum torque angle for this relay connection, that is, one which ensures correct directional discrimination with the minimum risk of mal-operation when applied to either plain or transformer feeders, is 0°. When used for the protection of plain feeders there is a slight possibility of the element associated with the A phase mal-operating for a reversed B—C fault.

A phase element connected lab Vac B phase element connected I b c V b a C phase element connected Ica Vcb (Fig.14) Vector diagram for the 60° No. 1 connection (phase A element) However, although the directional element may mal-operation, it is unlikely that the over current element which the directional element controls will receive sufficient current to cause it to operate. For this reason the connection may be safely recommended for the protection of plain feeders. When applied to transformer feeders there is a possibility of one of the directional elements mal-operation for an earth fault on the star side of a

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delta/star transformer, remote from the relay end. For mal-operation to occur, the source impedance would have to be relatively small and have a very low angle at the same time that the arc resistance of the fault was high. The possibility of mal-operation with this connection is very remote, for two reasons: first, in most systems the source impedance may be safely assumed to be largely reactive, and secondly, if the arc resistance is high enough to cause mal-operation of the directional element it is unlikely that the over current element associated with the mal-operation directional element will see sufficient current to operate. The connection, however, does suffer from the disadvantage that it is necessary to connect the current transformers in delta, which usually precludes their being used for any other protective function. For this reason, and also because it offers no advantage over the 90° connection, it is rarely used. 60° No. 2 connection (0° MTA) The A phase relay is supplied with current la and voltage In this case, the flux of the voltage coil lags the applied voltage by 90° so the maximum torque is produced when the current lags the system phase to neutral voltage by 60°. This connection gives

A phase element connected Ia —Vc B phase element connected Ib — Va C phase element connected Ic —Vb (Fig.15) Vector diagram for the 60° No. 2 connection (phase A element). a correct directional tripping zone over the current range of 30° leading to 150° lagging. The relay torque at unity power factor is 0.5 of the relay maximum torque and at zero power factor lagging 0.866; see (Fig.15). 344

The most suitable maximum torque angle for a directional element using this connection is 0°. However, even if this maximum torque angle is used, there is a risk of incorrect operation for all types of faults with the exception of three-phase faults. For this reason, the 60° No. 2 connection is now never recommended.

A phase element connected Ia Vbc B phase element connected Ib Vca C phase element connected Ic Vab (Fig.16) Vector diagram for the 90°- 30° connection (Phase A element) 90° relay quadrature connection This is the standard connection for the type CDD relay; depending on the angle by which the applied voltage is shifted to produce the relay maximum torque angle, two types are available. 90°- 30° characteristic (30° MTA) The A phase relay is supplied with la current and Vbc voltage displaced by 30° in an anti-clockwise direction. In this case, the flux due to the voltage coil lags the applied voltage Vbc by 60°, and the relay maximum torque is produced when the current lags the system phase to neutral voltage by 60°. This connection gives a correct directional tripping zone over the current range of 30° leading to 150° lagging; see (Fig.16). The relay torque at unity power factor is 0.5 of the relay maximum torque and at zero power factor lagging 0.866. A relay designed .for quadrature connection and having a maximum torque angle of 30° is recommended when the relay is used for the protection of plain feeders with the zero sequence source behind the relaying point. 90°- 45° characteristic (45° MTA) The A phase relay is supplied with current la and voltage Vbc displaced by 45° in an anti-clockwise direction. In this case, the flux due to the voltage coil lags the applied voltage Vbc by 45°, and the relay maximum torque is 345

produced when the current lags the system phase to neutral voltage by 45°. This connection gives a correct directional tripping zone over the current range of 45° leading to 135° lagging. The relay torque at unity power factor is 0.707 of the maximum torque and the same at zero power factor lagging; see (Fig.17).

A phase element connected Ia ,Vbc B phase element connected Ih Vca C phase element connected Ic Vab (Fig.17) Vector diagram for the 90°-45° connection (Phase A element) This connection is recommended for the protection of transformer feeders or feeders which have a zero sequence source in front of the relay. The 90°- 45° connection is essential in the case of parallel trans-formers or transformer feeders, in order to ensure correct relay operation for faults beyond the star/ delta transformer. This connection should also be used whenever single-phase directional relays are applied to a circuit Theoretically, three fault conditions can cause mal-operation of the directional element: a phase-phase ground fault on a plain feeder, a phaseground fault on a transformer feeder with the zero sequence source in front of the relay and a phase-phase fault on a power transformer with the relay looking into the delta winding of the transformer. It should be remembered, however, that the conditions assumed above to establish the maximum angular displacement between the current and voltage quantities at the relay, are such that, in practice, the magnitude of the current input to the relay would be insufficient to cause the over current element to operate. It can be shown analytically that the possibility of maloperation with the 90°- 45° connection is, for all practical purposes, nonexistent.

346

(Fig.18) Directional relays applied to parallel feeders. Parallel feeders If non-directional relays are applied to parallel feeders, any faults that might occur on any one line will, regardless of the relay settings used, isolate both lines and completely disconnect the power supply. With this type of system configuration it is necessary to apply directional relays at the receiving end and to grade them with the non-directional relays at the sending end, to ensure correct discriminative operation of the relays during line. faults. This is done by setting the directional relays R'1 and R'2 as shown in (Fig.18) with their directional elements looking into the protected line, and giving them lower time and current settings than relays R1 and R2. The usual practice is to set relays R'1 and R'2 to 50% of the normal full load of the protected circuit and 0.1 TMS, but care must be taken to ensure that their continuous thermal rating of twice rated current is not exceeded. Ring mains Directional relays are more commonly applied to ring mains. In the case of a ring main fed at one point only, the relays at the supply end and at the midpoint substation, where the setting of both relays are identical, can be made non-directional, provided that in the latter case the relays are located on the same feeder, that is, one at each end of the feeder. It is interesting to note that when the number of feeders round the ring is an even number, the two relays with the same operating time are at the same substation and will have to be directional, whereas when the number of feeders is an odd number, the two relays with the same operating time are at different substations and therefore do not need to be directional. It may also be noted that, at inter-mediate substations, whenever the operating times of the relays at each substation are different, the difference between their operating times is never less than the grading margin, so the relay with the longer operating time can be non-directional. Grading of ring mains

347

The usual procedure for grading relays in an inter-connected system is to open the ring at the supply point and to grade the relays first clockwise and then anti-clockwise; that is, the relays looking in a clock-wise direction round the ring are arranged to operate in the sequence 1—2—3—4—5—6 and the relays looking in the anti-clockwise direction are arranged to operate in the sequence 1'—2'—3'—4'—5'—6', as shown in (Fig.19)

(Fig.19) Grading of ring mains The arrows associated with the relaying points indicate the direction of current flow that will cause the relays to operate. A double-headed arrow is used to indicate a non-directional relay, such as those at the supply point where the power can flow only in one direction, and a single-headed arrow a directional relay, such as those at intermediate substations around the ring where the power can flow in either direction. The directional relays are set in accordance with the invariable rule, applicable to all forms of directional protection that the current in the system must flow from the substation bus-bars into the protected line in order that the relays may operate. Disconnection of the faulty line is carried out according to time and fault current direction. As in any parallel system, the fault current has two parallel paths and divides itself in the inverse ratio of their impedances. Thus, at each substation in the ring, one set of relays will be made inoperative because of the direction of current flow, and the other set operative. It will also be found that the operating times of the relays that are inoperative are

348

faster than those of the operative relays, with the exception of the mid-point substation, where the operating times of relays 3 and 3' happen to be the same. The relays which are operative are graded downwards towards the fault and the last to be affected by the fault operates first. This applies to both paths to the fault. Consequently, the faulty line is the only one to be disconnected from the ring and the power supply is maintained to all the substations. When two or more power sources feed into a ring main, time graded over current protection is difficult to apply and full discrimination may not be possible. With two sources of supply, two solutions are possible. The first is to open the ring at one of the supply points, whichever is more convenient, by means of a suitable high set instantaneous over-current relay and then to proceed to grade the ring as in the case of a single infeed, the second to treat the section of the ring between the two supply points as a continuous bus separate from the ring and to protect it with a unit system of protection, such as pilot wire relays, and then proceed to grade the ring as in the case of a single infeed. Directional Earth-Fault Protection In the directional over-current protection the current coil of relay is actuated from secondary current of line CT. whereas the current coil of directional earth fault relay is actuated by residual current. In directional over-current relay, the voltage coil is actuated by secondary of line VT. In directional earth fault relay, the voltage coil is actuated by the residual voltage. Directional earth fault relays sense the direction in which earth fault occurs with respect to the relay location and it operates for fault in a particular direction. The directional earth fault relay (single phase unit) has two coils. The polarizing quantity is obtained either from residual current I RS = (Ia + Ib + Ic) or residual voltage

VRs = V a + V b + V c

Where V a , V b and Vc are phase voltages. Referring to (Fig. 11) the directional earth-fault relay has two coils. One to the coils is connected in residual current circuits (Ref. Fig. 5). This coil gets current during earth-faults. The other coil gets residual voltage, V RS= V a + V b + V c Where V a , V b a n d V c are secondary voltages of the potential transformer

349

('Three phase five limb potential transformer or three separate single phase potential transformers connected as shown in Fig. 20). The coil connected in potential-transformer secondary circuit gives a polarizing field.

(Fig. 20) Connections of a directional earth-fault relay. The residual current I RS i.e. the out of balance current is given to the current coil and the residual voltage VRs is given to the voltage coil of the relay. The torque is proportional to T = I RS * V RS * cos (Φ - α) Φ = angle between I RS and VRs α = angle of maximum torque. Summary Over-current protection responds to increase in current above the pick-up value over-currents are caused by overloads and short-circuits. The over-current relays are connected the secondary of current transformer. The characteristic of over-current relays include inverse time characteristic, definite time characteristic. Earth fault protection responds to single line to ground faults and double line to ground faults. The current coil of earth-fault relay is connected either in neutral to ground circuit or in residually connected secondary CT circuit. Core balance CTs are used for earth-fault protection. Frame leakage protection can be used for metal clad switchgear. Directional over-current relay and Directional Earth fault relay responds to fault in which power flow is in the set direction from the CT and PT locations. Such directional relays are used when power can flow from both directions to the fault point. Co-ordination Correct current relay application requires knowledge of the fault current that can flow in each part of the network. Since large scale tests are normally impracticable, system analysis must be used. It is generally sufficient to use machine transient reactance X'd and to work on the instantaneous symmetrical currents. The data required for a relay setting study are: 1. A one-line diagram of the power system involved, showing the type and rating of the protective devices and their associated current transformers. 2. The impedances in ohms, per cent or per unit, of all power transformers, rotating machines and feeder circuits. 3. The maximum and minimum values of short circuit currents that are expected to flow through each protective device.

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4. The starting current requirements of motors and the starting and stalling times of induction motors. 5. The maximum peak load current through protective devices. 6. Decrement curves showing the rate of decay of the fault current supplied by the generators. 7. Performance curves of the current transformers. 8. The relay settings are first determined so as to give the shortest operating times at maximum fault levels and then checked to see if operation will also be satisfactory at the minimum fault current expected. It is always advisable to plot the curves of relays and other protective devices, such as fuses, that are to operate in series, on a common scale. It is usually more convenient to use a scale corresponding to the current expected at the lowest voltage base or to use the predominant voltage base. The alternatives are a common MVA base or a separate current scale for each system voltage. 9. The basic rules for correct relay co-ordination can generally be stated as follows: 10. Whenever possible, use relays with the same operating characteristic in series with each other. 11. Make sure that the relay farthest from the source has current settings equal to or less than the relays behind it, that is, that the primary current required operating the relay in front is always equal to or less than the primary current required operating the relay behind it. PRINCIPLES OF TIME/CURRENT GRADING Among the various possible methods used to achieve correct relay coordination are those using either time or over current or a combination of both time and over-current. The common aim of all three methods is to give correct discrimination. That is to say, each one must select and isolate only the faulty section of the power system network, leaving the rest of the system undisturbed. 1. Discrimination by time In this method an appropriate time interval is given by each of the relays controlling the circuit breakers in a power system to ensure that the breaker nearest to the fault opens first. A simple radial distribution system is shown in (Fig. 21) to illustrate the principle.

(Fig. 21) Radial systems with time discrimination Circuit breaker protection is provided at B, C, D and E, that is, at the infeed end of each section of the power system. Each protection unit comprises a definite time delay over current relay in which the operation of the current

351

sensitive element simply initiates the time delay element. Provided the setting of the current element is below the fault current value this element plays no part in the achievement of discrimination. For this reason, the relay is sometimes described as an 'independent definite time delay relay' since its operating time is for practical purposes independent of the level of over current. It is the time delay element, therefore, which provides the means of discrimination. The relay at B is set at the shortest time delay permissible to allow a fuse to blow for a fault on the secondary side of trans-former A. Typically, a time delay of 0.25s is adequate. If a fault occurs at F, the relay at B will operate in 0.25s, and the subsequent operation of the circuit breaker at B will clear the fault before the relays at C, D and E have time to operate. The main disadvantage of this method of discrimination is that the longest fault clearance time occurs for faults in the section closest to the power source, where the fault level (MVA) is highest. 1.

Discrimination by current

Discrimination by current relies on the fact that the fault current varies with the position of the fault, because of the difference in impedance values between the source and the fault. Hence, typically, the relays controlling the various circuit breakers are set to operate at suitably tapered values such that only the relay nearest to the fault trips its breaker. (Fig. 22) illustrates the method.

(Fig. 22) Radial system with current discrimination For a fault at F1, the system short circuit current is given by: I = 6350 /(Zs + ZL1)

A

Where Zs = source impedance = 11 2 / 250 = 0.485 ohms ZL1= cable impedance between C and B = 0.24 ohms Hence I=6350/0.725 = 8800 A So a relay controlling the circuit breaker at C and set to operate at a fault current of 8800 A would in simple theory protect the whole of the cable section between C and B. However, there are two important practical points which affect this method of co-ordination. 352

1. It is not practical to distinguish between a fault at Fl and a fault at F 2, since the distance between these points can be only a few meters, corresponding to a change in fault current of approximately 0.1%. 2. In practice, there would be variations in the source fault level, typically from 250 MVA to 130 MVA. At this lower fault level the fault current would not exceed 6800 A even for a cable fault close to C, so a relay set at 8800 A would not protect any of the cable section concerned.

Discrimination by current is therefore not a practical proposition for correct grading between the circuit breakers at C and B. However, the problem changes appreciably when there is significant impedance between the two circuit breakers concerned. This can be seen by considering the grading required between the circuit breakers at B and A in (Fig. 22). Assuming a fault at F 4, the short-circuit current is given by: I = 6350 /(Zs + ZL1 + ZL2 +ZT)

A

Where ZS = source impedance =112 / 250 = 0.485 ohms ZL1 = cable impedance between C and B 0.24 ohms ZL2 = cable impedance between B and 4 MVA transformer 0.04 ohms ZT = transformer impedance =0.07(112/4) =2.12 ohms Hence I = 6350/ 2.885 = 2200 A For this reason, a relay controlling the circuit breaker at B and set to operate at a current of 2200 A plus a safety margin would not operate for a fault at F 4 and would thus discriminate with the relay at A. Assuming a safety margin of 20% to allow for relay errors and a further 10% for variations in the system impedance values, it is reasonable to choose a relay setting of 1.3 x 2200, that is, 2860 A for the relay at B. Now, assuming a fault at F3, that is, at the end of the 11 kV cable feeding the 4 MVA transformers, the short-circuit current is given by: I = 6350 /(Zs + ZL1 + ZL2 +ZT) I = 6350 /(0.485 + 0.24 + 0.04)=8300 Amp. Alternatively, assuming a source fault level of 130 MVA: I = 6350 /(0.93 + 0.24 + 0.004)=5250 Amp. In other words, for either value of source level, the relay at B would operate correctly for faults anywhere on the 11 kV cable feeding the transformer.

353

ELECTRIC FIELD STRESSES ELECTRIC FIELD STRESSES Like In mechanical .designs where the criterion for design depends on the mechanical strength, of the materials and the stresses that are generated during their operation, in high voltage applications, the dielectric strength of insulating materials and the electric field stresses developed in them when subjected to high voltages are. The important factors in high voltage systems in a high voltage apparatus the important materials used are conductors and insulators. While the conductors carry current the insulators prevent the flow of currents undesired paths the electric, stress to which an insulating material is subjected to is numerically equal to the voltage gradient, and is equal to the electric field intensity

E = −∇ϕ

→1

Where E is the electric field intensity, φ is the applied voltage, And (read Del) operator is defined as ∇

∇ = ax

∂ ∂ ∂ + ay + az ∂X ∂Y ∂Y

Where ax, ay, and aZ are components of position vector

r = a . X +a .Y + a .Z

x y z . As already mentioned, the most important material used in a high voltage apparatus is the insulation. The dielectric strength of an insulating material can be defined as the maximum dielectric stress which the material can Withstand. It can also be defined as the voltage at which the current starts increasing to very high values unless controlled by the external impedance of the circuit.

The electric breakdown strength of insulating materials depends on a variety of parameters, such as pressure, temperature, humidity, field configurations, nature of applied voltage, imperfections in dielectric materials, material of electrodes, and surface conditions of electrodes, etc. An understanding of the failure of the insulation will be possible by the study of the possible mechanisms by which the failure can occur. The most common cause of insulation failure is the presence of discharges either within the voids in the insulation or over the surface of the insulation. The probability of failure will be greatly reduced if such discharges could be eliminated at the normal working voltage. Then, failure can occur as a result of thermal or electrochemical deterioration of the insulation. Gas/vacuum as Insulator Air at atmospheric pressure is the most common gaseous insulation. The breakdown of air is of considerable practical importance to the design engineers of power 354

transmission lines and power apparatus. Breakdown occurs in gases due to the process of collisional ionization. Electrons get multiplied in an exponential manner, and if the applied voltage is sufficiently large, breakdown occurs. In some gases, free electrons are removed by attachment to neutral gas molecules; the breakdown strength of such gases is substantially large. An example of such a gas, with larger dielectric strength, is sulphur hexafluoride (SF6). High pressure gas, provides a flexible and reliable medium for high voltage insulation using gases at high pressures, field gradients up to 25 MV/m have been realized. Nitrogen (N2) was the gas first used at high pressures because of its inertness and chemical stability, but its dielectric strength is the same as that of air. Other important practical insulating gases are carbon dioxide (CO2), dichlorodifluor9methane (CC12F2) (popularly known as Freon), and sulphur hexafluoride (SF6). The breakdown voltage at higher pressures in gases shows an increasing dependence on the nature and smoothness of the electrode material. It is relevant to point out that, of the gases examined to-date, SF6 has probably the most attractive overall dielectric and arc quenching properties for gas insulated high voltage systems. However, in recent years pure SF6 gas has been found to be a green house gas causing environmental hazards and therefore research efforts are presently focussed on finding a replacement gas or gas mixture which is environmentally friendly. Pure nitrogen, air and SF6/N2 mixtures show good potential to replace SF6 gas in high voltage apparatus. In the next few years, SF6/N2, SF6 gas has to be replaced by a new gas and lot of research is being done to find such a gas. Ideally, vacuum is the best insulator with field strengths up to 107 V/cm, limited only by emissions from the electrode surfaces. This decreases to less than 105 V/cm for gaps of several centimeters. Under high vacuum conditions, where the pressures are below 10-4 ton, the breakdown cannot occur due to collisional processes like in gases, and hence the breakdown strength is quite high. Vacuum insulation is used in particle accelerators, x-ray and field emission tubes, electron microscopes, capacitors, and Circuit Breakers. LIQUID DIELECTRICS Liquids are used in high voltage equipment to serve the dual purpose of insulation and heat condition. They have the advantage that a puncture path is self-healing. Temporary failures due to over voltage are reinsulated quickly by liquid flow to the attacked area. However, the products of the discharges may deposit on solid insulation supports and may lead to surface breakdown over these solid supports. Highly purified liquids have dielectric strengths as high as 1 MV/cm. Under actual service conditions, the breakdown strength reduces considerably due to the presence of impurities. The breakdown mechanism in the case of very pure liquids is the same as the gas breakdown, but in commercial liquids, the breakdown mechanisms are significantly altered by the presence of the solid impurities and dissolved gases.

355

Petroleum oils are the commonest insulating liquids. However, fluorocarbons, silicones, and organic esters including castor oil are used in significant quantities. A number of considerations enter into the selection of any dielectric liquid. The important electrical properties of the liquid include the dielectric strength, conductivity, flash point, gas content, viscosity, dielectric constant, dissipation factor, stability, etc. Because of their low dissipation factor and other excellent characteristics, polybutanes are being increasingly used in the electrical industry. However, in 1970s it was found that Askarels which more extensively used, exhibit health hazards and therefore most countries have legally banned their production and use. Many new liquids have since been developed which have no adverse environmental hazards. These include silicone oils, synthetic and fluorinated hydrocarbons. In practical applications liquids are normally used at voltage stresses of about 50–60 kV/cm when the equipment is continuously operated. On the other hand, in applications like high voltage bushings, where the liquid only fills up the voids in the solid dielectric, it can be used at stresses as high as 100–200 kV/cm.

·

SOLIDS AND COMPOSITES

1. Solid Dielectrics A good solid dielectric should have some of the properties mentioned earlier for gases and liquids and it should also possess good mechanical and bonding strengths. Many organic and inorganic materials are used for high voltage insulation purposes. Widely used inorganic materials are ceramics and glass. The most widely used organic materials are thermosetting epoxy resins such as polyvinyl chloride (PVC), polyethylene (PE) or cross linked polyethylene (XLPE). Kraft paper, natural rubber, silicon rubber and polypropylene rubber are some of the other materials widely used as insulates in electrical equipment. If the solid insulating material is truly homogeneous and is free from imperfections, its breakdown stress will be as high as 10 MV/cm. This is the `intrinsic breakdown strength', and can be obtained only under carefully controlled laboratory conditions. However, in practice, the breakdown fields obtained are very much lower than this value. The breakdown occurs due to many mechanisms. In general, the breakdown occurs over the surface than in the solid itself, and the surface insulation failure is the most frequent cause of trouble in practice.

2. Composites In many engineering applications, more than one types of insulation are used together, mainly in parallel, giving rise to composite insulation systems. Examples of such systems are solid/gas insulation (transmission line insulators), solid/vacuum insulation and solid/liquid composite insulation systems (trans356

former winding insulation, oil impregnated paper and oil impregnated metallised plastic film etc). In the application of composites, it is important to make sure that both the components of the composite should be chemically stable and will not react with each other under the application of combined thermal, mechanical and electrical stresses over the expected life of the equipment. They should also have nearly equal dielectric constants. Further, the liquid insulate should not absorb any impurities from the solid, which may adversely affect its resistivity, dielectric strength, loss factor and other properties of the liquid dielectric. It is the intensity of the electric field that determines the onset of breakdown and the rate of increase of current before breakdown. Therefore, it is very essential that the electric stress should be properly estimated and its distribution known-in a high voltage apparatus. Special care should be exercised in eliminating the stress in the regions where it is expected to be maximum, such as in the presence of sharp points.

·

Estimation and control of electrical

The electric field distribution is usually governed by the Poisson's equation:

ρ ε0

∇2ϕ =−

→2

Where φ is the potential at a given point, ρ

Is the space charge density in the region

ε0

Is the electric permittivity of free space (vacuum) However, in most of the high voltage apparatus, space charges are not normally present, and hence the potential distribution is governed by the Laplace's equation:

∇ 2ϕ = 0

→3

357

In Eqs. (2) and (3) the operator properties

∇2 =

∇2

is called the Laplacian and is a vector with

∂2 ∂2 ∂2 + + ∂X 2 ∂y 2 ∂Z 2

There are many methods available for determining the potential distribution. The most commonly used methods are 1.

The electrolytic tank method, and

2.

The numerical methods

3. The potential distribution can also be calculated directly. However, this is very difficult except for simple geometries. In many practical cases, a good understanding of the problem is possible by using some simple rules to plot the field lines and equipotentials. The important rules are 4.

The equipotentials cut the field lines at right angles,

5. When the equipotentials and field lines are drawn to form curvilinear squares, the density of the field lines is an indication of the electric stress in a given region, and in any region, the maximum electric field is given by dv/dx, where dv is the voltage difference between two successive equipotentials, dx apart. Considerable amount of labour and time can be saved by properly 'choosing the planes of symmetry and shaping the electrodes accordingly. Once the voltage distribution of a given geometry is established, it is easy to refashion or redesign the electrodes to minimize the stresses so that the onset of corona is prevented. This is a case normally encountered in high voltage electrodes of the bushings, standard capacitors, etc. When two dielectrics of widely different permittivity are in series, the electric stress is very much higher in the medium of lower permittivity. Considering a solid insulation in a gas medium, the stress in the gas εr

εr

becomes times that in the solid dielectric, where is the relative permittivity of the solid dielectric. This enhanced stress occurs at the electrode edges and one method of overcoming this is to increase the electrode diameter. Other methods of stress control are shown in Fig. 1

358

Fig. 1 Control of stress at an electrode edge SOLIDS AND COMPOSITES 1. Solid Dielectrics A good solid dielectric should have some of the properties mentioned earlier for gases and liquids and it should also possess good mechanical and bonding strengths. Many organic and inorganic' materials are used for high voltage insulation purposes. Widely used inorganic materials are ceramics and glass. The most widely used organic materials are thermosetting epoxy resins such as polyvinyl chloride (PVC), polyethylene (PE) or cross linked polyethylene (XLPE). Kraft paper, natural rubber, silicon rubber and polypropylene rubber are some of the other materials widely used as insulate in electrical equipment. If the solid insulating material is truly homogeneous and is free from imperfections, its breakdown stress will be as high as 10 MV/cm. This is the `intrinsic breakdown strength', and can be obtained only under carefully controlled laboratory conditions. However, in practice, the breakdown fields obtained are very much lower than this value. The breakdown occurs due to many mechanisms. In general, the breakdown occurs over the surface than in the solid itself, and the surface insulation failure is the most frequent cause of trouble in practice. 2. Composites In many engineering applications, more than one types of insulation are used together, mainly in parallel, giving rise to composite insulation systems. Examples of such systems are solid/gas insulation (transmission line insulators), solid/vacuum insulation and solid/liquid composite insulation systems (trans-former winding insulation, oil impregnated paper and oil impregnated metallised plastic film etc). In the application of composites, it is important to make sure that both the components of the composite should be chemically stable and will not react with each other under the application of combined thermal, mechanical and electrical stresses over the expected life of the equipment. They should also have nearly equal dielectric constants. Further, the liquid insulate should not absorb any impurities from the solid, which may adversely affect its resistivity, dielectric strength, loss factor and other properties of the liquid dielectric. It is the intensity of the electric field that determines the onset of breakdown and the rate of increase of current before breakdown. Therefore, it is very essential that the electric stress should be properly estimated and its distribution known in a high voltage apparatus. Special care should be exercised in eliminating the 359

stress in the regions where it is expected to be maximum such as in the presence of sharp points. In the design of high voltage apparatus, the electric field intensities have to be controlled, otherwise higher stresses will trigger or accelerate the aging of the insulation leading to its failure. Over the years, many methods for controlling and optimizing electric fields to get the most economical designs have been developed. Electric field control methods form an important component of the overall design of equipment. Electric Field A brief review of the concepts of electric fields is presented, as it is essential for high voltage engineers to have knowledge of the field intensities in various media under electric stresses. It also helps in choosing proper electrode configurations and economical dimensioning of the insulation, such that highly stressed regions are not formed and reliable operation of the equipment results in its anticipated life. The field intensity E at any location in an electrostatic field is the ratio of the force on an infinitely small charge at that location to the charge itself as the charge decreases to zero. The force F on any charge q at that point in the field is given by F = q*E

4

The electric flux density D associated with the field intensity E is D = ε*E 5 Where E is the permittivity of the medium in which the electric field exists. The work done on a charge when moved in an electric field is defined as the potential. The potential φ is equal to

Where l is the path through which the charge is moved. Several relationships between the various quantities in the electric field can be summarized as follows:

Where F is the force exerted on a charge q in the electric field E , and S is the closed surface containing charge q.

360

Uniform and Non-Uniform Electric Fields In general, the electric fields between any two electrodes can be both uniform and non-uniform. In a uniform field gap, the average field E is the same throughout the field rigion, whereas in a non-uniform field gap, E is different at different points of the field region. Uniform or approximately uniform field distributions exist between two infinite parallel plates or two spheres of equal diameters when the gap distance is less than diameter of the sphere. Spherical electrodes are frequently used for high voltage measurements and for triggering in impulse voltage generation circuits. Sometimes, parallel plates of finite size are used to simulate uniform electric fields, when gap separation is much smaller than plate size. In the absence of space charges, the average field E in a non-uniform field gap is maximum at the surface of the conductor which has the smallest radius of curvature. It has the minimum field E at the conductor having the large radius of curvature. In this case, the field is not only non-uniform but also asymmetrical. Most of the practical high voltage components used in electric power systems normally have non-uniform and asymmetrical field distribution. Estimation of Electric Field in Some Geometric Boundaries It has been shown that the maximum electric field Em in a given electric field configuration is of importance. The mean electric field over a distanced between two conductors with a potential difference of V12 is

Ε av =

V12 d

In field configurations of non-uniform fields, the maximum electric field Em is always higher than the average value. For some common field configurations, the maximum value of Em and the field enhancement factor f given by Em/Eav, are presented Below. f = Em / Eav 1-Parallel plates

Em = r

V r

f =1

Parallel plate

361

2- Concentric cylinders

3- Parallel cylinders of equal diameter

SURGE VOLTAGES, THEIR DISTRIBUTION AND CONTROL The design of power apparatus particularly at high voltages is governed by their transient behavior. The transient high voltages or surge voltages originate in power systems due to lightning and Switching operations. The effect of the surge voltages is severe in all power apparatuses. The response of a power apparatus to the impulse or surge voltage depends on the capacitances between the coils of windings and between the different phase windings of the multi-phase machines. The transient voltage distribution in, the windings as a whole are generally very nonuniform and are complicated by traveling wave voltage oscillations set up within the windings. In the actual design of an apparatus, it is, of course, necessary to consider the maximum voltage differences occurring, in each region, at any instant of time after the application of an impulse, and to take into account their durations especially when they are less than one microsecond. An experimental assessment of the dielectric strength of insulation against the power frequency voltages and surge voltages, on samples of basic materials, on less complex

362

assemblies, or on complete equipment must involve high voltage testing. Since the design of an electrical apparatus is based on the dielectric strength, the design cannot be completely relied upon, unless experimentally tested. High voltage testing is done by generating the voltages and measuring them in a laboratory. When high voltage testing is done on component parts, elaborate insulation assemblies, and complete full-scale prototype apparatus (called development testing), it is possible to build up a considerable stock of design information; although expensive, such data can be very useful. However, such data can never really be complete to cover all future designs and necessitates use of large factors of safety. A different approach to the problem is the exact calculation of dielectric strength of any insulation arrangement. In an ideal design each part of the dielectric would be uniformly stressed at the maximum value which it will safely withstand. Such an ideal condition is impossible to achieve in practice, for dielectrics of different electrical strengths, due to the practical limitations of construction. Nevertheless it provides information on stress concentration factors the ratios of maximum local voltage gradients to the mean value in the adjacent regions of relatively uniform stress. A survey of typical power apparatus designs suggests that factors ranging from 2 to 5 can occur in practice; when this factor is high, considerable quantities of insulation must be used. Generally, Improvements can be effected in the following ways: 1. by shaping the conductors to reduce stress concentrations, 2. by insertion of higher dielectric strength insulation at high stress points, and by selection of materials of appropriate permittivity to obtain more uniform voltage gradients. Insulating gases Electronegative gases make good insulators since the ions rapidly combine with the ions produced in the spark. However, they tend to be corrosive. Some gases though, dissociate only where the discharge is (or wants to be), making them particularly good insulators. Gases with electronegative species (i.e. halogens such as chlorine) make good insulators, hence the popularity of SF6, which is not only dense (breakdown voltage is roughly proportional to density) but is mostly Fluorine, a highly electronegative element. The halogenated hydrocarbon refrigerants are also a popular insulator. CCl4, CCl2F2, CCl3F, and C2Cl2F4 Unfortunately, the cost of insulating gases has greatly increased in the last few years largely due to the various treaties regulating halocarbon refrigerants. The traditional Freons (R-12, R-22) are not being produced any more, and are quite expensive. Since the regulatory thrust eliminated chlorinated alkanes, modern refrigerants are relying more on fluorinated or per-fluoro hydrocarbons (e.g.HC-134a) . Unfortunately, plant capacity is limited, and plants that used to make SF6 are now making fluorinated hydrocarbons resulting in much higher prices for SF6. In the mid 1980's SF6 was about $3-4/lb. Now, in the mid 90's, it is about $100/lb. Since a pound is only about 10 liters, filling up a large insulating tank with SF6 has become a very expensive proposition. 363

The breakdown voltage of most gases can be increased by increasing the absolute pressure. In the case of some gases, there is a limit imposed by the liquefaction point at normal operating temperatures (i.e. Freon 12 liquifies at 5 atmospheres). Mixtures of gases can overcome some of these issues and a mixture of Freon 12 and Nitrogen was popular. One disadvantage of the halogenated compounds is that the dissociation products are highly corrosive, so it is important that operating voltages remain well below corona starting voltages. Even air forms highly reactive nitrogen oxides and other corrosive compounds, particularly if there is any water vapor present. High pressure air can also support combustion due to the oxygen content. Pure Nitrogen seems to not have these disadvantages, although its breakdown is only about 15 % better than air. Air - approximate breakdown is 30 kV/cm at 1 atm. = 30 + 1.53d where d in cm. The breakdown of air is very well researched, to the point where the breakdown voltage of a calibrated gap is used to measure high voltages. Freons- The vapor pressure of CCl2F2 (R-12) is 90 psi at 23C, where the breakdown is some 17 times that of air at 1 atm. An even higher insulating strength can be obtained by adding nitrogen to the saturated CCl2F2 to bring the total pressuire to the desired value. The saturated vapor pressure of C2Cl2F4 at 23C is 2 atm abs, at which condition it has a relative dielectric strength of 5.6 times N2 at 1 atm Sulfur Hexafluoride (SF6) - Sulfur Hexafluoride is probably the most popular insulating gas, although its cost has risen dramatically recently. Hydrogen - Hydrogen gas is not a particularly good insulator (65% of air) from a breakdown voltage standpoint. Its very low viscosity and high thermal capacity make it an insulating gas of choice for high speed, high voltage machinery such as turbo generators. There isn't an explosion hazard, provided that the oxygen content in the hydrogen tank is kept below the flammable limit (around 5%). Of course, hydrogen has lots of other handling problems, including hydrogen embrittlement, it leaks through very tiny holes (even the pores in the metal tanks), and perfectly colorless, but very hot, flames. Relative spark breakdown strength of gases Gas N2 Air NH3 CO2 H2S O2 Cl2 H2 SO2 C2Cl2F4 V/Vair 1.15 1 1 0.95 0.9 0.85 0.85 0.65 0.30 3.2

CCl2F2 2.9

Conduction and breakdown in Gases 1 – Gases as insulating Media The .simplest and the most commonly found dielectrics are gases. Most of the electrical apparatus use air as the Insulating medium, and in a few cases other gases such nitrogen (N2), carbon dioxide (CO2), freon (CC12F2) and sulphur hexafluoride (SF6) are also used. Various phenomena occur in gaseous dielectrics when a voltage is applied. When the applied voltage is low, small currents flow between the electrodes and they insulation retains, it's electrical properties. On the other hand, if the applied voltages 364

are large, the current flowing through the insulation increases very sharply an electrical breakdown occurs. A strongly conducting spark formed during breakdown practically produces a short circuit between the electrodes. The maximum voltage applied to the insulation at the moment of breakdown is called the breakdown voltage In .order to understand the breakdown phenomenon in gases, a study of the electrical properties of gases and the processes by which high current are produced in gases is essential. The electrical discharges in gases are of two types:(i) Non-sustaining discharge. (ii) self- sustaining. The breakdown in a gas, called spark is the transition of non-sustaining discharge into a self-sustaining discharge. The build-up of high currents in a breakdown is due to the process known as ionization in which electrons and ions are created from neutral atoms or molecules' and their migration to the anode and cathode respectively leads to high current. At present two types of theories, viz. (i) Townsend theory (ii) Streamer theory are known 'Which explain the mechanism of breakdown under different condition? The various physical condition of gases namely' pressure, temperature, electrode field configuration nature of electrode surfaces and the availability of initial conducting particles are known to govern the ionization processes. COLLISION PROCESSES 1. Types of Collision An electrical discharge is normally created from unionized gas by collision processes. These processes are mainly gas processes which occur due to the collision between the charged particles and gas atoms or molecules. These are of the following two types. Elastic collisions: Elastic collisions are collisions which when occur, no change takes place in the internal energy of the particles but only their kinetic energy gets redistributed. These collisions do not occur in practice. When electrons collide with gas molecules, a single electron traces' a zig-zag path during its travel. But in between the collisions it is accelerated by the electric field. Since electrons are very light in weight, they transfer only a part of their kinetic energy to the much heavier ions or gas molecules with which they collide. These results in very little loss of energy by the electrons and therefore electrons gain very high energies and travel at a much higher speed than the ions. Therefore in all electrical discharges electrons play a leading role. Inelastic collisions: Inelastic collisions, on the other hand, are those in which internal changes in energy take place within an atom or a molecule at the expense of the total kinetic energy of the colliding particle. The collision often results in a change in the 365

structure of the atom. Thus all collisions that occur in practice are inelastic collisions. For example ionization, attachment, excitation, recombination are inelastic collisions.

2. Mobility of Ions and Electrons When an ion moves through a gas under the influence of a static uniform electric field, it gains energy from the field between collisions and loses energy during collisions. Electric force on an electron/ion of charge e is eE, with the resulting acceleration being eE/m. When the energy gained by the ions from the electric field is small compared with the thermal energy, the drift velocity in the field direction Wi is proportional to the electrical field intensity E and may be expressed as follows: Wi = µi * E

(1)

Where µi is called the mobility of ions the mobility is mainly a characteristic of the gas through which the ion moves. At normal temperatures and pressures the mobility µ is of the order of several cm2/volt-sec. However, the concept of ionic mobility cannot be directly applied to electrons because of their extremely low mass. Any externally applied electric field will cause the electrons to gain energies much higher than their mean thermal energy. So the electron drift velocity, which has been defined as the average velocity, with which the centre of mass of the electron swarm moves in the direction of the field, is not a simple function of E/p, but is determined from the energy distribution function. From the kinetic theory the electron drift velocity We is given in microscopic terms as follows:

We = Ee / 3ma2 d/dc (l c2)

(2)

Where l is an equivalent mean free path of an electron with speed c

3. Diffusion Coefficient When particles possessing energy, which is exhibited as a random motion, are distributed unevenly throughout a space, then they tend to redistribute themselves uniformly throughout the space. This process is known as diffusion and the, rate at which this occurrence is governed by the diffusion passing through unit area in unit time perpendicular to the concentration gradient and for unit concentration gradient. In three dimensions this may be written as

δn = −D∇2 n δt

→3

366

Where n is the concentration of particles. Kinetic theory gives D in microscopic terms as follows D = 1/3 (lc)

4

Where l is the mean free path and c the random velocity, the average being taken over c In electrical discharges, whenever there is a non-uniform concentration of charges there will be migration of these charges from regions of higher concentration to regions of lower concentration. This process is called diffusion and this causes a deionising effect in the regions of lower concentration. The presence of walls confining a given volume increases the de-ionisation effect since charged particles lose their charge on hitting the wall. Both diffusion and mobility result in mass motion described by a drift velocity caused either by unbalanced collision forces (concentration gradient) or by the electric field itself. 4. Electron Energy Distributions For the development of a complete theory giving the relationship between the data concerning single collisions of electrons with gas molecules, and the experimentally obtained average properties of discharges, a knowledge of the electron energy distribution functions is essential. The most widely used distribution functions are the Maxwellian and Druyesteynian distributions which apply specifically to elastic conditions. The Maxwellian distribution has been found to apply where there is thermal equilibrium between the electrons and molecules. The distribution takes the form

F (ε ) = C1ε

0.5

.e

( −1.5

ε ) ε−

→5

Where Cl is the constant and is the mean energy. Druyesteynian distribution applies when the electron or ion energy is much greater than the thermal energy and is therefore expected to be more of application in transcends discharges. This distribution takes the form

F (ε ) = C 2ε

0.5

.e

( −1.5

Where C2 is another constant

367

ε2 ε −2

)

→6

5. Collision Cross Section Collision cross section is defined as the area of contact between two particles during a collision. In other words, the total area of impaCT'sThis area of contact is different for each type of collision. For example, the area of impact is more for ionisation while for an excitation it is less. For simultaneously, occurring processes such as ionization, excitation, charge transfer, chemical reactions, etc., the effective cross section is obtained by simple a addition of all the cross sections. If q, is the total cross section, and if qi, qe, qc ... etc., are the cross sections for ionization, excitation, charge transfer, etc, respectively, then qt= qi +qe + qc + ……. Thus the use of collision cross sections instead of mean free paths has often proved to be advantageous. The collision cross section is also expressed in terms of the probability of a collision to take place, i.e., P = nq

(7)

which is the reciprocal of the mean free path. 6 The Mean Free Path (λ) The mean free path is defined as the average distance between collisions. When a discharge occurs large number of collisions occurs between the electrons and the gas molecules. Depending on the initial energy of the colliding electron, the distance between the two collisions vary The average of this is the mean free path. The free path is a random quantity and its mean value depends upon the concentration of particles or the density of the gas. The mean free path can be expressed as λ =k / p

(8)

Where k is a constant and p is the gas pressure in microns. The value of k for nitrogen is 5. From this equation it is seen that at a pressure of 1 torr, λ is 5 x 10-3 cm. If the pressure is 10-6 ton, then λ = 5 x 10+3 cm. From this it is seen that mean free path is very large at very low pressures and is very small at high pressures.

IONIZATION PROCESSES A gas in its normal state is almost a perfect insulator. However, when a high voltage is applied between the two electrodes immersed in a gaseous medium, the gas becomes a conductor and an electrical breakdown occurs.

368

The processes that are primarily responsible for the breakdown of a gas are ionization by collision, photo-ionization, and the secondary ionization processes. In insulating gases (also called electron-attaching gases) the process of attachment also plays an important role. 1. Ionization by Collision The process of liberating an electron from a gas molecule with the simultaneous production of a positive ion is called ionization. In the process of ionization by collision, a free electron collides with a neutral gas molecule and gives rise to a new electron and a positive ion. If we consider a low pressure gas column in which an electric field E is applied across two plane parallel electrodes, as shown in Fig. 1 then, any electron starting at the cathode will be accelerated more and more between collisions with other gas molecules during its travel towards the anode. If he energy (ε) gained during this travel between collisions exceeds the ionization potential, Vi, which is the energy required to dislodge an electron from its atomic shell, then ionization takes place. This process can be represented as

e − + A → e − + A+ + e − Where, A is the atom, A + is the positive ion and a is the electron.

Ultraviolet Light

Anode

Cathode

-

+ d Current limiting resistor

R HV source A

Fig 1 Arrangment for study of a townsend discharge A few of the electrons produced at the cathode by some external means, say by ultraviolet light falling on the cathode, ionize neutral gas particles producing positive ions and additional electrons. The additional electrons, then, themselves make `ionizing collisions' and thus the process repeats itself. This represents an increase in the electron current, since the number of electrons reaching the anode

369

per unit time is greater than those liberated at the cathode. In addition, the positive ions also reach the cathode and on bombardment on the cathode give rise to secondary electrons. 2. Secondary Ionization Processes Secondary ionization processes by which secondary electrons are produced are the one which sustain a discharge after it is established due to ionization by collision and photo-ionization. They are briefly described below. (i) Electron Emission due, to Positive Ion Impact Positive ions are formed due to ionization by collision or by photo-ionization, and being positively charged, they travel towards the cathode. A positive ion approaching a metallic cathode can cause emission of electrons from the cathode by giving up its kinetic energy on impaCT's If the total energy of the positive ion, namely, the sum of its kinetic energy and the ionization energy, is greater than twice the work function of the metal, then one electron will be ejected and a second electron will neutralize the ion. The probability of this process is γi

measured as , which is called the Townsend's secondary ionization coefficient due to positive ions and is defined as the net yield of electrons per incident positive ion. γi

, increases with ion velocity and depends on the kind of gas and electrode material used. (ii)

Electron Emission due to Photons

To cause an electron to escape from a metal, it should be given enough energy to overcome the surface potential barrier. The energy can also be supplied in the form of a photon of ultraviolet light of suitable frequency. Electron emission from a metal surface occurs at the critical condition

h .v ≥ ϕ where cp is the work function of the metallic electrode. The frequency (v) is given by the relationship

v=

ϕ h

(10)

Is known as the threshold frequency For a clean nickel surface With φ = 4.5 eV, the threshold frequency will be that corresponding to a wavelength λ = 2755 Aº. If the incident radiation has a greater frequency than the threshold 370

frequency ', then the excess energy goes partly as the kinetic energy of the emitted electron and partly to heat the surface of the electrode. Since φ is typically a few electrons volts, the threshold frequency lies in the far ultraviolet region of the electromagnetic radiation spectrum. (iii)

Electron Emission due to Metastable and Neutral Atoms

A metastable atom or molecule is an excited particle whose lifetime is very large (103 s) compared to the lifetime of an ordinary particle (10-8 s). Electrons can be ejected from the metal surface by the impact of excited (metastable) atoms, provided that their total energy is sufficient to overcome the work function. This process is most easily observed with metastable atoms, because the lifetime of other excited states is too short for them to reach the cathode and cause electron emission, unless they originate very near to the cathode surface. Therefore, the yields can also be large nearly 100%, for the interactions of excited He atom with a clean surface of molybdenum, nickel or magnesium. Neutral atoms in the ground state also give rise to secondary electron emission if their kinetic energy is high (= 1000 eV). At low energies the yield is considerably less.

Electron Attachment Process The types of collisions in which electrons may become attached to atoms or molecules to form negative ions are called attachment collision. Electron attachment process depends on the energy of the electron arid-the nature of the gas and is a very important process from the engineering point of view. All electrically insulating gases, such as O2, CO2, C12, F2, .C2F6, C3F8, C4F10, CC12F2, and SF6 exhibit this property. An electron attachment process can be represented as: Atom + e- → negative atomic ion + (Ea + K)

11

The energy liberated as a result of this process is the kinetic energy K plus the electron affinity Ea. In the attaching or insulating gases, the atoms or molecules have vacancies in their outermost shells and, therefore, have an affinity for electrons. The attachment process plays a very important role in the removal of free electrons from an ionized gas when arc interruption occurs in gas-insulated Switchgear. TOWNSEND'S CURRENT GROWTH EQUATION Referring to Fig. 1 let us assume that no electrons are emitted from the cathode. When one electron collides with a neutral particle, a positive ion and an electron are formed. This is called an ionizing collision. Let α be the average number of ionizing collisions made by an electron per centimeter travel in the direction of the field (α depends on gas pressure p and E/p, and is called the Townsend's first ionization coefficient). At any distance x from the cathode, let the number of electrons be nx. When these nx electrons travel a further distance of dx they give X=0 nx=n0 d nx/dx = α nx ; nx=n0 e αx Then, The number of electrons reaching the anode (x=d) 371

nd=no e(α.d) The number of new electrons created, on the average, by each electron is e(α.d) -1 = (nd - no) / no

12

Therefore, the average current in the gap, which is equal to the number of electrons traveling per second will be I =Io. e(α.d)

13

where 10 is the initial current at the cathode. BREAKDOWN IN GASES Townsend mechanism when applied to breakdown at atmospheric pressure was found to have certain drawbacks. Firstly, according to the Townsend theory, current growth occurs as a result of ionization processes, only. But in practice, breakdown voltages were found to depend on the gas pressure and the geometry of the gap. Secondly, the mechanism predicts time lags of the order of 10-5 s, while in actual practice breakdown was observed to occur at very short times of the order of 10-8 s. Also, While the Townsend mechanism predicts a very diffused form of discharge, in actual practice, discharges were found to be filamentary and irregular. The Townsend mechanism failed to explain all these observed phenomena and as a result, around 1940, Rather and, meek and. Loeb independently proposed the Streamer theory. Streamer Theory In practice, discharges were found to be filamentary and irregular. The Townsend Mechanism failed to explain all the above phenomena and therefore around 1940, Raether and Meek and Loeb independently proposed the Streamer theory. The growth of charge carriers in an avalanche in a uniform field is described by eαd. This is valid only as long as the influence of the space charge due to ions is very small compared to the applied field. In his studies on the effect of space charge on avalanche growth, Raether observed that when charge concentration was between 106 and 108, the growth of the avalanche became weak. On the other hand, when the charge concentration was higher than 108, the avalanche current was followed by a steep rise in the current between the electrodes leading to the breakdown of the gap. Both the slow growth at low charge concentrations and fast growth at high charge concentrations have been attributed to the modification of the originally applied uniform field (E) by the space charge P. Fig. 2 shows the electric field around the avalanche as it progresses along the gap and the resulting modification to the applied field.

372

For simplicity, the space charge at the head of the avalanche is assumed to have a spherical volume containing negative charge at its top because of the higher electron mobility. Under these conditions, the field gets enhanced at the top of the avalanche with field lines from the anodes terminating on its head. Further, at the bottom of the avalanche, the field between electrons and ions reduces the applied field (E). Still further down the field between cathode and the positive ions gets enhanced. Thus, the field distortion occurs and it becomes noticeable with a charge carrier number n < 106. For example, in nitrogen at p = 760 ton and with a gap distance of 2 cm, the filled field distortion will be about 1%. This 1% field distortion over the entire gap will lead to a doubling of the avalanche size, but as the distortion is significant only in the vicinity of the top of the avalanche its effect is still negligible. However, if a charge density in the avalanche approaches n = 108 the space charge filled field and the applied field will have the same magnitude and this leads to the initiation of a streamer. Thus, the space charge fields play an important role in the growth of avalanches in corona and spark discharges in non-uniform field gaps. It has been shown that transformation from an avalanche to a streamer generally occurs when the. charge within the avalanche head reaches A critical value of no e(αxe) = 108 or αxc lies between 18 and 20, Where xc is the length of the avalanche in which the secondary electrons are produced by photo-ionization of gas molecules in the inter-electrode gap.

Fig.( 2) Field distortion in a gap due to space charge Further, cloud chamber photographs of the avalanche development have shown that, under certain conditions, Ole space charge developed in an avalanche can transform the avalanche into streamers which lead to very rapid development of breakdown. In the theories proposed by Raether and Meek it has been shown that when the avalanche in the gap reaches a critical size, the combined applied field and the space charge field cause intense ionization and excitation of the gas particles in front of the avalanche. Instantaneous recombination between positive ions and electrons releases photons which in turn produce secondary electrons by photo-ionization. These secondary electrons under the influence of the field in the gap develop into secondary avalanches as shown in Fig. 3. Since photons travel with the velocity of light, the photo-ionization process gives rise to rapid development of conduction channels across the gap. 373

Fig. (3) Formation of secondary avalanches due to photo-ionization On the basis of experimental observations Raether proposed an empirical expression for the streamer spark criterion of the form αxc = 17.7 + In xc + In (Er/E)

(14)

Where Er is the space charged field directed radially at the head of the avalanche and E is the applied field. The conditions for the transition from the avalanche to streamer assumes that the space charged field, E, approaches the externally applied field (E = Er) and hence the breakdown criterion (Eq. (14)) becomes αxc = 17.7+ln xc

(15)

The minimum breakdown value for a uniform field gap by streamer mechanism is then obtained on the assumption that the transition from an avalanche to a streamer occurs when the avalanche has just crossed a gap, d. Thus, a minimum breakdown voltage by streamer mechanism occurs only when a critical length xc = d. Meek proposed a simple quantitative criterion to estimate the electric field that transforms an avalanche into a streamer. The field Er produced by the space charge, at the radius r, is given by Er = 5.27 * 10-7(α e(αxe))/(X/P)1/2

V/cm

(16)

Where α is Townsend's first ionization coefficient, p is the gas pressure in ton, and x is the distance to which the streamer has extended in the gap. According to Meek, the minimum breakdown voltage is obtained when Er = E and x = d in the above equation. The equation simplifies into, α d+ln(α/P)= 14.5+ln(E/P)+1/2 ln(d/p) (17) This equation is solved between α/P and E/P at which a given p and d satisfy the equation. The breakdown voltage is given by the corresponding product of E and d. The above simple criterion enabled an agreement between the calculated and the measured breakdown voltages. This theory also neatly fits in with the observed filamentary, crooked channels and the branching of the spark channels, and cleared up many ambiguities of the Townsend mechanism when applied to breakdown in a high pressure gas across a long gap.

374

It is still controversial as to which mechanism operates in uniform field conditions over a given range of pd values. It is generally assumed that for pd values below 1000 torr-cm and gas pressures varying from 0.01 to 300 torr, the Townsend mechanism operates, while at higher pressures and pd values the Streamer mechanism plays the dominant role in explaining the breakdown phenomena. POST-BREAKDOWN PHENOMENA AND APPLICATIONS This is the phenomenon which occurs after the actual breakdown has taken place and is of technical importance. Glow and arc discharges are the post-breakdown phenomena, and there are many devices that operate over these regions. In a Townsend discharge see Fig. (1) The current increases gradually as a function of the applied voltage. Further to this point (B) only the current increases and the discharge changes from the Townsend type to Glow type (BC). Further increase in current results in a very small reduction in voltage across the gap (CD) corresponding to the normal glow region. The gap voltage again increases (DE), when the current is increased more, but eventually leads to a considerable drop in the applied voltage. This is the region of the arc discharge (EG). The phenomena that occur in the region CG are the post-breakdown phenomena consisting of glow discharge (CE) and the arc discharge (EG). Glow Discharge A glow discharge is characterized by a diffused luminous glow. The colour of the glow discharge depends on the cathode material and the gas used. The glow discharge covers the cathode partly and the space between the cathode and the anode will have intermediate dark and bright regions. This is called normal glow. If the current in the normal glow is increased such that the discharge covers the entire cathode surface, then it becomes abnormal glow. In a glow discharge, the voltage drop between the electrodes is substantially constant, ranging from 75 to 300 V over a current range of 1 mA to 100 mA depending on the type of the gas. The properties of the glow discharge are used in many practical applications, such as cold cathode gaseous voltage stabilized tubes (voltage regulation tubes or VR tubes), for rectification, as a relaxation oscillator, and as an amplifier. Arc Discharge If the current in the gap is increased to about 1 A or more, the voltage across the gap suddenly reduces to a few volts (20—50 V). The discharge becomes very luminous and noisy (region EG in Fig. 1 This phase is called the arc discharge and the current density over the cathode region increases to very high values of 103 to 107A/cm2. Arcing is associated with high temperatures, ranging from 1000°C to several thousand degrees Celsius. The discharge will contain a very high density of electrons and positive ions, called the arc plasma. The study of arcs is important in circuit breakers and other switch contacts. It is a convenient high temperature high intensity light source. It is used for welding and cutting of metals. It is the light source in lamps such as carbon arc lamp. High temperature plasmas are used for generation of electricity through magneto-hydro dynamic (MHD) or nuclear fusion processes.

375

Fig. (1) d.c. voltage-current characteristic of an electrical discharge with electrodes having no sharp points or edges PRACTICAL CONSIDERATIONS IN USING GASES AND GAS MIXTURES FOR INSULATION PURPOSES Over the years, considerable amount of work has been done to adopt a specific gas for practical use. Before adopting a particular gas or gas mixture for a practical purpose, it is useful to gain knowledge of what the gas does, what its composition is, and what the factors is that influence its performance. The greater the versatility of the operating performance demanded from an insulating gas or gas mixture, the more rigorous would he the requirements which it should meet. These requirements needed by a good dielectric do not exist in a majority of the gases. Generally, the preferred properties of a gaseous dielectric for high voltage applications are: (a) high dielectric strength, (b) thermal stability and chemical inactivity towards materials of construction, (c) non-flammability and physiological inertness, and environmentally nonhazardous, (d), low temperature of condensation, (e) good heat transfer, and (f) ready availability at moderate cost. Sulphur hexafluoride (SF6) which has received much study over the years has been found to possess most of the above requirements. Of the above properties, dielectric strength is the most important property of a gaseous dielectric for practical use. The dielectric strength of gases is comparable with those of solid and liquid dielectrics see Fig. (2.). It is clear that SF6 has high dielectric strength and low liquefaction temperature, and it can be used over a wide range of operating conditions. SF6 was also found to have excellent arc-quenching properties. Therefore, it is widely used as an insulating as well as arc-quenching medium in high voltage apparatus

376

Fig (2) d.c. breakdown strength of typical solid, liquid, gas and vacuum insulations in uniform, fields SF6 and Other Gas Mixtures SF6 is widely used for applications in power system due to its high dielectric strength and good arc interruption properties. However, SF6 gas has been found to be a green house gas that causes environmental problems. The production and use of SF6 gas has increased steadily and today it is about 10,000 metric tons due to leakages into the atmosphere from the electrical equipment. The concentration of SF6 in the environment has been steadily increasing. The release of SF6 into the atmosphere leads to concentration of large volumes of SF6 gas in the upper atmosphere. SF6 molecules absorb energy from the sun and radiate it into the atmosphere for long duration of time. There has been a large concern for these environmental effects and therefore the electrical industry has been looking for an alternate gas or gas mixture to be used in electrical equipment which presently use SF6 gas, as an insulating and arc interruption medium. The large amount of experimental data that is presently available suggest that 40% SF6/60% N2 mixtures have all the dielectric characteristics that make it suitable for use as insulation in high voltage equipment. Ideally the gas mixture should be suitable for use in the existing equipment as well as in the equipment that will be designed and manufactured in future. Extensive research work done in SF6 and its mixtures with N2, air and CO2 has given breakdown values which are 80—90% of the pure SF6 values as shown in Table Lightning Impulse Breakdown Strength of SF6/Other Gas Mixtures (Breakdown Strength (kV/cm Breakdown Strength Mixture Ratio ((kV/cm 89.0 SF6 gas 100% 1% SF6/99% 80.0 Nitrogen 377

10% SF6/90% Nitrogen 20% SF6/80% Nitrogen 40% SF6/60% Nitrogen 10% SF6/90% CO2

78.0

20% SF6/80% CO2

76.5

40% SF6/60% CO2

75.5

10% SF6/90% Air

77.0

20% SF6/80% Air

76.5

40% SF6/60% Air

75.6

76.5 75.6 76.5

The industry is looking for a gas mixture that can replace the pure SF6 gas in the existing SF6 insulated apparatus, requiring no change in hardware, test procedures or ratings. SF6/N2 mixture is the one that has been found to be a good replacement for SF6. SF6/N2 mixtures have been used in Gas Insulated Transmission System and were found to perform well. Also, the work done so far has shown that the ability of SF6/N2 mixtures to quench high current arcs is promising. The cost of such mixtures is low and is less sensitive to field non-uniformities present inside the equipment. In view of the above, the industry is trying to find out the optimum mixture ratio and the total pressure of the SF6/N2 mixture that would be required for a variety of applications. For many applications, such as Gas Insulated Transmission Systems, cables, capacitors, current transformers and voltage transformers, mixtures with different SF6 concentrations varying from 5% to 40%. SF6/N2 mixtures show promise as a medium in circuit breakers. It has been found that a mixture containing 69% SF6/31 % N2 gave higher recovery rate than pure SF6 at the same partial pressure. It has also been shown that it is possible to further improve the arc interruption properties of SF6 by using SF6/N2 or SF6/He mixtures. In summary, it may be said that there is an urgent need to significantly reduce the use of SF6 gas and its leakage from power apparatus. Use of gas mixtures appears to be feasible, but it has to be ensured that there is no loss in the performance of the equipment. Wherefore, further research has to be carried out to identify a suitable gas mixture, its pressure and its arc interruption capability to be used in the existing apparatus and the apparatus that will be designed and manufactured in future.

Insulating Liquids Property

Transformer Cable Capacitor Silicone Askarels Oil Oil Oil Oils

378

Breakdown strength (20 C, 2.5mm sphere gap) Relative Permittivity (50Hz) Loss Tangent (50Hz) Loss Tangent (1 kHz)

150

300

200

2.2-2.3

2.3-2.6

2.1

.001 .0005

.001 0.1E-3

Resistivity (Ohm -cm)

1e12-1e13

.002 0.25E-3 0.60E-3 .0001 0.10E-3 0.50E-3 1e121e13-1e14 2e12 1e13

0.89

0.93

0.88-0.89

1.0-1.1

30

30

30

1.4820

1.4700

1.4740

0.01 7e-4/deg

0.01 7e-4

0.01 7e-4

50

50

50

Specific Gravity at 20 C Viscosity at 20 C (cStokes) Refractive Index Saponification Thermal Expansion Max permissible Water content (ppm)

200-250 300-400 4.8

1.4

2-73

3e14

100-150 10-1000 1.50001.6000 <0.01 <0.01 7e-4 5e-4 <30 <30 negligble negligible 1.6000

Pure Liquids Pure liquids often have much higher breakdown strengths than commercial liquids. For instance, the addition of 0.01% water to insulating oil reduces its breakdown strength to 20% of the "dry" value. Compare, for example, the breakdown for Transformer Oil is usually taken as 150 kV/cm (see above table), but when highly purified, it is almost 8 times that, or 1000 kV/cm.

Liquid Hexane Benzene Transformer Oil Silicone Liquid Oxygen Liquid Nitrogen Liquid Hydrogen Liquid Helium Liquid Argon

Max Breakdown Strength MV/cm 1.1-1.3 1.1 1.0 1.0-1.2 2.4 1.6-1.9 1.0 0.7 1.10-1.42

SOLIDS AND COMPOSITES 1. Solid Dielectrics A good solid dielectric should have some of the properties mentioned earlier for gases and liquids and it should also possess good mechanical and bonding strengths. Many organic and inorganic' materials are used for high 379

voltage insulation purposes. Widely used inorganic materials are ceramics and glass. The most widely used organic materials are thermosetting epoxy resins such as polyvinyl chloride (PVC), polyethylene (PE) or cross linked polyethylene (XLPE). Kraft paper, natural rubber, silicon rubber and polypropylene rubber are some of the other materials widely used as insulate in electrical equipment. If the solid insulating material is truly homogeneous and is free from imperfections, its breakdown stress will be as high as 10 MV/cm. This is the `intrinsic breakdown strength', and can be obtained only under carefully controlled laboratory conditions. However, in practice, the breakdown fields obtained are very much lower than this value. The breakdown occurs due to many mechanisms. In general, the breakdown occurs over the surface than in the solid itself, and the surface insulation failure is the most frequent cause of trouble in practice. 2. Composites In many engineering applications, more than one types of insulation are used together, mainly in parallel, giving rise to composite insulation systems. Examples of such systems are solid/gas insulation (transmission line insulators), solid/vacuum insulation and solid/liquid composite insulation systems (trans-former winding insulation, oil impregnated paper and oil impregnated metallised plastic film etc). In the application of composites, it is important to make sure that both the components of the composite should be chemically stable and will not react with each other under the application of combined thermal, mechanical and electrical stresses over the expected life of the equipment. They should also have nearly equal dielectric constants. Further, the liquid insulate should not absorb any impurities from the solid, which may adversely affect its resistivity, dielectric strength, loss factor and other properties of the liquid dielectric. It is the intensity of the electric field that determines the onset of breakdown and the rate of increase of current before breakdown. Therefore, it is very essential that the electric stress should be properly estimated and its distribution known in a high voltage apparatus. Special care should be exercised in eliminating the stress in the regions where it is expected to be maximum such as in the presence of sharp points. In the design of high voltage apparatus, the electric field intensities have to be controlled, otherwise higher stresses will trigger or accelerate the aging of the insulation leading to its failure. Over the years, many methods for controlling and optimizing electric fields to get the most economical designs have been developed. Electric field control methods form an important component of the overall design of equipment. Electric Field A brief review of the concepts of electric fields is presented, as it is essential for high voltage engineers to have knowledge of the field intensities in various media under electric stresses. It also helps in choosing proper electrode configurations and economical dimensioning of the insulation, such that highly stressed regions are not formed and reliable operation of the equipment results in its anticipated life. The field intensity E at any location in an electrostatic field is the ratio of the force on an infinitely small charge at that location to the charge itself as the charge decreases to zero. The force F on any charge q at that point in the field is given by F = q*E

4

380

The electric flux density D associated with the field intensity E is D = ε*E 5 Where E is the permittivity of the medium in which the electric field exists. The work done on a charge when moved in an electric field is defined as the potential. The potential φ is equal to

Where l is the path through which the charge is moved. Several relationships between the various quantities in the electric field can be summarized as follows:

Where F is the force exerted on a charge q in the electric field E , and S is the closed surface containing charge q. Uniform and Non-Uniform Electric Fields In general, the electric fields between any two electrodes can be both uniform and non-uniform. In a uniform field gap, the average field E is the same throughout the field rigion, whereas in a non-uniform field gap, E is different at different points of the field region. Uniform or approximately uniform field distributions exist between two infinite parallel plates or two spheres of equal diameters when the gap distance is less than diameter of the sphere. Spherical electrodes are frequently used for high voltage measurements and for triggering in impulse voltage generation circuits. Sometimes, parallel plates of finite size are used to simulate uniform electric fields, when gap separation is much smaller than plate size. In the absence of space charges, the average field E in a non-uniform field gap is maximum at the surface of the conductor which has the smallest radius of curvature. It has the minimum field E at the conductor having the large radius of curvature. In this case, the field is not only non-uniform but also asymmetrical. Most of the practical high voltage components used in electric power systems normally have non-uniform and asymmetrical field distribution. Estimation of Electric Field in Some Geometric Boundaries

381

It has been shown that the maximum electric field Em in a given electric field configuration is of importance. The mean electric field over a distanced between two conductors with a potential difference of V12 is

Ε av =

V12 d

In field configurations of non-uniform fields, the maximum electric field Em is always higher than the average value. For some common field configurations, the maximum value of Em and the field enhancement factor f given by Em/Eav, are presented Below. f = Em / Eav 1-Parallel plates

Em = r

V r

f =1

Parallel plate

2- Concentric cylinders

3- Parallel cylinders of equal diameter

382

SURGE VOLTAGES, THEIR DISTRIBUTION AND CONTROL The design of power apparatus particularly at high voltages is governed by their transient behavior. The transient high voltages or surge voltages originate in power systems due to lightning and Switching operations. The effect of the surge voltages is severe in all power apparatuses. The response of a power apparatus to the impulse or surge voltage depends on the capacitances between the coils of windings and between the different phase windings of the multi-phase machines. The transient voltage distribution in, the windings as a whole are generally very nonuniform and are complicated by traveling wave voltage oscillations set up within the windings. In the actual design of an apparatus, it is, of course, necessary to consider the maximum voltage differences occurring, in each region, at any instant of time after the application of an impulse, and to take into account their durations especially when they are less than one microsecond. An experimental assessment of the dielectric strength of insulation against the power frequency voltages and surge voltages, on samples of basic materials, on less complex assemblies, or on complete equipment must involve high voltage testing. Since the design of an electrical apparatus is based on the dielectric strength, the design cannot be completely relied upon, unless experimentally tested. High voltage testing is done by generating the voltages and measuring them in a laboratory. When high voltage testing is done on component parts, elaborate insulation assemblies, and complete full-scale prototype apparatus (called development testing), it is possible to build up a considerable stock of design information; although expensive, such data can be very useful. However, such data can never really be complete to cover all future designs and necessitates use of large factors of safety. A different approach to the problem is the exact calculation of dielectric strength of any insulation arrangement. In an ideal design each part of the dielectric would be uniformly stressed at the maximum value which it will safely withstand. Such an ideal condition is impossible to achieve in practice, for dielectrics of different electrical strengths, due to the practical limitations of construction. Nevertheless it provides information on stress concentration factors the ratios of maximum local voltage gradients to the mean value in the adjacent regions of relatively uniform stress. A survey of typical power apparatus designs suggests that factors ranging from 2 to 5 can occur in practice; when this factor is high, considerable quantities of insulation must be used. Generally, Improvements can be effected in the following ways: 1. by shaping the conductors to reduce stress concentrations,

383

2. by insertion of higher dielectric strength insulation at high stress points, and by selection of materials of appropriate permittivity to obtain more uniform voltage gradients. Capacitor Discharge Impulse Generators This is the simplest means of generating a high voltage impulse in a load. Practical considerations usually dictate that more sophisticated means be used (like Marx generators, Transmission line pulse formers, Impulse Transformers, etc.), but the basic capacitor discharge circuit is a good place to start.

The circuit above has all the essential components: Echg - A means of charging the capacitor. Often, either a current limited HV power supply and a Switch to connect it to the capacitor, or a HV power supply and a large series resistor to limit the charging current. Cs - A capacitor to store the energy. S - A Switch to apply the energy to the load R1 and L Series resistance and/or inductance, either parasitic or added for pulse shape control R2 - Load resistance Cload - Load capacitance Waveforms and the effect of resistances and inductances Assuming the parasitic inductances are small (often, this is not a valid assumption), the output of a capacitive impulse generator can be represented by a pair of exponentials, reflecting the charging of the load capacitance and then, the discharge of the storage and load capacitance. The most common way to describe the waveform is by it's rise and fall times. A standard waveform for lightning impulse testing would be a 2/50, where the load voltage reaches its peak in 2 microseconds, and the decay to half the peak voltage takes 50 microseconds.

384

Energy Discharge Capacitors In these systems, the capacitor is used to store the energy to be used for the impulse. Since fast rise times are usually desired, the capacitor should have low parasitic inductance. Resistive losses also result in lower efficiency and slower rise times. Commercial energy storage capacitors are designed to a specific capacitance. The manufacturer then tests them, and their actual characteristics (capacitance, stored energy) are marked on the label. Switches The Switches for an impulse generator fall into two general categories. The first is those that are primarily mechanical in nature, consisting of contacts that are closed by some means such as a spring, solenoid, air cylinder, or other actuator. The second is those that have no moving parts, with the triggered spark gap being very popular, although in some applications, devices such as SCR's are used. Capacitor Charging considerations The rectified output of a high voltage Transformer is probably the simplest system used for charging the capacitor. Some form of current limiting is necessary because the capacitor looks like a dead short when fully discharged. The current limiting is often in the form of a series impedance. The impedance be either inductive or resistive and can either be in the primary side of the Transformer or the secondary (or be in sort of both, in the form of leakage inductance in the Transformer). A resistive current limiter is simple, but the energy dissipated in the resistor is signficant, being equal to the stored energy in the capacitor. Inductive current limiters don't have the power dissipation problem of a resistor, but are more susceptible to unwanted resonance effects, particularly with parasitic reactance's. A resonant charging scheme using a diode and an inductor is very popular for capacitor discharge circuits that are fired repeatedly. Fruengel recommends the use of a voltage multiplier (Cockroft-Walton type), because it has a hyperbolic voltage/current characteristic that lends itself to capacitor charging. The disadvantage is that there is significant stored energy in the capacitor stack of the multiplier, although raising the input frequency reduces the size of capacitor required, and the stored energy. In fact, a logical outgrowth of this trend is the use of Switching power supplies. Switchers as capacitor chargers In recent years, Switching power supplies have become popular for capacitor charging. The generally high (tens of kHz) Switching frequency reduces the stored energy in the supply, which enhances safety and reduces the chances of a flashover arc developing. They can provide a constant charging current, reducing the power lost compared to a series resistor RC scheme. They can also detect faults and shut down the supply if an arc develops or a capacitor fails (shorted) during charging. HV power supply manufacturers such as Maxwell have power supplies designed specifically for charging capacitors. 385

Watch out for voltage reversals during discharge The system for charging should take into account the voltage reversal on the storage capacitor if any. For instance, a currrent limited HV Transformer feeding a bridge rectifier is a convenient way to charge a capacitor. However, if the capacitor discharge waveform has any voltage reversal, the diodes in the bridge will be forward biased in parallel with the capacitor, and the resulting high peak currents will most likely destroy the diodes.

Marx Generators A Marx Generator is a clever way of charging a number of capacitors in parallel, then discharging them in series. Originally described by E. Marx in 1924, Marx generators are probably the most common way of generating high voltage impulses for testing when the voltage level required is higher than available charging supply voltages. Furthermore, above about 200 kV, the discharge capacitor becomes very expensive and bulky. The Fitch circuit is becoming popular where very good control over impulse voltage is required.

How it works The charging voltage is applied to the system. The stage capacitors charge through the charging resistors (Rc). When fully charged, either the lowest gap is allowed to breakdown from over voltage or it is triggered by an external source (if the gap spacing is set greater than the charging voltage breakdown spacing). This effectively puts the bottom two capacitors in series, over voltage the next gap up, which then puts the bottom three capacitors in series, which overvoltages the next gap, and so forth. This process is referred to as "erecting". A common specification is the erected capacitance of the bank, equal to the stage capacitance divided by the number of stages. The charging resistors are chosen to provide a typical charging time constant of several seconds. A typical charging current would be in the 50-100 mA range. The charging resistors also provide a current path to keep the arc in the spark gaps alive, and so, should be chosen to provide a current of 5-10 amps through the gap. The resistors are sometimes called "feed forward" resistors for this reason. The discharge through the charging resistors sets an upper bound on the impulse fall time, although usually, the impulse fall time is set by external resistors in parallel with the load (or integrated into the generator, as described below). For example, with a stage voltage of 100 kV, a desired output voltage of 1 MV (i.e. 10 stages), the charging resistors should be about 20-40 kohms (corresponding to an arc current of 5 to 10 Amps). If the capacitors were 1 uF, then the discharge time constant

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would be 20 milliseconds, much, much longer than the 50 microsecond time constant of the standard test impulse. This example generator would have a stored energy of 5 kJ/stage or 50 kJ for the total system. At a charging current of 50 mA, it would take at least 20 seconds to charge the entire stack. If a constant voltage charging source is used, significant energy is dissipated in the charging resistors, equal to the stored energy in the capacitors. Design enhancements and considerations Charging with a constant current source If the Marx generator is charged from a constant voltage source, the energy dissipated in the charging resistors will be equal to that stored in the Marx capacitors. If the bank is charged with a constant current source, this energy loss can be substantially reduced. Integrating the wave shaping resistors into the generator In the classic capacitor discharge impulse generator, the shape of the pulse is controlled by external impedances (usually resistors) at the "output" of the pulse generator. As voltages get higher, it gets harder to build practical resistors with low parasitic inductance that will also withstand the full impulse voltage. The usual remedy for this is to include the wave-shaping resistors in the Marx bank itself, as illustrated in the following figure.

Reducing the jitter If the gaps in the Marx generator don't all fire at exactly the same time, the leading edge of the impulse will have steps and glitches as the gaps fire. These delays also result in an overall longer rise time for the impulse. If the jitter in the gaps is reduced, the overall performance is improved. The traditional Marx generator operating in air has all the gaps in a line with the electrodes operating horizontally opposed. This allows the UV from bottom gap to irradiate the upper gaps, reducing their jitter. Tests reported in Craggs and Meek showed that obstructing the UV led to greatly increased jitter in the bank output, which they attribute to the lack of UV irradiation on the upper gaps. For a Marx generator which is immersed in oil, or using enclosed spark gaps, resistor or capacitor networks can be used to propagate the trigger pulse to all the gaps, rather than relying on the over voltage of the upper gaps to fire them.. A design from Maxwell labs uses a series of resistors to apply the trigger impulse to all the gaps. Laser irradiation or triggering of the gaps could also be used. Craggs and Meek also report the use of radioactive sources included within the gap electrodes to reduce the jitter.

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Other Switching devices The Marx technique has been used to generate impulses of several kilovolts from a relatively low charging source using avalanche transistors as the Switching device instead of a spark gap. In this case, the resistors need to be chosen to keep the transistor turned on. Alternate charging schemes Particularly for lower output voltages, the capacitors can be charged in parallel from a common source through a series resistor or inductor. The charging impedance has to withstand the full output voltage for the top stage. For the solid state Marx generator running at a few kV described above, this isn't as much of a problem as it would be for a megavolt range lightning impulse simulator. Inductors as the charging impedances The charging resistors can be replaced by inductors, eliminating the power loss in the resistors.

The Fitch circuit Fitch Impulse Generators The Fitch circuit is used when better control of the impulse voltage is required than can be provided by the Marx circuit. 388

High Voltage Safety Contents 1. Electrical Hazards, Fuses and Safety Switches 2. Burns 3. Induction Field Effects 4. Ozone, Nitrites, and Vapors 5. Ultraviolet Light and X-ray Production 6. Radio Frequency Interference 7. Fire Hazards 8. Chemical Hazards 9. Explosion Hazards 10. Noise Hazards 11. Neighbors, The Spouse, and Children 12. Other 1.0) Electrical Hazards, Fuses and Safety Switches The risk of death or injury is significant in many high voltage, and particularly high energy systems. The following general guidelines are suggested: 1. Turn off the power before touching part of high voltage system, or even getting close. A key Switch or lockout device 2. High voltage capacitors may hold a charge long after power is turned off. Always discharge capacitors and keep them shorted in storage or when working on them.. Even after being shorted, a capacitor can regain significant voltage when open circuited. Ideally, the system should be designed so that the capacitor shorting is failsafe. 3. Make sure the metal cases of Transformers, motors, control panels and other items should be properly grounded. 4. Keep a safe distance from energized, or potentially energized components. OSHA guidelines provide for the following distances. Don't move conductive objects too close to energized components 5. Use adequate fusing of the power and/or Circuit Breakers to limit the maximum current 6. Spend some time laying out your circuits. Hot glue, electrical tape and exposed wiring are quick and easy, but could be lethal. Information about electricity and humans Lightning kills about 300 people each year in the United States, and injures an additional three to four times this number. (Sorry, I have no data for the rest of the planet.) More than one thousand people are killed each year in the U.S. due to generated electric current, and several thousand more are injured. (This would include potential tesla coilers.) In the case of lightning, the voltage and current are extremely high, but the duration is short. The current tends to flow on the outside of the body and may cause burns, respiratory arrest and/or cardiac arrest. Many die from lightning due to respiratory arrest rather than cardiac arrest. (The portion of the brain controlling breathing is often severely affected in a lightning strike.) Power line 389

deaths usually involve lower voltages and currents, but the duration may be significant. Often the current flows inside the body, causing deep burns and cardiac arrest. Frequently, the individual cannot let go of the power source due to involuntary muscle contraction. The brain and heart are the most sensitive organs. The dose response for animal and human data suggest the following: for less than 10 mA hand to foot of 50-60 cycle line current, the person merely feels a "funny" sensation; for currents above 10 mA, the person freezes to the circuit and is unable to let go; For currents of 100 mA to one ampere, the likelihood of sudden death is greatest. Above one ampere, the heart is thrown into a single contraction, and internal heating becomes significant. The individual may be thrown free of the power source, but may go into respiratory and/or cardiac arrest. Six factors determine the outcome of human contact with electrical current: voltage, amperage, resistance, frequency, duration and pathway. I will discuss each individually. Voltage Low voltages generally do not cause sudden death unless the external resistance is low (so don't fire up your coil in wet areas). As the voltage is increased, more and more current passes through the body, possibly causing damage to the brain, heart, or causing involuntary muscle contractions. Perhaps 100-250 volts A. C. is the most lethal voltage, because it is high enough to cause significant current flow through the body, and may cause muscles to contract tightly, rendering the victim incapable of letting go. Lower voltages often are insufficient to cause enough current flow, and higher voltages may cause the victim to be thrown clear of the hazard due to the particularly fierce involuntary muscle contractions. Arcing may occur with high voltages, however. Naturally, burns become more severe as the voltage is increased. Amperage Greater amperage means greater damage, especially due to heating within tissues. As little as 10 micro amps of current passing directly through the heart can cause ventricular fibrillation (heart muscle fibers beat out of sync, so no blood is pumped) and cardiac arrest. Because of the air filled lungs, much of the current passing through the chest may potentially pass through the heart. The spinal cord may also be affected, altering respiration control. 100-1000 milliamperes is sufficient to induce respiratory arrest and/or cardiac arrest. Thermal heating of tissues increases with the square of the current (I2R), so high current levels can cause severe burns, which may be internal. Resistance A heavily callused dry palm may have a resistance of 1 megohm. A thin, wet palm may register 100 ohms of resistance. Resistance is lower in children. Different body tissues exhibit a range of resistances. Nerves, arteries and muscle are low in resistance. Bone, fat and tendon are relatively high in resistance. Across the chest of an average adult, the resistance is about 70-100 ohms. Thermal burns due to I2R losses in the body can be significant, resulting in the loss of life or limb long after the initial incident. A limb diameter determines the approximate "cross section" which the 390

current will flow through, (for moderate voltages and low frequencies). As a result, a current passing through the arm generates more temperature rise and causes more thermal damage than when passing through the abdomen. Frequency The "skin effect" also applies to a human conductor, and as the frequency gets above about 500 kHz or so, little energy passes through the internal organs. (I unfortunately have little data in the 50-250 kHz range, where we operate most tesla coils. I'll check another reference I have at home.) At a given voltage, 50-60 A.C. current has a much greater ability to cause ventricular fibrillation than D.C. current. In addition, at 50-60 Hz, involuntary muscle contractions may be so severe that the individual cannot let go of the power source. Higher frequencies are less able to cause these involuntary contractions. Duration Obviously, the longer the duration, the more severe the internal heating of tissues. Duration is particularly a problem when working with 110-240 volts A.C., which can render the individual incapable of letting go. Pathway If the current passes through the brain or heart, the likelihood of a lethal dose increases significantly. For example, hand to hand current flow carries a 60% mortality, whereas hand to foot current flow results in 20% overall mortality. Be aware that foot to foot conduction can also occur, if a high voltage lead is inadvertently stepped on or if grounding is inadequate. Electrical Precautions Obviously, the A.C. line voltage, the high voltage Transformer and the high voltage R.F. generated by a tesla coil are each potentially lethal in their own unique ways. One must always respect this extreme danger and use high voltage shielding, contactors, safety interlocks, careful R.F. and A.C. grounding, and safe operating procedures when working with coils. A safety key to prevent inexperienced operators from energizing a coil is essential. High voltage capacitors can also retain lethal energies (especially in the "equidrive" configuration) and should always be grounded before adjusting a primary. Whenever possible, have a buddy around to assist you. Place one hand in your pocket when near electrical components so the current won't pass through your chest, and use the back of your hand to touch any electrical components so you can let go if it happens to bite you. Remember that most deaths are caused by regular 110 A.C. power! Never perform coiling when overtired or under the influence of mind altering drugs. Watch a tesla video instead!

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More Tesla coils electrical danger information The previous article mentioned some of them in a general electrical hazard context, while this article will attempt to discuss the dangers from a tesla coil point of view. Electrical Dangers Exposed wiring on Transformers. Most Transformers have exposed high voltage lugs. Most neon sign Transformers that I have seen used for tesla coil usage have exposed lugs. A 15000 volt Transformer has a turn ratio of 125:1 (assuming 120 volts in). If you haven't disconnected your input power from the source (unplugged your variac), you may be in for a surprise. A variac that is putting out two volts will give you a 250 volt shock if you touch the high voltage outputs of the neon sign Transformer! Pole pigs (also known as distribution Transformers, such as the one that is probably hanging on a utility pole near your home) have the same dangers as mentioned above, as well as having much more current available. At the output voltage of a pole pig, the current that can go through you is not really limited by anything other than the current regulation that you attached to the pig. Once I shocked myself with one end (7500 volts) of a 60 mA. neon sign Transformer. I just brushed against an exposed end, so I wasn't gripping anything. It was quite painful, much more so than touching a sparkplug wire. I felt the path of the current follow my arm, and go down my leg. Keep one hand in your pocket when working near or with charged items. (Capacitors, secondary coils, etc.) Richard Hull's "Tesla Coil Primer" tape has some excellent safety suggestions in it, is entertaining, informative, and well worth the money. One of his best suggestions is the one of holding the power plug to the power Transformer in your hand whenever you are putting your hands around the circuit. The transmission line between your high voltage Transformer and your tesla coil is another potential source of electrocution. This should be constructed using neon sign wiring (rated to 40 kV) or thick coaxial cable like RG-8A/U or RG-11A/U. If using coaxial cable, use the inner conductor for the high voltage, and strip back the outer braid about 6-12 inches from each end. Connect one end of the braid to your RF ground. Leave the other end unconnected so it does not form a current loop. Some coilers also place their high voltage cables inside a plastic conduit, which is laid on the floor. This also protects the cable somewhat from strikes. Charged capacitors. "Equidrive" systems will almost always have a residual charge remaining on the capacitor when the system is turned off. The "equidrive" system uses two capacitors in the primary coil circuit. The gap is across the Transformer, and the capacitors extend from the gap to each side of the primary coil. Even with the gap shorted, the capacitors can hold a lethal voltage. If you use this configuration, make yourself a shorting rod using a piece of copper tubing or wire with an insulating handle attached, and always short out each capacitor at the end of each run, and again each time you plan to touch the primary system. •

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Capacitors can also build up a residual charge from electrostatic sources. Capacitors have been known to accumulate a charge from various sources such as static electricity and electric fields. IF YOU STORE A CAPACITOR, STORE IT WITH A WIRE ACROSS THE TERMINALS. (MAKE SURE YOU DISCHARGE THE CAPACITOR BEFORE PUTTING THE WIRE ON!!!) Capacitors can "regain" charge from dielectric "memory". The dielectric in a capacitor is put under electrical stress during use. During operation, this stress may cause the molecules in the dielectric to orient themselves in such a manner that they store this charge in their structure. The charge remains after the capacitor has been discharged. Later the molecules return to their original states and the charge that they "captured" ends up on the plates of the capacitor. This charge is then available to shock you. Other sources of danger You are literally playing Russian Roulette when you stick a hand held metal rod into the output streamer of your coil running at 3kvA, while standing on a concrete floor!!! When you start running these kind of power levels (or even less) some coils have a tendency to form a corona or even send a streamer down to their own primaries every once in a while. A grounded strike ring is often added around the primary to try to prevent this self striking streamer from hitting the primary coil and thus introducing a high voltage pulse into the 'bottom end electronics' where it could do damage to components. These strike rails are not 100% effective. The streamer can still, and sometimes does strike a point downstairs that is part of the LETHAL high voltage 60 Hz circuitry. When such a contact is made, any person also connected to a corona/streamer link to the secondary at the same time will, via the ionized air path, become connected to lethal 60 Hz mains current. You could try the trick you described standing on the cement floor in your tennis shoes half a dozen times and live, or be killed the very next time you try it. The fact that the bottom of your secondary is tied to ground will not save you! If you isolate your own body well away from the floor and any other potentially conductive objects in the vicinity, such as sitting or standing on an elevated insulated platform (I would NOT consider a plastic milk crate adequate!), then you will probably survive if 60 Hz is introduced into the streamer you are in contact with by the mechanism described above. However, in setting up this insulated platform you must consider the path that may be taken from streamers that will re-emerge from your body and head off looking for other targets, which could result in direct contact with earth ground again. In a safety warning I have about the potential hazards of Tesla coils mention is made of a stage lecturer while demonstrating how he could cause long sparks to come out of his fingers (by standing on a specially constructed coil), was electrocuted when the discharge created an ionized path to grounded overhead pipes supporting stage back drops, and the lower voltage but far more deadly 60 cycle current passed through his body along that path. The name of this lecturer is believed to be Transtrom.

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I was dinking around once with a vacuum tube coil drawing 15 inch streamers to a hand-held, 10 megohm metal film porcelain resistor about a foot long while standing on a carpeted, elevated wooden floor in composition rubber soled dry shoes. I inadvertently got the resistor too close to the primary tank coil (the top end directly connected to the 3 kilovolt output of the plate supply Transformer) and the high voltage RF closed a path to the primary. I felt an uncomfortable 60 Hz shock through my entire body. Had that resistor been a solid metal rod I would have experienced a very painful jolt or worse, and had I been standing on a cement floor, I'd probably be 'worm food'. I think the danger of electrocution is just as real by making contact with a hand held florescent lamp tube, as any solid conducting metal objeCT's I cringe when I hear of some body contact stunts proposed by people on this list! The potential (no pun intended) for death is very real. Be EXTREMELY careful! Another viewpoint The 60 cycle side of things is where electrocution can happen. Keep well away from any 60 cycle leads, use grounds and cages as appropriate. Bear in mind that if a radio frequency arc starts from a place which also has 60 cycles on it (one side of a primary circuit, for example) there is the possibility of high-current 60 cycle conduction along the ionized path. That could be deadly..... Back to contents 2.0) Burns Tesla coils can cause burns, especially due to RF discharges from the secondary. Stay out of the immediate vicinity of a tesla coil. Remember, if you do get zapped by a large coil system, the heating effects may be mostly internal, causing lasting damage! Also remember that spark gaps and rotaries get hot and are a potential source of burns. 3.0) Induction Field Effects Tesla coils operate in a pulsed mode, and strong electric and magnetic fields are locally produced. In addition, significant amounts of RF may be produced if the grounding is poor, or before spark breakout. This can result in induced currents in other conductors, like test equipment, nearby computers and electronics, and metal structures in the facility. The end result is generally bad. Turn off computers and sensitive test equipment, and move it away from the vicinity of your coils. If you foolishly choose to use your house electrical ground as your RF ground, you are asking for trouble. Currents may be induced anywhere in the building, and voltage standing waves along the wiring may destroy electronics far from the coil location. Construct a dedicated RF ground, and make sure it is properly connected before firing any coil of substantial size. Fire from other induced currents.

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Tesla coils are good at inducing currents. Beware of metal things that are connected to the same ground as a tesla coil. For example, I run my coil in my garage, which has a wooden door on metal tracks. The tracks are against the concrete floor, and near the strap that serves as a ground for my coil. When the coil operates, it causes sparks to jump between the running hardware of the door and the tracks. Static charges During the operation of the tesla coil, significant static charges can build up on the secondary. If you need to move the secondary (say you are adjusting the coupling), you may get a nasty zap right across your chest when you pick it up with both hands. Before you touch the secondary, wipe it lightly with a grounded wire. You can sometimes hear the crackling as you do so. Besides the shock hazard, there is the physical hazard caused by the shock. You will likely drop the secondary or jump onto something that isn't soft. Hazards to electronics Strikes to house electrical ground -- also goes to power(?) A tesla coil must be connected to a ground that is separate from the house ground or water pipes. Connecting your coil to either of these grounds is a recipe for disaster. Notice that your stereo, computer, VCR, etc., have three prong plugs. Also, note where your telephone box is grounded. It is likely grounded to the water pipes. Consider what happens when your coil strikes the grounded strike rail, or an unexpectedly long spark that hits an electrical receptacle. That enormous voltage at high frequency will now be connected to the grounds of all your electronic goodies or your telephone. Furthermore, a spark is a conducting path in the atmosphere. By creating this path, you open your electrical system up to connections among the 120/220v house system and ground. Strikes to garage door opener rails. Since many people do their coiling in the garage, this topic deserves individual consideration. If you have a garage door opener, or are installing one, you should put in a mechanism, such as a Switch or plug and socket, that allows you to disconnect the opener from the house power. My garage door got zapped by my coil. The door is connected to the opener track so the opener got zapped too. The strike caused the opener to attempt to open the already open door. Since the door couldn't go any further, the opener started binding. I was able to unplug the opener and keep the thing from smoking. More than one person on the list has replaced their opener as a result of their coiling activity. Be warned of the dangers to the equipment. An untested suggestion is to put a grounded wire underneath the rail and opener to draw the sparks to the wire. Electric fields inducing currents and killing sensitive meters. Oddly enough sensitive meters and measuring equipment are just that -- sensitive. Solid state instruments are much more susceptible to damage from being near tesla coils than are vacuum tube items. Consider purchasing a cheap volt-ohmeter (VOM) with an analog meter movement. If will survive in places many digital units will not. A used vacuum tube 395

oscilloscope is also more likely to survive the tesla coil environment and can be obtained cheaply at hamfests. Good electrical practice Place your coil in a location that will prevent the strikes from hitting electrical outlets, people, animals, and sensitive electrical equipment. Turn off and unplug computers in your house. 4.0) Ozone, Nitrites, and Vapors A sparking tesla coil produces ozone, nitrites, and probably a host of other potentially toxic substances. Do not operate a large coil in an enclosed area for long periods of time. Make sure ventilation is adequate at all times. There have been anecdotal references to people becoming ill due to ozone toxicity. The long term bioeffects are unknown. (On the other hand, it does help out the ozone layer!) When constructing secondaries, use adequate ventilation when coating coils with varnish, etc. Some of these materials are also quite toxic. The flux from solder is also potentially hazardous. 5.0) Ultraviolet Light and X-ray Production Ultraviolet light may be produced by the spark gap during operation of a tesla coil. The human eye has no pain sensors within it, so the bioeffects are felt later, when it is too late. (Ever look at the sun for a while, or watch a welder at work?) The light produced in a spark gap is essentially identical to that produced by an arc welder, containing substantial amounts of hard ultraviolet light. As any professional arc welder will tell you "Don't Look At The Arc!" Spark gaps produce a large amount of UV and visible light. The visible light is extremely bright, and the ultraviolet light will damage your eyes, and can cause skin cancer. The arc is so bright that you couldn't make out any detail anyway, so why bother? If you must study your spark gap, use welder's glasses. Generally, it is not too difficult to rig up a piece of plastic, cardboard, etc. that will shield yourself and others. X-rays X-rays can be produced whenever there is a high voltage present. Although a number of coilers have tested their coils for x-ray radiation and found none present that is not to say that x-rays cannot be produced, especially if vacuum tubes, light bulbs, and other evacuated vessels are placed near a coil. Here is a little information about Xrays. X-ray Production A number of vacuum tubes work pretty well as X-ray tubes, and several articles have appeared in Scientific American magazine in the distant past. X-rays are typically produced by slamming electrons into either the nuclei or inner shell electrons of atoms. The source electrons are usually boiled off a heated filament (cathode), and accelerated toward an anode via some large potential difference, typically 25-150 kV in the medical world. Basically, any time the voltage gets above 10 kV, there is a significant risk of X-ray production, and the risk increases with increasing voltages. 396

You can also get some X-ray production via field emission, whereby electrons escape a cold metal due to very high local electric fields (the Schottky effect). This was probably the type of emission obtained by an amateur described recently on the list. For the remainder of this discussion I will limit my comments to conventional X-ray tubes, using a filament and anode, although most of it applies to both forms. The target or anode is normally a high atomic number material like tungsten. X-ray production is relatively inefficient, so most of the energy is wasted as heat (typically about 99% with good X-ray tubes). Tungsten works well because of its high melting point (to absorb all that wasted heat energy). If the potential difference between the anode and cathode is +100 kV D.C., a spectrum of X-rays will be produced with energies from zero to 100 keV. The graph of the number of X-rays produced (y-axis) versus X-ray energy (x-axis) has a negative slope with a Y=0 point at x = 100 keV. Hence, many more low energy X-rays are produced than high energy X-rays. Some of these low energy photons are absorbed by the tube housing. In a clinical X-ray machine, the tube is placed in a leaded shield with a window (hole) in it for the X-rays to escape through. This window has a piece of aluminum over it to further attenuate the low energy X-rays. In conventional equipment, the tube, housing and aluminum filter accounts for about 2.5 - 3.5 mm of aluminum equivalent material in the exit port. This effectively knocks out most of the low energy (<10 keV) radiation, which would be absorbed in the patient and could not contribute to producing an image anyway. X-ray Absorption High atomic number materials readily absorb x-ray radiation. There is an energy dependence here, as high energy X-rays are more penetrating than low energy x-rays. For example, the percentage of radiation which will pass through 10 cm (about 4 inches) of water is 0.04% at 20 keV, 10% at 50 keV and 18% at 100 keV. Compare this with 1 mm of lead (about 0.04 inches), which transmits 0.02% at 50 keV and 0.14% at 100 keV. The human body absorbs X-rays pretty readily (similar to water), but becomes more transparent as the energy of the X-ray increases. That is why we use 50-150 keV for many clinical procedures. The low energy X-rays are filtered out of the spectrum before they enter the patient, usually through the use of an aluminum filter, which lets the high energy X-rays pass through with little attenuation (except possibly to give you enough contrast to see what you want). Most of the x-rays are absorbed in the patient, with 1-5% exiting the patient typically. Low energy X-rays (015 keV) are totally absorbed in human skin near the skin surface, and would contribute substantially to patient dose if allowed to reach the patient. This is to be avoided in general! Shielding The best materials are lead or depleted (nonradioactive) uranium. Concrete and steel also work pretty well. Aluminum is a poor absorber of radiation, unless the radiation is very low in energy. Most plastics are similar to water in attenuating properties (quite poor).

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Hazards X-rays are capable of producing ionizations, which means that the electrons can be stripped off of atoms when an x-ray is absorbed in a material. This results in the production of chemically reactive free radicals, and the direct disruption of chemical bonds. This is generally bad in humans, causing cancer, leukemia cataracts, etc. However, due to natural background radiation levels, humans have built in radiation repair mechanisms and can handle low doses of radiation quite well. Bio-effects are not generally observed for doses of less than 25 rem. Skin reddening occurs with doses of around 300 rem or so. Natural background radiation levels typically contribute 0.2 - 0.5 rem per year. Most regulatory agencies recommend no more than 0.5 rem per year above background radiation levels for the general public. Occupational radiation workers can get 5 rem per year above background. The radiation from a well designed X-ray tube can be as high as 10-50 rem per minute of exposure, at a distance of 1/2 meter. The radiation source acts like a light bulb, decreasing in intensity via the square law with distance. Hence, don't stand close to a possible radiation source, use adequate shielding and minimize the exposure time. Incidentally produced radiation from metal objects other than X-ray tubes will generally be at much lower production levels, but should be avoided, nonetheless. Regulations In the U.S. the individual states regulate X-ray machines. They generally keep close tabs on clinical and industrial X-ray machines and aren't too impressed to see them in the hands of people without the appropriate licenses. If you happen across an old Xray tube, you might consider releasing the high vacuum inside (very carefully, please) so that it is inoperable, and a little safer to handle for show and tell (and much more acceptable to the regulators). This can be done by making a small hole in the glass envelope with a file, keeping the tube wrapped in a large quantity of towels for implosion protection during the process. (It goes without saying that you should always have your favorite towel handy anyway [for you Doug Adams fans]). Monitoring At this point I presume you are wondering how to tell if that great apparatus in your basement or garage is producing X-rays. There are several ways to tell. First, go look for a surplus Geiger-Mueller counter at your local hamfest or make friends with someone in your local fire department, since many fire departments have radiation survey meters at their stations (in case we have a nearby nuclear explosion, etc.). (Don't bother with the fire department if your apparatus is likely to upset them!) In addition, nearly every hospital has a radiation safety officer who is likely to be more than willing to take a look at your toys, and will bring a radiation survey meter along. The standard method for monitoring radiation dose is via film badge and/or thermoluminescent dosimetry monitors, but these are not all that useful to the experimenter since they must be mailed back to the dosimetry lab for reading. In general, film is quite insensitive to radiation, and is of limited value in the experimenters setting unless you can leave the equipment on for a long time to get adequate exposure. Cloud chambers are great fun and can detect a variety of radiation particles, but get easily overwhelmed by devices that put out even low radiation levels. If you don't expect any radiation but still want to check, a cloud chamber can 398

be used. Buy a thorium doped lantern mantle at your local camping store to use as a radiation check source to make sure your chamber is working okay before you power up your equipment. Another possibility is to construct an electroscope and place it near your apparatus. An electroscope measures the amount of charge using two thin metal foils which are charged up to a high potential, causing them to swing apart due to repulsion of like charges. Radiation ionizes the air in the electroscope chamber, causing a loss of charge on the foils. Naturally, this type of equipment has limited utility in the direct vicinity of high voltage equipment if electric fields are significant. X-rays and Tesla Coils I have monitored my various tesla coils using a number of different radiation instruments and have not seen measurable radiation levels. My coils produce 3 to 5 foot sparks in magnifier and conventional forms using up to 15 kV input, with power levels of no more than 1.5 kVA. Obviously, you don't want to get a survey meter too close to an operating tesla coil. Finally, always keep safety in mind with all of this equipment. Humans are not able to sense X-ray and ultraviolet radiation. If you think you are producing some, use an appropriate instrument to find out for sure. 6.0) Radio Frequency Interference Tesla coils are generally inefficient as antennas go, but can still produce a fair amount of RF, especially if operated with a large top capacitance, before spark breakout. Significant quantities of RF can also be produced if the RF grounding is inadequate. This can cause interference with TV's, radios, and other electronics. If you note interference, try to improve your ground first, since that is likely where your problem is. In addition, every tesla coil should be wired with a power line conditioner in series with the primary circuit. These are relatively inexpensive and are very effective in keeping RF out of the house wiring. Legal dangers In the United States, RF transmitters are regulated by the Federal Communications Commission ( FCC), and they generally aren't keen on any type of RF interference. They have specific rules which prohibit the operation of spark gap type damped oscillators, dating back to the early days of radio. Make sure you operate your coil with a good RF ground. If interference still exists, construct a Faraday cage from chicken wire or similar material, which should eliminate the interference. Other Comments When I first got interested in tesla coils, I called the FCC to ask about the legal aspects of coiling. While the man that I talked to wasn't too sure about the potential interference, he did say that modulation of the output is definitely illegal. Of course, if you shield your coil from emitting RF to the outside world, you can do anything you like.

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Try to be aware that your coil may cause various interference problems. If you know about any, take care to eliminate them if possible before they figure out who caused it.

7.0) Fire Hazards The danger of fires is substantial with tesla coils! Make sure you have a functional fire extinguisher designed for fighting electrical fires handy. Fires can be caused by an overheated spark gap, equipment failure (e.g., shorted Transformer), corona discharge, induced currents, to name a few causes. Fire starting from sparks to flammable points. The sparks from a tesla coil are hot. Depending on where they strike, these sparks can cause a fire. Richard Hull has captured fires caused by sparks from his coils on video tape. (This was due to a failed power line conditioner.) Be sure that when you run your coil, that there are no flammable substances around. For example, gas cans (e.g., for a lawnmower), ammunition, sawdust, fireworks, etc. Walls and ceilings can also be ignited, so keep the fire extinguisher handy. Gasoline on premises (mowers, etc.) Without a spark, what's a tesla coil? What's it take to ignite gasoline? Consider the location of gas cans, lawnmowers, etc. when operating your coil. Remember that when you operate your coil, it's usually in the dark with plenty of exposed high voltage wires. Not a good combination for fighting a fire in your garage. In addition, most coilers use polyethylene and other plastics in constructing their coils, capacitors, and other equipment. These plastics ignite at relatively low temperatures, and produce large quantities of toxic smoke. 8.0) Chemical Hazards Old capacitors and Transformers often used PCB oils for insulation. This oil is a known carcinogen. Similarly, the materials used to coat coils (e.g., varnish) may contain hazardous chemicals. Consult a Material Safety Data Sheet (MSDS) for any materials you have questions about. (Many of these are available via Internet. Use your favorite Web search engine with the key word MSDS'.) Some forms of solder contain lead, which is also generally bad for humans. 9.0) Explosion Hazards Explosions can and do occur with tesla coils! The rotary gap and capacitors are the most frequent culprits, but nearby flammables are also at risk. Rotary gaps During operation, rotary gaps spin at high speeds. The spinning rotor or disk is subjected to tremendous force. At a modest 3600 RPM, the periphery of a 10" disk is subjected to a force of 1835 G's. A 5 gram (0.011 lb) 1/4-20 brass acorn nut used as an 400

electrode will exert a force of over 20 pounds. The peripheral speed of the 10" disk is 107 MPH. At 10000 RPM, the edge of the disk is running at about 300 MPH! All these numbers translate into one thing: Danger. The best way to guard against this danger is to shield the rotor and build the entire system carefully and take pains to balance it. The shielding must be nearly bullet proof (literally). Lexan (polycarbonate) is an excellent plastic for shielding. It is nonconductive, strong, and tough. Consult with your plastics dealer to determine what thickness you need. Capacitors Capacitors are great at releasing energy very quickly. The explosion danger in a capacitor occurs when it shorts out and suddenly produces a large volume of hot vaporized gas. Since capacitors are usually in an airtight container, the volume of gas will cause the container to explode, sending pieces of solid cap guts and oil all over. One recommended method of shielding capacitors is in an HDPE (High Density PolyEthylene) pipe. These pipes are used in the pyrotechnics industry as mortars because of their strength and the fact that they don't create shrapnel as steel or PVC pipes do. Also, avoid storing gasoline or other flammables near a tesla coil! 10.0) Noise Hazards Tesla coils produce a lot of noise, and large coils can damage one's hearing. Go to your local gun shop and buy ear protection if you operate large coils. One type of spark gap, the air blast gap, produces a loud noise. Buy and use a set of ear muffs or ear plugs. There are a wide variety of types of ear plugs and muffs, so you will likely find one that works well and is comfortable. I prefer the roll up foam type myself. If you are on a tight budget (blew all the $$$'s on the pig), you can wash the foam ear plugs. Just put them in a pants pocket (one that closes is best) and run the pants through the wash. Works great. When a coil is in tune, you will notice a dramatic increase in the noise level as it sparks. This noise is loud enough that it can damage hearing. See the warnings in the previous paragraph. Hearing is important -- how will you tell if your teenager is mocking you behind your 11.0) Neighbors, The Spouse, and Children While the beauty of a tesla coil firing outside is something to behold, often your neighbors will not see it that way, and your local police will make a personal house call. Be cognizant of your possibly unreasonable neighbors, and do your work inside if possible, or invite them over and explain things before you start. Attitudes are a lot different if a little common sense is used first. 401

Coils are noisy Please consider your neighbor's sleep habits. Remember the following: ¨ For new parents, sleep is the most precious commodity that they have. ¨ Not everyone works 8am to 5pm. ¨ Not everyone is tolerant or nice. A potential secondary hazard would be from enraged neighbors if radio or TV interference was generated often enough to be a nuisance, and said neighbors could trace it to its source. Good citizenship will solve this problem (or a large building with a good RF ground and a batch of power line filters). Kids, small pets Kids and small pets are quite curious, innocent, and ignorant. (Note the similarity!) Their judgment isn't the greatest either. If you have children and they have access to your coil, install some sort of key lock on your power cabinet, variac, or whatever. Killing or injuring a child or pet, be it yours or neighbors, will most likely be the worst thing that will happen to you in your life. The Spouse Another potential hazard is if the spouse thinks one is spending too much time on his or her hobby. ANY HOBBY!!!! Expect the wife to not understand! 11) Other Whenever possible, have a buddy assist you. Most coilers prefer to operate their coils with the lights off, which is inherently dangerous. This situation can be improved by having an assistant around to operate the lights and/or power Switch. Also, have your buddy learn CPR, and post your local emergency telephone numbers, just to be safe. The layout of your apparatus is also a safety consideration. Many coilers throw their systems together using electrical tape, hot glue, and assorted bits of plastic. If things move around a bit during firing, the risk of something bad occurring is increased significantly. Spend a little time to construct yourself a nice power cabinet with a safety Switch, and construct a safe high voltage transmission line to your coil. Drinking and coiling can be lethal! If you feel the need to consume some mind altering drugs, watch a tesla video instead! Never operate a tesla coil while under the influence! Quaff the ales later during bragging hour, not when you are actually working.

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Corona Corona is caused by the electric field next to an object exceeding the breakdown value for air (or whatever it is immersed in). Since the magnitude of the field is inversely proportional to the radius of curvature, sharper edges break down sooner. The corona starting voltage is typically 30 kV/cm radius. Dust or water particles on the surface of the object reduce the corona starting voltage, probably by providing local areas of tighter curvature, and hence higher field stress. The easiest case to analyze is that of a sphere. The magnitude of the electric field at the surface of a sphere in free space is simply the voltage/radius. Note that if the sphere is near another conductor, the field is no longer uniform, as the charge will redistribute itself towards an adjacent conductor, increasing the field. Since corona is fundamentally a breakdown phenomenon, it follows Paschen's law: the voltage is a function of pd. Double all the dimensions and halve the gas pressure, and the corona voltage will be pretty much the same. Corona Surface Factor The following table gives empirically determined correction factors for various surface conditions. These factors are multiplied by the corona starting voltage (or field) to determine the corrected voltage. Condition of Conductor New, unwashed Washed with grease solvent Scratch-brushed Buffed Dragged and dusty Weathered (5 months) Weathered at low humidity For general design 7 strand concentric lay cable 19, 37, and 61 strand concentric lay cable

m0 0.67-0.74 0.91-0.93 0.88 1.00 0.72-0.75 0.95 0.92 0.87-0.90 0.83-0.87 0.80-0.85

Eliminating or reducing corona Smoothly radiusing the corners of objects at high voltages relative to nearby objects will reduce the local field strength. Put the sharp corner in something with a higher breakdown strength than air. The trick here is to make sure that you have really got the replacement substance in contact with the conductor. By making the high field occur within a substance with a higher breakdown than the surrounding air, corona can be reduced.

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Covering sharp corners with an insulating film increases the corona starting voltage at the points with high E-field stress. Generically known as "corona dope", this is an enamel or polystyrene paints or gels that you can apply. Glyptal is one example, and clear nail polish has also been used. Clear acrylic spray paint is another alternative, although the coating is quite thin. Potting the entire assembly in an insulator (traditionally paraffin or sulfur were used, silicone RTV is a more popular modern alternative) achieves the same result. Immersing the assembly in oil or other insulating fluids will also work. All of the potting and immersion techniques depend on removing the air or gas bubbles to work. Commercial manufacturers pull a vacuum on the container while the assembly is being potted to facilitate the removal of the air bubbles. Experimenters building polyethylene and aluminum foil capacitors for tesla coils run them at low powers using the electrostatic forces between the plates to vibrate and pump the air bubbles out. A popular approach to reducing corona on wires is to surrounding the conductor by a semiconducting film or layer of greater radius. This effectively increases the radius of the object, and hence lowers the field strength. You may not need a huge amount of copper to carry the required current (often micro or milliamps), but you want the diameter of the conductor large enough to reduce the corona. Wire of this type is manufactured by Belden, Rowe-Talley, and Caton, among others. Field grading rings are often used on high voltage equipment to control the electric field distribution. Rather than rely the field that would exist in free space between two charged conductors, a series of other conductors are interposed at intermediate voltages. The intermediate voltages are derived from a capacitive or resistive divider. A capacitive divider may be a simple as the inter electrode capacitances of the grading rings themselves. Running the system in a tank at high pressure, or in an insulating gas, will increase the corona starting voltage. Commissioning The purpose of commissioning is to satisfy, to pre-determined standards, that all the equipment erection is correct and that all the equipment connections / cables have been installed in accordance with the approved erection drawings and diagrams. Furthermore to demonstrate to the satisfaction of the client that the foregoing work has been done and that the equipment functions as designed. The 'Commissioning Procedures' as detailed in this document will be carried out by 'Commissioning Teams' under the direction of the Principal Commissioning Engineer (PCE). The PCE will take overall responsibility for the documentation, drawings, liaison with the client, commissioning lists/methods, supervision and direction of the commissioning teams and clients approval / acceptance. www.sayedsaad.com The format of the commissioning teams will vary of course from contract to contract as the work content and demands change. Normally the PCE will be 404

supported by one or more Senior Commissioning Engineers (SCE) who are authorized to deputies for the PCE in his absence. The appropriate Factory Test Engineers (FTE) and any Subcontractor Commissioning Engineers (CE) will also form an essential part of the team. www.sayedsaad.com The 'Commissioning Procedures' document covers the normal operational and electrical pre-commissioning and commissioning test / checks. It is not intended to cover the post-erection 'mechanical' checks that the (FTE's) carry out as part of their installation responsibility. www.sayedsaad.com To avoid any confusion in this respect this document covers all of the tests and checks that are genuinely considered part of the commissioning procedures to be carried out by the commissioning team and therefore under the direction of the PCE. To ensure that the commissioning procedures are carried out as effectively and efficiently as possible it is vital that co-operation and flexibility is paramount between the various personnel involved, viz erection engineers (factory and sub-contractor), factory test engineers, commissioning engineers and clients' representatives.

Commissioning High voltage equipment 1. Inspection of different compartments for every Switchgear bay including Bus-Bar compartment, Circuit Breaker compartment, Isolators & earthing Switches compartment and cable box compartment. www.sayedsaad.com 2. Circuit Breakers of the same rating shall be fully Interchangeable. www.sayedsaad.com 3. Inspection of the Circuit Breaker parts and its function, also SF6 gas pressure and other related works. 4. Inspection of Circuit Breakers operating mechanism and its function particularly the ones operated by hydraulic or pneumatic system. 5. Inspection of isolators & earthing Switches parts and its functions. www.sayedsaad.com 6. Inspection of the operation & control circuits for the Circuit Breakers isolators and earthing Switches. 7. Inspection of the control and relay boards. All Power Transformer kinds. 1. 2. 3. 4. 5.

Check the Transformer oil level. Check all valves of the Transformer are in the service position. Check the cooling fans operation. Check the automatic tap changer operation. Check for the Transformer protection functions,

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Check that the service settings are adopted for oil temperature & winding temperature instruments. 7. General inspection of all Transformers parts to ensure its healthy condition. Auxiliaries and other equipment. 1. 2.

Inspection of the batteries and its chargers function. Inspection of the air compressors and its function, also to confirm its service settings. 3. Inspection of the LT board and ensure the function of Circuit Breakers and isolators. 4. Inspection of the local Transformers and ensure the related parts healthiness, also service tap position adjustment for manual tap changer. www.sayedsaad.com 5. Inspection of the fire fighting equipment and confirm 'its function, settings and related alarms & signals. 6. 6Inspection of the power cables tails (for feeders and Transformers) and its related oil gauges and to confirm its function, settings, alarms, tank pits, fire resistant coating and all other related works. 7. Inspection of control center communication and telemetry equipment. 8. Inspection of substation main earthing system and connection of all equipment to the earth. www.sayedsaad.com • Protection equipment. Check that each bay is provided with main and back up protection relays. 1. Check that the equipment healthiness & nothing abnormal to block its function and the relay service settings are adopted. 2. Check that the test / service Switches function and all the Switches are in the service position. 3. Inspection of the pilot cable marshalling cabinets and confirm all wires connection with clear identifications 4. Check that all alarms and signals of the substation are received and connected to control center. 5. Check the function of the tap changer automatic voltage regulator, either individual or parallel. 6. Check the function of the Synchronizing equipment (if applicable) for closing or blocking the closing in case of not Synchronized system. 7. Checks the function of the auto reclosure equipment (if applicable) and the intertrip equipment. General note. Confirm the availability of nameplates & labels (for all panels & Transformers at different location of control & relay boards and equipment), operation instruction (if necessary), single line diagram, and GIS sectional drawing. All wires should be provided with ferrules and coloring code. Confirm the receipt of complete copies from test result sheets, instruction manuals and as built marked up drawings. 406

Check the availability of special operating tools, which should be supplied with the equipment and are necessary for the equipment operation and testing. Check the availability of the keys for control & relay panels and different equipment padlocks. These are to be provided in keyboards with proper identification labels & Nos. and to be located at suitable places. www.sayedsaad.com PRE-COMMISSIONING TESTS AND CHECKS 1- Visual Check and Inspection of all Electrical Equipment A visual check will be carried out on all electrical equipment, internally and externally, to determine that no transit/erection damage has occurred (or where this has happened that satisfactory rectification work has been done). All control and relay panels, local control panels, Switchgear and electrical devices will be internally checked for compliance with the approved drawings and approved connection wiring diagrams. The tests carried out in order to satisfy the above will be: 1. 2. 3. 4. 5.

Internal Panel Wiring Compliance Visual Check Internal Panel Wiring/Devices Insulation Check D.C. Supply Checks A.C. Supply Checks Scheme Checks (Positive and Negative Rail Principle)

All relays will be visually checked to see that there is no packing, dirt, metal swarf, etc., present in the magnet gaps or on the contacts. All connections will be checked for tightness on the relays and at all other wiring terminations including the terminal blocks. All devices shall be checked to see that they are clearly numbered/identified in accordance with the general arrangement drawings and that the phases are marked where appropriate. 2- Earthing An earth survey is carried out for each substation at the beginning of the contract in order to obtain a value for the site earth resistivity which is required as part of the Earthing design brief. This should be witnessed and signed by Owner. Standard earthing tests are carried out during the erection stage by the erection staff. On completion of these tests, a copy of the results obtained must be submitted to the PCE for his approval and retention. These tests will be repeated during the acceptance testing stage by the erection staff in liaison with a commissioning team member, when they will be witnessed by the client. www.sayedsaad.com

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3- Bus Wiring All inter-panel bus wiring will be tested and checked in accordance with the appropriate termination diagrams. Insulation checks will be made using a 500V Megger on each bus wire to earth and from each bus wire to all others. These checks should be carried out with all individual fuses, links, miniature Circuit Breakers, etc., open or removed at a) the source of supply and b) all incoming and outgoing circuit panels and Switchgear. www.sayedsaad.com 4- Multi-Core Cables All multi-core cables will be tested and checked in accordance with the appropriate termination diagrams. The insulation resistance will be measured using a 1000V megger after all the multi-core cables have been connected to the erected equipment. (These tests on the multi-core cables although done at the pre-commissioning stage to sort out any obvious problems will be repeated during the acceptance testing stage). 5 - Batteries and Chargers The batteries and chargers will be checked to see that they have been erected / assembled correctly in accordance with the manufacturers recommended procedures. The tests that are carried out at this stage will be to determine that the batteries and chargers are functioning correctly, within the recommended tolerances, so that their performance can be relied upon during the commissioning of the rest of the substation equipment. The responsibility for carrying out the above will be taken by a SCE. The actual acceptance tests, including the time-consuming discharge tests, to be witnessed by the client, are carried out towards the end of the commissioning programme. www.sayedsaad.com 6- 132kV GIS Site Tests These tests are carried out in accordance with the format of the Works Site Test Report. The tests conducted are: 1. Bus-Bar and Connections - Conductivity Tests 2. Circuit Breaker - Contact Resistance Checks 3. Circuit Breaker - Contact Timing Tests 4. Mechanical and Local Electrical Operational Checks 5. Air and Gas Leakage Tests 6. SF6 Gas Pressure Switch Setting Check 7. Compressed Air System Sequence Checks

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7- 132/11.5kV 30 MVA Transformer Site Tests The Transformers are inspected and tested in accordance with the factory check sheets for Transformer installation. As well as detailed inspection this also includes oil testing. 8- Shunt Reactor These tests are carried out in accordance with the format of the Works Site Test Report. The tests conducted are:(1) (2) (3) (4)

Visual Checks. www.sayedsaad.com Winding Insulation Level. Oil Tests. www.sayedsaad.com Oil / Winding Temperature Gauge Calibration Fan Control Sequence Test. www.sayedsaad.com

COMMISSIONING AND ACCEPTANCE TESTS 1- 275, 220,132 and 66kV VT Tests The tests carried out will be: 1. Insulation test 2. Flick Test The polarity of the VT will be checked by carrying out the flick test. 2.2 2- 275, 220,132 and 66kV CT Tests The tests carried out will be: 1. Insulation Test 2. Flick Test 3. Resistance Test 4. Saturation Test Where more than one CT is in each phase of a circuit, tests where practical will be carried out to prove the CT's are positioned correctly so that arranged overlap of zones of protection is correct This may be carried out by a) a visual inspection b) a continuity test. Flick tests will be done on all CT's in a group to prove that they are connected to the protection in the same polarity. These tests will also be done on CT's mounted in Transformer bushings. The flick test results should be compared with those expected from the schematic diagrams. All CT's will have the dc secondary loop resistance and individual secondary winding resistances measured. The saturation tests will be carried out to prove there are no shorted turns associated with the CT and to establish the knee point voltage of the CT's The magnetization curve will be plotted for each CT or superimposed on the factory curves in order to determine that the correct CT is installed.

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3- 275, 220,132 and 66kV Primary Injection Tests these tests carried out will be: 1. 2. 3. 4. 5. 6.

CT Ratio and Polarity Test Busbar Inter-Group CT Ratio and Polarity TestsRelay Operation Tests Busbar Protection Operation and Stability Tests Unit Protection Operation and Stability Tests Directional Over current Operation and Stability Tests

Primary current shall be passed through each CT to prove its ratio and polarity with reference to other CTs in its group. All relays and instruments will be proved to be wired in the correct phases. All current "test terminals" will be checked for correct phasing, CT shorting Switches will be proved and any withdrawable relays should have their shorting contacts checked. Inverse time relays shall be made to "creep' on minimum setting. Earth fault relays shall be checked for spill Current when injecting phase to phase and minimum operation. Transformer biased differential protection. The two groups of CTs, (one on the 132 kV side and one on the 11kV side of the Transformer) should each be proved for ratio and polarity, and the differential relay proved to operate for phase-phase, and phaseearth fault injection on each side of the Transformer. When the Transformer is energies, on load tests will be used to prove stability. Bus zone protection. The group of CT's of each circuit shall be checked for correct ratio and polarity. Each group of CT's should then be checked against the bus section/coupler CT's of the same zone of protection for out of zone stability by measuring spill currents. Directional Over current Protection Operation of the protection will be tested by primary injection of current and voltage simulating the fault direction. Reversal of the current polarity proves the stability of the protection. 4 - Secondary Injection Tests The secondary injection tests will be made to prove the relays, transducers and meters are operating and measuring correctly. Secondary injection tests will consist of 'a.c.' injection into the relay coils to prove that the relay calibration is correct A record of the relay type, serial number, and its setting range shall be recorded. The secondary current injection shall take place from the point at which the primary injection checks were made on the CT's.

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For inverse time relays, the minimum starting current for which the relay will close its contacts with a maximum time dial setting shall be recorded. The resetting time of the disc shall be recorded, and the time of operation for a current injection of twice, five times and ten times setting current. These results should be carried out on the relays service setting (or nominal setting if service not known). The results should be compared with the relay curve supplied by the manufacturer. Also the time setting multiplier characteristics will be checked at 2 points (setting point + 1 other point). For instantaneous relays the operating current or voltage and the drop off value shall be recorded. For all relays fitted with a mechanical flag, the flag should operate just before the contacts make and the flag mechanism should not interfere with the operation of the relay. Differential Relays (e.g. Transformer biased differential or pilot wire relays will require "on-load" checks to prove their stability) in addition to secondary injection tests. Distance protection relays will require current and voltage of varying magnitude injected into them to simulate different values of fault impedance and "on-load" checks will be required to. prove the directional feature of the relay. Directional elements of inverse time O / C and E / F relays will require secondary injection of current and voltage of varying phase angle between them to determine the operation and stability zone. The calibration of all instruments and transducers will be checked at i scale and full scale by current and/or voltage injection with varying phase angle as required. 5- 275, 220,132 and 66kV GIS Operational Tests The tests carried out will be: 1. Local and Remote Operations of all Isolators, Earth Switches and Circuit Breakers 2. Local and Remote Indications of above 3. Electrical Interlocks of above 4. Synchronizing Sequence Tests (including secondary injection of voltage selection scheme) 5. Gas Monitoring Sequence Tests 6. Alarm Sequence Tests 7. Tripping Tests Sequence tests will be carried out to prove all electrical circuits are operating correctly as shown in the schematic diagrams. The control circuits will be tested by the manual operation of all close-trip Switches from all positions, for all Circuit Breakers, disconnecting Switches (line Switches),

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ground Switches (earth Switches), and other devices in accordance with the schematic diagrams. The operation of all protection circuits will be proved to be in accordance with the protective gear schematic diagrams. The tests will be conducted by manually making every main relay contact or initiating device at source and observing Circuit Breaker tripping, auxiliary relay operation, lock-out relay operation and any others. Tripping initiated by each relay in a protection scheme will be tested with the appropriate trip link in and out to prove that the link is connected and labeled correctly. The annunciator circuits will be proved to be in accordance with the schematic diagrams including alarm buzzer and/or bell, lights and any other means of alerting staff. Operation tests of the alarm circuit will be by operating, at source, each alarm initiating relay, where possible, or otherwise by simulation. Operation of each Circuit Breaker, isolator, earthing Switch or other piece of equipment will be proved to be free or locked according to the interlock condition shown on the schematic diagrams. Synchronizing Sequence Tests will be made by secondary injection of voltage at the " VT test terminals" on the, appropriate panels. Care must be taken to ensure that the VT secondary are isolated from the VT voltage circuits so that no high Voltage is developed at the VT primary circuits. 6. 132/11.5kV 30 MVA Operational Tests and Measurement of Audible Noise Level The following checks will be carried out. 1. 2. 3. 4. 5. 6.

Winding Insulation Level Ratio Test Vector Group Test Cooling System Control Sequence Test Local/Remote Tap Change Operations (Mech. and Elec.) Operation of Protective Devices

Load drop compensation and winding temperature CTs mounted in the trans-former should be proved to be in the correct phase and have the correct ratio where practicable. Buchholz relays: the alarm and trip initiation shall be proved by means of the test button, if provided, or by shorting the appropriate terminals at the relay. Winding temperature tripping and alarms shall be proved by operating the appropriate initiating Switches. The cooler control ON and OFF shall be proved when three phase 'A.C.' supplies are available by operating the ON/OFF Switch and the appropriate temperature indicating initiating 412

Switches. The direction of the fan rotation must be checked in accordance with the mark. Tap-changer position indicator should be proved to indicate the correct tap position. The limit Switch must function properly to prevent the tap-changer from further movement beyond the two extreme tap positions. Tap-changing shall be tested for every step ensuring stepping relay functions correctly.

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Measurement of audible noise level on site will be carried out under the following conditions using a sound level meter (IEC Pub 551 type 1 or equivalent): The background noise level at all measuring points shall not exceed 45dBA in accordance with ANSI standard.

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Only the Transformer under test shall be energized and shall have been on soak for at least 24 hours prior to measurement. The tests shall be carried out at rated voltage with all normal fans running at no load conditions. 3. The audible sound level of each Transformer in turn will be measured at a number of points 30 meters from the substation. 4. The average value of the noise measurements for each Transformer shall be taken and this value checked to ensure it does not exceed 50dBA.

7- 11/0.433kV 250kVA Transformer Tests These tests are carried out in accordance with the format of the Works Site Test Report. The tests conducted are:a) Winding Insulation Level b) Ratio Test www.sayedsaad.com c) Vector Group 8- HV Pressure Tests (132kV Equipment) These tests will be carried out in accordance with the Works Site Test Reports. The magnitude and duration of the test voltage is given in Table below. An opportunity to check VT calibration will be taken during these tests. Test Voltage Test Equipment KV Duration 132 GIS 115 10 min. 11 KV 24 1 min 9- Supervisory Interface Test The tests carried out will be: a) Initiation of the appropriate alarms or indications at source and checking that the correct logic signals are received at the telemetry terminal (TTB) cabinet. 413

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Apply a 50V DC voltage to the (TTB) cabinet terminals and check that the correct Circuit Breaker or tap changer command is received and executed.

10 - 11kV VT Tests. www.sayedsaad.com The tests carried out will be: a) Insulation Test. www.sayedsaad.com b) Flick Test. www.sayedsaad.com The polarity of the VT will be checked by carrying out the flick test. 11 - 11kV CT Tests The tests carried out will be: a) Insulation Test. www.sayedsaad.com b) Flick Test. www.sayedsaad.com c) Resistance Test d) Saturation Test Where more than one CT is in each phase of a circuit, tests where practical will be carried out to prove the CT's are positioned correctly so that arranged overlap of zones of protection is correct This may be carried out by a) a visual inspection b) a continuity test. Flick tests will be done on all CT's in a group to prove that they are connected to the protection in the same polarity. These tests will also be done on CT's mounted in Transformer bushings. The flick test results should be compared with those expected from the schematic diagrams. All CT's will have the dc secondary loop resistance and individual secondary winding resistances measured. www.sayedsaad.com The saturation tests will be carried out to prove there are no shorted turns associated with the CT and to establish the knee point voltage of the CT's The magnetization curve will be plotted for each CT or superimposed on the factory curves in order to determine that the correct CT is installed. 12- 11kV Primary Injection Tests the tests carried out will be: a) CT Ratio and Polarity Test b) Relay Operation Tests c) Unit Protection Operation and Stability Tests Primary current shall be passed through each CT to prove its ratio and polarity with reference to other CTs in its group. All relays and instruments will be proved to be wired in the correct phases.www.sayedsaad.com All current "test terminals" will be checked for correct phasing, CT shorting Switches will be proved and any withdrawable relays should have their shorting contacts checked. Inverse time relays shall be made to "creep' on minimum setting.

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Transformer biased differential protection. The group of CTs should be proved for ratio and polarity, and the differential relay proved to operate for phase-phase, and phase-earth fault injection. Transformer Restricted Earth F a u l t Protections. The groups of CTs shall be proved for ratio and p o l a r i t y and stability by measuring spill currents. 13- 11kV Secondary Injection Tests The secondary injection tests will be made to prove the relays, transducers and meters are operating a n d measuring correctly. Secondary injection tests will consist of 'a.c.' injection into the relay coils to prove that the relay calibration is correct A record of the relay type, serial number, and its setting range shall be recorded. The secondary current injection shall take place from the point at which the primary injection checks were made on the CTs. For inverse time relays, the minimum starting current for which the relay will close its contacts with a maximum time dial setting shall be recorded. The resetting time of the disc shall b_ recorded, and the time of operation for a current injection of twice, five times and ten times setting current. These results should be carried out on the relays service setting (or nominal setting if service not known). The results should be compared with the relay curve supplied by the manufacturer. Also the time setting multiplier characteristics will be checked at 2 points (setting point +1 other point). For all relays fitted with a mechanical flag, the flag should operate just before the contacts make and the flag mechanism should not interfere with the operation of the relay. The calibration of all instruments and transducers will be checked at scale and full scale by current and/or voltage injection as appropriate. 14. 11kV Switchgear Contact Resistance Checks The contact resistance of all primary contacts will be checked by current injection and voltage drop measurement. 15. 11kV Switchgear Operational Tests The tests carried out will be: a) Local and Remote Operations of all Circuit Breakers b) Local and Remote Indications of above c) Electrical Interlocks of above d) Gas Monitoring Sequence Tests e) Alarm Sequence Tests f) Tripping Tests including Arc Fault Tripping scheme www.sayedsaad.com Sequence tests will be carried out to prove all electrical circuits are operating correctly as shown in the schematic diagrams.

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The control circuits will be tested by the manual operation of all close-trip Switches from all positions, for all Circuit Breakers and other devices in accordance with the schematic diagrams. The operation of all protection circuits will be proved to be in accordance with the protective gear schematic diagrams. The tests will be conducted by manually making every main relay contact and observing Circuit Breaker tripping, auxiliary relay operation, lock-out relay operation and any others. Tripping initiated by each relay in a protection scheme will be tested with the appropriate trip link in and out to prove that the link is connected and labeled correctly. www.sayedsaad.com The annunciator circuits will be proved to be in accordance with the schematic diagrams including alarm buzzer and/or bell, lights and any other means of alerting staff. Operation tests of the alarm circuit will be by operating, at source, each alarm initiating relay contact, where possible,-or otherwise by simulation. Operation of each Circuit Breaker disconnect Switch and earthing Switch will be proved to be free or locked according to the interlock condition shown on the schematic diagrams. www.sayedsaad.com 16.HV Pressure Tests (11kV Equipment) These tests will be carried out in accordance with the Marugame Works Test Sheets. The magnitude and duration of the test voltages are given in Table 1 www.sayedsaad.com 17. Battery and Charger Tests The batteries and chargers will have already been assembled, checked and put into service during the pre-commissioning stage by members of the commissioning team. However certain further tests are now done and others repeated during the acceptance testing stage to be witnessed by the client. These tests will be carried out in accordance with the manufacturers recommended testing procedures and will include the battery discharge tests. www.sayedsaad.com 18. Multi-Core Cable Tests All the multi-core cables will have already been checked to be in accordance with the appropriate termination diagrams during the pre-commissioning stage. The insulation resistance tests will be repeated during the acceptance testing stage when they will be witnessed by the client. www.sayedsaad.com 19. Earthing Tests The erection staff will have originally conducted earthing tests but these will be repeated during the acceptance testing stage when they will be witnessed by the client. www.sayedsaad.com 20. Fire Fighting Equipment Tests The Subcontractor will have already carried out limited post erection checks, i.e. mechanical checks including a pressure test on the main tank and air leakage tests on the air receiver. The commissioning tests for water spray system will be:www.sayedsaad.com a) Compressor Sequence Tests b) Alarm Sequence Tests

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c) Indication Sequence Tests d) Deluge Valve Sequence Tests e) Discharge and Water Spray Tests f) Inter-tripping Tests www.sayedsaad.com The commissioning for the other systems will be: www.sayedsaad.com a) Detector Operation Tests b) Detector Line Supervision Tests c) Pushbutton Function Tests d) Tripping Tests e) Halon Discharge Test f) Dry Powder Discharge Test

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