Power Systems Protection subtransmission, distribution & industrial levels, Part III POWER SYSTEMS STUDIES: In order to be able to adequately select the protective relays in an electrical power system, certain studies and calculations have to be performed. The degree of complexity varies from one system to another. Despite this fact certain studies are common to any system, though using different approaches and mathematical models. Power systems can be classified, broadly, into radial and network configurations (designs). The essential studies to be done are: fault calculations (parallel and series faults), load flow, transients and reliability. Fault calculations can be performed using the traditional method of system impedance (reactance) reduction or using the system (network) impedance (reactance) model. The major outputs of studies are: the short circuit current levels after the first cycle (important in calculating the mechanical forces exerted on the system and in specifying momentary ratings), after 3 or 5 or 8 cycle (required to specify the breaking device interrupting ratings, and the thermal overloading of the system) and after 30 cycles (if applicable, important for time delay calculations). Load flow studies are performed using Newton Raphson method or fast decoupled and successive elimination method of solving simultaneous equations. It is possible to use other methods. The admittance (susceptance) network (system) model is used to calculate the equivalent elements for the system under study. The study can be performed for different configurations and system components. It can, also, include for the effects of starting a large motor on the system. The major outputs are: the voltage and phase angle of each bus included in the study, the active and reactive power flowing between the different buses (nodes) in the system. Transients analysis will vary from one system to the other and it will depend on the operation of the system, its location, its extent, the transients that have to be investigated in order to get a better understanding of transients in the subject system. Examples of calculations are: the overvoltages induced in the system due to direct lightning hits, indirect lightning hits, the operation of the breaking devices under fault conditions, ferroresonance, the effect of the L.A. leads on the overvoltages seen by the protected equipment. Reliability studies, in general, includes for the relays (plus the other elements) in the system their number, type, failure rate, and number of hours per failure. The reliability study is function of the degree of compexity of the system under study (or design). Subtransmission and/or distribution system protection: The electrical power distribution system components constituting the utility portion up to the service entrance in a plant will, typically, have the following major elements: overhead high voltage transmission line (eg. 115kV or 230kV) high voltage disconnect switches (eg. 115kV or 230kV) lightning arresters (station, distribution and maybe riser pole types) capacitive voltage transformers power transformers (eg. 230kV/27.6kV, 100MVA) M.V. circuit breakers (main, tie and feeders) instrument transformers relay/metering panels
overhead distribution lines and poles fuses, insulators & switches underground cables, terminations & splices distribution transformers (single and three phase) reclosers and/or sectionalizers system control & data acquisition equipment distribution transformers (single and three phase) reclosers and/or sectionalizers system control & data acquisition equipment For distribution of power from the service entrance boards downstream to the different loads and load centers, the major elements are: M.V. service entrance board or gear complete with breakers or switches/fuses combination main distribution transformers (dry or liquid filled eg. 27.6kV/600V) 600V distribution board complete with molded case breakers/switches and/or power breakers secondary distribution transformers (600/120/208V) 600V motor control centres M.V. motor starters complete with motor protective relays distribution/lighting panels complete with molded case circuit breakers or fuses interconnecting wires/cables and loads (motors, lighting, appliances, office equipment, heating equipment and others) Protection for transformer station: The power transformers can have any of the following connections: Ydelta, deltaYG, YDYG, deltaYGYG, YZG, YZGZG. The protection to the power transformers (example of rating 75/100/125MVA, 230kV/27.6kV) will be against internal faults and is provided through the use of gas relays (in the transformer tank and tap changer enclosure) and one differential relay. Another differential relay of a different type, redundant (for dependability reasons) may,also, be used. Other faults that may occur and do not warrant a trip but rather an alarm or the operation of a bank of fans are: overload and overheating of the transformer. For overvoltage protection, horn gap protectors, lightning arresters and transformer rod gaps may be used. Overexciting of the transformer may occur and an overvoltage relay may be used to indicate or alarm, rather than to trip. Other devices that are found on transformers in order to indicate or protect against a certain abnormality are: thermometers, winding temperature equipment (thermometers) and pressure relief devices. Thermometers indicate top liquid temperature (ambient plus temperature rise of transformer). Thermometers may have a bimetal spiral in the metal housing, temperature indicating pointer, drag pointer (resettable). The liquid tight well for the sensing element allows the removal of the thermometer with no further steps. Thermometers may have up to three micro switches, the first for the fans (close @ 70 C, open @ 65 C), the second for the alarm (close @ 85, open @ 80) and the third for the trip (close @ 85 , open @ 90 ). The winding temperature thermometers can be classified into direct type and C.T. type. The first type has a capillary tube equiped with porcelain insulator that isolates the sensing bulb from the thermometer. The bulb is usually placed in direct contact with the low voltage
bus. The second type consists of thermometer bulb, a resistor or thermocouple inserted in resistance heating element which is energized from a current transformer. The heating element and temperature sensitive device are mounted in a dry well on the tank wall, the whole assembley is then immersed in the top liquid. Pressure relief devices are used in sealed transformers. The common types are the diaphragm and the mechanical automatic reseal. The diaphragm is designed to rupture before damaging pressure can build up. After operation the diaphram has to be replaced. The automatic reseal type will maintain its seal until the threshold pressure (eg. 8psi + 1) is reached, at which point the valve snaps open, the full operation takes about 2 milliseconds. The device automatically recloses and reseals when the intermal pressure drops to 4 psi approx. Remote and local indicators to show that the device had operated are, usually, available but not necessarly as a standard part of the transformer. Restricted ground (earth) faults may occur when the transformer neutral is grounded through high impedance, special protection is applied. The protection for this application is provided through the use of 4 current transformers (sensors), one in each phase and the fourth in the neutral circuit (between the neutral and the first terminal of the grounding resistor). The overcurrent relay connected in a differential protection configuration is connected across the C.T. in the neutral circuit and the other three current transformers connected in parallel. For external faults the secondary currents will circulate in the current transformers windings and not through the operating coil (circuit) of the relay; while in case of internal faults it will flow through the relay (this approach is also used in generator protection under similar conditions). The differential protection is one that operates when the vectorial difference of two or more electrical quantities of the same type exceeds a predetermined value. What makes a protection differential is the way the circuit is connected. The most extensively used current differential relay is the percentage. Such relay has operating and restraint coils or circuits. There are two types of percentage differential relays: the fixed and the variable. The fixed has the following property: the ratio of the differential operating current (the difference of the two secondary currents of the current transformers on the high and low voltage power transformer windings divided by 2) to the average restraining current (the sum of the two secondary currents of the current transformers on the high and low voltage power transformer windings divided by 2) is a fixed value. The variable has the following characteristics: the slope of the operating current to the restraint current increases with higher through currents. The current in the operating coil tends to operate the relay, the current in the restraint coil tends to prevent this operation. This design is necessary to restrain the relay from operation for any faults outside the protected zone or for any unbalanced conditions or for the discrepancies in the characteristics of the current transformers, avoiding nuisance tripping. Transformers draw a steady state magnetizing current under normal operation (exciting current). This current can vary between 1 and 5% (depending on the design and type of steel used in the core) of the rated full load current of the transformer. Subjecting transformers to overvoltage, increases the exciting current significantly and due to the nonlinear magnetizing ch/cs of the core, harmonics (third and fifth) will be present. A pickup setting above the steady state exciting current would seem good enough, however, the amount of unbalance and the limited restraint at high emergency through current loads, may dictate a higher setting. The choice of the percent slope value is a function of three factors. The unbalance in the secondary outputs of the differential zone C.T. may be caused by the tap changer of the power transformer. Secondly, there will be an error current due to the mismatch of the C.T. taps, it is based on
the average of the restraint currents. Finally, the ratio errors of the current transformers themselves may affect the unbalance of the secondary outputs. All these factors have to be taken into consideration to get the maximum possible percent unbalance. When transformers are energized, a large inrush transient current will flow through the primary of the transformer (and not seen by the secondary windings). Thus, the operating coil of the differential relay will receive currents with high peak values, leading to greater tendency for the relay to operate. The magnitude and wave shape of the inrush current is function of: the magnitude (point) of the supply voltage, at which the transformer is energized, the residual flux and its relationship in polarity and magnitude with respect to the instantaneous value of the steady state flux (corresponding to the particular initial energization point), the ratio of saturation flux density to the operating flux density at rated voltage. The duration of the inrush is affected by the size of the transformer bank and the resistance in the power system from the source to the transformer. The magnitude will be affected by the size of the power system, type of steel used in the transformer core and its saturation density and the residual flux level. For three phase transformers, the electrical connections of the windings and the magnetic coupling between the phases, affect the inrush. The inrush current is rich in second harmonic components, it varies from 20% to 65%. There are another two types of inrush, other than the initial, the first is the recovery which is the inrush that occurs after a fault external to the bank has been cleared and the voltage rises from the fault condition to the normal level. The second is the sympathetic inrush which is the inrush to an already energized transformer while another one in parallel with the first is being energized. Differential relays may have a second harmonic restraint element to prevent the relay operation during transformer energization. A dedicated overexcitation protection is provided when it is desired to protect against overvoltage (for short times). Differential relays can have a fifth harmonic filter to restrain the relay from operation (when overexcited). This will prevent the relay (instantaneous) operation, due to overvoltage. The percentage of the fifth harmonic (due to overvoltage) is approximately 35% of the fundamental. The third harmonic is also present when overexciting the transformer. The current transformers should be selected and connected to achieve the following: correct secondary currents of the current transformers to reflect the different voltages (and cosequently the full load and fault currents) of the secondary of the power transformer to its primary. if there is a phase shift angle between the secondary and primary, the C.T. connection on each side should compensate for such difference (eg. for a delta or a zigzag connected power transformer windings, the current transformers have to be connected in wye; for a wye connected power transformer windings, The current transformers to be connected in delta). the secondary currents through the differential relay should not cause the relay to operate under external (through) faults or maximum emergency load and should operate the relay for internal faults (should be sufficiently higher than the restraint pickup level). The C.T. ratio is chosen so that it will give a secondary current close to but less than the nominal rated current of the relay at maximum load condition. Two winding percentage differential relays can be used for three winding transformers, provided the current transformers on the secondary side of the transformer are connected in parallel. Its advantage is its cost saving. In a network where more than one station is fed from the same transmission line through power
transformers, a fault in the protected zone of the transformer should trip the breaker or breakers (main) on the low voltage side, remote tripping of the breakers upstream of this transformer (at terminal stations) and all low voltage side breakers (main) of transformers connected to the same line. The load break switch on the high voltage side, connected to the transformer high voltage bushing, is also tripped open. When the switch opens, the remote trip signal will be terminated (because of the disconnect switch interlock used in the remote trip circuit), the terminal breakers and l.v. breakers connected to the other than the faulty transformer are reclosed. For gas protection, Buchholz (pressure type) relays connected between the tank and the conservator (in the piping) are used. One of the 2 elements of this relay is a gas collecting chamber. After a certain amount of gas is collected, a contact is closed to sound an alarm. The second element contains a vane which is operated by the rush of oil through the piping. The first to protect against slow breakdown of insulation, the second against severe faults occurring inside the transformer. The second type of subtransmission/distribution system protection is the overhead line (H.V. eg. 230kV or 115kV) carried on transmission towers. This type of protection is applicable to transformer stations with ungrounded wye or delta transformer high voltage windings. Assuming a system that has two lines feeding a station through a breaker and a half (H.V. bus configuration) and the secondary of the transformers have main breakers and a tie breaker between the 2 medium voltage buses, under a fault on a line, a remote trip from the terminal stations is sent to initiate a trip and the pertinent M.V. breaker, that will complete the fault isolation, is opened. In this case, the line protection at the transformer station will be considered as backup. If the terminal station has no remote trip capability, this line protection at the transformer station is the first line of protection to trip the M.V. breaker. This protection is achieved through the use of directional phase distance relays (IEEE #21) and ground residual overvoltage relays (nondirectional). The use of two independent differential protections on power transformers at transformer stations, make it necessary to use circuit breaker failure protection for the main M.V. breakers. This protection is controlled from one of the contacts of the breakers auxiliary switch. When this protection is to operate with a standard configuration of a dual secondary winding power transformer, a signal is sent to initiate tripping of all breakers necessary to isolate a fault. In the event of failure of one of the main M.V. breakers, the breaker failure protection will trip all feeder breakers, the tie breaker and two of the remaining closed main breakers. It also sends remote trip to the terminal station affected and opens the transformer disconnect switch (at the right moment while no current is flowing through the switch) to isolate the transformer with the faulty breaker, thus permitting a reclose of the terminal breaker. Circuit breaker reclosing schemes are used between the terminal and transformer stations. The purpose of having such schemes is to permit reclosing after transient faults on H.V. lines thus: reestablishing the interrupted interconnections terminating any low voltages on customer buses restoring the previous level of load security Automatic reclosing can be classified into delayed and high speed. The latter is defined as closing the circuit breaker after a time delay, just sufficient to allow for the deionization of the arc. This time = 6 to 10.5 + (system KV/34.5) cycles and it varies from 12 to 17 cycles for 230kV lines. As long as maintaining stability of the system is not a function of reclosing, high speed reclosing is not a must.
The delayed reclosing is in the range of 510 seconds, this allows the initial system oscillation to decay. Reclosing is only permitted if specific system conditions are to be satisfied. When reclosing occurs for more than one circuit element, a predetermined sequence is to be set. The control logic to allow the reclosing can be any combination of the following: voltage presence, undervoltage, synchrocheck, long and short time. Two contacts from the voltage relay, one normally open, the other normally closed, provide the voltage presence and the undervoltage supervision, respectively. The relay picks up at 80% of the nominal and drops out at 30% of the nominal. The synchrocheck relay provided, checks for the presence of the voltage on both sides of the opened C.B. and that they are within the limits, it checks, also, for the phase angle between the two voltages and that they are within a preset range for the period of time defined. The long and shorttime time are usually used in conjunction with the voltage supervision relay (voltage presence using the U/V condition). Generally, any attempt to reclose (automatically) a circuit breaker following a trip is made only if there is a reasonable probability that the fault initiating the trip is transient in nature. A single shot reclose scheme (a practical approach), provides similar discrimination for line faults. A single close attempt, after the initial trip, is considered a test for the nature of the fault. If the breaker recloses and stays for a minimum period of 10 seconds, the fault is assumed to be of a transient nature and the scheme resets (getting ready for the next fault). Reclosure is cancelled, not initiated, if the fault is occurring in a zone where transients are unlikely like generators, transformers, bus ducts and switchgear bus assemblies. To achieve remote trips and reclose, communication channels are required. Signals can be transmitted through power line carriers, by microwave antenna or through a dedicated pair of telephone wires. The last has a d.c. voltage applied at the local end to energize voltage sensing relays, installed at the remote ends which trip/annunciate the appropriate circuit. Generally, two such channels are provided to improve reliability. The availability, routes, size and type of telephone wires vary greatly (eg. #22 to #26 or #19 AWG). The maximum loop resistance of the telephone circuit (for two ended circuits) has to be 9600 ohm if the voltage at the trip receive relay end is to be 55V d.c., when the sending end has 125V d.c. This resistance is equivalent to approximately 90 km of #22 AWG and 56 km of #24 AWG. When the sending end has 250V d.c., the loop resistance can be 10,600 ohms, which is equivalent to 100 km and 61 km of #22 & #24 AWG, respectively. Monitoring relays, located at one terminal only, are used to indicate or annunciate when a channel becomes defective. The operating time of such protection can be 25 MilliSec, when both channels operate (higher speed of operation is allowed as when both channels are operating the chance of having false signal from both channels simultaneously is quite remote) or when one channel operates (to allow for transients and to avoid nuissance tripping) is 85 MilliSec. The two remaining types of transformer station protection are: the medium voltage bus protection (differential, phase O/C and ground O/C relays), the feeder protection. In most cases, the M.V. bus is fed from the zigzag secondary winding of the power transformer with the neutral reactor grounded or from the delta winding. Overcurrent relays connected in a differential configuration or percentage differential relays or high impedance bus differential relays are used to protect against permanent faults in the bus zone. The common neutral of the differentially connected C.T.s (from the main transformer low voltage breakers, tie breaker and feeder breakers) are grounded at one point only. All current transformers will have the same ratio and characteristics. All feeder breakers, transformer breakers and tie breakers on the faulted bus are tripped and automatic reclosure is inhibited when this relay operates.
This differential protection relay (one per phase) will have an instantaneous and timed element. Overcurrent back up protection is provided using phase and ground inverse timed O/C relays. Reclosure is inhibited when this relay operates. This differential protection relay (one per phase) will have an instantaneous and timed element. Overcurrent back up protection is provided using phase and ground inverse timed O/C relays and is set to operate on the same breakers as the main protective relays if the bus differential scheme fails. Usually, the ground O/C relay requires a high current range to permit higher pickup current settings. The back up protection will trip the breakers as mentioned above, the overcurrent relays are connected to current transformers installed in the switchgear on the main transformers secondary breaker or breakers connected to the subject bus. The feeders (breakers) are protected against overcurrent & short circuit and protection is provided through the use of different types of relays O/C timed, instantaneous, auxiliary and reclosing (if required). Other types of relays like the solid state/microprocessor, can provide the previously mentioned protection with more flexibility and by using only one relay, substituting for the O/C, reclosing and auxiliaries. Another advantage of the solid state relay is the amount of data that can be retrieved under S.C. conditions on the feeder, like the magnitude of the fault current, the phase or phases affected. This data is also important to indicate the cumulative currents, the breaker is subjected to when interrupting faults. Generally, these relays have built in ammeters to indicate the current levels in the different phases under normal operation. As only radial feeders are covered here, the relays used are nondirectional. The timed element of O/C relays can have a few shapes such as definite time, inverse, very inverse and extremely inverse. The last provides fastest clearance at higher fault values. It closely approximates the fuse curves which the relay should coordinate with (downstream). The extremely inverse characteristics is preferred for cold load pickup. Initial cold load inrush can reach 4 times normal peak loads, for a few seconds (about 2 to 10), after which it will decay to approximately 1 1/2 times. The two parameters that govern the relay operation are the pickup current value and the duration the current has to stay above the pickup value. High set instantaneous protection are used to protect that portion of the feeder that is close to the station. Under closein S.C. conditions, fast clearance is a must. There is usually another setting in feeder protection called low set instantaneous. It is intended for transient faults and is used with a reclosing scheme. It is meant to reduce the mechanical and the thermal stress on the feeder (and the equipment or lines connected between the source and the faulty point) and to reduce voltage disturbances on the station bus and consequently, the other feeders. It is set low to cover the entire feeder. When this protection operates and reclosing is initiated, the low set instantaneous is blocked as a fault that persists after reclosing is probably permanent and requires coordinated (with downstream fuses and reclosers) isolation. The low setting protection is also blocked during line energization. When discrete relays are used to provide feeder protection, a number of measuring relay contacts are connected in parallel. When any of these relays operate, the trip relay is energized to trip the C.B., annunciate and initiate reclosing. Reclosing is only used with overhead feeder lines and most probably, will be a singleshot one. The reclose scheme is disabled through the use of an auxiliary breaker control switch or protective relay contacts (if the breaker was previously opened manually or tripped by another protection). Supervision for reclosing is provided through a timer. For single shot reclose, the breaker is locked out, under the following conditions: trip on the delayed portion of the current/time ch/cs curve, after the previous trip of same or low instantaneous,
after first trip on the high instantaneous. Typical settings of these relays are the pickup current is approximately twice the full load current of the feeder and less than the minimum feeder end fault (3 phase). The minimum feeder end fault is to be isolated in 2 to 3 seconds (this is for phase timed O/C protection). For ground timed O/C protection, the feeder end ground fault is to be isolated in 1.5 to 2 seconds. The pickup level is function of the available ground fault current. It has to accommodate for the possible feeder unbalance loading. Distribution system protection: From the transformer station, the feeder breakers are connected to cables and out it goes to overhead lines into distribution transformers, unit substations or distribution stations. The feeders are assumed to be of the radial design (rather than the loop network one). At the taps, from the overhead lines to, for example, underground residential areas or to an industrial plant service entrance board, a power fuse and a switching device are usually installed. For a tap into a distribution pole mounted transformer, a series of a fuse cutout, with fuse link plus current limiting fuse are installed ahead of the transformer. Other switching/protecting components that are found in overhead distribution systems are reclosers and sectionalizers. In underground systems, fuses and tripping devices are found. For Reclosers & Sectionalizers, refer to Part II. For Fuses for Distribution Transformers, refer to Part II. Industrial systems protection: In industrial systems the protection of equipment and systems uses a variety of breaking/protective devices. Certain protectiv/breaking devices are integral, others are separate from each other. The breaking devices can be: molded case circuit breakers, air magnetic circuit breakers, molded case switches, safety switches, contactors, medium voltage circuit breakers (breaking medium can be any of air, oil, SF6 or vaccum). Also, load break switches and disconnect switches are found in industrial systems. The majority of the load in such systems is squirrel cage induction motors (about 75 % in average of total connected load). In generators protective schemes, the following types of relays are found: overcurrent, o/c ground, differential, negative sequence o/c, reverse power, field failure and ground fault protection for the field. For motors, the following types of relays are usually applied: overcurrent, neutral or ground overcurrent, thermal overload, reverse (directional) power relay, phase sequence voltage and overvoltage/undervoltage relay. For transformer protection, transformer percentage differential, gas and overcurrent relays are found. For transmission lines, distance relays are used to protect against faults on lines. For bus protection, differential relays or overcurrent relays connected in differential configuration are used. Certain critical relays may be duplicated (redundancy) for reliability reasons. Backup protection is also common for critical stations. If the primary protections are to fail, the back up will take over, interrupt the circuit or circuits minimizing the disturbances to other load centres. For low voltage direct acting tripping devices and fuses, refer to Part II. For relays refer to Part II. Factory testing: Static relays testing methods differ from those of electromagnetic relays, as they have lower burdens,
are more susceptible to higher voltages and disturbances, are built from semiconductor components rather than coils and cores. For electromagnetic relays, the following tests are performed at the factory: operation, calibration, insulation withstandability and maybe impulse. For solid state/microprocessor based, the following tests are performed: operation, current circuit dielectric (insulation) withstandability tests (eg. 2.5 KV for 1 min. @ 50 or 60 c/s), other circuits dielectric (insulation) tests (eg. 2 KV for 1 min. @ 50 or 60 c/s), impulse voltsge tests (eg. 5 KV, .5 Joule, shape 1.2/50),fast transient disturbances (eg. 4 KV for 2 min.) and burst tests (eg. 1 MHZ, 2 KV decaying to 50 % in 6 cycles and remaining for 2 sec.). Site testing: This type of testing can be classified into commissioning and routine maintenance. The following are typical testing for certain protective relays at the site and prior to startup of the plant: Overcurrent (instantaneous or timed): insulation resistance, pickup value, dropout and timing. Over/undervoltage: same as overcurrent, above. Differential: insulation resistance, pickup value, timing and slope characteristics. Directional: insulation resistance, pickup, timing, polarity check, directional sensitivity and stray operation check. Reverse power: insulation resistance, polarity, directional sensitivity and stray operation check. Over/under frequency: insulation resistance, pickup value, dropout value and timing. Distance: insulation resistance, pickup, timing, polarity check, directional sensitivity, stray operation check and flag/auxiliary contacts operation. Negative sequence: insulation resistance, pickup and timing. Current balance: same as ve sequence, above plus slope characteristics. Periodic checks on relays to ensure that the setting (adjustment) has not been changed or drifted are important. At the setting the following is checked (whichever applicable to the relay type and application): operation of relay flags and/or visual indicators (local and remote), the tripping of the associated breaker, the operation of the annunciator panel or sound alarm. The frequency of such testing is function of the following factors: the environment in which the relay is installed and operated (eg. temperature, humidity, degree of pollution), whether the subject protective scheme is a backup or the primary protection, size and importance of equipment being protected, the consequences of maloperation of the protective scheme. Adjustments (settings): As mentioned previously, in order to reach the stage of setting the protective relays, a good understanding of the system has to be achieved and the necessary calculations and studies on the system have been done. For typical relays, the necessary settings will be given hereafter: Overcurrent relays: time delayed setting (eg. .5 to 200% of relay rated current), instantaneous setting (5 tp 30 times delayed relay setting or relay rated current function of type) and time multiplier setting (eg. .05 to 1 in .025 steps). Over/undervoltage relays: pickup setting (eg. 60 to 110 V), dropout (eg. 70 to 99 %), time delay on
pickup and dropout (eg. instantaneous or .1 to 1 sec.). Differential: pickup slope (eg. 20 to 50 %), operating current setting (eg. 20 to 50 % of relay rated current 1 or 5 amp.), unrestrained settable current (eg. 8,13,20 times relay rated current). Directional: maximum torque angle (eg. 0 to 90 deg.), sector width (30 to 180 deg.) Reverse power: operating time (eg. 1 to 30 sec or instantaneous), minimum pickup values of current and voltage (eg. rated volt, .02 amp.). Over/under frequency: frequency setting (eg. 59 c/s), timer setting range (.15 to 5 sec.) Distance: relay reach (eg. .2 to 4.5 secondary ohms or 1.27 to 36.6), maximum torque angle (eg. 60 to 75 deg.) Negative sequence: tap setting (eg. from 2.5 to 4.5 amp.), pickup setting (eg. from 10 to 40 % of tap setting), time setting (eg. 5 to 20). Current balance: ve sequence current pickup (eg. .3 to 1.2), time delay adjustment (eg. .5 to 4 sec.) Voltage phase unbalance: pickup (eg. 1, 2 or 3 ve sequence volt), time delay (4, 8 or 128 cycles). Synchrocheck: magnitude of vector difference voltage (eg. 20 to 60 V), time adjustment (eg. 1 to 15 sec.), dead busdead line levels (eg. 0 to 120 V). Loss of field: impedance setting (eg. 2.08 to 56 ohm in 3% steps), undervoltage unit setting (eg. 65 to 85 %), timer setting (.2 to 3 sec. in .2 sec.). Reclosing: number of reclosures (eg. 1 or 2 or 3), time between reclosures (eg. .5 to 5 sec. adjusted continuasly). Motor protection: full load current FLC (1 to 6 amp. in .1 amp. steps), instantaneous pickip (1 to 10 times full load current in 1 time x step), load jam current & delay (eg. 1 to 10 times FLC in .1 steps & .5 to 10 sec. in .1 sec.), load loss current & delay (eg. 0 to 1 FLC in .01 steps & 1 to 20 sec. in .1 sec steps), ground overcurrent pickup adjustment (eg. 5 to 50 amp. in primary current and in 1 steps), ground overcurrent time delay (.04 to 1 sec. in .01 sec.), ve sequence pickup adjustment (eg. .1 to .5 FLC in .01 steps), ve sequence tripping delay (eg. .05 to 5 sec. in .01 sec. steps), RTD trip setting (eg. 10 to 200 deg.), RTD alarm setting (eg. 2 to 20 deg. below trip setting). Feeder protection: low set starting current adjustment (eg. .5 to 2.5 times rated input current 1 or 5 amp.), time setting (.05 to 100 sec. or time multiplier = .05 to 1), high set starting current adjustment (eg. .5 to 20 times rated input current), operating time (.03 to 100 sec.), starting current of the low set ground (earth) fault (eg. .1 to .5 times rated input current), time setting (eg. .05 to 100 sec. or time multiplier = .05 to 10), starting current of the high set ground (earth) fault (eg. .1 to 4 times rated current), operating time setting (eg. .05 to 100 sec.), number of high speed reclosing (eg. 1), number of delayed reclosing (eg. 1 to 3 or 4), initiated by overcurrent starting delay preceding high speed or delayed reclosing (eg. .05 to 2.5 sec. or .05 to 5 sec.), initiated by ground fault starting delay preceding high speed or delayed reclosing ( similar to initiated by o/c), dead time of high speed or delayed reclosing (eg. .1 to 99 sec. or 2 to 999 sec.). Coordinaion studies: For the coordination study the following data are essential: the relays currenttime characteristics curves, fuses total clearing timecurrent & minimum melting timecurrent characteristic curves, total available 3phase short circuit current in the system, the 58% IEEE point for transformers connected in
delta wye, damage curves for cables & transformers, inrush currents to induction motors and their durations, inrush currents for transformers and duration, relays burden data, instrument transformers saturation, excitation, accuracy, ratio, taps number and ratios data. For a numerical example regarding power transformer protection, refer to EPDS, level 1, lesson 2, question 27 For a numerical example regarding sizing of breakong devices, refer to EPDS, level 1, lesson 3, question 16 For a numerical example regarding principle calculations of power systems analysis, refer to EPDS, level 1, lesson 5, question 12