Calculations of Protective Relay Settings

ABSTRACT CALCULATIONS OF PROTECTIVE RELAY SETTINGS FOR A UNIT GENERATOR FOLLOWING CATASTROPHIC FAILURE by Jaime Anthony Ybarra December2011 After a catastrophic failure of a unit generator system the major components may need to be replaced. Many times exact replacement of the failed or damaged components may not be possible. In such a case components with electrical characteristics as close to the original may be used. Therefore new protective relay settings must be calculated. In this thesis, we will examine a type of generator protection relays, evaluate new settings and develop a one-line diagram for a 25 MVA generator system. A methodology for the development of a safe and reliable protections scheme for a unit generator system is also presented. CALCULATIONS OF PROTECTIVE RELAY SETTINGS FOR A UNIT GENERATOR FOLLOWING CATASTROPHIC FAILURE A THESIS Presented to the Department of Electrical Engineering California State University, Long Beach In Partial Fulfillment of the Requirements for the Degree Master of Science in Electrical Engineering Committee Members: Hassan Mohamed-Nour, Ph.D (Chair) Mohammad Talebi, Ph.D. Hen-Geul (Henry) Yeh, Ph.D., P.E. College Designee: James Ary, Ph.D. By Jaime Anthony Ybarra B.S., 1999, California State University, Long Beach December 2011 UMI Number: 150766 All rghts reserve INFORMATION TO ALL USER The qualty of this reproduction is dependent on the quality of the copy su In the unlikely event that the author did not send a complete man and there are missing pages.O. Ml 48106-1 . United States C ProQuest LLC 789 East Eisenhower Parkws P. Box 134 Ann Arbor. Also. This edition of the work is protected a unauthorized copyng under Title 17. these will be noted. if material had to be a note will indicate the deleti UMI 150766 Copyright 2012 by ProQuest L All rghts reserved. 2.TABLE OF CONTENTS Page LIST OF TABLES LIST OF FIGURES CHAPTER 1. UNIT GENERATOR PROTECTION RELAYS Volt/Hertz relay (24) Synchronizing Check Relay (25) Under Voltage Relay (27) Directional Reverse Power Relay (32) Loss of Excitation (Field) Relay (40) Negative Sequence or Unbalance Relay (46) Stator Temperature Relay (49) Inadvertent Energization Protection Relay (50) Voltage Controlled Over Current Relay (51V) Over Voltage Relay (59) Voltage Balance Relay (60) Sudden Pressure Relay (63) Field Ground Relay (64F) Oil Level Relay (71) Out Of Step Relay (78) Frequency Relays (81) Lock Out Relay (86) iii 1 3 5 6 10 11 14 15 18 18 20 20 21 21 23 24 25 25 26 26 27 27 27 28 29 31 v vi . INTRODUCTION GENERATOR COMPONENTS AND PROTECTION SCHEME The Transformer Short Circuit Per Unit Quantities One Line Diagram Relay and Control Symbols Elementary Diagrams 3. 3 5 5 CONCLUSIONS 52 54 REFERENCES iv .CHAPTER Differential Relay (87) 4. SETTINGS CALCULATIONS AND EXPERIMENTAL RESULTS Preliminary Calculations Page 31 33 34 Typical Relay Settings Calculations and Verification with Experiment. B and C Phases Voltage Controlled Over Current Test Results Over Voltage Relay Test Result Relay Reverse and Forward Reach Z Test Results Relay Right Blinder Reach Z Test Result Left Blinder Reach Z Test Result Equipment Summary Table Relay Settings Summary Table 33 34 37 38 39 41 41 42 43 44 46 46 47 48 49 v .LIST OF TABLES Page Sample Generator Parameters Sample Unit Transformer Parameters Relay Volt/Hertz Experimental Test Result Under Voltage Test Result Reverse Power Test Result Zone 2 Test Result Loss of Excitation Zone 1 Reach Test Result Current Unbalance Pickups for A. LIST OF FIGURES Page Graphical representation of 3 phase power generation Basic structure of a cylindrical rotor Brushless excitation system Wye connected windings 3 Phase fault with DC component offset Short circuit waveform showing the three transient periods Typical electrical symbols Waveform output with polarities in phase Waveform output with polarities reversed Unit connected generator protection with typical relays Basic elementary diagram Various volts/hertz limit curves Generator. transformer and relay plot for volts/hertz relay plot 2 zone protection diagram Typical negative sequence relay curve Out of step protection zone Representation of differential protection 4 4 5 5 8 9 12 13 14 16 17 19 20 22 24 29 31 vi . 23. 21. 29. 25. 26. 28. B and C phases Voltage control relay (51C) results Voltage controlled relay (51C) RMS trip graph Over voltage relay (59) result plot Loss of Synchronization protection boundaries Forward reach results Reverse blinder result Right blinder result Left blinder result Sample system one line Page 36 37 38 39 40 40 41 42 43 44 44 45 45 46 46 46 50 vii . 34. 33. 24. 31.FIGURE 18. 30. 27. 32. Experimental setup RMS TIME vs VOLTS of volt/hertz relay (24) operation Under voltage (27) relay operation graph 3 phase vector diagram of reverse power relay (32) Zone reach impedance and phase angle relationship Loss of excitation zone 2 reach test Loss of excitation zone 1 reach test Unbalance A. 20. 22. 19. However. Calculate protective device settings based on new system. Develop or update electric system single line diagrams (one-lines) to describe the basic layout of the electrical system as well as basic information of the major components. The generator owner or user may have to purchase readably available equipment with capabilities as close as possible to original components. If any of these components are damaged beyond repair then they must be repaired or replaced. 3. Calculate the new capabilities of the generation system.CHAPTER 1 INTRODUCTION A generator system is designed to provide electric power to customers reliably. Verify that the relays will operate as programed or set with simulation of fault conditions inherent to that protective device. 1 . 2. 4. due to age and customized engineered system components exact replacements may not be available or the time for new components to be manufactured may not be economically viable. Failure of any electric component such as the generator. If this is the case new protective device settings must be calculated to properly protect the generation. In the event of the replacement of any of the components the following basic steps are recommended: 1. unit-transformer or auxiliary transformers can lead to catastrophic damage. 2 . Chapter 3 will describe protective relay types and functions. economical power to the customer as well as maintain a safe system for generator operation and maintenance personal. Chapter 2 will discuss generating system component and electrical fundamentals as well as the symbols used to describe an electrical system. Chapter 4 covers the calculation of the new protective relay settings and fault simulation testing of the protective functions with a 3 phase power simulator.The engineer in charge must produce a system that will provide reliable. This thesis is focused on recalculation of protective relay settings of a generator protection system with replacement components that do not have the same ratings or capabilities as the original and will require new protective relay settings calculations. This mechanical power may be derived from fossil fuels.CHAPTER 2 GENERATOR COMPONENTS AND PROTECTION SCHEME An electric generator is a device. In a 3 phase wye connected generator (see Figure 3) the 3 windings offset by 120 electrical degrees apart and share a common point referred to as the neutral. which converts mechanical energy into electrical energy (see Figure 1). The DC current may be derived externally and then transferred to the field windings on the rotor via brushes or the DC may be generated on the rotor itself by the addition a small permanent magnet AC generator and electronic circuits that will rectify the AC into DC for use for the field current (see Figure 3). The mechanical rotational motion is transferred via a shaft to the rotating portion of the generator. The prime mover provides the rotational mechanical power into the AC generator. The moving magnetic flux will induce voltage in the stationary portion of the generator referred to as the stator (see Figure 2) where the amount of flux being produced by the rotor is controlled by a device called the "Exciter" which controls the amount of current in the in the field windings. 3 . which is referred to as the rotor. nuclear or movement of water. The rotor will contain conductors of either copper or aluminum that will have a DC voltage applied and provides a current path that will set up a controlled magnetic flux these conductors are referred to as the field windings. Basic structure of a cylindrical rotor. 4 .The neutral may be solidly connected to the ground or connected through an impedance to ground that will limit the amount of current during a line to ground fault The voltage developed between windings is referred to as line to line voltage and voltage referenced to the grounded common connection is referred to as line to neutral voltage. Field windings Stator windings Stator Airgap Rotor FIGURE 2. Graphical representation of 3 phase power generation. Rotating Shaft 3-Phase Output t w Itel 3-Phase Electrical system w Prime Mover (Mechanical energy) DC Field Variable Source FIGURE 1. The Transformer A transformer allows the conversion of one voltage level to another voltage level. Wye connected windings.ROTATING ELEMENTS FIGURE 3. A higher voltage level allows for lower losses due to lower current levels for a given amount of power. A transformer consists of coils of copper or aluminum wrapped around a common core that readily conducts magnetic lines of force. Brushless excitation system [1]. Lower voltage levels in turn allow for higher currents to loads for the same given amount of power. Volts line to neutral A phase Volts line to line FIGURE 4. The 5 . Like a generator the transformer windings can be configured as a delta where there is no intention grounding of the conductors or in wye configuration that is configured such that each phase windings end point are connected together at a common point (see Figure 4). Short Circuit A power system is designed to be free of faults as much as possible through system design. equipment selection. Mathematically the relationship is expressed by the following equation. the voltages on the other phases will increase thereby stressing the insulation of the cables and equipment. Regardless of the cause a significant amount of current flows to the point of the fault.magnetic lines intersect each other within this core. moisture or inadvertent contact with conductive material. The advantage of a delta connected system is that if there were to be an inadvertent grounding of one of the phases only a small amount of current will flow and allow the system to stay online until it can be safely de-energized and repaired. However. NPVS= NPVS Where Np is the turns of conductor on the primary side Ns is the number of turns of conductor on the secondary side Vs is the voltage of the secondary side and Vp is the voltage on the primary side. However. At the fault location arcing 6 . This common point can be solidly connected to the ground or connected through impedance to ground to limit ground fault current. Some of these causes can be from insulation failure. installation and maintenance. even with these practices faults do occur. With a wye connected system the common point is referred to as the neutral. The system voltage levels will drop proportionally with the magnitude and distance to the point of the fault. During a 3 phase fault the current waveform will be offset by a DC component that shifts the sinusoidal waveform away from the horizontal axis (see Figure 5). The system impedance is taken from the point of the fault back to and including the source or sources of the fault current for the power system. The amount of DC offset depends on the X/R ratio which is the impedance divided by the resistance of the system. The "available" short circuit current is the maximum possible value of current that can occur at the location of the fault. The contribution to this maximum current comes from generators. These constants are derived by experiment or by analytical methods by the manufacture. A generator will have 3 short circuit constants inherent by design (see figure 6) that are used to set various protection elements. The basic short-circuit equation is shown below j _ "rms **system he ~~ ^ Where Isc is the short circuit current Vrms is the rms voltage and Zsystem ( or X ) is the equivalent system impedance (or reactance).and burning will occur as well as mechanical stress to the equipment. These constants are defined as follows 7 . synchronous and induction motors. 3 Phase fault with DC component offset [12]. 8 .Phase C DC Component FIGURE 5. 05 s after an applied fault [1]. v Y " d Transient reactance: Is the reactance of a generator between the subtransienl and synchronous states (see Figure 6.25s [1].). 9 . [ f\ ^*~ Subtransient Penod FIGURE 6. X& Direct axis: The steady-state reactance of a generator during fault conditions used to calculate the steady state fault current after the Subtransient and Transient components have decayed away (see Figure 6). Short circuit waveform showing the three transient periods [12]. The current decreases continuously during this period but are assumed to be steady at this value for approximately 0. This reactance is used for the calculation of the fault current during the period between the subtransient and steady state period (see Figure 6). The current continuously decreases lasting approximately 0.A"' d Subtransicnt reactance: Is the reactance of a generator at the initiation of a fault and is used in calculations of the initial asymmetrical fault current (see Figure 6). The other base values are then calculated from these two base values by the following equations: r _ _ MV ABase_3 phase V3 x kV.Per Unit Quantities A power system can be made up of various voltage levels there by making system calculations difficult. Once the base values have been established then the per-unit quantity of a value can be calculated with the following equation: Per Unit value = actual value base value Electrical components in a power system may have different per unit values based on its own ratings that differ from the chosen base. If this is the case they can be 10 . The two common base values chosen are voltage and power. Therefore. MVABase_3 phase is the chosen apparent power base and kVease_LL is the base line to line voltage For per phase quantities are required use line to neutral kV. to simplify calculations a common set of base values are selected and the remaining quantities are then scaled to these base values. BaseJLL 'Base 7 Base ^BaseLL MVA m v ^Base_3 phase Where ZBase is the base impedance in ohms. It is assumed unless indicated otherwise in the drawing that each device will have 3 units if they are single phase devices or 1 unit having 3 phase capabilities. . This is accomplished by taking the primary quantities and scaling it down by a known ratio. Each component is now displayed as a three phase device.converted into the chosen base per unit values. Since it is obvious that electro mechanical and electronic relays cannot directly operate at high voltages and current magnitudes they must be reduced to a magnitude that a relay can safely operate. but a circuit breaker will have 3 phase capabilities per each unit (See Table 1).kVBase =—) L x —— aw kVABasenew =— KvBasejiew ^^Base_old Whatever the value for the base voltage and MVA are chosen to be they will be designated as 1 per unit or 1 p. For example there will be one CT (current transformer) for each phase for a total of 3. A three-line diagram assists in the actual construction of power equipment. This will enable the builders of the system to interconnect the protection and other components.. j = Per unit impedanceoid n -J. The following equation will transform an old per unit impedance value into a new per unit impedance value: Per unit impedancenew ~ ... One Line Diagrams A one-line diagram graphically illustrates an electrical power system by representing a 3 phase system with single symbol components. 11 . u. The devices used to reduce the voltage and currents are referred to as potential transformers (PT) and current transformers (CT). • _i (— . Typical electrical symbols.© 3 phase generator uuuuuu nrrrm i T Medium voltage draw out circuit breaker Two winding transformer JIQ 3 phase disconnect switch with fuse Distribution bus Impedance ground with CT and resistor for ground fault detection r • • ( • ( 0 CT and PT symbols with reverse polarity Relay symbol where the " # " is replaced with the relay number CT and PT with polarity marks in phase A Y Open Delta and grounded Wye connections Delta connection and Wye connection © Circuit breaker close coil 0 Control path points to control device 0 Circuit breaker shunt trip coil Circuit breaker charging motor -QIndicating light 1 a±b T k Normally open and normally closed contacts FIGURE 7. 12 . If this is by design the dots will be reversed in the one line diagram (see Figure 8). 15 . Waveform output with polarities in phase. Both CT and PT have polarities. On a CT the current flowing into the polarity mark or HI will result in current flowing out of the secondary polarity mark or XI with little or no phase shift. 13 . The polarity of an instrument transformer indicates the phase relationship between the input and the output. Physically on a CT or PT the primary will be indicated by HI and H2 and XI and X2 for the secondary where HI and XI correspond to the dots in the one-line diagram. If the CT and PT are connected with their polarities reversed they would be indicated with the dots in the opposite side. Likewise for the PT (see Figure 7). A polarity mark as indicated by the dots in a one line diagram. I Pnmay current/voltage — « — Seconday current/voltage FIGURE 8.The symbols for current transformer (CT) and potential transformer (PT) also are referred to as Voltage Transformers (VT). A 180-degree phase shift will occur if the CT or PT secondary's are connected or installed in reverse. closes its alarm or trip contact a dashed line with arrows is often used to show the device that is activated. If ungrounded they may be connected as a delta or wye or if grounded they may be connected as an open delta or grounded wye. Placing these symbols on a one line and interconnecting the single line elements allows for the representation of any type of electrical system and is the standard method for the design of electrical systems.Pnmay current/voltage — — Set >nday c jrrer t/voltage 1 I 05 I ° 05 I 1 I I I " FIGURE 9. Note that open delta PT only 2 PTs are used with the secondary center phase grounded. 14 . Instrument transformers like power transformers may be connected in multiple ways depending on the application. Waveform output with polarities reversed. Relay and Control Symbols On a one line diagram a relay will be represented as a circle with the IEEE relay type number in the center (see Figure 7). The device that is activated when a relay operates that is. Note that these are contact not capacitors. A normally open contact or "a" has empty space between the lines and a normally closed contact or "b" contact has a line through it. The contacts from the various relays are also shown on Table 1.Elementary Diagrams In addition to a one line a control logic schematic must also be developed. This diagram is also referred to as an "Elementary Drawing ". Half the spring energy is used to close the circuit breaker and the other half is used to trip the circuit breaker. The Elementary Drawing shows the actual devices that are being activated. A red light is used to indicate the circuit breaker is closed and a green light indicates that the circuit breaker is open. The motor will recharge the springs after the trip operation. 15 . Two parallel lines represent contacts. That is. The motor is designated by the capital letter "M. When a signal to close is given a close coil (solenoid) is energized and closes the circuit breaker the same holds for the trip coil." Indicating lights on the switchgear panels are used to indicate the status of the circuit breaker. a DC bus will provide the power to either close a circuit breaker or trip it open and power the motor that will compress a spring. When the circuit breaker closes the state of the contact reverses. A circuit breaker opens and closes using stored energy in a compressed (charged) spring. When the circuit breaker is inserted secondary contacts in the switchgear make contact with power and control terminal in the cubicle and a motor in the circuit breaker charges the spring. These solenoids are referred to as close coils (CC) or trip coils (TC). The state as shown on elementary diagrams is when the circuit breaker is open. 9 "7T -idbN FIGURE 10. Unit connected generator protection with typical relays.->-$U<- UUUUUU Y rrrrm * (f i/ I <i—4>-—(0~» <HQ) <JU~4) (m) <s> ! $ Generator prime mover and field shut down controls. 16 . Shunt Tnp Coil Fuse M .Close Coil ST .+ Fuse A ~pLS Custoner CB close jI controls X CS ~~ C Relay protection CBtrip functions _L cs — T DC Control Power 0 ^ L A A © w C . Basic elementary diagram.Close T-Tnp C C .Spring Charging Motor LS . contact will open and shut motor when spring charged CS . .Limit Switch.CB Control Switch FIGURE 11. However. They are designed in such a way as provide the necessary flux for their rated load. Each type of relay will protect the system from a particular type of abnormality. but the stability of the system. Volt/Hertz Relay (24) An internal magnetic field is required by generators and transformers in order to operate. The following sections will describe the typical types of relays used in generator protection.CHAPTER 3 UNIT GENERATOR PROTECTION RELAYS A wide variety of relays are required to protect a generator system. with the advent of microprocessor based relays many fiinctions if not all are incorporated into one unit. This many relays are required due to the large capital investment of not only the generator and transformer. 18 . Over excitation occurs when abnormally high flux saturates the core steal and the excess flux flows into the portions of the stator that were not designed to handle this flux. Not all relays are used in every instance. If electro-mechanical relays are used it may require up to 3 relays of a single type to protect each phase of a 3 phase system. but a thorough review is necessary to allow the protection engineer to decide if the application warrants the inclusion of a certain protective function. 19 .• 001 H 0 1 1 10 1 10 1 100 1 1000 I 0 01 j 0 1 1 10 1 10 1 100 1 1000 I 0 01 1 0 1 1 10 1 10 1 100 1 1000 TIME (MINUTES) TIME (MINUTES) f » V l — P R O H I B I T E D REGION TIME (MINUTES) Figure 12. This excess heat will degrade lamination and winding insulation leading to equipment failure. Generator voltage regulators may also monitor and protect against over excitation and the 24 relay in this case would act as a backup or alarm relay.• 120-• o no-100. A similar transformer curve can be obtained and the relay set to protect both (see Figure 12). Since the voltage is a function of flux times speed the voltage regulator may attempt to increase the field current an attempt to maintain rated output voltage. A transformer is also susceptible to volts/hertz problems. A sample of limit curves are shown in Figure 11 below MFC 1 GENERATOR MFG 2 GENERATOR MFG 3 GENERATOR 150-- £ £ 130. To develop 24 relay settings the generator manufacture over excitation limit curves should be obtained.This flux in the unintended areas will create high circulating eddy currents which will in turn generate large amounts of heat. An example of when over excitation may occur is when a generator is started and has not come up to full speed and due to a voltage regulator malfunction or human error the field is applied. Various volts/hertz limit curves [1]. 01 TIME (MINUTES) FIGURE 13. 067 Hz. large currents will flow through the systems which can exceed those experienced during sudden short circuits.130- t 120- RELAY CHARACTERISTIC too. This action in a generation system is the closing of a circuit breaker thereby bringing the generator into parallel with the electrical system. Synchronizing Check Relay (25) A 25 sync check relay is used to check whether or not two separate portions of a system are of similar phasor quantities such as phase. Under Voltage Relay (27) The under voltage relay operates when the voltage applied drops below a predetermined value. frequency and magnitude and are within predetermined thresholds. Under voltage relays may have inverse time characteristics so that 20 . If and when the electrical differences between the two systems satisfy the threshold conditions an action may be taken. Typical limits are circuit breaker closing angle of ±10°. transformer and relay plot for volts/hertz relay plot [1]. If two electrical systems were brought together and if they are significantly different. Synchronizing limits that the two systems must be with specified limits in order to safely parallel. generator side voltage relative to system 0% to +5% and frequency differences of ±0. Generator. The intense currents and torques produced may cause server damages to the generator stator which may require it to be rewound. For paralleling a generator and distribution bus the 27 under voltage functions is incorporated into the 25 relay. Common causes of excitation loss can be operator error. line to line voltage. compressors. Transient reactance X'd. A type of 40 relay is called an offset MHO relay. Where R is the resistance 21 . Heavy currents will also be induced into the rotor teeth and wedges which will cause thermal damage to the generator if allowed to operate in this condition. excitation system failure. As a result it will draw reactive power from the system instead of providing it to the system.. accidental tripping of the field breakers or flashover of the exciter commutator. couplings. This will drive the prime mover and possibly damaging its shaft.the system may have time to stabilize before any trips or alarms are initiated or they may have definite level thresholds. The manufacture will often provide the reverse power threshold in primary watts and the amount of time the generator can "motor" before it is damaged. Directional Reverse power Relay (32) If a generator loses its prime mover it will go into a condition called "Motoring" which as the word implies the generator will now be powered by the external system and the generator will act as a synchronous motor.etcetera. and rated phase current. The manufacture provides the magnitude of reverse power that the generator system can withstand before damage occurs. all in secondary values. The protection characteristics are plot on the R-X plane. A 32 relay will also contain an adjustable time delay to allow short duration power variations to stabilize. Loss of Excitation (Field) Relay (40) Loss of excitation on a synchronous generator will cause the rotor to accelerate and operate as an induction generator. . The following information will be required from the manufacture to set the protection level: the generator direct axis reactance Xd. -j I ( v^j Dl/ METER » 1 Opu \ -2 v -X J 1 DIAMETER "X. 2 zone protection diagram [1].and X is the reactance of the system (see Figure 30). -1 2 FIGURE 14. 0 pu of impedance Z. The inner circle referred to as Zone 1 will trip the system offline and the outer circle referred to as Zone 2 will alarm before tripping the system offline.5 seconds for Zone 2 are suggested. The following equations are used to calculate the diameters and offsets..1 seconds for Zone 1 and . Time delays are of . 05 R -R « OFFSET " 2 . The offset of the inner and outer circle X is the negative quantity of the half the transient reactance. The diameter of the outer circle is equal to the direct access transient with the offset being equal to that of the Zone 1 offset. Zone 1 (inner circle) is commonly set to 1. Note that these values are in primary quantities and must be converted into relay base for used with the protection equipment. Note that values must be secondary ohms for use in the relay. 22 . IEEE standards dictate that all generators meet a negative sequence withstand capabilities [5]. where K= I2t and varies from 5 to 40. Two limits are used for 46 relay protection settings the Continues Negative-Sequence current capability limit and the Short Time Unbalance current limit.Negative Sequence or Unbalance Relay (46) Negative sequence stator currents. For generators continues negative-sequence limits range from 5 and 10% of rated current. 23 . These limits will be used to set the relay pickup values. The most serious series unbalance for example is an open phase. phase-to-ground. The short time limit is expressed in terms of K. due to a failed circuit breaker pole. The relay will have a time delay function to allow downstream circuit breakers to clear the portion of the system that is causing negative sequence currents. The actual values will be provided by the generator manufacture. Typical curves (see Figure 15) provide the protection engineer relay pickup and delay characteristics to coordinate trip functions of protection down the line. induce double frequency currents into the rotor that may eventually overheat elements not designed to be subjected to such currents as a result of the 11 losses. caused by unbalanced faults such as phase-tophase. double-line-to-ground or load unbalance. PER UNIT l2 FIGURE 15. Typical negative sequence relay curve [1]. Two pickup settings are commonly programmed into a temperature relay. 24 . These detectors called "RTD" can be made of platinum. The second higher threshold will trip the system in order to prevent thermal damage to the generator. copper or nickel. Stator Temperature Relay (49) Temperature Relay supplies a constant current to a remotely located resistive temperature detector usually installed in the windings. and senses the temperature of the detector by measuring the voltage across the resistive element. a lower threshold will alarm without shutting down the system to allow corrective action. A 27 under-voltage relay. The energized generator will act as an induction motor and rapidly accelerate which can cause extensive damage if the generator is not de-energized immediately. The basic operation of the relay is such that the pickup of the over-current unit is not activated until there is a voltage drop due to a short circuit out in the system. When the generator is de-energized the 27 under-voltage and 81 under frequency relays contacts will be closed thereby enabling the 50 instantaneous to operate if current is detected. Voltage Controlled Over Current Relay (51V) Voltage Controlled Over-Current relay is used to provide protection against a prolonged fault contribution by the generator. The further the fault is from the generator the lower the magnitude of the voltage drop. A timing device is also used with this scheme. 25 . For inadvertent energization protection 3 types of relays and a timing device are used in tandem. It will inhibit the operation of the 50 for a period of time so that it will not operate if there are short term instabilities in voltage or frequency levels and arm the 50 relay when the generator is taken out of service.Inadvertent Energization Protection Relay (50) Inadvertent energization of a generator can result from a circuit breaker flashover or a breaker that has closed onto an energized system while the generator is at standstill or rotating at slow speeds. a 81U under-frequency relay and a 50 instantaneous over-current relay. if one or more PT fuses providing signal to the voltage regulator fails and the 60 relay detects that the 2nd set of PT remain energized it can disable the voltage regulator. Under normal conditions all three phase PT output magnitudes are equal. If the voltage regulator sensed no voltage it may boost the field current in an attempt to maintain voltage thereby creating an over excitation condition. Typical settings for the overcurrent unit is 50% of the full load current if the activation voltage level is 75% of the rated voltage. As an example. Over Voltage Relay (59) The over voltage relay is used to senses above normal voltage magnitude. Another important use of an over voltage relay is for ground fault protection in impedance grounded generators. An impedance which may be a resistor or a step down transformer with the primary of the transformer in series with the neutral and the resistor across the secondary so that a flowing current through the resistor will develop a voltage which will be detected by the 59 relay. 26 .The relay received its input from potential transformers and works in conjunction with the 60 relay. If a 60 relay detects a blown fuse it will block the operation of the 51V relay due to voltage input being lost due to the blown fuse. Two sets of PT are used to implement this relay. Voltage Balance Relay (60) A voltage balance relay protects the power system from miss operation or false tripping in the event that a fuse blows in the voltage sensing circuit. An alarm is used after the 60 relay has operated to inform generator operators of a blown fuse. If a fuse is blown the relay compares the two inputs and if only one of the inputs has lost potential then other protective or control functions can be blocked or disabled. A time delay is employed in order to prevent unintentional operation due to short duration field transients. there is a greater chance of a second ground fault occurring after the first. Field Ground Relay (64F) The field circuit is normally ungrounded. The unbalance currents also produce heating in the rotor iron resulting in unbalanced temperatures that may also lead to damaging vibrations. The 63 is set to immediately remove power from the transformer by tripping the main circuit breaker and de-energizing the generator. However. The consequence of this is unbalanced air gap fluxes in the machine the unbalanced magnetic forces produced by the unbalanced fluxed can result in severe vibration leading to machine damage. If that were to occur that portion of the field winding will be short circuited. A single ground generally will not affect the generator operation nor may there be any immediate damage. If that level is exceeded then the main circuit breaker may be tripped and the generator taken offline. A ground in the field will cause the relay to operate. 27 . The relay is designed such that slow changes in pressure do to normal loading and oil expansion are not detected.Sudden Pressure Relay (63) A sudden pressure relay is a high speed device that detects a sudden increase in pressure within a transformer. The relay operates by placing a dc voltage source in series with an over-voltage relay connected between the negative side of the field winding and ground. As the oil level gets lower an alarm threshold may be set to alert plant personal. Oil Level Relay (71) The 71 oil level relay used a floatation device inside the transformer to detect the amount of oil inside the tank. diameter D = (2xX'd+ 1. If a system stability study is not available then conservative values for the settings should be used.Out Of Step Relay (78) In the event that fault or other disturbances causes a generator to loose synchronism with the power system it is imperative that if the generator does lose synchronism it be immediately separated from the system. the step up transformer impedance in secondary ohms and the impedance of the lines beyond the generator set-up transformer. These high currents and of-frequency operation lead to winding stress. The information need to calculate settings are the generator transient reactance in secondary ohms. All impedances must be in the generator base KV. If the generator is not separated prior to exceeding the manufactures tolerances the generator may be severely damaged resulting from high peak currents and off-frequency operation.£) Where d is the blinder distance (see Figure 33). The relay operates from voltage and current derived from voltage and current transformers. The diameter of the MHO unit is calculated. pulsating torques and mechanical resonances are damaging to the generator. 5x XTG) 28 . d = P* + X ™ + X>y"™\ x tan(90 . In this case set 5 = 120 . which will mostly be significant when an under frequency condition exists. Out of step protection zone. Under Frequency Relay (81U) At lower frequencies than 60 Hz the generator and its prime mover will begin to slow down as they attempt to carry the excess load. The diameter above does not contain Xsystem since in our sample system since we assume no system data or stability data exists.Uttsttfitt FIGURE 16. The relay will trip when the relay detects the impedance between the blinders and inside the circle. The reduced rotation also leads to 29 . Frequency Relays (81) The two main considerations with the operation of synchronous generators outside standard frequency ranges are: (1) rapid aging of the mechanical components during both under frequency and over frequency operation and (2) thermal considerations. When a protective relay activates the 86 lock out relay the changes contact states can be used to trip main circuit breakers. 30 . activate alarms systems. Over Frequency Relay (810) Is commonly the result of a sudden reduction in load.reduced ventilation thereby a reduction in power output. The external portion of the 86 relay consists of a handle which when tripped will rotate indicating a trip has occurred. However. Lock Out Relay (86) A 86 relay is not a protective device in its self but an auxiliary relay when it's desired that a number of operations be performed simultaneously from the operation of a single relay. The relays will have thresholds at which they can alarm for a set level and trip if a second threshold is exceeded. A time delay is also included at to give the system to stabilize before the generator is separated from the system. etcetera. field circuit breakers. generator turbines are designed to operate near 60 Hz outside the designed limit may produce destructive resonance in the rotating mechanical components. the 86 lock out relay internally contains multiple contacts what can be either normally open or normally closed and will change state when a protective device activates the 86. The lower frequency can also lead to over excitation since the flux is inversely proportional to the frequency. The protection engineer can specify the function of the 86 relay when the protection scheme is developed. In other words. During over frequency operation there is an improvement in ventilation and the flux density needed for a given terminal voltage is less and therefore does not produce the same heating as does an under frequency condition. 31 . core as well as producing severe mechanical torsional stress to shafts and couplings. Representation of differential protection. Under normal load conditions. If the fault occurs inside the zone that is between the two CTs the relay will operate and quickly trip the generator circuit breaker and field circuit breaker and deenergize the generator. except settings "taps" are included to compensate for transformer ratio differences between the primary and secondary and harmonic restrain to allow for inrush currents during energization. The output currents from the current transformers are connected such that they are offset by 180 degrees and cancel each other out so that the net resultant current is nearly 0. Differential Relay (87) Internal generator faults are considered serious since they cause severe costly damage to insulation windings. On transformers that are delta to wye or wye delta there is an inherent 30 degree phase shift. If a fault should occur outside the protection zone the relay will not operate. FIGURE 17. current flows through the protected equipment.While the relay is in the trip position the system will be "locked out" meaning that the circuit breakers cannot be closed until the relay is reset. Transformer differential relays operate on the same principle. The slope of the relay will be the sum of the errors induced by the CT ratio mismatch. Another use of differential protection is in Unit Protection configuration. In setting the taps the delta wired CTs secondary currents muct be multiplied by 1. Unit protection is implemented using microprocessor relays.73 to allow for the delta line currents. In this setup the generator step up transformer and service station transformer are included in the protection zone. 32 . CT errors and voltage level differences.To offset this the CT are configured in the opposite of the winding they are protecting. The difference in current in verses current out must exceed a set percentage difference in order to operate. That is a wye winding will have delta wired CTs and a delta winding will have wye connected CTs. The errors will allow you to select the proper slope of the relay. 85 14.15 0. TABLE 1.196 0.129 14400 120 120 1200 5 240 MVA Pf KV A pu pu pu pu V V A A 33 .4 1002 1.CHAPTER 4 SETTINGS CALCULATIONS AND EXPERIMENTS The following example will calculate the protection settings for 25MVA connected to a 30MVA replacement transformer in a Unit Generator configuration. The generator and associated equipment parameters are listed on Table 2. Sample Generator Parameters Generator Output Power factor Voltage Full Load Current (FLA) Direct axis synchronous reactance: Direct axis transient reactance: Direct axis subtransient reactance: Negative sequence reactance: Potential Transformers (PT) Xd= X'd= X"d= X2= Primary Secondary PT Ratio Primary Secondary CT Ratio = Current Transformers (CT) = 25 0.136 0. 80 36 0. The voltage and power of the generator will be used as the base quantities. 34 . Sample Unit Transformer Parameters Unit Transformer Power Windings Primary Voltage Secondary Voltage Leakage Reactance or impedance in pu Nameplate Impedance on 30 MVA Base FLA (Primary) FLA (Secondary) Primary Primary side CT Secondary Ratio Secondary side CT Primary Secondary 30 2 13.The Unit connected transformer parameters for our sample system are show in Table 2 TABLE 2.400K or 14 AkV MVABaseG = 2SMVA Using the values from Table 2 the transformer impedance is converted into the generator base. VBase_LL_G = 14.08 8 1.255 481 1500 5 300 600 5 MVA kV kV pu % A A A A A A Preliminary Calculations The relay setting calculations can be simplified if the generator and transformer parameters are first changed to a common base and converted to secondary PT and CT values what will be used. Those that do not require calculations will reference a figure for the corresponding setting. Schweitzer Engineering Laboratories SEL-700G protective generator relay and 3-phase power system simulator Megger MPRT Relay Tester.4007 _ T^Tjj — 69.4007 _ ^BaseJLL relay — 7 ^ — 1207 ^BaseJLNrelay — ~J=X 1 14. The following are the calculations for relays settings. The experimental verification setup (Figure 17) consists of a waveform and RMS capture device Dranetz Power Xploer PX-5. 2 8 7 - l _ 1002.287_ ^Base relay ~~ A * JCA "~" ^ Typical Relay Settings Calculations and Verification with Experiment. currents and impedances into the relay base _ 14.4fcl/ L 2 LBa5e _ 2 5 MVAcjase *Base_Primary_G ~ * ZV * " Since relay settings are based on the secondary magnitudes of the CT and PTs convert the Voltages. Calculate the generator base impedance ZBase_primary_G 7 _14.30 MVA 13.4 _ Base relay "" 2 40 ~~ _69.8kV? Where XBasejrc is the transformer on the generator MVA and Voltage base. 0 will be used to control the 3-phase simulator as well as vary the phase angles and record the results. 35 . The simulator software Megger AVTS 4. 28V x L 05 = 72. 36 . Over excitation Relay (24): The generator and transformer manufacture provided curves are used to set this relay. The theoretical voltage level is calculated by multiplying the line to neutral voltage by the percentage above the nominal voltage. Figure 34 shows the RMS values of the voltage as the relay trips the system offline. 1.The Dranetz Inc9 DRAN-VIEW 6 Software is used to record wave forms and phase angle vectors. FIGURE 18. That is 69. In our sample the over excitation trip point 105% will be tested by holding the frequency constantan and increasing the voltage. 74V. Experimental setup. 9 x 69. 37 .28 V = 62.75 Error (%) -0. 1 -^- 1 24 Relay trip at 72.Table 4 shows the tabulated results. Set the trip level at 90% of the line to neutral voltage. RMS TIME vs VOLTS of volts/hertz relay (24) operation.7 Volts ~] TIME FIGURE 19.72 ExpectedPU (Volts) 72.02 MaxRange (Volts) 73. Relay Volt/Hertz Experimental Test Result Pickup (Volts) 72.4V (see Figure 34) and the numerical results in Table 4. TABLE 3.47 Pass/Fail Pass 2. .35V or approximately 62. Under Voltage Relay (27): Use definite time function. The calculation is as follows.03 MinRange (Volts) 72. TABLE 4.85 pf = 0.62 Pass/Fail Pass 3.20 Expected PU (Volts) 62. Calculate the value in MW of the allowable reverse power.4kV = 17.02 x 25 MVA x 0.40 Error (%) -0. The calculation is as follows: .425MW Primary_reverse_power V3 14. FIGURE 20.32 Min Range (Volts) 59.4250 MW For relaying purposes the pickup up value must be in secondary quantities and the equivalent MVA value. 0. Reverse Power Relay (32): The prime movers manufacture provided the motoring power of 2% and can withstand for 50 seconds. Under Voltage Test Result Pickup (Volts) 62. Under voltage relay (27) operation graph.18 Max Range (Volts) 65.Vertical edge indicates relay has tripped.04 A 38 . 851 ExpectedPU 21. 59 Q negative since it is a negative offset MHO relay.580 21. The results shown on Table 5.196 0.04A "" JA() =.0 Error -0.071A Since our relay detects the total power.098 pu 39 . *^« 110* 2te* FIGURE 21. multiply the result by 3. 3 phase vector diagram of a reverse power relay (32).<\ * * j *'.21 A. Zone 1: Set the Mho circle at 1 pu. Loss of Field Relay (40): Calculate the protective zones. Values must be scaled to CT and PT secondary values.> 0 i „• JLMIIJJ tatf-M * * "AT 0 ***** iiLmmmt « * V ***<< s >* m* BV ^ MilP' 2T0 € t*0* V A iP*mm B A :\y C 1H« il ** %?r .To convert the primary value into secondary quantities divide the base current value the CT ratio. Zone 1 offset Xd 2 = 0. The current required will be . c« » * *. Where 1 pu is equal to Zease_reiay Zone 1 diameter = 1 pu = -16. 1 U Secondary_reverse_power 17. Reverse Power Test Result Pickup 20. TABLE 5. .420 Pass/Fail Pass 4. The currents are rotated 180 degrees (Figure 20) to simulate current flow into the generator.71 MinRange MaxRang e 20. 816 A 30. Loss of excitation zone 2 reach test.The offset needs to be converted into the relay base by multiplying it by Zfiasejeiay and changing the sign since the relay is a negative offset MHO relay.215 V f [ Current A 1 3.282 V 0. 59 | = 19.816 A 150. 07 O or 19. 28/1 19.000 Hz [' 60. 62 O The experimental results are calculated as follows.28V the impedance Z if calculated as follows I = V/Z. Zone 1 offset (relay) = . 59 = . The zone reach test values are calculated by holding the voltage constant and vary the current magnitude at the phase angles indicated in Figure 21.0 * j 60.0° f mmv I 120. 10 + 1. 62|) = 3.1. The reach is calculated by adding the offset and the zone diameter to get the zone reach. The experimental results are below. 59 + 1. 15 x 16.1 . 34A z* r "„ ^JzJL FIGURE 22.000 HE FIGURE 23.000 Hi f 60.0. 62|) = 3.59 O Zone 2 diameter (relay) = | .0 * SOSOHZ | """ 240.000 Hz 3. Zone reach impedance and phase angle relationship. Voltage A | f f | 89. 62 Q Zone 1 diameter Zeasejeiay = 16.816 A 270. 8A For Zone 1 Reach I = (69.6 * | 60. 40 . For Zone 2 Reach I = (69.1.0 8 Current B 1 F" f [ Current C I P J * 3. 28V/| 16.0 * SuioHz VottageB j Voltage C J [ 69. 098 x 16. 1 Zone 2 offset (relay) = Zone 1 offset (relay) = . With the voltage held constant at 69. TABLE 6. Zone 2 Test Result Impedance (Ohms) 20. 705 CalcZ (Ohms) 20.70 Error (%) 0.02 MinRange (Ohms) 19.66 MaxRange (Ohms) 21,73 Pass/Fail Pass Voltage A j Voltage B J Voltage C J Current A J Current B I I Current C p___ !____ j_™^__ p___ p——^ ^^—^ j _ _ ^ _ | , __ ^——— j p _ _ _ p__p ^___ FIGURE 24. Loss of excitation zone 1 reach test. TABLE 7. Loss of Excitation Zone 1 Reach Test Result Impedance (Ohms) 18.250 CalcZ (Ohms) 18.20 Error (%) 0.27 MinRange (Ohms) 17.29 MaxRange (Ohms) 19. 11 Pass/Fail Pass TestVolts (Volts) 69.28 5. Unbalance relay (46): The manufacture will design the generator in accordance with IEEE standards. For our example the manufacture has provided us with the following information: Pickup: 7% Time dial (K): = 9 with a linear reset of 4 minutes. The expected results are calculated by taking 7% or the full load amps which is 4.2A so that I = ,07 x 4.2A = . 94A but since we are testing 1 phase at a time while the other 2 phases are held at zero we must multiply by 3. Therefore the expected test current is .294 x 3 = .882A. The results are shown graphically in Figure 25, Note that figure 25 has all three phases superimposed on same graph. The first plot A-phase the current was held 41 constant then raised above the threshold before trip. Phases B and C the current is ramped up to trip, Note 1 phase lower than 2 other phases FIGURE 25. Unbalance A9 B and C phases. TABLE 8. Relay Current Unbalance Pickups for A9 B and C Phases PickupCurrent A PHASE (Amps) 0.90 PickupCurrent B PHASE (Amps) 0.91 PickupCurrent C PHASE (Amps) 0.91 CalcPickup A PHASE (Amps) 0.88 CalcPickup B PHASE (Amps) 0 88 CalcPickup C PHASE (Amps) 0.88 MinRange A PHASE (Amps) 0.84 MinRange B PHASE (Amps) 0.84 MinRange C PHASE (Amps) 0 84 MaxRange A PHASE (Amps) 0.93 MaxRange B PHASE (Amps) 0.93 MaxRange C PHASE (Amps) 0 93 Error A PHASE (%) 2.46 Error B PHASE (%) 3.54 Error C PHASE (%) 3.60 Pass/Fail Pass Pass Pass 6. Voltage controlled relay (51C): Set relay to pickup up the voltage control unit at 75% of rated voltage and the overcurrent pickup at 50% of the generator full-load current. 51C OC pickup = 4. 18 x . 50 - 2. 09A 51C undervoltage element pickup = 69. 28 * . 75 = 52V 42 Time Vs Current Multiples of Ptctajp FIGURE 26. Voltage control relay (51C) results. TABLE 9. Voltage Controlled Over Current Test Results Multiplier Applied ExpectedJTime Error MinRange Time (Seconds) (Amps) (Seconds) (Seconds) (X Pickup) (%) 6.00 3.7197 0.91 3.7539 3.55 3. 0000 10.00 0. 19 5. 0000 1.3598 1.3573 1.28 14.00 0, 7666 0.71 0. 7620 7. 0000 -0.61 MaxRange (Seconds) 3.89 1.44 0.82 Pass/Fail Pass Pass Pass Note that OC unit does not occur until voltage drops, FIGURE 27, Voltage controlled relay (51C) RMS trip graph, 43 Over Voltage Relay (59): For our experiment set the over voltage threshold to 110% of the nominal line to neutral voltage. Over Voltage Relay Test Result Pickup (Volts) 76. Over voltage relay (59) result plot. 23 fl or 1.70 ExpectedPU (Volts) 76. 5 = 10. 03 Q with impedance angle of 90 . a.02 Pass/Fail Pass 8. 2V Figure 28. 25 + 1. 28/6. 28= 1. 25 + 1.10 x 69. and a time delay of 50 ms> Theforwardreach (lower circle portion) is2x3 s 25 :=:: 6 s 5 and the reverse reach is L 5 x 1. 5 x 1. 02) = 8. TABLE 10. For our example the Xsystem = 00 with p = 90 and 8 = 120 with the assumption that no stability studies are available and there is no information on the system. 28 = 76. d (blinder distance) = (3.64 MinRange (Volts) 72. 65A 44 . 53 for our experiment use 1. MHO unit diameter = (2 x 3. 02 + 0)/2 x tan(30) = 1. 02 = 1. Loss of synchronization relay (78). 5 Again using the fact that I = Volts/Z we calculate thefollowingvalues.40 IVfaxRange (Volts) 80. 2fortests.7. 10 x 69. Forward reach current I = 69. 1.21 Error 0. 270 FIGURE 29.0 7§ Right Blinder 9. 5 = 13. Reverse reach current I = 69. 67A The protection zone are bound by these values (see Figure 29). Since we are interested in the current and the impedance is fixed we can use a lower voltage to calculate a suitable I.. Right Blinder the current phases are rotated as to allow the impedance vector approach from right to left as in b above 20V/1.b. Reverse and forward reach experimental results.o f6 i Left Blinder Relay will trip Forward reach ~ — —J inside circle and inside left and right Blinder lines._ "^< ***** . 28/1..2 = 16.000V* f"""" 240.2=16.0 _JV . 19A note that this is exceeds typical 3 phase test equipment. Loss of Synchronization protection boundaries.0 7. Left Blinder the current phases are rotated to allow the impedance to approach from left to right I is 20V/1. Forward reach results. Voltage A j [ Voltage B j 20.. Use 20V and calculate I. 3A c. 90 Reverse reach 180 11 0 9. 5 = 46. 20V/1. 45 .0 110 s.0 r Voltage c j Cur rent A j | Current B | 13J?? A Current C I f ™ blF* f nJffK [ mor [^SOOOHT pESoW FIGURE 30. 67A d. 37? A [ [ "™5S5So'v | p ™ l o ^ v " f" o.612 A 300.50 IdealJZJWD (Ohms) 6.012 A f [ | ISJUA 00. Left blinder result.00 ZJ78R1 (Ohms) 1. TABLE 12. Relay Reverse and Forward Reach Z Test Results Volts (Volts) 20.or P'OSOOOHZ"* [ lo~OQOHz" 6 0 .00 Current (Amps) 16.27 Voltage A 1 | 20.712A Current C 1 240.ooo Hz pgo^SflMHT 60. Re¥erse reach results.o* i [ H^oX 0 1337? A" j *""* 13.377 A [~"T£o v 210. TABLE 11.20 IdeaLZ (Ohms) 1.000 Hz FIGURE 32.500 -0.69 Angle (Degrees) 90. W Hz FIGURE 31.0 * ["~5bo.00 Current (Amps) 13.50 Z^FWD (Ohms) 6.712 A I Current B 16. Relay Right Blinder Reach Z Test Result Volts (Volts) 20.38 Current (Amps) 10.000 V VoftageBJ r 20. 46 .000 Hz m j 00.0 * 60.20 %error -0.Voltage A 1 J Voltage e l Voltage C J f Current A - Current B j Current € 13.26 %error -0.000 Hz tsar psbSoo HT FIGURE 33.000 V f Current A Current 8 I | [ 16.6 * 60.00 Angle (Degrees) 270. 00 ZJREV (Ohms) 1.000 Hz r'^oooHir m I 1*0.0 j 60.00 Volts (Volts) 20.483 Ideal Z REV (Ohms) 1. Relay right blinder result.33 VoltageAj Voltage B j Votlage C J Current A 16.000 Hz 0 0.71 Angle (Degrees) 0.000 V j Voltage C I 20.0 * Current C 10.0« oo.000 Hz | | 0. 47 . Only settings that required calculations are on Table 14. Note that all CT ratios are based on 5A secondary and PT are based on 120V secondary.20 ldeal_Z (Ohms) 1.00 Current (Amps) 16. 00 Z_78R2 (Ohms) 1.33 The settings results can then be summarized on a table which can be provided to the personnel programing and setting the relays.20 %error 0. Settings that require curve selection and not included.TABLE 13.61 Angle (Degrees) 180. Left Blinder Reach Z Test Result Volts (Volts) 20. TABLE 14.136 .85 120:1 Y 240:1 240:1 60:1 25Q 30.15 .40 .0 8% 1255 481 300:1 120:1 Solid 3 14.196 . Equipment Summary Table Generator Data MVA Xd X'd X"d X2 Voltage ( k V ) Power Factor (pf) PT Ratio PT Configuration D/Y CT Ratio Generator Differential CT Ratio Unit Differential Generator Grounding transformer ratio Grounding transformer resistor Unit Step up Transformer Data MVA Primary Voltage ( kV ) (adjust tap for +4%) Secondary Voltage ( kV ) Transformer nameplate impedance Primary Full Load Amps Secondary Full Load Amps CT Ratio Phase Primary CT Ratio Phase Secondary Grounding method Auxiliary Transformer Data MVA Primary Voltage (kV ) Secondary Voltage (kV ) Nameplate impedance CT Ratio Primary CT Ration Secondary Grounding method 25 1.8 36.4 .129 14.480 5% 25:1 800:1 Solid 48 .0 13. 62ft 7%. Relay Settings Summary Table Relay Function 25 Over Excitation 27 Under Voltage Trip 32 Reverse Power 40 Loss of Field (Negative offset MHO) Zone 1 Diameter Zone 1 Offset Zone 2 Diameter Zone 2 Offset 46 Current Unbalance Relay 51V Voltage controlled Over Current Relay 59 Over Voltage Trip 78 Loss of Synch Relay Left and right binders MHO diameter Forward reach Reverse reach Pickup 105% 62.03ft 6.5 ft Delay 2 seconds 50 seconds 4 minute linear reset Inverse time curve 10 seconds 50 milliseconds 49 .5 ft 1.07 ft -1.2V 1.09A @ 52V 76.4V .59ft -1.TABLE 15.2ft 8.62ft 19.21A@120V 16. K=9 2. 36KV. Sample system one-line.8KV-480V FIGURE 34. 600A O GFCT ( ) * j ' ' I* 13. . characteristic of short circuits and the variables that are used to express how the magnitudes will manifest during a fault are important for the engineer to understand prior to integrating replacement electrical components into the repaired system. In order to develop settings for relays that will be protecting replacement components that may not have the same electrical characteristics. Due to either obsolescence or long delivery time exact replacements may not be available therefore recalculations and verification of new relay settings are necessary. 51 . In order to achieve the highest reliability the new system should be based on available standards and the consequences of omitting a protective relay must be carefully evaluated. 2. transformer. The following conclusions are drawn from the presented study. An AC generator system that has experienced catastrophic failure may have one or more major components repaired or replaced. magnitude sensing devices and there unique functions are necessary. Basic knowledge of generators. thorough familiarity with the protective relays. 1. 3.CHAPTER 5 CONCLUSIONS A procedure for protective relay settings for a 25MVA generator has been presented. transformers and circuit breaker system. 8. develop or update one-line diagrams which will represent the generator. 5.4. Once electrical and control diagrams have been developed calculations to convert primary quantities into secondary quantities are performed to set all relays. Once replacement components have been obtained and installed. 52 . 7. This procedure may be applied to a unit configured AC generator. In order to reduce the chance of settings errors all electrical information needs to be gathered and documented prior to placing the generation system back online. 6. Prior to a generator system being place back into service. A 3 phase power systems simulator is used to verity the proper operation of the protective relays and all results documented. REFERENCES 53 . "IEEE Standards Dictionary: Glossary of Terms & Definitions. "IEEE guide for AC generator protection." New York. FL: CRC Press. Protective Relaying for Power Generation Systems." IEEE Std. NC: ABB Power T&D Company Inc. 242-1986) [IEEE Buff Book]. 142-2007 (Revision of IEEE Std.IEEE Std. 2008 IEEE Power & Energy Society. Boca Raton." IEEE Std. "IEEE standard for electrical power system device function numbers. " IEEE guide for generator ground protection. C37. IEEE Power & Energy Society.REFERENCES [I] IEEE Power & Energy Society. "IEEE recommended practice for protection and coordination of industrial and commercial power systems. IEEE Power & Energy Society. 1997. 13-2005. ABB Power T&D Company Inc. C50." IEEE Std. 2007.". 142-1991). "IEEE standard for cylindrical-rotor 50 Hz and 60 Hz synchronous generators rated 10 MVA and above.2. Electrical Transmission and Distribution Reference Book. IEEE Power & Energy Society.102-1995). C37. "IEEE guide for abnormal frequency protection for power generating plants. and contact designations. 2004." IEEE Std. Donald Reimert. C37.101-2006. IEEE Power & Energy Society." IEEE Std. 2001. NY: IEEE. [2] [3] [4] [5] [6] [7] [8] [9] [10] [II] 54 . 1994. acronyms.106-2003. 2006. Raleigh." IEEE Std. 141-1993. 242-2001 (Revision of IEEE Std." IEEE Std.102-2006 (Revision of IEEE Std. C37. 2006 IEEE Power & Energy Society. 2001. IEEE Power & Energy Society.2008. 2006. 2009. "IEEE recommended practice for electric power distribution for industrial plants. C37. "IEEE recommended practice for grounding of industrial and commercial power systems. IEEE Power & Energy Society. [13] [ 14] [15] 55 . Dallas. WA: Schweitzer Engineering Laboratories.[12] IEEE Power & Energy Society. TX: Megger Inc. 2011. 2010 Schweitzer Engineering Laboratories. Pullman. 1995 Megger Inc. 20110324. Piscataway. Instruction Manual for SEL-700G Generator Protection Relay. 710000...0 Advanced Visual Test Software. Instructional Manual for A VTS 4. Instructional Manual for MPRT Protective Relay Test System. Dallas. IEEE Tutorial on the Protection ofSynchronous Generators (Publication 95 TP 102). TX: Megger Inc. 2010 Megger Inc. NJ: IEEE.