ABSTRACT CALCULATIONS OF PROTECTIVE RELAY SETTINGS FOR A UNIT GENERATOR FOLLOWING CATASTROPHIC FAILURE by Jaime Anthony Ybarra December 2011 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
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TABLE OF CONTENTS Page LIST OF TABLES
v
LIST OF FIGURES
vi
CHAPTER 1.
INTRODUCTION
1
2.
GENERATOR COMPONENTS AND PROTECTION SCHEME
3
The Transformer Short Circuit Per Unit Quantities One Line Diagram Relay and Control Symbols Elementary Diagrams 3.
5 6 10 11 14 15
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
18 18 20 20 21 21 23 24 25 25 26 26 27 27 27 28 29 31
CHAPTER
Page Differential Relay (87)
4.
31
SETTINGS CALCULATIONS AND EXPERIMENTAL RESULTS Preliminary Calculations
33 34
Typical Relay Settings Calculations and Verification with Experiment. 3 5 5
CONCLUSIONS
52
REFERENCES
54
iv
LIST OF TABLES Page Sample Generator Parameters
33
Sample Unit Transformer Parameters
34
Relay Volt/Hertz Experimental Test Result
37
Under Voltage Test Result
38
Reverse Power Test Result
39
Zone 2 Test Result
41
Loss of Excitation Zone 1 Reach Test Result
41
Current Unbalance Pickups for A, B and C Phases
42
Voltage Controlled Over Current Test Results
43
Over Voltage Relay Test Result
44
Relay Reverse and Forward Reach Z Test Results
46
Relay Right Blinder Reach Z Test Result
46
Left Blinder Reach Z Test Result
47
Equipment Summary Table
48
Relay Settings Summary Table
49
v
LIST OF FIGURES Page Graphical representation of 3 phase power generation
4
Basic structure of a cylindrical rotor
4
Brushless excitation system
5
Wye connected windings
5
3 Phase fault with DC component offset
8
Short circuit waveform showing the three transient periods
9
Typical electrical symbols
12
Waveform output with polarities in phase
13
Waveform output with polarities reversed
14
Unit connected generator protection with typical relays
16
Basic elementary diagram
17
Various volts/hertz limit curves
19
Generator, transformer and relay plot for volts/hertz relay plot
20
2 zone protection diagram
22
Typical negative sequence relay curve
24
Out of step protection zone
29
Representation of differential protection
31
vi
FIGURE
Page
18.
Experimental setup
36
19.
RMS TIME vs VOLTS of volt/hertz relay (24) operation
37
20.
Under voltage (27) relay operation graph
38
21.
3 phase vector diagram of reverse power relay (32)
39
22.
Zone reach impedance and phase angle relationship
40
23.
Loss of excitation zone 2 reach test
40
24.
Loss of excitation zone 1 reach test
41
25.
Unbalance A, B and C phases
42
26.
Voltage control relay (51C) results
43
27.
Voltage controlled relay (51C) RMS trip graph
44
28.
Over voltage relay (59) result plot
44
29.
Loss of Synchronization protection boundaries
45
30.
Forward reach results
45
31.
Reverse blinder result
46
32.
Right blinder result
46
33.
Left blinder result
46
34.
Sample system one line
50
vii
CHAPTER 1 INTRODUCTION A generator system is designed to provide electric power to customers reliably. Failure of any electric component such as the generator, unit-transformer or auxiliary transformers can lead to catastrophic damage. If any of these components are damaged beyond repair then they must be repaired or replaced. However, 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. The generator owner or user may have to purchase readably available equipment with capabilities as close as possible to original components. 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. Calculate the new capabilities of the generation system. 2. Calculate protective device settings based on new system. 3. 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. 4. Verify that the relays will operate as programed or set with simulation of fault conditions inherent to that protective device.
1
The engineer in charge must produce a system that will provide reliable, economical power to the customer as well as maintain a safe system for generator operation and maintenance personal. 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. Chapter 2 will discuss generating system component and electrical fundamentals as well as the symbols used to describe an electrical system. Chapter 3 will describe protective relay types and functions. 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.
2
CHAPTER 2 GENERATOR COMPONENTS AND PROTECTION SCHEME An electric generator is a device, which converts mechanical energy into electrical energy (see Figure 1). The prime mover provides the rotational mechanical power into the AC generator. This mechanical power may be derived from fossil fuels, nuclear or movement of water. The mechanical rotational motion is transferred via a shaft to the rotating portion of the generator, which is referred to as the rotor. 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. 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. 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). 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.
3
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.
3-Phase
Rotating
Outputt
Shaft
w Itel
w
3-Phase Electrical system
Prime Mover (Mechanical energy)
DC Field Variable Source
FIGURE 1. Graphical representation of 3 phase power generation.
Field windings Stator windings
Stator
Airgap
Rotor
FIGURE 2. Basic structure of a cylindrical rotor.
4
ROTATING ELEMENTS
FIGURE 3. Brushless excitation system [1].
Volts line to neutral A phase
Volts line to line
FIGURE 4. Wye connected windings.
The Transformer A transformer allows the conversion of one voltage level to another voltage level. A higher voltage level allows for lower losses due to lower current levels for a given amount of power. Lower voltage levels in turn allow for higher currents to loads for the same 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. The
5
magnetic lines intersect each other within this core. Mathematically the relationship is expressed by the following equation. 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. 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). This common point can be solidly connected to the ground or connected through impedance to ground to limit ground fault current. 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, the voltages on the other phases will increase thereby stressing the insulation of the cables and equipment. With a wye connected system the common point is referred to as the neutral. Short Circuit A power system is designed to be free of faults as much as possible through system design, equipment selection, installation and maintenance. However, even with these practices faults do occur. Some of these causes can be from insulation failure, moisture or inadvertent contact with conductive material. Regardless of the cause a significant amount of current flows to the point of the fault. At the fault location arcing 6
and burning will occur as well as mechanical stress to the equipment. The system voltage levels will drop proportionally with the magnitude and distance to the point of the fault. 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, synchronous and induction motors. The basic short-circuit equation is shown below j
_
"rms
he ~~ ^ **system
Where Isc is the short circuit current Vrms is the rms voltage and Zsystem ( or X ) is the equivalent system impedance (or reactance). 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. 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 amount of DC offset depends on the X/R ratio which is the impedance divided by the resistance of the system. A generator will have 3 short circuit constants inherent by design (see figure 6) that are used to set various protection elements. These constants are derived by experiment or by analytical methods by the manufacture. These constants are defined as follows
7
Phase C DC Component
FIGURE 5. 3 Phase fault with DC component offset [12].
8
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 current continuously decreases lasting approximately 0.05 s after an applied fault [1]. vY"d Transient reactance: Is the reactance of a generator between the subtransienl and synchronous states (see Figure 6.). 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 decreases continuously during this period but are assumed to be steady at this value for approximately 0.25s [1]. 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).
[ f\
^*~
Subtransient Penod
FIGURE 6. Short circuit waveform showing the three transient periods [12].
9
Per Unit Quantities A power system can be made up of various voltage levels there by making system calculations difficult. Therefore, to simplify calculations a common set of base values are selected and the remaining quantities are then scaled to these base values. The two common base values chosen are voltage and power. The other base values are then calculated from these two base values by the following equations:
r
'Base
7
Base
__ MV ABase_3 phase V3 x kV,BaseJLL
^BaseLL MVA m v ^Base_3 phase
Where ZBase is the base impedance in ohms, 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. 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
converted into the chosen base per unit values. The following equation will transform an old per unit impedance value into a new per unit impedance value: ~
....
j
Per unit impedancenew
n
-J. •
_i
= Per unit impedanceoid
,kVBase
(—
aw
=—) L x ——
KvBasejiew
kVABasenew
=—
^^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. u. . 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. The devices used to reduce the voltage and currents are referred to as potential transformers (PT) and current transformers (CT). This is accomplished by taking the primary quantities and scaling it down by a known ratio. One Line Diagrams A one-line diagram graphically illustrates an electrical power system by representing a 3 phase system with single symbol components. 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. For example there will be one CT (current transformer) for each phase for a total of 3, but a circuit breaker will have 3 phase capabilities per each unit (See Table 1). A three-line diagram assists in the actual construction of power equipment. Each component is now displayed as a three phase device. This will enable the builders of the system to interconnect the protection and other components.
11
©
uuuuuu nrrrm
3 phase generator
Two winding transformer
i T Medium voltage draw out circuit breaker
JIQ Distribution bus
3 phase disconnect switch with fuse
r •
• (
•
A
0
(
CT and PT with polarity marks in phase
Impedance ground with CT and resistor for ground fault detection
CT and PT symbols with reverse polarity
Relay symbol where the " # " is replaced with the relay number
Y
Delta connection and Wye connection
Open Delta and grounded Wye connections
0
© Circuit breaker close coil
Circuit breaker shunt trip coil
-Q-
1 a±b T
Indicating light
Normally open and normally closed contacts
k
FIGURE 7. Typical electrical symbols.
12
Control path points to control device
0
Circuit breaker charging motor
The symbols for current transformer (CT) and potential transformer (PT) also are referred to as Voltage Transformers (VT). Both CT and PT have polarities. A polarity mark as indicated by the dots in a one line diagram. 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. The polarity of an instrument transformer indicates the phase relationship between the input and the output. 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. Likewise for the PT (see Figure 7). A 180-degree phase shift will occur if the CT or PT secondary's are connected or installed in reverse. If this is by design the dots will be reversed in the one line diagram (see Figure 8). If the CT and PT are connected with their polarities reversed they would be indicated with the dots in the opposite side.
15 , I
Pnmay current/voltage —« — Seconday current/voltage
FIGURE 8. Waveform output with polarities in phase.
13
Pnmay current/voltage — — Set >nday c jrrer t/voltage 1
I 05
I
°
05
I 1
I I
I "
FIGURE 9. Waveform output with polarities reversed.
Instrument transformers like power transformers may be connected in multiple ways depending on the application. 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. Note that open delta PT only 2 PTs are used with the secondary center phase grounded. 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, closes its alarm or trip contact a dashed line with arrows is often used to show the device that is activated. 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.
14
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 ". The Elementary Drawing shows the actual devices that are being activated. That is, 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. The contacts from the various relays are also shown on Table 1. 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. 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. Half the spring energy is used to close the circuit breaker and the other half is used to trip the circuit breaker. The motor will recharge the springs after the trip operation. These solenoids are referred to as close coils (CC) or trip coils (TC). The motor is designated by the capital letter "M." Indicating lights on the switchgear panels are used to indicate the status of the circuit breaker. A red light is used to indicate the circuit breaker is closed and a green light indicates that the circuit breaker is open. Two parallel lines represent contacts. 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 state as shown on elementary diagrams is when the circuit breaker is open. When the circuit breaker closes the state of the contact reverses.
15
->-$U<-
UUUUUU Y
rrrrm
* (f
i/
I
-—(0~»
(m)
! $
9
Generator prime mover and field shut down controls.
"7T -idbN
FIGURE 10. Unit connected generator protection with typical relays.
16
+ Fuse
A ~pLS
DC Control Power
Custoner
X CS ~~ C
Relay protection CBtrip functions
CB close jI controls
0 ^
Fuse
A
A
© w C - Close
LS - Limit Switch, contact will open and shut motor when spring charged
C C - Close Coil
FIGURE 11. Basic elementary diagram.
—
L
M - Spring Charging Motor
CS - CB Control Switch
_L cs
T-Tnp
ST - Shunt Tnp Coil
T
CHAPTER 3 UNIT GENERATOR PROTECTION RELAYS A wide variety of relays are required to protect a generator system. Each type of relay will protect the system from a particular type of abnormality. 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. However, 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, but the stability of the system. The following sections will describe the typical types of relays used in generator protection. Not all relays are used in every instance, but a thorough review is necessary to allow the protection engineer to decide if the application warrants the inclusion of a certain protective function. Volt/Hertz Relay (24) An internal magnetic field is required by generators and transformers in order to operate. They are designed in such a way as provide the necessary flux for their rated load. 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.
18
This flux in the unintended areas will create high circulating eddy currents which will in turn generate large amounts of heat. This excess heat will degrade lamination and winding insulation leading to equipment failure. 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. 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. 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. To develop 24 relay settings the generator manufacture over excitation limit curves should be obtained. A sample of limit curves are shown in Figure 11 below
MFC 1 GENERATOR
MFG 2 GENERATOR
MFG 3 GENERATOR
150--
£
130- •
£
120-•
o
no-100- • 001
H 0 1
1 10
1 10
TIME (MINUTES)
1
1
100
1000
I
j
0 01
0 1
1
1
1
1
10
10
100
1000
TIME (MINUTES)
I 0 01
1 0 1
1
1
1
10
10
100
1 1000
TIME (MINUTES)
f » V l — P R O H I B I T E D REGION
Figure 12. Various volts/hertz limit curves [1].
A transformer is also susceptible to volts/hertz problems. A similar transformer curve can be obtained and the relay set to protect both (see Figure 12).
19
130-
t
120-
RELAY CHARACTERISTIC
too.
01 TIME (MINUTES)
FIGURE 13. Generator, transformer and relay plot for volts/hertz relay plot [1].
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, frequency and magnitude and are within predetermined thresholds. If and when the electrical differences between the two systems satisfy the threshold conditions an action may be taken. This action in a generation system is the closing of a circuit breaker thereby bringing the generator into parallel with the electrical system. If two electrical systems were brought together and if they are significantly different, large currents will flow through the systems which can exceed those experienced during sudden short circuits. The intense currents and torques produced may cause server damages to the generator stator which may require it to be rewound. Synchronizing limits that the two systems must be with specified limits in order to safely parallel. Typical limits are circuit breaker closing angle of ±10°, generator side voltage relative to system 0% to +5% and frequency differences of ±0. 067 Hz. Under Voltage Relay (27) The under voltage relay operates when the voltage applied drops below a predetermined value. Under voltage relays may have inverse time characteristics so that 20
the system may have time to stabilize before any trips or alarms are initiated or they may have definite level thresholds. For paralleling a generator and distribution bus the 27 under voltage functions is incorporated into the 25 relay. 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. This will drive the prime mover and possibly damaging its shaft, couplings, compressors.. .etcetera. The manufacture provides the magnitude of reverse power that the generator system can withstand before damage occurs. A 32 relay will also contain an adjustable time delay to allow short duration power variations to stabilize. 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. 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. As a result it will draw reactive power from the system instead of providing it to the system. 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. Common causes of excitation loss can be operator error, excitation system failure, accidental tripping of the field breakers or flashover of the exciter commutator. A type of 40 relay is called an offset MHO relay. The following information will be required from the manufacture to set the protection level: the generator direct axis reactance Xd, Transient reactance X'd, line to line voltage, and rated phase current, all in secondary values. The protection characteristics are plot on the R-X plane. Where R is the resistance 21
and X is the reactance of the system (see Figure 30). 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.
05 R
-R
«
. -j
I (
-2
"
v^j
2
\ Dl/ METER » 1 Opu
v
-1
OFFSET
J -X
1
DIAMETER "X,,
2
FIGURE 14. 2 zone protection diagram [1].
The following equations are used to calculate the diameters and offsets. Note that values must be secondary ohms for use in the relay. Time delays are of .1 seconds for Zone 1 and .5 seconds for Zone 2 are suggested. Zone 1 (inner circle) is commonly set to 1. 0 pu of impedance Z. 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. Note that these values are in primary quantities and must be converted into relay base for used with the protection equipment. 22
Negative Sequence or Unbalance Relay (46) Negative sequence stator currents, caused by unbalanced faults such as phase-tophase, phase-to-ground, double-line-to-ground or load unbalance, 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. The most serious series unbalance for example is an open phase, due to a failed circuit breaker pole. Two limits are used for 46 relay protection settings the Continues Negative-Sequence current capability limit and the Short Time Unbalance current limit. IEEE standards dictate that all generators meet a negative sequence withstand capabilities [5]. For generators continues negative-sequence limits range from 5 and 10% of rated current. The short time limit is expressed in terms of K, where K= I2t and varies from 5 to 40. The actual values will be provided by the generator manufacture. These limits will be used to set the relay pickup values. 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. Typical curves (see Figure 15) provide the protection engineer relay pickup and delay characteristics to coordinate trip functions of protection down the line.
23
PER UNIT l2
FIGURE 15. Typical negative sequence relay curve [1].
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. These detectors called "RTD" can be made of platinum, copper or nickel. Two pickup settings are commonly programmed into a temperature relay, a lower threshold will alarm without shutting down the system to allow corrective action. The second higher threshold will trip the system in order to prevent thermal damage to the generator.
24
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. 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. For inadvertent energization protection 3 types of relays and a timing device are used in tandem. A 27 under-voltage relay, a 81U under-frequency relay and a 50 instantaneous over-current relay. 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. A timing device is also used with this scheme. 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. 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 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. The further the fault is from the generator the lower the magnitude of the voltage drop.
25
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. Typical settings for the overcurrent unit is 50% of the full load current if the activation voltage level is 75% of the rated voltage. 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. 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. Two sets of PT are used to implement this relay. Under normal conditions all three phase PT output magnitudes are equal. 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. As an example, 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. 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. An alarm is used after the 60 relay has operated to inform generator operators of a blown fuse. 26
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 is designed such that slow changes in pressure do to normal loading and oil expansion are not detected. The 63 is set to immediately remove power from the transformer by tripping the main circuit breaker and de-energizing the generator. Field Ground Relay (64F) The field circuit is normally ungrounded. A single ground generally will not affect the generator operation nor may there be any immediate damage. However, there is a greater chance of a second ground fault occurring after the first. If that were to occur that portion of the field winding will be short circuited. 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. The unbalance currents also produce heating in the rotor iron resulting in unbalanced temperatures that may also lead to damaging vibrations. 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. A ground in the field will cause the relay to operate. A time delay is employed in order to prevent unintentional operation due to short duration field transients. 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. As the oil level gets lower an alarm threshold may be set to alert plant personal. If that level is exceeded then the main circuit breaker may be tripped and the generator taken offline. 27
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. 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. These high currents and of-frequency operation lead to winding stress, pulsating torques and mechanical resonances are damaging to the generator. The relay operates from voltage and current derived from voltage and current transformers. The information need to calculate settings are the generator transient reactance in secondary ohms, the step up transformer impedance in secondary ohms and the impedance of the lines beyond the generator set-up transformer. All impedances must be in the generator base KV. If a system stability study is not available then conservative values for the settings should be used. In this case set 5 = 120 .
d = P*
+ X
™ + X>y"™\
x tan(90
- £)
Where d is the blinder distance (see Figure 33). The diameter of the MHO unit is calculated. diameter D = (2xX'd+
1.5x XTG)
28
Uttsttfitt
FIGURE 16. Out of step protection zone.
The diameter above does not contain Xsystem since in our sample system since we assume no system data or stability data exists. The relay will trip when the relay detects the impedance between the blinders and inside the circle. 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, which will mostly be significant when an under frequency condition exists. 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 reduced rotation also leads to
29
reduced ventilation thereby a reduction in power output. The lower frequency can also lead to over excitation since the flux is inversely proportional to the frequency. Over Frequency Relay (810) Is commonly the result of a sudden reduction in load. 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. However, generator turbines are designed to operate near 60 Hz outside the designed limit may produce destructive resonance in the rotating mechanical components. 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. 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. In other words, 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. When a protective relay activates the 86 lock out relay the changes contact states can be used to trip main circuit breakers, field circuit breakers, activate alarms systems, etcetera. The protection engineer can specify the function of the 86 relay when the protection scheme is developed. The external portion of the 86 relay consists of a handle which when tripped will rotate indicating a trip has occurred.
30
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. Differential Relay (87) Internal generator faults are considered serious since they cause severe costly damage to insulation windings, core as well as producing severe mechanical torsional stress to shafts and couplings. Under normal load conditions, current flows through the protected equipment. 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. If a fault should occur outside the protection zone the relay will not operate. 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.
FIGURE 17. Representation of differential protection.
Transformer differential relays operate on the same principle, 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. On transformers that are delta to wye or wye delta there is an inherent 30 degree phase shift. 31
To offset this the CT are configured in the opposite of the winding they are protecting. That is a wye winding will have delta wired CTs and a delta winding will have wye connected CTs. In setting the taps the delta wired CTs secondary currents muct be multiplied by 1.73 to allow for the delta line currents. The slope of the relay will be the sum of the errors induced by the CT ratio mismatch, CT errors and voltage level differences. The errors will allow you to select the proper slope of the relay. The difference in current in verses current out must exceed a set percentage difference in order to operate. Another use of differential protection is in Unit Protection configuration. In this setup the generator step up transformer and service station transformer are included in the protection zone. Unit protection is implemented using microprocessor relays.
32
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.
TABLE 1. 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)
Current Transformers (CT)
Xd= X'd= X"d= X2= Primary Secondary PT Ratio Primary Secondary CT Ratio
33
=
=
25 0.85 14.4 1002 1.15 0.196 0.136 0.129 14400 120 120 1200 5 240
MVA Pf KV A pu pu pu pu V V A A
The Unit connected transformer parameters for our sample system are show in Table 2 TABLE 2. 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 13.80 36 0.08 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. The voltage and power of the generator will be used as the base quantities. VBase_LL_G = 14,400K or 14AkV
MVABaseG
= 2SMVA
Using the values from Table 2 the transformer impedance is converted into the generator base.
34
30 MVA 13.8kV?
Where XBasejrc is the transformer on the generator MVA and Voltage base. Calculate the generator base impedance ZBase_primary_G 7
_14.4fcl/ L 2 LBa5e _
*Base_Primary_G
-
~ *
2 5 MVAcjase
ZV
* "
Since relay settings are based on the secondary magnitudes of the CT and PTs convert the Voltages, currents and impedances into the relay base _ 14,4007 _ ^BaseJLL relay —
1
^BaseJLNrelay
— ~J=X
7 ^
— 1207
14,4007 _ T^Tjj
_ 1002.4 _ Base relay "" 2 40 ~~
l
— 69. 2 8 7 -
_69.287_ ^Base relay ~~ A * JCA "~"
^
Typical Relay Settings Calculations and Verification with Experiment. The following are the calculations for relays settings. Those that do not require calculations will reference a figure for the corresponding setting. The experimental verification setup (Figure 17) consists of a waveform and RMS capture device Dranetz Power Xploer PX-5, Schweitzer Engineering Laboratories SEL-700G protective generator relay and 3-phase power system simulator Megger MPRT Relay Tester. The simulator software Megger AVTS 4. 0 will be used to control the 3-phase simulator as well as vary the phase angles and record the results.
35
The Dranetz Inc9 DRAN-VIEW 6 Software is used to record wave forms and phase angle vectors.
FIGURE 18. Experimental setup.
1.
Over excitation Relay (24): The generator and transformer manufacture
provided curves are used to set this relay. In our sample the over excitation trip point 105% will be tested by holding the frequency constantan and increasing the voltage. Figure 34 shows the RMS values of the voltage as the relay trips the system offline. The theoretical voltage level is calculated by multiplying the line to neutral voltage by the percentage above the nominal voltage. That is 69. 28V x L 05 = 72. 74V.
36
Table 4 shows the tabulated results.
1 -^-
1 24 Relay trip at 72.7 Volts
~] TIME
FIGURE 19. RMS TIME vs VOLTS of volts/hertz relay (24) operation.
TABLE 3. Relay Volt/Hertz Experimental Test Result Pickup (Volts) 72.72
2.
ExpectedPU (Volts) 72.75
Error (%)
-0.03
MinRange (Volts) 72.02
MaxRange (Volts) 73.47
Pass/Fail Pass
Under Voltage Relay (27): Use definite time function. Set the trip level at
90% of the line to neutral voltage. The calculation is as follows; .9 x 69.28 V = 62.35V or approximately 62.4V (see Figure 34) and the numerical results in Table 4. 37
Vertical edge indicates relay has tripped.
FIGURE 20. Under voltage relay (27) operation graph.
TABLE 4. Under Voltage Test Result Pickup (Volts) 62.20
Expected PU (Volts) 62.40
Error (%)
-0.32
Min Range (Volts) 59.18
Max Range (Volts) 65.62
Pass/Fail Pass
3. Reverse Power Relay (32): The prime movers manufacture provided the motoring power of 2% and can withstand for 50 seconds. Calculate the value in MW of the allowable reverse power. 0.02
x 25 MVA
x
0.85
pf =
0.4250
MW
For relaying purposes the pickup up value must be in secondary quantities and the equivalent MVA value. The calculation is as follows: .425MW Primary_reverse_power
V3 14.4kV
38
= 17.04 A
To convert the primary value into secondary quantities divide the base current value the CT ratio. 1 U Secondary_reverse_power
17.04A ""
JA()
=.071A
Since our relay detects the total power, multiply the result by 3. The current required will be .21 A. The currents are rotated 180 degrees (Figure 20) to simulate current flow into the generator. The results shown on Table 5. c« » * *. ,<\ * * j *',> 0
i
„•
JLMIIJJ
tatf-M * * "AT
BV
^
iiLmmmt 0
*****
m*
***<< s >* « *
V
MilP' 2T0
V
A
iP*mm B A :\y C 1H« il
€ t*0*
2te*
** %?r , *^« 110*
FIGURE 21. 3 phase vector diagram of a reverse power relay (32).
TABLE 5. Reverse Power Test Result Pickup
ExpectedPU
Error
20.851
21.0
-0.71
MinRange MaxRang e 20.580 21.420
Pass/Fail Pass
4. Loss of Field Relay (40): Calculate the protective zones. Values must be scaled to CT and PT secondary values. Zone 1: Set the Mho circle at 1 pu. Where 1 pu is equal to Zease_reiay Zone 1 diameter = 1 pu = -16. 59 Q negative since it is a negative offset MHO relay. Zone 1 offset
Xd 2
=
39
0.196
0.098 pu
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. Zone 1 offset (relay) = - 0. 098 x 16. 59 = - 1. 62 Q Zone 1 diameter Zeasejeiay = 16.59 O Zone 2 diameter (relay) = | - 1. 15 x 16. 59 | = 19. 07 O or 19. 1 Zone 2 offset (relay) = Zone 1 offset (relay) = - 1 . 62 O The experimental results are calculated as follows. The reach is calculated by adding the offset and the zone diameter to get the zone reach. 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. With the voltage held constant at 69.28V the impedance Z if calculated as follows I = V/Z. For Zone 2 Reach I = (69. 28V/| 16. 59 + 1. 62|) = 3. 8A For Zone 1 Reach I = (69. 28/1 19. 10 + 1. 62|) = 3. 34A z*
r
"„
^JzJL
FIGURE 22, Zone reach impedance and phase angle relationship. The experimental results are below.
f
89,282 V
f
0.0 *
|
SuioHz
Voltage C J
VottageB j
Voltage A |
f mmv I
120.0 *
j 60,000 Hz
f
3,816 A
| """ 240.6 *
[
8
|
[' 60.000 Hi
[
69.215 V
60.000 Hz
270.0
FIGURE 23. Loss of excitation zone 2 reach test. 40
Current C I
Current B 1
Current A 1
F"
3.816 A
P
3.816 A
f
30.0 *
J*
150.0°
[
SOSOHZ
f 60.000 HE
TABLE 6. Zone 2 Test Result Impedance (Ohms) 20. 705
Error (%) 0.02
CalcZ (Ohms) 20.70
Voltage A j
p___ !____
Voltage B J
j_™^__ p___
MinRange (Ohms) 19.66
Voltage C J
p——^ ^^—^
Current A J
Pass/Fail
MaxRange (Ohms) 21,73
Current B I I
j _ _ ^ _ | , __ ^——— j p _ _ _
Pass
Current C
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
Note that OC unit does not occur until voltage drops,
FIGURE 27, Voltage controlled relay (51C) RMS trip graph,
43
MaxRange (Seconds) 3.89 1.44 0.82
Pass/Fail Pass Pass Pass
7. Over Voltage Relay (59): For our experiment set the over voltage threshold to 110% of the nominal line to neutral voltage. 1.10 x 69. 28= 1. 10 x 69. 28 = 76. 2V
Figure 28. Over voltage relay (59) result plot. TABLE 10. Over Voltage Relay Test Result Pickup (Volts) 76.70
8.
ExpectedPU (Volts) 76.21
Error 0.64
MinRange (Volts) 72.40
IVfaxRange (Volts) 80.02
Pass/Fail Pass
Loss of synchronization relay (78). 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. d (blinder distance) = (3. 25 + 1. 02 + 0)/2 x tan(30) = 1. 23 fl or 1. 2fortests. MHO unit diameter = (2 x 3. 25 + 1. 5 x 1. 02) = 8. 03 Q with impedance angle of 90 . 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. 02 = 1. 53 for our experiment use 1. 5 Again using the fact that I = Volts/Z we calculate thefollowingvalues, a, Forward reach current I = 69. 28/6. 5 = 10, 65A
44
b.
Reverse reach current I = 69, 28/1. 5 = 46, 19A note that this is exceeds
typical 3 phase test equipment. Since we are interested in the current and the impedance is fixed we can use a lower voltage to calculate a suitable I. Use 20V and calculate I. 20V/1. 5 = 13. 3A c.
Right Blinder the current phases are rotated as to allow the impedance
vector approach from right to left as in b above 20V/1.2 = 16. 67A d.
Left Blinder the current phases are rotated to allow the impedance to
approach from left to right I is 20V/1.2=16. 67A The protection zone are bound by these values (see Figure 29), 90
Reverse reach 180
11 0
9.0
7,0
_JV
"^<
s.o
f6
Right Blinder
...,_
*****
i
.0
7§
9.0
110
Left Blinder Relay will trip inside circle and
Forward reach
inside left and ~ —
right Blinder lines,
—J
270
FIGURE 29, Loss of Synchronization protection boundaries, Reverse and forward reach experimental results. Voltage A j
Voltage B j [
f ™ blF*
Voltage c j
Current B |
Cur rent A j |
20.000V* f"""" 240.0
13J?? A
r
pESoW
[^SOOOHT
FIGURE 30. Forward reach results. 45
Current C I
f nJffK [ mor
Voltage A 1 J
Voltage e l
Voltage C J
[ "™5S5So'v | p ™ l o ^ v " f"
o.o* i [
P'OSOOOHZ"*
H^oX
-
f
0
1337? A" j *""* 13.377 A
[~"T£o
Current €
Current B
Current A
v
210,0 *
j
[
13.37? A
["~5bo.or
6 0 . W Hz
[ lo~OQOHz"
FIGURE 31. Re¥erse reach results, TABLE 11. Relay Reverse and Forward Reach Z Test Results
Volts
Current (Amps) 13.38 Current
Angle (Degrees) 90.00 Angle
ZJREV (Ohms) 1.50 Z^FWD
Ideal Z REV (Ohms) 1.50 IdealJZJWD
(Volts)
(Amps)
(Degrees)
(Ohms)
(Ohms)
20.00
10.69
270. 00
6.483
6.500
Volts (Volts) 20.00
Voltage B j
VoltageAj
Votlage C J
16.712 A 0.0«
60.000 Hz
oo.ooo Hz
240.0 j 60.000 Hz
-0.33
-0.26
Current B
Current A
0
%error
I
Current C 1
16.712A
pgo^SflMHT
FIGURE 32, Relay right blinder result. TABLE 12, Relay Right Blinder Reach Z Test Result Volts (Volts) 20.00
Angle (Degrees) 0.00
Current (Amps) 16.71
|
20.000 V
|
0.6 *
|
60.000 Hz
Voltage C I
VoftageBJ
Voltage A 1
r
20.000 V
j
20.000 V
10,012 A
r'^oooHir
I 1*0.000 Hz
j 00.000 Hz
m
m
tsar
FIGURE 33. Left blinder result.
46
-0.27
Current 8 I
Current A
f
%error
IdeaLZ (Ohms) 1.20
ZJ78R1 (Ohms) 1.20
Current C
|
16.612 A
f
ISJUA
[
300.0 *
[
00.0 *
psbSoo HT
|
60,000 Hz
TABLE 13. Left Blinder Reach Z Test Result Volts (Volts) 20.00
Current (Amps) 16.61
Angle (Degrees) 180. 00
Z_78R2 (Ohms) 1.20
ldeal_Z (Ohms) 1.20
%error 0.33
The settings results can then be summarized on a table which can be provided to the personnel programing and setting the relays. Note that all CT ratios are based on 5A secondary and PT are based on 120V secondary. Only settings that required calculations are on Table 14. Settings that require curve selection and not included.
47
TABLE 14. 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
25 1.15 .196 .136 .129 14.40 .85 120:1 Y 240:1 240:1 60:1 25Q
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
30.0 13.8 36.0 8% 1255 481 300:1 120:1 Solid
Auxiliary Transformer Data MVA Primary Voltage (kV ) Secondary Voltage (kV ) Nameplate impedance CT Ratio Primary CT Ration Secondary Grounding method
3 14.4 .480 5% 25:1 800:1 Solid
48
TABLE 15. 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
49
Pickup 105% 62.4V .21A@120V
2 seconds 50 seconds
16.59ft -1.62ft 19.07 ft -1.62ft 7%, K=9 2.09A @ 52V 76.2V
4 minute linear reset Inverse time curve 10 seconds
1.2ft 8.03ft 6.5 ft 1.5 ft
Delay
50 milliseconds
36KV. 600A
)
O GFCT (
FIGURE 34. Sample system one-line.
*
j
'
'
I* 13.8KV-480V
CHAPTER 5 CONCLUSIONS A procedure for protective relay settings for a 25MVA generator has been presented. An AC generator system that has experienced catastrophic failure may have one or more major components repaired or replaced. Due to either obsolescence or long delivery time exact replacements may not be available therefore recalculations and verification of new relay settings are necessary. The following conclusions are drawn from the presented study. 1. Basic knowledge of generators, transformer, 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. 2. In order to develop settings for relays that will be protecting replacement components that may not have the same electrical characteristics, thorough familiarity with the protective relays, magnitude sensing devices and there unique functions are necessary. 3.
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.
51
4. Once replacement components have been obtained and installed, develop or update one-line diagrams which will represent the generator, transformers and circuit breaker system. 5. 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. Once electrical and control diagrams have been developed calculations to convert primary quantities into secondary quantities are performed to set all relays. 7. 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. 8. This procedure may be applied to a unit configured AC generator.
52
REFERENCES
53
REFERENCES [I]
IEEE Power & Energy Society. "IEEE guide for AC generator protection." IEEE Std. C37.102-2006 (Revision of IEEE Std. C37.102-1995), 2006.
[2]
IEEE Power & Energy Society. " IEEE guide for generator ground protection." IEEE Std. C37.101-2006, 2007.
[3]
IEEE Power & Energy Society. "IEEE standard for electrical power system device function numbers, acronyms, and contact designations." IEEE Std. C37.2- 2008, 2008
[4]
IEEE Power & Energy Society. "IEEE guide for abnormal frequency protection for power generating plants." IEEE Std. C37.106-2003, 2004.
[5]
IEEE Power & Energy Society. "IEEE standard for cylindrical-rotor 50 Hz and 60 Hz synchronous generators rated 10 MVA and above.",IEEE Std. C50. 13-2005, 2006
[6]
IEEE Power & Energy Society. "IEEE recommended practice for electric power distribution for industrial plants." IEEE Std. 141-1993, 1994.
[7]
IEEE Power & Energy Society. "IEEE recommended practice for protection and coordination of industrial and commercial power systems." IEEE Std. 242-2001 (Revision of IEEE Std. 242-1986) [IEEE Buff Book], 2001.
[8]
IEEE Power & Energy Society. "IEEE recommended practice for grounding of industrial and commercial power systems." IEEE Std. 142-2007 (Revision of IEEE Std. 142-1991), 2001.
[9]
Donald Reimert. Protective Relaying for Power Generation Systems. Boca Raton, FL: CRC Press, 2006.
[10]
ABB Power T&D Company Inc. Electrical Transmission and Distribution Reference Book. Raleigh, NC: ABB Power T&D Company Inc, 1997.
[II]
IEEE Power & Energy Society. "IEEE Standards Dictionary: Glossary of Terms & Definitions." New York, NY: IEEE, 2009.
54
[12]
IEEE Power & Energy Society. IEEE Tutorial on the Protection ofSynchronous Generators (Publication 95 TP 102). Piscataway, NJ: IEEE, 1995
[13]
Megger Inc. Instructional Manual for MPRT Protective Relay Test System, 710000. Dallas, TX: Megger Inc., 2010
[ 14]
Megger Inc. Instructional Manual for A VTS 4.0 Advanced Visual Test Software. Dallas, TX: Megger Inc., 2010
[15]
Schweitzer Engineering Laboratories. Instruction Manual for SEL-700G Generator Protection Relay, 20110324. Pullman, WA: Schweitzer Engineering Laboratories, 2011.
55
