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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
All rghts reserve
INFORMATION TO ALL USER The qualty of this reproduction is dependent on the quality of the copy su
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a note will indicate the deleti
UMI 150766
Copyright 2012 by ProQuest L
All rghts reserved. This edition of the work is protected a unauthorized copyng under Title 17, United States C
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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 5 Short Circuit 6 Per Unit Quantities 10 One Line Diagram 11 Relay and Control Symbols 14 Elementary Diagrams 15
3. UNIT GENERATOR PROTECTION RELAYS 18
Volt/Hertz relay (24) 18 Synchronizing Check Relay (25) 20 Under Voltage Relay (27) 20 Directional Reverse Power Relay (32) 21 Loss of Excitation (Field) Relay (40) 21 Negative Sequence or Unbalance Relay (46) 23 Stator Temperature Relay (49) 24 Inadvertent Energization Protection Relay (50) 25 Voltage Controlled Over Current Relay (51V) 25 Over Voltage Relay (59) 26 Voltage Balance Relay (60) 26 Sudden Pressure Relay (63) 27 Field Ground Relay (64F) 27 Oil Level Relay (71) 27 Out Of Step Relay (78) 28 Frequency Relays (81) 29 Lock Out Relay (86) 31
i i i
CHAPTER Page
Differential Relay (87) 31
4. SETTINGS CALCULATIONS AND EXPERIMENTAL RESULTS 33
Preliminary Calculations 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.
Rotating
Shaft
3-Phase
Output
Prime Mover (Mechanical
energy)
t w
Itel w
3-Phase
Electrical
system
DC Field Variable Source
FIGURE 1. Graphical representation of 3 phase power generation.
Field windings
Airgap
Stator windings
Stator
Rotor
FIGURE 2. Basic structure of a cylindrical rotor.
4
ROTATING ELEMENTS
FIGURE 3. Brushless excitation system [1].
A phase
Volts line to
neutral
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).
[ Subtransient f\ ^*~ 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 __ MV ABase_3 phase
'Base V3 x kV, BaseJLL
7 ^BaseLL Base 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:
actual value Per Unit 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 n -J. • _i ,kVBase aw kVABasenew Per unit impedancenew = Per unit impedanceoid (— =—)Lx —— =— 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. 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
© 3 phase generator
uuuuuu n r r r m
Two winding transformer
i
T Medium voltage draw out circuit
breaker
3 phase disconnect switch with fuse
JIQ Distribution bus Impedance ground with CT and
resistor for ground fault detection
• r • ( • ( 0
CT and PT with polarity marks in phase CT and PT symbols with reverse polarity Relay symbol where the " # " is replaced with the relay number
A Y Delta connection and Wye connection Open Delta and grounded Wye connections Control path points to control device
© 0 0 Circuit breaker close coil
Circuit breaker shunt trip coil Circuit breaker charging motor
-Q-Indicating light
1 T k a±b
Normally open and normally closed contacts
FIGURE 7. Typical electrical symbols.
12
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
I (m)
<i—4>-—(0~»
* (f
<HQ) <JU~4)
<s> !
i/
9
Generator prime
mover and field
shut down
controls.
"7T
$
-idbN
FIGURE 10. Unit connected generator protection with typical relays.
16
+ Fuse
DC Control
Power
Fuse
0 ^
A ~ p L S jI controls
Custoner
CB close controls
M - Spring Charging Motor
LS - Limit Switch, contact will open and shut motor when spring charged
CS - CB Control Switch
FIGURE 11. Basic elementary diagram.
X CS ~~ C
A
© w
Relay protection CBtrip functions
L
_L cs — T
A
C - Close T-Tnp
C C - Close Coil
ST - Shunt Tnp Coil
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
150--
£ 130- •
£ 120-•
o no--
100- •
0 0 1
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
MFC 1 GENERATOR MFG 2 GENERATOR MFG 3 GENERATOR
H 1 1 1 1 I j 1 1 1 1 I 1 1 1 1 1 0 1 1 0 10 100 1000 0 01 0 1 10 10 100 1000 0 01 0 1 1 0 10 100 1000
TIME (MINUTES) TIME (MINUTES) TIME (MINUTES)
f»Vl—PROHIBITED REGION
130-
t 120-
too.
01
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
RELAY CHARACTERISTIC
TIME (MINUTES)
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
. -j
-2
I
( v v ^
«
j Dl/ »1
OFFSET
METER Opu
J
" 2
\
DIAMETER "X,,
R
- 1 - X 1 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-to-
phase, 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 t a n ( 9 0 - £)
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)
25 0.85
14.4 1002
Xd= 1.15 X'd= 0.196 X"d= 0.136 X2= 0.129
Primary 14400 Secondary 120 PT Ratio = 120 Primary 1200 Secondary 5 CT Ratio = 240
MVA Pf KV A pu pu pu pu V V
A A
33
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 side CT
Secondary side CT
Primary Secondary Ratio 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/L2
LBa5e _ *Base_Primary_G - 2 5 MVAcjase ~ * Z V * "
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 — 7 ^ — 1 2 0 7
1 14,4007 _ ^BaseJLNrelay — ~J=X T^Tjj — 69 . 2 8 7
_ 1002.4 _ -lBase relay "" 240 ~~
_ 6 9 . 2 8 7 _ ^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
ExpectedPU (Volts) 72.75
Error (%)
-0.03
MinRange (Volts) 72.02
MaxRange (Volts) 73.47
Pass/Fail
Pass
2. 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
= 17.04 A
38
To convert the primary value into secondary quantities divide the base current value the
CT ratio.
U 17.04A
=.071A 1Secondary_reverse_power "" JA()
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« ,<\ i „ •
tatf-M
V A **
* * "AT
BV ^
i A C 1H«
%?r
» * *. * * j * 0
JLMIIJJ
0 *****
',>
iiLmmmt
***<< s > * « * V
MilP' 2T0
P*mm B :\y il , *^«
€ t*0*
2te* 110*
m*
FIGURE 21. 3 phase vector diagram of a reverse power relay (32).
TABLE 5. Reverse Power Test Result
Pickup
20.851
ExpectedPU
21.0
Error
-0.71
MinRange
20.580
MaxRang e
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
= 0.196 0.098 pu
39
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.
Voltage A |
f 89,282 V
f 0.0 *
| SuioHz
VottageB j
f mmv I 120.0 *
j 60,000 Hz
Voltage C J
[ 69.215 V
| """ 240.6 *
| 60.000 Hz
Current A 1
f 3,816 A
[ 270.08
[' 60.000 Hi
Current B 1
F" 3.816 A
f 30.0 *
[ SOSOHZ
Current C I
P 3.816 A
J* 150.0°
f 60.000 HE
FIGURE 23. Loss of excitation zone 2 reach test.
40
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——^ j _ _ ^ _ | , _ _ p _ _ p ! _ _ _ _ p _ _ _ ^^—^ ^——— j 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 (X Pickup)
3. 0000 5. 0000 7. 0000
Applied (Amps)
6.00 10.00 14.00
Time (Seconds) 3.7539 1.3598 0. 7620
ExpectedJTime (Seconds) 3.7197 1.3573 0, 7666
Error
(%) 0.91 0. 19 -0.61
MinRange (Seconds)
3.55 1.28 0.71
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
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
ExpectedPU (Volts) 76.21
Error
0.64
MinRange (Volts) 72.40
IVfaxRange (Volts) 80.02
Pass/Fail
Pass
8. 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. 2 for tests.
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>
The forward reach (lower circle portion) is2x3s25 :=::6s5 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 the following values,
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
180 11 0
Reverse reach
9.0 7,0
Left Blinder
Forward reach
s.o f6 i
_ J V ...,_
" ^ < *****
~ — —J
Right Blinder
.0 7 § 9.0 110
Relay will trip
inside circle and
inside left and
right Blinder lines,
270
FIGURE 29, Loss of Synchronization protection boundaries,
Reverse and forward reach experimental results.
Voltage A j
f ™ blF*
Voltage B j
[ 20.000V*
Voltage c j
f"""" 240.0 r
[^SOOOHT
Cur rent A j Current B |
| 13J?? A
pESoW
Current C I
f nJffK [ m o r
FIGURE 30. Forward reach results.
45
Voltage A 1 J Voltage e l
[ "™5S5So'v | p ™ l o ^ v "
f" o.o* i [ H^oX0
P'OSOOOHZ"* [ lo~OQOHz"
Voltage C J Current A Current B
f - 1337? A" j *""* 13.377 A
[~"T£ov
60 .W Hz
210,0 *
Current € [
j 13.37? A
["~5bo.or
FIGURE 31. Re¥erse reach results,
TABLE 11. Relay Reverse and Forward Reach Z Test Results
Volts (Volts)
20.00
Volts
(Volts)
20.00
Current (Amps) 13.38
Current
(Amps)
10.69
Angle (Degrees)
90.00 Angle
(Degrees)
270. 00
ZJREV (Ohms)
1.50 Z^FWD
(Ohms)
6.483
Ideal Z REV (Ohms)
1.50
IdealJZJWD
(Ohms)
6.500
%error
-0.33
-0.26
VoltageAj Voltage B j
j 60.000 Hz
Votlage C J
240.0 0
60.000 Hz
Current A
16.712 A
0.0«
oo.ooo Hz
Current B
I 16.712A
Current C 1
pgo^SflMHT
FIGURE 32, Relay right blinder result.
TABLE 12, Relay Right Blinder Reach Z Test Result
Volts (Volts) 20.00
Current (Amps) 16.71
Angle (Degrees)
0.00
ZJ78R1 (Ohms)
1.20
IdeaLZ (Ohms)
1.20
%error
-0.27
Voltage A 1
| 20.000 V
| 0.6 *
| 60.000 Hz
VoftageBJ
r 20.000 V
r'^oooHir m
Voltage C I
j 20.000 V
I 1*0.000 Hz m
Current A
f 10,012 A
j 00.000 Hz tsar
Current 8 I
| 16.612 A
[ 300.0 *
psbSoo HT
Current C
f ISJUA
[ 00.0 *
| 60,000 Hz
FIGURE 33. Left blinder result.
46
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 (kV) 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 1.15 .196 .136 .129
14.40 .85
120:1 Y 240:1 240:1
60:1 25Q
30.0 13.8 36.0 8% 1255 481 300:1 120:1 Solid
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
Pickup 105% 62.4V
.21A@120V
16.59ft -1.62ft 19.07 ft -1.62ft 7%, K=9 2.09A @ 52V
76.2V
1.2ft 8.03ft 6.5 ft 1.5 ft
Delay
2 seconds 50 seconds
4 minute linear reset Inverse time curve 10 seconds
50 milliseconds
49
36KV. 600A
O ) * j ' ' I* 13.8KV-480V
GFCT (
FIGURE 34. Sample system one-line.
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.
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