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.
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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
In the unlikely event that the author did not send a complete man and there are missing pages, these will be noted, Also, if material had to be
a note will indicate the deleti
UMI 150766
Copyright 2012 by ProQuest L
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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
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
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.
[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 of Synchronous 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