ALSTOM T&D. Network Protection And Automation Guide (NPAG)

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Chapter 17



Generator and Generator Transformer Protection

17-27

This is particularly true for geographically islanded power

systems, such as those of the British Isles. An alternative to

ROCOF protection is a technique sometimes referred to as

‘voltage vector shift’ protection. In this technique the rate of

phase change between the directly measured generator bus

voltage is compared with a memorised a.c. bus voltage

reference.

Sources of embedded generation are not normally earthed,

which presents a potential safety hazard. In the event of an

Utility system earth fault, the Utility protection should operate

to remove the Utility power infeed. In theory, this should also

result in removal of the embedded generation, through the

action of the stipulated voltage/frequency protection and

dependable ‘loss of mains’ protection. However, in view of

safety considerations (e.g. fallen overhead line conductors in

public areas), an additional form of earth fault protection may

also be demanded to prevent the backfeed of an earth fault by

embedded generation. The only way of detecting an earth

fault under these conditions is to use neutral voltage

displacement protection. The additional requirement is only

likely to arise for embedded generation rated above 150kVA,

since the risk of small embedded generators not being cleared

by other means is negligible.

17.21.2 ROCOF Relay Description

A ROCOF relay detects the rate of change of frequency in

excess of a defined setpoint. The signal is obtained from a

voltage transformer connected close to the Point of Common

Coupling (PCC). The principal method used is to measure the

time period between successive zero-crossings to determine

the average frequency for each half-cycle and hence the rate of

change of frequency. The result is usually averaged over a

number of cycles.

17.21.3 Voltage Vector Shift Relay Description

A voltage vector shift relay detects the drift in voltage phase

angle beyond a defined setpoint as long as it takes place within

a set period. Again, the voltage signal is obtained from a

voltage transformer connected close to the Point of Common

Coupling (PCC). The principal method used is to measure the

time period between successive zero-crossings to determine

the duration of each half-cycle, and then to compare the

durations with the memorised average duration of earlier half-

cycles in order to determine the phase angle drift.

17.21.4 Setting Guidelines

Should loss of the Utility supply occur, it is extremely unlikely

that there will be an exact match between the output of the

embedded generator(s) and the connected load. A small

frequency change or voltage phase angle change will therefore

occur, to which can be added any changes due to the small

natural variations in loading of an isolated generator with time.

Once the rate of change of frequency exceeds the setting of the

ROCOF relay for a set time, or once the voltage phase angle

drift exceeds the set angle, tripping occurs to open the

connection between the in-plant and Utility networks.

While it is possible to estimate the rate of change of frequency

from knowledge of the generator set inertia and MVA rating,

this is not an accurate method for setting a ROCOF relay

because the rotational inertia of the complete network being

fed by the embedded generation is required. For example,

there may be other embedded generators to consider. As a

result, it is invariably the case that the relay settings are

determined at site during commissioning. This is to ensure

that the Utility requirements are met while reducing the

possibility of a spurious trip under the various operating

scenarios envisaged. However, it is very difficult to determine

whether a given rate of change of frequency will be due to a

‘loss of mains’ incident or a load/frequency change on the

public power network, and hence spurious trips are impossible

to eliminate. Thus the provision of Loss of Utility Supply

protection to meet power distribution Utility interface

protection requirements, may actually conflict with the

interests of the national power system operator. With the

growing contribution of non-dispatched embedded generation

to the aggregate national power demand, the loss of the

embedded generation following a transmission system incident

that may already challenge the security of the system can only

aggravate the problem. There have been claims that voltage

vector shift protection might offer better security, but it will

have operation times that vary with the rate of change of

frequency. As a result, depending on the settings used,

operation times might not comply with Utility requirements

under all circumstances. [Reference 17.1] provides further

details of the operation of ROCOF relays and the problems that

may be encountered.

Nevertheless, because such protection is a common

requirement of some Utilities, the ‘loss of mains’ protection

may have to be provided and the possibility of spurious trips

will have to be accepted in those cases. Site measurements

over a period of time of the typical rates of frequency change

occurring may assist in negotiations of the settings with the

Utility, and with the fine-tuning of the protection that may

already be commissioned.

17.22 EXAMPLES OF GENERATOR

PROTECTION SETTINGS

This section gives examples of the calculations required for

generator protection. The first is for a typical small generator

installed on an industrial system that runs in parallel with the

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Network Protection & Automation Guide

17-28

Utility supply. The second is for a larger generator-transformer

unit connected to a grid system.

17.22.1 Protection Settings of a Small Industrial

Generator

Salient details of the generator, network and protection

required are given in Table 17.2. The example calculations are

based on an Alstom MiCOM P343 relay in respect of setting

ranges, etc.

Table 17.2: Data for small generator protection example

17.22.1.1 Differential Protection

Biased differential protection involves the determination of

values for four setting values:

, I

, K

and K

in Figure 17.5.

can be set at 5% of the generator rating, in accordance with

the recommendations for the relay, and similarly the values of

(120%) and K

(150%) of generator rating. It remains for

the value of

to be determined. The recommended value is

generally 0%, but this only applies where CTs that conform to

IEC 60044-1 class PX (or the superseded BS 3938 Class X) are

used – i.e. CTs specifically designed for use in differential

protection schemes. In this application, the CTs are

conventional class 5P CTs that meet the relay requirements in

respect of knee-point voltage, etc. Where neutral tail and

terminal CTs can saturate at different times due to transiently

offset magnetising inrush or motor starting current waveforms

with an r.m.s level close to rated current, and where there is a

high L/R time constant for the offset, the use of a 0% bias slope

may give rise to maloperation. Such waveforms can be

encountered when plant of similar rating to the generator is

being energised or started. Differences between CT designs or

differing remanent flux levels can lead to asymmetric

saturation and the production of a differential spill current.

Therefore, it is appropriate to select a non-zero setting for K

and a value of 5% is usual in these circumstances.

17.22.1.2 Voltage Controlled Overcurrent Protection

This protection is applied as remote backup to the downstream

overcurrent protection in the event of protection or breaker

failure conditions. This ensures that the generator will not

continue to supply the fault under these conditions.

At normal voltage, the current setting must be greater than the

maximum generator load current of 328A. A margin must be

allowed for resetting of the relay at this current (reset ratio =

Generator Data

KVA KW PF

Rated

Voltage

Rated

Current

Rated

Frequency

Rated

Speed

Prime Mover

Type

6250 5000 0.8 11000 328 50 1500 Steam Turbine

Generator Parameters

Generator

Type

p.u.

Xd'

p.u.

CT Ratio VT Ratio

Salient Pole 2.349 0.297 500/1 11000/110

Network Data

Earthing

Resistor

Maximum Earth Fault

Current

Minimum Phase Fault

Current

Maximum Downstream Phase

Fault Current

31.7W 200A 145A 850A

Existing Protection

Overcurrent Settings Earth Fault Settings

CT Ratio

Characteristic Setting TMS Characteristic Setting

TMS

200/1 SI 144A 0.176 SI 48A 0.15

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Chapter 17



Generator and Generator Transformer Protection

17-29

95%) and for the measurement tolerances of the relay (5% of I

under reference conditions), therefore the current setting is

calculated as:

vcset

5.362

05.1

95.0

328

The nearest settable value is 365A, or

0.73In.

The minimum phase-phase voltage for a close-up single-phase

to earth fault is 57%, so the voltage setting

must be less

than this. A value of 30% is typically used, giving

= 33V.

The current setting multiplying factor

K must be chosen such

that

is less than 50% of the generator steady-state current

contribution to an uncleared remote fault. This information is

not available (missing data being common in protection

studies). However, the maximum sustained close-up phase

fault current (neglecting AVR action) is 145A, so that a setting

chosen to be significantly below this value will suffice. A value

of 87.5A (60% of the close-up sustained phase fault current) is

therefore chosen, and hence K = 0.6. This is considered to be

appropriate based on knowledge of the system circuit

impedances. The TMS setting is chosen to co-ordinate with

the downstream feeder protection such that:

x for a close-up feeder three-phase fault, that results in

almost total voltage collapse as seen by the re

lay

x for a fault at the next downstream relay location, if the

relay voltage is less than the switching voltage

It should also be chosen so that the generator cannot be

subjected to fault or overload

current in excess of the stator

short-time current limits. A curve should be provided by the

manufacturer, but IEC 60034-1 demands that an AC

generator should be able to pass 1.5 times rated current for at

least 30 seconds. The operating time of the downstream

protection for a three-phase fault current of 850A is 0.682s, so

the voltage controlled relay element should have a minimum

operating time of 1.09s (0.4s grading margin used as the relay

technology used for the downstream relay is not stated – see

Table 9.2). With a current setting of 87.5A, the operating time

of the voltage controlled relay element at a TMS of 1.0 is:

s01.3

5.87

850

14.0

02.0



Therefore a TMS of:

362.0

01.3

09.1

is required. Use 0.375, nearest available setting.

17.22.1.3 Stator Earth Fault Protection

The maximum earth fault current, from Table 17.2, is 200A.

Protection for 95% of the winding can be provided if the relay is

set to detect a primary earth fault current of 16.4A, and this

equates to a CT secondary current of 0.033A. The nearest

relay setting is 0.04A, providing protection for 90% of the

winding.

The protection must grade with the downstream earth fault

protection, the settings of which are also given in Table 17.2.

At an earth fault current of 200A, the downstream protection

has an operation time of 0.73s. The generator earth fault

protection must therefore have an operation time of not less

than 1.13s. At a TMS of 1.0, the generator protection relay

operating time will be:



200

14.0

02.0

= 2.97s, so the required TMS is

38.0

97.2

13.1

Use a setting of 0.4, nearest available setting.

17.22.1.4 Neutral Voltage Displacement Protection

This protection is provided as back-up earth-fault protection

for the generator and downstream system (direct-connected

generator). It must therefore have a setting that grades with

the downstream protection. The protection is driven from the

generator star-connected VT, while the downstream protection

is current operated.

It is therefore necessary to translate the current setting of the

downstream setting of the current-operated earth-fault

protection into the equivalent voltage for the NVD protection.

The equivalent voltage is found from the formula:





VTratio

epe

eff

3uu

V6.45

100

37.3148

where:

eff

= effective voltage setting

= downstream earth fault current setting

= earthing resistance

Hence a setting of 48V is acceptable. Time grading is

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Network Protection & Automation Guide

17-30

required, with a minimum operating time of the NVD

protection of 1.13s at an earth fault current of 200A. Using

the expression for the operation time of the NVD element:



1

where:

snvd

and

V = voltage seen by relay

snvd

= relay setting voltage

the value of K can be calculated as 3.34. The nearest settable

value is 3.5, giving an operation time of 1.18s.

17.22.1.5 Loss of Excitation Protection

Loss of excitation is detected by a mho impedance relay

element, as detailed in Section 17.16.2. The standard settings

for the P340 series relay are:

VTratio

CTratio

5.0 secondary quantities

:

uuu

5.14

100

500

36.19297.05.0

VTratio

CTratio

227

100

500

36.19349.2

The nearest settings provided by the relay are

:

227

5.14

The time delay t

should be set to avoid relay element

operation on power swings and a typical setting of 3s is used.

This value may need to be modified in the light of operating

experience. To prevent cyclical pick-up of the relay element

without tripping, such as might occur during pole-slipping

conditions, a drop-off time delay tdo1 is provided and set to

0.5s.

17.22.1.6 Negative Phase Sequence Current Protection

This protection is required to guard against excessive heating

from negative phase sequence currents, whatever the cause.

The generator is of salient pole design, so from IEC 60034-1,

the continuous withstand is 8% of rating and the

t value is

20s. Using Equation 17.1, the required relay settings can

found as

>> = 0.05 and K = 8.6s. The nearest available

values are

>> = 0.05 and K = 8.6s. The relay also has a

cooling time constant

reset

that is normally set equal to the

value of K. To co-ordinate with clearance of heavy asymmetric

system faults, that might otherwise cause unnecessary

operation of this protection, a minimum operation time

min

should be applied. It is recommended to set this to a value of

1. Similarly, a maximum time can be applied to ensure that

the thermal rating of the generator is not exceeded (as this is

uncertain, data not available) and to take account of the fact

that the P343 characteristic is not identical with that specified

in IEC 60034. The recommended setting for

max

is 600s.

17.22.1.7 Overvoltage Protection

This is required to guard against various failure modes, e.g.

AVR failure, resulting in excessive stator voltage. A two-stage

protection is available, the first being a low-set time-delayed

stage that should be set to grade with transient overvoltages

that can be tolerated following load rejection. The second is a

high-set stage used for instantaneous tripping in the event of

an intolerable overvoltage condition arising.

Generators can normally withstand 105% of rated voltage

continuously, so the low-set stage should be set higher than

this value. A setting of 117.7V in secondary quantities

(corresponding to 107% of rated stator voltage) is typically

used, with a definite time delay of 10s to allow for transients

due to load switch-off/rejection, overvoltages on recovery from

faults or motor starting, etc.

The second element provides protection in the event of a large

overvoltage, by tripping excitation and the generator circuit

breaker (if closed). This must be set below the maximum

stator voltage possible, taking into account saturation. As the

open circuit characteristic of the generator is not available,

typical values must be used. Saturation will normally limit the

maximum overvoltage on this type of generator to 130%, so a

setting of 120% (132V secondary) is typically used.

Instantaneous operation is required. Generator manufacturers

are normally able to provide recommendations for the relay

settings. For embedded generators, the requirements of the

local Utility may also have to be taken into account. For both

elements, a variety of voltage measurement modes are

available to take account of possible VT connections (single or

three-phase, etc.), and conditions to be protected against. In

this example, a three-phase VT connection is used, and

overvoltages on any phase are to be detected, so a selection of

‘Any’ is used for this setting.

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Chapter 17



Generator and Generator Transformer Protection

17-31

17.22.1.8 Underfrequency Protection

This is required to protect the generator from sustained

overload conditions during periods of operation isolated from

the Utility supply. The generating set manufacturer will

normally provide the details of machine short-time capabilities.

The example relay provides four stages of underfrequency

protection. In this case, the first stage is used for alarm

purposes and a second stage would be applied to trip the set.

The alarm stage might typically be set to 49Hz, with a time

delay of 20s, to avoid an alarm being raised under transient

conditions, e.g. during plant motor starting. The trip stage

might be set to 48Hz, with a time delay of 0.5s, to avoid

tripping for transient, but recoverable, dips in frequency below

this value.

17.22.1.9 Reverse Power Protection

The relay setting is 5% of rated power.

VTratioCTratio

100500

10505.0

This value can be set in the relay. A time delay is required to

guard against power swings while generating at low power

levels, so use a time delay of 5s. No reset time delay is

required.

A summary of the relay settings is given in Table 17.3.

Protection Quantity Value

120%

Differential protection

150%

0.04

Stator earth fault

TMS 0.4

snvd

48V

Neutral Voltage Displacement

K 3.5

-14.5

227

Loss of excitation

d01

0.5s

vcset

0.73

K 0.6

Voltage controlled overcurrent

TMS 0.375

I2>> 0.05

K 8.6s

reset

8.6s

min

1.5s

Negative phase sequence

max

600s

V> meas mode three-phase

V> operate mode any

V>1 setting 107%

V>1 function DT

V>1 time delay 10s

V>2 setting 120%

V>2 function DT

Overvoltage

V>2 time delay 0sec

F<1 setting 49Hz

F<1 time delay 20s

F<2 setting 48Hz

Underfrequency

F<2 time delay 0.5s

P1 function reverse power

P1 setting 5W

P1 time delay 5s

Reverse Power

P1 DO time 0s

Table 17.3: Small generator protection example – relay settings

17.22.2 Large Generator Transformer Unit Protection

The data for this unit are given in Table 17.4. It is fitted with

two main protection systems to ensure security of tripping in

the event of a fault. To economise on space, the setting

calculations for only one system, that using an Alstom MiCOM

P343 relay are given. Settings are given in primary quantities

throughout.

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Network Protection & Automation Guide

17-32

Parameter Value Unit

Generator MVA rating 187.65 MVA

Generator MW rating 160 MW

Generator voltage 18 kV

Synchronous reactance 1.93 pu

Direct-axis transient reactance 0.189 pu

Minimum operating voltage 0.8 pu

Generator negative sequence capability 0.08 pu

Generator negative sequence factor, K

Generator third harmonic voltage under load 0.02 pu

Generator motoring power 0.02 pu

alarm 1.1

time delay 5

Generator overvoltage

trip 1.3

Generator undervoltage not required

Max pole slipping frequency 10 Hz

Generator transformer rating 360 MVA

Generator transformer leakage reactance 0.244 pu

Generator transformer overflux alarm 1.1 pu

Generator transformer overflux alarm 1.2 pu

Network resistance (referred to 18kV) 0.56

Network reactance (referred to 18kV) 0.0199

System impedance angle (estimated) 80 deg

Minimum load resistance 0.8

Generator CT ratio 8000/1

Generator VT ratio 18000/120

Number of generators in parallel 2

Table 17.4: System data for large generator protection example

17.22.2.1 Biased Differential Protection

The settings follow the guidelines previously stated. As 100%

stator winding earth-fault protection is provided, high

sensitivity is not required and hence

can be set to 10% of

generator rated current. This equates to 602A, and the nearest

settable value on the relay is 640A (= 0.08 of rated CT

current). The settings for

and K

follow the guidelines

in the relay manual.

17.22.2.2 Voltage Restrained Overcurrent Protection

The setting current I

set

has to be greater than the full-load

current of the generator (6019A). A suitable margin must be

allowed for operation at reduced voltage, so use a multiplying

factor of 1.2. The nearest settable value is 7200A. The factor

K is calculated so that the operating current is less than the

current for a remote end three phase fault. The steady-state

current and voltage at the generator for a remote-end three-

phase fault are given by the expressions:



ftdf

flt

nXXXnR



Where

flt

= minimum generator primary current for a multi-phase

feeder-end fault

= no load phase-neutral generator voltage

= generator d-axis synchronous reactance

= generator transformer reactance

= feeder resistance

= feeder reactance

n = number of parallel generators

Hence,

nflt

IAI 361.02893

and



 

ftdf

ftfN

flt

nXXXnR

nXXnRV





07.0

1304

A suitable value of K is therefore

3.0

2.1

361.0

A suitable value of V2set is 120% of Vflt, giving a value of

1565V. The nearest settable value is 3000V, minimum

allowable relay setting. The value of V1

set

is required to be

above the minimum voltage seen by the generator for a close-

up phase-earth fault. A value of 80% of rated voltage is used

for V1

set

, 14400V.

17.2.2.3 Inadvertent Energisation Protection

This protection is a combination of overcurrent with

undervoltage, the voltage signal being obtained from a VT on

the generator side of the system. The current setting used is

that of rated generator current of 6019A, in accordance with

IEEE C37.102 as the generator is for installation in the USA.

Use 6000A nearest settable value. The voltage setting cannot

be more than 85% of the generator rated voltage to ensure

operation does not occur under normal operation. For this

application, a value of 50% of rated voltage is chosen.

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Chapter 17



Generator and Generator Transformer Protection

17-33

17.22.2.4 Negative Phase Sequence Protection

The generator has a maximum steady-state capability of 8% of

rating, and a value of

of 10. Settings of I

2cmr

= 0.06

(=480A) and

= 10 are therefore used. Minimum and

maximum time delays of 1s and 1300s are used to co-ordinate

with external protection and ensure tripping at low levels of

negative sequence current are used.

17.22.2.5 Overfluxing Protection

The generator-transformer manufacturer supplied the

following characteristics:

Alarm

1.1!

Trip

2.1!

inverse time characteristic

Hence the alarm setting is

315

05.1

18000 u

A time delay of 5s is used to avoid alarms due to transient

conditions. The trip setting is:

360

2.1

18000 u

A TMS value of 10 is selected, to match the withstand curve

supplied by the manufacturer.

17.22.2.6 100% Stator Earth Fault Protection

This is provided by a combination of neutral voltage

displacement and third harmonic undervoltage protection. For

the neutral voltage displacement protection to cover 90% of the

stator winding, the minimum voltage allowing for generator

operation at a minimum of 92% of rated voltage is:

1.956

1.01892.0

Use a value of 935.3V, nearest settable value that ensures 90%

of the winding is covered. A 0.5s definite time delay is used to

prevent spurious trips. The third harmonic voltage under

normal conditions is 2% of rated voltage, giving a value of:

8.207

01.018

The third harmonic undervoltage protection setting must be

below this value, a factor of 80% is acceptable. Use a value of

166.3V and a time delay of 0.5s. Inhibition of the element at

low generator output must be determined during

commissioning.

17.22.2.7 Loss of Excitation Protection

The client requires a two-stage loss of excitation protection

function. The first is alarm only, while the second provides

tripping under high load conditions. To achieve this, the first

impedance element of the P343 loss of excitation protection

can be set in accordance with the guidelines of Section

17.16.3 for a generator operating at rotor angles up to 120

,as

follows:

: 

245.075.0

666.15.0

Use nearest settable values of 1.669: and 0.253:. A time

delay of 5s is used to prevent alarms under transient

conditions. For the trip stage, settings for high load are used,

as given in Section 17.16.3:

: 

1406.075.0

727.1

65.187

MVA

The nearest settable value for

is 1.725:A time delay of

0.5s is used.

17.22.2.8 Reverse Power Protection

The manufacturer-supplied value for motoring power is 2% of

rated power. The recommended setting is therefore 1.6MW.

An instrumentation class CT is used in conjunction with the

relay for this protection, to ensure accuracy of measurement.

A time delay of 0.5s is used. The settings should be checked at

the commissioning stage.

17.22.9 Over/Under-Frequency Protection

For under-frequency protection, the client has specified the

following characteristics:

x Alarm: 59.3Hz, 0.5s time delay

x 1

stage trip: 58.7Hz, 100s time delay

x 2

stage trip: 58.2Hz, 1s time delay

Similarly, the overfrequency is required to be set as follows:

x Alarm: 62Hz, 30s time delay

x Trip: 63.5Hz, 10s time delay

These characteristics can be set in the relay

directly.

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Network Protection & Automation Guide

17-34

17.22.2.10 Overvoltage Protection

The generator manufacturers’ recommendation is:

x Alarm: 110% voltage for 5s

x Trip: 130% voltage, instantaneous

This translates into the following relay settings:

x Alarm: 19800V, 5s time delay

x Trip: 23400V,

0.1s time delay

17.22.2.11 Pole Slipping Protection

This is provided by the method described in Section 17.7.2.2.

Detection at a maximum slip frequency of 10Hz is required.

The setting data, according to the relay manual, is as follows:

x Forward Reach,



24.0

22.002.0

TnA

ZZZ

x Reverse Reach,

652.0

GENB

x Reactance Line,,

198.0

22.09.0

9.0

where:

= generator transformer leakage current

= network impedance

The nearest settable values are 0.243: 0.656: and 0.206:

respectively.

The lens angle setting, D, is found from the equation:





min

54.1

tan2180

and, substituting values,

5.62

min

Use the minimum settable value of 90

. The blinder angle, T

is estimated to be 80

, and requires checking during

commissioning. Timers T

and T

are set to 15ms as

experience has shown that these settings are satisfactory to

detect pole slipping frequencies up to 10Hz.

This completes the settings required for the generator, and the

relay settings are given in Table 17.5. Of course, additional

protection is required for the generator transformer, according

to the principles described in Chapter 16.

Protection Quantity Value Protection Quantity Value

8% P1 function

reverse

power

100% P1 setting 1.6MW

K1 0% P1 time delay 0.5s

Differential

protection

150%

Reverse Power

P1 DO time 0s

n3H<

166.3V Dead Mach I> 6000A

100% Stator earth

fault

n3H

delay 0.5s

Inadvertent

energisation

Dead Mach V< 9000V

snvd

935.3V Z

0.243W

Neutral Voltage

Displacement

Time Delay 0.5s Z

0.656W

-0.245W Z

0.206W

1.666W a 90°

5s q 80°

-0.1406W T

15ms

1.725W

Pole Slipping

Protection

15ms

0.5s F>1 setting 62Hz

Loss of Excitation

DO1

0s F>1 time delay 30s

set

7200A F>2 setting 63.5Hz

K 3

Overfrequency

F>2 time delay 10s

1set

14400V P1 function

reverse

power

Voltage restrained

overcurrent

2set

3000V P1 setting 1.6MW

I2>> 0.06 P1 time delay 0.5s

Reverse Power

P1 DO time 0s

reset

10 F<1 setting 59.3Hz

min

1s F<1 time delay 0.5s

Negative phase

sequence

max

1300s F<2 setting 58.7Hz

V> meas

mode

three-

phase

F<2 time delay 100s

V> operate

mode

any F<3 setting 58.2Hz

V>1 setting 19800V

Underfrequency

F<3 time delay 1s

V>1 function DT

V>1 time

delay

V>2 setting 23400V

V>2 function DT

Overvoltage

V>2 time

delay

0.1s

Table 17.5: Relay settings for large generator protection example

17.23 REFERENCE

[17.1] Survey of Rate of Change of Frequency Relays and

Voltage Phase Shift Relays for Loss of Mains Protection.

ERA Report 95-0712R, 1995. ERA Technology Ltd.

copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid.

Chapter 17



Generator and Generator Transformer Protection

17-35

copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid.

ALSTOM T&amp;D. Network Protection And Automation Guide (NPAG)

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ALSTOM T&D. Network Protection And Automation Guide (NPAG)