Protection Application Handbook (англ. яз.)

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PROTECTION RELAYS SETTING

Setting of Protection

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Figure 6. RADSS/REB 103 operating principle for one phase.

RADSS setting is made by adjusting the so called slope, adjusted

on resistors R

, which give the stability line of the protection and

the resistor R

d11

which gives the total resistance of the differen-

tial circuit and thus the operation level of differential relay d

. Set-

ting of these resistors give the operation value of the protection

together with setting of the separate start relay S

, provided to

give two separate conditions for tripping. The start relay is set

higher than maximum through load thus providing stability for

open CT circuits under load conditions. REB 103 has ﬁxed set-

tings of slope and R

d11

resistor due to the design ensuring that

the relay is always suitable for all switchgears and short circuit

levels.

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Transformer differential protection

Transformer differential protection relays are percentage restraint

differential relays, where operation level is in percent of mea-

sured current for external faults which gives a secure through

fault stability. This is a necessary requirement for transformer dif-

ferential protection relays as normal differential currents occurs

due to tap changers (TC).

For internal faults the sensitivity will be in percent of the trans-

former rated current.

The percentage setting of Transformer Differential relays shall be:

Max. TC error (from mid-end position) + Errors from CT and aux

CT + 15 (margin).

A high set unrestraint stage provides extremely fast tripping for

heavy internal faults. The unrestraint stage must be set above

maximum through fault current and above maximum inrush cur-

rent. If inrush currents are not known the following table can be

used as a general guide.

Connection Rated power Energizing from

High voltage side

- <10 MVA 20 x

Yy 10-100 MVA 13 x

Yy >100 MVA 8 x

Yd - 13 x

Dy <100 MVA 13 x

Dy >100 MVA 8 x

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Figure 7. The differential relay for a transformer needs to have phase angle

shift compensation and must have a percentage restraint to operate correct-

ly for through faults as the tap changer percentage error will be increased at

through faults. Stabilization is achieved with a summation (I1 + I2)/2

Restricted earth-fault protection

As earth-fault protection on solidly earthed transformers a Re-

stricted Earth Fault protection (REF) is often provided. ABB REF

type RADHD or SPAE 010 are high impedance protection, stabi-

lized against maloperation by setting the operation voltage just

above the maximum achieved voltage during external faults with

one CT core fully saturated, which is the worst case. The principle

is simple and will thus give fast operating relays. However the

type can only be used for differential relays where the same ratio

is available for all involved CT’s.

A voltage dependent resistor is connected across the relay to lim-

it overvoltages at internal faults as high voltages will be achieved

at internal faults as current transformers due to the high internal

resistance will immediately saturate with high CT output voltages

as a result.

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The required voltage setting U

is selected as:

Figure 8. The connection and principle for a Restricted Earth Fault protec-

tion (REF)

~ I

Fmax

+ R

) where

Fmax

is max through fault current at an external fault

= Current transformer secondary resistance

= Maximum cable loop resistance seen from the summation

point

Calculated required voltage setting will give a primary sensitivity

Ip:

= n • (I

+ I

res

+∑I

) where

= relay current is 20 mA +24° to +45° dependent

on the selected relay operating voltage

res

= current through voltage dependent resistor MXA

= sum of magnetizing current to all CT's. Angle of magnetizing

current is -34° to -60° dependent on relay operation voltage, type

of CT and the core data.

n = current transformer ratio

Normally a restricted earthfault protection will get a sensitivity of

5-15% of transformer rated current with higher values (lower sen-

sitivity) when lower CT ratios are provided as the inﬂuence of

magnetizing current is increasing.

RELATIVE SELECTIVE PROTECTION RELAYS

Setting of Protection

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Pilot wire differential protection.

ABB pilot wire differential protection type RADHL communicates

with remote end RADHL on a pair of pilot wires. The relay has a

ﬁxed sensitivity for all types of faults, where the sensitivity differs

between fault types because of the summation transformer. An-

other relay based on the same principle is SOLKOR Rf from Rey-

rolle protection.

No setting is required for RADHL if no starting relays are provid-

ed. The starting relays shall (when provided), with sufﬁcient mar-

gin, be set above maximum load current. If no starting relays are

provided the relay will operate for open or short circuited pilot

wires as the sensitivity will be below rated current in most phas-

es. Due to the summation type input transformer the sensitivity

will vary with fault type.

3. RELATIVE SELECTIVE PROTECTION RE-

LAYS

Overcurrent relays

Overcurrent relays are used as Back-up protection for short cir-

cuits and earth-faults for most types of objects. Overcurrent re-

lays are relative selective protection relays where selectivity is

achieved by a grading of current and/or time setting.

Overcurrent relays can be current selective, time selective or cur-

rent and time selective.

Current selectivity

Current selectivity means that two overcurrent relays are made

selective by grading of current setting, i.e. relay at A below is set

high enough not to detect faults at F3 or F4 which should be

tripped by the relay at B.

RELATIVE SELECTIVE PROTECTION RELAYS

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Figure 9. Current selective relays at A and B.

In practice this method can only be used when impedance R1 +

jX1 is of a relatively high value and thus limits fault current much

more than the variation in source impedance. This is normally

only the case where transformers are involved and a high-set

stage with a well deﬁned limited reach can be used.

For example an instantaneous high-set stage on relay at B above

would detect faults in F3 but not in F4. A low-set delayed stage

would then detect faults at F4 and further on in the system. Relay

A can then be set on a higher value than relay B instantaneous

stage and need thus only be time selective against relay B instan-

taneous stage, as current selectivity is achieved between relay at

B and low set stage on relay at A.

Time selectivity

Time selectivity is used at many occasions to get selectivity be-

tween independent time delayed current protection relays and

fuses.

Figure 10. A Fuse and time selective overcurrent protection.

For the simple radial power system above, fuse tB will blow ﬁrst.

A time delay t1 of 150-250 ms is then required on relay B to allow

this to reset after the fuse blowout.

Relay at A must then be set selective to relay at B by setting a

time t2 which allows relay at A to reset for a fault successfully

cleared by relay at B. Required margins are discussed below.

Disadvantage with time selective protection is that times start

adding and back-up trip times will be very long for a fault between

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A and B where fault current is highest as the fault is closest to the

source.

Current and time selectivity

lnverse type protection relays with Normal, Very or Extremely in-

verse characteristic have operating time dependent of fault cur-

rent. Inverse type protection relays are simultaneously time and

current selective.

Figure 11. Inverse time delayed relays are at the same time current and time

selective.

Such relays can decrease back-up tripping times in a system

since operation time is decreasing with increasing fault levels.

In a radial system as below where current selectivity cannot be

achieved between different relays, inverse type characteristics

will give an advantage as shown by the selectivity chart below.

Comparison of independent (deﬁnite) time-lag relays and inverse

time-lag relays:

Deﬁnite time-lag. Inverse time-lag.

Easy to apply Selectivity plan elaborate

Simple selectivity plan Distribution of load and fault currents affects the

tripping time.

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Short circuit protection

When overcurrent relays are used as short circuit protection, fol-

lowing aspects must be considered at the setting.

Current settings shall:

- be high enough not to risk maloperation at maximum load cur-

rents.

- be low enough to give secure operation at minimum fault current

(tripping requirement)

Generally one shall not use lower current setting than required to

detect the occurring fault currents as this will only increase the

risk of unnecessary operations.

Margin to load

When selecting current setting, sufﬁcient margin must be given

for maximum load currents. The margin allows the current relay

to reset when fault is tripped by an other protection and only load

current is ﬂowing again or after e.g. a transformer inrush or a mo-

tor start. For modern static relays the reset ratio can be 90-98%

whereas for electromechanical relays the resetting ratio can be

70% or even less. This means that a setting of 1.3 times max load

can be sufﬁcient for a static relay, whereas an electromechanical

relay requires a setting of 1.5 times max load. For H.V. side of

transformers setting should be 1.3 - 2 times load current for in-

verse type protection relays and 3-5 times load current for deﬁnite

time delayed protection relays to prevent maloperation for trans-

former inrush currents.

Tripping time independent of

the actual short circuit power.

Large variations in short circuit power may give

long tripping time.

Good correspondence between tripping time and

short time current rating of primary equipment.

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Margin to other protection relays

Figure 12. Setting of overcurrent relays must provide margin to maximum

load current.

Further to margin to load, a short circuit protection selective to a

short circuit protection in a remote station, may not detect faults

not detected by the protection in remote station. This means a

setting of I1, according to ﬁg, to: I

1set

+ I

2set

+ I

3set

+ I

4set

where:

2set

> I

3set

4set

It should be noted in the above formula that the load currents

have a lower phase angle than fault currents, which can be used

to get a low set value when problem arises with sensitivity under

minimum conditions.

When directional protection relays are used, the directional ele-

ment, normally with operation angle of 60° lagging, should be set

lower than 0.25-0.5 times the current relay setting, to ensure a

secure and quick operation of the directional element at opera-

tion current of the protection. The directional relay should howev-

er preferably not be operated during normal load.

The 60° characteristic achieved on ABB directional relays, when

used as short circuit protection, gives operation for other angles

Ø when:

I > I

/cos (60- Ø).

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Figure 13. Directional short circuit protection, e. g. type RXPE 42 have

60-65° angle on characteristic for maximum sensitivity.

Instantaneous stage

An instantaneous stages can be used as short circuit protection

for passive loads as motors, reactors capacitors etc. with no or

limited outfeed of fault current. It can be also be used for trans-

formers, where the impedance of the transformer gives a limita-

tion of the fault current to a, for through faults, well deﬁned value,

little dependent of the source variations.

Figure 14. For a transformer an instantaneous stage can be used as the im-

pedance of the transformer will limit the fault current at a low voltage fault.

For the above transformer a low voltage fault will have a higher

fault power than: