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

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Chapter 20  System Integrity Protection Schemes

20-5

Figure 20.4: WAMPAC opportunities

Figure 20.4 shows applications based on the use of

synchrophasors and state estimation (SE) for oscillatory

stability, voltage stability, transient stability (or angular

instability prediction), and system restoration.

The technology can also offer event triggering based on

overcurrent, under/overvoltage, under/over-frequency and

under/over-rate of change of frequency.

20.3.1.1 Synchrophasors for Oscillatory Stability

Synchrophasors can be used for oscillatory stability detection

designed to detect slower inter-area system oscillations. These

are characterised by power oscillations between two areas of

generation, running at slightly different speeds and following

small system perturbations such as load switching or tap

changes. If there is insufficient system damping, these

oscillations do not die away and can escalate leading to

potential out-of-step conditions if no pre-emptive action is

taken. If the phasor measurement units feature frequency

tracking that can accurately measure and track small changes

in signal frequencies, this can provide an accurate

measurement for the fast detection of small signal oscillations

to initiate damping actions.

Figure 20.5: PMU data viewed in a simple visualisation tool

Synchronised measurements allow the comparison of the

phase of the oscillatory modes to determine the parts of the

system that are oscillating with respect to each other, and

enable stabilising actions to be initiated as shown in Figure

20.6.

Figure 20.6: Oscillatory instability prediction

20.3.1.2 Synchrophasors for Voltage Stability

Synchrophasors can be used to predict voltage instability. By

comparing voltage and power transfers on the line against

specific stability margins, operators can be alerted to slow

voltage declines and take remedial actions such as switching in

reactors as shown in Figure 20.7.

Voltage

instability

prediction

~10s of

seconds

Slow voltage decline

or load level?

Capacitor switching

Reactor switching

SVC setting

Undervoltage shedding

Remedial actions

Fast unit runback

Key

SVC: Static Var Compensator

Figure 20.7: Voltage instability prediction

20.3.1.3 Synchrophasors for Transient Stability

Synchrophasors can be used to defend transient stability by

predicting angular instability. By being measured in real-time

rather than estimated, generator and bus-phase angles can be

compared and stability threats can be presented to an operator

for remedial action such as controlled islanding as shown in

Figure 20.8.

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Angular

instability

prediction

~milliseconds

Frequency decline

Controlled islanding

Generator tripping

Dynamic braking

Underfrequency.

shedding

Fast load shedding

FACTS, HVDC controls

Remedial actions

Special protection

Fast unit runback

Key

FACTS: Flexible AC Transmission System

HVDC: High Voltage DC

Figure 20.8: Angle instability prediction

Figure 20.9 shows the relative phase angles from two parts of

the North American grid taken on August 14th 2003.

Figure 20.9: Phase angle divergence prior to blackout

The phase angles from the two parts of the system can be seen

diverging. A major blackout followed. This is the type of event

that the synchrophasor technology can help prevent. But what

exactly is a synchrophasor?

20.3.2 Synchronised Phasor Measurements

A phasor is a representation of a sinusoidal quantity,

representing the sinusoid as a vector rotating on the complex

plane, defined in terms of amplitude and phase. As steady

state power system quantities are sinusoids, it follows that

they can be represented by phasors. When augmented by an

accurate time synchronisation signal, time synchronised

phasors, known as synchrophasors can be produced. The

potential benefits of synchrophasor technology have long been

recognised, but it is only since enabling technologies have

developed that their effective application became reality.

In 1893, Charles Proteus Steinmetz presented a paper on a

simplified mathematical description of the waveforms of

alternating electricity. Steinmetz called his representation a

phasor, and phasor notation became widely used in the field of

electrical power systems (see section 3.4.1). The time

synchronisation of phasors in what were to become known as

phasor measurement units evolved and in 1988 the first

phasor measurement units based on Steinmetz’s technique,

were developed. The first commercial phasor measurement

unit was launched in 1992.

The deployment of phasor measurement units into electrical

power systems, however, was limited initially as two main

issues could not be addressed:

x Accuracy of time synchronisation

x Cost effective, high-speed, communications

With the global positioning satellite system, the ability to time

synchronise anywhere in the world to an

accuracy of better

than a micro-second is achievable. Developments in the

telecommunication markets have brought fast Ethernet to the

substation, and with these developments, the hurdles are

overcome, and the potential of synchrophasors can be

exploited to the maximum.

20.3.3 Synchrophasor Definition

A phasor is a vector representation on the complex plane of a

sinusoidal quantity such as an alternating current.

A synchrophasor is a phasor calculated from sampled values

that are referenced to a common timing signal. The timing

signal is global, meaning that a synchrophasor measured

anywhere in the world will be referenced to the same time

signal. This enables synchrophasors to be communicated for

collation and comparison. This is the fundamental concept

behind wide-area special protection schemes.

The IEEE 1344 standard for synchrophasors was published in

1995. It was reaffirmed in 2001, but in 2005 it was

superseded by IEEE C37.118. This recognised the

developments that would facilitate the effective application of

synchrophasors to electrical power systems. IEEE C37.118

describes the standards for measurement of synchrophasors,

the method of quantifying the measurements, as well as the

testing and certification requirements for verifying accuracy. It

also prescribes the data transmission format and protocol for

synchrophasor communication.

The standard prescribes that all measurements are referenced

to an accurate one pulse per second (1pps) signal. Generally it

is anticipated that this will be derived from the global

positioning satellite system, but it can be from any external

source provided the accuracy is in accordance with the

requirements.

Phasor representation defines the complex exponential as a

point or vector on the complex plane according to the

equation:

sinjcose



The IEEE C37.118 standard specifies that the angle  is zero

degrees when the maximum of the signal to be measured

coincides with the leading edge of GPS 1pps pulse. It follows

that it will be –/2 radians (-90 degrees) if the positive zero

crossing coincides with the 1pps pulse, +/2 radians (+90

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Chapter 20  System Integrity Protection Schemes

20-7

degrees) if the negative zero crossing coincides with the 1pps

pulse, and π radians (180 degrees) when the reverse polarity

peak of the signal to be measured coincides with the 1pps

pulse.

The relationship of time domain and frequency domain signals

relative to the 1pps signal is further described in Figure 20.10,

where

)(nX

and )(nX

are the RMS real and imaginary

filtered components at a particular instance and θ is the phase

angle as per the IEEE C37.118 standard definition.

1 PPS

Peak

Xi(n)

Xr(n)

Figure 20.10: Time and frequency domain representation of

synchrophasors

The measured angle θ is valid in the range of –π to +π

radians.

A primary requirement for synchrophasors is the accuracy of

the measured phasor. The IEEE C37.118 standard defines the

total permitted vector error (TVE) for the static condition at

nominal frequency as:



X)n(XX)n(X

TVE

iirr







Where

(n) and X

(n) are the measured real and imaginary

components and

and X

are the reference values.

Levels of accuracy are specified for the permissible total vector

error as shown in Table 20.1 .

Range of influence quantity change with respect

to reference and maximum allowable TVE (in %)

for each compliance level

Level 0 Level 1

Influence

quantity

Reference

Condition

Range

TVE

(%)

Range

TVE

(%)

Signal frequency

nominal

+/- 0.5Hz 1 +/- 5Hz 1

Signal

magnitude

100% rated 80% -120% rated 1 10% -120% rated 1

Phase angle 0 radians +/-π radians 1 +/-π radians 1

Harmonic

distortion

<0.2%

(THD)

1%, any harmonic

up to 50th

1%, any harmonic

up to 50th

Range of influence quantity change with respect

to reference and maximum allowable TVE (in %)

for each compliance level

Level 0 Level 1

Influence

quantity

Reference

Condition

Range

TVE

(%)

Range

TVE

(%)

Out-of-band

interfering signal

at freq f

<0.2% of input

signal

magnitude

1% of input signal

magnitude

1% of input signal

magnitude

ff 

, where

= phasor reporting rate and

nominal

Table 20.1: Influencing quantities and allowable error limits for

compliance levels 0 – 1.

Devices offering compliance level 1 perform better in SIPS

schemes, whereas level 0 devices are intended more for

measurement purposes.

This measurement accuracy will vary with the magnitude and

frequency of the input signal and may be depicted graphically

as shown in Figure 20.11. The graph depicts a device with a

total vector error typically less than 0.4% (y-axis), consistent for

system frequency excursions off-nominal (z-axis), and

maintained for all except very low current magnitudes (x-axis).

Figure 20.11: Graphical representation of synchrophasor total vector

error

20.3.4 Synchrophasor Communication

As well as the generation of synchrophasors, the IEEE C37.118

standard also defines how the synchrophasor values are to be

communicated.

Whilst the standard does not mandate that Ethernet

communications are used for synchrophasor transmission, it is

Ethernet that often enables wide-area phasor measurement

technology, and that is reflected in this section. Some

knowledge of Ethernet communications is assumed here, but if

needed, a more detailed discussion on substation

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communications, including Ethernet, is presented in chapter

24: ‘The Digital Substation’.

Four message types associated with synchrophasor

communications are described in the standard:

x Data

x Configuration

x Header

x Command

All message types have a similar frame structure to package

the information.

The “Configuration”, “Header” and

“Command” types are used to set up the communications and

are used infrequently. The “Data” type is used for the real-

time transfer of synchrophasor values, and that will have the

largest impact on the communications system.

According to the standard, synchrophasor signals are

encapsulated into data packets, or frames, for transmission

across, say, an Ethernet network. An example of a typical data

frame is shown in Table 20.2.

Field function Field size (bytes)

Message synchronisation 2

Frame size definition 2

PMU ID code* 2

Real time timing information 8

Status information 2

Phasor data values Typically 48

System frequency measurement 2

Rate of change of system frequency 2

Digital data values 2

Frame checksum 2

Total Typically 72

Table 20.2: Synchrophasor data frame format

* The PMU ID code is set to uniquely associate the

synchrophasor values to the PMU responsible for producing

them.

The rate at which the frames are sent is defined.

x For 50Hz operation the frame repetition rate can be set

to 10, 25 or 50 frames per second

x For 60Hz operation the frame repetition rate can be set

to 10, 12, 15, 20, 30, or 60 frames per second.

The faster the rate of frame repetition, the shorter the latency

in responding to a developing system condition, allowing fa

ster

SIPS and state estimation reaction.

Clearly the more times per second that the data is sent, the

greater the impact on the Ethernet communications.

20.3.4.1 Mapping Synchrophasors to Ethernet

When mapped to Ethernet the synchrophasor phasor data

frames can use either transmission control protocol (TCP) or

user datagram protocol (UDP) according to preference. TCP is

a connection-oriented protocol. It manages message

acknowledgement, re-transmission and time out. As such it

can be considered to be reliable and ordered, but carrying

overheads. UDP is a simpler protocol that broadcasts

messages from the transmitter without checking the state of

the receiver. As such it can be considered less reliable and not

ordered, but lean. The choice will come down to the specific

requirements of the application.

The TCP or UDP mapped messages are written to and read

from using standard internet protocol (IP) input-output

functions. These functions apply a numerical identifier for the

data structures of the terminals of the communications. The

terminal is referred to as a port and the numerical identifier is

called the port number. The port number should be set to

align with the recipient phasor data concentrator (see section

20.3.7).

Other settings that apply as the phasor message is mapped to

the Ethernet layer are the IP address, subnet mask, and

gateway address.

20.3.4.2 Communication Bandwidth Requirements

It can be useful to understand how much loading the addition

of a phasor measurement unit can have on a communications

system. A typical frame length of 72 bytes has already been

mentioned. For a typical application with a frame length of 72

bytes and a repetition rate of 60 per second, the minimum

bandwidth requirement for these raw frames is, therefore,

4320 bytes per second.

Ethernet conforms to the OSI (Open System Interconnect) 7

layer model (covered in chapter 24). Some layers require extra

information to be added and so, in addition to the raw data

frames, there is an overhead associated with the OSI 7-layer

model.

For TCP/IP mapping the overhead is:

x TCP 24 bytes per frame

x IP 20 bytes per frame

x MAC 18 bytes per frame

So the TCP/IP overhead is 62 bytes of data per frame.

For UDP/IP mapping the overhead is:

x Source port 2 bytes

x Destination Port 2 bytes

x UDP length 2 bytes

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Chapter 20  System Integrity Protection Schemes

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x UDP checksum 2 bytes

x IP 20 bytes per frame

So the UDP/IP overhead is 28 bytes of data per frame.

As the C37.118 frame contains 72 bytes, the total number of

bytes per frame is 134 for TCP and 100 for

UDP.

With 8 bits per byte, the resulting bandwidth of the maximum

frame rate is thus:

x 1072 * 50 = 53.6kbps for a maximum frame rate of 50

frames per second (TCP)

x 1072 * 60 = 64.32kbps for a

maximum frame rate of

60 frames per second (TCP)

x 800 * 50 = 40kbps for a maximum frame rate of 50

frames per second (UDP)

x 800 * 60 = 48kbps for a maximum frame rate of 60

frames per second (UDP)

These figures

are not absolute, but they can be of benefit in

planning network requirements when installing and operating

phasor measurement units.

20.3.5 Phasor Measurement Units

Synchrophasors are generated in phasor measurement units.

A typical phasor measurement unit architecture is shown in

Figure 20.12.

Ethernet

processor

GPS

Receiver

Protection and

measurement

processors

Data frames over

serial or Ethernet

(TCP/UDP)

A/D

Digitised

samples

Analogue

electrical

signals

1 PPS

IRIG-B

IEEE C37.118 data

PMU

Figure 20.12: Typical Phasor measurement unit architecture

Electrical signals to be converted into synchrophasors are

presented at the analogue inputs. They are sampled and

converted into numerical values in an analogue to digital

converter (A/D). The sampling is controlled by the

measurement processor which is synchronised to the GPS

system by a 1pps signal from a time synchronisation unit. The

numerical values representing the digitised samples are passed

to the measurement processor. The measurement processor

determines the amplitude and phase quantities required for the

synchrophasors according to their displacement from the 1pps

signal. The measurement processor also calculates the derived

quantities that are required to be presented as synchrophasors.

These include sequence components, frequency, and rate-of-

change of frequency, etc.

An IRIG-B signal from the time synchronisation unit allows the

measurement processor to accurately time-stamp the

synchrophasor values before passing them to the Ethernet

processor. The Ethernet processor frames the synchrophasor

values according to IEEE C37.118 before transmitting over

either TCP/IP or UDP/IP.

20.3.5.1 Physical Deployment of Phasor

Measurement Units

There is no need to install phasor measurement units at every

bus on the system as this will not necessarily contribute to

more efficient system operation. Indeed, too many phasor

measurement units could cause congestion on the

communications system, making data less manageable.

Phasor measurement units should be connected so that inter-

area oscillations and other critical dynamics will be correctly

monitored. They should be deployed on the network at critical

buses to ensure that a sufficient picture of the system

dynamics is available to the control centre to enable decisions

to be made. System visualisation using synchrophasors from

various parts of the system can show, for example, the

angular, frequency and voltage differences between groups of

generators. To do this, synchrophasors from various locations

need to be brought together, and one method of achieving this

is by means of phasor data concentrators, which is covered in

section 20.3.7.

20.3.6 Time Synchronisation

Phasor measurement units require accurate time

synchronisation.

IEEE-1588 describes a high-precision time protocol that can

achieve sub-microsecond accuracy for time synchronisation to

be used in measurement systems. It is an Ethernet protocol

that can be connected to a local area network (LAN). Timing

is derived from the global positioning satellite (GPS) system.

Since the synchronism is delivered by the Ethernet LAN, only

one GPS receiver is required to synchronise all devices on the

LAN. This offers potential cost benefits when compared to

using dedicated time synchronisation devices, especially as the

PMUs are typically connected to the Ethernet for the

transmission of synchrophasors. Given the criticality of

delivering the time synchronisation signal, however, it may be

more conservative to apply dedicated time synchronisation

devices into the substation using connections that are separate

to the LAN. A typical time synchronisation device might

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provide a one-pulse-per-second (1pps) signal, derived from

the GPS signals, in order to provide precise alignment of the

synchrophasors. To combat the effects of electrical

interference in the substation environment, the 1pps signal is

generally presented as a fibre-optic signal. The accuracy is

typically better than 0.1s. Although the 1pps signal is very

accurate (Figure 20.13), the pulse on it only signifies that

another second has passed (or is about to start). In order that

the phasor measurement unit can provide an accurate time

stamp for the synchrophasors, it is necessary to provide an

additional ‘real’ time signal. This is achieved with an IRIG-B

output, which delivers coordinated universal time (UTC) for

very accurate time stamping. It is quite likely that the time

synchronisation device will feature multiple outputs and be

capable of synchronising multiple PMUs and merging units,

providing substation-wide timing information.

Figure 20.13: 1pps accuracy

The GPS system consists of more than 20 satellites rotating in

orbit above the earth. The satellites are not in geo-stationary

orbit, and so the constellation that can be ‘seen’ is constantly

changing. In general, up to 7 satellites can be ‘seen’ at any

time. When GPS time synchronising receivers are energised,

they need to initialise their timing algorithms. Generally, this

requires that at least 4 satellites are in view for a short while.

In order to receive the signals from the GPS satellites, an

antenna is required. This needs to be mounted externally. A

mounting pole is generally used as shown Figure 20.14.

Mounting pole / mast

is to be earthed to

ma in building earth

Note

Earth cable to be <=10m

Earth cable to be 10mm

Lightning

arrester

See note

See detail

See note

Figure 20.14: Antenna connection details

It is vital that the receiving antenna has the best possible

mounting location to maintain reception with as many

satellites as possible, thus the ideal mounting is shown in

Figure 20.15.

Figure 20.15: GPS antenna required line of sight

The antenna should be mounted so that it is above the roofline

of the building to which it is attached, ensuring that there is a

360º horizontal view and a 150º vertical view of the sky (a

masking angle of 15º with respect to the horizon is the

maximum that should be permitted). Ideally there should be

no obstructions in view such as metal structures or buildings.

If the masking angle is greater than 15º with respect to the

horizon (i.e. if is a large obstruction) the antenna must be re-

sited or mounted on a longer antenna pole.

Due to the requirement for ensuring such a clear view of the

GPS constellation, the antenna is likely to be the highest

component in the vicinity. As such it is exposed to lightning,

and suitable protection is required. A lightning arrestor is

recommended for protection.

20.3.7 Phasor Data Concentrators

As shown in Figure 20.16, a phasor network consists of phasor

measurement units (PMU) dispersed throughout the electricity

system and connected to an energy management system via

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Chapter 20  System Integrity Protection Schemes

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phasor data concentrators (PDC). Phasor data concentrators

are devices which collect data from a number of phasor

measurement units. They convert such data into a single data

stream for onward transmission. Phasor measurement units

are connected to a phasor data concentrator at either the

substation or the control centre level.

Phasor data concentrators connect to supervisory control and

data acquisition (SCADA) systems and/or energy management

systems (EMS) at the central control facility to provide the

synchrophasor information for the wide-area applications.

PMU

PDC

GPS

Receiver

GPS

Receiver

PMU

Visualisation

Software

PMU

Substation A Substation B

From other

substations

Figure 20.16: PMU and PDC architecture

The complete network requires rapid transfer of data within

the frequency of sampling of the synchrophasor data.

The phasor data concentrator correlates the data, and controls

and monitors the phasor measurement units. It also serves to

archive the data, which is essential in the event that post-

disturbance analysis might be undertaken in order to

determine the root causes of cascade events. At the central

control facility, the SCADA/EMS system presents system-wide

data on all generators and substations in the system with

frequent regular updates. These updates provide for a

visualisation of the system which facilitates response-based

schemes.

20.3.8 System Visualisation

System visualisation enhances wide-area schemes. Figure

20.17, Figure 20.18, and Figure 20.19, show visualisations of

electrical networks as presented on an advanced energy

management system.

Figure 20.17: Stability state: annunciating voltage contours, weak

elements and possible remedial actions

Figure 20.18: Visualisation of inter-area oscillations: frequency,

severity and damping

Figure 20.19: Angular separation across transmission lines: alerts to

dispatchers

The figures show how phasor measurement units are providing

EMS software with synchrophasor values and how virtual

phase-meters connected to the lines give a clear picture of the

real-time phase differences between buses. If the angular

displacement exceeds a preset value, dispatchers are informed

of the violation and the options available to them for remedial

action.

System visualisation of real-time data realised thanks to wide-

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Network Protection & Automation Guide

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area technology provides power system operators greater

awareness, and hence more precise control of the system.

Underpinning this wide-area technology is the capability to

accurately time synchronise the phasor measurement units.

20.4 NON-SYNCHRONISED SYSTEM

INTEGRITY PROTECTION SCHEMES

The system integrity protection schemes described in the

previous section require highly accurate time synchronisation

and fast communications infrastructure. One might be

tempted to consider that system integrity protection can only

be afforded where these facilities are available. This is not,

however, the case.

The numerical busbar protection outlined in chapter 15 can be

considered as a distributed protection scheme as information is

gathered from peripheral units at various points on the system

for transmission to a central unit where protection monitoring

and control is managed. This shows how distributed

intelligence can work, and by increasing the geographical

spread of other suitable devices, wide-area schemes are the

next logical step.

Recognising however that sometimes information is available

only from a single point in the system, system integrity

protection schemes have been developed that require neither

communications, nor accurate time synchronisation.

By taking signal inputs from single points in the power system,

and by using special filters and techniques such as fuzzy logic,

predictive out-of-step or loss of synchronism conditions can be

detected and consequently acted upon to maintain system

stability. Similar techniques can be used to detect and act on

changes to system topology such as loss of power corridor.

By adding in busbar protection and relabeling the horizontal

axis in Figure 20.2 , the communication requirement of system

integrity protection can be highlighted, as shown in Figure

20.20.

Local Centralised

Figure 20.20: Communications requirements for system integrity

protection schemes.

This shows ‘local’ IED system integrity protection schemes that

do not require any communications, and these form the

subject of the rest of this chapter.

20.4.1 Single-point special protection

In countries where large sources of power generation are

geographically far from the principal loads, so-called

transmission corridors of power provide the routes for the

transmission of that power. One example of this is the Hydro-

Québec network in Canada as shown in Figure 20.21.

Figure 20.21: Hydro-Quebec 735kV series-compensated transmission

system (reproduced courtesy of Hydro-Quebec)

Reliability of transmission of power on such systems can be

achieved by the addition of series compensation and shunt

reactors, but these bring added complexity. Protection against

system disturbances may be provided to some extent by

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Chapter 20  System Integrity Protection Schemes

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frequency relays or voltage relays set to initiate actions such as

load-shedding on under-frequency conditions, but these may

not be sufficient in themselves for all applications and

sophisticated system integrity protection schemes have been

developed to complement them. Two particular examples that

do not require communications are described in sections

entitled 20.4.2 System Topology Changes and 20.4.3 System

Synchronism S

tability. The former describes an example of an

event-based system integrity protection scheme looking for

changes in system topology. The latter describes an example of

a response-based system integrity protection scheme looking

for system instability.

Both of these system integrity protection schemes are able to

anticipate system-threatening conditions using local variables

only. They are based on Kalman filters and fuzzy-logic multi-

criteria algorithms. These system integrity protection schemes

are applicable to large power systems prone to transient and

dynamic instabilities.

20.4.2 System Topology Changes

Detecting topology changes such as open line conditions

allows timely initiation of system defence plans for severe

contingencies such as a loss of transmission corridor. In the

absence of communications, signalling an open line condition

from a remote terminal is not possible and so, detecting a loss

of corridor caused by a remote terminal action using only

locally available signals can enable system stabilising actions

to be initiated.

20.4.2.1 Open Line Detection

Open line detection, like any other protection, needs to be

secure, reliable, and sufficiently fast.

To be secure, the detector should not operate in cases of low or

zero power transfer on the monitored line, distortion on line

voltages and currents during faults, fast variations in the

power flow, reversal of the power flow, power swings, sub-

synchronous resonances resulting from the parallel

combination of shunt reactors and series capacitors, nor

should it operate in the presence of harmonics.

To be reliable, the detector should detect line opening at the

remote end, line closing at the local end when already open at

the remote end, and line closing or opening with a shunt

reactor connected.

The typical speed required for open line detection operation is

two cycles or less.

As with many other aspects of electrical power systems, open

line operation can be characterised by both transient and

steady state conditions. Observation of the transient state

aspects and steady state aspects of open line conditions

reveals that transient events generally are associated with line

opening, whilst steady state phenomena are more closely

linked to closed lines.

An open line condition is very similar to a closed line which has

no active power transfer. If the relationship of critical

measured variables such as the voltage and the reactive power

are observed when the active power of a connected line

disappears, certain characteristics become apparent. Figure

20.22 shows that, for a given line length, an operating point

(consisting of the angle shift and the voltage ratio between its

ends) can be found so that, as seen from the sending end,

both active and reactive powers disappear.

Angle shift for zero Ps and Qs (degrees)

Voltage ratio zero Ps and Qs

Figure 20.22: Voltage ratio and angle trajectories vary with line length

for sending end active (Ps) and reactive (Qs) powers both at zero.

Although this critical operating point can be calculated, it is

very sensitive: For short lines, say 30km, the typical

sensitivities are 45% MW per degree of angle shift and 25%

MVAr per unit of voltage ratio.

It is therefore difficult to accurately detect this condition based

on power or current measurement alone, and thus it cannot

form a reliable basis for detecting open lines.

Studying the transient state aspects of opening a line provides

a better basis for open line detection. Observing the rate of

change of active and reactive power for various system events

produces interesting results. The rate of change of power

(dP/dt, or DeltaP) can be studied for various system events

and two in particular are illustrated in Figure 20.23 and Figure

20.24.

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Network Protection & Automation Guide

20-14

DeltaP

P Ramp

Time(s)

2pu/min

1pu/min

60pu/min

0.5pu/min

Figure 20.23: Rate of change of power (DeltaP) filter response to

power flow reversal

DeltaP

Figure 20.24: Rate of change of power (DeltaP) at breaker opening

Figure 20.23 shows power transfer ramping from a positive

direction to a negative direction, thus passing through zero

without apparently any significant effect. As the power ramp

crosses zero, however, it can be seen that DeltaP reaches a

maximum value a few cycles later. Although the maximum

value of DeltaP varies according to the power slope, the

maximum is reached at nearly the same time.

Figure 20.24 shows the effect on DeltaP of suddenly opening a

line at various values of surge impedance loading. In all cases,

when the line is opened, DeltaP increases sharply from its zero

steady-state value to its maximum value.

It is apparent that observing DeltaP provides the capability for

fast reliable detection of line opening.

20.4.2.2 Implementing Open Line Detection

SUBSTATION

BUSBARS

CVT

LINE BREAKERS

SHUNT REACTOR

ICT1

ICT2

IREACTOR

CT1 CT2

LINE

CT3

LINE

DISCONNECTOR

Figure 20.25: Connections for open line detection.

Figure 20.25 shows typical inputs used by an open line

detection algorithm. The inputs are taken from a capacitive

voltage transformer (CVT) and three sets of current

transformers (CT1, CT2 associated with the circuit breakers

and CT3 associated with the shunt reactor).

The functional diagram of the open line detection is shown in

Figure 20.26. It consists of five principal elements.

x Anti-alias filtering

x Kalman filtering

x Pre-processing

x Fuzzy logic

x Output logic

Fuzzy Logic Engine

Output logic

Anti-alias filter

Kalman filters

Open Line Detection Pre-

processor

Figure 20.26: Open-line detection functional block diagram

Anti-aliasing filters limit the bandwidth of the input signals

before high speed data acquisition converts the input signals

into numeric values for provision to the principal filtering unit.

The signals are filtered to extract the fundamental phasor

components.

These vectors are used as the inputs into a Kalman Filter. A

Kalman Filter is used since it can extract the fundamental

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

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