D5.1-Part 1_List of components impacting the future ETN performance

Deliverable D5.1

Modeling requirements for the ETN

Part 1: List of components impacting the future ETN performance

Proprietary Rights Statement

This document contains information, which is proprietary to the "PEGASE" Consortium. Neither this

document nor the information contained herein shall be used, duplicated or communicated by any

means to any third party, in whole or in parts, except with prior written consent of the "PEGASE"

Consortium.

Grant Agreement Number: 211407 implemented as Large-scale Integrating Project

Coordinator: Tractebel Engineering S.A.

Project Website: http://www.fp7-pegase.eu

http://www.xxx.yyy/

Date: 11/01/2010 Page: 2

Document Name: D5.1: Modeling requirements for the ETN – Part 1: List of components

impacting the future ETN performance

ID: DEL_WP5 1_D5.1-Part_1-Modeling_requirements_for_the_ETN–

List_of_components_impacting_the_future_ETN_performance_v0

WP: 5

Task: 5.1

Revision: v0

Revision Date: 11/01/2010

Author: FGH

Diffusion list

STB, SSB and Coordinator

Approvals

Name Company Date Visa

Author

Vadims Strelkovs

Vladimir Chuvychin

Antans Sauhats

Dmitrij Lubarskyi

Alexander Rubtsov

Oliver Scheufeld

Fekadu Shewarega

RTU

RTU

RTU

ESP

ESP

FGH

UDE

Task Leader Hendrik Vennegeerts

Oliver Scheufeld FGH

WP Leader István Erlich

Fekadu Shewarega UDE

Documents history

Revision Date Modification Author

01

02

03

04

05

Date: 11/01/2010 Page: 3

Executive Summary

The prevalence of new power electronic converter based devices and systems in their multifaceted

applications are steadily increasing in the European power systems. Additionally, protection and control

systems are becoming more and more complex and their impact and geographic reach is continuously

increasing.

As the first part of the deliverable 5.1 within the context of a multi-layered approach to tackle the issue,

this report provides the list of devices and systems slated for detailed analysis, which can broadly be

categorised into two: primary power equipment and protection and automation devices.

With regard to the former category, the report, by and large, deals with equipment containing voltage

source converters as key ingredients, such as the newer types of HVDC transmission systems, FACTS

devices, and wind farm aggregate models. Newer versions of phase shifting transformers are also

included in the list. The list is augmented by a brief review of the mode of operation and functionality

description of these devices and systems. This is followed by an analysis of the existing models used in

various simulation software packages with regard to their adequacy for steady state, quasi-steady state

and transient simulations.

The modelling of power system protection and automation systems is also in the focus of this deliverable.

This part of the assignment is broader in scope, with the ultimate objective being providing some suitable

models for protection and automation systems to be incorporated into simulation packages. The models

can serve as key ingredient in providing a tool to TSO that would enable the synchronous display of the

state of the ETN close to real time. They can also be used in OPF programs to determine realistic system

operating points, in preventive security assessment, in real-time congestion management or in dispatcher

training. In a broader context, suitable models can also improve on the existing practice in time

simulation of very large systems and open up the possibility of a realistic study of the ETN including

interactions with neighbouring systems.

The present report starts with the categorisation of protection and automation systems. The category

protection system includes the survey of all well-established protective schemes together with the current

difficulty in modelling using widely used simulation platforms. The list of automation systems has been

drawn down to under frequency load shedding, automatic re-closing, automatic synchronizing and over-

voltage/under-voltage limitation automation.

In general, protective relaying models describe a sequence of scenarios depicting connection and

disconnection of units for pre-determined model of the power system reflecting isolation/restoration of

service by means of protection system activation. The validity of the models can only be ascertained only

after a proper validation process. This process generally assumes a set of testing procedures, and

appropriate external signals are needed for testing. The form of the test signal for model validation is

contingent on the degree of simplification acceptable for the model under consideration.

Date: 11/01/2010 Page: 4

Table of content

Executive Summary ............................................................................................................ 3

1. Introduction ................................................................................................................ 6

2. List of new devices, concepts and systems to have an impact on the future ETN performance ............................................................................................. 7

2.1. List of primary power equipment to be considered and the description of their functionality ................. 7

2.1.1. Voltage source converter based HVDC transmission systems ..................................... 8

2.1.1.1. Fundamentals ............................................................................................ 8

2.1.1.2. Voltage source converter based HVDC versus classical HVDC ............... 8

2.1.1.3. Control of voltage source converter based HVDC ..................................... 9

2.1.2. The static synchronous shunt compensator (STATCOM) .......................................... 11

2.1.2.1. STATCOM basics .................................................................................... 11

2.1.2.2. STATCOM control .................................................................................... 11

2.1.3. Static Synchronous Series Compensator (SSSC) ...................................................... 12

2.1.3.1 SSSC basics ............................................................................................ 13

2.1.3.2 SSSC control ............................................................................................ 13

2.1.4. Wind farm aggregate model ........................................................................................ 14

2.1.5. Thyristor controlled series compensator (TCSC) ........................................................ 16

2.1.6. Hexagonal phase shifting transformers ....................................................................... 20

2.1.7. Asynchronized Synchronous Machine (ASM) ............................................................. 21

2.1.8. Magnetically controlled reactor (MCR) ........................................................................ 23

2.1.8.1. Detailed model ......................................................................................... 23

2.1.8.2. Simplified model for dynamic simulation .................................................. 27

2.2. List of relay protection and automation devices and system to be considered and the description of their functionality ............................................................................................................................... 27

2.2.1. Classification of protection and control systems ......................................................... 27

2.2.2. Classification of automation systems 1 ....................................................................... 43

2.2.3. Classification of automation systems 2 ....................................................................... 46

2.2.4. Current state of the technology and level of diffusion ................................................. 48

2.2.4.1. Classification of protection systems ......................................................... 48

2.2.4.2. Special protection schemes ..................................................................... 49

2.2.4.3. Example of a special protection scheme in Baltic interconnection .......... 51

2.2.5. Existing different software describing models of protective relaying and power system automation devices ......................................................................................... 54

2.2.5.1. PSCAD (Relay & Instrument Transformer Library) .................................. 54

2.2.5.2. CAPE (Relay catalog) .............................................................................. 55

2.2.5.3. EUROSTAG ............................................................................................. 55

Date: 11/01/2010 Page: 5

2.2.5.4. MATLAB / SIMULINK ............................................................................... 56

2.2.5.5. Conclusions .............................................................................................. 57

3. Conclusions.............................................................................................................. 58

4. References ............................................................................................................... 59

Date: 11/01/2010 Page: 6

1. Introduction

The objective of this work package within the context of the much broader set of tasks identified by

PEGASE is to set up a general methodology for modelling active system components, including

controllers and protection systems, to build a reliable system for validating models and data and to

specify or develop methods and tools for identifying model parameters. This will form the basis for the

process of standardization of models and achieving a better quality of simulation results.

Limitations on the further expansion of transmission facilities as a result of environmental concerns

means that the need for increased transmission capacity is more and more often achieved through the

implementation of fast acting higher-level protection and control structures that coordinate the operation

of several devices. This represents a shift from passive to active network security management. Such

protection systems and schemes are often difficult to model realistically with existing tools.

An accurate simulation of the behaviour of a power system taking these new developments into

consideration presupposes an accurate modelling of its individual elements. In the discussions leading

up to the launching of this project, the assumption was that many models of power system components

in use today are deemed to be inaccurate or computationally inefficient. When it comes to power system

dynamic modelling, even an agreed standard for control structures that are able to model equipment

behaviour with adequate accuracy are not available. Sometimes - as currently experienced with wind

generation systems - manufacturers are reluctant to divulge details of the control algorithms of their

equipment due to product protections reasons. On top of these permanent concerns, it is far from

obvious how the models of the new power technologies (electronic interfaces, FACTS, digital

controllers and protections, active distribution networks) should be introduced into the full time-scale

model of the power system.

The increasingly tight integration of the European power systems requires that the individual systems

exchange information so that each can assess the influence that the other systems might have on its own.

As long as these power systems consisted only of conventional components, this could be achieved

through an exchange of parameter/data. As the number of complex devices and control systems

increases, mere exchange of data is no longer sufficient because these organizations are likely to use

different simulation tools.

Thus it was found necessary to include the development of common formats for the exchange of power

system data in this work package. The common format would ensure that all TSOs have a common

understanding of how a particular device or control system operates. Thanks to this common

understanding, TSOs would be able to simulate accurately, using their own tools, the effect that their

neighbours’ system will have on the security of their own system.

Date: 11/01/2010 Page: 7

2. List of new devices, concepts and systems to have an impact

on the future ETN performance

2.1. List of primary power equipment to be considered and the description of

their functionality

Table 1 provides an overview of the primary power equipment which has to be considered for this task.

The first column of the table is assigned for the name of the respective device, system or scheme. The

second column contains of short description of the functionality whereas the third and last column

provides information about the issues of the device, system or scheme in terms of modelling.

Device/System/Scheme Description of functionality Issues in modelling

Voltage source conver-

ter based HVDC trans-

mission systems

Connection of two or more

AC terminals through voltage

source converter and DC

links.

Response to electrically close short-

circuits / inter-area power swings is

questionable. Furthermore the reac-

tion to significant frequency devia-

tions (>1 Hz) is not accurate.

Voltage source conver-

ter connecting wind

turbine generators to

the AC grid

AC/DC – DC/AC conversion

by voltage source converter

based on PWM technology.






Doubly-fed induction

generator (DFIG)

Electric machine equipped

with three phase rotor.






Wind farm aggregate

model

Dynamic equivalence repre-

senting wind farms with

respect to grid connection

point.






Interaction with harmonics is usu-

ally not considered.

STATCOM Device for reactive power

generation using converters

based on PWM technology.






Thyristor controlled se-

ries compensator

(TCSC)

Usually applied with long

transmission lines for compen-

sation of series line reactance.






Static Var Compensa-

tor (SVC)

Device for reactive power

generation using converters

based on Thyristor

technology.




tion to significant frequency

deviations (>1 Hz) is not accurate.

Date: 11/01/2010 Page: 8

Phase shifting

transformers

Device for power flow control Model for short-circuit studies not

fully established, especially for

newer technologies.

Table 1: List of primary power equipment

The following section provides based on the table above some background details, which include:

a closer description of each device’s functionality

the reasons that gave rise to the perceived modeling deficits and where these deficits are

the scope of applicability of the corresponding models (timeframe and phenomena)

2.1.1. Voltage source converter based HVDC transmission systems

2.1.1.1. Fundamentals

HVDC Light is a DC transmission technology consisting of voltage source converter (VSC) stations and

a pair of cables. The DC transmission system comprises of extruded polymer cables both for land

transmission (underground) and across water (submarine cables). HVDC Light is by nature bipolar.

The converters use a set of six valves, two for each phase, which are equipped with high-power

Insulated Gate Bipolar Transistors (IGBT). The valves are controlled by a control system using pulse-

width modulation (PWM). Currently HVDC Light comes in unit sizes ranging from a few tens of MW.

In the upper range, the technology now reaches 1,200 MW and ±320 kV. Figure 1 provides a general

schematic of the circuit diagram of a VSC based HVDC Light

system.

Since IGBTs can be switched on or off as desired, output voltages and currents on the AC side can be

controlled precisely, and the control system thus enables the control of voltage, frequency, and flow of

active and reactive power according to the needs of the network. Additionally, HVDC Light has the

capability to rapidly control active and reactive power independent of one another.

2.1.1.2. Voltage source converter based HVDC versus classical HVDC

The superiority of HVDC Light from the classical HVDC stems from the fact that the outputs of the

VSC are determined solely by the control system and not by the AC network’s ability to keep the

voltage and frequency constant. This gives total flexibility regarding the location of the converters in the

AC system since the requirements on the AC network in terms of short-circuit capacity (SCR) is low

(SCR can even be as low as zero). In other words, HVDC Light can feed power even into a passive

network.

Classic HVDC terminals can provide limited control of reactive power by means of switching of filters

and shunt banks and to some degree through firing angle control.

But the HVDC Light control makes it possible to create any voltage phase angle or amplitude, which

can be accomplished almost instantly. Unlike conventional HVDC converters that normally have a 5%

minimum current, the HVDC Light converter can operate at very low power or even at zero power. As

the active and reactive power are controlled independently, at zero active power the full rating can be

Sending end converter (SEC) Receiving end converter (REC)

Figure 1: Circuit diagram of a VSC based HVDC (HVDC Light)

Date: 11/01/2010 Page: 9

utilized to transmit reactive power. If and when the need arises, the same converter can even be used as

a SVC and it is then called SVC Light.

Active power transfer can be quickly reversed by HVDC Light without any change of control mode, and

without any filter switching or converter blocking. The power reversal is obtained by changing the

direction of the DC current and not by changing the DC voltage as for conventional HVDC. The table

below (Table 1) shows a comparison of the characteristics of a classical HVDC and the HVDC Light.

Function Classical HVDC HVDC Light

Converter valves Thyristor IGBT

Connection

valve - AC grid

Converter transformer Series reactor (+ transformer)

Filtering and reactive

compensation

50% -filters and shunt capacitors Only small filter

DC current smoothing Smoothing reactor + DC filter DC capacitor

Communication between

converter station controls

Needed Not needed

Table 2: Summary of the key differences between classical HVDC and HVDC Light

After the analysis of the differences between classical HVDC and HVDC Light, the subsequent section

deals with the control of HVDC which is based on voltage source converters.

2.1.1.3. Control of voltage source converter based HVDC

The function of the receiving end converter (REC) is to transfer the active power transmitted by the

sending end converter (SEC) to the AC grid by maintaining the DC voltage at the desired level. The

reactive power channel is used to support the grid voltage during faults and also in steady-state. The

control structure for the REC is shown in Figure 2.

Figure 2: Simplified model of the DC and AC voltage control of receiving end VSC

Date: 11/01/2010 Page: 10

The PI-controller maintains DC voltage through active converter current under consideration of a feed-

forward term representing the power transfer through the DC link. AC voltage control is performed by

two controllers. The PI controller in the upper branch is slow and only responsible for set-point tracing

in steady-state operation. The controller in the lower branch is a fast-acting proportional controller with

dead band. It is activated when the voltage error is larger than 0.1 p.u. and it is responsible for grid

voltage support during faults. The magnitude of the current outputs is limited. In steady-state operation

the DC voltage control and by implication the d-component of the REC current has higher priority. In

case of a grid fault the priority is switched to reactive current to provide voltage support. The decoupled

control of active and reactive current is achieved by a feed-forward current control with a very good

dynamic response. This control is based on a vector control approach with its rotating reference frame

aligned to the grid voltage. Due to the voltage orientation of the reference frame, active power can be

controlled through d- and reactive power through q- component of the converter current. The current

control structure makes use of standard PI controllers (Figure 3). The magnitude of the output voltages

is limited by the maximum modulation index and the DC voltage.

Figure 3: Feed-forward Decoupled Current Control

The SEC is responsible for transmitting the active power injected into the sending end of the

transmission system, while maintaining the AC voltage set point. HVDC Light will increasingly play an

important role to transmit power from offshore wind farms to the respective distribution or transmission

grid onshore (high or extra-high voltage). The frequency control capability can be used to control the

slip of the doubly-fed induction machines (DFIM) feeding into SEC. This may be used to reduce the

active power flow through the converter of the DFIM into its rotor circuit (thus the converter rating) still

further without reducing the total power.

As the power control is performed by the wind turbines, a simple voltage magnitude controller for the

SEC will suffice to fulfil the aforementioned requirements. The frequency can be directly regulated

without the need for a closed loop structure. Figure 4 shows the control structure of the SEC.

Figure 4: Simplified model of sending end VSC control

Date: 11/01/2010 Page: 11

Since no current control is used, a current limitation can only be achieved indirectly by blocking the

IGBTs during a severe fault in the (internal) wind farm grid. The voltage control capability of the SEC

can be used to initiate a controlled voltage drop to reduce the wind farm power during fault ride-through

in the high voltage grid.

2.1.2. The static synchronous shunt compensator (STATCOM)

2.1.2.1. STATCOM basics

The STATCOM is a shunt-connected, controlled reactive power source. Its capacitive or inductive

output current can be controlled independently of the AC system voltage, and thus provides voltage

support by generating or absorbing reactive power at the point of common coupling without the need for

external reactors or capacitor banks.

The basic scheme is shown in Figure 5 below.

Figure 5: Basic structure of the STATCOM

The basic components of a STATCOM are an inverter with a capacitor on the DC side, coupling

transformer, and the control system. The equipment action results from the continuous and quick control

of capacitive or inductive reactive power.

2.1.2.2. STATCOM control

The interaction between the AC system voltage at the point of connection determined by the system

load flow configuration and the voltage produced by the inverter enables the control of the STATCOM

var output. When these two voltages are synchronized and have the same amplitude, the active and

reactive power exchange is zero. However, if the amplitude of the STATCOM voltage is smaller than

that of the system voltage, it produces a current lagging behind the voltage by 90 degrees, and the

compensator behaves as an inductive load, whose value depends on the voltage amplitude difference.

Making the STATCOM voltage higher than the AC system voltage will cause the current to lead the

voltage by 90 degrees, thus injects reactive power into the bus connecting the STATCOM to the system.

I

Ut

Ut <Uac

Ut >Uac

Q generation

Q consumption

Filters

Udc

Ut

Voltage source

converter

Network bus

DC capacitor

Uac

Date: 11/01/2010 Page: 12

2.1.3. Static Synchronous Series Compensator (SSSC)

Figure 7 shows the basic structure of a SSSC.

U1 U2

Useries

Uconv

Udc

DC capacitor

The main characteristics and basic functions are described in the following two sections.

Figure 7: Basic scheme of the SSSC

Figure 6: Simplified control scheme for the STATCOM

Date: 11/01/2010 Page: 13

2.1.3.1 SSSC basics

The Static Synchronous Series Compensator (SSSC) is a series FACTS device used to control the power

flow and to improve power oscillation damping on power grids. The SSSC injects a voltage Useries in

series with the transmission line to which it is connected.

As the SSSC does not use any active power source, the injected voltage must stay in quadrature with the

line current. By varying the magnitude Useries = Uq of the injected voltage (which is in quadrature with

the current), the SSSC performs the function of a variable reactance compensator, either capacitive or

inductive.

The variation of an injected voltage is performed by means of a Voltage-Source Converter (VSC)

connected on the secondary side of a coupling transformer. The VSC uses forced-commutated power

electronic devices (GTOs, IGBTs or IGCTs) to synthesize a voltage Uconv from a DC voltage source.

A capacitor connected on the DC side of the VSC acts as a DC voltage source. A small active power is

drawn from the line to keep the capacitor charged and to cover the transformer and VSC losses, so that

the injected voltage Us is practically 90 degrees out of phase with the current I.

2.1.3.2 SSSC control

The control system of a SSSC consists of the following elements:

A phase-locked loop (PLL) which synchronizes on the positive-sequence component of the

current I. The output of the PLL (angle Θ=t) is used to compute the direct-axis and

quadrature-axis components of the AC three-phase voltages and currents (labeled as Ud, Uq or

Id, Iq on the diagram).

Measurement systems measuring the AC positive-sequence of voltages U1 and U2 (U1q and

U2q) as well as the DC voltage UDC.

AC and DC voltage controllers which compute the two components of the converter voltage

(Ud_conv and Uq_conv) are required to obtain the desired DC voltage (UDC-ref) and the injected

voltage (Uq-ref). The Uq voltage regulator is assisted by a feed forward type regulator which

predicts the Uconv voltage from the Id current measurement.

Figure 8: Simplified control structure of the SSSC

Date: 11/01/2010 Page: 14

2.1.4. Wind farm aggregate model

The most commonly used generator type in modern wind turbines is the DFIG. A typical layout of a

DFIG system is shown in Figure 9. The back-to-back frequency converter in combination with pitch

control of the rotor blades enables variable speed operation, leading to higher energy yields compared to

fixed speed wind turbines.

Since the IGBT-converter is located in the rotor circuit, it only has to be rated to a small portion of the

total generator power (typically 20-30%, depending on the desired speed range). A rotor crowbar is used

to protect the rotor side converter against over-currents and the DC capacitors against over-voltages

during grid faults. But a crowbar ignition means the loss of the generator controllability through the

machine side converter (MSC), since the machine rotor is short-circuited through the crowbar resistors

and the MSC is blocked. During this time slot the generator acts as a common induction generator and

consumes reactive power, which is not desirable for low voltage ride-through (LVRT). To avoid a

crowbar ignition for most fault scenarios, a DC chopper is used to limit the DC voltage by short-

circuiting the DC circuit through the chopper resistors. A line inductor and an AC filter are used at the

grid side converter to improve the power quality.

Operating Control

Pitch Control

Gearbox

Measurements

Generator

ASG

3-

Line

Crowbar

MSC PWM LSC PWM

Back-to-Back PWM Converter

Converter Control

L

Chopper

Figure 9: DFIG based wind energy conversion system

The combination of mechanical pitch control and speed control through the electromechanical generator

torque is standard in modern multi-MW wind turbines. The speed control acts to maximize the power

output of the wind turbine across a wide range of wind speeds by adjusting the turbine rotational speed

according to the rotor blade characteristics by adjusting the generator torque. The pitch control tries to

maintain the generator speed constant for operation above nominal wind speed and during wind gusts by

pitching the rotor blades out of the wind, thereby reducing the mechanical stress on the wind turbine and

the drive train at high wind speeds and limits the output power of the WT.

Figure 9 also shows the distribution of the control tasks in a DFIG based wind turbine. The operating

control is responsible for the coordination of pitch and converter control and also assumes some

supervisory control tasks to guarantee safe and automatic operation of the wind turbine.

The commonly used control approach for the speed is based on standard PI controllers and the speed

using a fixed relationship between measured power and reference speed, which is stored in a lookup

table. The control approach is based on power measurement, because wind speed measurement is

inaccurate due to the wind sensor location behind the turbine. The control structure is shown in Figure

10. The upper part shows the speed control, which uses the measured electrical power to determine the

speed set-point with a lookup table. The PI controller adjusts the generator speed by changing the

reference value of the electromagnetic torque. With this value and the measured generator speed the

Date: 11/01/2010 Page: 15

reference electrical power is calculated and passed to the converter control, which controls the active

power to the desired value. The lower part of the control structure describes the pitch control, which is

also based on a PI controller. This controller is only active, if the generator speed exceeds its nominal

value. The controller output is the set-point for the pitch angle, which is adjusted by the pitch actuator

with a certain delay. The pitch actuator can easily be modelled by a PT1 element with rate and output

limitation. The structure shown also includes a wind turbine model based on the cp-curves of the WT

and the basic equation of wind power conversion. The wind speed used in this power conversion model

is filter by a PT1 element to consider the smoothing effect across the area swept by the rotor blades.

Figure 10: Speed and pitch control

Figure 11shows the circuit diagram of the LSC. In a DFIG system the function of the LSC is to maintain

the DC voltage and provide reactive current support for optimization of the reactive power sharing of

MSC and LSC in steady-state. During grid faults additional short-time reactive power can be fed to

support the grid. Especially when the machine rotor is short circuited through the crowbar resistors, the

generator consumes reactive power. This reactive power has to be compensated by the LSC.

Date: 11/01/2010 Page: 16

Figure 11: Line side converter control

The MSC controls active and reactive power of the DFIG and follows a tracking characteristic to adjust

the generator speed for optimal power generation depending on wind speed. Optionally a fast local

voltage controller can be implemented. The cascaded control structure of the MSC is shown in Figure

12. The outer power control loop of the MSC adjusts the rotor current set values of the inner rotor

current loop.

Figure 12: Machine side converter control

The control structures described above adequately reflect the behavior of a single machine. However,

modern wind turbines are rarely used as standalone systems. More significant is the study of the number

of machines operating together as a wind farm. How the currently established control structures need to

be modified for the aggregate model is the focus of the next phase of the study.

2.1.5. Thyristor controlled series compensator (TCSC)

A Thyristor Controlled Series Capacitor (TCSC) is a series-controlled capacitive reactance that can

provide continuous control of power on the AC line over a wide range. From the system viewpoint, the

principle of variable-series compensation is simply to increase the fundamental-frequency voltage

across the fixed capacitor (FC) in a series compensated line through appropriate variation of the firing

angle, . This enhanced voltage changes the effective value of the series-capacitive reactance.

Date: 11/01/2010 Page: 17

The basic module of a TCSC has a series capacitor in parallel with a thyristor-controlled reactor, L as

shown in Figure 13. An actual TCSC system usually comprises a cascaded combination of a number of

these TCSC modules, together with a fixed series capacitor, CF. This fixed series capacitor is provided

primarily to minimise costs. The capacitors C1, C2,...,Cn; in different TCSC modules may have different

values to provide a wider range of reactance control. The inductor in series with the anti-parallel

thyristor is split into two parts to protect the thyristor valves in case of an inductor short circuit. A

practical TCSC module also includes protective equipment normally installed with series capacitor.

A simple understanding of TCSC functioning can be obtained by analyzing the behavior of a variable

inductor connected in parallel with an FC. The equivalent impedance, Ze, of this combination is

expressed as:

CjZe

1

LC

LjLj

21

Uc

IL

Figure 13: Basic TCSC scheme

tcosIi ll ω

For a more detailed insight into the functioning of the TCSC, the differential equations governing the

behaviour of the TCSC can be written as follows:

Basic differential equations:

CL u

dt

diL

βωβ t

LlC itcosÎ

dt

duC ω

0dt

diL L

βπωβ t

tcosIdt

duC l

C ω

Date: 11/01/2010 Page: 18

The solution of the above differential equations:

)tcos()cos(

costcos

I)t(i l

L

ωλ

βλ

βω

λ

λ

12

2

βωβ t

)tsin()tsin(

)cos(

cosLI)t(u Rl

C ωωλβλ

βλ

λ

ωλ

12

0)t(iL

βπωβ t

βλβλ

λ

βλωωλ tan(tan

cos)tsin(LI)t(u RlC

12

Definitions:

: firing angle

: control angle (=180°-)

R: resonant angle (=C.L

R

1ω )

: ratio between resonant and supply frequencies, i.e. π

ω

ω

ωλ

100

RR

Boost factor

The peak value of thyristor current occurs at t=0. Thus,

1

12

2

)cos(

cosIi l

maxLλβ

β

λ

λ

The peak value of the voltage across the capacitor

The ratio of the fundamental frequency component of the thyristor current to the peak value of the line

current is given by the relationship:

βλβλ

λ

βββ

λ

λ

πtantan

cossin

I

i

l

maxL

1

2

21

22

2

2

2

The ratio of the fundamental frequency component of the capacitor current to the peak value of the line

current is given by the relationship:

21

2

1

21

2

2

2

2 βββλβλ

λ

β

λ

λ

π

sintantan

cos

I

iI

I

i

l

maxCl

l

maxC

The capacitor voltage can then be obtained by multiplying the maximum current with

Date: 11/01/2010 Page: 19

0

1XjLj

CjR λλω

ω . Thus,

21

2

1

21

2

2

2

2

0

βββλβλ

λ

β

λ

λ

πλ

sintantan

cosXj

I

iI

I

u

l

maxCl

l

maxC

The ratio between the fundamental frequency component of the capacitor voltage with and without

thyristor action is defined as boost factor. Thus boost factor kB is defined as:

21

2

1

21

2

2

2

2

0

βββλβλ

λ

β

λ

λ

πλ

sintantan

cos

I

iI

XjI

uk

l

maxCl

l

maxCB

0 10 20 30 40 50 60 70 80 90-20

-15

-10

-5

0

5

10

15

20

25

control angle

boost

facto

r

Boost factor as a function of control angle

capacitive mode

inductive mode

Figure 14: Boost factor for lambda = 2.77

Date: 11/01/2010 Page: 20

Xc

Controller

Voltage

Detection

Uc

Xc

Measurement

Power

Oscillation

Damper

IL

Power

Measurement

Figure 15: Control structure for TCSC

2.1.6. Hexagonal phase shifting transformers

Phase shifting transformers (PST) are used to control power flows by inserting a series voltage into the

line. The procedure essentially involves two windings, the series winding and the excitation winding. To

obtain a phase shift between the incoming and outgoing voltages, the excitation voltage must be

supplied by a phase different from the one into which the series winding inducing voltage. Different

regulating transformer technologies employ different methods of creating the shifted voltage. A

common method of deriving the extra voltage is to couple the series winding of a PST with the

quadrature voltage—the phase-to-phase voltage of the two other phases. Such a traditional PST design

works with the excitation winding connected either in delta or wye. This simple approach, however,

results in an asymmetrical transformer design: the magnitudes of the incoming and outgoing voltages

differ depending on the applied regulating angle. This causes changes in the flow of the reactive power,

leading to undesired coupling of the active and reactive power control actions. More sophisticated

designs are used to make the solution symmetrical in order to maintain the same voltage magnitudes at

the load and source sides of a PST. Symmetrical PSTs shift the voltages while keeping their magnitudes

identical 0. Hexagonal PSTs are of a symmetrical design. Six windings are placed on a three-legged

core. These windings are interconnected in such a way that both the series and excitation windings

virtually intersect each other with the effect that no delta or wye winding can be isolated in the structure

of a hexagonal PST as shown in Figure 16.

Date: 11/01/2010 Page: 21

IcIbIa

I’cI’bI’a

V2a V2c

I2b I2bI2a

ΔVa

Va Vb Vc

Figure 16: Winding connection for a single core hexagonal phase shifter

2.1.7. Asynchronized Synchronous Machine (ASM)

ASM (as compared to conventional a synchronous machine) has two field windings shifted for some

angle (often 90º). An additional winding may have a power rating equal or less than main winding. Each

of the field windings is controlled independently. This can be used to improve the transient stability of a

generator especially in reactive power consumption mode. When both windings have the same power

rating, ASM becomes a variant of a DFIG with a two-phase rotor.

An ASM can operate in three general modes, depending on the number of field windings excited:

1. Asynchronized synchronous generator (both windings are controlled by Automatic Voltage

Regulation (AVR))

2. Synchronous generator (only one winding is controlled by AVR)

3. Induction generator (both windings are shorted)

Figure 19 below provides a static power diagram for an ASM with a rated power of 160 MW.

Date: 11/01/2010 Page: 22

Figure 17: Static power diagram for an ASM (rated power 160MW)

The different areas shown in Figure 17 are:

1 Field current limit

2 Stator current limit

3 Induction generator mode curve

4 Minimal excitation limit (overcame in asynchronized mode)

5 Minimal excitation limit (overcame in asynchronized mode)

The differential equations for an asynchronized synchronous machine (in d-q frame) [83] are:

With the following constraints:

Date: 11/01/2010 Page: 23

Where

j – time constant of the machine,

s - slip,

MM – mechanical torque,

– rotor angle,

ufd, ufd – excitation voltages,

ud, uq – machine terminal voltages,

id, iq – machine terminal currents,

ifd, ifq – field winding currents,

i1d, i1q – damper winding currents,

xd, xq, xffd, xffq, x11d, x11q – leakage inductances of machine stator, field windings and damper

windings,

xafd, xa1d, xf1d, xafq, xa1q, xf1q – mutual inductances of machine stator, field windings and damper

windings.

As seen from the equations the main difference of an ASM compared to a synchronous machine is in the

additional equation for the second field winding magnetic flux derivative pfq. Therefore these

equations may be further simplified similar to ordinary synchronous machine equations if required.

AVR generates control signals in frame xy that corresponds to the terminal voltage. Then these signals

are transformed to the machine frame qd.

Simplified AVR equations may be represented as follows (details are not disclosed by manufacturers):

where ut, u0 – terminal voltage and its reference, , 0 - rotor angle and its reference, P, P0 – generator

active power and its reference, s – slip, ku1, ku2, ku3, kd, ks, kp - coefficients, Ue - signal produced by

special block to equalize currents in both windings in steady state.

Ue signal may be calculated with equation

where kfu – coefficient that defines main and additional winding currents ratio in steady state.

2.1.8. Magnetically controlled reactor (MCR)

A MCR is a device for local voltage regulation. The main winding that is connected to the power system

is placed on the core and its saturation is regulated by the current in the control winding. As an effect

the device reactance can be adjusted to keep the voltage at a defined set point.

The advantage of MCR against SVC is that it does not require thyristor valves rated to full power of the

device, but only for the control winding power. Also filters are not required for MCR as well as step-up

transformer.

2.1.8.1. Detailed model

MCR may have various designs and detailed model depending on the particular design used. An

example of a MCR scheme is shown in Figure 18 below [84]:

Date: 11/01/2010 Page: 24

Figure 18: Example of a MCR scheme

Figure 19: Equivalent electrical circuit diagram for the main windings of a MCR

Date: 11/01/2010 Page: 25

Figure 20: Equivalent electrical circuit diagram for the control windings of a MCR

Figure 21: Equivalent magnetic circuit diagram of a MCR

For this MCR design the model may be formulated as a matrix differential equation:

where

Date: 11/01/2010 Page: 26

111111

111

22

22

32310000

32220000

22210000

12110000

21110000

011

010

09

08

07

06

05

04

03

02

01

012

LLWWWW

LLWWWW

LLWWWW

LLWWWW

LLWWWW

LLWWWWWWWWWW

LLWWWWWWWWWW

WWWR

WWR

WWR

WWWR

WWWR

WWR

WWR

WWWR

WWWR

WWR

WWR

WWWR

A

CBMBBMMBBMMM

BAMMMBBMMBBM

MM

B

B

MM

MM

B

B

MM

MM

B

B

MM

32

31

22

21

12

11

1

1

1

11

10

9

8

7

6

5

4

3

2

1

12

i

i

i

i

i

i

i

i

i

x

C

B

A

0

0

)()(

)()(

0

0

0

0

0

0

0

0

0

0

0

0

)(

32323131

32322222

22222121

12121111

21211111

11

11

RiRi

RiRi

RiRi

RiRi

RiRi

RRiRRi

RRiRRi

xc

CmCCBmBB

BmBBAmAA

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

U

U

U

U

U

b

BC

AB

Ri = Ri + Rci,

Ri – linear reluctances,

Rci(Bci) – differential reluctances,

RAm, RBm, RCm – resistances that reflect core losses,

Rij – resistances of control winding branches,

WM, WB, W0 – winding turns,

Date: 11/01/2010 Page: 27

LA, LB, LC – leakage inductances of main windings,

Lij – leakage inductances of control winding branches,

i – magnetic fluxes,

iij – control winding currents,

iA, iB, iC - phase currents,

UAB, UBC – phase-to-phase voltages,

U0 – control winding voltage.

This detailed model allows an accurate simulating of the core saturation processes and therefore

sinusoidal components production.

2.1.8.2. Simplified model for dynamic simulation

In dynamic simulation MCR may be accounted as a variable susceptance. Then the following equation

may be used:

where BR – reactor susceptance, BAVR – reference susceptance as calculated by automatic voltage

regulator, TR – equivalent time constant of the MCR.

A typical value for TR constant is 0.3 s. This model is valid for normal operational conditions and does

not account effects of close short circuit faults, because in case of a voltage drop the MCR is unloaded

instantly because of the decrease of saturation.

2.2. List of relay protection and automation devices and system to be considered

and the description of their functionality

This chapter provides a list of the most common protection systems for main power system units. The

first section of this chapter classifies protection systems for power systems, whereas the second section

describes the current state of technology and level of diffusion regarding protection systems.

The authors divided the description into two parts:

protective relaying and

power system automation

The reason is that they fall into different categories:

a) A protective relay is the device, which gives instruction to disconnect a faulty part of the

system. This action ensures that the remaining system is still fed with power, and protects the

system from further damage due to the fault.

b) Power system automation is the application of automatic devices to the electric transmission

or distribution systems. Automation is primarily used to monitor the state of the system,

operate switching and control devices remotely, and protect the system from disturbances.

2.2.1. Classification of protection and control systems

The list of protection system used for power systems is arranged in table form. This table consists of 6

columns:

Type of the protected object and /or physical quantity monitored. The first column provides information

about the object or apparatus (e.g. transformers etc.) which is protected or the physical quantity (current,

voltage etc.) which is monitored in order to protect the equipment in case the physical quantity exceeds

certain (predefined) limit.

Type of protection. The column contains the type of protection according to (ANSI/IEC)

definitions.

Date: 11/01/2010 Page: 28

Input analog and digital signals. The different input signals (analog or digital) that are required

by the protection system are described here.

Main settings. The typical/most common configuration or settings of the respective protection

system is specified in the fourth column.

Output digital signals. The type of (digital) output signals (e.g. warnings etc.) is named in this

column.

Additional information

TYPE OF

PROTECTED

OBJECT

TYPE OF

PROTECTION

INPUT ANALOG

AND DIGITAL

SIGNALS

MAIN

SETTINGS

OUTPUT

DIGITAL

SIGNALS

ADDITIONAL

INFORMATION

GENERAL

CURRENT

PROTECTIONS

Instantaneous

and definite

time over-

current

protection for

phase currents

ANSI 50/51

(non-

directional)

ANSI 67

(directional)

iA(t), iB(t), iC(t)

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Direction

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Inverse time

over-current

protection for

phase currents

ANSI 51 (non-

directional)

ANSI 67

(directional)

iA(t), iB(t), iC(t)

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Settings for

IEC, ANSI

or user

defined

curves.

Direction

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Comments:

Phase over-current protection can be implemented as three-phase or as single-

phase protection.

RMS or instantaneous values of phase currents can be used.

For the phase directional element the fault current of the corresponding phase

and the un-faulted phase-to-phase voltage are used as reference voltage. With

three-phase short-line faults, stored voltage values are used to clearly determine

the direction if the measurement voltages are not sufficient.

Phase over-current protection can contain a number of supplementary functions

(switch on to fault function, harmonic restraint blocking function, dynamic

increase of pick-up values function).

Date: 11/01/2010 Page: 29

Instantaneous

and definite

time over-

current

protection for

residual

currents

ANSI 50N/51N

(non-

directional)

ANSI 67N

(directional)

iA(t), iB(t), iC(t),

3i0(t)

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Direction

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Inverse time

over-current

protection for

residual

currents

ANSI 51N

(non-

directional)

ANSI 67N

(directional)


3i0(t)

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Settings for

IEC, ANSI

or user

defined

curves.

Direction

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Comments:

Residual over-current protection can be implemented as three-phase or as

single-phase protection.

The over-current protection for the ground current can either operate with

measured or calculated quantities of 3I0.

Residual over-current protection can contain a number of supplementary

functions (switch on to fault function, harmonic restraint blocking function,

dynamic increase of pick-up values function).

Instantaneous

and definite

time over-

current

protection for

negative

sequence

currents

(unbalanced

load

protection)

ANSI 46

iA(t), iB(t), iC(t)

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Direction

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Inverse time

over-current

protection for

negative

sequence

currents

(unbalanced

load

protection)

ANSI 46

iA(t), iB(t), iC(t)

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Settings for

IEC, ANSI

or user

defined

curves.

Direction

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Date: 11/01/2010 Page: 30

Circuit

Breaker

Failure

Protection

ANSI 50BF


3i0(t)

Circuit breaker

position

Pick-up

settings.

Time delay

settings.

Tripping

signal

Blocking

signal

Necessary for

network

simulations

The circuit breaker failure function ensures fast back-up tripping of surrounding

breakers. A current check with extremely short reset time is used as check criteria to

achieve a high security against unnecessary operation.

The unit can be single or three-phase started to allow use with single phase tripping

applications. The current criteria can be set to two out of four e.g. two phases or one

phase plus the residual current to achieve a higher security.

The function can be programmed to give single or three phase re-trip of the own

breaker to avoid unnecessary tripping of surrounding breakers at an incorrect starting

due to mistakes during testing.

Pole

Discordance

Protection

ANSI 50PD

Might not be

necessary

Single pole operated circuit breakers can due to electrical or mechanical failures end

up with the different poles in different positions (close-open). This can cause negative

and zero sequence currents, which gives thermal stress on rotating machines and can

cause, unwanted operation of zero sequence current functions.

Normally the own breaker is tripped to correct the positions. If the situation consists

the remote end can be inter-tripped to clear the unsymmetrical load situation.

The pole discordance function operates based on information from auxiliary contacts

of the circuit breaker for the three phases with additional criteria from unsymmetrical

phase current when required.

Thermal

overload

protection

ANSI 49

iA(t), iB(t), iC(t)

Blocking signal

Coolant

temperature

Alarm, trip,

and reset

settings.

Temperatur

e settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Three methods of overload detection can be used (depends on the type of the

protected object):

Overload calculation using a thermal replica according to IEC 60255-8, without

ambient temperature influence.

Overload calculation using a thermal replica according to IEC 60255-8, with

ambient temperature influence.

Calculation of the hot-spot temperature and determination of the ageing rate

according to IEC 60354.

Phase

undercurrent

protection

ANSI 37

Might not be

necessary

Date: 11/01/2010 Page: 31

This protection is used to protect pump un-priming or breaks in load coupling. The un-

priming of a suction pump can be due to the absence of liquid in the pump. Pump un-

priming or a break in a coupling leads to off-load operation of the motor and therefore a

drop in the current absorbed.

Protection

against neutral

earthing

impedance

overloads

ANSI 50N/51N

Might not be

necessary

This protection allows the limiting impedance to be protected against the thermal

effects of an overload. When a phase-to-earth fault occurs on the network, the fault

current is reclosed via the neutral earthing connection. If the fault is resistive, the fault

current may be lower than the earth fault protection thresholds and higher than the

permanent current that the resistor can withstand. A permanent current thus flows

through the limiting impedance and may damage it.

Instantaneous

high-current

switch-on-to-

fault protection

(SOTF)

Might not be

necessary

The instantaneous high-current switch-onto-fault protection function is provided to

disconnect immediately and without delay feeders that are switched onto a high-current

fault. It is primarily used as fast protection in the event of energizing the feeder while the

earth switch is closed, but can also be used every time the feeder is energized - in other

words also following automatic re-closure

GENERAL

VOLTAGE

PROTECTIONS

Over-voltage

protection

ANSI 59

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Inverse time

over-voltage

protection

ANSI 59

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Settings for

IEC, ANSI

or user

defined

curves.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Residual over-

voltage

protection

ANSI 59N

uA(t), uB(t), uC(t),

3u0(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Date: 11/01/2010 Page: 32

Under-voltage

protection

ANSI 27

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Inverse time

under-voltage

protection

ANSI 27

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Settings for

IEC, ANSI

or user

defined

curves.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Remanent

under-voltage

protection

ANSI 27

Might not be

necessary

After the opening of a circuit during an automatic switchover (or a short cut in the

power supplied by the utility), the motors maintain a voltage for the time it takes for the

flux to be extinguished. If the voltage supply is restored while the motors are operating

as generators, this may lead to phase opposition coupling causing transient electrical and

mechanical phenomena that might be damaging for the motor.

The remanent under-voltage protection monitors the voltage of the busbar supplying

the motors and authorizes the power supply to be restored if this voltage is lower than

the threshold.

Over-

excitation

protection

ANSI 24

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Settings for

preset or

user defined

curves.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Comments:

The overexcitation protection measures the ration voltage/frequency, which is

proportional to the induction ―B‖ in the iron core.

The maximum of the three phase-to-phase voltages is decisive for the

calculation.

Synchrocheck

and voltage

check

ANSI 25

Refers to

automation

devices.

Date: 11/01/2010 Page: 33

The synchronism and voltage check function ensures, when switching a line onto a

busbar, that the stability of the network is not endangered. The voltage of the feeder to

be energized is compared to that of the busbar to check conformances in terms of

magnitude, phase angle and frequency within certain tolerances. Optionally, de-

energization of the feeder can be checked before it is connected to an energized busbar

(or vice versa).

The synchronism check can either be conducted only for automatic re-closure, only

for manual closure (this includes also closing via control command) or in both cases.

Different close permission (release) criteria can also be programmed for automatic and

manual closure.

GENERAL

FREQUENCY

PROTECTIONS

Over/under

frequency

protection

ANSI 81O/U

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

Rate-of-change

of frequency

protection

ANSI 81R

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Tripping

signal

Blocking

signal

Warning

signal

Necessary for

network

simulations

SPECIFIC

TRANSFORMER

AND

AUTOTRANSFORME

R

PROTECTIONS

Differential

protection

(current)

ANSI 87


3i0(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Tripping

signal

Blocking

signal

Necessary for

network

simulations

Comments:

Phase currents are taken from all ends of the protected transformer.

The simple current differential protection using time over-current relays is

considered here. It is seldom used in present day applications due to their

susceptibility to false operation from causes such as a) inrush magnetizing

current when energizing the transformer, and b) saturation errors or mismatch

errors of current transformers.

Differential

protection

(percentage)

ANSI 87T


3i0(t)

Blocking signal

Settings for

tripping

characteristi

c.

Settings for

2nd

and 5th

harmonic

restraint.

Tripping

signal

Blocking

signal

Necessary for

network

simulations

Comments:


The biased (stabilized) differential protection is considered here. It is known

also as percentage differential protection.

Percentage differential protection contains a number of supplementary

functions (adaptation to transformation ratio and vector group, stabilization

against in-rush and over-excitation).

Date: 11/01/2010 Page: 34

Differential

protection

(high

impedance)

ANSI 87


3i0(t)

Blocking signal

Settings for

tripping

characterist

ic.

Tripping

signal

Blocking

signal

Necessary for

network

simulations

Comments:


The high impedance differential protection is considered here. It can be used

when the involved CT cores have same turn ratio and similar magnetizing

characteristics. It utilizes an external summation of the phases and neutral

current and a series resistor and a voltage dependent resistor externally to the

relay.

Restricted

earth fault

protection

ANSI 87N


3i0(t)

Blocking signal

Settings for

tripping

characteristi

c.

Tripping

signal

Blocking

signal

Necessary for

network

simulations

The restricted earth fault function can provide higher sensitivity for earth fault

currents than differential protection and it do not need harmonics stabilization.

Restricted earth fault protection is usually configured to measure one neutral current and

one three-phase set of currents.

Tank earth

leakage

protection

ANSI 50/51

Might not be

necessary

This protection is designed to protect a transformer against internal faults

between a winding and the frame.

Protection by

gas, pressure

and

temperature

detection

(DGPT)

Might not be

necessary

The DGPT (detection of gas, pressure and temperature) is a protective device used

for liquid-insulated transformers. It detects anomalies inside the liquid dielectric such as

emission of gas, or a rise in pressure or temperature, and causes the transformer-

switching device (circuit-breaker or switch-fuse) to trip.

Date: 11/01/2010 Page: 35

SPECIFIC

TRANSMISSION

AND

DISTRIBUTION

LINE

PROTECTIONS

Distance

Protection

ANSI 21


3i0(t)

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Direction

settings.

Settings for

tripping

characterist

ic.

Load

encroachm

ent settings.

Blocking

from power

swings

settings.

Tripping

signal

Blocking

signal

Necessary for

network

simulations

Comments:

Distance protection can contain a number of supplementary functions (power

swing detection, switch on to fault function, load encroachment function).

Tele-

protection

schemes for

distance

protection

Tripping signal

Blocking signal

Releasing

(unblocking)

signal

Type of

tele-

protection

scheme.

Distance

protection

zone for

tele-

protection

scheme.

Pick-up,

waiting,

prolongatio

n, and time

delay

settings.

Tripping

signal

Blocking

signal

Releasing

(unblocking)

signal

Necessary for

network

simulations

In under-reach schemes, the protection is set with a normal grading characteristic. If a

trip command occurs in the first zone, the other line end receives this information via a

transmission channel. There the received signal initiates a trip.

In overreach schemes, the protection works from the start with a fast overreaching

zone. This zone, however, can only cause a trip if the opposite end also detects a fault in

the overreaching zone. A release (unblock) signal or a block signal can be transmitted.

In cases where there is no or only weak in-feed present at one line end, the distance

protection does not pick up there during a short-circuit on the line. Likewise, on lines

where there is only a single sided in-feed or where the star-point is only earthed behind

one line end, the line end without zero sequence current cannot generate a permissive

signal, as fault detection does not take place there. In these cases special measures for

weak and zero in-feed are used.

Date: 11/01/2010 Page: 36

Tele-protection

schemes for

earth fault

protection

Tripping signal

Blocking signal

Releasing

(unblocking)

signal

Type of

tele-

protection

scheme.

Earth fault

protection

zone for

tele-

protection

scheme.

Pick-up,

waiting,

prolongatio

n, and time

delay

settings.

Tripping

signal

Blocking

signal

Releasing

(unblocking)

signal

Necessary for

network

simulations

Directional comparison scheme.

When the earth fault protection recognizes a fault in the forward direction, it

initially sends a permissive signal to the opposite line end. If a permissive

signal is also received from the opposite end, a trip signal is routed to the trip

logic.

Directional unblocking scheme.

The unblocking method is a permissive scheme. It differs from the directional

comparison scheme in that tripping is possible also when no release signal is

received from the opposite line end. It is therefore mainly used for long lines

when the signal must be transmitted across the protected feeder by means of

power line carrier (PLC) and the attenuation of the transmitted signal at the

fault location may be so severe that reception at the other line cannot

necessarily be guaranteed.

Directional blocking scheme.

In the case of the blocking scheme, the transmission channel is used to send a

block signal from one line end to the other. The signal may be sent directly after

fault inception (jump detector above dotted line) and stopped immediately, as

soon as the distance protection detects a fault in the forward direction,

alternatively the signal is only sent when the distance protection detects the

fault in the reverse direction. It is stopped immediately as soon as the earth fault

protection detects an earth fault in forward direction. Tripping is possible with

this scheme even if no signal is received from the opposite line end. It is

therefore mainly used for long lines when the signal must be transmitted across

the protected line by means of power line carrier (PLC) and the attenuation of

the transmitted signal at the fault location may be so severe that reception at the

other line cannot necessarily be guaranteed.

Date: 11/01/2010 Page: 37

Differential

protection

ANSI 87L


3i0(t)

Blocking signal

Settings for

tripping

characterist

ic.

Settings for

2nd

harmonic

restraint.

Settings for

charging

current

compensati

on.

Tripping

signal

Blocking

signal

Necessary for

network

simulations

Comments:

Phase currents are taken from all ends of the protected object.

For lines with three or more ends or for bus bars, the principle of differential

protection is extended in that the total sum of all currents flowing into the

protected object is zero in healthy operation, whereas in case of a fault the total

sum is equal to the fault current.

The measured quantities should be sent as digital telegrams via communication

channels. For this, each device should be equipped with at least one protection

data interface.

Broken

conductor

detection

Might not be

necessary

The relay can incorporate an element, which measures the ratio of negative to

positive phase sequence current (Ι2/Ι1) to detent broken conductor. This will be affected

to a lesser extent than the measurement of negative sequence current alone, since the

ratio is approximately constant with variations in load current. Hence, a more sensitive

setting may be achieved.

SPECIFIC

GENERATOR

AND

MOTOR

PROTECTIONS

Start-up

overcurrent

protection

ANSI 51

Might not be

necessary

Gas turbines can be started by means of a startup converter. A controlled converter

feeds a current into the generator creating a rotating field of gradually increasing

frequency. This causes the rotor to turn and thus drive the turbine. At approx. 70 % of

rated speed, the turbine is ignited and further accelerated until it attains rated speed. The

startup converter is thereby switched off.

Assuming that a short-circuit can occur in the generator during startup, a short-circuit

protection is necessary over the entire frequency range.

Excessive

start-up time

and locked

rotor

protection

ANSI 51LR

Might not be

necessary

Date: 11/01/2010 Page: 38

Excessive start-up time.

When a machine is switched on, protection is activated if the current of one of

the three phases is higher than the current threshold for a time T. This time T

must be above the maximum value of the normal start-up time.

Rotor locking.

The protection is locked during start-up. In steady-state operating conditions, the

protection is activated when the current of one of the three phases is higher than

the current threshold for a time exceeding the set time delay.

Protection

against too

many

successive

startups

ANSI code 66

Might not be

necessary

Too many successive start-ups may be due to the faulty operation of an automatic

control device, too many manual operations or a series of re-closings when a fault

occurs. The consequences are excessive rise in temperature and a succession of

mechanical shocks on the couplings.

These problems can be avoided using a protection device that counts the number of

start-ups carried out over a determined period of time.

Under-

excitation (loss

of field)

protection

ANSI 40

iA(t), iB(t), iC(t)

uA(t), uB(t), uC(t)

Blocking signal

Under-

excitation

characteri

stic.

Time

delay

settings.

Tripping

signal

Blocking

signal

Warning

signal

The under-excitation protection protects a synchronous machine from asynchronous

operation in the event of faulty excitation or regulation and from local overheating of the

rotor. Furthermore, it avoids endangering network stability by under-excitation of large

synchronous machines.

Protection

against

reversals in

active power

ANSI 32P

iA(t), iB(t), iC(t)

uA(t), uB(t),

uC(t)

Blocking signal

Pick-up

settings.

Time

delay

settings.

Direction

settings.

Tripping

signal

Blocking

signal

Warning

signal

This type of protection allows an inversion of the active power sign to be

detected in the absence of an electrical fault.

Protection

against

reversals in

reactive power

ANSI 32Q

iA(t), iB(t), iC(t)

uA(t), uB(t), uC(t)

Blocking signal

Pick-up

settings.

Time delay

settings.

Direction

settings.

Tripping

signal

Blocking

signal

Warning

signal

Date: 11/01/2010 Page: 39

This protection is used to detect a loss in excitation of the synchronous machines

connected to the network. Upon occurrence of a loss in excitation, the machine

compensates for the drop in magnetizing power by absorbing the reactive power on the

network. The reactive power of the machine is thus negative. The protection detects the

inversion of the sign of the machine’s reactive power.

Jump of

voltage vector

Might not be

necessary

Sometimes consumers with their own generating plant feed power directly into a

network. The incoming feeder is usually the ownership boundary between the network

utility and these consumers/producers. A failure of the input feeder line for example due

to a three-pole automatic re-closure, can result in a deviation of the voltage or frequency

at the feeding generator which is a function of the overall power balance. When the

incoming feeder line is switched on again after the dead time, it may meet with

asynchronous conditions, which cause damage to the generator or the gear train between

generator and drive.

One way to identify an interruption of the incoming feeder is to monitor the phase

angle in the voltage. If the incoming feeder fails, the abrupt current interruption causes a

phase angle jump in the voltage. This jump is detected by means of a delta process. As

soon as a preset threshold is exceeded, an opening command for the generator or bus-tie

coupler circuit breaker is issued.

This means that the vector jump function is mainly used for network decoupling.

90 % stator

earth fault

protection

ANSI 59N,

64G, 67G

Might not be

necessary

The stator earth fault protection detects earth faults in the stator windings of three-

phase machines. The machine can be operated in busbar connection (directly connected

to the network) or in unit connection (via unit transformer). The criterion for the

occurrence of an earth fault is mainly the emergence of a displacement voltage, or

additionally with busbar connection, of an earth current. This principle makes possible a

protected zone of 90 % to 95 % of the stator winding.

Sensitive earth

fault

protection

ANSI 51GN,

64R

Might not be

necessary

The highly sensitive earth fault protection detects earth faults in systems with

isolated or high-impedance earthed starpoint. This stage operates with the magnitude of

the earth current. It is intended for use where the earth current amplitude gives an

indication of the earth fault. As an example of this is with electrical machines in busbar

connection in an isolated power system, where during a machine earth fault of the stator

winding, the entire network capacity supplies the earth fault current, but with a network

earth fault, the earth fault current is negligible due to the low machine capacitance. The

current may be measured using toroidal CTs or CTs in Holmgreen connection.

100 % stator

earth fault

protection

with 3rd

harmonic

ANSI 27/59TN

Might not be

necessary

Date: 11/01/2010 Page: 40

The 3rd harmonic emerges in each machine in a more or less significant way. The

shape of the poles causes it. If an earth fault occurs in the generator stator winding, the

division ratio of the parasitic capacitances changes, since one of the capacitances is

short-circuited by the earth fault. During this procedure, the 3rd harmonic measured in

the starpoint decreases, whereas the 3rd harmonic measured at the generator terminals

increases (see the following figure). The 3rd harmonic forms a zero phase-sequence

system and can thus also be determined by means of the voltage transformer switched in

wye/delta or by calculating the zero phase-sequence system from the phase-earth-

voltages.

100 % stator

earth fault

protection with

20Hz voltage

injection

ANSI 64G

Might not be

necessary

An external low frequency alternating voltage source (20 Hz) injects into the

generator starpoint a voltage of max. 1% of the rated generator voltage. If an earth fault

occurs in the generator starpoint, the 20 Hz voltage drives a current through the fault

resistance. From the driving voltage and the fault current, the protective relay

determines the fault resistance.

Inter-turn

protection

ANSI 59N

Might not be

necessary

The inter-turn fault protection detects faults between turns within a generator winding

(phase). This situation may involve relatively high circulating currents that flow in the

short-circuited turns and damage the winding and the stator. The protective function is

characterized by a high sensitivity.

Given the way the generators are constructed, it is rather unlikely that an inter-turn

fault will occur.

Generators with a separate stator winding (e.g. large-sized hydro-electric generators)

are more likely to be affected. In this configuration, the transverse differential protection

or the zero sequence current protection are used instead between the connected star-

points.

Rotor earth

fault protection

ANSI 64R

Might not be

necessary

Rotor earth fault protection is used to detect earth faults in the excitation circuit of

synchronous machines. An earth fault in the rotor winding does not cause immediate

damage; however, if a second earth fault occurs it constitutes a winding short-circuit of

the excitation circuit. The resulting magnetic imbalances can cause extreme mechanical

forces, which may destroy the machine.

Sensitive rotor

earth fault

protection

with 1 to 3 Hz

square wave

voltage

injection

ANSI 64R

Might not be

necessary

Date: 11/01/2010 Page: 41

The rotor earth fault protection works with a direct voltage of approximately 50V, the

polarity of which is reversed between 1 and 4 times per second, depending on the

setting. This voltage is injected into the rotor circuit. The voltage passes through a

resistor unit and is symmetrically coupled to the excitation circuit via high-resistance

resistors, and at the same time connected to the earthing brush (potential to earth) via a

low-resistance measuring shunt. The voltage taken at the measuring shunt and the

control voltage are fed into the protection device via measuring transducers. The control

voltage is proportional to the injected 50V voltage in terms of amplitude and frequency.

The measurement voltage reflects the earth current flowing in the rotor.

Voltage

restrained

overcurrent

protection

Might not be

necessary

The generator terminal voltage will drop during fault conditions and so a voltage-

measuring element can be used to control the current setting of this element. On

detection of a fault the current setting is reduced by a set factor. This ensures faults are

cleared in spite of the presence of the generator decrement characteristic.

Restart inhibit

for motors

ANSI 66/49

Might not be

necessary

The rotor temperature of a motor generally remains well below its maximum

admissible temperature during normal operation and also under increased load

conditions. However, with startups and resulting high startup currents caused by small

thermal time constants it may suffer more thermal damage than the stator. To avoid

multiple startup attempts causing tripping, a repeated startup of the motor must be

prevented, if it may be assumed that admissible rotor heating would be otherwise be

exceeded.

Inadvertent

energization

ANSI 50/27

Might not be

necessary

The inadvertent energizing protection serves to limit damage by accidental

connection of the stationary or already started, but not yet synchronized generator, by

fast actuation of the mains breaker. A connection to a stationary machine is equivalent

to connection to a low-ohmic resistor. Due to the nominal voltage impressed by the

power system, the generator starts up with a high slip as an asynchronous machine. In

this context, un-permissibly high currents are induced inside the rotor, which may

finally destroy it.

DC

voltage/current

protection

ANSI

59NDC/51ND

C

Might not be

necessary

To detect DC voltages, DC currents and small AC quantities, relay can be equipped

with a measuring transducer input that can be used either for voltages (±10V) or currents

(± 20mA). The DC voltage / DC current protection can be used, for example, for the

monitoring of the excitation voltage of synchronous machines or for the detection of

earth faults in the DC section of the start-up converter of a gas turbine set.

Shaft current

protection

Might not be

necessary

Date: 11/01/2010 Page: 42

Positive

sequence

under-voltage

and phase

rotation

direction

protection

Might not be

necessary

This type of protection is used to protect motors. It performs two protection

functions:

Protects against positive-sequence voltage drops. The positive-sequence voltage

accurately defines the motor torque value. It is therefore more accurate than the

voltage measurement.

Protects against an inversion in phase rotation direction. An inverse phase

rotation direction may be due to a cable connection error. This inversion leads to

the motors operating in the opposite direction, which may be prejudicial to the

mechanical load and, consequently, to the motor.

SPECIFIC

SHUNT REACTOR

AND

SHUNT

CAPACITOR

PROTECTIONS

Neutral to

neutral

unbalance

protection

ANSI 50N/51N

Might not be

necessary

This protection is designed to protect double star-connected capacitor banks.

Harmonic

current

overloading

protection

Might not be

necessary

Where excessive harmonic currents are anticipated, harmonic relaying may be

required for shunt capacitors.

Voltage

differential

protection

method for

grounded wye

banks

Might not be

necessary

Comparing capacitor bank tap voltage with the bus voltage derives a signal

responsive to the loss of individual capacitor elements or units. The capacitor bank tap

voltage is obtained by connecting a voltage-sensing device across the ground end

parallel group (or groups) of capacitors. This may be a midpoint tap, where the voltage is

measured between the midpoint of the phase and ground. Alternatively, the tap voltage

may be measured across low-voltage capacitors (that is, a capacitive shunt) at the neutral

end of the phase.

SPECIFIC

BUSBAR

PROTECTIONS

End Fault

Protection

(dead zone

protection)

Might not be

necessary

The function of the end fault protection is to protect the zone between the current

transformer and the circuit breaker when the circuit breaker is open.

Partial

Differential

Protection

Might not be

necessary

Date: 11/01/2010 Page: 43

This type of bus protection is also referred to as ―bus overload‖ or ―selective backup‖

protection. It is a variation of the differential principle in which currents in one or more

of the circuits are not included in the phasor summation of the currents to the relay. This

method may be used as a backup to a complete differential protection scheme, as

primary protection for a station with loads protected by fuses or to provide local breaker

failure protection for load breakers, or both.

OTHER

USEFUL

ELEMENTS

FOR

NETWORK

SIMULATION

MODELS

Tripping logic

A function block for protection tripping can be provided for circuit breakers

involved in the tripping of the fault. It can provide the pulse prolongation to

ensure a trip pulse of sufficient length, as well as all functionality necessary for

correct co-operation with autoreclosing functions.

The trip function block can include functionality for evolving faults and breaker

lockout.

It can enable single and two-pole tripping for those functions, which do not

have their own phase selection capability.

Fuses

Sequence

(harmonic)

analyzer

RMS

computation

block

ABC to DQ0

transformation

block

REMARKS:

a) Monitoring, measuring and signaling devices (such as fault locators) are not included in the

table as they would not influence the simulation processes.

b) The parameters and features of the protection functions are selected and shown in the table so

that the corresponding models would remain as simple as possible, yet detailed enough to

capture the underlying physical phenomena.

2.2.2. Classification of automation systems 1

Power system automation falls into a different category than protective relaying system do. Power

system automation is the application of automatic devices to the electric transmission or distribution

systems. Automation is primarily used to monitor the state of the system, operate switching and control

devices remotely, and protect the system from negative implications caused by disturbances.

Date: 11/01/2010 Page: 44

TYPE OF

PROTECTED

OBJECT

TYPE OF

PROTECTION

INPUT SIGNALS

NECESSARY

SETTINGS

OUTPUT

SIGNALS

Calculated

signals

Power

system,

island of

power

system

Underfrequency

load shedding uA(t), uB(t), uC(t),

1. Frequency

settings

2. Rate-of-

change of

frequency

settings

(optional)

3. Number of

load

shedding

steps

4. Maximum

anticipated

overload

5. Size of the

load shed at

each step

6. Time delay

Tripping

signal

Power

system

frequency f,

Rate-of-

change of

frequency

df/dt,

frequency

deviation

from rated

value Δf

Comments:

In large systems the load shedding devices should be spread throughout the system.

The reclosing of feeders that have been tripped for load shedding is left to system

operator. Frequency relays can be used to restore loads automatically

Normally input signal is one line-to-line voltage

Transmission

line

Automatic

reclosing

Protection tripping

signal,

Circuit breaker's

disconnection

signal,

Circuit breaker's

closing signal,

Blocking signals,

Transmission line's

voltages (optional)

1. Dead time

setting

2. Reset time

setting

3. Single or

multiple-shot

reclosing?

4. Operating

time of

circuit

breaker

5. Number of

reclose

attempts

Tripping

signal

Dead time

and reset

time settings

Comments:

Time settings are defined in IEEE Std. C37.100 – 1992

Synchronism check relays should be used on highly interconnected transmission

On single-tie circuit with dispersed generation, reclosing on the circuit must be

delayed long enough for the dispersed generation to be isolated from the utility

The protection on transmission lines that have tapped transformers without breakers

should be blocked from reclosing for faults within the transformer

For lines with capacitors voltage supervision may be required

Date: 11/01/2010 Page: 45

Transmission

line,

Generators

Out-of-step

protection



Rate-of-change

of impedance,

Double blinder

characteristics,

Tripping time

delay,

Negative

sequence of

current,

Direction of

power flow,

Voltage phases

differences

setting

Tripping

signal,

Blocking

signal

Positive-

sequence

impedance,

Rate-of-

change of

impedance,

Negative

sequence of

current,

Direction of

power flow,

Voltages

phases

differences

Comments:

Two methods can be used for out-of-step protection: impedance associated and phase

associated

Reclosing of

generator

and power

system,

Reclosing of

two power

systems

Automatic

synchronizing

Phase voltages at

synchronized ends

Δf,

Difference in

voltages,

Phase angle that

the breaker

contacts close

Reclosing

signal

Phase

voltages on

synchronized

ends,

Difference in

phase

voltages,

Frequencies

on

synchronized

ends f1 and f2,

Δf=f1- f2,

Difference in

phase angles

of voltages

on

synchronized

ends

Comments: Synchronizer compares the voltages on two sides of an open breaker

Generators

Turbine speed

governor



Speed droop,

Pref,

Governor's time

constants,

Limiters values

Control

signal

Generator's

output

power,

Frequency

Comments: standard models of specific governor systems should be used

Generators

Overfrequency

protection uA(t), uB(t), uC(t),

Frequency

setting,

Tripping time

delay

Tripping

signal

Generator's

frequency

Comments: overfrequency protection disconnects excessive generation

Date: 11/01/2010 Page: 46

2.2.3. Classification of automation systems 2

This chapter presents list of automation systems which are specific for applications used in UPS

countries.

TYPE OF

PROTECTED

OBJECT

TYPE OF

PROTECTION

INPUT SIGNALS

NECESSARY

SETTINGS

OUTPUT

SIGNALS

GENERAL

Overvoltage

limitation

automation

uA(t),uB(t),uC(t),3u0(t),

iA1(t),iB1(t),iC1(t),3i01(t)

iA2(t),iB2(t),iC2(t),3i02(t)

Signal of remote

switching on of reactors

Signal of remote

disconnection of reactors

Signal of remote

disconnection of line

Detection of

disconnection of phases

A, B and/or C of

transmission line

Voltage settings,

Current settings,

Reactive power setting,

Active power setting,

Active power's braking

coefficient,

Control time delay,

Reactor's connection

time delay,

Time delay of

transmission line

disconnection,

Breaking failure

automation time delay

Control signal,

Reactor switching

on,

Disconnection of

transmission line,

Remote switching

on of reactor at

the other side

transmission,

Remote

disconnection of

the end of

transmission line,

Signal of breaking

failure automation

Device for

detection of

transmission

line

disconnection

Position of line isolator,

State of phases A, B and

C of the circuit breaker 1,

State of phases A, B and

C of the circuit breaker 2,

Disconnection of line by

personnel

Single-phase

disconnection by

protective relaying,

Three-phase

disconnection by

protective relaying,

Three-phase

disconnection by

protective relaying

with blocking of

reclosing,

State of the 2 circuit

breaker

Autoreclosing

connection time delay

Disconnection

before auto

reclosing

operation,

Disconnection

after

autoreclosing

operation,

Connection of

line,

Disconnection for

maintenance

procedure

Date: 11/01/2010 Page: 47

TYPE OF

PROTECTED

OBJECT

TYPE OF

PROTECTION

INPUT SIGNALS

NECESSARY

SETTINGS

OUTPUT

SIGNALS

Overcurrent

detection

device

iA(t),iB(t),iC(t),

External blocking,

Temperature of

environment

Stage 1...n

Set of three time delay

settings for each stage:

Stage1:

Signal1, signal2,

signal 3

.

.

Stage n:

Signal1, signal2,

signal3

Undervoltage

limitation

automation

uA(t),uB(t),uC(t),

iA1(t),iA2(t),...iAN(t),

External start signal

Blocking signal

Umin setting

Time delay

Umax setting

Logic of feeders'

disconnection order

Tripping signal,

Closing signal,

Blocking of

reclosing

Same set for each

feeder

Device for

monitoring of

preceding

condition

uA(t),uB(t),uC(t),3 u0(t)

iA(t),iB(t),iC(t), 3i0(t)

Few active power

settings – n stages Stage 1 ... stage n

Overload

detection

device

uA(t),uB(t),uC(t),3 u0(t)

iA(t),iB(t),iC(t), 3i0(t)

Few active power

settings – n stages

Time delay settings

Stage 1 ... stage n

Date: 11/01/2010 Page: 48

2.2.4. Current state of the technology and level of diffusion

2.2.4.1. Classification of protection systems

Relays are compact networks that are connected throughout the power system to detect intolerable or

unwanted conditions within an assigned area. In theory relay system should be able to respond to the

infinity of abnormalities that can possible occur within the power system.

The Institute of Electrical and Electronic Engineers (IEEE) defines a relay as "an electric device that is

designed to respond to input conditions in prescribed manner and, after specified conditions are met, to

cause contact operation or similar abrupt change in associated electric control circuits".

The existing protective systems can be classified by design as:

a) Electromagnetic type relays.

b) Analog type solid-state relay.

c) Microprocessor based protective system.

The electromagnetic types of relays are still in service in the power systems and few manufacturing

companies produce electromagnetic relays at present.

Analog solid-state relays are devices of generation preceding microprocessor era. Some relays are in

service in the power systems but manufacturing process practically stopped.

Microprocessor-based protection systems are the new generation of protection and control equipment.

There are some advantages as well as disadvantages of microprocessor-based devices.

Advantages of Microprocessor-based protective systems:

1) Many microprocessor-based protective systems allow to record and then reply modes

preceding of functioning during breakdown, for analysis of emergency situation.

2) Microprocessor-based protective systems allow changing pick-up settings with the help of a

computer and turning from one characteristic to the other using only software tools.

3) Microprocessor-based protective systems allow the provision of all information regarding

their state to remote operational centers through special communication channels.

4) Microprocessor-based protective systems are less prone to dust, increased humidity,

aggressive gas than electromechanical relays.

5) A small microprocessor-based protective system can replace a whole set of standard

electromechanical relays.

6) Higher reliability of static microprocessor-based protective systems in comparison with

electromagnetic relays containing elements moving mechanically.

Disadvantages of Microprocessor-based protective systems:

1) Impact of electromagnetic disturbances from the power supply network to the operation of

the system.

2) There are essential differences in operation of electromechanical and microprocessor-based

relays caused by their different susceptibility to harmonics, saturation and other wave

distortion.

Date: 11/01/2010 Page: 49

3) Considerable complication of exploitation.

4) Information redundancy.

With electronic relays, the protection principles and fundamentals are essentially unchanged as are the

issues regarding protection reliability. Though regarding the modeling issue all types of relays should be

considered separately.

Basic components of a digital relay are:

a) A signal conditioning subsystem.

b) A conversion subsystem.

c) A digital processing relay subsystem.

Typical logic units that may be involved in a microprocessor-based protective system are shown in

Figure 22.

Figure 22: Basic components of a microprocessor-based system

2.2.4.2. Special protection schemes

Date: 11/01/2010 Page: 50

According to [80], special protection schemes are defined as: ―a protection scheme that is designed to

detect a particular system condition that is known to cause unusual stress to the power system and to

take some type of predetermined action to counteract the observed condition in a controlled manner. In

some cases, SPSs are designed to detect a system condition that is known to cause instability, overload,

or voltage collapse. The action prescribed may require the opening of one or more lines, tripping of

generators, ramping of HVDC power transfers, intentional shedding of load, or other measures that will

alleviate the problem of concern. Common types of line or apparatus protection are not included in the

scope of interest here [32].

According to [31], there are five states of operating conditions – Normal, Alert, Emergency, In Extremis

and Restorative. In case of highly reliable SPS with a good performance, a normal power system

operation could be shifted from the Normal state to Alert state (Figure 23). This confidence in SPS

would allow much better utilization of existing assets (transmission lines etc.).

Figure 23: Power system operating states (arrows express possible transitions among them)

In 1992, CIGRE and IEEE performed a survey about the installed SPSs among the utilities. The detailed

statistical results of the answers reporting 111 installed SPSs can be found in [80]. Very important and

interesting observations and information can be extracted from it, although they are not explicitly stated

there [32]:

The trend is quite obvious; the most SPSs have been commissioned in the nineties. The

degree of complexity is rapidly increasing and the solutions are more and more

sophisticated.

All installed SPSs are dedicated solutions for particular power systems. There is no scheme

that could be applied to another power system with minimal modifications.

All installed SPSs are either fully or in major part designed and installed by utilities. There is

no company that would offer a SPS to utilities as a complete solution ranging from data

acquisition to execution of control actions, except ABB. Only some parts of existing SPSs

have been supplied to utilities from an external environment, e.g. algorithm, software

package etc.

SPS should be armed (i.e. ready for operation) all the time, not only in the periods when the

power system is heavily stressed.

―…the cost of the false trips is generally much lower than the cost of failure of the SPS to

operate when required…‖ This implies, that even with the risk of malfunction, SPS

installation is economically beneficial / profitable.

Regardless of the third last bullet, some utilities look for assistance from the vendors’ side of two kinds:

Date: 11/01/2010 Page: 51

1) A complete ―turn-key‖ solution – they don’t specify the way in which the problems should

be resolved but only provide a description of the problems and critical scenarios.

2) Delivery of a part of the solution – they have their own ideas, algorithms or studies but they

need a help to set up the system / platform, build an infrastructure etc.

The four main design criteria, which should be used for SPS, are:

1) Dependability – The certainty that the SPS operates when required, that is, in all cases where

emergency controls are required to avoid a collapse.

2) Security – The certainty that the SPS will not operate when not required, does not apply

emergency controls unless they are necessary to avoid a collapse.

3) Selectivity – The ability to select the correct and minimum amount action to perform the

intended function, that is, to avoid using disruptive controls such as load shedding if they are

not necessary to avoid a collapse.

4) Robustness – The ability of the SPS to provide dependability, security and selectivity over

the full range of dynamic and steady state operating conditions that it will encounter.

Other very important relevant questions have been raised in [81]:

1) Reliability of SPS (the author means basically the availability of the system, i.e. inability of

the system to operate due to the failure of one or more of its components should be minimal,

similar to Dependability as defined by CIGRE).

2) Impact on daily operation of a grid (i.e. acceptance by the operators and required effort for

the training of the operators).

3) Documentation of SPS.

Conclusion:

Due to all installed SPSs are dedicated solutions for particular power systems and there is no scheme

that could be applied to another power system with minimal modifications. SPS systems are not

classifiable. So this report will not present modeling problems for SPS. Below is example of specific

SPS solution for the Baltic power system.

The Classification of SPS and further analysis is planned for the future report WP5.3. There is a need in

developing common methodology for the assessment of power system security during operation of SPS

systems. One of the approaches can by the application of Hybrid Dynamic Systems.

The example of the specific SPS solution for the Baltic power system is presented below.

2.2.4.3. Example of a special protection scheme in Baltic interconnection

High voltage power lines of 330 kV form the basic network of the Baltic interconnection. There are 58

high-voltage transmission lines of total length 4136.9 km and 32 substations equipped with 54

autotransformers of the 347/242kV and 330/115 kV voltages with the total capacity of 8665.0 MVA.

Regional transmission network of the Baltic interconnection consists primarily of 110 kV lines, with the

only exception of Estonian power system, where in addition, 220 kV voltage is used.

Date: 11/01/2010 Page: 52

Figure 24: The interconnection of the Baltic region

The simplified structure of the anti-emergency automation system, which is used in the Baltic

interconnection, is shown in Figure 24. The main part of this system is the so-called ―adaptive matrix‖

(4th block in Figure 25). It analyzes the information of region’s state (i.e. number of operating hydro

units, number of hydro units in the pumping or compensation state, power flow between Latvia and

Estonia etc.) and distributes the appropriate control action.

The algorithm of the described anti-emergency automation system was carefully simulated using

Mustang software developed by the Latvian TSO department. Investigations of the described SPS

system will be executed during the fulfillment of task 3 of WP5.

An adaptive matrix operates in the united power system as well as in islanded mode.

Date: 11/01/2010 Page: 53

Figure 25: Simplified structure of the system of anti-emergency in the Baltic interconnection

1) Anti-emergency system of Ignalinos NPP (see also Figure 24).

2) Anti-emergency system of Smolensk NPP.

3) Anti-emergency system of 750kV substation Belorusskaja.

4) Adaptive matrix, which distributes the amount of necessary control action among hydro

power plants. It can disconnect the load as well.

5) Block, which determines the necessity of the disconnection of load.

Blocks 4 and 5 are two similar blocks located in Plavinas HPP and Ignalinos NPP with

similar settings. Each block controls different power stations. Signals to Kruonio PSHPP

duplicate control to increase operation reliability.

6) Adaptive disconnection of load in Belorussia.

7) Adaptive disconnection of load in Latvia and Lithuania.

8) Disconnection of pumps in Kruonio PSHPP.

9) Start-up of all hydro units in Kruonio PSHPP.

10) Start-up of one hydro unit in Kruonio PSHPP.

11) Number of pumps in Kruonio PSHPP before the contingency.

12) Start-up of hydro units in Pļaviņu HPP: I - 100 %; II - 50 % amount.

13) Start-up of hydro units in Ķeguma HPP: I - 100 %; II - 50 % amount.

14) Start-up of hydro units in Rīgas HPP: I - 100 %; II - 50 % amount.

15) Control of active power flow between Latvia and Estonia before contingency.

Date: 11/01/2010 Page: 54

The main factors for operation of the special protection scheme are:

1) Under-frequency situation in the power system (f<49.4 Hz, t=1 sec).

2) Loss of one or two blocks at the Ignalinos NPP (750 MW or 1300 MW).

3) Loss of specific intersystem transmission lines.

Here we will consider the behavior of emergency automation only during the disturbances associated

with under-frequency situations.

An excerpt from the adaptive matrix of the Pļaviņu HPP is shown in Figure 26. In case of frequency

decline below 49.4 Hz, the control action depends on the situation in Kruonio pumped storage power

plant and on the situation in Pļaviņu HPP.

Figure 26: Excerpt from the adaptive matrix of the Latvian Pļaviņu HPP

The main shortcoming of the considered approach is linked with the pre-determined control actions of

the adaptive matrix. These control actions and settings are chosen in advance according to some

previously calculated possible emergency situations. However, it is not possible to foresee all the

possible power system failures and cascading events. Therefore the considered approach is most

effective when the emergency situation corresponds or is close to the foreseen one. In other cases it can

produce wrong control actions.

2.2.5. Existing different software describing models of protective relaying and power

system automation devices

2.2.5.1. PSCAD (Relay & Instrument Transformer Library)

PSCAD software contents few very simple models of protective relaying and power system automation.

For example, differential protection model provides verification if operational point is situated in

tripping zone? Other necessary models are possible to create using logical and mathematical basic

elements. It is also possible to create new models using Fortran software.

Date: 11/01/2010 Page: 55

Figure 27: Example of a PSCAD library

2.2.5.2. CAPE (Relay catalog)

Authors of CAPE software periodically update relay's data. Relay's models are created with high

resolution. Unfortunately it is not possible to transfer models to another software environment. Besides

CAPE software can simulate only steady state conditions.

Figure 28: Screenshot from the CAPE software

2.2.5.3. EUROSTAG

EUROSTAG software gives excess to different protection and automation devices. The list of devices is

limited. It is not possible to transfer models to another software environment. Mathematical descriptions

are internal type only. It is possible to create model using EUROSTAG blocks with transfer functions.

For users applying the EUROSTAG software, the included concept of macro-automation probably will

be convenient and sufficient for the analysis of the model.

Date: 11/01/2010 Page: 56

Figure 29: User interface of EUROSTAG

2.2.5.4. MATLAB / SIMULINK

MATLAB software with SIMULINK does not have a library of protective relaying and automation

elements. The advantage of the software is the availability of a wide range of basic elements to create

the required models. Below is one example of a model (Figure 30).

A package developed at Texas A&M University using MATLAB and SIMULINK provides such

capabilities through five standard component libraries. For example, Relay Element library contains:

Data Acquisition Board, Digital Filter, Digital Fourier Transform, Basic Measurement, Differential

Equation-Based Impedance Measurement, Universal Comparator, Zone Comparator, Triggering

Element, Symmetrical Components and Bias Characteristic. Using elements from Relay Library, one

can quickly model a given relay. Developed models can be made part of existing or new libraries.

Figure 30: Example of a model in MATLAB/SIMULINK

Date: 11/01/2010 Page: 57

2.2.5.5. Conclusions

a) Traditional electric power system's elements (transformers, transmission lines, generators and

so on), protective relaying and automation devices can be represented as models. Description

of their operational principles and mathematical models can be found in textbooks and

surveys of relays. Some specific operational algorithms companies use to provide speed of

relay response (for example distance protection should locate appearance of fault, type of

fault with high speed and accuracy) is not known. Using standard algorithms is not possible

to receive high accuracy. Unfortunately, companies usually do not describe all details of their

of their protection devices such as a full specification and description of control units.

In stable networks, as found e.g. in Europe, extremely short tripping times are not required. A total fault

clearance time (protection plus circuit-breaker) of approximately 5 cycles (100 ms in 50 Hz systems) is

generally sufficient.

The German utility board (VDEW) states the following requirement for the protection tripping time

during the critical three-phase close-in fault:

EHV-system 25 ms

HV-system 30 ms

MV-system 40 ms

Table 1: Example for protection tripping time (German Utility Board (VDEW))

b) In spite of the use of protective relaying devices in different software environments new

models should be developed for PEGASE project. In contrast to turbine governors, excitation

systems and synchronous generators for protective relaying and automation devices there are

no mathematical description or standard block diagrams in standards.

In case existing protective relaying model is planned to be used from any model library there should be

need in modification of the model.

Date: 11/01/2010 Page: 58

3. Conclusions

This report represents the first part of deliverable D5.1 in the framework of the PEGASE project. It

provides an overview of the components which are considered to have an impact on the future ETN

performance.

The focus lies on primary power equipment which consists of electronic components and features a non-

linear behavior in general. Furthermore, protective relaying and automation systems are considered to

have an impact on the future ETN performance due to the fact that the system as such is operated closer

to its limits and future tasks will require e.g. special protection schemes.

The report starts-off with listing new concepts, devices and systems slated for detailed analysis,

description of their functionality and some initial thoughts spelling out performance and quality

requirements expected of the models. Based on the preliminary analysis of existing models with regard

to their adequacy for the different simulation purposes, possible modelling gaps have been suggested.

This is followed by a survey of the current approach in modelling protective relaying and automation

systems. Presently each producer of protective and automation systems proposes its own model tied to a

particular application, significantly reducing or precluding the portability of the models for use on other

platforms. The analysis of the current modelling practice and the fidelity of the models to reproduce the

physical reality will be the subject of further work in this Work Package.

Date: 11/01/2010 Page: 59

4. References

1 Bogdan Kasztenny and Eugeniusz Rosolowski: Modeling and Protection of Hexagonal Phase-

Shifting Transformers Part I: Short-Circuit Model, IEEE TRANSACTIONS ON POWER

DELIVERY, VOL. 23, NO. 3, JULY 2008

2 Michael P. Bahrmann and Brian K. Johnson: The ABC of HVDC Transmission technologies:

An overview of HVDC sytems and applications, IEEE Power & Energy Magazine March/April

2007 Vol. 5 No. 2

3 Stanley H. Horowitz, Arun G. Phadke, “Power System Relaying,” 3rd edition, John Wiley &

Sons Ltd., 2008, ISBN: 978-0-470-05712-4.

4 Q. H. Wu, Z. Lu, T. Y. Ji, “Protective Relaying of Power Systems Using Mathematical

Morphology,” Springer, 2009, ISBN 978-1-84882-498-0

5 Network Protection and Automation Guide, Alstom, 2002, ISBN 2-9518589-0-6

6 Bertil Lundqvist, “100 Years of Relay Protection, the Swedish ABB Relay History”

7 SIPROTEC Multi-Functional Protective Relay with Local Control 7SJ62/64 v4.7, Manual,

Siemens.

8 Pedro Nunes, Atef Morched, M. Teresa Correia de Barros, “Analysis of Generator Tripping

Incidents on Energizing nearby Transformers,” International Conference on Power Systems

Transients – IPST 2003 in New Orleans, USA.

9 Ziegler G.: Numerical Distance Protection, 2nd Edition, Publicis Corporate Publishing, 2006,

ISBN 3-89578-266-1.

10 Elmore W. A.: Protective Relaying Theory and Applications, 2nd Edition, Marcel Dekker Inc.,

2003, ISBN 0-82470-972-1

11 Héctor J. Altuve, Michael J. Thompson, Joe Mooney, “Advances in Breaker-Failure

Protection,” Schweitzer Engineering Laboratories, Inc., 2006.

12 S. Casoria, Patrice Brunelle, Gilbert Sybille, “Hysteresis Modeling in Matlab Power System

Blockset.”

13 SIPROTEC Distance Protection 7SA6 V4.61, Manual, Siemens.

14 Li-Cheng Wu, Chih-Wen Liu, Ching-Shan Chen, “Modeling and Testing of a Digital Distance

Relay Using MATLAB and SIMULINK.”

15 IEC 60255-24 Electrical Relays – Common Format for Transient Data Exchange

(COMTRADE) for Power Systems, 2001.

16 SIPROTEC Differential Protection 7UT613/63x V4.60, Manual, Siemens.

17 Leonard L. Grigsby, Power System Stability and Control, CRC Press, 2006.

18 Anderson, P. M., LeReverend, B. K., “Industry experience with special protection schemes,”

IEEE/CIGRE Committee Report, IEEE Transactions on Power Systems, PWRS, 11, 1166–

1179, August 1996.

Date: 11/01/2010 Page: 60

19 James D. McCalley, Weihui Fu, “Reliability of special protection schemes,” IEEE

Transactions on Power Systems, Vol. 14, No. 4, November 1999.

20 Fabio Saccomanno, “Electric Power Systems, Analysis and Control,” IEEE Press, 2003, ISBN

0-471-23439-7

21 P.M.Anderson, B.K.Lereverend: Industry Experience with Special Protection Schemes, IEEE

Transactions on Power Systems, Vol. 11, No. 3, August 1996.

22 E.K.Nielsen, M.E.Coultes, D.L.Gold, J.R.Taylor, P.J.Traynor: An Operations View of Special

Protection Systems, IEEE Transactions on Power Systems, Vol. 3, No. 3, August 1988.

23 Ziegler G.: Numerical Differential Protection, Publicis Corporate Publishing, 2005, ISBN 3-

89578-234-3.

24 Ziegler G.: Numerical Distance Protection, 2nd Edition, Publicis Corporate Publishing, 2006,

ISBN 3-89578-266-1.

25 Elmore W. A.: Protective Relaying Theory and Applications, 2nd Edition, Marcel Dekker Inc.,

2003, ISBN 0-82470-972-1.

26 Reimert D.: Protective Relaying for Power Generation Systems, Taylor & Francis, 2006, ISBN

0-8247-0700-1.

27 Horowitz S. H, Phadke A. G.: Power System Relaying, 3rd Edition, John Wiley & Sons, 2008,

ISBN 978-0-470-05712-4.

28 Hewitson L. G., Brown M., Balakrishnan R.: Practical Power System Protection, Elsevier,

2004, ISBN 0-7506-6397-9.

29 Gurevich V.: Protection Devices and Systems for High-Voltage Applications, Marcel Dekker,

2003, ISBN 0-8247-4056-4.

30 Preve C.: Protection of electrical networks, ISTE, 2006, ISBN 1-905209-06-1.

31 Phadke A.G., Thorp J. S.: Computer Relaying for Power Systems, John Wiley & Sons, 1993,

ISBN 0-471-92063-0.

32 Bernas S., Ciok Z.: Mathematical Modeling of Power System Elements, Warsaw, VNT, 1977.

33 Gers J. M., Holmes E. J.: Protection of Electricity Distribution Networks, 2nd Edition, The

Institution of Electrical Engineers, 2004, ISBN 0-86341-357-9.

34 Blackburn J.L, Domin T.J.: Protective relaying, Principles and Applications, 3rd Edition, CRC

Press, 2007, ISBN 1-57444-716-5.

35 Kundur P.: Power System Stability and Control, McGraw-Hill, Inc., 1994

36 Marek Zima: Special Protection Schemes in Electric Power Systems, Literature Survey, Swiss

Federal Institute of Technology, Zurich, 2002.

37 Generator Protection. Application Guide, ABB, 1986.

38 Transformer Protection IED RET670, Technical Reference Manual, ABB, 2006.

39 Transformer Protection IED RET670, Application Manual, ABB, 2006.

40 Line Distance Protection IED REL670, Technical Reference Manual, ABB, 2006.

Date: 11/01/2010 Page: 61

41 Line Distance Protection IED REL670, Application Manual, ABB, 2006.

42 Busbar Differential Protection IED REB670, Technical Reference Manual, ABB, 2006.

43 Busbar Differential Protection IED REB670, Application Manual, ABB, 2006.

44 Bay Control IED REC670, Technical Reference Manual, ABB, 2006.

45 Bay Control IED REC 670, Application Manual, ABB, 2006.

46 Line Differential Protection IED RED670, Technical Reference Manual, ABB, 2006.

47 Line Differential Protection IED RED670, Application Manual, ABB, 2006.

48 REF 542 Plus Switchbay Protection and Control Unit, Manual part 1: Operation and

Maintenance, ABB, 2001.

49 REU 523 Combined Overvoltage and Undervoltage Relay, Technical Reference Manual, ABB,

1999.

50 RXHB 411 and RAHB 411 Compact Breaker Failure Relay, Technical Reference Manual,

ABB, 2001.

51 Network Protection and Automation Guide, Alstom, 2002, ISBN 2-9518589-0-6.

52 MiCOM P631, P632, P633, P634 Transformer Differential Protection, Software Version: 610,

Technical Manual, Areva.

53 MiCOM P125, P126, P127 Directional/Non-directional Relay, Version 6D, Technical Guide,

Areva.

54 MiCOM P139 Feeder Management and Bay Control, Software Version: 605/611/612,

Technical Manual, Areva.

55 MiCOM P342, P343 Generator Protection Relays, Software Version: 0070C, Technical Guide,

Areva.

56 MiCOMho P443 and P445 Distance Relay, Software Version: 33, Technical Manual, Areva.

57 MiCOM P54x Series Current Differential Relays, Technical Guide, Alstom, 2002.

58 MiCOM P740 Numerical Busbar Protection, Technical Manual, Alstom.

59 MiCOM P921-P922-P923 Voltage and Frequency Relays, Technical Guide, Alstom.

60 PS 462, PS 482 Time-Overcurrent Protection Devices, Software Version: 610, Technical

Manual, Alstom.

61 SIPROTEC Differential Protection 7UT613/63x V4.60, Manual, Siemens.

62 SIPROTEC Distance Protection 7SA6 V4.61, Manual, Siemens.

63 SIPROTEC Numerical Voltage, Frequency, and Overflux Protection 7RW600 V3.0, Instruction

Manual, Siemens, 2001.

64 SIPROTEC Line Differential Protection with Distance Protection 7SD52/53 V 4.60, Manual,

Siemens.

Date: 11/01/2010 Page: 62

65 SIPROTEC Multi-Functional Protective Relay with Local Control 7SJ62/64 V4.7, Manual,

Siemens.

66 SIPROTEC Distributed Busbar/ Breaker Failure Protection 7SS522 V4.6, 7SS523 V3.3,

7SS525 V3.3, Manual, Siemens, 2007.

67 SIPROTEC Multifunctional Machine Protection 7UM62 V4.6, Manual, Siemens, 2005.

68 SIPROTEC Breaker Management Device 7VK61 V4.60, Manual, Siemens, 2008.

69 Mason C. R.: The Art & Science of Protective Relaying, GE. Available at

http://www.gedigitalenergy.com/multilin/notes/artsci/index.htm

70 T60 Transformer Management Relay, UR Series Instruction Manual, Revision 5.2x, GE

Multilin, 2007.

71 745 Transformer Management Relay, Instruction Manual, Firmware Revision: 280.000, GE

Multilin, 2004.

72 C60 Breaker Protection System,UR Series Instruction Manual, Revision: 5.4x, GE Multilin,

2007.

73 F650 Digital Bay Controller, User manual, Firmware version: 3.7X, GE Multilin, 2007.

74 G60 Generator Management Relay, UR Series Instruction Manual, Revision: 5.2x, GE

Multilin, 2006.

75 ANSI/IEEE Std. C37.91-2000 - IEEE Guide for Protective Relay Applications to Power

Transformers, 2000.

76 IEEE Std. PC37.119 D7 - IEEE Guide for Breaker Failure Protection, Draft, 05/16/2005.

77 IEEE Std. C37.113-1999 - IEEE Guide for Protective Relay Applications To Transmission

Lines, 1999.

78 IEEE Std. C37.2-1991 - IEEE Standard Electrical Power System Device Function Numbers,

1991.

79 IEEE Std. C37.96-2000 - IEEE Guide for Ac Motor Protection, 2000.

80 IEEE Std. C37.97-1979 - IEEE Guide for Protective Relay Applications To Power System

Buses, 1979.

81 IEEE Std. C37.99-2000 - IEEE Guide for the Protection of Shunt Capacitor Banks, 2000.

82 IEC 60255-13 Electrical Relays - Biased (Percentage) Differential Relays, First Edition, 1980.

83 IEC 60255-8 Electrical Relays - Thermal Electrical Relays, Second Edition, 1990.

84 L.G.Mamikonyanz, Aspects of transients and asynchronous mode of synchronous and induction

machines analysis (Л.Г. Мамиконянц, Анализ некоторых аспектов переходных и

асинхронных режимов синхронных и асинхронных машин), Moscow, 2006.

85 E. I. Zabutskiy, Combined controllable electromagnetic reactors (Е. И. Забудский,

Совмещенные регулируемые электромагнитные реакторы), Moscow, 2003.

http://www.gedigitalenergy.com/multilin/notes/artsci/index.htm

D5.1-Part 1_List of components impacting the future ETN performance

Documents

Transcript of D5.1-Part 1_List of components impacting the future ETN performance