UNIVERSITY OF ÇUKUROVA INSTITUTE OF NATURAL AND …

UNIVERSITY OF ÇUKUROVA INSTITUTE OF NATURAL AND APPLIED SCIENCE

MSc THESIS

Seyfeddin Olcay BERĐKOL

RESPONSE TESTS OF LOAD-FREQUENCY CONTROL IN THERMAL POWER PLANTS REGARDING UNION FOR THE CO-ORDINATION OF TRANSMISSION OF ELECTRICITY (UCTE) POLICIES

DEPARTMENT OF ELECTRICAL AND ELECTRONICS ENGINEERING

ADANA, 2009

ÇUKUROVA ÜNĐVERSĐTESĐ

FEN BĐLĐMLERĐ ENSTĐTÜSÜ

RESPONSE TESTS OF LOAD FREQUENCY CONTROL IN THERMAL POWER PLANTS REGARDING UNION FOR THE CO-ORDINATION OF TRANSMISSION OF ELECTRICITY (UCTE) POLICIES


YÜKSEK LĐSANS TEZĐ

ELEKTRĐK ELEKTRONĐK MÜHENDĐSLĐĞĐ ANABĐLĐM DALI

Bu tez ..../...../2009 Tarihinde Aşağıdaki Jüri Üyeleri Tarafından Oybirliği/Oyçokluğu Đle Kabul Edilmiştir.

Đmza............………

Prof. Dr. Mehmet TÜMAY

DANIŞMAN

Đmza............……… Đmza............………

Yrd. Doç. Dr. K.Çağatay BAYINDIR Yrd. Doç. Dr. Ramazan ÇOBAN

ÜYE ÜYE

Bu tez Enstitümüz Elektrik Elektronik Mühendisliği Anabilim Dalında hazırlanmıştır Kod No: Prof. Dr. Aziz ERTUNÇ Enstitü Müdürü Đmza ve Mühür Not: Bu tezde kullanılan özgün ve başka kaynaktan yapılan bildirişlerin, çizelge, şekil ve fotoğrafların kaynak gösterilmeden kullanımı, 5846 sayılı Fikir ve Sanat Eserleri Kanunundaki hükümlere tabidir.

I

ÖZ

YÜKSEK LĐSA�S TEZĐ

AVRUPA ELEKTRĐK ĐLETĐMĐ KOORDĐ�ASYO�U BĐRLĐĞĐ (UCTE) KRĐTERLERĐ ÇERÇEVESĐ�DE TERMĐK SA�TRALLERĐ� YÜK FREKA�S TEPKĐSĐ�Đ� ARAŞTIRILMASI


ÇUKUROVA Ü�ĐVERSĐTESĐ

FE� BĐLĐMLERĐ E�STĐTÜSÜ

ELEKTRĐK ELEKTRO�ĐK MÜHE�DĐSLĐĞĐ A�ABĐLĐM DALI

Danışman: Prof. Dr. Mehmet TÜMAY Yıl: Eylül 2009, Sayfa: 99

Jüri: Prof. Dr. Mehmet TÜMAY Yrd. Doç. Dr. K.Çağatay BAYI�DIR

Yrd. Doç. Dr. Ramazan ÇOBA�

Bir enerji iletim şebekesinde aktif ve reaktif gücün akışı birbirinden bağımsızdır ve farklı denetim faaliyetleri ile kontrol edilirler. Reaktif güç kontrolü, gerilim kontrolü ile bağlantılıyken, aktif güç kontrolü ile frekans kontrolü arasında yakın bir ilişki bulunmaktadır. Frekans kontrolü, hem elektrik ağının enerji kalitesini göstermesi bakımından hem de Türkiye elektrik enterkoneksiyonunun Avrupa Elektrik Đletimi Koordinasyonu Birliğine (UCTE) katılabilmesi için gerekli bir parametredir. Avrupa kıtasını kapsayan UCTE büyük bir organizasyondur ve kendine has politikaları bulunmaktadır. Bu politikalardan en önemlisi yük-frekans kontrolüdür. UCTE ağıyla, Türkiye ağının enterkoneksiyonu 90’lı yılların sonundan beri devam eden bir projedir ve TEĐAŞ aracılığıyla referans olarak seçilen hidroelektrik ve termik santrallerde testlere devam edilmektedir.

Bu tezin amacı, UCTE kapsamında belirtilen birincil yük-frekans tepkisini termik santraller için incelemektir. Tezde referans santralin, türbin kontrolörü Matlab/Simulink programı yardımıyla modellenip simülasyonu yapılmaktadır. Saha testleri sonucunda, referans santralin yük-frekans performansı elde edilmiştir. Sonuçlar Digsilent yazılımı aracılığıyla bilgisayar ortamına aktarılmış ve simülasyon da elde edilen sonuçlar ile karşılaştırılıp yorumlanmıştır. Anahtar Kelimeler: Yük-Frekans Kontrol, Birincil Kontrol, Hız Eğimi ve UCTE

II

ABSTRACT

MSc THESIS

RESPO�SE TESTS OF LOAD-FREQUE�CY CO�TROL I� THERMAL POWER PLA�TS REGARDI�G U�IO� FOR THE CO-ORDI�ATIO� OF TRA�SMISSIO� OF ELECTRICITY (UCTE) POLICIES


U�IVERSITY OF ÇUKUROVA

I�STITUTE OF �ATURAL A�D APPLIED SCIE�CES

DEPARTME�T OF ELECTRICAL ELECTRO�ICS E�GI�EERI�G

Supervisor: Prof. Dr. Mehmet TÜMAY Year: September 2009, Pages: 99 Jury: Prof. Dr. Mehmet TÜMAY

Asst. Prof. Dr. K.Çağatay BAYI�DIR Asst. Prof. Dr. Ramazan ÇOBA�

Active and reactive power flows are independent from each other and they are controlled by different methods in an interconnection system. The control of active power is closely related to frequency control and the control of reactive power is related to voltage control. Frequency control is a necessary parameter in order to both indicate energy quality of electricity network and join Turkish interconnected system to Union for the Co-ordination of Transmission of Electricity (UCTE). UCTE in Europe mainland is a huge organization and has own policies. The most important parameter of those policies is load-frequency control. The interconnection of Turkish electrical network with UCTE network is an ongoing project since the end of 90’s and tests are persisting in both hydro power plants and thermal power plants chosen as references in Turkey via TEĐAŞ.

The goal of this thesis is to investigate primary load-frequency control involved in UCTE policies for thermal power plants. Turbine controller of reference power plant is modeled and simulated by using Matlab/Simulink program in the thesis. Load-frequency performance of reference power plant is achieved by the field test. The results of tests are transferred into computer via Digsilent software and results of tests are compared with results of simulations. Keywords: Load-Frequency Control, Primary Control, Speed Droop and UCTE

III

ACK�OWLEDGEME�TS

I wish to express my gratitude to my supervisor Prof. Dr. Mehmet Tümay for

his guidance, encouragement and support during my studies.

I would like to thank K. Çağatay Bayındır who has made any necessary

changes in the thesis with remarkable patience.

Many thanks to my department manager Mr. Đlker Öztürk who supports me

during my thesis. His continuous support helped me to finish this thesis.

I would like to thank my colleague Serdal Uğur for offering valuable advice

in finding this topic at the beginning of the thesis.

I would like to thank all ISKEN family for their helping in each step of

creating this thesis.

I thank Asst. Prof. Dr. Ramazan Çoban for serving as a member of my

committee.

I would like to say a special thank to M. Uğraş Cuma for his helping.

Finally, I would like to thank my family for their endless support and

encouragements.


IV

CO�TE�TS PAGE

ÖZ I

ABSTRACT II

ACK�OWLEDGEME�TS III

CO�TE�TS IV

LIST OF TABLES VII

LIST OF FIGURES VIII

LIST OF SYMBOLS X

LIST OF ABBREVATIO�S XII

1. I�TRODUCTIO� 1

1.1. Frequency Control 3

1.2. Literature 5

1.3. Content 6

2. THERMAL POWER PLA�TS 8

2.1. Steam Turbine 9

2.1.1. Governor (Control) and Stop Valves 11

2.1.2. Condenser 12

2.1.3. Turbine Bypass System 13

2.2. Steam Generator 14

2.2.1. Combustion Loop 15

2.2.2. Combustion Air and Flue Gas 16

2.2.3. Pressure Part (Water / Steam) 17

2.2.4. Water / Steam Cycle 18

2.2.5. Cooling Water System 19

2.2.6. Generator System 20

3. UCTE 22

3.1. UCTE Policies 23

3.1.1. Load-Frequency Control and Performance 24

3.1.1.1. Primary Control 26

3.1.1.2. Balance between Generation and Demand 26

V

3.1.1.3. System Frequency 26

3.1.1.4. Network Power Frequency Characteristic 27

3.1.1.5. Primary Control Basics 29

3.1.1.6. Principle of Joint Action 30

3.1.1.7. Target Performance 31

3.1.1.8. Primary Control Reserve 34

3.1.1.9. Deployment Time of Primary Control Reserve 34

3.1.1.10. Secondary Control 35

3.1.1.11. Tertiary Control 37

3.1.1.12. Time Control 38

3.1.2. Scheduling and Accounting 39

3.1.3. Operational Security 39

3.1.3.1. Voltage and Reactive Power Control 40

3.1.3.2. “N-1”Network Security 41

3.1.4. Co-ordinated Operational Planning 42

3.1.5. Emergency Procedures 42

4. CO�TROL STRATEGY OF GE�ERATOR 44

4.1. General 44

4.2. Frequency and Voltage Control 46

4.2.1. Modeling the PSS 48

4.2.2. Modeling the Excitation System 49

4.2.3. Modeling the Turbine and Governor 50

4.2.3.1. Electro Hydraulic Governing System 54

4.2.3.2. Speed Controller and Power-Load Controller 55

4.2.3.3. Droop Characteristic 58

4.2.3.4. Governor insensitivity or dead band 60

4.2.3.5. Transient Speed Rise 61

5. SIMULI�K MODELI�G OF TURBOSET 63

5.1. General 63

5.2. Design Considerations 64

5.3. Proposed Configuration of Turbine Control System 66

VI

5.3.1. Synchronous Machine (Generator) 69

5.3.2. Turbine-Governor Control System 72

5.3.3. Excitation Control Block 75

5.4. Field Test Procedure 78

5.5. Simulation and Field Test Results 79

5.6. Comparison of Simulation and Test Results 91

6. CO�CLUSIO�S 93

REFERE�CES 97

BIOGRAPHY 99

VII

LIST OF TABLES

Table 3.1 Self regulating effect of load 33

VIII

LIST OF FIGURES

Figure 2.1 A turbo-generator system with five mass 13

Figure 3.1 System frequency movements

for different design hypothesis 32

Figure 4.1 Generator control system 47

Figure 4.2 Power system stabilizer 48

Figure 4.3 Voltage control of synchronous generator 50

Figure 4.4 Steam turbine governing scheme 52

Figure 4.5 Block diagram of the governing system 53

Figure 4.6 Electro-hydraulic governor scheme 54

Figure 4.7 Speed and load controllers 55

Figure 4.8 Power control and Speed control modes 57

Figure 4.9 Droop characteristic 58

Figure 4.10 Different droop with same primary control reserve 59

Figure 4.11 Dead band characteristic 60

Figure 5.1 Power responses in frequency deviations -200 mHz 65

Figure 5.2 Power responses in frequency deviations +200 mHz 65

Figure 5.3 Power-frequency curve at ±200 mHz 66

Figure 5.4 MATLAB/Simulink model of turboset 68

Figure 5.5 Parameters of generator 70

Figure 5.6 Turbine-governor block 73

Figure 5.7 Speed governor block 73

Figure 5.8 Turbine power fractions and

time constants of turbine parts 74

Figure 5.9 Simulated frequency 75

Figure 5.10 Excitation control description 76

Figure 5.11 Excitation control block 76

Figure 5.12 Parameters of excitation 77

Figure 5.13 Test mode 78

Figure 5.14 --200 mHz frequency deviation for case 1.a 80

IX

during simulation

Figure 5.15 -200 mHz frequency deviation for case 1.b 81

during simulation

Figure 5.16 Unit response to -200 mHz frequency 81

deviation for case 1.b during simulation



Figure 5.18 -200 mHz frequency deviation 83

for case 1.a during field test

Figure 5.19 -200 mHz frequency deviation 83

for case 1.b during field test


deviation for case 1.a during field test


deviation for case 1.b during field test

Figure 5.22 +200 mHz frequency deviation 86

for case 2.a during simulation

Figure 5.23 +200 mHz frequency deviation 86

for case 2.b during simulation

Figure 5.24 Unit response to +200 mHz frequency 87

deviation for case 2.a during simulation

Figure 5.25 Unit response to +200 mHz frequency 87


Figure 5.26 Frequency deviation +200 mHz at time 1830 88

seconds for case 2.a during field test

Figure 5.27 Frequency deviation +200 mHz for 15 minutes 89

at time 1830 seconds for case 2.b during field test

Figure 5.28 Test result of unit response +200 mHz frequency 89

deviation at full load for case 2.a during field test

Figure 5.29 Test result of unit response +200 mHz frequency 90

deviation at full load for case 2.b during field test

X

LIST OF SYMBOLS

f Set point of frequency

fo Dead band

fn Rated nominal frequency

∆f Frequency deviation in synchronous system

∆fdyn.max Dynamic frequency deviation

Gf∆ Sensed frequency after dead band

∆P Deviation in power output of a generator

PN Active power output

Pm Mechanical power input

Pset Power set point

Ppu The total primary control reserve for the entire synchronous

area

Q Primary frequency control reserve

λi Frequency characteristic of a synchronous area for i

λu Frequency characteristic of whole synchronous area

λio Set point frequency characteristic of a synchronous area for i

λuo Set point frequency characteristic of whole synchronous area

Ei Being the electricity generated in control area i

Eu Being the total electricity production in all n control area

Ci Contribution coefficients for λ in i control area

Ppu The total primary control reserve for synchronous area

∆Pa Power deviation of a synchronous area

∆Pdi Control instruction for the activation of generating units under

secondary control in area i

βi Proportional gain of the controller in area i

Tri Integration time constant for the network controller in area i

Gi Overall control deviation (area control error) in area i

∆Pi Interchange capacity deviation for area i in relation to the

scheduled power exchange program

XI

Kri [MW/Hz] parameter applied to network controller of area I

Ke Exciter gain

Ka Regulator gain of exciter

Kf Damping filter gain

Kp Proportional gain

Te Exciter time constant

Tb Transient gain reduction

Tr Low-pass filter time constant of exciter

ef Regulator output of exciter

Efmin Minimum output of regulator

Efmax Maximum output of regulator

h Position of the governor valve

Vfd Exciter voltage

Vn RMS line-to-line voltage

Vt Terminal voltage of generator

GPV Transfer function

Xd Synchronous reactance of direct axis

Xd’ Transient synchronous reactance of direct axis

Xd’’ Sub-transient synchronous reactance of direct axis

Xq Synchronous reactance of quadrature axis

Xq’ Transient synchronous reactance of quadrature axis

Xq’’ Sub-transient synchronous reactance of quadrature axis

Xl Stator leakage reactance

Tdo’ d-axis no load transient time constant

Tdo’’ d-axis no load sub-transient time constant

Tqo’ q-axis no load transient time constant

Tqo’’ q-axis no load sub-transient time constant

H Inertia Constant

XII

LIST OF ABBREVIATIO�S

AGC Automatic Generation Control

APH Air Pre Heater

AVR Automatic Voltage Regulator

CV Control Valve

EH Electronic Highway

EHC Electro Hydraulic Converter

EHG Electro Hydraulic Governor

ESP Electro Static Precipitator

ETSO European Transmission System Operators

FACTS Flexible Ac Transmission Systems

FD Forced Draft

FGD Flue Gas Desulphurization

GENCO Generation Companies

GUI Graphical User Interface

HP High Pressure

ID Induced Draft

IP Intermediate Pressure

LFC Load Frequency Control

LSR Load Shedding Relay

LP Low Pressure

LSR Load Shedding Relay

PC Power Control

PD Proportional Derivative

PI Proportional Integral

PSS Power System Stabilizer

SC Speed Control

SD Speed Droop

SVC Static Var Compensator

TIE Tie Communication Line

XIII

TSO Transmission System Operator

TSR Transient Speed Rise

UCTE Union for the Co-ordination of Transmission of Electricity

UTC Universal Coordinated Time

VWO Valves Wide Open

1. INTRODUCTION S. Olcay BERĐKOL

1

1. I�TRODUCTIO�

Controlling frequency and voltage has always been an essential part of

operating a power system. However, since the liberalization of the electricity supply

industry, the resources required to achieve this control have been treated as services

that the system operator has to obtain from other industry participants. Because this

liberalization has proceeded independently in different parts of the world and

because of the structural differences in the underlying power systems, the technical

definitions of these services and the rules governing their trading vary considerably.

This framework is based on the one used by the Union for the Co-ordination of

Transmission of Electricity (UCTE), which is the association of Transmission

System Operators (TSOs) operating within the synchronous system of mainland

Europe. The UCTE has been establishing the security and reliability standards for

interconnected system (Rebours et al., 2007).

As a part of the European Transmission System Operators (ETSO), the UCTE

is the association of transmission system operators in continental Europe which

interconnects and supplies the vast majority of the population of Europe with

electrical power. Even though the UCTE has developed a number of technical and

organizational rules defined in the UCTE Operation Handbook, the responsibility of

the national TSOs must still be determined in their own guidelines. Because grid

structures vary in different countries and due to the way in which the interfaces to the

other transmission systems are defined and thus to the way in which energy is

exchanged with these other systems over the interconnected power lines, it is

necessary to define specific requirements.

To ensure smooth operation of the system and to enable grid disturbances to

be controlled, a number of technical rules and recommendations need to be followed

in operation of this system. The rules and recommendations of the UCTE form a

common basis for this, providing minimum requirements to be met for grid operation

on this system, which is operated in overall synchronism. These rules and

recommendations stimulate the exchange of electric power beyond the boundaries of


2

the separate countries that form this synchronously interconnected system, and also

promote nondiscriminatory exchange of data for this task.

The technical rules and recommendations do, however, give the individual

TSOs the option of going beyond more compliance with these minimum

requirements, implementing more stringent requirements or even defining these in

greater detail. As a result, individual TSOs or regional TSO associations have drawn

up national grid codes with a number of functions such as defining the sharing of

responsibilities for security of supply, reliability and profitability for the system. For

the TSOs to be able to meet their responsibilities, transmission system users must

comply with the technical minimum requirements and rules specified in the relevant

grid codes.

Not least of all, grid operators are being challenged to make ever larger power

reserves available, to achieve improved distribution of these power reserves within

the interconnected power system and to develop new and better load shedding

concepts for response to disturbances.

There are various reasons for the size and uniformity of the power reserves.

On the one hand, it is necessary for conventional power plants to provide control

reserves corresponding to the entire output supplied by energy producers which

operate without any frequency-control capability, such as renewable energy plants

like wind power stations. These control reserves serve to compensate for power

fluctuations or outages at wind power stations.

On the other hand, liberalization of the electric power markets in Europe and

heavy emphasis on unhindered commercial trading of electric power across national

boundaries wherever possible have also presented new challenges to the transmission

systems. Shortly, members of the UCTE followed suit and reviewed their national

grid codes for the European mainland. The interconnected power system, which was

originally envisioned primarily as a source of mutual assistance and optimization, is

more and more becoming a commercial marketplace.

In the future, transmission system operators must pay even closer attention to

compliance with requirements when the generating units are connected and must also

use test programs to verify the necessary flexibility of these units for grid operation.


3

Power plant manufacturers are working intensively in close co-operation with

companies that operate the generating units to comply with these ever more intricate

rules. These companies have a vested interest in ensuring a reliable energy supply

even in the event of grid disturbances, especially if they are responsible for supplying

power to large urban areas with many industrial plants.

From the perspective of providers of voltage control services it is convenient

to divide the production of reactive power into a basic and an enhanced reactive

power service. The basic or compulsory reactive power service encompasses the

requirements that generating units must fulfill to be connected to the network. The

enhanced reactive power service is a non-compulsory service that is provided on top

of the basic requirements. The terminology of voltage control is much more uniform

than for frequency control and does not need to be discussed further here. This thesis

is especially interested in frequency control.

1.1. Frequency Control

Load-frequency control (LFC) is of importance in electric power system

design and operation. The loading in a power system is never constant. To ensure the

quality of the power supply is necessary to design a load-frequency control system

which deals with the control of loading of the generator depending on the frequency.

There has been continuing interest in designing load-frequency controllers with

better performance. Many control strategies for LFC have been proposed since the

1970s (Wang et al., 1993).

For grid system operation, it is required that the power generated is

continuously matched to demand for the power plant. One parameter for this balance

is the system frequency. If power generation and power demand in the grid system

are the same under undisturbed generation conditions, the system frequency is

exactly equal to the rated frequency 50 Hz. Unforeseen events such as perturbations

in the grid system or shutdown of power plants create an imbalance between

generation and demand, and are reflected in changes in the system frequency.


4

If the power generation is greater than power demand, generators connected

to the grid system speed up. If the power generation is less than power demand,

generators connected to the grid system slow down. When power generation and

power demand are back in balance, the frequency stabilizes. For correct operation of

the transmission system it is necessary to hold the frequency within defined narrow

limits. Minor deviations from the frequency reference value 50 Hz or absence of any

such deviations show that there is a balance of generation and power demand. Faults,

resulting from loss of power plants, shutdown of loads, short circuits, etc. in the

system, result in deviations and gradients of varying magnitudes. These faults can

result with instability of the grid or even in grid outage.

Faults within the anticipated range are controlled by provision of reserve

power. Those faults result in frequency fluctuations that remain within a control band

defined by the grid operator e.g. at UCTE = +/-200 mHz.

Serious system faults that are counteracted by disconnection from the

interconnected system can be occurred and measured such as load shedding. Fast

decreases in frequency in the case of serious system faults can not be solely

counteracted by measures on the generating side. Protection devices are implemented

which switch off loads (load shedding) in case of a specific under-frequency. In the

case of fast decreases in frequency where the frequency remains above a

disconnection limit, it is the task of the generators in order to remain in a stable load

operation mode.

The reaction on frequency deviation caused by an event in the grid is handled

by the frequency control. This is implemented in two time ranges called primary and

secondary controls.

Primary control is the automatic, stabilizing action of active power controls

for the turbine-generators interconnected in the synchronous three-phase grid. This

type of control acts in the time frame of seconds using turbine speed control. We can

say for primary control is the fast component of LFC. Generated power is adjusted

due to the speed by the action of the governor valves in thermal power plants.

Secondary control takes effect after about thirty seconds and acts in the time

frame of minutes so we can say that secondary control slow component of LFC.


5

In order to give reaction to LFC, two basic control methods are used in

thermal power plants called speed control (SC) and power control (PC). SC is used

for start-up, in disturbance states and in island operation. PC mode is used for

primary frequency control while the units are supplying power to 380 kV Turkish

network. Therefore UCTE tests are carried out in PC mode. Speed-governors

compare actual turbine speed with the governor reference 50 Hz rated frequency and

outputs a control signal to the gate controller in accordance with speed-droop set

value, while the units are operating in PC mode.

ISKEN is chosen as reference thermal power plant in Turkey to be able to

understand whether supporting load frequency control policy of UCTE or not. In this

thesis, unit frequency response of reference power plant control system is

investigated and discussed with both simulation and field tests.

1.2. Literature

In literature, a lot of studies about LFC and UCTE are available. Especially,

design of newer and faster controller, giving power reaction regarding to the

frequency, has been studied during the last 30 years. Some of them are listed as

follows.

Inoue and Amano (2006) had investigated thermal power plant model for

dynamic simulation of load frequency control. In the model, MW response of the

thermal power plant is represented using two components. One is the slow

component responding to the MW demand change from the LFC, and the other is the

fast component due to the primary frequency (governor) control. For the former,

demand rate limit, boiler response delay, and boiler steam sliding pressure control

are also considered. For the latter, turbine governor response, turbine load reference

control and steam pressure change due to turbine control valve movement are

considered. The MW control is conducted through the turbine control valve (CV)

position control to fit the generator output power to the MW demand.

Wang et al. (1993) had investigated a robust controller that is proposed for

power system load-frequency control. The proposed robust controller is simple,


6

effective and can ensure that the overall system is asymptotically stable for all

admissible uncertainties. Simulation results show that the proposed robust load-

frequency controller can achieve good performance even in the presence of

generation rate constraint.

Rebours et al. (2007) had investigated survey of the frequency and voltage

control ancillary services due to the UCTE in power systems from various parts of

the world. That study provides a basis for a comparison of frequency control

ancillary services across systems. The document also explains the important

technical features that must be taken into account when procuring or trading

frequency and voltage control ancillary services. Lastly, the specifications for these

ancillary services in eight different systems are reviewed.

Salami et al. (2006) had investigated a method to improve the frequency

response of a power system during restoration. A Load Frequency Control (LFC)

scheme with a PID controller is used. In the initial phase of restoration; the proposed

control scheme helps to increase the amount of load pickup. Presented method is

capable of achieving better frequency response for a determined load step. The aim is

to assess desired frequency response for different power plant. The proposed

controller has been tested for different power plants, and simulation results.

1.3. Content

The content of the thesis is arranged as follows:

After this introduction chapter, chapter 2 presents to the dynamics and

fundamental systems of thermal power plants.

In chapter 3, the goals, benefits and policies of UCTE are presented. The

UCTE regulation of load frequency control is mainly presented.

In chapter 4, control strategy of a steam turbine is presented. Both frequency

control and voltage control are mentioned. Modeling of turbine governor, excitation

and droop characteristic is defined. Speed Controller and Power controller modes are

explained as detailed.


7

In chapter 5, proposed controller is modeled. The simulation results of the

proposed model and the actual test results of step response tests in reference thermal

power plant are presented. The actual test results are compared with simulation

results in this chapter and proven whether they support or not the UCTE requests

regarding primary frequency control.

In chapter 6, a general view to the thesis is presented and the important

conclusions of this study are explained.

2.THERMAL POWER PLANTS S. Olcay BERĐKOL

8

2. THERMAL POWER PLA�TS

The power plant is a facility that transforms various types of energy into

electricity or heat for some useful purpose. The energy input to the power plant can

vary significantly, and the plant design to accommodate this energy is drastically

different for each energy source. The forms of this input energy can be as follows:

• The potential energy of an elevated body of water, which, when used,

becomes a hydroelectric power plant

• The chemical energy that is released from the hydrocarbons contained in

fossil fuels such as coal, oil, or natural gas, which becomes a fossil fuel fired

power plant

• Solar energy from the sun, which becomes a solar power plant

• The fission or fusion energy that separates or attracts atomic particles, which

becomes a nuclear power plant (Woodruff et al., 2004)

In those power plants, the conversion of water to steam is the predominant

technology, and this chapter describes this process, various systems and equipments.

A thermal power station is a power plant in which the prime mover is steam

or gas driven. The greatest variation in the design of thermal power stations is due to

the different fuel sources. Some prefer to use the term energy center because such

facilities convert forms of heat energy into electrical energy. Almost all coal, nuclear,

geothermal, solar thermal electricity, and waste incineration plants, as well as many

natural gas power plants are thermal.

The basically general process of a thermal power plant can be briefly

explained as follows. Water is heated, turns into steam and spins a steam turbine

which drives an electrical generator. After it passes through the turbine, the steam is

condensed in a condenser. This is known as a rankine cycle which originated around

the performance of the steam engine.

In a thermal power plant, the chemical energy stored in fossil fuels such as

coal, fuel oil, natural gas is converted successively into thermal energy, mechanical

energy and finally electrical energy for continuous use and distribution across a wide

geographic area. In the rankine cycle, high pressure and high temperature steam


9

raised in a boiler is expanded through a steam turbine that drives an electric

generator. Thermal power plants have very high availability and can operate for more

than a year between shutdowns for maintenance and inspections. Their unplanned or

forced outage rates are very low.

The electric efficiency of a conventional thermal power station, considered as

saleable energy produced at the plant bus bars compared with the heating value of

the fuel consumed, is typically 33 to 48% efficient, limited as all heat engines are by

the laws of thermodynamics called carnot cycle. The rest of the energy must leave

the plant in the form of heat. This waste heat can be disposed of with cooling water

or in cooling towers. If the waste heat is utilized for e.g. district heating, it is called

cogeneration. An important class of thermal power station is associated with

desalination facilities; these are typically found in desert countries with large

supplies of natural gas and in these plants, freshwater production and electricity are

equally important co-products.

ISKEN, our reference plant, is coal fired thermal power plant and consists of

two units with 605MW net output at valves wide open (VWO) each. The plant is

designed for base load operation between 80 and 100 % net output and is connected

to the Turkish grid via 380kV substation.

2.1. Steam Turbine

A steam turbine is a mechanical device that extracts thermal energy from

pressurized steam, and converts it into rotary motion. Steam turbines are made in a

variety of sizes ranging from small 1 hp (0.75 kW) units rarely used as mechanical

drives for pumps, compressors and other shaft driven equipment, to 2,000,000 hp

(1,500,000 kW) turbines used to generate electricity. There are several classifications

for modern steam turbines.

An ideal steam turbine is considered to be an isentropic process, or constant

entropy process, in which the entropy of the steam entering the turbine is equal to the

entropy of the steam leaving the turbine. No steam turbine is truly isentropic,

however, with typical isentropic efficiencies ranging from 20%-90% based on the


10

application of the turbine. The interior of a turbine comprises several sets of blades,

or called buckets as they are more commonly referred to. One set of stationary blades

is connected to the casing and one set of rotating blades is connected to the shaft. The

sets intermesh with certain minimum clearances, with the size and configuration of

sets varying to efficiently exploit the expansion of steam at each stage.

To maximize turbine efficiency, the steam is expanded, generating work, in a

number of stages. These stages are characterized by how the energy is extracted from

them so there are two principal turbine types called impulse and reaction turbines

(Bloch, 1995). Most modern steam turbines are a combination of the reaction and

impulse design. Typically, higher pressure sections are impulse type and lower

pressure stages are reaction type.

An impulse turbine has fixed nozzles that orient the steam flow into high

speed jets. These jets contain significant kinetic energy, which the rotor blades,

shaped like buckets, convert into shaft rotation as the steam jet changes direction. A

pressure drop occurs across only on the stationary blades, with a net increase in

steam velocity across the stage.

As the steam flows through the nozzle its pressure falls from steam chest

pressure to condenser pressure or atmosphere pressure. Due to this relatively higher

ratio of expansion of steam in the nozzle, the steam leaves the nozzle with a very

high velocity. The steam leaving the moving blades is a large portion of the

maximum velocity of the steam when leaving the nozzle. The loss of energy due to

this higher exit velocity is commonly called the carry over velocity or leaving loss.

In the reaction turbine, the rotor blades themselves are arranged to form

convergent nozzles. This type of turbine makes use of the reaction force produced as

the steam accelerates through the nozzles formed by the rotor. Steam is directed onto

the rotor by the fixed vanes of the stator. It leaves the stator as a jet that fills the

entire circumference of the rotor. The steam then changes direction and increases its

speed relative to the speed of the blades. A pressure drop occurs across both the

stator and the rotor, with steam accelerating through the stator and decelerating

through the rotor, with no net change in steam velocity across the stage but with a


11

decrease in both pressure and temperature, reflecting the work performed in the

driving of the rotor.

Steam turbine in reference thermal plant is five mass with separate casings-

arranged on one rotor with the generator. The steam turbine generator set is of the

single reheat condensing type. The turbine set consists of one high pressure (HP),

one intermediate pressure (IP) and two low pressure (LP) casings exhausting

downwards into the condenser. The greater part of the blade is designed as drum-

type blade with 50% reaction.

The HP turbine is of single flow design with full arc admission. The double-

shell casing consists of a guide blade carrier and a barrel-type outer casing. Main

steam to the HP turbine is admitted laterally via two combined stop and control

valves. At the front end of the HP turbine the steam is exhausted downward via an

exhaust branch to which the cold reheat is connected.

The IP turbine is of double flow design. The double shell casing is of a split

inner and outer casing. Reheat steam is admitted via two combined stop and control

valves into the middle of the turbine. The exhaust branch on the top of the casing is

mounted to the crossover piping which leads to the LP turbine.

The LP turbines consist of two double flow units with a horizontally split

multi-shell casing. The welded outer casing rests on the condenser to which it is

rigidly connected by means of a welded joint. The cast inner casing is supported by

four integrally cast support arms which rest on the bearing brackets protruding

through the end walls of the LP turbine.

2.1.1. Governor (Control) and Stop Valves

The governor valve is common to all turbine applications. This is the valve

between the main supply and the turbine. This valve is the primary means of

controlling unit. When the demand for energy from the turbine is changed, it is the

opening of this valve that changes to match the new demand by introducing a new

supply of steam energy (Liptàk, 2006). Hence, it can be said that governor valves


12

control the flow of steam to turbine according to a specified load so in literature,

governor valve is also called control valves.

The stop valves are isolating valves with protective function, triggered by

protective devices to interrupt the steam supply in the event of dangerous operating

conditions. For this reason, they are designed for high-speed closing with maximum

reliability. The stop and control valves have electro-hydraulic actuators with fluid

supply by self contained high pressure fluid system with positive displacement

pumps. The actuator travels the respective valve by hydraulic action against the force

of a spring. The valves are closed by spring force in the event of loss of power

supply.

2.1.2. Condenser

The function of the condenser is to condense the steam exhausted from the LP

cylinders and to produce and maintain as high a vacuum as possible in order to

increase the heat drop which can be utilized in the turbine. The condensers are

single-flow box-type surface condenser with water boxes on each end. The steam

space is of rectangular cross-section to achieve optimum utilization of the enclosed

volume for the necessary condensing surface. The condensers are located below the

LP turbines shown in figure 2.1 and form an integral part of it. If the condenser can

be made cooler, the pressure of the exhaust steam is reduced and efficiency of the

cycle increases. Cooling water circulates through the tubes in the condenser's shell

and the low pressure exhaust steam is condensed by flowing over the tubes. The

tubing is designed to reduce the exhaust pressure, avoid subcooling the condensate

and provide adequate air extraction. The condenser, in effect, creates the low

pressure required to drag steam through and increase the efficiency of the turbines.

The limiting factor is the temperature of the cooling water and that, in turn, is limited

by the prevailing average climatic conditions at the power plant's location (it may be

possible to lower the temperature beyond the turbine limits during winter, causing

excessive condensation in the turbine). Powerful condensate pumps, where is in the


13

bottom of the condenser, recycle the condensed steam (water) back to the

water/steam cycle.

Figure 2.1 A turbo-generator system with five mass

2.1.3. Turbine Bypass System

During startup, shutdown and load disturbances in a power plant, the boiler

and steam turbine need to be isolated from one another. This is to protect the turbine

from any water carry over, but also to protect additional plant equipments from large

thermal transients. By isolating the boiler and steam turbine, it is also possible to

reduce fuel consumption during startup and shutdown. In the event of a load

rejection, reloading times can also be improved through the turbine bypass system.

The bypass system of turbine is used to send steam into condenser. After

condenser, a condensate pump is used to pump the condensate back to the feedwater

tank/deaerator (Kehlhofer et al., 1999). The turbine bypass system is designed to

provide the quickest startup time by controlling both boiler pressure and temperature.

Bypassing the steam around the turbine allows the steam to attain the desired

qualities before being routed through the turbine. If the turbine bypass system were


14

not used, the firing rate of the boiler would have to be reduced, which could lead to

tube failures. The bypass system allows the boiler to be fired at full capacity without

introducing large thermal gradients in the thick walled components such as the boiler

drum and any separators or flash tanks.

The steam is desuperheated by means of feedwater or condensate injection

via spray water valves. The bypass system discharges the steam into the condenser.

The bypass system is in operation when the steam turbine is not able to receive the

entire steam quantity, e. g. during start-up or in case of a load rejection.

2.2. Steam Generator

Steam generators or boilers are a central element in today’s modern thermal

power station. They convert the energy in the fuel to a useful form called steam. The

steam generating boiler has to produce steam at the high purity, pressure and

temperature required for the steam turbine that drives the electrical generator.

The steam generator includes the economizer, the steam drum, the chemical

dosing equipment, and the furnace with its steam generating tubes and the

superheater and reheater coils. Superheaters and reheaters are used in once-through

and drum boilers and consist of in-line tube bundles that increase the temperature of

the steam. They are simple single-phase heat exchangers with steam flowing inside

the tubes and the flue gas passing outside. They are typically configured to help

control steam flow pressure loss. The economizer is a counterflow heat exchanger for

energy recovery downstream of the superheater and reheater. It increases the

temperature of the feedwater before it enters the steam drum. The tube bundle is

typically an arrangement of parallel horizontal serpentine tubes with water flowing

inside but in the opposite direction (counterflow) to the flue gas. By design, steam is

usually not generated inside these tubes (Elliott et al., 1997).

The efficient combustion of fuel and transfer of heat in the boiler require that

adequate combustion air be provided and that flue gas be removed from the area of

combustion. In some small, old boilers, removal is accomplished solely by natural

convection, commonly called natural draft. The hot flue gas rises through the stack


15

and draws in cool air for combustion. As boilers become larger, natural draft alone

becomes inadequate, and a fan must be added to blow enough air into the furnace for

combustion. If the fan is large enough, it pressurizes the boiler furnace and aids in

the removal of the flue gas. Such a fan is called a forced-draft (FD) fan. Boilers with

FD fans and no induced-draft (ID) fans are called pressurized-furnace boilers

because flue gas, which is toxic and corrosive, and fly ash leak out of the smallest

openings in the furnace, causing maintenance and personnel safety problems. In

addition, some large boilers with considerable convective heat-transfer area need

more than just an FD fan to move the flue gas.

The solution to these problems is another fan-ID fan- that takes suction on the

furnace at the flue gas exit. Boilers having both FD and ID fans include dampers or

inlet vanes on the fans to balance them, and they operate at a slightly negative

furnace pressure.

Another feature in combustion air and flue gas systems is combustion air

heater. In order to increase the thermal efficiency of boiler, air-preheater (APH) is

used.

Also, steam generator has fly ash collectors (electro static precipitator or

baghouse), the flue gas stack for air emission controls and necessary safety valves

are located at suitable points to avoid excessive boiler pressure (Babcock & Wilcox

Co., 2005).

The steam generator in reference plant is of the subcritical, once-through

(BENSON), modified sliding pressure type, burning pulverized coal in a low-NOx

firing system. The combustion air and flue gas system is of single-train design and is

arranged in one line, including fans, air heaters, and flue gas desulphurization (FGD)

system. The steam generator is a fully welded version suspended in a steel

supporting structure and is an outdoor tower construction.

2.2.1. Combustion Loop

On the hot gas side of the boiler, two types heat transfer are available as

thermal radiation and convection. This situation exists because the fireball from the


16

burning fuel is so hot that a tremendous amount of energy is generated, heating the

gas to very high temperatures. Almost all heat transferred to the waterwalls of the

boiler is by thermal radiation. After the fuel burns and the combustion products (flue

gas) cool in the furnace, the gas that remains is still very hot, but much less so than in

the combustion zone. Thus there is much less radiation. Heat is primarily transferred

from the hot gas to other tubes in the boiler by convection. Usually the superheater

and reheater are in the convection section of the steam generator, while the

economizer is always in this section.

The steam generator is equipped with direct pulverized bituminous coal firing

in reference plant. To ignite the steam generator and to serve as backup for the coal

firing system at low load, a backup and ignition firing system for light oil is installed.

The coal firing system for the steam generator is an opposed firing system with

vertically staggered burner arrangement.

Raw coal is transported from the coal bunker through a feeder into the mill

where it is uniformly ground and dried. Drying as well as subsequent transport of the

pulverized coal through the various pulverized-coal pipes to the burners takes place

by means of primary air. The primary air is a mixture of hot air and cold air.

Combustion air is delivered to the firing system as follows:

• Primary air including sealing air via the coal mills

• Core air to the burners

• Secondary air to the burners

• Tertiary air to the burners

• Relatively small amount of air via the dry ash extraction system below the

furnace hopper

2.2.2. Combustion Air and Flue Gas

The air and flue gas system comprises, besides the air and flue gas lines, the

necessary facilities for instrumentation and control of the following main

components: forced draft fan, primary air fan and induced draft fan, steam air heater,


17

regenerative air heater, electrostatic precipitator (ESP) and flue gas desulphurization

(FGD) plant.

The flue gas from each unit is united after the two electrostatic precipitators

(for each unit) to a common bus bar and routed to the absorber system. The flue gas

ducts feeding the stack are equipped with dampers with seal air. This allows to

bypass the subsequent equipment in case of operating problems with the flue gas

desulphurization plant. The clean gas duct downstream flue gas desulphurization to

gas bus bar (to stack) is also equipped with a double damper to allow operation

without the flue gas desulphurization plant. The flue gas desulphurization process

applied is the wet process with limestone and the production of dry gypsum.

2.2.3. Pressure Part (Water / Steam)

The feedwater enters the boiler via one connection pipe at economizer inlet.

The economizer is passed parallel to the flue gas flow. From the economizer outlet

the preheated water flows via connection pipes and distributors to the evaporator

inlet headers. From the evaporator inlet the medium passes the hopper and the spiral

walls of the furnace and radiation chamber. Behind the spiral the medium is

distributed to the vertical tubing of the radiation chamber and convection part of the

boiler.

Water-steam separation is necessary for once-through boilers only at part

load, for all recirculation boilers besides the combined-circulation boiler over the

whole-load range (Kakaç, 1991). The outlet of the vertical tubing builds the outlet of

the evaporator. Depending on the load, the steam or water-steam mixture is led to the

separators for separation of steam and water. In normal Benson operation, the

medium is superheated at this point.

The steam flows via two connection pipes to the superheater 1 supporting

tubes and screen system. The supporting tubes, on which the convection heating

surfaces are suspended, are flown through in counter flow of the flue gas. The

surface is at the outlet divided into four symmetrical, parallel systems. The first spray

type attemperator is arranged behind superheater 1. The steam is cooled down by


18

feedwater. The bleeding point for the spray water is arranged behind the HP

preheater.

Superheater 2 is a coil tube heating surface and is arranged in counter flow to

the flue gas. The second spray water attemperator is placed behind superheater 2.

Superheater 3 is arranged in parallel flow to the flue gas and is the final superheater.

Between superheater 2 and superheater 3 there is a steam-side crossing for reducing

the temperature differences between the two parallel systems. The steam is heated up

to 541 °C and led to the turbine or to the HP-bypass station.

The steam coming from the HP turbine or from the HP Bypass, flows via the

cold reheat line to reheater 1. Reheater 1 is a coil tube heating surface and is arranged

in counter flow to the flue gas. The reheater spray water attemperator is placed

behind reheater 1. Reheater 2 is arranged in parallel flow to the flue gas and is the

final reheater. Between reheater 1 and reheater 2 there is a steam-side crossing for

reducing the temperature differences between the two parallel systems. The steam is

heated up to 539 °C and led to the IP/LP turbine or to the LP-bypass station.

To control malfunctions, the high pressure system is equipped HP bypass

station and part flow safety valves. The reheat system has also safety valves. The

safety valves discharge the steam directly to atmosphere.

2.2.4. Water / Steam Cycle

The main condensate arising through condensation of the exhaust steam, the

drains from LP feedwater heaters and the makeup water in the two condenser

hotwells is collected in the condenser hotwells and discharged by the condensate

pumps system. The heated condensate is routed via the deaerator into the feedwater

tank.

The LP feedwater heaters and the feedwater tank are heated using extraction

steam from the steam turbine. A condensate polishing plant is arranged in parallel to

the condensate system. The condensate is deaerated to deaerator before entering the

feedwater tank. The feedwater tank serves as a buffer for feedwater supply to the

steam generator. During normal operation the tank is heated by intermediate pressure


19

extraction steam from turbine extraction point. In the event of turbine trip or low-

load operation the deaerator is supplied with pegging steam from the cold reheat line.

During start-up, the feedwater tank is heated using auxiliary steam.

During normal operation the two main feedwater pumps pump the feedwater

from the feedwater tank through two high pressure feedwater heaters to the steam

generator.

After entering the steam generator superheated steam is produced and this is

returned to the condenser via the main steam system. A sufficient scope of

instrumentation provides information on pressures, temperatures, flowrates and valve

positions. Connections to sampling system allow steam quality to be monitored.

During start-up operation or in the event of turbine trip the pressure of the

generated HP steam is controlled by HP bypass station. The temperature is controlled

by spray attemperation using feedwater. The steam is then routed to the boiler via the

cold reheat system in order to cool the reheater. The steam leaves the boiler through

the hot reheat system and is routed to the turbine condensers via LP reducing station.

Supply lines from the cold reheat piping are provided for the auxiliary steam header.

2.2.5. Cooling Water System

Cooling water is extracted from the sea or lake, in reference plant from the

sea, and cooling water systems consist mainly of:

• Circulating water system

• Service water system

• Auxiliary cooling water system

The circulating water system is designed to remove the heat of the main

steam turbine condensers. The heat of condensation is transferred from the turbine

condenser to the circulating water which flows through the condenser tubes. A

second task of the circulating water system is to supply the service water system with

water for cooling the closed cooling water heat exchanger. The corresponding branch

to the service water system is located upstream the steam turbine condenser.


20

The cooling water of the circulating water system is pumped by the

circulating water pumps to the main steam turbine condensers and to the service

water system. The cooling water is taken from the intake pump house building

located at the Mediterranean sea coast and discharged via a seal pit back to sea. As

long as the circulating water is in operation, the tube cleaning system for the

condenser tubes should be in operation too. It removes any deposits which might

impair the heat transfer through the condenser tubes.

The service water system has the task to remove heat dissipated by the

various auxiliary equipments to the closed cooling water system via the closed

cooling water heat exchangers to the circulating water system. The required service

water mass flow is taken from the circulating water system upstream the condenser

and is calculated on the basis of the maximum heat to remove and required

temperature drop over the closed cooling heat exchangers.

The closed cooling water is designed as a closed circuit system and serves to

transfer the heat dissipated by components or their auxiliary equipments, such as

turbine lube oil coolers, seal oil coolers, exciter coolers etc., via the closed cooling

water heat exchanger to the service water system. The auxiliary cooling water system

has to be available during start-up, normal operation and shutdown of the plant and

standby operation of certain auxiliary equipment. The closed cooling water cycle is

filled with demineralized water which is treated with ammonia.

2.2.6. Generator System

Electric generators are rotating machines that convert mechanical energy to

electric energy. The synchronous generator is a relatively simple machine made of

two basic parts: a stator (stationary) with the output windings arranged around its

periphery and a rotor (rotating) with dc windings acting as an electromagnet. The

rotor windings are fed from a dc source either an external source or an exciter

system.

Synchronous generators are so named because an exact relationship exists

among the number of electrical poles, rotating speed, and the output frequency of the


21

machine, which is in synchronism with all other machines on the interconnected

system. The generated frequency (in cycles per second, or hertz) is equal to the

number of rotor magnetic poles times the speed (expressed in revolutions per minute

or rpm) divided by 120. For example, a two pole machine rotating at 3000 rpm has

an output frequency 50 Hz. Changing the speed of the driving engine or turbine will

change the output frequency exactly as the speed is changed. If the synchronous

generator is connected to a large power grid, attempts to increase the turbine speed

by increasing the mechanical power output will result in a corresponding increase in

electric power output at the speed and frequency determined by the interconnected

synchronous power system.

The generator unit comprises a two-pole, hydrogen-cooled turbogenerator

which is directly coupled to the turbine, a direct water cooling system for the stator

winding, a static excitation system with a two-channel digital voltage regulator and

the requisite supply systems in reference power plant.

The stator winding (armature) is connected to the ac electrical transmission

system through the bushings and output terminals. The rotor winding (field) is

connected to the generator's excitation system. The excitation system provides the

direct-current (dc) field power to the rotor winding via carbon brushes riding on a

rotating collector ring mounted on the generator rotor.

There are five sources of heat loss in a synchronous generator: stator winding

resistance, rotor winding resistance, core, windage and friction, and stray losses.

Removing the heat associated with these losses is the major challenge to the machine

designer. The cooling requirements for the stator windings, rotor windings, and core

increase proportionally to the cube of the machine size.

The stator winding of generator in reference plant is directly cooled by water

and the rotor winding by hydrogen. The heat produced in the other components as a

result of losses such as iron losses, friction and stray losses is dissipated by hydrogen

cooling. The heat in the core is uniformly dissipated via a large number of radial

cooling slots.

3. UCTE RULES S.Olcay BERĐKOL

22

3. UCTE (Union for the Co-ordination of Transmission of Electricity)

The UCTE is the association of transmission system operators in continental

Europe, providing a reliable market base by efficient and secure electric power

highways. UCTE is keeping the lights on throughout the electric system, serving

some 500 million people. Annual electricity consumption is approximately 2100

TWh through the networks of UCTE (UCTE Operation Handbook, 2004).

UCTE has co-ordinated through a wide variety of technical rules and

recommendations for the international operation of high-voltage grids that all work

with one heart beat. The 50 Hz UCTE frequency is related to the nominal balance

between offer and demand. UCTE commits itself to the development of the system to

meet all new market requirements, but without accepting losses in terms of reliability

for the existing system. UCTE operates one of the largest electric synchronous

interconnections worldwide. This technical solution permits the functioning of a free

electricity market in general and regional markets as well.

Therefore, UCTE is an efficient, qualitative and secure operation of the

interconnected electrical power supply-demand and gives signals to markets when

system adequacy declines.

The goals of UCTE are as follows;

• to ensure reliable and secure interconnected transmission system operation

• to reduce transmission costs to the lowest possible level by

� co-ordinating electricity flows and

� sharing reserve capacities among countries

• to facilitate the functioning of the electricity market by ensuring non-

discriminatory domestic and cross-border access to the grid

• to enhance opening up of national transmission systems for international

exchanges

• to enlarge the existing electricity market place by extending the

interconnected area towards South-East Europe and neighbouring regions

• to lobby on the behalf of its members at EU institutions, regulators and other

associations of the electricity market in order to ensure the maintenance of


23

reliability and the development of the electricity system in the open electricity

market.

The benefits of UCTE are as follows;

• optimization of the use of installed capacities

• reliability improvements reducing the economic cost of power outages

• improved control of system frequency to minimize major disturbances

• stable voltage

• sharing reserve capacities and reducing the level of reserves required

• providing mutual support for the interconnected systems in case of

emergency

In this study, load-frequency control policy, which is the most important

parameter in order to be a member of UCTE network, is especially mentioned and

other policies interested by UCTE are briefly explained.

3.1. UCTE Policies

UCTE has seven strict policies/rules to provide high quality and reliability

electricity in interconnected network. Titles and subtitles of policies are listed as

below.

1. Load-Frequency Control and Performance

1.1. Primary Control

1.2. Secondary Control

1.3. Tertiary Control

1.4. Time Control

1.5. Measures for Emergency Conditions

2. Scheduling and Accounting

2.1. Scheduling

2.2. Online Observation

2.3. Accounting

3. Operational Security

3.1. N-1 Security (operational planning and real-time operation)


24

3.2. Voltage control and reactive power management

3.3. Network faults clearing and short circuit currents

3.4. Stability

3.5. Outages scheduling

3.6. Information exchanges between Transmission System Operators (TSOs) for

security of system operation

4. Co-ordinated Operational Planning

4.1. Outage Scheduling

4.2. Capacity Assessment

4.3. Capacity Allocation

4.4. Day Ahead Congestion Forecast

4.5. Congestion Management

5. Emergency Procedures

6. Communication Infrastructure

6.1. The Electronic Highway (EH) Network, Architecture and Operation

6.2. Real Time Data Collection and Exchange

6.3. File Transfer data Exchange

6.4. E-Mail on the EH

6.5. Information Publication in Hypertext on EH

6.6. Procedures for future Services on EH

6.7. Non-EH communication among TSOs

7. Data Exchanges

7.1. Code of conduct and generic rules to handle the data

3.1.1. Load-Frequency Control and Performance

The generation of power units connected to the UCTE network needs to be

controlled and monitored for secure and high-quality operation of the synchronous

areas. The generation control, the technical reserves and the corresponding

performance measurements are essential to allow transmission system operators

(TSO) to perform daily operational business. Control actions are performed in


25

different successive steps, each with different characteristics and qualities, and all

depending on each other (UCTE Operation Handbook Policy1, 2004)

• Primary control starts within seconds as a joint action of all undertakings

involved.

• Secondary control replaces primary control after minutes and is put into

action by the responsible undertakings / TSOs only.

• Time control corrects global time deviations of the synchronous time in the

long term as a joint action of all undertakings / TSOs.

Transmission System Operator (TSO) is the pilot of the electricity system.

The TSO is responsible for the safe operation of the system. Each of TSO in the

UCTE interconnected network (synchronous areas) has declared to follow the

technical standards and procedures that are comprised in operation handbook (UCTE

Operation Handbook, 2004). This means that

• taking care of the safe transmission of electricity

• taking care of the reliability and stability of the system

• balancing supply and demand at any time

• maintaining and developing the infrastructure: the networks and related

technical facilities.

In the liberalized electricity market that is developing in the European Union,

the TSO is not itself a market party. Rather, it is the provider of the infrastructure and

of the system management services that are the necessary prerequisites for the

functioning of the market.

As a provider of these services to market parties (generators, traders and

suppliers of electricity) the TSO has not only the technical responsibility for system

operations, but is also responsible for the fair and non-discriminatory access to these

services by market participants. The neutral and independent TSO is a precondition

for fair competition.

Each of generation companies, operating a generating unit in the UCTE

interconnected network, makes use of the transmission network and may have to

deliver products for the provision of system services that are indispensable for secure

and stable grid operation


26

3.1.1.1. Primary Control

The objective of primary control is to maintain a balance between generation

and demand (consumption) within the synchronous areas, using turbine speed or

turbine governors. By the joint action of all interconnected undertakings / TSOs,

primary control aims at the operational reliability of the power system of the

synchronous areas and stabilizes the system frequency at a stationary value after a

disturbance or incident in the time-frame of seconds, but without restoring the

reference values of system frequency and power exchanges. Adequate primary

control depends on generation resources made available by generation companies to

the TSOs (UCTE Operation Handbook Policy1, 2004).

3.1.1.2. Balance between Generation and Demand

In any electric system, the active power has to be generated at the same time

as it is consumed. Power generated must be maintained in constant equilibrium with

power consumed / demanded, otherwise a power deviation occurs. Disturbances in

this balance, causing a deviation of the system frequency from its set-point values,

will be offset initially by the kinetic energy of the rotating generating sets and motors

connected. There is only very limited possibility of storing electric energy as such. It

has to be stored as a reservoir (coal, oil, water) for large power systems, and as

chemical energy (battery packs) for small systems. This is insufficient for controlling

the power equilibrium in real-time, so that the production system must have

sufficient flexibility in changing its generation level. It must be able instantly to

handle both changes in demand and outages in generation and transmission, which

preferably should not become noticeable to network users (UCTE Operation

Handbook Appendix1, 2004).

3.1.1.3. System Frequency

The electric frequency in the network (the system frequency f) is a measure


27

for the rotation speed of the synchronized generators. By increase in the total demand

the system frequency (speed of generators) will decrease, and by decrease in the

demand the system frequency will increase. Regulating units will then perform

automatic primary control action and the balance between demand and generation

will be re-established. The frequency deviation is influenced by both the total inertia

in the system, and the speed of primary control. Under undisturbed conditions, the

system frequency must be maintained within strict limits in order to ensure the full

and rapid deployment of control facilities in response to a disturbance. Out of periods

for the correction of synchronous time, the set point frequency is 50 Hz (UCTE

Operation Handbook Appendix1, 2004).

Three types of operating conditions are considered where the deviation |∆f|

between the instantaneous frequency and the set point frequency is

• Equal to or less than 50 mHz, operating conditions are considered as normal

• Greater than 50 mHz but less than 200 mHz, operating conditions are deemed

to be impaired, but with no major risk, provided that control facilities in the

affected areas are ready for deployment

• Greater than 200 mHz, operating conditions are deemed to be severely

impaired, because there are significant risks of the malfunction of the

interconnected network.

Even in case of a major frequency deviation / offset, each control area will

maintain its interconnections with adjoining control areas, provided that the secure

operation of its own system is not jeopardized.

3.1.1.4. (etwork Power Frequency Characteristic

An interconnected system consists of control areas (power generation center)

connected by a tie line (TIE). A Tie line is a communication connection between

extensions of a private telephone system. For load-frequency the studies, each area

may be represented by an equivalent bus. On each bus there is equivalent generation.

The network power frequency characteristic of whole synchronous area uλ is

quotient of the power deviation ∆Pa responsible for the disturbance and the quasi-


28

steady state frequency deviation ∆f caused by the disturbance (power deficits are

considered as negative values).

f

P au ∆

∆=λ in MW/ Hz (3.1)

The network power frequency characteristic, λi is measured for a given

control area i. This corresponds to the quotient of the power deviation, ∆Pi, and the

frequency deviation, ∆f, in response to the disturbance (in the control area where the

disturbance originates, it will be necessary to add the power surplus, or subtract the

power deficit, responsible for the disturbance concerned).

f

Pii

∆

∆=λ in MW/ Hz (3.2)

The contribution of each control area to the network power frequency

characteristic is based upon the set point value for the network power frequency

characteristic, λio, in the control area concerned. This set-point value is obtained by

the multiplication of the set-point network power frequency characteristic for the

entire synchronous area, λuo, and the contribution coefficients of the various control

areas, Ci :

uoiC λλ ×=io (3.3)

This formula is used to determine the requested contribution Ci of a control

area to primary control.

The network power frequency characteristic of a given control area should

remain as constant as possible, within the frequency range applied. This being so, the

insensitivity range of controllers should be as small as possible, and in any case

should not exceed ±10 mHz. Where dead bands exist in specific controllers, there

must be offset within the control area concerned. The set-point value λuo for the

overall network power frequency characteristic is defined by the UCTE on the basis

of the conditions described in the policy, taking account of measurements,

experience and theoretical considerations (UCTE Operation Handbook Appendix1,

2004).


29

3.1.1.5. Primary Control Basics

Various disturbances or random deviations which impair the equilibrium of

generation and demand will cause a frequency deviation, to which the primary

controller of generating sets involved in primary control will react at any time.

The proportionality of primary control and the collective involvement of all

interconnection partners are such that the equilibrium between power generated and

power consumed will be immediately restored, thereby ensuring that the system

frequency is maintained within permissible limits. In case that the frequency exceeds

the permissible limits, additional measures out of the scope of primary control, such

as (automatic) load-shedding, are required and carried out in order to maintain

interconnected operation.

This deviation in the system frequency will cause the primary controllers of

all generators subject to primary control to respond within a few seconds. The

controllers alter the power delivered by the generators until a balance between power

output and consumption is re-established. As soon as the balance is re-established,

the system frequency stabilizes and remains at a quasi-steady-state value, but differs

from the frequency set-point because of the droop of the generators which provide

proportional type of action. Consequently, power cross-border exchanges in the

interconnected system will differ from values agreed between companies. Secondary

control will take over the remaining frequency and power deviation after 15 to 30

seconds. The function of secondary control is to restore power cross-border

exchanges to their (programmed) set-point values and to restore the system

frequency to its set-point value at the same time (UCTE Operation Handbook

Appendix1, 2004).

The magnitude of the dynamic frequency deviation is governed mainly by the

following:

• The amplitude and development over time of the disturbance affecting the

balance between power output and consumption

• The kinetic energy of rotating machines in the system


30

• The number of generators subject to primary control, the primary control

reserve and its distribution between these generators

• The dynamic characteristics of the machines (including controllers)

• The dynamic characteristics of loads, particularly the self-regulating effect of

loads

The quasi-steady-state frequency deviation is governed by the amplitude of

the disturbance and the network power frequency characteristic, which is influenced

mainly by the following:

• The droop of all generators subject to primary control in the synchronous

areas

• The sensitivity of consumption to variations in system frequency

3.1.1.6. Principle of Joint Action

Each TSO must contribute to the correction of a disturbance in accordance

with its respective contribution coefficient to primary control. These contribution

coefficients Ci are calculated on a regular basis for each control area or

interconnection partner / TSO using the following formula:

uii EEC ÷= (3.4)

Ei being the electricity generated in control area/ i (including electricity

production for export and scheduled electricity production from jointly operated

units) and Eu being the total (sum of) electricity production in all N control areas of

the synchronous areas.

In order to ensure that the principle of joint action is observed, the network

power frequency characteristics of the various control area should remain as constant

as possible. This applies particularly to small frequency deviations ∆f, where the

dead bands of generators may have an unacceptable influence upon the supply of

primary control energy in the control area s concerned (UCTE Operation Handbook

Appendix1, 2004).


31

3.1.1.7. Target Performance

Defining conditions for the target efficiency of primary control are based upon

the following parameters:

• the simultaneous loss of two power plant units, or the loss of a line section or

busbar

• experience has shown that incidents leading to an even greater loss of power

are extremely rare

• the control of such incidents by the activation of far greater control power

than is necessary may lead to the overloading of the transmission system,

thereby jeopardizing the interconnected network

The design hypothesis applied is based upon unfavorable parameters which

provide a margin of safety in estimated values. Consequently, it is probable that even

more serious incidents could be accommodated in practice without the need for load-

shedding. Based on the parameters above, the reference incident was defined to be

3000 MW for the entire synchronous areas.

Starting from undisturbed operation of the interconnected network, a sudden loss

of 3000 MW generating capacity must be offset by primary control alone, without

the need for customer load-shedding in response to a frequency deviation. In

addition, where the self-regulating effect of the system load is assumed according to

be 1 %/Hz, the absolute frequency deviation must not exceed 180 mHz. Likewise,

sudden load-shedding of 3000 MW in total must not lead to a frequency deviation

exceeding 180 mHz. Where the self-regulating effect of the load is not taken into

account, the absolute frequency deviation must not exceed 200 mHz. The following

figure 3.1 shows movements in the system frequency for a given design hypothesis

(case A), where dynamic requirements for the activation of control power are

fulfilled in accordance with the requirements for deployment time. Unfavorable

assumptions have been selected for all model parameters. The maximum absolute

frequency deviation is 800 mHz - this means that the threshold for load-shedding will

not be reached by some margin.


32

A Loss in generating capacity: P =3000 MW, Pnetwork = 150 GW, self-regulating effect of load

1% / Hz B1 Loss in generating capacity: P =1300 MW, Pnetwork = 200 GW, self-regulating effect of

load 2% / Hz B2 Loss in generating capacity: P =1300 MW, Pnetwork = 200 GW, self-regulating effect of

load 1% / Hz

Figure 3.1 System frequency movements for different design hypothesis (UCTE Operation Handbook Appendix1, 2004)

For comparative purposes, simulations have also been undertaken using

realistic model parameters (case B), in order to allow the typical frequency deviation

associated with customary losses in generating capacity to be plotted in parallel.

These simulations show that, for a loss of capacity up to 1300 MW, the absolute

frequency deviation will remain below 200 mHz. If the target performance described

above is to be achieved, the system must be operated in such a way, depending upon

the system load, that the network power frequency characteristic for the entire

synchronous area falls within a relatively narrow band. Taking account of the self-

regulating effect of load, this gives the following table (UCTE Operation Handbook

Appendix1, 2004).


33

Table 3.1 Self regulating effect of load (UCTE Operation Handbook Appendix1, 2004)

Self-regulating effect Network power Network power frequency characteristic

1 %/Hz 150 GW 16500 MW/Hz

1 %/Hz 300 GW 18000 MW/Hz

2 %/Hz 150 GW 18000 MW/Hz

2 %/Hz 300 GW 21000 MW/Hz

The following assumptions have been applied for the definition of marginal

conditions for the operation of primary control:

• Design basis / reference incident: Sudden deviation of 3000 MW in the

balance of production and consumption; system off-peak load about 150 GW

and peak load about 300 GW

• System start time constant: 10 to 12 seconds

• Self-regulating effect of load: 1 %/Hz

• Maximum permissible frequency deviation quasi-steady-state: ±180 mHz and

dynamic: ±800 mHz

The maximum dynamic frequency deviation of ±800 mHz includes a safety

margin. This margin of 200 mHz in total is intended to cover the following

influences and elements of uncertainty:

• Possible stationary frequency deviation before an incident (50 mHz)

• Insensitivity of turbine controller (20 mHz)

• Larger dynamic frequency deviation at the site of the incident, not taken into

account in the specific network model used for simulations (50 mHz)

• Other elements of uncertainty in the model (approximately 10 %, 80 mHz)

In case of load-shedding, accuracy of 50 to 100 mHz will generally suffice

for relay trip thresholds (UCTE Operation Handbook Appendix1, 2004).


34

3.1.1.8. Primary Control Reserve

The total primary control reserve, Ppu, for the entire synchronous area is

determined by the UCTE on the basis of the conditions set out in the previous

subsections, taking account of measurements, experience and theoretical

considerations.

The shares Ppi of the control areas are defined by multiplying the calculated

reserve for the synchronous area and the contribution coefficients Ci of the various

control areas :

ipupi CPP ×= (3.5)

The entire primary control reserve is activated in response to a quasi-steady-

state frequency deviation of -200 mHz or more. Likewise, in response to a frequency

deviation of +200 mHz or more, power generation must be reduced by the value of

the entire primary control reserve.

In order to restrict the calling up of the primary control reserve to

unscheduled power unbalances, the system frequency should not exceed or fall

below a range of ±20 mHz for long periods under undisturbed conditions (UCTE


3.1.1.9. Deployment Time of Primary Control Reserve

The deployment time of the primary control reserves of the various control

areas should be as similar as possible, in order to minimize dynamic interaction

between control areas. In this instance, we are concerned with anticipated

performance, rather than with the logic of controllers.

A reference incident of 3000 MW (loss of generation or load) for the

synchronous area is considered. The primary control reserve of each control area

must be fully activated within 15 seconds in response to disturbances ∆P of less than

1500 MW (it has been assumed that, where values for reserve power to be activated

are smaller, deployment times of less than 15 seconds will be difficult to achieve), or


35

within a linear time limit from 15 to 30 seconds in response to a ∆P of 1500 to 3000

MW.

3.1.1.10. Secondary Control

Any imbalance between electric power generation and consumption will

result (in real-time) in a frequency change within the complete network of the

synchronous area. As a result over time, a frequency deviation occurs. At system

frequencies below 50 Hz, the total demand has been larger than the total generation,

at frequencies above 50 Hz the total demand has been less than the total generation.

In practice, the demand varies continuously, even without having forecast errors, so

that secondary control on a real-time basis is required on a continuous basis. A

deviation ∆f of system frequency from its set-point value of 50 Hz will activate

primary control power throughout the synchronous area (UCTE Operation Handbook

Appendix1, 2004)

fP uu ∆×=∆ λ (3.6)

With, λu is the power system frequency characteristic of the whole

synchronous area, i.e. the sum of the power system frequency characteristic of all

control areas.

Primary control allows a balance to be re-established at a system frequency

other than the frequency set-point value (at a quasi-steady-state frequency deviation

∆f), in response to a sudden imbalance between power generation and consumption

(incident) or random deviations from the power equilibrium. Since all control areas

contribute to the control process in the interconnected system, with associated

changes in the balance of generation and consumption in these control area, an

imbalance between power generation and consumption in any control area will cause

power interchanges between individual control areas to deviate from the agreed /

scheduled values (power interchange deviations ∆Pi).

The function of secondary control is to keep or to restore the power balance

in each control area and, consequently, to keep or to restore the system frequency f

to its set-point value of 50 Hz and the power interchanges with adjacent control areas


36

to their programmed scheduled values, thus ensuring that the full reserve of primary

control power activated will be made available again. In addition, secondary control

may not impair the action of the primary control. These actions of secondary control

will take place simultaneously and continually, both in response to minor deviations

(which will inevitably occur in the course of normal operation) and in response to a

major discrepancy between production and consumption (associated e.g. with the

tripping of a generating unit or network disconnection). In order to fulfill these

requirements in parallel, secondary control needs to be operated by the network

characteristic method.

Whereas all control areas provide mutual support by the supply of primary

control power during the primary control process, only the control area affected by

a power unbalance is required to undertake secondary control action for the

correction. Consequently, only the controller of the control area, in which the

imbalance between generation and consumption has occurred, will activate the

corresponding secondary control power within its control area. Parameters for the

secondary controllers of all control areas need to be set such that, ideally, only the

controller in the zone affected by the disturbance concerned will respond and initiate

the deployment of the requisite secondary control power. Within a given control

area, the demand should be covered at all times by electricity produced in that area,

together with electricity imports (under purchase contracts and/or electricity

production from jointly operated plants outside the zone concerned). In order to

maintain this balance, generation capacity for use as secondary control reserve must

be available to cover power plant outages and any disturbances affecting production,

consumption and transmission. Secondary control is applied to selected generator

sets in the power plants comprising the control loop. Secondary control operates for

periods of several minutes, and is therefore timely dissociated from primary control.

This behavior over time is associated with the PI (proportional-integral)

characteristic of the secondary controller. Secondary control makes use of

measurements of the system frequency and active power flows on the TIE lines of

the control area, a secondary controller, which computes power set-point values of


37

selected generation sets for control, and the transmission of these set-point values to

the respective generation sets.

When consumption exceeds production on a continuous basis, immediate

action must be taken to restore the balance between the two (by the use of standby

supplies, contractual load variation or Load-Shedding or the shedding of a proportion

of customer load as a last resort). Sufficient transmission capacity must be

maintained at all times to accommodate reserve control capacity and standby

supplies. Since it is technically impossible to guard against all random variables

affecting production, consumption or transmission, the volume of reserve capacity

will depend upon the level of risk which is deemed acceptable. These principles will

apply, regardless of the division of responsibilities between the parties involved in

the supply of electricity to consumers (UCTE Operation Handbook Appendix1,

2004).

Secondary control must begin within 30 seconds of the disturbance

concerned, i.e. when the action of primary control is complete, even under the most

stringent conditions assumed for the reference incident; secondary control must be

fully deployed within 15 minutes. If the loss of the largest generating unit supplying

the area concerned is not covered by the secondary reserve of that area, provision

must be made for an additional reserve which will offset the loss of capacity within

the requisite time. This reserve may take the form of generating plant with the

facility for rapid start-up, the adjustment of set points for generating units in service

or load shedding. This additional reserve may also be obtained from other control

areas. The operator responsible for each control area will undertake the regular

assessment of the performance of secondary control, particularly in the case of losses

of capacity exceeding 600 MW. Members will provide the information required for

this analysis.

3.1.1.11. Tertiary Control

Tertiary control is any automatic or manual change in the working points of

generators or loads participating, in order to:


38

• Guarantee the provision of an adequate secondary control reserve at the right

time,

• Distribute the secondary control power to the various generators in the best

possible way, in terms of economic considerations.

Changes may be achieved by:

• connection and tripping of power (gas turbines, reservoir and pumped storage

power stations, increasing or reducing the output of generators in service);

• redistributing the output from generators participating in secondary control;

• changing the power interchange program between interconnected

undertakings;

• load control

Typically, operation of tertiary control (in succession or as a supplement to

secondary control) is bound to the time-frame of scheduling, but has on principle the

same impact on interconnected operation as secondary control.

The power which can be connected automatically or manually under tertiary

control, in order to provide / restore an adequate secondary control reserve, is known

as the tertiary control reserve / 15 minute reserve. This tertiary control reserve must

be used in such a way that it will contribute to the restoration of the secondary

control range when required (UCTE Operation Handbook Appendix1, 2004).

3.1.1.12. Time Control

If the mean system frequency in the synchronous zone deviates from the

nominal frequency of 50 Hz, this results in a discrepancy between synchronous time

and universal coordinated time (UTC). This time offset serves as a performance

indicator for primary, secondary and tertiary control (power equilibrium) and must

not exceed 30 seconds. The Laufenburg control centre in Switzerland is responsible

for the calculation of synchronous time and the organization of its correction.

Correction involves the setting of the set-point frequency for secondary control in

each control area at 49.99 Hz or 50.01 Hz, depending upon the direction of

correction, for full periods of one day (from 0 to 24 hours).


39

The quality of system frequency will be regarded as satisfactory over one

month period (UCTE Operation Handbook Appendix1, 2004)

• where the standard deviation for 90% and 99% of measurement intervals is

less than 40 mHz and 60 mHz respectively for the whole month considered;

• where the number of days’ operation at a set point frequency of 49.99 Hz or

50.01 Hz does not exceed eight days per month respectively (to be confirmed

by experience).

3.1.2. Scheduling and Accounting

It is compulsory to schedule in advance the power to be exchanged at the

interconnection borders between the system operators in order to operate a large

power system like UCTE and to create the suitable conditions for commercial

electricity trade.

During daily operation, the schedules are followed by means of the load-

frequency control installed in each control area. Notwithstanding load-frequency

control, unintentional deviations invariably occur in energy exchanges. For this

reason, it is necessary to co-ordinate the schedule nomination between the system

operators, to observe in real-time unintentional deviations and to co-ordinate

accounting and computation of the compensation programs to balance unintentional

deviations (UCTE Operation Handbook Policy2, 2004)

3.1.3. Operational Security

System safety is the primary goal of the operation of the interconnected

network. In an interconnected system there exist numerous inter-dependencies of the

networks forming part of the system. In addition, there are impacts attributable to the

usage of the system by market players. In an unbundled environment, network

operators are not allowed to interfere with market forces unless system safety is at

stake. The operation of the interconnected network is founded on the principle that

each partner is responsible for its own network. To harmonize the operating methods


40

for the interconnected network, UCTE has since the beginning worked out rules,

instructions and suggestions, to which the operation of each network has to make

reference in order to ease inter-operability. TSOs are in charge of managing the

security of operation of their own networks in a subsidiary way. The most relevant

rules for the security of interconnected operation are related mainly to the

functioning of interconnections. TSOs cooperatively adapt continuously such

common rules for inter-operability to be applied mainly at the borders of their control

areas and consequently at the borders of countries . These rules create favorable

conditions for cross-border exchanges at destination of network users and of TSOs

themselves. All these co-ordinating rules complement any other existing national

commitments for network access (legal and contractual) for the transmission

networks when they exist. The control of performances of facilities connected to

networks remains under the responsibility of TSOs to the extent of their national

commitments. This policy specifies the requirements for operating the transmission

system to maintain security. Each control area and transmission system operator -

TSO - is responsible of procedures for reliable operation over a reasonable future

time period in view of real-time conditions, with contingency and emergency

conditions, and of their preparation. Coordination between TSOs contributes to

enhance the common solidarity (to cope with risks) resulting from the operation of

interconnected networks, to prevent disturbances, to provide assistance in the event

of failures with a view to reducing their impact and to provide resetting strategies

after a collapse. This co-ordination is intensively developed covering today new

aspects related to market mechanisms (UCTE Operation Handbook Policy3, 2004)

3.1.3.1.Voltage and Reactive Power Control

Since reactive power transmission over long distances is virtually impossible,

the balance between reactive power generation and demand must be maintained on a

regional basis within the area of operation concerned. Reactive power transmission

will cause voltage drops and losses. It is therefore preferable that system operation

should be optimized in such a way that the balance of reactive power will be


41

maintained as effectively as possible on a local basis. In reactive power (and

therefore voltage) control, a distinction is drawn between primary, secondary and

tertiary voltage control.

Primary control is implemented by the voltage regulators of generating units,

which will initiate a rapid variation in the excitation of generators when they detect a

variation in voltage across their terminals. Other controllable devices, such as static

var compensators (SVCs) may also be involved in primary voltage control.

Secondary control co-ordinates the action of voltage and reactive power control

devices within a given zone of the network in order to maintain the requisite voltage

level in the system. Tertiary control involves a process of optimization, using

calculations based upon real time measurements, in order to adjust the settings of

devices which influence the distribution of reactive power (generating unit

controllers, tap transformer controllers and compensating devices, such as

inductances and capacitors). Where the system load is high, the operator must be

certain that, in case of a loss of generation, the remaining facilities will be able to

deliver enough reactive power to keep the voltage within the required range. The

same applies to the converse situation, where the system load is low and reactive

power needs to be absorbed. Voltage profiles on either side of tie-lines must be

harmonized by the operators of adjoining systems in order to allow the effective

management of reactive power flows. Where voltage deviations lead to constraints

on adjoining systems on a regular basis, compensating equipment must be installed

in order to keep the system voltage within the normal range.

3.1.3.2.“(-1”(etwork Security

The “N-1” criterion means that, under all operating conditions, the loss of any

given element (line, transformer, generating unit, compensation facility etc.) will not

lead to operating constraints in adjoining operating zones (as a result of limit values

being exceeded for current, voltage, stability, etc.) and, by the same token, will not

cause interruptions in supply. Although, under these conditions, it will not be

necessary to interrupt network operation as a result of the loss of one element, the


42

structure of the system concerned will need to be reorganized in order to comply

again with the ”N-1” criterion within the shortest possible time. In the intervening

time, the loss of a further element might indeed jeopardize continuity of operation.

Various arrangements may be prepared to ensure operational security in case

of serious outages, such as the simultaneous loss of both circuits on a double circuit

line or the loss of a bus-bar. The selection of measures to be applied will depend

upon the comparative analysis of technical and economic factors, taking account of

the following:

• the probability of the type of incident concerned;

• the consequences of that type of incident;

• expenses incurred for the provision of permanent risk cover;

• the cost of protective measures required to prevent the extension of an

incident

The entire network, including cross-border tie-lines, must be operated in such

a way that sufficient transmission capacity will be available for the delivery of

reserve primary control power to the areas which may be affected by an incident.

3.1.4. Co-ordinated Operational Planning

UCTE describes several stages of the operational planning phase. It starts

approximately one year before actual operation with an outage scheduling process

and continues through capacity assessment, day ahead congestion forecast until real-

time n-1 security management (UCTE Operation Handbook Policy4, 2006).

3.1.5. Emergency Procedures

In an extremely complex and highly meshed system, disturbances may be

propagated over a vast area within a very short period of time. Whatever precautions,

the short-term occurrence of insecure operating conditions can take place at any time

due to a cascade of contingencies. Therefore, it is necessary in the “Emergency

Operations” to anticipate any critical situation within a very few hours or a few


43

minutes before the real time operation, preventing system cascading and limiting its

consequences (UCTE Operation Handbook Policy5, 2006).

4.CONTROL STRATEGY OF GENERATOR S.Olcay BERĐKOL

44

4. CO�TROL STRATEGY OF GE�ERATOR

4.1. General

The frequency of a power system is dependent on real power balance. A

change in real power demand at one point of a network is reflected throughout the

system by a change in frequency (Kundur, 1994). Therefore, system frequency

provides a useful index to indicate system generation and load imbalance. Any short-

term energy imbalance will result in an instantaneous change in system frequency as

the disturbance is initially offset by the kinetic energy of the rotating plant.

Significant loss in the generation without an adequate system response can produce

extreme frequency excursions outside the working range of the plant.

Depending on the type of generation, the real power delivered by a generator

is controlled by the mechanical power output of a prime mover such as a steam

turbine, gas turbine, hydro-turbine or diesel engine. In the case of a steam or hydro-

turbine, mechanical power is controlled by the opening or closing of valves,

regulating the input of steam or water flow into the turbine. Steam (or water) input to

generators must be continuously regulated to match real power demand, failing

which the machine speed will vary with consequent change in frequency. For

satisfactory operation of a power system, the frequency should remain nearly

constant. In addition to a primary frequency control, most large synchronous

generators are equipped with a supplementary frequency control loop.

Maintaining the frequency at its target value requires that the active power

produced and/or consumed be controlled to keep the load and generation in balance.

A certain amount of active power, usually called frequency control reserve, is kept

available to perform this control. The positive frequency control reserve designates

the active power reserve used to compensate for a drop in frequency. On the other

hand, the deployment of negative frequency control reserve helps to decrease the

frequency.

Primary and secondary frequency control in a coordinated mode is required in

any transmission and distribution grid in order to keep the frequency as close as


45

possible to the nominal frequency. The operation of the grids is necessary in order to

protect the consumers connected as well as to keep the grid in a stable condition.

Reasons for frequency deviations

• Deviations in consumption

• Failures in the grid and transmission system respectively

• Failures in the generation; forced shut downs of generators

• Generation program is not matching the consumption

Primary frequency load control, decentralized on the generators, is a local

automatic control that adjusts the active power generation of the generating units and

the consumption of controllable loads to restore quickly the balance between load

and generation and counteract frequency variations (Ingleson et al., 2005). Hence,

the purpose of primary control is to balance the energy in interconnected system

between demand and supply.

In particular, it is designed to stabilize the frequency following large

generation or load outages. It is thus indispensable for the stability of the power

system. All generators that are located in a synchronous zone and are fitted with a

speed governor perform this control automatically. The demand side also participates

in this control through the self-regulating effect of frequency-sensitive loads such as

induction motors (Kundur, 1994) or the action of frequency-sensitive relays that

disconnect or connect some loads at given frequency thresholds. However, this

demand-side contribution is not always taken into account in the calculation of the

primary frequency control response.

The provision of this primary control is subject to some constraints. Some

generating units that increase their output in response to a frequency drop cannot

sustain this response for an indefinite period of time. Their contribution must

therefore be replaced before it runs out. It is also important that the contributors to

primary control be distributed across the interconnected network to reduce unplanned

power transits following a large generation outage and enhance the security of the

system. In addition, a uniform repartition helps maintain the stability of islanded

systems in case of a power system separation.


46

Secondary frequency control is a centralized automatic control that adjusts

the active power production of the generating units to restore the frequency and the

interchanges with other systems to their target values following an imbalance. In

other words, while primary control limits and stops frequency excursions, secondary

control brings the frequency back to its target value. Only the generating units that

are located in the area where the imbalance originated should participate in this

control as it is the responsibility of each area to maintain its load and generation in

balance. Note that loads usually do not participate in secondary frequency controls.

Contrary to primary frequency control, secondary frequency control is not

indispensable. This control is thus not implemented in some power systems where

the frequency is regulated using only automatic primary and manual tertiary control.

However, secondary frequency control is used in all large interconnected systems

because manual control does not remove overloads on the tie lines quickly enough

(Rebours et al., 2007).

Tertiary frequency control refers to manual changes in the dispatching and

commitment of generating units. This control is used to restore the primary and

secondary frequency control reserves, to manage congestions in the transmission

network, and to bring the frequency and the interchanges back to their target value

when the secondary control is unable to perform this last task. Some aspects of

tertiary control relate to the trading of energy for balancing purposes. This paper

does not deal with secondary and tertiary frequency control because they do not

represent a criteria applied to the TSO by the UCTE.

4.2. Frequency and Voltage Control

The turboset is mainly controlled by the turbine governor, which consists of a

power and a speed controller, and the voltage regulator (see figure 4.1). The turbine

governor influences the position h of the control valves that regulate a mass flow of

gas or steam to the turbine. By means of the governor droop, it is able to perform a

frequency response contribution to slow changes in the grid frequency but, owing to


47

the limited dynamic range of the valves, it cannot intervene at frequencies above

approximately 0.1Hz.

Figure 4.1 Generator control system

The purpose of the voltage regulator is to keep the terminal voltage of the

generator as constant as possible, thus making it independent of external interference.

If the voltage then behaves like an impressed quantity, the generator is able to make

a substantial contribution towards supporting the grid. Thus, one of the most

important tasks of a voltage regulation facility is to adjust the available excitation

power in the case of a short circuit in the grid so as to enable tracing of the fault

location and its isolation from the grid. When this has taken place, the task of the

voltage regulator is to stabilize the required terminal voltage as swiftly as possible to

prevent the failure of station-service equipment. The same applies conversely in the

case of load rejection. A high quality of voltage regulation is therefore an important

requirement. As mentioned above, the dynamic range of voltage regulation must not

be increased at random.

The high dynamics of the excitation system basically permits a reaction to

active power oscillations, but the voltage is fed to the voltage regulator as a

controlled variable.


48

After a consideration of the turboset in its entirety as a controlled system, the

approach towards combating oscillations becomes apparent. The manipulated

variable of voltage regulation, the exciter voltage Vf, not only influences the

generator’s terminal voltage Vt, but also the active power P

e delivered to the grid

(transfer function GPV). Although the steady state portion of the active power cannot

be modified by the exciter voltage (this can only be done by the turbine governors),

the dynamic portions can be influenced by exciter voltage transients.

The link between the exciter voltage and the output active power can be used

to realize an additional stabilization control loop shown in figure 4.2. The component

used for stabilization is the power system stabilizer (PSS) (Kutzner, 1999). PSS is

not a must to control a generator or to operate a power plant. It is used as an option.

Figure 4.2 Power system stabilizer (Kutzner, 1999)

4.2.1. Modeling the PSS

The use of a PSS can be looked upon as being an option. Basically, a power

plant can also be operated without a PSS if the voltage regulator is set to a low gain.

If noteworthy grid support is to be realized, however, the proportional gain of the

voltage regulator must be increased in order to have a greater effect in the event of

grid interference. The resulting quick response of the modes of the turboset on the


49

grid should, however, be counteracted by a PSS that has been harmonized to the

voltage regulator.

The arrangement of the PSS clearly indicates the factors that restrict its

performance capabilities:

• Only oscillating components of the active power can be influenced. The

DC component and the low-frequency components can only be

influenced by a variable supply of power by the way of the control

valves.

• If the effect of the PSS in the lower frequency range is not suppressed

by the design criteria or by other measures, extreme interactions

between voltage regulation and the PSS may be the result. It is

therefore necessary to harmonize the regulator design and the

parameters of the PSS.

• Extreme power transients may trigger considerable shifts of the reactive

power, which might lead to tripping of protective facilities. This must

be avoided by means of suitable switch-off criteria.

• The dynamic range of the PSS is limited only by the exciter system. At

the same time, in comparison with the frequencies of the occurring

generator oscillations, the fact that the dynamic range is restricted by

the time constant of the main exciter hardly is of any importance

(Kutzner, 1999).

4.2.2. Modeling the Excitation System

Control of the excitation system of a synchronous machine has a very strong

influence on its performance, voltage regulation, and stability. Not only is the

operation of a single machine affected by its excitation, but also the behavior of the

whole system is dependent on the excitation system of separate generators. For

example, inter-area oscillations are directly connected to the excitation of separate

generators. These are only a few arguments justifying the necessity for accurate and


50

precise modeling of the excitation system of a synchronous machine. A basic scheme

of excitation control is shown in figure 4.3.

Figure 4.3 Voltage control of synchronous generator

The purpose of the automatic voltage controller (AVR) is to control the

machine terminal voltage. This is achieved by the adjusting the setting of the

excitation system which ultimately adjusts the field voltage seen by the machine. It is

a common practice to use the AVR to fix the terminal voltage of the machine and

adjust the HV grid voltage by tapping the generator transformer.

This subsection therefore presents the modeling principles of the excitation

system. A detailed treatment of all aspects of the modeling is far beyond the scope of

the thesis; we only synoptically present a literature survey on the subject.

4.2.3. Modeling the Turbine and Governor

The number of poles of a synchronous generator and the speed of the prime

mover determine the frequency of the ac current produced by the generator. In order


51

to control the primer mover, turbine with associated controls is used in power

systems.

The MW response of the thermal power plant to the frequency regulation can

be divided into two components; one is the slow component responding to the MW

demand change due to secondary control, and the other is the fast component around

the slow component due to the action of the primary frequency (governor) control to

the generator speed error.

Demand rate limit, boiler response delay, and boiler steam sliding pressure

control are considered while designing a LFC. For the fast action, turbine governor

response, turbine load reference control and steam pressure change due to turbine

control valve movement are also considered. This study is dealing with primary

frequency control due to the UCTE policy.

Governing system is an important control system in the power plant as it

regulates the turbine speed, power and participates in the grid frequency regulation.

For starting, loading governing system is the main operator interface. Steady state

and dynamic performance of the power system depends on the power plant response

capabilities in which governing system plays a key role. With the development of

electro- hydraulic governors, processing capabilities have been enhanced but several

adjustable parameters have been provided. A thorough understanding of the

governing process is necessary for such adjustment.

The load on a turbine generating unit does not remain constant and can vary

as per consumer requirement. The mismatch between load and generation results in

the speed (or frequency) variation. When the load varies, the generation also has to

vary to match it to keep the speed constant. This job is done by the governing

system. Speed which is an indicator of the generation - load mismatch is used to

increase or decrease the generation.

Governing system controls the steam flow to the turbine in response to the

control signals like speed error, power error. It can also be configured to respond to

pressure error. It is a closed loop control system in which control action goes on till

the power mismatch is reduced to zero.


52

As shown in the basic scheme given in figure 4.4, the inlet steam flow is

controlled by the control valve or the governor valve. It is a regulating valve. The

stop valve shown in the figure ahead of control valve is used for protection. It is

either closed or open. In emergencies steam flow is stopped by closing this valve by

the protective devices.

Figure 4.4 Steam turbine governing scheme

The governing process can be functionally expressed in the form of signal

flow block diagram shown in figure 4.5. The electronic part output is a voltage or

current signal and is converted into a hydraulic pressure or a piston position signal by

the electro- hydraulic converter (EHC). Some designs use high pressure servo valves.

The control valves are finally operated by hydraulic control valve servo motors.


53

Figure 4.5 Block diagram of the governing system

The steam flow through the control valve is proportional to the valve opening

in the operating range. So when valve position changes, turbine steam flow changes

and turbine power output also changes proportionally. Thus governing system

changes the turbine mechanical power output.

In no load unsynchronized condition, all the power is used to accelerate the

rotor only (after meeting rotational losses) and hence the speed changes. The rate of

speed change is governed by the inertia of the entire rotor system. In the grid

connected condition, only power pumped into the system changes when governing

system changes the valve opening.

When the turbine generator unit is being started, governing system controls

the speed precisely by regulating the steam flow. Once the unit is synchronized to the

power system grid, same control system is used to load the machine. As the

connected system has very large inertia (infinite bus), one machine cannot change the

frequency of the grid. But it can participate in the power system frequency regulation

as part of a group of generators that are used for automatic load frequency control.

As shown in the block diagram figure 4.5, the valve opening changes either

by changing the reference setting or by the change in speed (or frequency). This is

called primary regulation. The reference setting can also be changed remotely by

power system load frequency control (secondary regulation). Only some generating

units in a power system may be used for secondary regulation.


54

4.2.3.1. Electro Hydraulic Governing System

Basically the controls can be described as speed control when the machine is

not connected to the grid or in isolation and load control when the machine is

connected to the grid. The governing system has three functional parts: sensing part,

processing part and amplification. These functions are realized using a set of

electronic, hydraulic and mechanical elements, in the electro-hydraulic governor

(EHG), as shown in figure 4.6.

Figure 4.6 Electro-hydraulic governor scheme

Sensing is to sense speed and power. The well known fly ball governor is a

mechanical speed sensor which converts speed signal into a mechanical movement

signal. Nowadays electronic sensors using Hall Effect principle and/or hydraulic

sensor (a special pump whose output pressure varies with pump speed linearly) is

used for speed measurement.

Processing is to evolve the desired valve opening command signal

proportional (P) or proportional integral (PI) or proportional integral derivative (PID)

or a combination of these. In digital governors the processing is done using software

blocks.

Amplification is necessary to obtain sufficient power to operate the steam

control valve.


55

4.2.3.2. Speed Controller and Power-Load Controller

Speed control provides the primary method of controlling the speed of the

turbine by comparing the feedback from the power grid or two speed signals to the

speed set point. This comparison generates an error term which is used to generate

the control output. The control output is low selected with the output of the valve

ramp function and the auxiliary loop function to obtain the value for the valve output

function.

Speed Control (SC) is used for start-up, in disturbance states and in island

operation. Power Control (PC) mode is used for primary frequency control. Speed

control loop demands additional capability to dampen the speed oscillations. This is

obtained using so called proportional derivative (PD) controller. In this the valve

opening command is proportional to the rate of change (or derivative) of the error

also. This can improve the dynamic response considerably. Power-Load control loop

deals only with MW error, which is obtained using a MW- transducer and is mainly a

proportional integral (PI) controller. This loop is active when the steam turbine

generator is connected to the grid. There is a selection logic which decides which

control loop should prevail. Separate control actions incorporated for speed and load

control are shown in figure 4.7.

Figure 4.7 Speed and load controllers


56

During grid operation the speed controller is deactivated. There is only

frequency droop that modifies power. Therefore this mode is referred to as power

control mode shown in figure 4.8.

The expression “island” in figure 4.8 refers to the formation of a partial grid

after a system fault with disconnection from the interconnected system, with one or

more generators then supplying the remaining loads. At the moment of disconnection

from the interconnected system the terminal load of the generators must suddenly

adapt to the new load level. The transient and the remaining generation must be

managed by the frequency/load controller.


57

ISLA�D OPERATIO�

PARALLELGRID

Figure 4.8 Power control and Speed control modes


58

4.2.3.3. Droop Characteristic

Whenever there is a mismatch in power, speed changes. As mentioned earlier,

the governing system senses this speed change and adjusts valve opening which in

turn changes power output. This action stops once the power mismatch is made zero.

But the speed error remains. What should be the change in power output for a change

in speed is decided by the regulation. If 4% change in speed causes 100% change in

power output, then the droop is said to be 4% (or in per unit 0.04).

Speed-droop is the change in active power output of the unit proportional to

the frequency deviation as shown in figure 4.9. At 100 % load the generation is also

100 %, frequency (or speed) is also 100%. When load reduces frequency increases,

as generation remains the same. When load reduces by 50 %, frequency increases by

2 %, in the characteristic shown. When load reduces by 100 %, frequency increases

by 4 %. In other words 4 % rise in frequency should reduce power generation by 100

%. The characteristic is of drooping type. Droop or regulation is an important

parameter in the frequency regulation. In thermal power plants droop value is

generally between 4 % and 6 %.

Figure 4.9 Droop characteristic

In terms of control system steady state gain is expressed as inverse of droop:

gain of 25 in per unit corresponds to 4 % (or 0.04 p.u.) droop.


59

The speed droop (S.D.) of a generator is briefly defined as a ratio (without

dimension) and a percentage;

%100P / P

f / f-..

N

n×

∆

∆=DS (4.1)

The variation in system frequency ∆f is defined as follows, with fn being the

nominal frequency and f is the set frequency (50 Hz).

nfff −=∆ (4.2)

The relative variation in power output is defined as the quotient of the

variation in power output ∆P of a generator (in steady-state operation, provided that

the primary control range is not completely used up) and its rated active power

output PN .The contribution of a generator to the correction of a disturbance on the

network depends mainly upon the droop of the generator and the primary control

reserve of the generator concerned. The following figure 4.10 shows a diagram of

variations in the generating output of two generators “a” and “b” of different droop

under equilibrium conditions, but with identical primary control reserves (UCTE


Figure 4.10 Different droop with same primary control reserve (UCTE Operation

Handbook Appendix1, 2004)


60

In case of a minor disturbance (frequency offset < ∆fb), the contribution of

generator “a”, which has the controller with the smaller droop, to the correction of

the disturbance will be greater than that of generator “b”, which has the controller

with the greater droop. The frequency offset (∆fa) at which the primary control

reserve of generator a will be exhausted (i.e. where the power generating output

reaches its maximum value Pmax) will be smaller than that of generator b (∆fb), even

where both generators have identical primary control reserves In case of a major

disturbance (frequency offset > ∆fb), the contributions of both generators to primary

control under quasi-steady-state conditions will be equal (UCTE Operation

Handbook Appendix1, 2004).

4.2.3.4. Governor insensitivity or dead band

The governing system action depends on speed sensing. There is a minimum

value of speed which cannot be picked by the sensing mechanism and hence may

remain uncorrected. This minimum value is called governor insensitivity or dead

band. The characteristic is shown in figure 4.11.

Figure 4.11 Dead band characteristic

Valve Opening

Speed Frequency

Dead band or insensitive zone


61

Sometimes due to wear and tear dead band increases over a period of time.

This is detrimental to the frequency regulation. In control system analysis, it is well

known that dead band or hysteresis in a closed loop causes instability or limit cycle

oscillations. Governor hunting may occur. At the same time, governor should not

react for very small changes in frequency, so dead band is introduced intentionally in

the electronic governor which is an adjustable feature.

4.2.3.5. Transient Speed Rise

The governing system, as noted earlier is a closed loop control system.

Stability is an important parameter in any feedback control system. Stability and

speed of response depend on the signal modifications done by various blocks in the

loop. The closed loop gain depends on the individual block gains and the adjustable

gains provided in the speed controller and load controller. The gain at the steady state

and during the transient is important in deciding the performance. If the gain is not

proper there can be hunting in the system. Various parameters like speed, power,

valve opening will be oscillating continuously and may ultimately result in the trip of

the turbine.

Governing system maintains the turbine speed as set by the reference. When

there are disturbances, the response should be quick otherwise speed may continue to

deviate. Transient speed rise (TSR) is one important criterion that is used to judge the

response capability of the governing system. Load shedding or load rejection is a

major disturbance. When the turbogenerator unit is running at full load, if the circuit

breaker opens, load is cut off. The full load steam flow causes the rotor to accelerate.

The steam inflow is to be cutoff as soon as possible. It cannot be done

instantaneously as the hydro mechanical elements take certain time to respond.

Speed shoots up and then falls gradually due to the closure of control valve. The

peak value of speed is called transient speed rise (TSR).


62

Even when the control valves are closed steam remaining in the steam

volume of reheater piping, turbine cylinders (entrained steam) continue to do the

work and increase the speed for few seconds.

There is an emergency governor provided to stop the turbine if the speed

crosses its setting. The standards specify that the TSR value should be less than the

emergency governor setting. That means when there is a full load throw-off,

governing system should act fast so that turbine does not trip.

There are other devices provided in the governing system which help in

minimizing transient speed rise like load shedding relay (LSR) which cause feed

forward action to close governing valves before speed variation is sensed by the

speed transducer.

5.SIMULINK MODELING OF TURBOSET S. Olcay BERĐKOL

63

5. SIMULIK MODELIG OF TURBOSET

5.1. General

Simulink is a graphical extension to MATLAB for the modeling and

simulation of systems. In simulink, systems are drawn on screen as block diagrams.

Many elements of block diagrams are available (such as transfer functions, summing

junctions, etc.), as well as virtual input devices (such as function generators) and

output devices (such as oscilloscopes). Simulink is integrated with MATLAB and

data can be easily transferred between the programs. Simulink is supported on

UNIX, Macintosh, and Windows environments.

Simulink supports linear and non-linear systems modeled in continuous time,

sampled time or a hybrid of the two. Simulink includes a comprehensive block

library of sinks, sources, linear and non-linear components and connectors (Dynamic

System Simulation for Matlab, 1998). It has an extensive control library that allows

easy implementation of any control algorithm, including linear control, fuzzy logic,

neural networks and others. Simulink provides a graphical user interface (GUI) for

building models as block diagrams. Simulink encourages you to try things out. You

can easily build models from scratch or take an existing model and add to it. You

have instant access to all the analysis tools in MATLAB, so the results can be taken,

analyzed and visualized.

The power system blockset is designed to provide a modern design tool that

allows scientists and engineers to rapidly and easily build models that simulate

power systems. Models are hierarchical, so we can build models using both top-

down and bottom-up approaches. After a model is defined, it can be simulated, using

a choice of integration methods, either from the Simulink menus or by entering

commands in the MATLAB command window.

SimPowerSystems extends simulink with tools for modeling and simulating

the generation, transmission, distribution, and consumption of electrical power. It

provides models of many components used in these systems, including three-phase

machines, electric drives, and libraries of application-specific models such as flexible


64

ac transmission systems (FACTS) and wind-power generation. SimPowerSystems

models can be discretized to speed up simulations. The sensor blocks can be used in

SimPowerSystems to measure current and voltage in your power network, and then

pass these signals into standard simulink blocks. Source blocks enable simulink

signals to assign values to the electrical variables current and voltage. Sensor and

source blocks can be connected a control algorithm developed in simulink to a

SimPowerSystems network.

5.2. Design Considerations

The design consideration of turboset is mainly affected by the concept of

primary control. Primary control of the power unit is described by the following

equation:

(5.1)

in which f∆ is the change in frequency in Hz, nomf is the nominal frequency (50

Hz), P∆ is the change in power in MW, nomP is the nominal power in MW and S.D

is the droop as %.

Selected reference power plants in Turkish interconnected system have an

obligation to give support to the system frequency. Each of selected power plants in

Turkey must support the primary frequency control due to their abilities. Those

contractual obligations are 10% of the nominal power for hydroelectric power plants

and 5% of the nominal power for coal and gas fired thermal power plants based on

UCTE regulations. Contractual obligation of the reference thermal power plant for

the primary frequency control reserve to be maintained is %5 of nominal power.

When units are scheduled only for primary control, they are operated at 100% of

nominal load and in case of a frequency deviation of ±200 mHz, they can take load

up to 105% of nominal and maintain this output. Each unit of the power plants

joining primary control will put in operation its reserve power, defined as primer

frequency reserve capacity in mandatory auxiliary services agreement, whenever the

%100. ×∆

=∆

×

nomnom f

f

P

PDS


65

frequency oscillates ±200 mHz from nominal value. This reserve power must be

given to the interconnected system in 30 seconds. When frequency oscillates ±200

mHz at nominal frequency 50 Hz, ideal turboset control response will be as shown in

figure 5.1 and figure 5.2 respectively. On those graphics, we assume that generators

do not be connected to real grid.

Figure 5.1 Power responses in frequency deviations -200 mHz

Figure 5.2 Power responses in frequency deviations +200 mHz


66

setP is the setting power and P∆ is reserve power for both negative and positive

power.

The ideal power-frequency graphic can be shown in figure 5.3 for both -200

mHz and +200 mHz.

Figure 5.3 Power-frequency curve at ±200 mHz

of is the dead band, Q is primary frequency control reserve, Gf∆ is sensed frequency

after dead band and f∆ is frequency deviation of the system.

5.3. Proposed Configuration of Turbine Control System

Steam turbine in reference thermal plant is five mass with separate casings-

arranged on one rotor with the generator. The steam turbine generator set is of the

single reheat condensing type. The turbine set consists of one HP, one IP and two

LP.


67

In proposed turboset model, power must be increased or decreased up to 5% of

nominal power in 30-50 seconds due to UCTE primary control whenever frequency

deviates ±200 mHz. A generator control system is mainly consisting of two parts

called turbine governor control and excitation control as mentioned in chapter 4.2. In

the scope of this thesis, governor control part is especially investigated because

primary control is directly proportional to turbine governor control block. Since

excitation control affects voltage control, available simulink block of MATLAB will

be used.

The proposed turboset control is built in MATLAB / Simulink shown in

figure 5.4. Basically, proposed model can be observed as two parts steam turbine

governor control, excitation system control blocks. Generator is controlled by those

two parts and generator output bus is connected to an infinite network through 3

phase 21 kV/400 kV voltage transformer (733 MVA / 50 Hz).


68

Figure 5.4 MATLAB/Simulink model of turboset


69

5.3.1. Synchronous Machine (Generator)

The shaft models a five-mass system, which is coupled to the mass in the

synchronous machine model. In parameters of the proposed controller, the machine's

mass, generator is labeled mass #1. The mass in the steam turbine and governor

block, which is closest to the machine's mass, is mass #2 (LP2 turbine), and

respectively mass #3 (LP1 turbine) and mass #4 (IP turbine) while the mass farthest

from the machine is mass #5 (HP turbine). The model takes into account the

dynamics of the stator, field, and damper windings. The equivalent circuit of the

model is represented in the rotor reference frame (q-d frame). All rotor parameters

and electrical quantities are viewed from the stator. They are identified by primed

variables. The subscripts used are defined as follows:

d,q: d and q axis quantity,

R,s: Rotor and stator quantity,

l,m: Leakage and magnetizing inductance,

f,k: Field and damper winding quantity,

Fundamental parameters in synchronous machine (generator) are shown in

figure 5.5.


70

Figure 5.5 Parameters of generator

Mechanical input allows you to select either the torque applied to the shaft or

the rotor speed as the simulink signal applied to the block's input. Mechanical power

Pm specifies a mechanical power input, in pu. The machine speed is determined by

inertia constant H and by the difference between the mechanical torque Tm, resulting

from the applied mechanical power Pm. The sign convention for the mechanical

power is the following: when the speed is positive, a positive mechanical power

signal indicates generator mode.


71

Specified rotor types can be salient-pole or round (cylindrical). This choice

affects the number of rotor circuits in the q-axis (damper windings). Proposed model

due to reference power plant is round.

Nominal power, voltage, frequency, and field current are chosen due to

reference thermal power plant parameters. The total three-phase apparent power Pn

(VA), rms line-to-line voltage Vn (V), frequency fn (Hz).

733=nP MVA,

21)( =rmsn VV kV,

50=nf Hz

Damper reactances are like below;

Synchronous reactance of direct axis, 13.2)( =puXd

Transient synchronous reactance of direct axis, 26.0)(' =puXd

Sub-transient synchronous reactance of direct axis, 18.0)('' =puXd

Synchronous reactance of quadrature axis, 02.2)( =puXq

Transient synchronous reactance of quadrature axis, 74.0)(' =puXq

Sub-transient synchronous reactance of quadrature axis, 18.0)('' =puXq

Stator leakage reactance, 156.0)( =puXl

D-axis and q-axis time constants are defined. These values must be consistent with

choices made on the two previous lines.

d-axis no load transient time constant, 51.5' =Tdo

d-axis no load sub-transient time constant, 04.0'' =Tdo

q-axis no load transient time constant, 93.1' =Tqo

q-axis no load sub-transient time constant, 26.0'' =Tqo

Inertia Constant (whole shaft including turbine), 6)/( =MVAMWsH

Inputs of generators are “Pm”, “Vf” while output of it is “m” as mentioned below.

“Pm” is the first simulink input is the mechanical power at the machine's

shaft. In generating mode, this input can be a positive constant or function or the

output of a prime mover block.


72

“Vf” is the second simulink input of the block is the field voltage. This

voltage can be supplied by a voltage regulator in generator mode.

The “m” is the simulink output of the block is a vector containing twenty two

signals. We can use any parameter that we want. Rotor speed value is only used as

feedback to control system in this model.

When synchronous machine blocks are used in discrete systems, a small

parasitic resistive load should be better, connected at the machine terminals, in order

to avoid numerical oscillations. Large sample times require larger loads. The

minimum resistive load is proportional to the sample time. As a rule of thumb, with a

25 µs time step on a 50 Hz system, the minimum load is approximately 2.5% of the

machine nominal power. For example, a 733 MVA synchronous machine in a power

system discretized with a 50 µs sample time requires approximately 5% of resistive

load about 36 MW. If the sample time is reduced to 20 µs, a resistive load of 15 MW

should be sufficient as shown in figure 5.4. That load is used between generator and

transformer.

5.3.2. Turbine-Governor Control System

The main consideration for control system of a steam turboset due to active

power is steam turbine-governor control. The dynamics of speed governing system,

steam turbine, and multimass shaft are shown in figure 5.6. The steam turbine and

governor block implements a complete tandem-compound steam prime mover,

including a speed governing system, a five-stage steam turbine, and a shaft with up

to five masses.


73

Figure 5.6 Turbine-governor block

As seen on figure 5.6, turbine-governor blocks consists of other parts as

defined below.

The speed governing system, which is part of turbine-governor block,

consists of a proportional regulator, a speed relay, and a servomotor controlling the

gate opening as shown in figure 5.7.

Figure 5.7 Speed governor block

Rp is speed droop and be set 4%. Dead zone is also mentioned in chapter

4.2.3.4 and be set to 0mHz in proposed model because it is reduced to 0mHz in

reference thermal power plant during real test. Normally, dead band can be ranged

between 0 mHz and 50 mHz permitted by UCTE. At the operating condition of a

power plant, dead band should be higher value for power plant dynamics. Gain of


74

generator is set to 1. Since flow and pressure of steam cannot be modeled in this

thesis, it is accepted to have no effect on system by adjusting 0.

Governor part is electro-hydraulic. The necessary parameters in governor

control are speed relay, servomotor time constant, servomotor speed limit and

servomotor position. Design values of them are 0.01 second for speed relay, 0.15

second for servomotor time constant, -0.1 and 0.1 pu/s for gate opening limits, 0 pu

for minimum gate opening, and 1 pu for maximum gate opening.

The steam turbine has five stages, each modeled by a first-order transfer

function. The first stage represents the steam chest while the three other stages

represent reheater and crossover piping. Since the boiler simulation is out of this

thesis, boiler pressure is assumed a constant value at 1.0 pu. Fractions F2 to F5 are

used to distribute the turbine power to the various shaft stages shown in figure 5.8.

Each turbine contribution is different to generated power. Those values are as

follows:

A generated power consists of 26% power (F5) by HP turbine, 38% power by

IP (F4), 18% power (F3) by LP1, and 18% power (F2) by LP2. Also each turbine has

time constant. Those time constants show that the duration of steam produced by

superheater and reheater. Typical values are taken from reference power plant; 30 sec

for HP, 50 sec for IP, 0.01 sec for LP1, 0.01 sec for LP2 respectively.

Figure 5.8 Turbine power fractions and time constants of turbine parts


75

Normally, actual speed coming from generator is used as rotor frequency

sensed by the system. In simulated control system, a simulated frequency must be

applied as externally. Speed information comes from generator but system senses

simulated frequency as seen in figure 5.9. When frequency is simulated, firstly step

time is adjusted to a value we want. Then, an initial and a final value are entered as

parameters of simulated frequency block. Since pu is used, data conversion can be

calculated as follows

for +200 mHz; puHz

Hz004.1

50

2.50= (5.2)

for -200 mHz; puHz

Hz996.0

50

8.49= (5.3)

Figure 5.9 Simulated frequency

5.3.3. Excitation Control Block

Excitation system regulates its terminal voltage in generating mode for

synchronous machine. Because this control block does not directly affect load-

frequency relationship, this control block is not modeled as detailed in this thesis.

Excitation block built for generator is taken from simulink library. Used excitation

block in proposed model can be seen in figure 5.10.


76

Figure 5.10 Excitation control description

Vref is the desired value, in pu, of the stator terminal voltage. Vd is the

component, in pu, of the terminal voltage. Vq component, in pu, of the terminal

voltage. Vstab is connected to a power system stabilizer to provide additional

stabilization of power system oscillations, we connected a ground. Vf is the output

and it is field voltage, in pu, for the generator.

The excitation system block is a simulink system implementing a DC exciter

described in [1], without the exciter's saturation function in figure 5.11. The basic

elements that form the excitation system block are the voltage regulator and the

exciter. It is shown in figure 5.11

Figure 5.11 Excitation control block


77

The exciter is represented by the following transfer function between the

exciter voltage Vfd and regulator’s output ef

eef

fd

sTKe

V

+=

1 (5.4)

Exciter is the gain Ke and time constant Te, in seconds (s), of the first-order

system representing the exciter. The parameters of excitation system are shown in

figure 5.12.

Figure 5.12 Parameters of excitation


78

Low-pass filter time constant is the time constant Tr, in seconds (s), of the

first-order system that represents the stator terminal voltage transducer.

Regulator gain and time constant are the gain Ka and time constant Ta, in

seconds (s), of the first-order system representing the main regulator.

Transient gain reduction is the time constants Tb, in seconds (s), and Tc, in

seconds (s), of the first-order system representing a lead-lag compensator.

Damping filter gain and time constant are the gain Kf and time constant Tf, in

seconds (s), of the first-order system representing a derivative feedback.

Regulator output limits and gain are limits Efmin and Efmax are imposed on

the output of the voltage regulator. The upper limit can be constant and equal to

Efmax, or variable and equal to the rectified stator terminal voltage Vt times a

proportional gain Kp.

5.4. Field Test Procedure

In reference thermal power plant, the tests carried out on the load-frequency

control system shall be realized according to the UCTE test procedure, by directly

simulating the frequency measurement signal of the unit control system. Method to

be applied is given below:

Figure 5.13 Test mode

The power plant has built-in frequency simulator therefore there is no need to

connect any signal generator. An artificial input signal ±200 mHz shall be added to


79

the turbine governor input signal, corresponding to the rated frequency 50 Hz. The

dead-band of the governor shall be adjusted to “0” prior to the tests.

At the beginning of the test, frequency is disconnected from grid and adjusted

50 Hz via simadyn, a special fast controller. Then system was reached to nominal

power 660 MW by system operator and frequency was manually decreased 49.8 Hz

for case 1 by simadyn software. After frequency stayed in 49.8 Hz during 15

minutes, it was adjusted to 50 Hz again and power was reached to nominal frequency

660 MW. For case 2, frequency was increased to 50.2 Hz by simadyn. Tests for each

cases continued 15 minutes.

The power plant has measurement recording for turbine speed measurement,

voltage measurement by voltage transformer, current measurement by current

transformer. Turbine speed (Hz) and turbine output power (MW) shall be recorded.

The measurements shall be recorded as 10 samples per second. All test results are

taken into computer environment via Digsilent software.

5.5. Simulation and Field Test Results

A speed /load-control system is capable of controlling and regulating the

speed of the turbine in conformity with the performance characteristics hereinafter

specified. The speed/load-control system should include means by which the steady-

state speed regulation is adjusted to values within the limits herein specified.

In order to show whether reference thermal power plant fulfills UCTE

requests due to primary control, proposed turboset control mechanism, taken values

from reference power plant, is simulated for the following case studies. Also, real

test results will be presented and compared with simulation results.

Case (1) -200 mHz frequency deviation:

Two conditions for this case must be fulfilled during tests as below:

a. taking reserve power within 30 seconds

b. hold its power during 15 minutes:


80

In simulation, system is operated up to 660 MW nominal power at 50 Hz.

Frequency is decreased 49.8 Hz from 50 Hz. Frequency in a short period is shown in

figure 5.14 for case 1.a and all simulation is represented in figure 5.15 for case 1.b.

Power response to frequency is shown in figure 5.16 for case 1.a and 5.17 for case

1.b. Power of proposed model is operated 660 MW at 50 Hz and frequency is

suddenly deviated by -200 mHz at 30th seconds shown in figure 5.14 and 5.15.

Figure 5.14 -200 mHz frequency deviation for case 1.a during simulation


81

Figure 5.15 -200 mHz frequency deviation for case 1.b during simulation

Figure 5.16 Unit response to -200 mHz frequency deviation for case 1.a during simulation


82

Figure 5.17 Unit response to -200 mHz frequency deviation for case 1.b during

simulation

At the beginning of field tests, reference power plant is operated at 50 Hz

simulated frequency and frequency was suddenly deviated and then steam turbine

shows response to deviations. The figure 5.19 shows simulated frequency for 15

minutes and figure 5.18 shows a short period of figure 5.19. Power response to

frequency is presented in figure 5.20 and 5.21. The primary control test results are

presented in figure 5.20 for a defined period. Figure 5.21 starts at the end of figure

5.20 in order to observe during 15 minutes.


83

t/s140 150 160 170 180 190 200 210 220 230 240 250 260 270 280

Frequency/Hz

49,7

49,8

49,9

50,0

50,1

50,2

Figure 5.18 -200 mHz frequency deviation for case 1.a during field test

t/s100 200 300 400 500 600 700 800 900 1000

Frequency/Hz

49,7

49,8

49,9

50,0

50,1

50,2

Figure 5.19 -200 mHz frequency deviation for case 1.b during field test


84

Figure 5.20 Unit response to -200 mHz frequency deviation for case 1.a during field

test

Figure 5.21 Unit response to -200 mHz frequency deviation for case 1.b during field test

Case 1.a

Reserve primary control according to UCTE policy for proposed thermal

power plant must be;


85

MWMW 33%5660 =× (5.5)

In simulation, system starts to take reserve power up to 34 MW in first 30

seconds shown in figure 5.16 when frequency is deviated. This is in the acceptable

range due to UCTE. As it can be seen on figure 5.16, system continues to take power

by first 40 seconds from its starting. It takes about 43 MW ( )MW660%7 ×≈ in 40

seconds and stay with 700 MW. Because frequency is still 49.8 Hz, system tries

frequency to reach to 50 Hz by increasing its power 10 MW more so this is better for

Turkish interconnected system.

As it can be seen on figure 5.20, for the 200 mHz frequency deviation, unit

responds with 25 MW ( )MW660%4 ×≈ and reaches +45 MW respond within 90

seconds in field test.

Case 1.b

After frequency decreases, reserve power must be taken in 30 seconds and

stay there during 15 minutes according to UCTE load frequency regulation.

After generator takes reserve power in case of -200 mHz frequency deviation

in simulation, generator stays there during 15 minutes. As it can be seen on figure

5.17, power response of system is never less than 40 MW ( )MW660%6 ×≈ .

In field test, unit responds with 45 MW ( )MW660%7 ×≈ for the first 4

minutes and at the end of 15 minutes the response is never less than +30

MW ( )MW660%5 ×≈ shown in figure 5.21.

Case (2) +200 mHz frequency deviation:

Two conditions for this case must be fulfilled as below:

a. throwing reserve power within 30 seconds

b. hold its power during 15 minutes:

In simulation, system is operated up to 660 MW nominal power at 50 Hz.

Frequency is increased 50.2 Hz from 50 Hz. Frequency in a short period is shown in

figure 5.22 for case 2.a and all simulation is represented in figure 5.23 for case 2.b.

Power response to frequency is shown in figure 5.24 for case 2.a and 5.25 for case


86

2.b. Power of proposed model is operated up to 660 MW at 50 Hz and frequency is

suddenly deviated by +200 mHz at 30th seconds shown in figure 5.22 and 5.23.

Figure 5.22 +200 mHz frequency deviation for case 2.a during simulation

Figure 5.23 +200 mHz frequency deviation for case 2.b during simulation


87

Figure 5.24 Unit response to +200 mHz frequency deviation for case 2.a during

simulation

Figure 5.25 Unit response to +200 mHz frequency deviation for case 2.b during

simulation


88

During field test, reference power plant is operated at 50 Hz simulated

frequency and frequency was suddenly deviated and then steam turbine shows

response to deviations. The figure 5.27 shows simulated frequency for 15 minutes

and figure 5.26 shows a short period of figure 5.27. Power response to frequency is

presented in figure 5.28 and 5.29. The primary control test results are presented in

figure 5.28 for a defined period. Figure 5.28 starts at the end of figure 5.27 in order

to observe during 15 minutes.

t/s1820 1830 1840 1850 1860 1870 1880 1890 1900 1910 1920

Frequency/Hz

49,7

49,8

49,9

50,0

50,1

50,2

Figure 5.26 Frequency deviation +200 mHz at time 1830 seconds for case 2.a during field test


89

t/s1900 2000 2100 2200 2300 2400 2500 2600

Frequency/Hz

49,7

49,8

49,9

50,0

50,1

50,2

Figure 5.27 Frequency deviation +200 mHz for 15 minutes at time 1830 seconds for

case 2.b during field test

Figure 5.28 Test result of unit response +200 mHz frequency deviation at full load

for case 2.a during field test


90

Figure 5.29 Test result of unit response +200 mHz frequency deviation at full load

for case 2.b during field test

Case 2.a

Reserve primary control according to UCTE policy for proposed thermal

power plant must be ( )MWMW 33%5660 =× .

In simulation, unit responds with -34 MW in first 30 seconds shown in figure

5.24 when frequency is deviated. This is in the acceptable range due to UCTE. As it

can be seen on figure 5.24, unit responds with -40 MW ( )MW660%6 ×≈ in 40

seconds and stay with 618 MW. Because frequency is still 50.2 Hz, system tries

frequency to reach to 50 Hz by decreasing its power 8 MW more so this is better for

Turkish interconnected system.

As it can be seen on the figure 5.28 due to field test results, unit responds

with -45 MW ( )MW660%7 ×≈ to +200 mHz frequency deviation for the first 30

seconds, but with the pressure increase, gives back ~15 MW of its initial response

duration of 90 seconds transiently.

Case 2.b

After frequency increases, reserve power must be given in 30 seconds and

stay there during 15 minutes according to UCTE load frequency regulation.


91

After generator gives reserve power in case of +200 mHz frequency

deviation, generator stays there during 15 minutes. As it can be seen on figure 5.25,

power response of system is never less than -40 MW ( )MW660%6 ×≈ .

At the end of 15 minutes in the field test, response is never below -30

MW ( )MW660%5 ×≈ .

5.6. Comparison of Simulation and Test Results

Results of proposed turboset model and results of the test are seen above

figures. They are different each other because our proposed model cannot include

mechanical loss, operating conditions of equipments and some mechanical parts.

Also, ideal curves for test are represented in figure 5.1 and figure 5.2. Results can be

compared as follows.

When frequency deviations -200 mHz:

Ideal curve must be like figure 5.1. System must take its reserve power within

30 seconds.

In the first 30 seconds, unit responds with ~34MW ( )MW660%5 ×≈ and

reaches to +43 MW ( )MW660%7 ×≈ within 40 seconds during the simulation.

During the test unit responds with ~25 MW ( )MW660%4 ×≈ and reaches +45 MW

respond within 90 seconds.

In simulation, as it can be seen on figure 5.15, it takes about 40 MW and stay

within 700 MW. When we can not model boiler, no pressure fluctuations or any

peak, falling and rising could not be seen in the proposed model.

In the test, as it can be seen on figure 5.24, for the 200 mHz frequency

deviation, unit responds with 45 MW ( )MW660%7 ×≈ for the first 4 minutes, and at

the end of 15 minutes the response is never less than +30 MW ( )MW660%5 ×≈

shown in figure 5.25. The reason of this fluctuation is fast pressure drop and it is

normal to be not seen in the simulation because boiler could not be modeled in the

scope of this.


92

When frequency deviations +200 mHz:

Ideal curve must be like figure 5.2. System must throw out its reserve power

within 30 seconds.

For the first 30 seconds, unit responds with ~-34 MW ( )MW660%5 ×≈ during

both test and simulation. For the duration of 90 seconds, the response goes back to -

30 MW ( )MW660%5 ×≈ transiently in test but power is kept in the same level after

first 30 seconds in simulation.

In simulation, as it can be seen on figure 5.19, power responds about -40

MW ( )MW660%6 ×≈ in 40 seconds and stay within 618 MW. When we can not

model boiler, no pressure fluctuations or any peak, falling and rising could not be

seen in the proposed model.

As it can be seen on the figure 5.28, unit responds with -45 MW (~7 % *660

MW) to +200 mHz frequency deviation, but with the pressure increase, gives back

~15 MW of its initial response transiently. At the end of 15 minutes, response is

never below -30 MW (~5 %* 660 MW) shown in figure 5.29. The reason of this

fluctuation is fast pressure changing and it is normal to be not seen in the simulation

because boiler could not be modeled.

As a result of the tests that were carried out reference thermal power plant, it

can be stated that the obligatory primary frequency control participation is realized

with:

%4 turbine control droop value without any limitation on the turbine,

~40 MW limited boiler control system response

Although the transient response is higher, the contractual obligation of 5%

reserve is provided in 30-50 seconds and maintained for the duration of 15 minutes

in both real test results and simulation results.

6. CONCLUSIONS S. Olcay BERĐKOL

93

6. CO�CLUSIO�S

In this thesis, primary load-frequency control related with UCTE policies is

investigated.

Load frequency control (LFC) investigated in this study has recently come

into question in operation of interconnected power networks. Frequency is a sensitive

parameter which affects the system operation so it must be controlled certainly.

Therefore power utilities consider the frequency and active power balance

throughout their networks to sustain the interconnection so that load-frequency

control is of importance in both electric power system design and operation. The

loading in a power system is never constant. To ensure the quality of the power

supply is necessary to design a load-frequency control system which deals with the

control of loading of the generator depending on the frequency.

The literature research was carried out in order to explain and design load

frequency control. The main desire, expected from LFC, was explained in chapter 3

and chapter 4. UCTE regulations including load frequency policy were clarified in

chapter 3 as detailed. A load frequency controller for the thermal power plant was

designed in chapter 5. Primary control response tests of reference thermal power

plant were carried and also results of the tests were given and then compared with

results of simulation in chapter 5.

The main consideration of the proposed turbine model was to investigate

primary control support of reference power plant needed to meet UCTE requirements

to Turkish power network. The proposed turbine control system for thermal power

plant was connected to interconnected network through 3 phase 21/400 kV step-up

voltage transformer. The turboset is controlled by the turbine governor, which

consists of a power and a speed controller, and the voltage regulator. Turbine

governor control block was especially designed because this thesis is directly

interested in primary control. By means of the governor droop, it is able to perform a

frequency response contribution to slow changes in the grid frequency. Governing

system is an important control system in the power plant as it regulates the turbine

speed, power and participates in the grid frequency regulation. For grid system


94

operation, it is required that the power generated is continuously matched to demand

for the power plant. If power generation and power demand in the grid system are the

same under undisturbed generation conditions, the system frequency is exactly equal

to the rated frequency and we can say that grid system is in the balance.

The proposed turboset model consisted of five mass. Each turbine had

different torque fractions in generation of electricity. Their contributions in

producing power were also considered while the turboset controller was designing.

The studies of two cases due to UCTE tests had been realized to verify the

operation and performance of the designed system in MATLAB/Simulink program.

When grid frequency deviations +200 mHz defined in UCTE operation handbook, it

means that the power generation is greater than power demand, so generators

connected to the grid system speed up. If the power generation is less than power

demand or grid frequency deviations -200 mHz defined in UCTE policy, generators

connected to the grid system slow down.

While proposed turboset system was simulated, system operated up to 660

MW. As far as frequency was artificially deviated -200 mHz at 50 Hz by a signal

generator proposed turboset took its reserve power about 34 MW in 30 seconds

which is in the acceptable range due to UCTE policy. System kept its power up to

700 MW during 15 minutes.

System was reached up to 660 MW. Then frequency was suddenly fluctuated

+200 mHz at 50 Hz by signal generator, proposed turboset decreased its power -34

MW for the first 30 seconds and -40 MW in 40 seconds which is in the acceptable

range due to UCTE policy. System kept its power level at 618MW during 15

minutes.

The synchronization of Turkish grid to UCTE through 380 kV network will

enlarge the capacity of UCTE system by 40.000 MW roughly when the project is

realized. Preliminary works for this interconnection have been carried out by Turkish

utility according to UCTE regulations. Primary frequency control performance test of

the power plants planned for primary control is one of those works which were

carried out at ISKEN power plant.


95

In order to give reaction to LFC, two basic control methods are used in

thermal power plants called speed control (SC) and power control (PC). SC is used

for start-up, in disturbance states and in island operation. PC mode is used for

primary frequency control while the units are supplying power to 380 kV Turkish

network. Therefore UCTE tests were carried out in PC mode.

While tests were applied on reference plant, the frequency was disconnected

from the grid. The frequency measurement signal of the unit control system was

directly simulated by signal generator. An artificial input signal ±200 mHz shall be

added to the turbine governor input signal, corresponding to the rated frequency 50

Hz. During the test and simulation, speed droop of turbine governor parameter is set

4% and dead band is adjusted to 0 mHz. All test results were taken into computer

environment via Digsilent software.

During test, system operates up to 660 MW. Frequency was deviated -200

mHz, system took 30 MW of its power reserve in 30 seconds. However generator

had continued to take power up to 45MW within 100 seconds, with the pressure

decreases. Then system had decreased its power and held in 700 MW during 15

minutes.

When frequency was deviated +200 mHz, system decreased its rated power

about 45 MW in 35 seconds which is in the acceptable range due to UCTE policy.

Then, generator took a little bit power reserve about 10MW, with the pressure

increase, and kept its power level at 620MW during 15 minutes.

As a result of the tests that were carried to the reference thermal power plant,

it can be stated that the obligatory primary frequency control participation is realized

with %4 turbine control droop value without any limitation on the turbine and ~40

MW limited boiler control system response

Although the transient response is higher, the primary support obligation of

5% reserve is provided in 30-50 seconds and maintained for the duration of 15

minutes.

In the tests, when frequency initiated to deviate -200 or +200 mHz at 50 Hz,

the power of generator fast increased or decreased. Peak points were seen on the

graphics and after a few seconds system protected stabilization of its output power


96

during the test. Those peaks occurred because pressure was changing suddenly. It is

normal that peaks cannot be seen in simulation results because boiler cannot be

modeled in the scope of this thesis.

Test and simulation results showed that the load-frequency control ability of

reference thermal power plant was enough in order to respond frequency fluctuations

on the interconnected system. In this thesis, observed simulation results and test

results of reference thermal power plant were closely matched with each other and

cover load frequency criteria defined UCTE policies.

97

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99

BIOGRAPHY

I was born in Adana, Turkey in 1982. I completed the high school education

in Adana. I received the B.S degree in Electrical and Electronics Engineering from

Çukurova University, Adana, Turkey in 2004. After completion my B.S. training, I

have started to work in EKĐNCĐLER steel and iron industry as electrical maintenance

engineer from september 2005 to november 2006. I have been studying MSc degree

in the department of Electrical and Electronics Engineering at Çukurova University

and also have been working in ISKEN thermal power plant as instrumentation and

control maintenance engineer since 2006.

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