Frequency Control on an Island Power System

Frequency Control on an Island Power

System

with Evolving Plant Mix

by

Gillian R. Lalor

A thesis presented to

The National University of Ireland

in fulfilment of the

requirements of the degree of

Philosophiae Doctor

in the

School of Electrical, Electronic and Mechanical Engineering

University College Dublin

September 2005

Supervisor of Research: Professor M.J. OMalleyNominating Professor: Professor A.M. de Paor

Abstract

Continual balancing of active power generated and consumed is vital for power system

security and stability, and to maintain frequency within an acceptable tolerance around

nominal system frequency. Due to the large size of individual generators with respect to

total system size, the loss of a generator in a small island system can cause a large power

imbalance, and consequently a significant frequency excursion. Low system inertia

results in high rates of change of frequency when a power imbalance occurs. Therefore,

system frequency control on an isolated power system is particularly challenging.

As the generating mix on a power system evolves, moving away from traditional steam

generating units, the behaviour of the power system in response to a power imbalance

also changes. Both combined cycle gas turbine (CCGT) and wind turbine generators

have distinctive effects on system frequency control. As each technology comprises an

increasing proportion of generation on power systems worldwide, a clear understanding

of the effects of CCGT and wind turbine generator characteristics on system frequency

control is required in order to maintain secure and stable power systems.

A dynamic model of the Ireland electricity system is developed, tuned and validated

for the purpose of studying short-term frequency control on an island system. Each

frequency responsive generating unit on the Ireland system is modelled using low order

models tuned to extensive data from frequency events on the Ireland system. The

system load is modelled using a single measurement based dynamic load model, which

incorporates the frequency sensitivity and inertial contribution of the load during power

imbalances. Frequency control through under-frequency load shedding is also incorpo-

rated in the model. The system model was subsequently validated through comparison

with frequency events not previously used for tuning. The resultant system model has

the ability to predict the under-frequency behaviour of the Ireland power system for

up to 20 seconds following a loss of generation with a very good level of accuracy.

i

The active power generated by a base loaded CCGT is coupled to system frequency. A

model suitable for studying the short-term dynamic response of a combined cycle gas

turbine to a system frequency deviation is developed. The model is tuned and validated

with event data from combined cycle gas turbines on the Ireland electricity system. This

model is used in conjunction with the validated system model to study the impact of

increasing levels of CCGT generation on short-term frequency control of a small island

system during a loss of generation event. Results indicate that as the number and

proportion of base loaded combined cycle gas turbines increases, frequency control

may become more challenging. The magnitude of the system frequency excursion

increases non-linearly as the proportion of base loaded CCGTs increases. Therefore, if

the number of CCGTs increases, large frequency excursions will become more likely and

transmission system operators may need to review their frequency control strategies to

maintain current security standards and to avoid the shedding of customers.

Increased system inertia is intrinsically linked to the addition of synchronous genera-

tion to power systems. However, due to differing electromechanical characteristics, this

inherent link is not present in wind turbine generators. Dynamic models of two differ-

ent wind turbine technologies are integrated into the validated system model, which

is modified to represent the predicted 2010 Ireland electricity system. The effect on

system frequency during a loss of generation event is examined for varying wind pene-

trations on the system. The results indicate that regardless of wind turbine technology,

the displacement of conventional generation with wind will result in increased rates of

change of system frequency. The magnitude of the frequency excursion following a loss

of generation may also increase. Amendment of reserve policies or modification of wind

turbine inertial response characteristics may be necessary to facilitate increased levels

of wind generation, particularly for an isolated power system.

In addition to the short-term dynamic effects of wind generation on frequency control,

longer-term effects as a result of the wind generation characteristics of variability and

unpredictability need to be taken into account in order to maintain adequate levels

of system security in all time frames. However, while a clear understanding of the

technical aspects of frequency control is vital to ensure system security, they comprise

just one part of the whole frequency control issue. The technical aspects therefore need

to be put in perspective by examining them as part of the broader picture, which also

includes economic consequences. With rapidly increasing wind generation on many

power systems, the effect on all aspects of frequency control is being examined in

ii

detail, to assess and quantify the impact of wind integration. A review of a number

of previous wind integration studies is carried out and a preliminary methodology

is proposed for examining the effects of wind integration on all aspects of frequency

control over a number of time-frames. Some illustrative results are given for a sample

AC interconnected system.

iii

Acknowledgements

I would like to thank everybody whose help and support contributed to this thesis. In

particular, there are some without whom this thesis would not have been possible:

Professor Mark OMalley, whose guidance, help, expertise and encouragement through-

out the project was invaluable. Always making time for discussion, his supervision

throughout has been excellent and I am extremely grateful for everything over the last

four years. Thank you.

Dr. Damian Flynn and Julia Ritchie, of the Queens University of Belfast, who collab-

orated on the development of the Ireland electricity system model and with whom I

had many useful and informative discussions.

Dr. Lawrence Jones of Areva T&D, who gave me the opportunity to to spend 3 months

working with Areva T&D in Bellevue, Washington.

Professor Chen Ching Liu of the University of Washington, Seattle, without whom the

trip to Washington would not have been possible.

Colleagues in ESB National Grid, for many useful discussions and interactions, in

particular Jonathan OSullivan, Michael Power, Doireann Barry, Kate OConnor, Pat

McGrath and John Kennedy.

ESB Power Generation, in particular Michael OMahony, Alan Egan and Nicholas

Tarrant, for information and advice during the development of the CCGT model.

Tom Wilson of Viridian, for help and useful discussions during the development of the

CCGT model.

Dr. Alan Mullane, for his guidance and expertise in collaboration on the study into

iv

frequency control and wind turbine technology. Also for all the advice and questions

answered, about LaTex as well as wind, and proof reading this thesis.

Ronan Doherty, with whom I collaborated on the study into frequency control in com-

petitive market dispatch in addition to a number of different projects, for the many

useful and informative discussions throughout.

All occupants of Room 157 over the course of the last four years. In particular, Shane

Rourke for his help, advice and the invaluable discussions since I started and Hugh

Mullany for his advice and proof reading this thesis. Also Tim Hurley, Andy Keane,

Eleanor Denny, Garth Bryans and Ciara OConner for the constant moral support, tea

and coffee breaks, and a enjoyable working atmosphere.

My family, Liz, Pamela, Richard, John, and in particular Mum and Dad. Thank you

for the constant support and encouragement, not just over the last four years, but in

everything I do.

All my friends, whose friendship I value greatly.

And finally James, for the endless encouragement, support, confidence in me and, not

least, patience, which have been invaluable over the last number of years. Thank you

for everything.

v

Publications arising from this thesis

Journal Papers:

R. Doherty, G. Lalor and M. OMalley,Frequency Control in Competitive Electricity

Market Dispatch, IEEE Transactions on Power Systems, August 2005, Vol. 20, No.

3, pp. 1588-1596. (Appendix C)

G. Lalor, J. Ritchie, D. Flynn, and M. OMalley, The Impact of Combined Cycle Gas

Turbine Short Term Dynamics on Frequency Control, IEEE Transactions on Power

Systems, August 2005, Vol. 20, No. 3, pp. 1456-1464. (Appendix B)

G. Lalor, A. Mullane and M. OMalley, Frequency Control and Wind Turbine Tech-

nologies, IEEE Transactions on Power System. In press, 2005. (Appendix D)

Conference Papers:

G. Lalor and M. OMalley, Frequency Control on an Island Power System with In-

creasing Proportions of Combined Cycle Gas Turbines, presented at IEEE Powertech

Conference, Bologna, June 2003. (Appendix E)

G. Lalor, J. Ritchie, S. Rourke, D. Flynn, and M. OMalley, Dynamic Frequency Con-

trol with Increasing Wind Generation, presented at IEEE Power Engineering Society

General Meeting, Denver, Colorado, June 2004. (Appendix F)

vi

Table of Contents

1 Introduction 1

1.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1.2 Frequency Control of an Island Power System . . . . . . . . . . . . . . 4

1.2.1 Frequency Control . . . . . . . . . . . . . . . . . . . . . . . . . 4

1.2.2 Island Power Systems . . . . . . . . . . . . . . . . . . . . . . . . 7

1.2.3 Literature Review . . . . . . . . . . . . . . . . . . . . . . . . . . 9

1.3 The Aims and the Scope of this Thesis . . . . . . . . . . . . . . . . . . 12

2 System Model 14

2.1 The Ireland Power System . . . . . . . . . . . . . . . . . . . . . . . . . 14

2.2 Modelling the Ireland Power System. . . . . . . . . . . . . . . . . . . . 16

2.2.1 Assumptions of the Model . . . . . . . . . . . . . . . . . . . . . 17

2.2.2 Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

2.2.3 Load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

2.2.4 Connecting System . . . . . . . . . . . . . . . . . . . . . . . . . 32

2.3 Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

2.4 Simulation Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

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2.5 Tuning the Ireland System Model . . . . . . . . . . . . . . . . . . . . . 35

2.5.1 Generating Units . . . . . . . . . . . . . . . . . . . . . . . . . . 36

2.5.2 Load Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

2.5.3 Connecting System . . . . . . . . . . . . . . . . . . . . . . . . . 44

2.6 Results and Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

2.6.1 Validation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

2.6.2 Frequency Control in Competitive Electricity Market Dispatch . 46

2.7 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

3 Frequency Control with Combined Cycle Gas Turbines 53

3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

3.2 CCGT Background and Characteristics . . . . . . . . . . . . . . . . . . 54

3.2.1 Gas Turbine Component . . . . . . . . . . . . . . . . . . . . . . 55

3.2.2 The Heat Recovery Steam Generator and Steam Turbine Com-ponents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

3.3 Literature review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

3.3.1 CCGT Modelling . . . . . . . . . . . . . . . . . . . . . . . . . . 63

3.4 CCGTs on the Ireland System . . . . . . . . . . . . . . . . . . . . . . . 65

3.5 CCGT Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

3.5.1 CCGT Model Structure . . . . . . . . . . . . . . . . . . . . . . 66

3.5.2 Model Tuning and Validation . . . . . . . . . . . . . . . . . . . 70

3.6 The Impact of CCGT Dynamics on Frequency Control . . . . . . . . . 75


3.8 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

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4 Frequency control and Wind Turbine Technology 81

4.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

4.2 Wind Generation Technology . . . . . . . . . . . . . . . . . . . . . . . 82

4.3 Wind Turbine Generator Modelling . . . . . . . . . . . . . . . . . . . . 86

4.3.1 Fixed Speed Wind Turbine Model . . . . . . . . . . . . . . . . . 86

4.3.2 DFIG Wind Turbine Model . . . . . . . . . . . . . . . . . . . . 89

4.4 Wind Generation on the Ireland Electricity System . . . . . . . . . . . 92

4.4.1 Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

4.4.2 Simulating Procedure . . . . . . . . . . . . . . . . . . . . . . . . 93


4.5.1 Response of wind turbine technologies to system frequency devi-ations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

4.5.2 System frequency control with increasing wind penetration . . . 95

4.5.3 Supplementary response from DFIG . . . . . . . . . . . . . . . . 100

4.6 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

5 Supplementary Study: Wind Integration Studies and Frequency Con-trol 105

5.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

5.2 Review of Wind Integration Studies . . . . . . . . . . . . . . . . . . . . 107

5.3 Preliminary Wind Integration Frequency Control Study . . . . . . . . . 114

5.3.1 e-terra simulator . . . . . . . . . . . . . . . . . . . . . . . . . . 115

5.3.2 Wind Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

5.3.3 Determination of Wind Variability Costs . . . . . . . . . . . . . 118

5.3.4 Determination of Wind Unpredictability Costs . . . . . . . . . . 121

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5.4 Preliminary Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

5.4.1 Available Wind Data . . . . . . . . . . . . . . . . . . . . . . . . 122

5.4.2 Scope of the study . . . . . . . . . . . . . . . . . . . . . . . . . 122

5.4.3 Sample Test System . . . . . . . . . . . . . . . . . . . . . . . . 123

5.4.4 Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

5.4.5 Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

5.5 Discussion and Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . 130

6 Conclusions 134

6.1 Synopsis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

6.2 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

6.3 Scope for future work . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138

References 140

A Frequency Disturbance Event 152

B The Impact of Combined Cycle Gas Turbine Short Term Dynamicson Frequency Control 155

C Frequency Control in Competitive Electricity Market Dispatch 166

D Frequency Control and Wind Turbine Technologies 176

E Frequency Control on an Island Power System with Increasing Pro-portions of Combined Cycle Gas Turbines 186

F Dynamic Frequency Control with Increasing Wind Generation 194

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List of Figures

1.1 Operating reserve time-scales . . . . . . . . . . . . . . . . . . . . . . . 6

1.2 Recorded system frequency on Ireland electricity system . . . . . . . . 9

2.1 Generation mix on the Ireland electricity system for 1995, 2005 and 2010 15

2.2 Steam unit model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

2.3 Open cycle gas turbine model . . . . . . . . . . . . . . . . . . . . . . . 24

2.4 Linear hydroelectric-turbine model . . . . . . . . . . . . . . . . . . . . 28

2.5 Ireland system model . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

2.6 Inertial response control loop . . . . . . . . . . . . . . . . . . . . . . . 37

2.7 Six frequency events on the Ireland system with corresponding poweroutput of a sample generator . . . . . . . . . . . . . . . . . . . . . . . . 38

2.8 Comparison between actual and simulated frequency response of a steamunit to a low frequency event . . . . . . . . . . . . . . . . . . . . . . . 40

2.9 Turlough Hill generating unit response for two low frequency events . . 42

2.10 Actual and simulated system frequency for a 267 MW generation loss . 46




2.14 Simplified system frequency model . . . . . . . . . . . . . . . . . . . . 50

xi

2.15 Comparison of the generation response of the black box model with thevalidated system model . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

3.1 Single-shaft CCGT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

3.2 Multi-shaft CCGT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

3.3 CCGT model structure . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

3.4 CCGT ambient temperature dependency . . . . . . . . . . . . . . . . . 71

3.5 CCGT ambient pressure dependency . . . . . . . . . . . . . . . . . . . 72

3.6 Change in power output of a typical near base loaded CCGT in responseto a frequency event on the system . . . . . . . . . . . . . . . . . . . . 73

3.7 Simulated power output of the GT component of a typical CCGT to afrequency drop of 0.5 Hz . . . . . . . . . . . . . . . . . . . . . . . . . . 74

3.8 Winter peak scenario with 422 MW trip . . . . . . . . . . . . . . . . . 77

3.9 Summer night valley scenario with 400 MW trip . . . . . . . . . . . . . 78

3.10 Summer day valley scenario with 400 MW trip . . . . . . . . . . . . . . 79

3.11 Sensitivity of system frequency nadir to increasing proportions of CCGTs 80

4.1 Typical Cp curve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

4.2 Fixed speed wind turbine Generator . . . . . . . . . . . . . . . . . . . . 84

4.3 Doubly fed induction generator . . . . . . . . . . . . . . . . . . . . . . 85

4.4 DFIG model with FOC controller . . . . . . . . . . . . . . . . . . . . . 91

4.5 Comparison of fixed speed WTG and DFIG WTG responses to the lowfrequency event . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

4.6 Effect of increasing wind penetration on maximum rate of change offrequency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

4.7 Simulated system frequency following the trip of largest infeed duringthe SDV scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

xii

4.8 Frequency nadir and static reserve tripped following the loss of thelargest infeed for increasing wind penetration during the Summer DayValley scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

4.9 Frequency nadir and static reserve tripped following the loss of thelargest infeed for increasing wind penetration during the Summer NightValley scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

4.10 Supplementary control loop for DFIG WTG controller. . . . . . . . . . 102

4.11 Comparison of fixed speed WTG and DFIG WTG responses to the lowfrequency event, including supplementary control loop . . . . . . . . . . 103

4.12 Simulated system frequency following the trip of largest infeed duringthe SDV scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

5.1 Test system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

5.2 Wind farm power output time series . . . . . . . . . . . . . . . . . . . 126

5.3 System frequency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

5.4 ACE: Control Area A . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

5.5 ACE: Control Area B . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

5.6 ACE: Control Area C . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

5.7 Generator power output: Control Area A . . . . . . . . . . . . . . . . . 131

5.8 Generator power output: Control Area B . . . . . . . . . . . . . . . . . 132

5.9 Generator power output: Control Area C . . . . . . . . . . . . . . . . . 133

A.1 Recorded system frequency on Ireland electricity system . . . . . . . . 152

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List of Tables

2.1 Under-frequency setting for Turlough Hill operating modes . . . . . . . 28

4.1 Comparison of inertial response from various generators . . . . . . . . . 95

4.2 Maximum ROCOF following loss of largest infeed (422MW) for variousoperating scenarios, wind turbine penetrations and wind turbine tech-nology type. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

5.1 Test system generation capacity . . . . . . . . . . . . . . . . . . . . . . 123

5.2 Test system set-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

5.3 Test case scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

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Nomenclature

a = Frequency sensitivity of GT exhaust gas flow calculation factor

A = Area swept by wind-turbine rotor (m2)

b = Constant, such that a+b=1

B = Frequency bias setting (MW/0.1Hz)

Cp = Performance coefficient

CD = Boiler drum integral coefficient (s)

CSH = Boiler superheater integral coefficient (s)

f = System frequency (Hz)

FA = Actual control area frequency (Hz)

fgen = Under frequency relay setting for Turlough Hill gen mode (Hz)

FHP = Fraction of power output from high pressure ST stage

fint = Under frequency relay setting for interruptible customers (Hz)

FIP = Fraction of power output from high pressure ST stage

FLP = Fraction of power output from high pressure ST stage

fmin = Under frequency relay setting for Turlough Hill min gen mode (Hz)

fo = Nominal system frequency (Hz)

fpump = Under frequency relay setting for Turlough Hill pump mode (Hz)

FS = Scheduled control area frequency (Hz)

fspin = Under frequency relay setting for Turlough Hill spin mode (Hz)

fUFLS = Under frequency load shedding relay setting (Hz)

G = Set of generators

Gw = Gate position (per unit)

i = Current (A)

igv = Inlet guide vane angle ()

Ij = Inertia of generating unit j (kgm2)

INT = Logical operator for inertial control loop

xv

J = Polar moment of inertia of wind turbine and rotor (kgm2)

K = Friction drop coefficient of orifice between drum and superheater

K1P = Proportional gain for d axis current controller

K2P = Proportional gain for q axis current controller

K1I = Integral gain for d axis current controller

K2I = Integral gain for q axis current controller

KBB1 = Black box model parameter 1

KBB2 = Black box model parameter 2

Ki = IGV controller constant

kpf = Steady state frequency sensitivity of the load

kpv = Active power and voltage load model parameter

kqf = Reactive power and frequency load model parameter

kqv = Reactive power and voltage load model parameter

Kscl = Supplementary control loop constant

KE = Kinetic energy (MWs)

KEi = Kinetic energy of generator i (MWs)

KEL = Kinetic energy of system load (MWs)

KEo = Kinetic energy at nominal frequency fo (MWs)

Ligv = Inlet guide vane position (per unit)

Lm = Per phase mutual inductance (H)

Lr = Per phase rotor inductance (H)

Ls = Per phase stator inductance (H)

L = L2

m LrLs (H)

m = Steam flow rate out of boiler drum (per unit)

ms = Steam flow rate into steam turbine (per unit)

mw = Steam flow rate into boiler drum (per unit)

N = System speed (per unit)

NG = Number of generators

Nref = Reference system speed (per unit)

NIA = Algebraic sum of the actual flows on all tie lines/interconnectors (MW)

NIS = Algebraic sum of the scheduled flows on all tie lines/interconnectors (MW)

p = Differential operator

P = Active power (MW)

Pa = Ambient pressure (mbar)

Paero = Accelerating aerodynamic power (MW)

xvi

PD = Boiler drum pressure (per unit)

Pelec = Electrical power (MW)

Pf = Number of machine poles

PGEN = Active power generated (MW)

Pk = Amount of generation lost (MW)

Pload = Active power required by the load (MW)

Pmax = Maximum rated generator power output (MW)

Pmech = Mechanical power (MW)

Pmin = Minimum rated generator power output (MW)

Po = Steady state system demand (MW)

Ppu = Active power (per unit)

PT = Boiler throttle pressure (per unit)

Q = Heat Energy (per unit)

Qload = Reactive power required by the load (MVAR)

R = Resistance ()

Rd = Droop (%)

Rr = Radius of rotor (m)

Rp = Primary reserve available at 5 seconds (MW)

SP = Generator operating set-point (per unit)

T1 = Load time constant (T)

Ta = Ambient temperature (C)

Tcd = Compressor discharge time constant (s)

TCH = Steam transport and conversion time constant (s)

TCO = Steam turbine crossover and conversion time constant (s)

Tem = Electromagnetic torque (N m)

Temref = Reference electromagnetic torque (N m)

Tgf = Gas fuel system time constant (s)

Ti = IGV controller integration rate (s)

Tigv = IGV actuator time constant (s)

Tpf = Ratio of load inertia to system frequency

Tpv = Active power and voltage load model parameter

Tqf = Reactive power and frequency load model parameter

Tpf = Reactive power and voltage load model parameter

Tr = Gas turbine rated exhaust gas temperature (C)

Tref = Reference torque (N m)

xvii

TRH = Steam turbine reheater and conversion time constant (s)

Ts = Droop governor time constant (s)

Tsc = Supplementary control loop torque (N m)

Tt = Temperature controller integration rate (s)

Tv = Valve positioner time constant (s)

Tw = Water time constant (s)

Tx = Gas turbine exhaust gas temperature (C)

Txc = Gas turbine corrected exhaust gas temperature (C)

Txm = Gas turbine measured exhaust gas temperature (C)

TDCR = Combustion reaction time delay (s)

TDTE = Exhaust gas transport delay (s)

u = wind speed (m/s)

V ,v = Voltage (V)

Wf = Gas turbine fuel flow (per unit)

Wx = Gas turbine exhaust gas flow (per unit)

= Blade pitch angle (rad)

Pint,j = Inertial response of generating unit j (MW)

= Tip-speed ratio

= Flux linkage (Wb)

o = Average slip of an average induction machine

= Supplementary control loop time constant (s)

i = Inertial control loop time constant (s)

= Density of air (kg/m3)

= system speed (rad/s)

dq = dq reference frame angular velocity (rad/s)

m = Rotor mechanical angular velocity (rad/s)

s = Shaft speed (rad/s)

t = Wind-turbine rotor speed (rads1)

r = Rotor electrical angular velocity (rad/s)

Subscripts

d, q = Direct, Quadrature axis component

I, P = Integral, Proportional

r, s = Rotor, Stator

xviii

Acronyms

AC Alternating Current

ACE Area Control Error

AGC Automatic Generation Control

BPA Bonneville Power Administration

DC Direct Current

CCGT Combined Cycle Gas Turbine

CER Commission for Energy Regulation

CHP Combined Heat and Power

CLP China Light & Power Co.

CO2 Carbon Dioxide

DFIG Doubly Fed Induction Generator

EMS Energy Management System

ESB Electricity Supply Board

ESBNG ESB National Grid

FOC Field Orientated Controller

GT Gas Turbine

HEC Hong Kong Electric Co.

HRSG Heat Recovery Steam Generator

HVDC High Voltage Direct Current

IEC Israel Electric Corporation

IGV Inlet Guide Vane

NIE Northern Ireland Electricity

NOx Oxides of Nitrogen

OCGT Open Cycle Gas Turbine

POR Primary Operating Reserve

ROCOF Rate Of Change Of Frequency

SCADA Supervisory Control and Data Acquisition

SCIG Squirrel Cage Induction Generator

xix

SO System Operator

SONI System Operator of Northern Ireland

ST Steam Turbine

TH Turlough Hill

TNB Tenaga Nasional Berhad

UFLS Under Frequency Load Shedding

WTG Wind Turbine Generator

xx

Chapter 1

Introduction

1.1 Background

The function of a power system is to provide customers with an electricity supply of

acceptable reliability, where reliability signifies the ability to supply adequate electric

service on a nearly continuous basis with few interruptions over an extended period of

time (IEEE/CIGRE, 2004). Therefore, to design and operate a power system within

adequate reliability margins such that overall costs are minimised is a key objective for

all system operators.

Power system security is an indication of the level of robustness of the power system

at any instant in time to a disturbance (Fink and Carlsen, 1978). When operating

in a secure state, a power system can withstand most severe disturbances without

interruption to customer supply. However, if operating in a state with reduced security

margins, a power system will be more susceptible to disturbance, resulting in a higher

likelihood of customer supply disruption. To maintain adequate reliability it is desirable

to maximise the time the power system is operating in a secure state, with frequency

and voltage levels within acceptable standards. In order for a power system to be

secure, the power system must be operating in a stable state. Stability indicates

the ability of the system to return to an equilibrium operating state subsequent to a

disturbance, and is dependent on both the type of disturbance and the initial power

system operating conditions (IEEE/CIGRE, 2004). Although the electricity industry

is undergoing regulatory and organisational changes, the basic concepts and rules for

1

Chapter 1. Introduction 2

reliable, secure and stable system operation remain unchanged.

Ancillary services can be broadly defined as the range of technical services required

by the system operators to maintain both secure and stable operation of the power

system. These include operating reserves for frequency control, voltage control and also

system restoration/black start capability. While the methods by which these services

are procured may vary and evolve with regulatory structure, the necessity of ancillary

services is unquestionable. This is highlighted by a number of recent contingencies

worldwide resulting in severe lapses in the security of power systems including blackouts

in the Eastern US and Canada, Italy and the UK (NERC, 2004; UCTE, 2003; NGC,

2003).

The control of system frequency is a vital aspect of secure and stable power system

operation. A continuous balance between active power generated and active power

consumed by the load and losses is required to maintain frequency constant at nominal

system frequency. Any imbalance in active power will result in a frequency devia-

tion. While precise instantaneous balancing of active power is not viable, frequency

control ensures that the system frequency remains within acceptable frequency limits.

Frequency control can be called upon for a variety of conditions ranging from a grad-

ual change in load levels over time to a sudden loss of generation or step increase in

demand.

A range of power system characteristics including system size, individual generator and

load frequency response characteristics and plant mix on the system influence frequency

control. The size and speed of a frequency deviation depends on the magnitude of the

power imbalance and the power system size. Power system inertia is the resistance

of the individual rotating masses of the generator and load components synchronised

to the system to a change in system speed. The greater the inertia of the system,

the slower the rate of change of frequency in the event of a power imbalance of given

magnitude. Large interconnected power systems have high system inertia, due to the

large number of components synchronised to the system. In addition, the size of in-

dividual components, such as generators, tends to be small in comparison with total

system size. As such, large frequency excursions from nominal are uncommon, and the

rate of change of frequency is relatively slow due to high inertia. Small isolated power

systems, in contrast, have much lower system inertia. Combined with the fact that a

single generator can comprise a sizeable proportion of total generation, large power im-


balances relative to the system size are more frequent and frequency changes are faster.

Adequate frequency control on such a system is vital to prevent the excursion of system

frequency beyond limits where interruption to customer supply through load tripping

starts to occur. Therefore, maintaining system frequency at nominal frequency for a

small island power system with limited interconnection can be technically challenging.

Plant mix is continually evolving, for all power systems, large and small. Knowledge

of the impact that evolving plant mix will have on system frequency control is vital

to maintain a secure and stable power system with adequate reliability standards.

Traditionally large coal and oil fuelled thermal plant comprised the majority of the

generation mix on many power systems. However, due to economic and environmental

driving forces, increasing proportions of combined cycle gas turbines and open cycle

gas turbines are now being used to meet increasing demand and to replace older coal

and oil-fired plants as they are retired.

Combined cycle gas turbines (CCGTs) offer higher efficiency, greater flexibility and

lower emissions than many conventional thermal generators, in addition to progressively

shorter installation times and reducing installation costs. As a result, CCGT generating

units comprise an ever increasing proportion of generation capacity for many electricity

systems. The efficiency of combined cycle gas turbines is maximised when operating at

or near maximum or base load, and declines with decreased loading. The behaviour of

CCGT generators in response to frequency excursions differs from that of a conventional

steam turbine, and may have a detrimental effect on the system frequency response

when the CCGT is run at, or near, base load. This effect will be progressively more

apparent as CCGTs operating at or near base load comprise increasing proportions of

the generation.

In conjunction with the shift towards CCGT plant, many power systems worldwide are

also experiencing a rapid increase in wind generation. This trend is driven by a variety

of reasons including environmental concerns, targets for electricity production from

renewable energy resources, the desire for increased fuel diversity, constant advances

in technology and economic factors including declining costs. While the addition of

conventional synchronous generators to a power system will result in an inherent in-

crease in the system inertial response, this is not necessarily the case with wind turbine

generators. Therefore, if rapidly increasing levels of wind generation begin to displace

conventional synchronous generation, erosion of system inertial response may result.


This effect will result in increasing rates of change of frequency during power imbal-

ances, and the magnitude of frequency excursions may also rise. These effects will

influence small isolated power systems, in particular, where system inertia levels are

inherently low.

1.2 Frequency Control of an Island Power System

1.2.1 Frequency Control

System frequency provides a instantaneous indication of system operating conditions,

as any imbalance between active power generated and consumed manifests itself as a

deviation from nominal system frequency. The magnitude of the frequency excursion

and the rate of change of frequency are dependent on a number of factors, including

the size of the power imbalance and the characteristics of the power system. While

small variations in system frequency will not result in a reduction is system reliability

or security, large frequency deviations can have a serious impact on power system

components and power quality is degraded. Damage to generators and transformers

can result from overheating due to increases in the volts/hertz ratio during times of

low frequency. In addition, generator damage due to mechanical vibrations can occur if

frequency deviations greater than 5% of nominal frequency occur (Kirby et al., 2002).

As a result, most power system components are equipped with protective relays, which

are triggered if system frequency reaches critical conditions. Therefore, control of

system frequency is vital for the secure, reliable operation of the power system.

The objective of frequency control is to maintain adequate balance between active

power consumed and generated on a power system such that frequency remains within

acceptable limits around nominal frequency. As the demand of a power system is con-

stantly changing, frequency control is continuously called upon to fulfil this objective.

To a large extent, the changing system load is predictable and generators are committed

and dispatched based on the forecast load levels (Machowski et al., 1997). Therefore,

under normal operating conditions, the balancing of energy is achieved by adjusting

generator active power set-points. Signals to generators for such adjustments are ei-

ther issued by the system operator or automatically generated and issued by automatic

generation control (AGC).


In the event of an unpredicted increase in system load or an unexpected loss of genera-

tion or transmission line, an imbalance of active power will occur. Every power system

has stored kinetic energy by virtue of the masses of the generator and load compo-

nents rotating in synchronism, which is a function of both the system inertia and the

system frequency. In response to a power imbalance, stored kinetic energy is released

to redress the imbalance, resulting in an inherent reduction in system frequency. In

the event of active power generated exceeding demand, kinetic energy is absorbed and

an increase in system frequency results. However, while frequency control in the event

of high frequency events is essential and many issues discussed here are relevant, low

frequency events are the focus of this thesis.

In order to limit the frequency excursion from nominal system frequency, and to main-

tain a stable and secure system, action in addition to the inherent system inertial

response is required, i.e. frequency control. Frequency control may be broadly cat-

egorised into automatic and manual frequency control. The former responds auto-

matically to either a deviation from nominal system frequency or a rate of change of

frequency in excess of a predefined threshold. Sources of automatic frequency control

are the natural reduction in system load with low frequency, the automatic increase in

generator active power output activated by the speed droop governor, low frequency

or rate of change of frequency triggered responses from pumped storage units and the

automatic shedding of load. Manual frequency control encompasses all instructions

issued by the system operator to generators (and load if applicable, i.e. in the event

of load participation) for changes from the reference set point of the generator (or to

current active power consumption in the case of load).

Additional active power capacity available (i.e. when compared to steady state oper-

ation prior to a frequency event) from generation units or through reduction in load

for the purpose of frequency control is known as operating reserve (ESBNG, 2005b).

Many different definitions for the categorisation of operating reserve exist. In this the-

sis, reserve is categorised into primary, secondary and tertiary operating reserve, as

defined by ESBNG (2005b), and illustrated in Fig. 1.1.

Primary operating reserve (POR) is the additional active power available from genera-

tors and through reduction of active power consumption of the load which is available

between 5 and 15 seconds subsequent to an event on the system. Secondary reserve is

defined to be the additional active power available and sustainable for the time period


Figure 1.1: Operating reserve time-scales (SEI, 2004)

from 15 to 90 seconds after the event. Tertiary reserve is the additional active power

available from 90 seconds to 20 minutes subsequent to the event. Finally replacement

reserve is the additional active power available from 20 minutes to 4 hours after the

event.

In the event of a power imbalance, POR automatically responds to arrest the falling

frequency and initiate recovery towards nominal frequency through the reduction of

the power imbalance. The predominant source of POR on the majority of systems is

the automatic droop governor response of generators operating below maximum rated

active power output to a deviation in speed. Other sources of POR from generators

can include an increase in active power when under-frequency relays or rate of change

of frequency (ROCOF) relays are triggered. One example is under-frequency relaying

triggering a rapid increase in active power generation from a pumped storage generating

unit.

System load also contributes to POR. In addition to the natural load reduction due to

low system frequency, system load can also provide static reserve in the form of either

interruptible customers or under-frequency load shedding (UFLS). Static reserve is

defined here as capacity available instantaneously when called upon, with negligible

dynamics.

Some customers (interruptible customers) are contracted to make their load available

for short term interruptions. Specific blocks of load are configured to be tripped by


under-frequency relays if frequency falls to a threshold level. UFLS, however, is the

tripping of uncontracted load at distribution system level and is called upon to pre-

vent system collapse only when other sources of POR fail to arrest falling frequency.

Discrete blocks of load are tripped until generation and load are once again in balance

(Machowski et al., 1997), and frequency decline is arrested.

Once the system frequency has been arrested and stabilised by the POR, it is the task of

secondary and tertiary reserve to restore the system frequency to nominal value. This is

achieved through a combination of automatic droop governor response while frequency

remains below nominal and through discrete instructions issued by the system operator

to generators for changes from the reference set point of the generator until power

is once again balanced, and frequency restored to nominal. Replacement reserve is

employed to replace operating reserve, restoring the system to a secure operating state.

Capacity to provide operating reserve is dispatched in conjunction with generation by

the system operator to ensure availability of adequate operating reserves in the event

of a power imbalance. For a secure system, adequate operating reserve is required

so that the power system can withstand most severe frequency disturbances without

interruption to customer supply. The majority of power system worldwide operate with

an N-1 security criterion (Bialek, 2003). This criterion states that the power system

should operate so instability or load shedding do not occur as a result of the most

severe single contingency. From a frequency control perspective, this entails having

sufficient reserve to withstand the loss of the large power infeeds to the system.

1.2.2 Island Power Systems

Worldwide, power systems have a considerable range of characteristics including size,

both geographical and electrical, the extent of interconnection to other power systems

and generation mix. Many formerly isolated power systems with varying characteristics

have become part of larger synchronous power systems through the use of alternating

current (AC) interconnection. AC interconnection between power systems yields multi-

ple advantages, increased system inertia, trading of energy, sharing of spinning reserve

provision (operating reserve available from online generators) and mutual support dur-

ing contingencies to name just a few (Mak and Law, 1991). While direct current (DC)

interconnection allows energy exchange, power systems linked by DC interconnection


are not synchronous. Therefore, some advantages of AC interconnection such as in-

creased system inertia and the sharing of spinning reserves do not inherently occur

with DC interconnection. However, although frequency control is not inherent, DC

interconnections may be designed to provide spinning reserve.

In large interconnected power systems, the size of individual components such as gener-

ators tends to be small in comparison with the magnitude of the entire system. Power

imbalances due to the loss of a single component in such systems, when they occur, are

therefore generally small with respect to the total system size. In addition, the rate at

which the frequency changes tends to be low due to high system inertia. The construc-

tion of sizeable, more economically viable generating units is possible with minimal

risk to system security. In addition, the provision of operating reserve is shared over a

great number of generators, and may be shared between different systems within the

larger interconnected power system. Generally, geographical dispersion is a character-

istic of large interconnected power systems, and can contribute to a reduced capacity

requirement, as a result of load diversity. One example of the benefits of geographical

dispersion is the staggered occurrence of peak demand when a power system spans

different time zones.

While large strongly interconnected systems comprise a large proportion of power sys-

tems worldwide, there are nonetheless a sizeable number of small isolated or poorly

interconnected systems, for example Israel, New Zealand, Crete, Cyprus and Ireland.

Small power systems that are either isolated or with only DC interconnection have low

system inertia. A power system with low system inertia is more sensitive to system

disturbances, due to less stored energy available to redress energy imbalances and to

slow the rate of change of frequency. In addition, for such power systems, system com-

ponents such as generators tend to be large in comparison with the total system size.

In particular at times of low load, a single generator can comprise a large proportion

of the total system generation. Therefore, in the event of a loss of generation, there is

a greater likelihood of a large frequency excursion as the power imbalance is large with

respect to total system size. On the Ireland electricity system, for example, frequency

deviations of 1% are not uncommon, while larger frequency excursions occur occasion-

ally, as illustrated by the recorded system frequency in Fig. 1.2. (This frequency event

is described in more detail in Appendix A.)

As a consequence of both low system inertia and potential large power imbalances


0 100 200 300 400 500 600 700 80048.4

48.6

48.8

49

49.2

49.4

49.6

49.8

50

Time (s)

Freq

uenc

y (H

z)

Figure 1.2: Recorded system frequency on Ireland electricity system

in addition to the relatively small range of generators to provide operating reserve,

frequency control on small, isolated or DC interconnected systems is particularly chal-

lenging. Distinctive operating and control strategies are necessary to maintain the

system within limits of reliability and security. The main dynamic operation problems

in small power systems relate to frequency control, in particular the behaviour of the

system in response to large disturbances (Kottick and Or, 1996). Frequency control

on such systems can in fact cause technical problems an order of magnitude greater

than those experienced on large interconnected systems (OSullivan et al., 1999). The

importance of frequency control on island systems during a contingency is evident in

the considerable volume of relevant literature.

1.2.3 Literature Review

The benefits of AC interconnection between power systems are highlighted in Mak and

Law (1991), where the AC interconnection between The China Light & Power Co.


(CLP) and Hong Kong Electric Co. (HEC) are examined. The evolution of CLP from

an isolated system to one with AC interconnection to other systems was found to have

beneficial effects on system performance during system contingencies and also resulted

in a more economical system operation. However, AC interconnection is not always an

option and therefore a clear understanding of the frequency control dynamics of island

power system is necessary to ensure optimal system security and reliability.

Two neural network models that predict the frequency nadir (minimum frequency)

and calculate the amount of UFLS during a loss of generation on the Israel Electric

Corporation (IEC) system are developed in Kottick and Or (1996). The IEC operates

an island system and at the time of the study the installed capacity was approximately

5050 MW, with a 550 MW unit as the largest infeed. As the transmission system is

strongly connected, frequency throughout the system is uniform. Therefore, transmis-

sion effects could be neglected and a single busbar model was employed. Both the

magnitude of the frequency excursion and the extent of UFLS are indicators of the

severity of the contingency, and comprise two components of the dynamic security as-

sessment for the IEC system. The models developed were demonstrated to perform

well in assessing the UFLS subsequent to a loss of generation. The potential effect on

frequency regulation (which is the automatic power balancing on a second to second

basis) of a 25 MWh capacity battery energy storage device on the IEC system was

investigated in Kottick et al. (1993), where a single busbar model was again used to

represent the power system. It was demonstrated that simulated frequency deviations

resulting from sudden demand variations were reduced considerably through the ad-

dition of the battery energy storage device, which was assumed capable of sustaining

a power output of 30 MW for 15 minutes. Due to a fast response time, the battery

energy storage device was found to be potentially useful for regulation and as rapid

operating reserve on an island system, where the rapid response time is critical due to

low system inertia.

The application of UFLS to the isolated power system of Cyprus is considered in Con-

cordia et al. (1995). At the time of the study, the Cyprus system (with a peak load of

500 MW) had a largest infeed of 60 MW, which was 12% of peak load and comprised

a significantly greater proportion of load at times of low demand. While the general

principles of UFLS are independent of system size, the distinguishing characteristics

of isolated system must be taken into account when devising the UFLS plan. A well

devised UFLS schedule results in the system surviving situations that would have oth-


erwise resulted in blackouts. In Concordia et al. (1995), a criteria deemed appropriate

for UFLS on an isolated system was developed and applied to the Cyprus system. It

was also found that the effectiveness of load shedding increases with increasing system

load.

The effects of increasing proportions of renewable generation resources on the system

frequency control on the island of Crete have been the focus of several studies (Hatziar-

gyriou et al., 2000, 2002; Papazoglou and Gigandidou, 2003). In particular, Crete has

experienced a rapid growth in wind generation in recent years. These studies pre-

dominantly focus on the system under non-contingency operating conditions over the

economic dispatch and unit commitment time frames. The short-term dynamic effects

of wind turbine generators on the system frequency during a frequency event are not,

however, considered.

Another example of an island electricity system is the Ireland power system, which con-

sists of two synchronous power systems. Before interconnection between the Northern

Ireland Electricity (NIE) system and the Electricity Supply Board (ESB) system of the

Republic of Ireland, each system on the island of Ireland operated as a small isolated

system. With peak loads of approximately 1650 MW and 3300 MW respectively before

interconnection, each system had low system inertia and as a result emergency control,

i.e. frequency control in the event of a contingency, was critical.

The strategies of the NIE system for emergency control of frequency when operating

as an isolated system are outlined in Fox and McCartney (1988). Several obstacles

such as inaccurate unit response information and difficulties with the coordination of

under-frequency relay settings with system dynamics are also discussed. Limited UFLS

was tolerated as a likely necessity on the NIE system at the time of the study in the

event of the loss of a major infeed. Further studies into the control and proper design

of UFLS arrangements are carried out in Fox et al. (1989) and Thompson and Fox

(1994). The use of rate of change of frequency as an activating signal for UFLS was

used in Fox et al. (1989), and found to provide more accurate load shedding than

the use of under frequency relays. System frequency was simulated using a single

busbar model. This approach was expanded in Thompson and Fox (1994), where each

UFLS relay uses system demand, spinning reserve, system inertia and the amount of

low priority load available for shedding elsewhere in conjunction with the local rate of

change of frequency to assess whether to operate. This approach resulted in a significant


reduction in the amount of excessive UFLS when compared to the fixed rate of change

of frequency scheme of Fox et al. (1989). The effect of flywheel energy injection on

emergency control of frequency on the NIE system has also been studied (Hampton

et al., 1991). Once again a single busbar system model to predict system frequency

following a unscheduled generation outage was used, and the model was validated by

comparison to actual power system measurements. It was found that the use of the

flywheel energy storage and retrieval scheme can contribute to considerable savings

through spinning reserve replacement if correctly designed and scheduled.

An emergency reserve model of the ESB system was developed and implemented to

study frequency control on an island power system in OSullivan and OMalley (1996),

OSullivan (1996) and OSullivan et al. (1999). The single busbar model was tuned

using actual frequency events on the ESB system to accurately account for the dy-

namic system characteristics following a loss of generation. The provision of frequency

control was shown to be a critical issue as electricity markets emerge for island systems

(OSullivan et al., 1999). As a result, the above model was subsequently incorporated

into a new methodology for the provision of reserve in a competitive market (OSullivan

and OMalley, 1999).

1.3 The Aims and the Scope of this Thesis

The objective of this thesis is to examine frequency control on an island system with

evolving plant mix. In particular, the influence of the characteristics of CCGTs and

wind turbine generators on system frequency control will be examined, and the Ireland

electricity system is used as an illustration.

Simulation, using validated models, is a good first step in understanding frequency

control in the context of evolving plant mix. A single busbar model of the Ireland

electricity system is developed, tuned and validated in Chapter 2. This model is suitable

for the study of frequency response behaviour of an island system for up to 20 seconds

after a power imbalance occurs. This system model is subsequently employed to tune a

black-box model, which is used as the basis for the derivation of a minimum frequency

control constraint (Appendix C).

A model suitable for studying the short-term dynamic response of a combined cycle gas


turbine to a system frequency deviation is developed, tuned and validated in Chapter

3. This model is then used in conjunction with the Ireland system model of Chapter 2

to study the impact of increasing levels of CCGT generation on frequency control of a

small island system (Appendix B).

Models for two different wind turbine technologies are presented in Chapter 4. To

examine the short-term dynamic response of an island power system to sudden power

imbalances with increasing proportions of wind generation, these models are integrated

into the Ireland system model of Chapter 2, which is modified to represent the proposed

2010 system model (Appendix D).

The impact of wind generation on both short-term and long-term frequency control

are assessed in Chapter 5. A review of a number of wind integration studies is carried

out. Consequently, a preliminary methodology for a wind integration frequency control

study using the Areva T&D e-terra simulator is proposed, which is applicable to both

island and interconnected power systems. This work was carried out during a three

month industry placement with Areva T&D in Bellevue, Washington.

Chapter 2

System Model

2.1 The Ireland Power System

The electricity system on the island of Ireland operates at 50 Hz, with a current peak

load of approximately 6100 MW (ESBNG, 2004b; SONI, 2003b). The Ireland electricity

system consists of two power systems: the NIE system, operated by System Operator

for Northern Ireland (SONI) and the ESB system, operated by ESB National Grid

(ESBNG). Prior to 1995, the ESB and NIE power systems operated in isolation, with

the limited connection between the two systems generally out of service and, as a

consequence, unreliable (OSullivan, 1996). In 1995, however, the two systems were

reconnected, and now comprise a single synchronous system, connected to each other

through a number of AC lines. The main connection between the NIE and ESB systems

consists of two 275 kV circuits, each with a capacity of 600 MW and of length 50 km.

There are also two additional 110 kV lines, with capacity of 120 MW, connecting

the systems at two separate locations along the interface between Northern Ireland

and the Republic of Ireland (ESBNG, 2004a). A single high voltage direct current

(HVDC) interconnection is in operation between Northern Ireland and Scotland with

a capacity of 500 MW (ESBNG, 2004b). However, this HVDC interconnection is not

currently configured to provide frequency response in the short time frame. With no

AC interconnection to other systems to increase the inertia of the system and share

reserve provision requirements, the Ireland electricity system is essentially an isolated

system.

Chapter 2. System Model 15

The generating capacity of the Ireland electricity system consists of a combination of

reheat and non reheat fossil fuelled steam turbine generators, open cycle gas turbines

(OCGTs), combined cycle gas turbines (CCGTs), hydroelectric generators, a single

pumped storage station and wind turbine generators. In addition, other resources such

as biomass generators, combined heat and power (CHP) and other renewables also

provide limited generating capacity. Generation mix is constantly evolving, with both

CCGTs and wind turbine generators in particular comprising increasing proportions of

generation on the system. A comparison of the generation mix on the Ireland system

in 2005 with the ESB and NIE systems in 1995 is illustrated in Fig. 2.1.

Figure 2.1: Generation mix on the Ireland electricity system for 1995, 2005 and 2010((SONI, 2003b; ESBNG, 2004b))

The reduction in the proportion of steam units from 1995 to 2005, alongside the increase

in proportions of both CCGT and wind generation is clearly illustrated. The predicted

Ireland generation mix in 2010 is also included in Fig. 2.1, to illustrate the forecast

changing proportions of generation on the system.

The system operator (SO) of each system performs scheduling and dispatch indepen-

dently, while incorporating contracted flows on the interconnections between the two

systems. The provision of primary operating reserve, however, is shared between the

two systems.


In accordance with the system grid codes (ESBNG, 2005b; SONI, 2003a) frequency

regulation is provided by each generator on the system, by virtue of a droop governor,

with a compulsory droop setting of 4%. Operating reserve is divided into several

categories according to the timescale within which it is available in response to an event,

as described in Chapter 1. On the Ireland system, the primary operating reserve (POR)

requirement corresponds to 75% of the largest infeed onto the system. At present, the

largest infeed is 422 MW (the 500 MW HVDC interconnection to Scotland is operated

with a maximum limit of 400 MW for system security reasons i.e. to limit the size

of the largest infeed), thus making the primary reserve requirement 317 MW. The

availability of primary reserve to meet this requirement is divided such that the ESB

and NIE systems provide 67% (211 MW) and 33% (105 MW) respectively. Sources of

POR include spinning reserve from generating units online and static reserve, such as

interruptible load. Static reserve consists of blocks of reserve that are available almost

instantaneously when tripped by the system frequency falling below the predetermined

frequency setting of each block. Interruptible load is a form of static reserve, whereby

certain load on the power system has an agreement with the SO that some or all of

the load may be tripped during certain hours when the frequency falls below 49.3 Hz.

The proportion of the POR provided by spinning and static reserve sources varies with

time of day. The contribution of the pumped storage station to POR depends on the

operational mode in which it is running, as described later in Section 2.2.2.

2.2 Modelling the Ireland Power System.

The dynamic model of the Ireland system used in this thesis is based on two previous

models (OSullivan, 1996; Fox et al., 1989), with considerable enhancements introduced.

An emergency reserve model of the ESB electricity system circa 1995 was developed

by OSullivan (1996). The objective of this single busbar model was to accurately

predict the system frequency following a contingency, by simulating the primary reserve

response of the system. Installed generators are represented using low order models,

and include dynamics for prime mover, turbine and governor valve characteristics where

appropriate. A low order model, derived based on consideration of resistive and motor

loads, is used to represent the system load. A similar single busbar model of the isolated

NIE system circa 1989 was applied in Fox et al. (1989) for the evaluation of emergency

load shedding schemes.


The present Ireland electricity system has evolved and developed from the ESB and NIE

systems represented in OSullivan (1996) and Fox et al. (1989) respectively. A sizeable

growth in system load has occured and new generating plants have been introduced onto

the system and older plants decommissioned and removed. In particular, proportions

of both combined cycle gas turbines and wind generation have increased significantly,

and are predicted to comprise increasingly large proportions of system generation mix

in the future, as illustrated in Fig. 2.1.

The dynamic model representative of the Ireland electricity system is developed based

on OSullivan (1996), and also Fox et al. (1989), augmented with more detailed and

additional models where necessary. Each generating unit on the Ireland system is

individually modelled, with the exception of wind, small hydro and other generators

subject to a de minimis level of 10 MW. The details of the individual unit models are

given in Section 2.2.2. The load model is presented in Section 2.2.3, and an overview

of the entire Ireland model, with details of the connecting system and is presented in

Section 2.2.4. The development and tuning of the Ireland electricity system model

was carried out in collaboration with Dr. Damian and Flynn and Julia Ritchie of the

Queens University of Belfast.

2.2.1 Assumptions of the Model

A fundamental assumption made in the development of the system model is that fre-

quency is uniform throughout the system. This assumption is made on the basis that

the electricity system of Ireland is tightly meshed and electrically short, with the rel-

ative impedances between nodes quite small. Therefore, during a major contingency

involving the loss of significant generation, the system will remain in synchronism and

the frequency deviation will be very similar at all points on the system. This is borne

out by system studies carried out by the Transmission System Operators and by fre-

quency measurements during major events with frequency deviations of up to 0.8 Hz

during sudden generation deficits. The system is designed and operated so that in

the event of the loss of the largest infeed there should be no consequential events (i.e.

the protection does not trip out any other devices, for example lines). Historical data

shows that the loss of a transmission line has never occurred during a loss of generation

event. In particular, during a major loss of generation there are noticeable changes in

power flow across the AC lines between the NIE and ESB systems, due to the shar-


ing of reserve (DETINI, 2003; ESBNG, 2005c). These rapidly changing power flows

have never caused any additional tripping of lines. Therefore, for frequency control

studies on the Ireland electricity system, a uniform system frequency is assumed and

a single busbar model has traditionally been employed (OSullivan, 1996; OSullivan

and OMalley, 1996; OSullivan et al., 1999) and is appropriate for this study. It is

also assumed that changes in voltage have negligible effect on real power balance on

the system. In the event of a loss of generation on the system, voltage deviations will

occur around the site of the contingency. However, these effects are only local and will

not manifest themselves globally (OSullivan, 1996).

The objective of the development of the Ireland electricity system model is to examine

the effect of evolving plant mix on frequency control during a frequency event. The

timescale of interest is the time immediately prior to and the first 20 seconds of a

frequency disturbance event. For the purpose of short-term frequency control, as of

interest in the system model, dynamics outside the timescale of interest are neglected.

In addition, the system is assumed to be in steady state at nominal frequency prior to

any frequency event.

On the Ireland electricity system, if the frequency falls below 49.7 Hz (99.4% of nom-

inal), it is deemed to be a significant frequency disturbance event (ESBNG, 2005b).

Below 47.5 Hz (95% of nominal), the system will lose synchronism as generating units

and load trip off the system. The system model is designed for relatively small fre-

quency deviations of less than 3% ( 1.5 Hz). Therefore, system frequency changes

can be assumed to be small with respect to nominal system frequency.

2.2.2 Generation

The majority of electricity generating units consist of a prime mover to produce me-

chanical energy and a generator to convert this mechanical energy into electrical energy

suitable for supply to the power system (Machowski et al., 1997). A variety of energy

resources may be used to impart energy to the prime mover, resulting in a number

of different prime movers types. These can be broadly categorised as steam turbines,

combustion turbines and turbines which are driven directly by the energy resource,

such as hydroelectric turbines, wind turbines and tidal energy turbines.


The energy resources associated with steam units are generally fossil fuels and nu-

clear fission. The energy from combustion of the fuel (or heat energy resulting from

the nuclear fission) is used to produce steam in a boiler, which drives the steam tur-

bine. Combustion turbines, alternatively, use the exhaust gases from the combustion

reaction to drive the prime mover. Hydroelectric turbines can have many different con-

figurations, but water is used to drive the prime mover in all cases. Similarly, energy

from wind and tides can be extracted in appropriately designed turbines to produce

mechanical energy to convert into electrical energy in the generator.

Steam Units

Fossil fuelled steam units have been in use for over 120 years and can have a number of

different configurations. However, the basic principle remains the same: the combustion

of the fuel in the furnace heats the water in the boiler to produce steam, which is used

to drive the steam turbine. Thus, the working fluid for a steam unit is water. The

rotational energy of the steam turbine is then converted to electrical energy in the

synchronous generator.

The boiler can be either drum or once through configuration. In a drum boiler, water

enters the waterwalls from the reservoir of water in the drum. Heat energy from the

fuel combustion process is transferred through conduction, convection and radiation to

the water in the waterwalls. The resultant steam and water mixture then re-enters the

drum. In the drum, steam separates from water and travels to the steam turbine, via

the superheater, with steam flowrate dependent on the pressure differential between

drum and turbine. The pressure in the drum is dependent on the fuel firing rate, and

steam flowrate can therefore be controlled by adjusting the firing rate. Superheated

steam temperature is controlled by means of spray water attemperation (Flynn, 2003).

Drum boilers may use either natural or forced circulation, but natural circulation is

the more common configuration. Although higher pressure, and thus efficiency, can be

achieved through the use of pumps, it is generally only viable in very large plants.

The once through boiler configuration contains no internal reservoir and the water is

forced through a continuous pipe to the steam turbine by means of pumping. As a

result, steam flowrate is determined by the boiler feed pump and steam temperature

is controlled by adjusting the fuel firing rate. Once through boilers are designed to


operate at supercritical temperatures, yielding higher efficiency. However, although

increased efficiency results in reduced operating costs, the increased installation costs

of such boilers generally make drum boilers more economically viable (Flynn, 2003).

Boiler dynamics are highly complex, and over long time frames, detailed models are

required to accurately capture dynamic behaviour. Complex models derived from phys-

ical principles have been developed (Chien et al., 1958; McDonald and Kwatny, 1970;

Kwan and Anderson, 1970; Flynn and OMalley, 1999) to capture the dynamics of the

boiler over different timescales. A low order nonlinear boiler model was developed in

IEEE (1973b). In this model, pressure and steam flowrate are defined as functions of

the energy input to the boiler and the turbine control valve area.

DeMello (1991) examined and justified the use of simplified boiler models (IEEE,

1973b) for power system modelling. Various simplified models, which captured the

essential nonlinear characteristics of the boiler, were compared to a detailed model

based on mass, volume and energy balance equations and found to be adequate for use

in power system dynamic performance studies. The simplified model of IEEE (1973b)

and DeMello (1991) was adopted for the emergency reserve model of OSullivan (1996),

and is employed in the Ireland system model of this thesis to model the boiler compo-

nent of the steam units on the Ireland system.

The boiler model is illustrated in the schematic of the steam turbine model in Fig. 2.2,

which also includes the steam turbine model and the governor model.

There are time delays in a boiler associated with the fuel dynamics and the transfer of

heat energy to the water in the waterwalls when generating steam. The time constant

for the fuel dynamics varies from 20 to 40 seconds depending on the fuel type in use.

The waterwall lag has a time constant of approximately 5 seconds. Due to the relatively

long time constant for the fuel dynamics in comparison with the time scale of interest

here, the heat energy, Q, can therefore be assumed constant. However, as the heat

energy Q remains constant, the waterwall lag component, a first order lag, may be

neglected. Therefore, steam generation mw is equal to the heat energy Q.

Pressure in the drum, PD, is proportional to the integral of the difference between the

steam generation mw (i.e. steam flowing into the drum) and the steam flowrate out of

the drum, m. The throttle pressure at the entrance to the steam turbine valve, PT , is

propotional to the integral of the difference between the steam flowrate from the drum,


Figure 2.2: Steam unit model (See text for details)

m and the steam flowrate exiting the valve into the steam turbine, ms. The non-linear

nature of the boiler process is due to the steam flowrate from the drum to the throttle,

which is proportional to the square root of the pressure difference between the two.

From the boiler, the steam enters the steam turbine, where the heat energy in the steam

is converted to rotational energy to turn the turbine. When a gas passes through

a nozzle, it expands converting heat energy into mechanical energy. Therefore, as

the steam expands through the stages of the steam turbine blades, temperature and

pressure drop as the energy is imparted to the rotating turbine.

A model which can represent both reheat and non-reheat turbine systems is presented

in IEEE (1973a). This model, also used in IEEE (1991) and OSullivan (1996), is

employed to model the steam turbine component of the steam units in this thesis, as

illustrated in Fig. 2.2.

The steam flow entering from the boiler, ms, directly determines the power generated

in the turbine, with appropriate time delays incorporated. In a reheat steam turbine,

three time delays are required. The time delay for transport of steam from the boiler

to the first turbine stage and also the conversion of steam to rotational energy in the

first or high pressure turbine stage is represented using a first order lag with a time


constant TCH . The time delay due to the reheater and conversion of heat energy to

rotational energy in the intermediate stage is captured by the first order lag with time

constant TRH . Finally, the transport delay to the final or low pressure turbine stage as

well as the conversion of heat to rotational energy in this stage is captured by the a first

order lag with time constant TCO. The fractions of the total power output generated

at each stage are represented by FHP , FIP and FLP . A non-reheat unit will result in

all power generation coming from the high pressure stage and therefore FIP and FLP ,

the fractions of the total power generated in intermediate and low pressure stages of

the steam turbine, will be zero.

All dispatchable generating units on the Ireland system are fitted with droop governors

and required by regulations (ESBNG, 2005b; SONI, 2003a) to have a droop setting of

4%. The governor model used for the steam turbine units is the simplified speed

governor of Elgerd (1982), and is illustrated in Fig. 2.2. Using the difference between

actual and nominal frequency as input, the signal to the control valve is determined,

which is proportional to the inverse of the droop, Rd. A time delay with time constant

Ts due to the action of the hydraulics associated with the turbine valves is incorporated,

along with maximum and minimum limits (Pmax and Pmin) to maintain the valve area

within actual limits.

Open Cycle Gas Turbine Units

In the open cycle gas turbine, the working fluid is air. Air at atmospheric conditions

enters the compressor, where energy is imparted to the air from the spinning compressor

stages. On exiting the compressor, the air enters the combustion chamber where fuel is

added and combustion occurs, resulting in the conversion of chemical energy in the fuel

into heat energy. The hot gases produced by the combustion process then enter the

gas turbine under high pressure and are expanded as they pass through the different

turbine stages, converting the heat energy of the gases into rotational energy of the

gas turbine. The gas turbine, compressor and generator rotate on a single shaft. The

mechanical energy produced by the turbine, less the mechanical energy required by the

compressor, is the net mechanical energy and this is converted to electrical energy in

the synchronous generator.

Numerous models of gas turbines have been developed, with varying degrees of com-


plexity and detail (Rowen, 1983b; Hung, 1991; Cohen et al., 1996; Kunitomi et al.,

2001; Pourbeik, 2002). The dynamic model developed by Rowen (1983b) incorporates

the main dynamics of a gas turbine for a wide range of operating speeds (95 - 107%)

and conditions, and is suitable for use in power system stability studies. As a result,

this model is used as the basis for many gas turbine and combined cycle gas turbine

modelling applications (Bagnasco et al., 1998; Kunitomi et al., 2001; Lalor et al., 2005).

The model developed in Rowen (1983b) includes the relationships between pertinent

gas turbine components and also the control systems for speed, temperature and ac-

celeration in addition to maximum and minimum fuel limits. Further simplifications

of the model are also outlined.

At the time of development of the emergency reserve model (OSullivan, 1996), a num-

ber of OCGTs existed on the ESB system. However, due to an absence of data for any

gas turbines during frequency events, identification of the dynamic parameters for the

gas turbine model of Rowen (1983b) was not possible (OSullivan, 1996). As a result,

a simple ramp based model was implemented, using the approximate reserve charac-

teristics supplied by the system operator to provide limited identification (OSullivan,

1996).

For the Ireland system model developed here, OCGT generating units are explicitly

modelled, using a model adapted from that of Rowen (1983b). The OCGT model

structure is illustrated in Fig. 2.3.

As acceleration control generally only comes into play during start-up and shut-down,

the acceleration controller is neglected in this model, due to the assumption that the

model is initially generating in steady state. The output from the speed and temper-

ature controllers feeds into a minimum selector, where the lower of the two signals

determines the fuel flow. Under normal operating conditions, the fuel flow is under

the control of the speed controller (the governor). The speed controller consists of a

simple droop governor. The temperature control loop compares the measured temper-

ature of the exhaust gases, Txm, to the rated exhaust temperature, Tr. If measured

exhaust temperature exceeds rated exhaust temperature, the temperature controller

signal falls below unity, and the temperature controller takes over the fuel flow control.

The exhaust temperature Tx is calculated using the equation (2.1):


Figure 2.3: Open cycle gas turbine model (See text for details)

Tx = Tr 700 (1Wf) + 550 (1N) (2.1)

where Wf is the gas turbine fuel flow (per unit) and N is the system speed (per unit).

Power output is the product of the torque and the system speed, where the torque

produced by the gas turbine is determined by the equation (2.2):

Torque = 1.3 (Wf 0.23) + 0.5 (1N

Nref) (2.2)

where Nref is the reference system speed (per unit).

Combined Cycle Gas Turbine Units

Combined cycle gas turbines fuse the technologies of both steam and gas turbine units,

resulting in a unit capable higher efficiency than either of the two individual compo-

nents. CCGTs are not included in the emergency reserve model of OSullivan (1996).


However, due to a significant increase in CCGT generation on the ESB system, these

units comprise a large proportion of total generating capacity. The details of the

CCGT model structure used for the system model in this thesis, together with the

CCGT model tuning and validation methodology are given in Chapter 3, where the

impact of CCGT short term dynamics on frequency control is studied.

Hydroelectric Units

Hydroelectric generation uses the potential energy contained in water moving from a

higher to a lower height to turn a turbine. Thus the potential energy is converted into

kinetic or rotational energy of the turbine, which in turn is connected to an electric

generator where kinetic energy is converted to electrical energy. There are three prin-

cipal forms of hydro-turbines available and choice of turbine will depend on both the

potential energy or head of the water supply and also the volume of water available.

The three types are the Francis turbine, the Kaplin turbine and the Pelton wheel (Kun-

dur, 1994). Both Francis and Kaplin hydraulic turbines are reaction turbines, relying

on the weight of the water column to react against blades of the rotating element of

the turbine, the runner. The runner is fully immersed in water and is enclosed in a

pressure casing. The pressure differences across the runner blades imposes lift forces,

which cause the runner to rotate. Francis turbines are the most widely used turbine

type and designed to operate under medium heads of water, while the Kaplan turbine

generally operates under lower heads of water with higher flow rates. Pelton wheels are

impulse type turbines where the runner is spinning in air and rotated by the impact of

a water jet on the blades. These are generally used only with high heads of water.

One distinctive property characteristic of hydroelectric generation is the initial drop in

power output that occurs when the opening of the intake gate is increased. This non-

minimum phase characteristic is caused by the inertia of the water and the momentary

reduction in head that occurs when the gate initially opens further, before the water

flow through the turbine increases again (Elgerd, 1982; OSullivan, 1996). Therefore

adequate representation of this phenomenon is required for accurate dynamic models

of hydroelectric generating units, in particular for frequency control.

The two hydro-turbine types used for generation on the Ireland system are Francis and

Kaplan hydraulic turbines (OSullivan, 1996; ESBNG, 2004). A number of different


models for hydraulic hydro-turbines and their speed controllers

Documents

Frequency Control on an Island Power System