TECHNICAL AND ECONOMIC ASPEC I S OF OPERATION OF THERMAL AND HYDRO POWER SYSTEMS

NTNU TRONDHEIM Norges tekmsk- naturvitenskapelige universitet Trondheim I\}£T - —*?(?(

Technical and economic aspects of operation of thermal and hydro power systems

by

Bj0rn Harald Bakken

A thesis submitted to

Norwegian University of Science and Technology Faculty of Electrical Engineering and Telecommunications Department of Electrical Power Engineering

in partial fulfilment of the requirements for the degree of Doktor Ingenipr

February 1997 DISCLAIMER

Portions of this document may be illegible in electronic image products. Images are produced from the best available original document. Corrections

Location Error Correction

Page 30, eq. (3.9) ^■Psw ~ Pu APsw = 0.05 pu Page 37, tables 3.1 and 3.2 Page 115, table 5.6 Primary reserve Primary res.+rel. Page 116, figures Primary reserve Primary res.+rel. 5.28 and 5.29 Page 176, figure A3.1 Am Am r pu

®0 ®Ar Page 187, figure A3.16: UMIN, UMAX

UMAX 10 = 11 MAX

IO = i1MAX‘UDV/UMAX

10 = I0X*•UDV/UMAX

I1MIN

IO = KUMIN'UDV

UMAX Figure A3.16 Voltage dependent current order limiter (VDCOL) [24]

Page 219, figure A6.3 Page 221, figure A6.5

l Acknowledgements

During the more than four years of work which have been used for this thesis, numerous people have given their valuable contributions in the form of com ­ ments, suggestions and answers to my ever persisting questions. It is impossible to mention all contributors by name, thus my general gratitude is meant for all of them.

However, there are some names whichshould be mentioned here:

Statnett SF for their financial support during several of my travels abroad,

the people at Hauptschaltleitung Brauweiler, RWE, Germany, for housing and guiding me for one week in the spring of 1994,

the people of Elektizitdtsgesellschaft Laufenburg, Switzerland, for housing and guiding me for 3 weeks in the autumn of 1994,

and finally, my supervisor Prof. Hans H. Faanes, my colleagues at the Dept, of Electrical Power Engineering, NTNU, and the students who have con ­ tributed to this work.

This book is dedicated to Mari and Margrethe, who made it all possible with their patience and co-operation, and to my mother, who never got to see it fin ­ ished.

Trondheim, February 1997

Bj0m Harald Bakken

l

Abstract

Following some years in the mid- and late 80 ’s with very high precipitation in the hydro power system of Norway, several projects for new HVDC connections between Norway and the thermal dominated power systems of Continental Europe were initiated, soon to be followed by similar Swedish and Danish projects. The possible alternatives for operation of these HVDC connections can be separated into four main levels on a time scale:

• Expansion planning - energy export : Contractual net energy export of hydro power from Norway to substitute new thermal power capacity in Europe. Time frame: Several years

• Pumped storage co-operation - energy exchange: Norwegian hydro power is exported during peak load hours, while surplus thermal power can be imported during off-peak hours. Time frame: Week/day

• Secondary control - spinning reserves: HVDC cable capacity is reserved for secondary control, substituting thermal spinning reserves. Time frame: Minutes

• Primary control - HVDC frequency control: The high controllability of the HVDC connection is utilized for frequency control, both to substitute thermal reserves and to improve the transient frequency characteristics of the receiving system. Time frame: Seconds

At present, there is no energy surplus in the Norwegian system, and the Norwe­ gian government does not accept net energy export agreements which might initi ­ ate construction of new hydro power capacity. According to present knowledge, all new agreements from Norway are based on the pumped storage principle.

Short-term co-operation in the seconds range (primary control) and in the min ­ utes range (secondary and tertiary control), are at present not considered as far as the author knows. Thus, the ambition of this study has been to analyse technical and economic aspects of primary and secondary control in hydro and thermal power systems. When studying different system characteristics, possible advan ­ tages and/or problems of this kind of co-operation can be identified. Note that the focus of this study is system operation and operational costs, and that investment costs are not considered.

m Abstract

The cost of providing primary control reserves in thermal power systems is esti­ mated to 1-3% of total production cost. Hydro power units, on the other hand, provide a very cheap primary reserve compared to thermal units, although spe ­ cific figures for cost of primary control reserve in hydro power units are not found in this work.

The HVDC connection can be used for primary control in either direction, but due to the economic motivation, only substitution of reserves in the thermal sys­ tem with reserves from the hydro system is examined. Utilizing the high control ­ lability of the HVDC connection, the transient characteristics of the receiving system are considerably improved, and an amount of thermal spinning reserve corresponding to the available HVDC capacity can be substituted, without caus­ ing unacceptable disturbances in any system.

Although this is both a technically and economically interesting alternative, it is probably not very realistic in the near future, as there is no tradition for trading primary control reserves in the European power systems today.

The alternative to sell secondary control reserves across the HVDC connections seems much more realistic. The cost of keeping spinning reserve for automatic secondary control in a thermal power system is estimated to 3-5% of total pro ­ duction cost. Thus, the possibility to purchase secondary control reserves from the hydro power system should be interesting, and it can be done without chang ­ ing the current automatic secondary control system on the continent.

Secondary control reserves are probably not competitive to the value of the peak load export (note that capacity investment costs are not considered), but during off-peak hours with ‘price-dependent energy exchange ’ the alternative of using at least part of the HVDC capacity as secondary control reserve for the thermal sys­ tem should be seriously considered.

Whether the present and future HVDC connections from Norway (or Sweden/ Denmark) are to be used for some control purposes, or just operated according to the pumped storage principle, the present manual secondary control in the Nordel power system will probably be insufficient to handle the increased operational strain on the system. Some additional automatic control functions will have to be introduced.

The concept of automatic secondary control is treated in this study both theoreti ­ cally and by simulations to gain a better understanding of the basic concepts and the manner of operation. Analyses made on a simplified model of the Nordel power system show that there are no special technical difficulties by introducing automatic secondary control in the Nordel system. Both a general load-frequency

IV Abstract control (LFC) scheme, and a ramp controller dedicated to follow HVDC connec ­ tions have been implemented and tested with satisfactory result in the simulation model.

The general LFC scheme can be used both to completely substitute the current manual secondary control or as a supplement to the current system. The dedi­ cated ramp following controller, on the other hand, can only be used as a supple ­ ment to the current system.

A main problem which remains to be solved whether an automatic secondary control scheme is introduced or not, seems to be the question of providing suffi­ cient reserves and to which units these should be allocated.

v

Contents

2. Introduction...... 1 2.1 General ...... 1 2.2 Present situation ...... 2 2.2.1 Existing connections ...... 3 2.2.2 Planned new connections from Norway ...... 3 2.3 Different co-operation levels...... 6 2.4 Definitions ...... 7 2.5 Scope and layout of the work...... 9

2. The European power transmission systems...... 13 2.1 Overview...... 13 2.2 The synchronous Nordel grid...... 14 2.2.1 Denmark ...... 15 2.2.2 Finland ...... 16 2.2.3 Norway ...... 17 2.2.4 Sweden ...... 18 2.3 The synchronous UCPTE grid...... 18 2.3.1 Germany ...... 21 2.3.2 Holland ...... 21 2.3.3 Switzerland ...... 22 2.3.4 Other UCPTE participants ...... 23 2.4 The national power system of United Kingdom ...... 24

3. High voltage DC connection with primary control...... 25 3.1 Overview...... 25 3.2 Constant load on the HVDC connection ...... 26 3.3 Frequency controller at the inverter terminal ...... 28 3.3.1 Case a) 250 MW available capacity ...... 31 3.3.2 Case b) 400 MW available capacity ...... 34 3.3.3 Case c) 100 MW available capacity ...... 36 3.3.4 Comparison of different alternatives ...... 36 3.4 Effects on the hydro power system...... 40 3.4.1 Basic model ...... 40 3.4.2 SVC equipment in hydro system...... 43 3.5 Enlarged systems...... 43 3.6 Additional remarks...... 46 3.6.1 UCPTE frequency deviations ...... 47

vii Contents

3.6.2 Operational limitations of the HVDC connections ...... 48 3.6.3 Operating several HVDC connections in parallel ...... 49 3.7 Summary...... 49

4. Automatic secondary control...... 51 4.1 Basic principles of load-frequency control ...... 51 4.1.1 Area Control Error ...... 51 4.1.2 Load-frequency control ...... 54 4.2 Functional structures of load-frequency control ...... 58 4.3 7-area model of the Norwegian power system...... 59 4.3.1 Model construction and tuning ...... 60 4.3.2 Ramping domestic and HVDC load...... 61 4.4 Centralized load-frequency controller ...... 67 4.4.1 Present system...... 67 4.4.2 New connections in the next decade...... 72 4.5 Ramp following controller ...... 76 4.5.1 Controller layout ...... 76 4.5.2 Controller tuning ...... 78 4.5.3 Ramp following ability ...... 81 4.6 Additional system faults...... 83 4.7 Summary...... 84

5. Cost of spinning reserve in thermal power systems...... 87 5.1 Primary control in thermal power units ...... 87 5.1.1 Additional unit reserve costs ...... 87 5.1.2 Relocation costs ...... 92 5.2 10 unit test system...... 92 5.3 General spinning reserve requirements ...... 96 5.3.1 “Optimal ” dispatch of reserve...... 97 5.3.2 “Manual ” dispatch of reserve...... 100 5.4 Specific system reserve costs...... 102 5.4.1 Specific reserve costs at “optimal ” dispatch ...... 102 5.4.2 Specific reserve costs at “manual ” dispatch ...... 105 5.4.3 Daily average costs...... 106 5.4.4 Comparison of specific reserve costs...... 108 5.5 Example: System reserve costs according to UCPTE recommendations ...... 109 5.5.1 Primary control reserves...... 110 5.5.2 Secondary control reserves...... 113 5.6 Summary...... 118 Contents

6. Cost of spinning reserve in hydro power systems...... 121 6.1 Primary control reserve...... 121 6.2 Secondary control reserve...... 124 6.3 Summary...... 125

7. Summary and conclusions...... 127 7.1 Primary control ...... 127 7.2 Secondary control ...... 129 7.3 Conclusions ...... 130 7.4 Further work...... 131

References...... 133

Appendices

Al. Interconnected system reserve recommendations...... 143 Al.l UCPTE reserve recommendations ...... 143 Al.1.1 Primary control ...... 143 A 1.1.2 Secondary control ...... 145 Al.l.3 Tertiary control ...... 148 A 1.1.4 Time deviation ...... 150 Al.1.5 Start-uptime ...... 150 Al.1.6 Operation during frequency deviations ...... 150 A 1.2 Nordel reserve recommendations ...... 151 A 1.2.1 Primary control ...... 151 A 1.2.2 Secondary control ...... 153 Al.2.3 Tertiary control ...... 155 A 1.2.4 Time deviation ...... 155 A 1.2.5 Load and production shedding ...... 156

A2. Primary control in thermal power units...... 157 A2.1 Overview...... 157 A2.2 Overall unit control ...... 159 A2.3 Fossil fuelled steam power units ...... 160 A2.3.1 Methods to meet fast power demands ...... 160 A2.3.2 Operational comparison of different methods ...... 166 A2.3.3 Combined heat and power plant (CHP)...... 167 A2.4 Nuclear power plant ...... 168

IX Contents

A2.4.1 Pressurized Water Reactor (PWR)...... 168 A2.4.2 Boiling water reactor (BWR)...... 170 A2.4.3 Economic aspects ...... 171 A2.5 Gas turbine units ...... 172

A3. Standard SIMPOW components ...... 173 A3.1 Loads...... 173 A3.2 Synchronous machines ...... 174 A3.2.1 Synchronous machine models...... 174 A3.2.2 Equation of motion ...... 176 A3.2.3 Exciters...... 176 A3.2.4 Power system stabilizers ...... 177 A3.3 Turbines and governors ...... 178 A3.3.1 Steam turbines ...... 178 A3.3.2 Steam turbine governor ...... 180 A3.3.3 Hydro turbines ...... 180 A3.3.4 Hydro turbine governor ...... 182 A3.4 The HVDC system ...... 183 A3.4.1 AC/DC converter terminals ...... 183 A3.4.2 Control system...... 185 A3.5 SVC equipment ...... 190

A4. Basic theory of load-frequency control ...... 191 A4.1 Load-frequency control schemes ...... 191 A4.2 Frequency and power interchange ...... 193 A4.2.1 Centralized LFC...... 193 A4.2.2 Hierarchical LFC...... 195 A4.2.3 Controller failure in centralized LFC...... 196 A4.2.4 Insufficient reserves...... 200 A4.3 Time and energy deviations ...... 202

AS. Relation between HVDC gain and thermal spinning reserve...... 205 A5.1 Unconstrained operation ...... 205 A5.1.1 Reduction of thermal spinning reserve...... 205 A5.1.2 Reduction of stationary frequency deviation ...... 208 A5.2 Operation at current limit...... 210

A6. Hydraulic turbine models...... 211 A6.1 Basic hydrodynamic equations ...... 211 A6.1.1 Equation of motion ...... 211

x Contents

A6.1.2 Continuity equation ...... 212 A6.2 Travelling wave model...... 213 A6.3 Non-linear turbine model with inelastic water column ...... 217 A6.4 Further model improvements ...... 220 A6.4.1 Model with surge tank and inelastic water column ...... 220

xi 1. Introduction

1.1 General

During the last decade the electricity industry has undergone large changes; in particular in Norway but also several other places around the world. The trend towards a more liberalized and market oriented organization of the industry can more or less be found all over the world, but few, if any, countries have moved so fast from the old regime with regional monopolies and government control to a totally liberalized and open energy market as Norway. By the Energy Act which came into force on January 1 1992, the regional monopolies of large vertically integrated 1 electricity companies were cancelled. Instead, a debundling into sepa ­ rate financial areas for production, transmission and distribution was required. While the transmission part of the industry is still kept as a monopoly system with government control, the production and distribution sectors have to compete with each other in a mutual market. Also single end-user customers can operate directly in this electricity market, regardless of size.

The nature in Norway makes it possible to base the electricity production almost solely on hydro power, but this also makes the industry vulnerable to annual var­ iations in precipitation. Following some years in the mid- and late 80 ’s with very high precipitation, several projects for new connections between Norway and Continental Europe were initiated, soon to be followed by similar Swedish and Danish projects. Most European countries have little hydro power production, and the economically feasible alternatives to electricity production based on fos­ sil fuels are few. The possibility to buy cheap surplus hydro energy from Scandi ­ navia was interesting for the European utilities, while the large energy capacity of the thermal systems might provide a security against dry years in Scandinavia.

Simultaneously to the planning of these projects, also the new Energy Act was shaped, but it is difficult to say which is the cause and which is the result. The new connections which are now decided to build between Scandinavia and Con ­ tinental Europe would probably have been built sooner or later in any case, but the liberalization of the electricity industry in Norway and later also Sweden, speeded up the process.

1. When production, transmission and distribution of electricity, possibly down to end-users are owned and operated by a single electricity company, it is termed ‘Vertically integrated ’.

1 1. Introduction

1.2 Present situation

Status for existing and planned connections between Scandinavia and Continen ­ tal Europe as known in December 1996 are shown in figure 1.1. Due to the long distances all submarine connections have to be based on high voltage direct cur­ rent (HVDC) transmission. Total AC transmission capacity over land between some countries are also shown. To give a detailed description of each of the projects would be beyond the scope of this section, thus only a short presentation of the different projects will be given, based on references [58, 70].

Statkraft - ELSAM 2*250 MW + 500 MW

Statkraft - PreussenElektra tenfall - Imatran Voima 6-800 MW from 2003 i MW Concession given

Eurokraft - RWE/HEW 6-800 MW from 2002 Concession given Statnett/N. Hydro - England Planning Z Negotiations Vattenfall - ELSAM 290 + 380 MW

ELSAM - ELKRAFT 5-600 MW from 1997 (?)

V—_ VattenfVSv. Kraftnat - PPGC 600 MW from 1999

VattenfVSydkraft - PreussenE 600 MW from 1994 (450 MW temporarily)

ELKRAFT - VEAG from 1995 Statkraft - CPTE/SEP Planning / Negotiations Statkraft - SEP 6-800 MW from 2001 Concession given

Figure 1.1 Status for existing and planned connections between Scandina ­ vian and European power systems (December 1996) 1.2 Present situation

1.2.1 Existing connections

Today there are three HVDC cables between Norway and Jutland, Denmark - the Skagerrak connection - with a total capacity of 1 040 MW. The current exchange agreement between Statkraft and Elsam utilizes the full capacity of the connec ­ tion. However, this agreement expires in 1998, and the new agreement with Elsam utilizes only 600 MW of the transmission capacity to allow room for the new PreussenElektra agreement (see below). The new Elsam agreement consists of 1.5 TWh/year export from Norway, the rest of the capacity is to be used for ‘price dependent exchange ’ based on the difference between the Norwegian spot price and the marginal cost in the Elsam system.

Between Jutland and Sweden there are two cables with a total capacity of 670 MW - the Konti-Skan connection - and between Sweden and Finland there is one cable with 500 MW capacity - the Fenno-Skan connection. The agreements for the operation of these connections are not known.

In 1994 a new connection between Vattenfall and Sydkraft in Sweden and Preus­ senElektra in Germany with a transmission capacity of 600 MW, called Baltic Cable, was commissioned. At present, however, this connection is being oper ­ ated at reduced load due to problems with commissioning a new 400 kV over ­ head line past Liibeck. The existing 110 kV grid is not able to transfer the full HVDC transmission capacity.

Also, in 1995 a 600 MW connection between Elkraft in Den mark and VEAG in former East Germany was commissioned, called the Kontek cable. This connec ­ tion operates at full capacity. It is not known, however, to what extent the opera ­ tion of the Baltic and Kontek cables are co-ordinated.

Vattenfall and Svenska Kraftnat in Sweden have also made an agreement with PPGC in Poland for a cable which is expected to be commissioned already in 1998/1999.

1.2.2 Planned new connections from Norway

The first new HVDC connection from Norway to Continental Europe to be com­ missioned is the agreement between Statkraft and SEP in the Netherlands, the NorNed cable. The other Norwegian companies in the Norsk Krafteksport group 1 will also be included in this agreement.

1. Norsk Krafteksport A/S is a Norwegian electricity export group consisting of the companies Statkraft, BKK, Lyse, Oslo Energi, SKK, SFE, Sunnhordaland Kraftlag and VAE.

3 1. Introduction

The cable has a total capacity of 600 MW (with possible extension to 800 MW) and will be commissioned in 2001. The agreement includes 2.16 TWh/year of peak load exports from Norway and import to Norway of 0.6 TWh/year when required by one of the partners. The cable will also be used for short term price dependent exchange, giving a total exchange capacity for Norway of ±5 TWh/ year depending on the precipitation.

The next HVDC connection is the Eurokraft 1 - EuroStrom 2 agreement which will be commissioned in 2002, also with a capacity of 6-800 MW. This agreement consists of only 0.5 TWh/year peak load exports from Norway, however, while ±1.5 TWh is ‘agreed exchange ’.

The last connection which is to be commissioned in 2003, is the Statkraft - Preus- senElektra agreement, which consists of the 6-800 MW Viking cable plus addi­ tionally 400 MW transit capacity through the existing Skagerrak connection and the Danish grid. The 400 MW Danish transit will start already in 1998. The agreement consists of 2.0 TWh/year peak load exports from Norway, whi le the off-peak capacity is to be used for price dependent exchange.

The agreed utilization of the present and future HVDC connections between Nor­ way and Continental Europe is summarized in figure 1.2. Note that 400 MW of the capacity of the Skagerrak connection is reserved for the PreussenElektra agreement.

TWh/year Price dependent exchange Import rights Peak load exports

Skagerrak NorNed EuroStrom Viking

Figure 1.2 Utilization of HVDC connections between Norway and Continental Europe

Plans also exist for a second agreement with SEP including CPTE in Belgium, and a connection to England with possible multiterminal connection of the North

1. Eurokraft Norge AS is owned by 22 Norwegian electricity companies and will operate the agreement on their behalf. 2. EuroStrom is a German company owned 50/50 by RWE and HEW.

4 1.2 Present situation

Sea oil installations. If realized, the latter will be the longest of the HVDC con ­ nections from Norway. The present status and realism of these two projects are not known.

It is also interesting to note that although there has been a lot of focus on the con ­ struction of new HVDC connections between Scandinavia and Continental Europe these last years, the idea is absolutely not new. As can be seen in figure 1.3, the interconnection of the thermal power based power systems of Central Europe with hydro power from Scandinavia was suggested by the German engi ­ neer O. Oliven already in 1930.

GroRkraftlinien rd. 400 kV Erweiterungen Auszubauende Kraftquellen Wasserkraft Warmekraft (Steinkohle) Warmekraft (Braunkohle) Warmekraft (01)

Figure 1.3 Interconnected European power system suggested by O. Oliven 1930 [67]

The Norwegian Power Grid Company Statnett SF will be the constructor and owner of the Norwegian part of all HVDC connections from Norway, while the contractual partners (Statkraft and Eurokraft) rent the capacity on the cables for their exchange agreements.

5 1. Introduction

1.3 Different co-operation levels

The possible alternatives for co-operation between the hydro power system of Norway and the thermal dominated power systems of Continental Europe might be separated into four main levels on a time scale:

• Expansion planning - energy export The building of new HVDC connections between Norway and Central Europe for contractual net energy export will substitute new thermal power capacity in Europe. At present, there is no energy surplus in the Norwegian system, and the Norwegian government has not allowed agreements which might initiate the construction of new hydro power capacity. This might change, however, with the construction of Norwegian gas fired power plant in the near future. Timeframe'. Several years

• Pumped storage co-operation - energy exchange Norwegian hydro power is exported during peak load periods substituting expensive thermal units. During off-peak periods there is a price dependent energy exchange, which means that during a year with high precipitation in Norway surplus energy can be exported; during a year with low precipitation large amounts of energy can be imported to prevent an expensive energy defi­ cit. There is no strict demand of energy balance for a given time period. Timeframe: Week/day

This kind of flexible pumped storage co-operation is implemented in all the new HVDC agreements from Norway.

• Secondary control - spinning reserves The capacity of the HVDC connection (or a part of it) can be reserved as spin­ ning reserve for the Continental European systems, substituting expensive thermal reserves. This reserve is used whenever the need arises; fully auto­ mated as part of the secondary control of the thermal system, or by manual control actions as part of the tertiary control. Time frame: Minutes

• Primary control - HVDC frequency control This level utilizes the characteristics of the HVDC connection rather than the hydro-thermal combination. The thyristor based converters in an HVDC con ­ nection are very fast controllable compared to both hydro- and thermal power stations. By utilizing this speed for frequency control, the transient frequency characteristics of the receiving system might be considerably improved, and expensive thermal reserves can be substituted. Time frame: Seconds

6 1.4 Definitions

This study will focus on the last two co-operation levels; active power control in the seconds and minutes range. The high controllability of HVDC connections can be valuable in improving the dynamic performance of large power systems, and examples of control systems with different aims which are already in opera ­ tion around the world can be found in reference [69]. However, this kind of oper ­ ation has so far not been considered for the Norwegian - European connections. Even the existing agreements with exchange based only on the pumped storage principle might cause a need for changes in the current principles of system oper ­ ation.

1.4 Definitions

In international literature a lot of different terms and definitions are used to describe aspects of frequency and active power control. This section will define central concepts and terms used in this work. Terms regarding voltage and reac­ tive power control are not treated as they are beyond the scope of this work.

Primary control is fast control actions made by the speed governor due to fre­ quency deviations in the system to keep the instantaneous balance between pro ­ duction and consumption. The somewhat ambiguous term ‘frequency control ’ can also often be seen used for primary control.

Primary control reserve is the positive part of the primary control band, calcu­ lated from the operating point up to the maximum available primary control capacity. The term primary control reserve is applicable both for individual units, control areas and total interconnected systems.

Control area is a geographical area defined by the location of points of measure­ ment of power exchange on inter-regional and international tie-lines. These points of measurement are used by the secondary control.

Secondary control is slow control actions to re-establish nominal system fre­ quency and scheduled power interchanges after a deviation, and thus also re­ establish the used primary control reserves.

In the UCPTE system both primary control and secondary control are fully auto­ mated, while in the Nordel system the secondary control is handled manually.

Secondary control reserve is the positive part of the secondary control band, calculated from the operating point up to the maximum available secondary con ­ trol capacity. The part of the secondary control band which is already in use, is termed secondary control power.

7 1. Introduction

Tertiary control is all automatic or manual displacements of operating point of units taking part in secondary control in the UCPTE system, both to re-establish used secondary control reserves and to redispatch the secondary control reserve between different machines to obtain a more economic operation. Included in the tertiary control are also start-up (or stop) of fast startable units like gas turbines or hydro power units, manual change of operating point of not controlled units and changes in inter-regional exchanges.

Note that the question of economic operation is introduced first at the tertiary control level.

Tertiary control reserve is the reserve capacity available for automatically or manually re-establishing the secondary control reserve. This reserve is also termed minute reserve in the UCPTE system. The tertiary control reserve does not have to be located within the respective control area, but can be purchased from neighbouring areas.

Spinning reserve is, generally speaking, reserves that are ‘spinning ’, not stand ­ ing. In a thermal power system this would include both primary and secondary control reserves, but in a hydro power system as in Norway, only the primary control reserves would have to be spinning.

Load-frequency control (LFC) is slow automatic adjustments of unit operating point in the minute range to re-establish nominal system frequency and scheduled interchanges after a deviation. These adjustments are based on integration of the Area Control Error of the control area. LFC is the most common, but not the only, function of the automatic secondary control.

Area Control Error (ACE) is a measure of a control area’s deviation from agreed power interchange with it’s neighbours, compensated for the area’s acti­ vated primary control reserves.

Economic dispatch (ED) is most commonly used during operational planning, but is also applicable during operation as one of several functions of the tertiary control. ED during operation - which is the context in which ED will be used in this study - includes both manual and automatic adjustments of unit operating point to achieve a more optimal distribution of the momentary load.

Automatic generation control (AGC) is a term which is often used in a very imprecise and general way. Roughly speaking, the concept of AGC can include all automatic active power control actions except primary control.

Figure 1.4 shows the co-ordination between primary control and the other control functions sorting under the ‘AGC’ label. Whi le speed governor based primary

8 1.5 Scope and layout of the work control can be found in most units (unless they are operated with a frequency dead band), the AGC introduces a secondary feedback loop. Based on measure­ ments of system frequency and inter-area tie-line power, the AGC sends load change commands to selected units. Note also that if the ‘AGC’ block was replaced by a simple I- or Pi-controller, figure 1.4 would represent the load-fre­ quency control (LFC) scheme as treated in Chapter 4.

r f— s Tie-line power Electric power system • Loads AGC Frequency • Transmission grid v____ J • Generation v ______,______/ To selected units only Energy supply system (Steam/Water) T Load Speed Valves/ Turbine Generator changer governor Gates

Speed Figure 1.4 Co-ordination between AGC and primary control functions

1.5 Scope and layout of the work

During the years that have been used for this thesis there has been a development, part intentionally, part naturally, towards a rather operational oriented view. Thus, this study does not go very deep in theoretical analyses, but instead focuses on how the different systems are operated today, and presents some new alternatives of how they could be operated. Note that only frequency and active power con ­ trol is treated in this study, while topics related to voltage control are not consid ­ ered. Also, as the focus of this study is system operation and operational costs, investment costs are not considered.

The main analytical tool used in this study is time domain simulations with the SIMPOW program system [24]. The choice of using SIMPOW as main tool was made early to have the advantage of the great flexibility of a commercial simula­ tion program. However, the drawback has been the lack of detailed knowlegde of the models used in the program. The component library of SIMPOW is only doc­ umented on the block diagram level as shown in Appendix 3 Standard SIMPOW components. Thus, detailed equations for components like synchronous machines and HVDC converters as implemented in SIMPOW have not been available.

9 1. Introduction

The initial ambition was to make an analysis of both technical and economic aspects of primary and secondary control in hydro and thermal power systems related to the present and future HVDC connections between Norway and Conti ­ nental Europe. By the aid of such an analysis, system characteristics could be studied and possible advantages and/or problems of a closer co-operation in both the seconds and minutes range could be identified. However, this proved to be a too ambitious goal, and time has not allowed a full analysis of the two systems.

In the seconds range (primary control) a co-ordinated analysis have been made with a simulation model including a hydro power system, a thermal power sys­ tem and an HVDC connection, while in the minutes range (secondary control), simulations have been made for the Nordel (hydro) system only, omitting the thermal system and the HVDC connection itself.

The omission of the HVDC connection can be made without problems, as this system component is fast enough to be decoupled from the slow dynamics in the minutes range. The omission of the thermal system is done mainly because the amount of necessary modelling effort would have been too high compared to the usefulness of such a simulation. Long-term simulation of a thermal power system would have required full models of the different power plant, including boiler/ combustion chamber, firing system controls, heat transfer/steam system and tur­ bines. As the fully automated secondary control have been utilized successfully for many years in the UCPTE system, no basically new information could have been found from such simulations. On the other hand, automatic secondary con ­ trol is not used in the Nordel system, and constructing a simulation model to study how such control functions could aid the system operator in handling the increased strain on the system due to the new pumped storage agreements was a much more rewarding task.

On the economic side, the operational costs related to primary and secondary control are not very well known in any system. Especially from a Norwegian point of view, the operation of a thermal power system on the unit level proved to be very little known at the beginning of this work. Thus, a study of the opera ­ tional costs in a thermal system was important to increase the knowledge and understanding of the “counterpart ” of present and future HVDC agreements between Norway and UCPTE.

The costs related to primary and secondary control in hydro power systems, on the other hand, are certainly not less interesting, but can safely be assumed to be of a totally different scale than in the thermal system. Thus, the perhaps biggest disappointment in this work is that time has not allowed a more detailed study of also these costs except some general comments given in Chapter 6.

10 1.5 Scope and layout of the work

This thesis consists of three main parts, which can actually be read independently of each other. Chapter 2 gives a short introductory presentation of the present European power systems. As the first main chapter, Chapter 3 describes the technical analysis of primary control co-operation across an HVDC connection with detailed time domain simulations in the seconds range. The analyses are made with a simplified simulation model consisting of both a hydro power sys­ tem and a thermal power system interconnected with an HVDC link.

In Chapter 4 the concept of automatic secondary control is studied. Following some general studies of control principles and manner of operation, a simplified model of the Nordel power system is developed and verified, and then excitated with different load ramps due to the new HVDC connections from southern Nor­ way. Two different secondary control concepts are implemented to study how these might aid the system operator in handling the increased strain from the HVDC connections.

In Chapter 5 the economic aspects of primary and secondary control in thermal power systems are studied with the aid of an unit commitment program. Different cost elements are identified and several approaches are tried to quantify these costs.

Included in this thesis are also 6 appendices, which contain part supplementary information and part tutorial explanations. Especially Appendices 2, 4 and 6 are written mainly as tutorials for the readers who are not familiar with the respective themes.

Appendix 1 gives a summary of current interconnected system recommendations related to frequency and active power control. Appendix 2 describes different technical possibilities for provision of primary control reserves from thermal power plant, and is important for the understanding of the economic analyses made in Chapter 5. Appendix 3 is a presentation of standard system components available in the SIMPOW program system which is used for all simulations in this thesis. Appendix 4 presents some basic mathematical concepts regarding load-frequency control. In Appendix 5 equations for the relation between HVDC gain and thermal spinning reserve as used in Chapter 3, are deduced. Finally, Appendix 6 shows a deduction of non-linear hydraulic turbine models which are used in the simulations in Chapter 4.

11

2. The European power transmission systems

2.1 Overview

There are three major interconnected power systems in Europe today, each inte ­ grated and synchronized, operating in real time and in a coordinated way; the Scandinavian Nordel system, the western European UCPTE system (Union for the Coordination of Production and Transmission of Electricity) and the central- eastern European IPS system (Interconnected Power System), as shown in figure 2.1 (where only the central European part of the EPS system is shown).

Figure 2.1 The synchronous European power transmission systems

In addition to these three interconnected systems, there are also some isolated national systems like Ireland and United Kingdom, the latter being connected to the European continent via a 2160 MW HVDC connection. Albania is not a part of the UCPTE cooperation, but is synchronized to the UCPTE grid. However, due to the war in former Yugoslavia, Albania and Greece have been disconnected from the rest of the UCPTE system.

Jutland and Fyn in Denmark are also synchronized to the UCPTE grid, although Denmark is part of the Nordel co-operation.

13 2. The European power transmission systems

An HVDC cable between southern Italy and Greece and an AC connection between Spain and Morocco are in planning.

In September 1995, the so-called CENTREL countries (Poland, the Czech Republic, Slovakia and Hungary) together with the former East Germany was disconnected from IPS and synchronized to the UCPTE grid. This integration increased the total consumption of the UCPTE system with about 300 TWh or 20% [6 ].

Both the many HVDC projects between the Nordel and UCPTE systems and the integration of the CENTREL countries into UCPTE show that the process of inte ­ grating the different power systems in Europe into even bigger and stronger sys­ tems will continue.

2.2 The synchronous Nordel grid

Nordel, founded in 1963, is an advisory and recommendatory association which is entrusted with the task of contributing to an efficient electrical system in the Nordic countries, taking into account the conditions prevailing in the individual countries [1], The synchronous Nordel grid includes the national grids of Nor­ way, Sweden, Finland and Zeeland/Denmark. Iceland and Jutland/Denmark are also a part of the Nordel cooperation, although Iceland is of course an island grid, while Jutland is synchronously connected to the UCPTE grid.

The total electricity consumption in the Nordel system is about 350 TWh/year. Depending on the hydrological situation, 50-60% of the electricity production is based on hydro power, with more than half of this in Norway. About 25% is nuclear power (in Finland and Sweden only). Table 2.1 shows the electricity con ­ sumption and generation (TWh) in the synchronous Nordel grid (except Iceland) in 1994, while table 2.2 shows installed capacity (MW) and system peak load as measured the 3rd Wednesday of January.

The following section will give a short overview of the national systems in the Nordel cooperation, based mainly on references [1, 6, 75]. Note that the Nordel partners are in the middle of a dramatic change towards a more liberalized and market oriented organization of the electricity industry. This affects not only the operation of the system but also the organization and the structure of the industry. Thus, the following overview can only give a snapshot of the current situation (1996).

14 2.2 The synchronous Nordel grid

Generation (TWh) Consump- don Country Hydro Nuclear Thermal Wind TOTAL (TWh)

Denmark - - 36.9 1.1 38.0 33.2 Finland 11.7 18.3 32.1 - 62.1 68.2 Norway 112.9 - 0.6 - 113.5 113.6 Sweden 57.9 70.2 9.5 - 137.6 137.9 NORDEL 182.5 88.5 79.2 1.1 351.3 352.9

Table 2.1 Electricity generation and consumption in the synchronous Nordel grid in 1994 (except Iceland ) [1 ]

Generation (MW) Peak load (MW) Country Hydro Nuclear Thermal Wind TOTAL

Denmark 10 - 9 794 538 10 342 5 607 Finland 2 802 2 310 9 408 5 14 525 10 704 Norway 27 144 - 278 4 27 426 18 045 Sweden 16 502 10 040 8 457 38 35 037 23 248 NORDEL 46 458 12 350 27 937 585 87 330 57 604

Table 2.2 Installed production capacity compared to system peak load in the Nordel grid in 1994 (except Iceland ) [1 ]

2.2.1 Denmark

The electricity production in Denmark is based on conventional coal fired power plant, with some oil and gas fired plant plus 1.1 TWh wind power. A major part of the Danish power plant are combined heat and power (CHP) plant for district heating.

The eastern part of Denmark (Zeeland) is synchronously connected to the Nordel grid via an 1100 MW AC connection to Sweden. In 1995 a 600 MW HVDC con ­ nection to VEAG in former East Germany was commissioned, called the Kontek cable (see also figure 1.1). The coordination company Elkraft is owned by i/s Sjaellandske Kraftvaerker (with 80% of the generating capacity) and Kpbenhavns Belysningsvaesen, and is responsible for system operation and planning and inter ­ national exchanges.

15 2. The European power transmission systems

Western Denmark (Jutland and Fyn) is synchronously connected to the UCPTE grid via 3 AC connections with a total capacity of 1400 MW. There are also HVDC connections to Norway (1040 MW) and Sweden (670 MW). Local gener ­ ating companies are cooperating in the Elsam company responsible for system operation and planning and international exchanges.

Today there is no connection between the Elsam and Elkraft systems. However, at the request of the Danish parliament it is decided to build a 5-600 MW HVDC connection across Storebzelt which was originally planned to be commissioned already in 1997.

With its thermal based power system, Denmark is an ideal cooperation partner for the hydro power based systems of Norway and Sweden. During a year with high precipitation like in 1990, Denmark covered 38% of its total electricity con ­ sumption with imports from Norway (4.0 TWh) and Sweden (7.7 TWh). Note also that Sweden imported 11.9 TWh from Norway while exporting 7.7 TWh to Denmark.

During a year with very low precipitation like 1996, however, the possibilities for imports from Denmark have not been fully utilized. One main reason for this ‘deficit’ is that the Elsam system does not have enough capacity surplus for full export to both Norway and Sweden during heavy load, nor during the summer revision period. Analyses show an annual average export level to Norway of approximately 670 MW [74].

2.2.2 Finland

In Fin land 50% of the generating capacity is owned by the industry, 35% by the national company Imatran Voima OY (IVO) and 15% by local authorities. In 1994 the total electricity production of 62 TWh consisted of 19% hydro power, 30% nuclear power, 32% CHP and 19% conventional thermal power. The net import was 6.7 TWh, including 5.0 TWh from Russia. Finland had the highest growth in gross consumption in Nordel in 1994 with 4.2%.

There are two cooperating grid companies in Finland; the national grid company I VS (owned by I VO) and the industrial grid company TVO. The Finnish electric­ ity market was liberalized by the Electricity Market Act in 1995, and the electric­ ity companies have started the process of unbundling. A national spot market was created in 1996 with competition between large industrial customers and distri­ bution utilities. Finland is expected to join the mutual Norwegian-Swedish spot market in the future.

The thermal dominated Finnish power system is dimensioned by capacity, and is

16 2.2 The synchronous Nordel grid therefore an interesting cooperation partner for Norway. However, most of the generating capacity is nuclear power or CHP, which all have low marginal oper ­ ating costs. A closer cooperation between Finland and Norway might therefore not be economically feasible at the moment. On the other hand, there are strong objections in the Finnish Parliament against meeting increasing electricity demands with more nuclear power. Finland might therefore become a more inter ­ esting cooperation partner in the future.

2.2.3 Norway

In 1994 the gross electricity consumption in Norway was 108.3 TWh, an increase of 4% since 1993. In addition, the estimated consumption in electric boilers was 5.3 TWh. The total electricity production was 112.9 TWh hydro power plus 0.6 TWh thermal power. In 1994 Norway had a net import of only 84 GWh, while in 1993 the net export was 7.8 TWh.

In 1993 the third HVDC cable between Norway and Denmark was commis­ sioned, increasing the capacity to 1040 MW. As described in section 1.2.2 Planned new connections from Norway, there is now decided to build three more 6-800 MW HVDC cables between Norway and UCPTE to be commissioned in 2001,2002 and 2003, respectively.

The Energy Act which came into force on January 1 1992 caused dramatic changes in the Norwegian electricity industry. The distribution utilities lost then- regional electricity supply monopoly position. Any customer now has the right to purchase electricity from any supplier and have it delivered on the grid. A number of power brokers and traders have appeared as new market players.

In 1992 the Norwegian Parliament also opened for concession free export con ­ tracts with a duration of up to 5 years, with an upper limit of 5 TWh/year. How­ ever, there are strong political objections against new export agreements which might exert pressure towards building new hydro power plant or reducing the reliability of supply in the Norwegian electricity system, and the arrangement will not be renewed in 1998.

The former State Power Board (Statkraft) has been divided into two separate companies; The production company Statkraft SF which has taken over the long term agreements on power deliveries and interchanges concluded by the State with foreign power utilities, and the grid company Statnett SF which has been given the responsibility for both the technical and administrative handling of trade in electricity. Statnett SF is also given the responsibility for the short term power interchanges with foreign countries (5 TWh/year). The company will

17 2. The European power transmission systems however not become involved in the business deals, merely serve as a market place for the different players.

2.2.4 Sweden

In 1994 the total electricity production in the Swedish power system was 137.6 TWh, of which hydro power generated 42%, nuclear power 51%, CHP 6.3% and other thermal 0.6%. The gross electricity consumption was 133.8 TWh plus 4.1 TWh to electric boilers, an increase of only 0.6% since 1993. In 1994 Sweden had a net import of only 253 GWh, while in 1992 the amount was 2.2 TWh.

There are already HVDC connections between Sweden, Finland and Denmark. In 1994 a new 600 MW HVDC connection between Sweden and Germany was commissioned (the Baltic cable), but it is still unable to operate at full load. Plans also exist for an HVDC connection to Poland from 1999.

There are two large generating companies dominating the Swedish system: Vattenfall owned by the Swedish State, and Sydkraft which is privately-held. As in Norway, the national grid is owned and operated by a separate grid company, Svenska Kraftnat, and former vertically integrated companies have been unbun ­ dled. The joint Swedish-Norwegian power pool was opened January 1 1996.

About 50% of the Swedish generating capacity is hydro power, with similar hydrological variations as in Norway. Therefore, Sweden is not an ideal coopera ­ tion partner for Norway. Instead, as Sweden is positioned between the hydro power of Nordel and the thermal power of UCPTE, Sweden could make a high profit by forwarding excess hydro power to Germany. However, there is an ongo ­ ing discussion about the future of the Swedish nuclear power. The structure of the Swedish electricity production might therefore change considerably in the future.

2.3 The synchronous UCPTE grid

The Union for Coordination of Production and Transmission of Electricity (UCPTE) was founded in 1951. It is an association whose members are chosen among the representatives of managers of electricity generation and transmission companies from Austria, Belgium, France, Germany, Greece, Holland, Italy, Luxembourg, Portugal, Spain, Switzerland, Slovenia, Croatia, Bosnia-Herze- govina and other regions of former Yugoslavia. From 1996 are also Poland, the Czech Republic, Slovakia and Hungary members of the UCPTE.

18 2.3 The synchronous UCPTE grid

Generation (TWh) Consump- don Country Conv. therm Nuclear Hydro TOTAL (TWh)

B 28.8 38.5 1.2 68.5 71.4 D 225.9 141.8 18.2 385.9 388.1 E 66.5 53.0 25.9 145.4 146.0 F 29.7 341.6 76.4 447.7 381.1

GR 31.1 - 2.8 33.9 34.1 I 173.0 - 47.0 220.0 253.4 SLO/HR 6.5 4.4 8.0 18.9 20.5 JUEL-EKC 26.7 - 14.4 41.1 40.3 L 0.5 - 0.7 1.2 4.8 ML 55.8 3.7 - 59.5 70.3 A 10.9 - 34.0 44.9 42.6 P 16.7 - 10.4 27.1 27.9 CH 1.1 23.0 39.6 63.7 50.5 UCPTE 673.2 606.1 278.6 1 557.8 1 531.0

Table 2.3 Electricity generation and consumption (TWh) in the UCPTE in 1994 [7],

The synchronous UCPTE grid is one of the world ’s largest interconnected power systems, with a production capacity which is now more than 400 GW. In 1994 the UCPTE countries produced 1558 TWh, of which 18% were hydro power, 39% nuclear power and 43% conventional thermal power [7]. The consumption was 1531 TWh, which is an increase of 1.7% compared to 1993. The sum of electricity exchanges between the UCPTE members including third countries reached 156 TWh in 1994. As mentioned above, Albania and Jutland/Fyn in Denmark are also synchronously connected to this system.

Total electricity generation and consumption (TWh) in the UCPTE system in 1994 is shown in table 2.3 while maximum generation capacity and winter peak load (MW) is shown in table 2.4. Note that although maximum capacity is more than 50% higher than the peak load, only 28.4 GW is counted as available sur­ plus capacity [7]. 2. The European power transmission systems

Generation (MW) Peak load (MW) Country Conv. therm Nuclear Hydro TOTAL

B 7 958 5 528 1407 14 893 11200 D 59 276 22 507 6 408 88 191 61 100 E 18 568 7 400 16 459 42 427 24 800 F 22 000 58 500 24 200 104 700 63 500 GR 5 403 - 2 522 7 925 5 600 I 44 500 - 19 700 64 200 42 000 SLO/HR 2 300 632 2 698 5 630 3 600 JUEL-EKC 8 063 - 5 151 13 214 7 300 L 197 - 1 124 1321 800 ML 14 539 505 - 15 044 10 800 A 5 066 - 10 556 15 622 7 400 P 3 862 - 3 759 7 621 4 700 CH 800 2 990 11760 15 550 8 600 UCPTE 192 532 98 062 105 744 396 338 251 400

Table 2.4 Maximum generation capacity (MW) compared with winter peak load in the UCPTE in 1994/95 [7],

The electricity industry of the UCPTE participants consists mainly of monopo ­ lies. In all countries except Germany and Switzerland the national electricity sup ­ ply is optimized before possible exchanges with neighbouring countries are decided. The electricity markets are mainly reserved for generating companies.

The UCPTE countries closest to the North Sea are the most interesting partners for a possible HVDC connection from Norway; Germany and Holland. Switzer­ land is also interesting, not as a cooperation partner, but because this country have an electricity production with a large amount of hydro power which is already used as pumped storage capacity together with the thermal based power systems in neighbouring countries.

This section gives a short summary of the characteristics of the national power systems of some of the UCPTE participants, based on references [6 , 7, 75].

20 2.3 The synchronous UCPTE grid

2.3.1 Germany

Germany is a very interesting market for Norwegian hydro power, both because it is the UCPTE member closest to Norway and because of the large part of con ­ ventional thermal power. In 1995, total demand for electricity in Germany (including former East Germany and Berlin) reached 492.5 TWh [75], and the country had a net import of 2.3 TWh. The amount of import is likely to increase in the near future, as demand is expected to rise faster than supply, and it has become increasingly difficult to attain permission for new generating capacity.

In Germany nine regional companies exchange electrical power with each other and with foreign countries without any preferences to German companies. These companies are organized in the Deutsche Verbundgesellschaft, DVG, and have in reality a monopoly on the main grid in their respective areas. They sell their elec­ tricity to 55 regional energy companies. Today, these regional companies and other local energy companies have little freedom of choice when buying electric­ ity. A possible liberalization of the German transmission grids will therefore be of great importance for the future electricity market.

The grid of the former East Germany, owned by VEAG and BEWAG (Berlin), was connected to the synchronous UCPTE grid in September 1995. Since the reunion, all nuclear power plant and several conventional thermal power plant in former East Germany have been closed down due to unsatisfactory technical standards.

As explained in section 1.2.2, Eurokraft is given concession for a 600 MW HVDC cable from Norway to HEW/RWE to be commissioned in 2002, while Statkraft SF is given concession for a deliverance of 1000 MW to PreussenEle- ktra AG, of which 400 MW will be transmitted through existing HVDC cables between Norway and Denmark and through the grid of Elsam from 1998. The final 600 MW will be transmitted via a new HVDC cable to be commissioned in 2003.

2.3.2 Holland

Holland is also an interesting future cooperation partner for Norway. However, the country already has contracts for import of excess nuclear power from France and Belgium, which has low marginal costs.

Holland is the greatest user of natural gas for electricity production of the UCPTE countries. In 1994, the country produced 59.5 TWh electrical energy, of which more than 50% came from gas fired power stations. In addition, the net import was 10.8 TWh. This amount is expected to rise towards the turn of the

21 2. The European power transmission systems century, after which it will start to fall due to commissioning of several new large CCGT plant.

Although natural gas is by far the dominating fuel in Holland, most of the Dutch power stations are capable of utilizing several kinds of fossil fuels, mainly gas or oil, but also gas/coal and oil/coal. This gives the flexibility to adjust to changing fuel prices.

There are four regional production companies in Holland, which deliver all their electricity production to the Dutch Electricity Generating Board (SEP), which is owned by these four companies. The four companies then buy from SEP the amount of electricity needed to supply their own regions. SEP owns the main electricity grid, co-ordinates generation and transmission for the whole country and has monopoly on imports and exports of electrical energy for general supply. SEP also buys most of the fuel for the power stations - from 1995 also directly from Norway.

About 35 local distribution companies, with additional own production capacity, buy electricity from the four regional companies. These local companies are cur­ rently being horizontally integrated into larger energy utilities delivering both electricity, gas and district heating. They have monopoly on energy distribution in their respective districts.

There is expected some liberalization of the Dutch electricity supply in the future, among others on the import monopoly of SEP, and introduction of open access to the Dutch grid. The role of SEP as a co-ordinator for 4 generating com­ panies might be replaced by one single national generation company to create a more powerful company against the possible threat from foreign companies in France and Germany.

2.3.3 Switzerland

Hydro power within the UCPTE area is already extensively used as pumped stor­ age capacity together with the thermal power capacity. As an illustration, on December 16 1992 at 03.00 Switzerland imported 1313 MW, and at 11.00 the same day, in addition to meeting increased domestic comsumption, the country exported 757 MW [6 ]. There is now, however, little unexploited hydro power left in the UCPTE area.

The Swiss electricity industry consists of more than 1000 production and distri­ bution utilities, of which 80% are owned or controlled by the cantons or munici ­ palities. The industry is dominated by 5 production companies which exchange electric power with each other and with foreign companies without any optimiza ­

22 2.3 The synchronous UCPTE grid tion of the national electricity supply. Substantial interconnection capacity exists with France, Germany and Italy and also with Austria.

Generally, there is a flow of imports from France and Germany (7.8 TWh and 6.1 TWh in 1994, respectively) and exports to Italy (19.1 TWh). This energy transit is highly profitable for the Swiss utilities, and the biggest and strongest compa ­ nies are the ones which own the international tie-lines. However, the transit also occupy a large part of the national transmission capacity and plans exist for a substantial expansion of the interconnection capacity, especially to France and Italy.

At present, Switzerland is a large net exporter of electrical energy (depending on the hydrological situation), with net export of 11.6 TWh in 1994. This amount is expected to be gradually reduced over the next years, due to both the moratorium on the construction of new nuclear power plant and requirements on minimum storage capacity for hydro power plant. As the country is not bound by EU direc­ tives, an opening of the Swiss electricity market is unlikely in the near future.

2.3.4 Other UCPTE participants

Belgium is after France the second greatest (relative) user of nuclear energy in Europe, with about 60% of the electricity production. Belgium has a close co­ operation with Holland, and is used as a transit country for electricity from France to Holland.

France has the greatest amount of nuclear power in Europe, giving the country relatively cheap and abundant electricity. Of a total production in 1994 of 447.7 TWh, about 75% were nuclear power. After Norway it is also the greatest hydro power nation in Europe. In 1994, France had a net export of 60.7 TWh, of which 16.9 TWh was exported to England via the HVDC connection.

The French power system has a generation capacity of about 100 GW and is organized as a vertically integrated state monopoly through the national company EdF which controls most generation, all transmission and virtually all distribu ­ tion, in addition to all imports and exports. EdF is likely to lose its near-monop ­ oly in generation in the near future, but will probably keep the monopoly over transmission and distribution.

23 2. The European power transmission systems

2.4 The national power system of United Kingdom

During the last years, plans for an HVDC connection from Norway to United Kingdom (UK) has been discussed on and off. A multiterminal HVDC connec ­ tion across the North Sea might also supply the oil installations of Ekofisk and neighbouring fields with hydro power instead of the gas turbine based electricity supply of today, giving important environmental benefits. In this section a short overview of the national power system of UK will be given, based on reference [75], but UK will not be further treated in this thesis.

The total electricity production in England, Wales and Scotland in 1994 was 303.9 TWh, of which 72% came from conventional steam power stations, 26% from nuclear power stations and 2% from hydro power stations. There is an ongoing change from coal and oil fired to new gas fired power stations.

Following the liberalization of the UK electricity industry in 1989, the industry in England and Wales is dominated by three producers and 12 regional distribution companies, while the transmission system is operated by the National Grid Com­ pany. In Scotland, however, there are two vertically integrated companies which handles both production, transmission and distribution.

Due to low transmission capacity between the Scottish and the English/Wales grids, a possible HVDC connection from Norway would have to be connected in the southern part of the system, making it the longest of the HVDC cable projects.

24 3. High voltage DC connection with primary control

In this chapter the possibility of using the HVDC connections between Norway and UCPTE for primary control is discussed. Basic principles are tested and examined, but it is not intended to do a detailed simulation of the Nordel and UCPTE systems. However, after initial simulations on a simple model system, the model is extended and adjusted to a capacity and a frequency response simi­ lar to the real systems to see how this might affect the conclusions. All simula­ tions are made with the SIMPOW program system [24].

One basic assumption of these simulations is that no additional equipment or extensive control strategies should be needed beyond what is already existing at the terminals today. There are assumed no additional investments like extra over ­ load capacity, filtering or reactive power compensation. Thus, special cases like additional faults, low short circuit capacity etc. are not tested.

3.1 Overview

Figure 3.1 shows an overview of the simplified model used in these simulations. The model includes a detailed representation of the 500 MW Skagerrak 3 DC cable [3] with phase compensators and capacitor banks, connecting a 12500 MVA hydro power system with two units and a 13130 MVA thermal power sys­ tem with three conventional units. The model is based on standard SIMPOW components, which are described in detail in Appendix 3.

The disturbances imposed on the thermal system are the connection of a load at the swing bus 7200, simulating a loss of production capacity in the “main ” power system. A loss of production of both 2.5% and 5% of the swing bus initial load is simulated. To get a clearer picture of the interaction between the HVDC connec ­ tion and the generating units, all loads are modelled as constant power loads.

As the interconnected UCPTE system had a total installed capacity of 396 GW in 1994, a loss of 2.5% initial production is an unlikely situation in normal opera ­ tion, a 5% loss even more so. A disturbance of this magnitude is introduced mainly to force the HVDC into saturation to see how this affects the frequency and voltages in the system. However, if the HVDC connection is feeding into a smaller grid already separated from the main UCPTE grid, disturbances of this magnitude might occur.

25 3. High voltage DC connection with primary control

H300 T200 T_SW 12.000 MVA 10.000 +j1.000 MVA 10.000+ J3.000 MVA 250 + j75 MVA H_SW 12.000 MVA 300 km 250 km 250 km

H200 H100 7300 T_500 H_C03 T_C03 500 MVA 50 km Skagerak 3 50 km ©—3D 124 km <3D—© H_500 200 + j20 MVA 500 MVA

H_PHC T_PHC 140 MVA 90 MVAr 140 MVA 90 MVAr 100 km

800 + j250 MVA TJB30 T400 630 MVA

Figure 3.1 Simplified model of a HVDC connection between hydro and thermal based power systems

These simulations are a continuation of basic work done in a Master thesis at The Dept, of Electrical Power Engineering, NTH, in 1993 [28].

3.2 Constant load on the HVDC connection

When the HVDC connection is operating at a constant load (constant current control mode), the transmission level will normally not change when a distur­ bance occurs in the thermal system (provided of course that the disturbance does not affect the HVDC connection directly). Figures 3.2 and 3.3 show basic simu­ lations of the frequency response of the thermal system with the HVDC connec ­ tion in constant current control mode at rated load 500 MW. The extra load at the swing bus T200 is connected after 0.5 seconds, simulating a loss of production capacity in the main power system.

The initial gain kt of the speed controllers of the thermal units are set to 20 (MVA base values are used instead of rated MW because all pu quantities in the simula­ tions are given on an MVA base), giving an initial frequency bias of the thermal system: K^h — 20 • = 5252 (MW/Hz) (3.1)

As all loads are modelled as frequency independent, the frequency bias is equal to the total system power-frequency characteristic X (MW/Hz). See also equation (4.1).

26 3.2 Constant load on the HVDC connection

A commonly used measure of the “strength ” of a power system is the Short Cir­ cuit Ratio SCR, defined as the ratio between the short circuit capacity SCC at the commutation bus and the rated DC power. For the thermal system:

Vs r SCC SCR = 7.8 (3.2) th ~ PN, DC N,DC

However, a more appropriate quantity for the strength of the system as seen from the HVDC terminals is the Effective Short Circuit Ratio ESCR, where the effects of AC side equipment at the converter terminal are taken into account (filters, shunt capacitors, synchronous compensators etc.) [17, 41]:

SCC-Qr ESCRh = —------= 7.3 (3.3) PN, DC

Traditionally, the AC system is classified as strong when ESCR > 5. With the present DC and AC system controls, however, the AC system is recommended classified as strong when ESCR > 3 [17].

Measurements of the short circuit capacity at the planned HVDC terminals in the UCPTE system are not available, but calculated short circuit currents on border nodes between Holland and Northern Germany ranges from 14.6 kA at 220 kV level to 24.4 kA at 380 kV level [45], indicating a short circuit ratio in the vicin ­ ity of the terminals of about 9 at 220 kV level and about 27 at 380 kV level.

In the interconnected UCPTE system the total power-frequency characteristic was about 30.000 MW/Hz [63] before the Centre! countries (Poland, the Czech Republic, Slovakia and Hungary) were synchronously connected in September 1995. The amount of transient and stationary frequency deviations observed in these initial simulations are therefore not directly applicable to the real UCPTE system. The influence of the actual size of the systems is examined in section 3.5.

A 2.5% loss of production causes a maximum frequency deviation of 0.348% at unit T_630, 1.42 seconds after the fault, as shown in figure 3.2. This corresponds to a transient minimum frequency of 49.83 Hz. The stationary frequency devia­ tion is 0.095%, corresponding to a frequency of 49.95 Hz.

If the loss of production is as large as 5% of the initial production, the maximum frequency deviation increases to 0.732% at unit Tj630 after 1.43 seconds, as shown in figure 3.3. This corresponds to a transient minimum frequency of 49.63 Hz. The stationary frequency deviation is in this case 0.190%, corresponding to a stationary frequency of 49.90 Hz. Some hunting between the swing bus T_SW and the two smaller units can also be observed.

27 3. High voltage DC connection with primary control

Synchr. speed (pu) 1.002

1.000

0.996

0.994 - T_SW T_500 T_630

0.992

Time (s)

Figure 3.2 Synchronous speed of thermal power units after loss of 2.5% initial production

Synchr. speed (pu)

1.000

0.996

T_SW T_500 T-600

0.992

Time (s)

Figure 3.3 Synchronous speed of thermal power units after loss of 5% initial production

The voltages in the thermal system are not greatly influenced by this disturbance. For the worst case (-5%), maximum voltage decrease is observed at node T200 with a transient dip of only 2.20 kV.

3.3 Frequency controller at the inverter terminal

When a frequency controller is applied to the inverter terminal of the HVDC con ­ nection, a choice has to be made on which principles this frequency controller should be operating. As the interconnected UCPTE system already is a very large and stable system with relatively small frequency deviations, it would probably not be commercially interesting to aid the system to reduce the frequency devia­

28 3.3 Frequency controller at the inverter terminal tions further. Instead, it might be more interesting for the UCPTE partners to be able to reduce the costs related to the provision of primary control reserves in their power plant.

Thus, it is decided that the HVDC connection should substitute thermal reserves so that the total frequency bias of the thermal system remains unchanged (5252 MW/Hz). In addition, all available capacity of the connection should be activated within the UCPTE recommendation for maximum stationary frequency deviation of 125 mHz1.

A simplified structure of the HVDC control system as implemented in SIMPOW is shown in figure 3.4. Normally, a constant reference value for the transmission level Pref is given to the Central controller, which maintains this level unaffected by normal frequency and voltage deviations in the AC systems. In these simula­ tions, a simple Power-frequency controller DCR is added to the control system, measuring the frequency of the thermal system and giving an additional current order to the Central Controller proportional to the frequency deviation (when the connection is operating in current control mode) [47]:

(pu) (3.4) where kDC - DCR controller gain (kA/pu Hz) IdN - rated DC current (kA) A/ - thermal system frequency deviation (pu).

Gamma (voltage) controller Current order controller/ Ay Current controller P

Central controller Pref CC

I Power-frequency /vininflar

Figure 3.4 Simplified structure of HVDC control system in SIMPOW [24]

1. Since these simulations were made, the UCPTE recommendation for maximum station­ ary frequency deviation is increased from 125 mHz [8] to 150 mHz [49].

29 3. High voltage DC connection with primary control

The HVDC control system is described in more detail in section A3.4 in Appen ­ dix 3, while the influence of the DCR controller on the HVDC transmission level is treated mathematically in Appendix 5.

The simulations are made for three pre-fault HVDC transmission levels: a) PpC = 250 MW (50%), making the available capacity PDC m = 250 MW b) P®DC = 100 MW (20%), making the available capacity PDC av = 400 MW c) Pq C = 400 MW (80%), reducing the available capacity to only 100 MW.

In the latter case, the HVDC substitutes only the reserves of the two smaller units without a calculated reduction of the swing bus reserve, making the total system frequency bias slightly higher.

The primary control reserves of the two smaller units T_500 and T_630 are set to zero in all simulations. By requiring all available HVDC capacity PDC fully activated within 0.125 Hz, the reserve of the swing bus T_SW is reduced in case a) and b) with the scaling factor Apsw to maintain the total frequency bias of the system:

r _ 12000 • kpsw+PDc,av Kth - - 5325 = 5252 MW/Hz (3.5) with the swing bus speed governor gain: , 1 ^PtPN _ ^PSW ^ ^ " 63025

The three pre-fault HVDC transmission levels give the following values for the swing bus speed governor gain ksw:

lca - = 250 MW => ^Psw = 04X339 pu => Ksw ~ 13.55 (3.7)

=> kb - 4c,.v = 400 MW => ~ 0-0214 pu KSW ~ 8.55 (3.8)

= 100 MW —^ ^Psw = ^ 0 pu II 20.0 (3.9)

In addition, k500 = k630 = 0 for the two smaller units in all simulations.

All results described in the following sections are summarized in tables 3.1 and 3.2 on page 37. The influence on the feeding hydro power system is treated in section 3.4.

30 3.3 Frequency controller at the inverter terminal

All simulations shown here are made with the HVDC connection in current con ­ trol mode (.Mode 0 of figure A3.18). Additional simulations with the connection in power control mode have also been made, but as both the sending and the receiving system are rather strong, the results were not influenced.

3.3.1 Case a) 250 MW available capacity

With an available capacity on the HVDC connection of 250 MW, or 50%, it is assumed that half of the capacity is reserved for primary control and half of the capacity is used for a more “standard ” transmission like contracted exports or the day-time export of a pumped storage agreement. In this case the HVDC connec ­ tion can respond equally to both a loss of production and loss of consumption in the thermal system.

According to equation (3.7), the swing bus speed governor gain ksw is now reduced to 13.55.

At a 2.5% loss of production, the gain kDC of the DCR controller necessary to maintain the frequency bias and hence the same stationary frequency deviation of 0.095% (figure 3.2), is found by trial-and-error to be 300. Although the HVDC connection is now adjusted primarily to supply stationary primary control reserves, figure 3.5 shows also a considerable improvement of the transient fre­ quency response. The maximum transient frequency deviation is reduced to 0.206% at unit T_500,1.22 sec. after the fault, corresponding to 49.90 Hz.

Synchr. speed (pu) 1.002

1.000

0.998

With HVDC Basic system 0.994 freq. control

0.992

Time (s)

Figure 3.5 Synchronous speed of thermal swing bus after loss of 2.5% initial production (ksw=13.55, lcDC=300)

The reason for the transient response improvement can be seen from figure 3.6 where the fast response of the HVDC connection is compared to the slower swing bus unit T_SW. (Note that the DC power is shown on the right axis.) The

31 3. High voltage DC connection with primary control

HVDC power transfer rises from 0.5 pu to 0.874 pu in 1.47 seconds, correspond ­ ing to a rise rate of 127.2 MW/s. The two smaller units TJ500 and T_630 are not responding to the disturbance, as their speed governor gains are set to zero.

Mech. torque (pu) DC Power (pu)

Figure 3.6 Mech. torque and DC power in thermal power system after loss of 2.5% initial production (ksw=13.55, kDC=300)

The fast increase of the DC power transfer level causes a corresponding increase in the reactive consumption of the inverter terminal, causing voltage dips in the thermal system. The additional reactive power has to be supplied from the phase compensator T_PHC and the thermal units, but the relatively fast response of the voltage controllers reduces the voltage stresses on the system. In this case with a 2.5% loss of initial production, the largest voltage dip is observed at the bus T100 (the HVDC connection bus), with a maximum voltage decrease of only 1.19% or 4.57 kV.

The stationary frequency deviation of the system can also be reduced by further increasing the gain of the DCR controller, thus increasing the response of the HVDC transmission. When the DCR controller gain is increased to 600, the sta­ tionary frequency deviation is reduced to 0.0693%, corresponding to 49.97 Hz, still without causing severe voltage problems in the thermal system. See also fig­ ure 3.12.

When simulating a 5% loss of production, the response of the DCR controller forces the HVDC connection into saturation. This is however handled by the existing current order controller COR, and does not require any additional protec ­ tive equipment.

The gain of the DCR controller necessary to maintain the frequency bias and hence the same stationary frequency deviation of 0.190% as shown in the initial case in figure 3.3, is found by trial-and-error to be 306. As shown in figure 3.7, also the transient frequency deviation is considerably reduced (to 0.518% after

32 3.3 Frequency controller at the inverter terminal

1.83 seconds at unit T_500, corresponding to 49.74 Hz). Only the speed of unit T_SW is shown in the figure, but there is still some hunting between the swing bus and the two smaller units.

Synch r. speed (pu) 1.002

1.000

fretco*d Basic system 0.994

0.992

Time (s)

Figure 3.7 Synchronous speed of thermal swing bus after loss of 5% initial pro - duction (ksw= 13.55, kDC=306)

The torque characteristics of figure 3.8 show the very fast response of the HVDC connection compared to the slower swing bus T_SW. The HVDC power transfer rises from 0.5 pu to about 0.97 pu in 0.68 seconds before current order limit UMAX is reached, corresponding to a maximum rise rate of about 345 MW/s.

Mech. torque (pu) DC power (pu)

T_SW

T_500 - 0.80

T_630

HVDC

0.80 rf t 0.40

Time (s)

Figure 3.8 Mech. torque and DC power in thermal power system after loss of 5% initial production (k^=13.55, kDc=306)

During the initial 235 MW active power transfer increase, the reactive power consumption of the inverter increases with about 160 MVAr or 0.32 pu. A drop of 7.6% or 26.7 kV in the DC voltage on the inverter side is also observed. How­ ever, the relatively fast response of the voltage controllers at the phase compensa ­ tor and the thermal units reduces the largest AC voltage dip to a maximum of

33 3. High voltage DC connection with primary control

3.18% or 12.23 kV, again observed at the HVDC connection bus T100.

Also in this case the stationary frequency deviation of the system can be reduced by increasing the gain of the DCR controller further.

For a loss of initial production of up to 5% of initial load, the high load change rate of the HVDC connection can be utilized both to reduce the need for spinning reserves in the thermal units and to reduce the transient frequency deviation after a disturbance. However, when the HVDC connection is driven fast into satura­ tion as shown in figure 3.8, the voltage deviations in the thermal system increases rapidly, which again increases the need for additional reactive compensating equipment. Another alternative is to reduce the rise ramp limit of the HVDC cur­ rent controller, but this of course also reduces the positive effects on the transient frequency characteristics.

3.3.2 Case b) 400 MW available capacity

With an available capacity on the HVDC connection of 400 MW, or 80%, it is assumed that most of the cable capacity is kept available as primary control reserves. The DCR controller of the HVDC connection can now give a maximum response only to a loss of production in the thermal system, and the response capability to a loss of consumption is only 100 MW.

Changing of the cable polarity within the primary control time range of 30 sec. is theoretically possible without special design of the converters [28]. In the case of the Skagerrak 3 connection used here (124 km submarine cable), a polarity change might take place in about 0.3 seconds without special equipment, while the new connections to Germany or Holland (approx. 600 km) would need 1.5 seconds. In any case, including polarity change in the primary control scheme cannot be recommended without much more detailed examinations of both the converter equipment and the system responses. This is however not a significant problem, as a loss of consumption which requires a reduced output from remain ­ ing units generally is looked upon as a much smaller problem for a thermal sys­ tem than a loss of production, which requires increased output from the remaining units [15].

According to equation (3.8), the swing bus speed governor gain ksw is now fur­ ther reduced to 8.55, and the DRC controller must have a much higher gain to maintain the initial frequency bias and hence the same stationary frequency devi­ ation. At a 2.5% loss of production, the necessary gain of the DCR controller is found to be 468. The maximum transient frequency deviation is now further reduced to 0.181% at the swing bus T_SW, 0.88 seconds after the fault, corre­ sponding to 49.91 Hz.

34 3.3 Frequency controller at the inverter terminal

The HVDC power transfer rises smoothly from 100 to 344.1 MW in 1.34 sec­ onds, corresponding to a rise rate of 182.2 MW/s. The largest voltage dip is observed at bus T100, with maximum voltage decrease of only 1.11% or 4.28 kV.

At a 5% loss of production, the gain of the SIMPOW DCR controller necessary to maintain the frequency bias and the same stationary frequency deviation of 0.190% (figure 3.3), is found to be 483. The maximum transient frequency devi­ ation is in this case further reduced to 0.460% at unit T_500, 1.13 sec. after the fault, corresponding to 49.77 Hz.

As shown in figure 3.9 the HVDC power transfer level now rises from 100 MW to about 470 MW in 0.80 seconds before current order limit UMAX is reached, corresponding to a rise rate of 462.5 MW/s. The next couple of seconds there is a slow, further increase due to the re-establishing of the AC voltage on the bus HI00 in the hydro system. Finally, there is a sharp drop in the transfer level after about 3.5 seconds as the frequency dependent current order falls below UMAX again, and the COR controller is reactivated.

Mech. torque (pu) DC power (pu)

T_SW

T_500

T_630

HVDC

Time(s)

Figure 3.9 Mech. torque and DC power in thermal power system after loss of 5% initial production (ksw=8.55, kDC=483 )

These changes in the HVDC transfer level do not have any significant effect on the voltages of the thermal system. The largest voltage dip is again observed at bus T100, with a maximum decrease of only 3.94% or 15.17 kV.

When the available capacity of the HVDC is increased from 250 to 400 MW there is no improvement in the stationary frequency response as the primary con ­ trol reserve of the swing bus is reduced accordingly. However, a reduction in the transient deviation due to the larger free capacity of the HVDC is observed.

35 3. High voltage DC connection with primary control

3.3.3 Case c) 100 MW available capacity

This alternative is included to see the effect of using a smaller part (20%) of the HVDC capacity for primary control, substituting only the primary control reserves of the two units closest to the inverter terminal. This is probably the most realistic way to use the future connections between Norway and UCPTE. The swing bus speed governor gain ksw is kept unchanged at a value of 20.

At a 2.5% loss of production, the gain of the DCR controller necessary to main ­ tain the initial stationary frequency deviation of 0.095%, is found to be 69. The maximum transient frequency deviation is now reduced only to 0.300% at unit TJ500, 1.42 seconds after the fault, corresponding to 49.85 Hz. Maximum volt ­ age deviation at bus T100 is only 0.51%, or 1.97 kV.

At a 5% loss of production, the gain of the DCR controller necessary to maintain the initial stationary frequency deviation of 0.190%, was found also to be 69. The maximum transient frequency deviation is reduced only to 0.637% at unit T_500, 1.43 sec. after the fault, corresponding to 49.68 Hz.

Maximum voltage deviation is for this case only 1.07%, or 4.12 kV, at bus TWO.

3.3.4 Comparison of different alternatives

Tables 3.1 and 3.2 show a summary of the previously described results with con ­ stant frequency bias in the thermal system, for loss of 2.5% and 5% initial pro ­ duction, respectively.

To be able to evaluate the advantages for the thermal system when using the HVDC connection for frequency control, the expression for the stationary ther ­ mal reserve reduction APfh (MW) as a function of HVDC frequency controller gain kDC is deduced in Appendix 5 and shown in equation (3.10):

u,DN A/y+APt; Apth = -« + O *DN Kth 'In

p0 i APf+APbloss u dn ~ (

Equation (3.10) is shown with dotted lines in figures 3.10 and 3.11 for the two faults. There are no significant differences in reduced thermal reserves depending on available capacity on the HVDC connection until it reaches current limit. The slight difference in slope is caused by the transmission losses. Due to the contin ­ uous 20% current overload capacity of the converters, the 100 MW alternative

36 3.3 Frequency controller at the inverter terminal actually supplies a reserve of 119 MW. Similarly, the 250 MW alternative which reaches saturation for a 5% loss of thermal production, supplies 258 MW reserve. See also equation (A5.24).

REFERENCE High load Medium Low load Const, load HVDC load HVDC HVDC HVDC (Case c) (Case a) (Case b)

0 100 250 400

ksw 20 20 13.55 8.55

kDC 0 69 300 468

A7m„(0 (Hz) 0.174 0.150 0.103 0.0905 (unit) (TJ530) (T_500) (71500) (T_SW) A/(oo) (Hz) 0.0475 0.0475 0.0475 0.0475 A [/„„(,) (kV) 1.07 1.97 4.57 4.28 (node) (7200) (7700) (7700) (T100)

APDC/At - 40 127 182 (MW/s)

Table 3.1 Summary of main results at loss of 2.5% initial production

REFERENCE High load Medium Low load Const, load HVDC load HVDC HVDC HVDC (Case c) (Case a) (Case b)

A7%c(MW) 0 100 250 400

ksw 20 20 13.55 8.55

kDC 0 69 306 483

4L«(f) (Hz) 0.366 0.319 0.259 0.230 (unit) (71630) (71500) (71500) (71500) A/(=) (Hz) 0.0950 0.0950 0.0950 0.0950

A [/.«(;) (kV) 2.20 4.12 12.23 15.17 (node) (7200) (7700) (7700) (TWO)

APDC/At - 95 345 462 (MW/s)

Table 3.2 Summary of main results at loss of 5% initial production

37 3. High voltage DC connection with primary control

To confirm the validity of equation (3.10) simulations are done for several values of kDc. In all simulations the thermal swing bus speed governor gain ksw is adjusted to give the same stationary frequency deviation as in the initial case without HVDC frequency control (0.095% and 0.190%, respectively). The sta­ tionary thermal reserve reduction APfh (MW) is then calculated from the approx ­ imate expression (3.11). As can be seen, the simulations are well in accordance with the calculated expression of (3.10).

A Pth = -A Kth • Af-fN = - Af.fN (MW) (3.11) Jn

dP th (MW)

Figure 3.10 Reduction of thermal reserves as function of DC frequency controller gain for 2.5% loss of production

dP th (MW)

Figure 3.11 Reduction of thermal reserves as function of DC frequency controller gain for 5% loss of production

Based on the initial simulations with constant frequency bias as given in tables 3.1 and 3.2, another series of simulations is done where only the HVDC fre­

38 3.3 Frequency controller at the inverter terminal quency controller gain kDC is changed. As the swing bus speed governor gain is kept constant, the contribution from the HVDC connection increases the total frequency bias of the system, thus reducing the stationary frequency deviation after the fault.

Figures 3.12 and 3.13 show a comparison of the three simulated cases for 2.5% and 5% loss of production, respectively. The points on the straight line are the initial simulations from tables 3.1 and 3.2, which are adjusted to the initial fre­ quency deviation without HVDC control, while the dotted lines show the change in stationary frequency deviation as kDC is changed.

df (%) -0.0600 No HVDC contr.

Avail, cap. HVDC dP = 100 MW -0.0800 X dP = 250 MW

-0.1000 dP = 400 MW z :/‘3-' □ /' -0.1200

-0.1400 / 0 100 200 300 400 500 600 700 DC frequency controller gain (k-DC)

Figure 3.12 Comparison of stationary frequency deviation for 2.5% loss of production

df(%)

Figure 3.13 Comparison of stationary frequency deviation for 5% loss of production

The relation between HVDC frequency controller gain kDC and stationary fre­ quency deviation A/ as shown by the dotted lines, is given in equation (3.12) (see

39 3. High voltage DC connection with primary control

Appendix 5):

pO -] * DC Afy+AfL, A/+ UDN (d r + d x) ■ —— • kDC + ksw ■ SN' sw — 1 DNnv _ A/ (3.12)

Figures 3.12 and 3.13 show that as long as the HVDC connection do not reach saturation, the reduction of stationary frequency deviation is independent of the available reserve of the HVDC connection. Thus, a reduction of stationary fre­ quency deviation to e.g. 0.075% (corresponding to 49.96 Hz) after loss of 2.5% production is possible whether the available reserve of the HVDC is 100, 250 or 400 MW.

From an operational point of view, while 80% of the cable capacity is utilized for a more standard exchange agreement and only 100 MW are reserved for stand-by frequency control reserves for the thermal system, it is still possible to obtain the desired reduction in stationary frequency deviation. Also, the maximum transient deviation is reduced considerably. From an economic point of view, however, case c) gives the least reduction of thermal spinning reserves and thus the least reduction in costs for the thermal system.

No final comparison is made of the transient characteristics in these simulations. The transient characteristics are highly dependent on the models used, and could differ considerably from a simulation using data for the real power systems con ­ nected to the Skagerrak HVDC link. The transient frequency deviations are slightly less the bigger the available HVDC capacity is.

3.4 Effects on the hydro power system

3.4.1 Basic model

The frequency bias and the effective short circuit ratio of the hydro power system model are:

SN,h _ 12000 + 500 * = ------a. = 6250 (MW/Hz) (3.13)

SCC-Qc ESCRh = —5------=5.5 (3 14) * N,DC\7 rxr'

In this case, the frequency bias is comparable to the minimum frequency bias rec­

40 3.4 Effects on the hydro power system ommendation of the NORDEL grid, and also the short circuit ratio is of the same magnitude as the SCR at the Norwegian side of the existing Skagerrak connec ­ tion (about 5 with no outages).

When using the HVDC connection for primary control in the thermal power sys­ tem, problems are transferred from the thermal system to the hydro power sys­ tem. The hydro system responds to the change in HVDC power transfer as if it was a disturbance in the hydro system, resulting is a corresponding frequency deviation:

(pu) (3.15) where APDC & - change of HVDC power transfer seen from the hydro system

As hydro power units generally respond slower than thermal units the first couple of seconds, the transient frequency response of the hydro system when aiding the thermal system, turns out to be worse than the initial frequency response of the thermal system without HVDC frequency control.

Figure 3.14 shows the synchronous speed of the hydro units compared to the thermal swing bus for case al: 2.5% disturbance with 250 MW prefault load on the HVDC connection. Note that the time scale is decreased to show the station ­ ary situation of the hydro power system. As previously seen in figure 3.5, the aided thermal system has a maximum transient frequency deviation of 0.206%, 1.22 seconds after the fault, and ends up with a stationary frequency deviation of 0.095%. The hydro system, however, has a maximum transient frequency devia­ tion of 0.584%, corresponding to 49.71 Hz, 4.28 sec. after the fault, but reaches a much smaller stationary deviation of 0.030%, corresponding to 49.98 Hz.

Synchr. speed (pu) 1.002 i------;------

1.000

0.998

0.996

0.994 T_SW H_SW H_500

0.992 0 10 20 30 40 50 60 Time (s)

Figure 3.14 Synchronous speed of hydro and thermal power units after loss of 2.5% initial thermal production

41 3. High voltage DC connection with primary control

The reason for the greater transient frequency deviation in the hydro system can be seen in figure 3.15, where the mechanical torque of the hydro units are com­ pared to the torque of the thermal swing bus and the HVDC power transfer. The time constants used in the hydro turbine models (typically 1.0 sec.) are greater than those of the steam turbines (typically 0.4 sec.), causing a much slower response in the hydro system. Also, while the thermal units respond to a step excitation, the response of the hydro units are delayed by the HVDC connection.

Mech. torque (pu) DC power (pu) 1.0

H_SW

H_500

T_SW 0.85 - HVDC

0.2

0.0

Time (s)

Figure 3.15 Mech. torque of hydro units compared with thermal swing bus torque and DC power transfer after loss of 2.5% thermal production

Also the voltages of the hydro system show a slightly larger transient deviation than the voltages of the thermal system. For this disturbance, the largest voltage dip of 1.95%, or 5.85 kV, is observed on the HI00 bus (the converter terminal).

Increasing the utilization of the HVDC connection of course increases the stresses on the hydro system. By increasing the HVDC frequency controller gain to 600, the maximum transient frequency deviation in the hydro system increases to 0.726%, corresponding to 49.64 Hz, and the stationary deviation increases to 0.044%, corresponding to 49.98 Hz. The maximum voltage deviation increases to 3.46%, or 10.37 kV, at bus H100.

Also, by increasing the available capacity of the HVDC connection to 400 MW, the maximum transient frequency deviation in the hydro system increases to 0.743%, corresponding to 49.63 Hz, and the stationary deviation increases slightly to 0.048%, corresponding to 49.98 Hz. The maximum voltage deviation is smaller than in the previous high gain case: 2.13%, or 6.38 kV, at bus H100.

When the disturbance is increased to 5% in the thermal system and the HVDC connection is driven into current limit, the consequences for the hydro system becomes worse. For case b2: 5% disturbance with 100 MW prefault load on the HVDC connection, the maximum frequency deviation of the hydro system is

42 3.5 Enlarged systems

I. 49%, 4.68 sec. after the fault, corresponding to 49.26 Hz. The stationary fre­ quency deviation is however not that large: 0.097%, corresponding to 49.95 Hz. The largest voltage deviation is again observed at bus HI00: 5.96% or 17.88 kV.

3.4.2 SVC equipment in hydro system

In connection with the operation of the third Skagerrak HVDC connection, it is already decided to install ±200 MVAr SVC equipment on the Norwegian side. An SVC installation of this magnitude is therefore included in the model on the hydro system bus HI00. Changing the parameters of the voltage controllers, or changing the controllers altogether, will also influence the voltage characteristics of the system.

For case al: 2.5% disturbance with 250 MW prefault HVDC load , the previous maximum voltage deviation on bus H100 is reduced to 0.56%, or 1.68 kV. Instead, maximum voltage deviation is now observed at bus H200 with 1.58%, or 4.73 kV. The frequency characteristics are not influenced by the SVC installation.

The advantages of the SVC installation become more apparent as the system is more stressed. For case b2: 5% disturbance with 100 MW prefault HVDC load, the maximum voltage deviation on bus H100 is reduced from 5.96% to 3.98%, or II. 95 kV. Because of the improved voltage characteristics on the HVDC terminal bus HI 00, there is a slightly faster increase in DC power transfer, causing a small reduction in maximum frequency deviations; from 0.460% to 0.455% for the thermal system; from 1.49% to 1.46% for the hydro system. There is no change in the stationary frequency deviations in either system.

3.5 Enlarged systems

The previous simulations have shown that if the HVDC connection is used for primary control in the receiving (thermal) system, frequency problems are trans ­ ferred to the sending (hydro) system. The consequences are for some cases worse in the sending system than in the receiving system where the fault originated. This is not an incitement to consider primary control as an interesting commer­ cial possibility.

However, in these simulations the two model systems are of similar size, while in reality the capacity of the UCPTE system is 4-5 times larger than the Nordel sys­ tem. The previous conclusions are therefore not directly applicable to the present and future Nordel - UCPTE connections.

To test how the size of the real systems would influence the situation, additional

43 3. High voltage DC connection with primary control simulations are done in which the hydro and thermal systems are enlarged to approximate the real systems ’ capacities during a heavy load period. As sending (hydro) system is used the 7-area model of the Norwegian power system which is developed and tuned in section 4.3, figure 4.12, while due to lack of data the receiving (thermal) system is simply extended with a large swing bus of 76 000 MVA and a giant “dummy” machine of 170 000 MVA which contributes to the rotating mass but which has a frequency controller gain set to zero. This enlarge ­ ment is illustrated in figure 3.16.

The frequency bias of the hydro system is found from table 4.1 to be 14 959 MW/ Hz, while the frequency bias of the enlarged thermal systems is:

N,th _ 2Q 76000 + 630 + 500 Kth ~ kth 30852 (MW/Hz) (3.16) fj 50 N

Since the extra generation capacity is balanced with corresponding extra load in the thermal system, the ESCR of the thermal system is not changed significantly. In the hydro system, the aggregated 7-area model generates a far too high ESCR of 19.5. However, this does not influence the frequency response of the model at normal operating conditions.

30 852 MW/Hz

”NORDEL" 14 959 MW/Hz

Figure 3.16 Enlarged hydro- and thermal systems

The response of the hydro model is verified in figure 4.13, while the thermal sys­ tem is adjusted to approximate recorded system responses to a casually chosen disturbance in the UCPTE system [44]. It is not intended to show the exact response of the real system, only to enlarge the model to show a response similar to the real system. The chosen UCPTE disturbance (900 MW) is then simulated

44 3.5 Enlarged systems with the HVDC connection substituting frequency control reserves in the same manner as described in section 3.3 (equations (3.5) - (3.9)).

As an illustration, figure 3.17 shows a comparison of synchronous speed of the two swing buses for the case of 250 MW free HVDC capacity. The gain of the HVDC frequency controller is now 298, nearly independent of system size. The thermal (“UCPTE”) system is so large that even a 900 MW fault causes only a very small frequency deviation (0.096% transient (49.95 Hz) and 0.058% station ­ ary (49.97 Hz)). Thus, the frequency dependent response of the HVDC connec ­ tion is sufficiently small that the hydro (“Nordel”) system has virtually no stationary frequency deviation at all.

Synchr. speed (pu) 1.001

1.000

0.999 -

0.998 -

0.997 -

0.996 - Hydro unit Thermal unit

0.995

Time (s)

Figure 3.17 Synchronous speed of hydro and thermal power units in enlarged system (kgy/=18.98, kj)C=298)

Of course, if the gain of the HVDC frequency controller is increased further, the consequences for the hydro system get worse. But even with 400 MW available capacity on the HVDC connection and kDC increased to 600, the maximum fre­ quency deviation of the hydro system is only 0.081% (49.96 Hz) and the station ­ ary deviation is 0.016% (49.99 Hz).

As shown in figures 3.18 and 3.19, equations (3.10) - (3.12) apply also to the enlarged systems.

Considering the large UCPTE system and the difference in size between the UCPTE and Nordel systems, there does not seem to be any operational problems related to utilizing the HVDC connection for frequency control for what might be considered “normal ” outages (1-2000 MW). However, if one fault has already occurred in the receiving thermal system causing a smaller separate grid, this might result in a situation similar to the initial simulations in this chapter, with sending and receiving systems of similar size and with reduced ESCR. If a sec­ ond and relatively large fault should then occur, the transient deviations of fre-

45 3. High voltage DC connection with primary control quency and voltage might become rather large in the sending hydro system. The stationary situation would however not be a problem as long as the HVDC capac ­ ity available for frequency control is kept smaller than the dimensioning fault in the Nordel system.

dP th (MW) Avail, cap. HVDC dP= 100 MW

dP = 250 MW

dP = 400 MW

200 300 400 500 DC frequency controller gain (k-DC)

Figure 3,18 Reduction of thermal reserves as function of HVDC frequency control ­ ler gain for enlarged systems.

df (%) -0.0520 No HVDC contr.

-0.0540 Avail, cap. HVDC dP = 100 MW X -0.0560 dP = 250 MW

-0.0580 ,a""' dP = 400 MW -3T □ .0' -0.0600

-0.0620

-0.0640 0 100 200 300 400 500 600 700 DC frequency controller gain (k-DC)

Figure 3.19 Comparison of stationary frequency deviation for enlarged systems

3.6 Additional remarks

The simulations described in the previous sections are highly simplified model simulations intended to give basic and general knowledge about the conse ­ quences of using an HVDC connection for frequency control purposes. Detailed simulations with more accurate system representation and data would in any case be necessary before the existing or future connections between Nordel and

46 3.6 Additional remarks

UCPTE could be used in this way. Especially the design and adjustment of the HVDC control scheme would need more detailed studies. Some additional remarks can also be made about angles which are not treated in detail here but which should be kept in mind for future studies.

3.6.1 UCPTE frequency deviations

As already mentioned, the interconnected UCPTE system has a power-frequency characteristic of about 30.000 MW/Hz. This was increased even further when the Centrel countries (Poland, the Czech Republic, Slovakia and Hungary) were included in September 1995. There is however a stochastic, lasting ripple in the frequency which should not be allowed to influence the operation of the HVDC connection. In figure 3.20 a rather old measurement from 1980 is shown [46], where the ripple stays within a band of ±25 mHz 73% of the time (6400 h/a). Introducing a deadband in the HVDC frequency controller scheme of ±25 - 50 mHz would filter the ripple and make sure that the HVDC connection only took part in frequency control at bigger outages.

Introducing a deadband DF in the DCR controller (see figure A3.19) would nec ­ essarily reduce the transient benefits for the thermal system. As a test, a dead­ band of 50 mHz is introduced in case al: 2.5% disturbance with 250 MW prefault load on the HVDC connection. This increases the maximum frequency deviation in the thermal system from 0.206% to 0.277%, corresponding to 49.86 Hz, while the maximum deviation in the hydro system decreases from 0.584% to 0.436%, corresponding to 49.78 Hz. Also the voltage deviation in both systems is decreased; for the hydro system from 5.85 kV to 4.82 kV, for the thermal system from 4.58 kV to 3.35 kV.

Relative duration (%)

-100 -50 0 50 100 df (mHz)

Figure 3.20 Example of duration of UCPTE frequency deviations [46]

47 3. High voltage DC connection with primary control

Introducing such a deadband in the DCR controller will however move the slope KF of the input filter away from origo, influencing also the stationary response of the HVDC connection.

3.6.2 Operational limitations of the HVDC connections

The existing HVDC connections between Nordel and Jutland, which is synchro ­ nously connected to the UCPTE system and also dominated by thermal produc ­ tion capacity, are used today in both directions for contingency reserve between 49.85 and 49.50 Hz, and as emergency support between 49.50 and 49.0 Hz and above 50.6 Hz [2, 60]. This is however not a continuous primary control function as described in this chapter but rather protective actions similar to load or pro ­ duction shedding. The reserve is activated at different frequency levels with dif­ ferent amount of MW with load change rates from 8 to 240 MW/s. It is not known whether these load change rates are set according to dynamic characteris ­ tics of the interconnected systems or the HVDC connections themselves. Some load changes are even termed “instantaneous ”, but does not imply a disconnec ­ tion of the HVDC connection. In none of the cases are change of cable polarity and thus a change of power flow direction assumed.

These reserve actions are most often triggered by frequency deviations in the Nordel grid. The thermal dominated UCPTE system is thus aiding the hydro dominated Nordel system with primary control reserves, an opposite situation of what is tested in these simulations.

To ensure a coordinated control of an HVDC connection the inverter and rectifier side have to communicate. The communication delay (via radio link) is however dominated by the component ’s response time, not the distance between the con ­ verters. Typical delay time for coordinated frequency control as simulated here could be 1-200 ms.

Studies show no indication of deterioration of converter devices (diodes, thyris ­ tors and GTO’s) with time [61]. Also, as activated primary reserves according to present recommendations should be re-established within 15 minutes (see figures A1.3 and A1.6), there are no significant thermal stresses in the cable. Operating an HVDC connection with continuous frequency control should thus not influ ­ ence the expected life time of the components.

48 3.7 Summary

3.6.3 Operating several HVDC connections in parallel

The previous simulations are made on a model system with only one HVDC con ­ nection. However, between the Nordel and UCPTE systems there are already several HVDC connections operating in parallel, and several more are planned (see figure 1.1). Additional simulations have therefore been made to see if there are any mutual influence between parallel connections.

The basic HVDC controller scheme reacts primarily to voltage fluctuations on the converter terminals, and is unresponsive to frequency deviations when not equipped with a special frequency controller as in the previous simulations. If one or more of parallel operating HVDC connections are equipped with a fre­ quency controller, they would react simultaneously to frequency deviations in the AC system, giving an added response. In the simplified model used in this study, they do not influence the connections which are not equipped with frequency controllers unless the converter terminals are close enough to react to voltage deviations caused by the controlling terminals.

However, when several HVDC connections are being operated in parallel, there is an increased danger of voltage instability if the ESCR is low and the imped ­ ance between the terminals is high [42]. Also, some danger of inter-area oscilla­ tions have been detected in connection with the Baltic and Kontek cables to Germany, and the Kontek cable is equipped with a special damping controller [43]. This possible problem will have to be further studied also for the new Nor­ wegian connections in the continuation of this work.

Also, if the contractual partners of one HVDC connection should want to use “their ” connection for frequency control, they would utilize the spinning reserves of the total Nordel system. Thus, the possible income from such an operational mode would have to be distributed between all parties providing spinning reserve.

3.7 Summary

In this chapter the possibility of using the HVDC connections between Nordel and UCPTE for primary control have been studied with model simulations. It is not intended to do a detailed modelling and simulation of the Nordel and UCPTE systems. One basic assumption has been that no additional equipment or exten­ sive control strategies should be needed beyond what is already existing at the terminals today. Thus, special cases like additional faults or low short circuit capacity are not studied.

49 3. High voltage DC connection with primary control

The simulations show that the high load change rate of an HVDC connection can be utilized both to reduce the transient frequency deviation after a fault and to reduce the need for spinning reserve in the thermal system. However, as hydro power units generally respond slower than thermal units the first couple of sec­ onds, the transient response after the disturbance in the thermal system might actually be magnified in the hydro system. On the other hand, the stationary response of the hydro system is rather small as only a part of the HVDC reserve capacity is still utilized in the stationary phase following the disturbance.

No exact limit for the utilization of the HVDC connection is found in these simu­ lations, as all simulations are within the stability limits of the systems with effec­ tive damping of transients. For the thermal system, none of the simulations cause problems indicating the need for investments. For the hydro system, however, an SVC is recommended at the converter terminal to reduce the voltage fluctuations. Care should also be taken to ensure that the frequency deviations stay within the limits for emergency load shedding.

The size of the two interconnected systems compared to the HVDC capacity used for primary control are crucial for the size of the deviations. Tests on an enlarged model show that the large UCPTE system handles quite large faults with small frequency deviations, thus reducing the strain on the sending (Nordel) system considerably.

In these simulations only supply of primary control reserves in the thermal sys­ tem from the hydro system is tested, as the economic benefits of reduced primary control reserves are much more interesting in the thermal system than in the hydro system (see chapter 5 Cost of spinning reserve in thermal power systems). However, protective actions due to frequency deviations at the current connec ­ tions are most often directed to the hydro (Nordel) system from the thermal. Also, recent experience with high import to Norway across the Skagerrak connection during low load periods indicate possible problems both with the provision of sufficient spinning reserve and the short circuit capacity at the converter termi­ nals. Thus, in the near future extensive studies have to be made also of situations with import to Norway/Nordel.

Technical aspects might in some cases overrule the economic benefits and neces ­ sitate the use of the HVDC connections for primary control also in the hydro sys­ tem. The basic principles would then be as studied here. However, it seems that also cases with low short circuit capacity have to be studied, a situation that was not anticipated when this study was initiated. This is especially true for the future situation with several HVDC connections operating in parallel.

50 4. Automatic secondary control

Whether the new HVDC connections from Norway are to be used for primary (or secondary) control purposes, or just for the already agreed pumped storage oper ­ ation, it will be nearly impossible to handle the increased system load changes only with the current Regulating Power Market. Introducing some kind of auto­ matic control functions thus seems to be a possible solution.

The principle of automatic secondary control, or load-frequency control, is well known and used for many years in UCPTE, while in Nordel so far the secondary control has been handled with manual control actions. This chapter presents the concept of automatic secondary control from a Scandinavian point of view, start­ ing with an illustration of the basic principles on a simplified system model. Then an 11-area model of the power system of Norway and Sweden is presented for a further study of secondary control principles in the Nordel system.

4.1 Basic principles of load-frequency control

Due to primary control actions, a change in system load will result in a stationary frequency deviation, depending on unit governor droop characteristics and the frequency sensitivity of the load. All synchronized units on speed governing will contribute to the overall change in generation, regardless of their location in the system. The automatic secondary control, more commonly referred to as load- frequency control (LFC), is then responsible for bringing system frequency back to the specified nominal value and maintaining the power interchange between control areas at scheduled values by adjusting the output of selected generators. See also figure 1.4. The LFC is the primary objective of the Automatic Genera ­ tion Control (AGC).

4.1.1 Area Control Error

The basic principles of LFC can be illustrated with a simplified example where two separate system areas are exchanging power across a single inter-area tieline. Figure 4.1 shows the situation after a sudden loss of generation capacity in area 1, simulated with the connection of an additional load of 250 MW. The system frequency drops, but all synchronized units react to the fault with an increase in their production and stabilize the frequency at a new level, regardless of which

51 4. Automatic secondary control

Mech. torque H_SW System frequency

Mech. torque GEN2A Time (s) Time (s)

+250 MW at t= 10 s H_SW Power exchange Px 5.000+ j500 MVA 10.000 MVA

Time (s)

GEN2A Time (s) 4.000 MVA GEN2B H_500 Inter-area tieline 1.000 MVA 500 MVA 2.500 +J250 MVA

AREA 1 AREA 2

Figure 4.1 Primary control response to loss of generation capacity area they belong to. Thus, the initial export Px from area 1 to area 2 is also reduced, as shown in the figure.

If the exact frequency dependency of all components in the system is known or measured, an area droop characteristic similar to the unit droop characteristic can be drawn for each interconnected area, as shown in figure 4.2. For simplicity, the characteristic is assumed to be linear. The slope of this characteristic is the area power-frequency characteristic X.:

^ = -X. (MW/Hz) (4.1)

Figure 4.2 illustrates the different response from the two areas of figure 4.1 due to the same frequency deviation. The difference in power-frequency characteristic is mainly due to the different size of the generation capacity in the two areas.

The stationary frequency deviation after the fault Ais:

A/=-x^ (4-2)

where Xj - power-frequency characteristic of area 1 (MW/Hz) X2 - power-frequency characteristic of area 2 (MW/Hz)

52 4.1 Basic principles of load-frequency control

Area 1 Area 2

Z P, (MW)

Figure 4.2 Area power-frequency characteristics

Area 1 has activated primary control reserves of APj = • A/, while area 2 is assisting area 1 by delivering AP2 = • Af of its primary reserves in the form of a reduced import (APx = -AP2).

The Area Control Error (ACE) for each area can now be defined as [2, 49]:

Gt = APxi + KriAf (4.3) where: AP . - net area interchange deviation (MW) Kri - frequency bias setting (MW/Hz) Af - system frequency deviation (Hz)

In the ideal case Kri = X., and equation (4.3) then yields for the two areas:

Area 1: Gj = APX + Krl ■ Af = X2 • Af + • Af = (Xx+X2) • Af = -APf (4.4)

Area 2: G2 = — APx + Kr2 ■ Af = -X2-A/+X2-A/= 0 (4.5)

The Area Control Error for the faulted area 1 is equal to the size of the fault, while the ACE for the faultless area 2 is zero. Thus, the faulted area is alone responsible for replacing the lost capacity. The ACE for the two areas in the sim­ ulation of figure 4.1 (primary control response only) are plotted vs. frequency and time in figure 4.3.

53 4. Automatic secondary control

Area Control Error ACE (%)

1.0 Frequency (pu)

Figure 4.3 Area control error due to primary control response

4.1.2 Load-frequency control

Closed-loop secondary control, or load-frequency control (LFC), can now be obtained simply by integrating the ACE and returning an additional signal to selected generating units [49]:

APd = -pG-ljGtift (4.6) where APd - additional power demand signal distributed to the control units in the network (MW) P - proportional gain (0.1 - 0.5) Tr - integration time constant (50 - 200 sec.) G - Area Control Error (ACE)

The basic controller layout is shown in figure 4.4, where APd (MW) is the total additional generation needed to return the ACE to zero. C(- are participation fac ­ tors, deciding how much of the total additional generation each connected unit should provide. The sum of all C, is 1.0.

When this basic controller is used, the system responds as shown in figure 4.5. The mechanical torque of the controlled unit H_SW in the faulted area 1 contin ­ ues to rise until the whole fault is replaced by this unit. Both system frequency and inter-area power interchange then return to initial values, and unit GEN2A can also return to initial production, although the unit helped to stabilize the sys­ tem during the first few seconds through its primary control.

54 4.1 Basic principles of load-frequency control

Pl-controller

Figure 4.4 Basic load-frequency controller/secondary controller [10]

Mech. torque H_SW System frequency

Time(s) Time(s) Mech. torque GEN2A

4-250 MW at t = 10 H_SW Power exchange Px 10.000 MVA

Time (s)

GEN2A Time(s> 4.000 MVA GEN2B H_500 Inter-area tieline 1.000 MVA 500 MVA 2.500+]250 MVA

AREA 1 200 + j20 MVA 200+J20 MVA AREA 2

Figure 4.5 Illustration of load-frequency control -1

For this situation, the traces of the ACE return to zero for both areas, as shown in figure 4.6. The ACE of the faultless area 2 turns positive while the activated pri ­ mary reserves are reset.

When a fault instead happens in area 2, the LFC ensures exactly the same response, only this time it is unit GEN2A which replaces the fault, while H_SW can return to initial output. This is illustrated in figure 4.7.

55 4. Automatic secondary control

Area Control Error ACE (%)

1.0 Frequency (pu)

Figure 4.6 Area Control Error with load-frequency control

Mech. torque H_SW System frequency

Mech. torque GEN2A Time (s) Time (s)

hLSW Power exchange Px 5.000 +j500 MVA 10.000 MVA

Time (s)

GEN2A Time (s) 4.000 MVA GEN2B H_500 Px Inter-area tieline 1.000 MVA 500 MVA 2.500+ ]250 MVA

+250MWatt = 10 AREA 1 200 + J20MVA 200 + j20 MVA AREA 2

Figure 4.7 Illustration of load-frequency control - 2

The slow integrating control function of the LFC is quite stable and robust. All simulations shown above are made with identical I-controllers in both areas (Tr = 120 sec.), but also Pi-controllers are used without changing the results signifi ­ cantly. Also, the controllers in the different areas working in parallel does not have to be equal; figure 4.8 shows an illustration where area 1 is equipped with a /"/-controller with P; = 0.1, Trl = 60 sec., while area 2 uses an /-controller with Tr2 = 120 sec.

56 4.1 Basic principles of load-frequency control

Area Control Error ACE (%) Area Control Error ACE (%)

Area 1 Area 2

1.0 Frequency (pu) Time (s)

Figure 4.8 Area Control Error with Pi-controller i Area 1 (P=0.7, Tr=60 sec) and I-controller in Area 2 (Tr=120 sec)

The choice of integration time constant Tr is not critical for the control function as long as it is kept within reasonable limits (50-200 sec. according to UCPTE recommendations). However, the system performance, and even stability, is quite sensitive to the size of the proportional gain |3. As shown in figure 4.9, with (3 = 1.0 oscillations are apparent in the ACE. These fluctuations are transferred to both the controlling and the non-controlling units, causing undesirable gate movements and increased abrasion of the equipment. When (3 is further increased to 2.0, the system becomes unstable. Changing the Tr does not improve the situa­ tion if |3 is given a too large value.

Area Control Error ACE (%) Area Control Error ACE (%)

Area 1 Area 2 /

1.0 Frequency (pu) Time (s)

Figure 4.9 Area Control Error when Pi-controller with p=1.0 is used in both areas (Tr=120 sec)

57 4. Automatic secondary control

Also, the frequency bias setting Kri of the LFC controllers does not have to corre­ spond exactly to the respective area power-frequency characteristics X,-, as the integrator will ensure that the ACE is eventually returned to zero. However, the frequency bias setting should not deviate too much from the power-frequency characteristic, as this might lead to undesirable controller movements and coun ­ ter-control actions both in the faulted and the faultless areas.

4.2 Functional structures of load-frequency control

In an interconnected power system like UCPTE the load-frequency control can be handled in several different ways. Figure 4.10 shows the functional structures of the most common alternatives:

There is no superior LFC controller at the interconnected (international) system level, while at the national level three basic structures are shown, operating in parallel: Country 1 has one single controller LFCj taking care of the whole coun ­ try. This structure is called centralized load-frequency control, and can be found e.g. in France and Holland. Country 3 has a strict hierarchical LFC structure, where one controller at the national level (LFC3) is superior to the controllers at the lower levels. The regional controllers are responsible for their own regions, while the national controller takes care of the international tie-lines. This hierar ­ chical structure might have several levels. Hierarchical LFC can be found in Switzerland and Spain. Country 2 has a mixed solution with hierarchical struc­ ture in some regions, while other regions within the same country are placed at an equal national level. This country has no single national responsible controller.

1. Interconnected system level

2. National level

4. Sub-regional

Figure 4.10 Functional structures of LFC in an interconnected power system [29]

58 4.3 7-area model of the Norwegian power system

The functional structure of figure 4.10 can also be represented in an organiza ­ tional tableau as shown in figure 4.11. Note that although the controllers LFC23j and LFC232 functionally act on the national level as they have no superior con ­ trollers, they actually belong to the sub-regional level. The same observation also applies for the other regional and sub-regional controllers in country 2 due to the missing national controller. Thus, as explained in more detail in Appendix 4, sub ­ ordinate controllers act as a backup for higher control levels if the superior con ­ trollers) should fail.

Interconnected Country Region Sub-region system

1. Centralized 211. Centralized 21. Hierarchical 212. Centralized 2. Decentralized 22. Centralized Decentralized 231. Centralized 23 Decentralized 232. Centralized 31. Centralized 3. Hierarchical 321. Centralized 32. Hierarchical 322. Centralized

Figure 4.11 Organizational levels ofLFC in an interconnected power system [29]

The general mathematical theory for both centralized and hierarchical LFC is treated in detail in reference [29]. For illustrational purposes the most important aspects are shown in Appendix 4, with emphasis on the basic centralized LFC.

4.3 7-area model of the Norwegian power system

In the energy management system at the national control centre of the Norwegian Power Grid Company (Statnett) a system supervising picture is used where the Norwegian power system is represented as 8 geographical areas with only the inter-area tielines and their power flow shown. This picture is ideal for illustra­ tion of automatic secondary control, and is used as a basis for the simulations in this section. All simulations are made with the SIMPOW program system [24].

59 4. Automatic secondary control

4.3.1 Model construction and tuning

To obtain a simulation model that is both simple enough to give a good illustra­ tion of the basic principles of automatic secondary control in Norway, but at the same time also detailed enough to make it possible to compare the model conclu ­ sions with the real power system, the following steps were made:

1. A system model consisting of seven 300 kV buses, each with one generator and one load was constructed, representing 7 geographical areas in Norway, while four 400 kV buses represent a parallel connection through the Swedish grid. (The middle and northern Norwegian areas 7-8 were combined.) 2. Three areas which are characterized by long geographical distances and a distinct partition between generation in one part of the area and load in another, were further divided into two (area 2 and 4) and three (area 3) sub- areas, respectively. The resulting model consists of 15 buses with generation and/or load. 3. Each physical inter-area tieline is identified and modelled in an aggregate way such that between any two areas only one tieline at 300 kV and one at 400 kV (if existing) are represented. For simplicity and due to lack of data, lines from 132 kV and down are neglected. The complete model structure is shown in figure 4.12. 4. Based on generation and consumption statistics, each area were given aggre­ gated values of generation and load approximating a Norwegian peak load situation [50]. 5. Given the grid structure of 15 interconnected buses, the values of generation and load in each area were adjusted to get a reasonably good correspondence with two different load situations: Peak load winter 1994 and low load sum­ mer 1994. The correspondence between the reference load flows calculated with the complete power system [51,52] and the model load flows are shown in the tables 4.2 and 4.4, while total generation, load, available capacity and resulting area power-frequency characteristic are shown in the tables 4.1 and 4.3. 6 . Based on frequency measurements from actual generation outages [53], dynamic parameters of the generators in the peak load model were adjusted to give a response similar to the complete Nordel grid to a casually chosen fault at heavy load (830 MW nuclear power unit in Sweden) - first the sta­ tionary droop of the turbine controllers to approximate the stationary situa­ tion, then the generator inertias and the controller transient droops and time constants to approximate the transient response. The correspondence between the peak load model response and the measurement is shown in fig­ ure 4.13.

60 4.3 7-area model of the Norwegian power system

SV-M400 SV-STKH ©+-» 300/420 I

420/300 300/420

300/420

420/300 300/420 420/300

SV-SYD

SV-WEST

Figure 4.12 Complete (7+4)-area system model

1. Given the adjusted peak load model, only the capacity SN of the units were reduced in the low load dynamic model before comparing with another Nor- del fault response at low load (590 MW nuclear power unit in Sweden). As shown in figure 4.14, the model follows also this response fairly well, but as can be seen from table 4.3 the generator spinning capacity in the model is unrealistic high. In reality, unit droop characteristics are also often adjusted during the summer. By doing this, the low load model could probably have shown an even better correspondence with the measurement, and the amount of spinning capacity could have been reduced.

In the measurements of figures 4.13 and 4.14 a superposed higher order fre­ quency oscillation is apparent which is not reproduced by the model. The cause of this oscillation is not known, but badly tuned controllers and controller and servo deadbands are possible causes.

4.3.2 Ramping domestic and HVDC load

The primary objective of this section is to study the system ’s ability to follow a gradually increasing load over a fairly long time compared to traditional transient stability studies. The simulations are made for a time period of 15 minutes, in which the domestic load is increased with a constant ramp. 80 MW/min (0.44%/ min) in the peak load model and 50 MW/min (0.77%/min) in the low load model

61 4. Automatic secondary control

Capacity Generation Load Frequency bias1 Area (MVA) (MW) (MW) / (MVAr) (MW/Hz)

FI 600 500 4 600 460 325

F2 - - 750 75 1087 F2_l 2 600 2 460 1 500 150 F3 2 200 2 000 850 100 F3_l - - 540 50 603 F3_2 - - 40 5 F4 4 000 3 4832 2 000 200 2 523 F4_l 2 000 1 700 1 500 150 F5 3 000 2 700 400 40 807 F6 1250 1 150 1 300 130 358 F7 +F8 5200 4 900 4 690 500 1 945 NORWAY 20 850 18 893 18 170 1 860 7 648 SV-M400 6 000 1 850 2 460 500 SV-STKH 8000 5 300 2 500 500 7 311 SV-SYD 5 000 4 000 9 600 1 000 SV-VEST 12 000 10 250 7 110 1 200 TOTAL 51 850 40 293 39 840 5 060 14 959

1. Recorded area power-frequency characteristic 2. The generator at busbar F4 is the swing bus of the model

Table 4.1 Summary of peak load situation are chosen as typical “high ” values for the Norwegian power system1. The Swed­ ish load is ramped with the same percentage. In the peak load model the load is ramped totally 6 .6 % up to the situation shown in table 4.1, while in the low load model the load is ramped 11.5% upfront the situation in table 4.3.

In addition to the constant domestic load ramp, the 4 HVDC connections to Den ­ mark (DK), Germany (D) and Holland (NL) are introduced with different ramps to increase the system strain. Statnett will probably request a maximum ramp rate of 20 MW/min/connection [58], but also much steeper ramps are tested.

1. Recent information [76] show that the current maximum load ramp in the Norwegian system is only 40 MW/min, while 80 MW/min typically applies to the total Nordel system. The ramps used in these simula­ tions are thus too steep, but this is not important for the illustrations and conclusions in this section.

62 4.3 7-area model of the Norwegian power system

Inter-area Base case1 11-area model Deviation connection (MW) (MW) (MW)

FI -F2 -1 272 -1 402 130 FI -F4 -624 -527 -97 FI -F5 -2 695 -2 596 -99 FI -F6 24 32 8 FI - SV-VEST 346 342 -4 F2 - F2_l -2 103 -1 681 -422 F2 - F3_2 -437 -490 53 F2_l- F4 -790 -723 -67 F3 - F3_l 540 540 0 F3 - F3_2 677 736 59 F3-F4 -141 -136 -5 F4 - F4_l 85 97 12 F4_l - F5 262 296 34 F6-F7 -122 -118 -4 F7 - SV-M400 90 92 2

1. From reference [51]

Table 4.2 Overview of net load flow result. Peak load

The connection to Denmark is modelled as an extra AC load ramp on node F3_2, whi le the other three connections are added and modelled as one AC load ramp on node F3. The converters themselves are not modelled in these simulations, as they due to the high controllability can be decoupled from the slow dynamics studied in this chapter.

Due to the long simulation period with large variations in unit output, a 1. order non-linear turbine model is used instead of the classic linearized model. The non ­ linear model is developed in Appendix 6 , and is shown in figure A6.3.

63 4. Automatic secondary control

Capacity Generation Load Frequency bias1 Area (MVA) (MW) (MW) / (MVAr) (MW/Hz)

FI 500 200 1 250 100 91 F2 - - 350 50 910 F2_l 2 000 890 425 40 F3 2 000 600 240 20 F3_l - - 110 10 625 F3_2 - - 90 10 F4 4 000 6822 600 60 3 195 F4_l 2 000 1250 485 50 F5 2 500 1 700 430 50 683 F6 1 000 830 500 50 277 F7 + F8 4 000 2 256 2 000 200 1474 NORWAY 18 000 8 408 6 480 640 7 255 SV-M400 5 000 900 800 100 SV-STKH 6000 2 120 2000 100 5 270 SV-SYD 4 000 1460 3 500 350 SV-VEST 8 000 3 600 2 800 300 TOTAL 41 000 16 488 15 580 1 490 12 525

1. Recorded area power-frequency characteristic 2. The generator at busbar F4 is the swing bus of the model

Table 4.3 Summary of low load situation

64 4.3 7-area model of the Norwegian power system

Inter-area Base case1 9-area model Deviation connection (MW) (MW) (MW)

FI -F2 135 115 -20 F1-F4 108 -44 -152 F1-F5 -1 760 -1 606 -154 FI -F6 -388 -389 1 FI - SV-VEST 859 858 -1 F2 - F2_l -446 -520 74 F2 - F3_2 223 284 61 F2_l - F4 -56 -56 0 F3 - F3_l 110 110 0 F3 - F3_2 697 653 -44 F3-F4 -449 -404 -45 F4 - F4_l -375 -427 52 F4_l - F5 391 336 -55 F6-F7 -56 -59 3 F7 - SV-M400 200 197 -3

1. From reference [52]

Table 4.4 Overview of net load flow result. Low load

65 4. Automatic secondary control

..ijt...... —

\mmzn mm? ...... -... t—-'------.

Figure 4.13 Comparison of model response and measured Nordel grid response after loss of 830 MW nuclear power at heavy load (Hz) [53]

! ,

- ^ L 2ft —Yi. . - ^ - jff* " x t-V-r...... ’• ,•■'■• • ?•<"' t • ...... ' ■'------1 / L j, 4...... -ON- / - ,/ I • ■> A •* lc ——-— S 4 J . J. ^ flfcx.''* .. . . ——J

f 4t/ < *>| m <> •* /t A» —■ >*%>*>;* WW'vfW* & . M; v>s fKswSi iS'Tp n IWXV/ J ' ^<*>4 £,# < w/s. >!A vai w* - ^ y y % % ' ■ ...... / a. -x>< t j.

| ' 1' rm mjSwwW’ ' "! ' "' ".!' " p , r ...... v*> AV \T ] ...... ' ' ' ' ri^ % A* J l/'/A ' '■ ' ' KaatW M1- O' ■ / /4f\ ------

. A / /A 41-35 - _ V^JMn,toKk)X6.Vi>V«‘ViV«

Figure 4.14 Comparison of model response and measured Nordel grid response after loss of 590 MW nuclear power at low load (Hz) [53]

66 4.4 Centralized load-frequency controller

4.4 Centralized load-frequency controller

4.4.1 Present system

If the system was left alone without any secondary control actions, the unit droop characteristics would cause nearly linear changes in unit generation following the load ramp, with corresponding nearly linear reduction of system frequency and changes in inter-area transmissions. This rather trivial result is shown for illustra- tional purposes in figure 4.15 with only the 80 MW/min domestic load ramp as excitation.

The dotted line shows an attempt to represent also the current manual control of the Norwegian system; A deviation is noticed by the system operator, who calls upon capacity offered at the Regulating Power Market. This capacity will then be manually activated after a certain time delay, and in gradual steps if more than one unit is required to regulate. Such “manual ” control will not be further treated in this section.

The starting point (7=0) in these simulations can be any instant during the hour when there is a momentarily balance between a constant production and a contin ­ ually changing load. Note also that in order to get a stable start of the simulation, the load ramp starts after a 10 sec. delay. This is done in all simulations shown in the following sections.

System frequency (pu) (Hz) 1.002 50.10

- 50.05

1.000 50.00

- 49.95

0.998 - - 49.90

0.997 - 49.85

Time (s)

Figure 4.15 System frequency response to a load ramp of 80 MW/min at peak load without any secondary control actions

The most “elegant ” way to handle the increased operational strain on the system caused by the new HVDC agreements is to introduce general load-frequency control in the Nordel system. The LFC would then handle all deviations in the

67 4. Automatic secondary control system, including normal load changes, HVDC ramping and faults. As will be shown, this requires simple, standard control equipment which has been used successfully for many years in the UCPTE system.

For simplicity, only centralized national LFC is implemented. The total signal tableau as implemented in SIMPOW is shown in figure 4.16, with the Norwegian system controllers to the left and the corresponding Swedish controllers to the right. The MPX component (Measurement of Power exchange) measures the power flow in the two international tie lines (Area F7 - SV-M400 and FI - SV- WEST). The AGC2 are the two national load-frequency controllers with basic structures as shown in figure 4.4, only with an input of two tie line measurements. The national controllers generate total national additional generation demand signals _DPG_N and _DPG_S, respectively, which is distributed to selected units by the distributing components PARTICIP5 and PARTICIP2 (for 5 and 2 partici ­ pating generators).

•NORWAY' 'SWEDEN' SV-M

SV-W

PL_F7 PLF1 _PL_SVW PLSVM

AGC2 AGC2

DPG_N _DPG_S

PARTICIP5 PARTICIP2

DP_G1 DP_GS1

HGOV4 HGOV4

Figure 4.16 LFC signal tableau

In the Norwegian system the generators on the busbars F2_l, F3, F4, F5 and F7 are used for LFC, while in the Swedish ring the (hydro) generators on SV-M400 and SV-WEST are used (see also figure 4.12). The AGC2 and PARTICIP5 control ­ lers are shown in figures 4.17 and 4.18, and the modified hydro turbine governor HGOV4 with an extra input for the additional generation demand signal _DP_Gi is shown in figure 4.19.

68 4.4 Centralized load-frequency controller

Frequency bias and pu scaling

to generator pu

Figure 4.17 Central load-frequency controller AGC2

In the AGC2 controller there are two pu scaling factors introduced due to SIM- POW requirements which have no influence on the controller operation. First, the unit speed to is measured in pu of 50 Hz, while the frequency bias setting Kr is given in [MW/Hz]. As the power interchange Px is measured in pu of the global 500 MVA base, the frequency bias signal have to be scaled before added to the power interchange deviation:

Kr [MW/Hz] • 50 [Hz] Kr (4.7) Aa>[pii Hz] ■ 500 [MVA] = Aro ' 10 [pu MVAJ

Second, when the frequency bias and the pu interchange deviation is added, the signal have to be scaled from global pu base to local generator MVA-base. The scaling factor ^SNi is equal to the sum of the MVA-bases of all the participating generators, and the national additional power demand signal _DPG_x is thus in an aggregated MVA-base. From tables 4.1 and 4.3 it can be found that the aggre­ gated MVA base for Norway is 17000 MVA in the peak load situation and 14500 MVA at low load. Corresponding values for the Swedish ring are 18000 MVA and 13000 MVA, respectively. A new scaling for each participating generator is made in the PARTICIPn controllers.

In all simulations shown in this section the integrator time constant T=120 sec. to ensure a smooth unit operation, with (3=0 (only integrator). Values of (3 within the range recommended by UCPTE (0.1 - 0.5) are also tested without changing the results significantly.

The sum of all participating factors C, in the signal distributors is unity.

69 4. Automatic secondary control

DPG1

DP G2

DPGx DP_G3

DP G4

DP G5

Figure 4.18 Additional generation demand signal distributor PARTICIP5

_DP_Gi POREF

\ 1 + 1 + sTT + BP (1 + STA)(1 + STB)

(0

Figure 4.19 Modified hydro turbine governor HGOV4

By introducing this controller scheme, the system response to the domestic load ramp from figure 4.15 changes to that shown in figure 4.20a. The system fre­ quency is kept at a small constant deviation, as the controllers are unable to catch up with the ramp (as opposed to the step excitation from section 4.1). The size of the deviation is dependent on the total system frequency bias. Since the fre­ quency bias of the systems are nearly equal, the Norwegian and Swedish ACE values in figure 4.20b are nearly equal. Note that the ACE are given in pu of aggregated MVA base of controlled units. The domestic load ramp causes an ACE slightly above 100 MW for each country, which is well within the required values given in table A 1.5.

Figure 4.20c illustrates the different response of mechanical torque of one unit participating in LFC (unit SW4 at busbar F4) and one unit responding only to the frequency deviation according to its governor droop (unit GEN4_1). Note also from figure 4.20d that although the LFC keeps the total national power inter ­ change constant, the transmission on each line is changing (500 MW is the global pu base).

70 4.4 Centralized load-frequency controller

a) System frequency (pu) b) ACE (pu)

Norway Sweden

(N: 112 MW)

-0.010 Time (s)

c) Mech. torque (pu) d) Tie-line transmission (pu 500 MW)

SW4 GEN4_1

F7-SVM

Time (s) Time (s)

Figure 4.20 System response to a load ramp of 80 MW/min at peak load with central LFC

During the simulation period busbar voltages are reduced approximately 0.5%, and there is no danger of overload on any inter-area tie-lines. The model is how ­ ever not well suited for detailed studies of transmission capacity. Parallel lines between two areas are modelled as one, and the thermal current limits of each line are simply added, although the geographical distance between the real lines might be large. Thus, when the model indicates no overload on any inter-area connection, there might still be danger of overloading one of the lines in the real grid if the local impedance relations should cause unfavourable distribution of the transmitted power. This would have to be checked in each case with simula­ tions or load-flow calculations on the complete grid.

The LFC system is able to handle quite steep ramps in a satisfactory way. As an illustration, figures 4.21a-d show the response when the HVDC connection to Denmark is ramped from initially 200 MW load to full load of 1000 MW in 10 minutes (starting after 100 seconds in the simulation). This doubles the load change rate in the Norwegian system from 80 MW/min to 160 MW/min.

The system frequency is still kept well under control, but the increased ACE clearly shows that the Norwegian system is working hard. Indeed, looking at fig­ ure 4.21d it can be seen that due to the extra frequency reduction the Norwegian system “borrows ” spinning reserves from the Swedish system during the HVDC ramping. The demanded ramp of the controlled unit SW4 in figure 4.21c is smooth, however, and should not cause any operational problems.

71 4. Automatic secondary control

a) System frequency (pu) b) ACE (pu)

Norway Sweden 1.000

(244 MW) 0.997 -

Time (s) Time (s)

c) Mech. torque (pu) d) Tie-line transmission (pu 500 MW) 1.000 SW4 GEN4_1 F1-SVW F7-SVM 0.950

0.900

Time (s) Time (s)

Figure 4.21 System response at peak load with central LFC to load ramps of 80 MW/min domestic + 800 MW/10 min HVDC (DK)

Without any compensating equipment installed, the voltage at the HVDC termi­ nal is reduced with approximately 5% during the ramping, while other busbars experience a voltage reduction of 1-2%. There are no indications of overload on any inter-area connections. The transmission on the connection F3-F3_2 increases to 1200 MW, the connection F4-F3 to 385 MW, while the initial flow from F3_2 to F2 is reduced.

4.4.2 New connections in the next decade

Entering the next decade, at least three new HVDC connections between Norway and UCPTE will be commissioned. At present, special paragraphs in the agree­ ments concerning the maximum load change rate exist for only one of the con ­ nections, but the system operator Statnett probably wants to limit this rate to 20 MW/min/connection [58]. Applying this ramp to all four HVDC connections in addition to the 80 MW/min domestic load ramp, the situation from figure 4.20 changes to that shown in figures 4.22a-d.

As can be seen from the figures, the ramp itself causes no problems for the sys­ tem. But shortly after 700 sec. the frequency starts to drop, and from figure 4.22b it can be seen that the Norwegian ACE drops fast, indicating that the cause of the problem is in the Norwegian system. The cause is apparent from figure 4.22c: Controlled units reaching maximum load (max gate opening). For each unit reaching maximum load, the rest of the controlled units have to increase then- output faster, thus creating a cascading effect which might lead to system black-

72 4.4 Centralized load-frequency controller

a) System frequency (pu) b) ACE (pu)

Norway Sweden

Time(s) Time (s)

c) Mech. torque (pu) d) Tie-line transmission (pu 500 MW)

F1-SVW F7-SVM

SW4 GENS

0.750

Time (s) Time (s) Figure 4.22 System response at peak load with central LFC to load ramps of 80 MW/min domestic + 4x20 MW/min HVDC (DKZD/D/NL) out if no other actions were taken. Unit GEN5 in figure 4.22c illustrates this increased load ramp.

When the system frequency starts to drop, more spinning reserves are taken from all synchronized units in the system, including the Swedish ones. Thus, the initial export from Norway is reduced with increasing rate, as shown in figure 4.22d.

When all the new HVDC connections are introduced in the model, SVC equip ­ ment is installed on the terminal buses F3 and F3_2 with 900 and 500 MVAr capacity, respectively, preventing possible voltage problems due to the increased reactive power consumption by the HVDC terminals. The voltages change approximately 0.5% during the simulation. Also, there is no danger of overload on any transmission lines. The connection with the heaviest load is F4-F3 with 1250 MW.

The situation above shows that the capacity of the system might become a bigger problem than the ramp rate. When instead the same load ramp is used on the low load situation of table 4.3, the system is quite able to handle the ramp, as shown in figures 4.23a-d. Note that the ACE are now given in pu of the low load MVA base, and that the power interchanges in figure 4.23d are shown on different axes (Fl-SVW to the left, F7-SVM to the right) to avoid masking the changes with too large scales. The SVC equipment at the HVDC terminals ensures that the voltage drops are less than 1%, and there is no overload on any tie-lines.

73 4. Automatic secondary control

a) System frequency (pu) b) ACE (pu)

Norway Sweden

-0.005

Time (s) Time (s)

c) Mech. torque (pu) d) Tie-line transmission (pu 500 MW)

GEN4_1

F1-SVW F7-SVM

Time (s) Time (s)

Figure 4.23 System response at low load with central LFC to load ramps of 50 MW/min domestic + 4x20 MW/min HVDC (DK/D/D/NL)

Just to test how high load ramp rate the LFC is able to handle without violating current frequency requirements (and without capacity limits in the system), the four HVDC connections are ramped up to rated load in 2 minutes from the low load situation. The connection to Denmark is ramped from 200 MW to 1000 MW, while each of the three connections from node F3 is ramped from 100 MW to 600 MW, implying an extreme Norwegian system load ramp of

800 + 3 ■ 500 + 50 = 1200 MW/min (4.8) 2

The result is shown in figures 4.24a-d. The LFC is no longer able to keep the sys­ tem frequency above the normal operation limit of 49.9 Hz (0.998 pu), and the Norwegian ACE increases to 1663 MW. However, as soon as the HVDC ramps are finished, the system returns to the stable situation of following the normal domestic load ramp. The units operating under LFC are exposed to rather large and rapid load changes, as illustrated in figure 4.24c, and the export to Sweden is dramatically reduced during the HVDC ramping.

When looking closer at the turbine characteristics of the unit with the largest load change (GEN3) in figures 4.25a-d, the changes are large but not dramatic. The mechanical torque of the unit rises approximately 25% in 3 minutes, which should be quite possible in modem high pressure units. (It must be kept in mind that this 25% is actually 500 MW, and thus have to be distributed between several units.) Nor are the changes in gate opening, flow rate or turbine head dramatic. Note also that there is no observable inverse response in the unit torque.

74 4.4 Centralized load-frequency controller

a) System frequency (pu) b) ACE (pu)

1.000

Norway Sweden

(1663 MW)

Time (s) Time (s)

c) Mech. torque (pu) d) Tie-line transmission (pu 500 MW)

o.soo F1-SVW F7-SVM

SW4 GEN4_1

Time (s)

Figure 4.24 System response at low load with central LFC to extreme load ramps of 50 MW/min domestic + 2300 MW/2 min HVDC (DK/D/D/NL)

The other controlled units experience similar but slightly smaller load changes. As explained earlier, the distribution of the total power demand between the con ­ trolled units is dependent on the choice of participation factors in figure 4.18, which must be carefully selected according to local unit and grid characteristics.

The voltages in the system are reduced less than 1% during the ramping, and when the four HVDC connections reach rated load the heaviest loaded connec ­ tion is still F4-F3 with 1650 MW.

a) Mech. torque GEN3 (pu 2.000 MW) b) Gate opening Y (pu)

0,200 0 300 600 900 Time (s) Time (s)

c) Turbine flow rate Q (pu) d) Net turbine head He (pu)

0.500 -

Time (s) Time (s)

Figure 4.25 Turbine characteristics of unit GEN3 at extreme load ramp

75 4. Automatic secondary control

4.5 Ramp following controller

Fully automatic load-frequency control as illustrated above is technically a rather simple and easy way to handle the secondary control in the Nordel system. The fact that the control functions are generally aimed at keeping system frequency and only international power interchanges (in the case of centralized LFC) at their nominal values ensures that all deviations in the system are taken care of, no matter where the deviation occurs and what might be the cause. The only condi ­ tion is that there are sufficient reserves and transmission capacity available.

However, the general LFC system is not very well suited to the deregulated energy market of Norway and Sweden, a fact which is recognized also by other authors [4]. In the typical monopoly systems of UCPTE the power producer is also the owner and operator of the grid, but in Norway the Norwegian Power Grid Company (Statnett) is responsible for the system operation, and thus the secondary control, while the generating units are owned by several other power companies. Statnett would have to buy all reserve capacity from the producers on a commercial basis, and in the case of automatic LFC for rather long periods of time and for large and frequent unit load changes. Thus, the price needed to get sufficient amounts of reserve capacity might be high. On the other hand, it would be very difficult to place any kind of responsibility for system deviations at a given time, thus the financing of LFC would most probably have to be made with a general fee.

An alternative secondary control system is therefore introduced in which special power stations are selected to follow the HVDC load automatically, while the “rest” of the system deviations are handled via the existing Regulating Power Market as today. In this case there is a clear connection between the responsibil ­ ity for the “disturbance ” - the contractual partners) of the HVDC connection - and the provision of sufficient reserve power. Thus, the contractual partner would have to supply the reserve from own generation capacity or by purchase, not the system operator.

4.5.1 Controller layout

Instead of the MPX, AGC2 and PARTICIP5 components in figure 4.16 the single HVDC ramp following controller of figure 4.26 is now introduced. (No control ­ lers are needed on the Swedish side.) As shown in the figure, the different HVDC ramps (e.g. daily plans of operation) are added in the preprocessor DCRAMP, which sends a total MW demand signal _DP_DC to the ramp following control ­ ler. Similar to the LFC scheme, this signal have to be scaled with generator MVA-base before being compared to the actual Generator electric Power output

76 4.5 Ramp following controller

PGi and integrated. PGO is the initial generator output. Although only one unit is used for ramp following in these simulations, the additional output demand sig­ nal _DP_Gi can be distributed to any number of units with a signal distributor similar to PARTICIP5 in figure 4.18.

HVDC ramps 1,2,.... Ramp addition and pu scaling DP Gi DCRAMP DP DC

_BLOCK

Figure 4.26 HVDC ramp following controller RFC1

The additional output demand signal _DP_Gi to the turbine governor HGOV4 is added to the normal stationary droop signal, as can be seen in figure 4.19, and one important problem now arises. When integrating APG from the generator, also normal generator primary control response will be affected. In fact, the shown controller will prevent the unit from participating in primary control. The binary _BLOCK signal prevents this undesirable controller operation when the HVDC ramp is zero, but has to be switched on when the ramp is running. A sim­ ilar blocking signal could also be introduced when the ramp has reached rated load, but is not implemented here.

This problem can be solved in two ways: One possibility is to accept that the ramp following unit do not participate in primary control at all. This is the sim­ plest solution from a technical point of view, but not a very realistic one. As the dedicated reserve needed for HVDC ramp following might be several thousand MW, the Norwegian primary control reserves would be reduced accordingly. Thus, the ramp controller have to be modified with a unit droop compensation module as shown in figure 4.27. In this module the generator feedback PGi is reduced with a signal which is an estimate of the frequency-dependent part of the total unit response. BP is the static droop of the controlled unit, while RC is an empirical correction factor for losses and non-linearities between governor input and generator output. The importance of this droop compensation is illustrated in the following section.

Of course, given the flexibility of modem microprocessor based controller tech ­ nology, the droop compensation module can be designed with any level of com­ plexity. The simple layout implemented here is meant only as an illustration of important aspects, not as the final solution. Note also the structural similarity between this ramp following controller and the general controller of figure 4.4.

77 4. Automatic secondary control

Unit droop compensation

HVDC ramps 7,2,.... Ramp addition and pu scaling DP Gi DCRAMP DP_DC

_BLOCK

Figure 4.27 HVDC ramp following controller with droop compensation RFC2

4.5.2 Controller tuning

Since the problem of reserve capacity have to be handled no matter which sec­ ondary control scheme is used, all simulations with ramp following control is made with the low load model to emphasize the basic control aspects. For com­ parison, the situation with only domestic load ramp (50 MW/min) without any secondary control actions is shown in figure 4.28. Accidentally, due to reductions in both load ramp and spinning reserves this system frequency response is nearly identical to the peak load response of figure 4.15.

System frequency (pu)

1.000

0.999

0.998

0.997 -

0.996

Time (s)

Figure 4.28 System frequency response to a load ramp of 50 MW/min at low load without any secondary control actions

As the purpose of the ramp following control scheme is to handle the HVDC ramps automatically, while the normal domestic load ramp will be handled by the

78 4.5 Ramp following controller current manual control actions, the controller used in these simulations must be tuned such that the system frequency follows the (uncontrolled) response of fig­ ure 4.28 as closely as possible. In most of the simulations shown in the following, the generator SW4 at busbar F4 (the swing bus) is chosen as controlled unit, both due to the large available capacity and the short distance to the HVDC terminals. Some basic aspects when choosing the controller parameters are illustrated in fig­ ures 4.29a-d, where system frequency with HVDC ramping is compared to the basic response of figure 4.28. To emphasize the difference in controller response, the rather steep ramp of 100% in 10 minutes is used for all connections, giving a total HVDC ramp rate of 230 MW/min. The stability of the system is ensured by inspecting the eigenvalues in each case.

The slow I-controller (7=120 s) which was used successfully for LFC purposes in the previous section is no longer sufficient, as shown in figure 4.29a. This con ­ troller reacts too slowly and causes a large frequency deviation while the HVDC is ramping, and is also unable to keep up with the domestic load ramp when the HVDC has reached rated load.

Introducing a Pi-controller with T = 30 s, p = 2, improves the result considerably, but the system frequency reduction still has a different slope than the reference. Decreasing the time constant to 10 s does not improve the result significantly, as shown in figure 4.29c. Such a small time constant also causes large overshoots in the power demand signal _DP_Gi (which is however not much apparent in the shown frequency response). Nor is increasing the controller gain (3 a good solu­ tion as this might cause instability.

a) (-controller (T= 120 s) b) Pl-controiler (T = 30 s, b = 2)

1.000

0.998

Time (s) Time (s)

c) Pi-controller (T= 10 s, b = 2) d) Pl-controller (T = 30 s, b = 2) w/ droop comp.

1.000

0.997

Time (s)

Figure 4.29 System frequency response (pu) to a total HVDC ramp of 2300 MW in 10 minutes for different controller settings

79 4. Automatic secondary control

However, when the unit droop compensation module as shown in figure 4.27 is introduced in the controller, the system frequency with the HVDC ramp follows the reference quite good, as can be seen in figure 4.29d. This clearly demon ­ strates the importance of the droop compensation. The small difference in slope still apparent towards the end of the curve is caused by increased transmission losses and an imperfect ramp correction factor RC.

In these simulations the ramp correction factor RC in figure 4.27 is calculated as the pu relation between turbine governor output Y and turbine mechanical power PM, giving a linear approximation of the turbine model for each time step (see also figure A6.3). As already mentioned, this compensation module can have a much more complex design, but even the simple linear relation used here improves the ramp following ability of the controller considerably.

Figures 4.30a-d show some selected system variables for the simulation of figure 4.29d. In figure 4.30a two internal signals in the ramp following controller is shown; the input and output (_DP_Gi) of the integrator block (note that the two curves have different scales), while in figure 4.30b the HVDC ramp _DP_DC is compared to the mechanical torque of the controlled generator SW4 at busbar F4. The difference in slope is due to the subordinated unit primary control response.

Looking at tie-line transmissions, figure 4.30c shows (again with different scales) that the interchange with Sweden is mainly influenced by the uncontrolled domestic ramp, not the HVDC ramp. More important is the transmission between areas F3 (HVDC terminals) and F4 (controlled unit) in figure 4.30d which reaches 2175 MW, indicating danger of overload. The current transmission capacity between these two areas is approximately 1500 MW, but reinforcements will be made before the new HVDC connections are commissioned [54].

As already mentioned, the problem of overload on transmission lines must be checked with more detailed grid models. In the case of RFC, the danger of over ­ load can generally be assumed to be greater than with LFC, since large amounts of power have to be transferred between a few controlled units and the HVDC terminals, while in the LFC scheme the general reserve provision is usually much more distributed in the grid and does not have to be transported a certain dis­ tance. However, for the same reason it is easier to detect danger of overload on the possible transmission channels in the RFC scheme, while it is difficult to con ­ trol how the power flow will change due to LFC control actions.

80 4.5 Ramp following controller

a) Internal RFC signals (pu 4000 MVA) b) HVDC and generator ramp (pu 4000 MVA)

Integrator Integrator output input _DP_G4 0.020 TM_SW4 ,DP_DC

Time (s)

c) Tie-line transmission (pu 500 MW) d) Tie-line transmission (pu 500 MW)

F1-SVW F7-SVM

Time (s) Time (s) Figure 4.30 Selected system variables at HVDC ramping with Pi-controller with droop compensation (T=30 sec, (3=2J

4.5.3 Ramp following ability

The task of following a ramp is technically more difficult than responding to a step, which is the usual way of excitating a power system model. The controller feedback loop used here for this purpose consists of the elements shown in figure 4.31: Compensated ramp following controller RFC2, speed governor HGOV4, non-linear turbine HTURB2 and finally the 5th order generator model of SIM- POW, including both the voltage controller and a PSS.

DP Gi RFC2 HGOV4 HTURB2

Figure 4.31 Ramp following control loop

The fact that the internal SIMPOW generator representation is not known in detail makes it difficult to prove the ramp following ability of the controller mathematically. However, although it is not a strict proof it is possible to show this ability with rather simple calculations. Assuming that the complete control loop is linearized, it can be simplified to the system shown in figure 4.32.

81 4. Automatic secondary control

APc(s) A%(s)

Figure 4.32 Linearized ramp following control loop

In this system the controller transfer function is

i +spr (4.9) sT while the process transfer function can be written as a function of general polyno ­ mials with one or more zero poles

n n ■ s + ... + n.Q n(s) Hp (s) (4.10) d m-sm~l+ ...+d ; sl • d (s) where i> 1 «Q^0 d Q = d. = 0

The existence of one or more zero poles is due to both the lack of a constant fre­ quency reference in the model and because the generator damping coefficients are neglected.

The control deviation is Dc(s) A?DC(^ Ae (5) — APjyg (s) APQj (5) (4.11) 1 +Hr(s) Hp (s) 1+A(s)

l+s$T n(s) where A(f) sT sl ■ d (s) If this system is excitated with a step function Cfs the well known integrator response is obtained:

lim Ae (t) f —5> 00 1 +A (s) s s — 0

si + 2Td(s) Ci = 0 (4.12) si+^Td(s) + s|37>z (s) +n(s) 5 = 0

82 4.6 Additional system faults

However, also when the excitation is a ramp function C2/s2 the following result can be found:

si + 2Td(s) = 0 (4.13) si+lTd(s) + s$Tn (s) +n(s)

Thus, the chosen control structure is able to follow the HVDC ramp without deviations, ensuring in the ideal case that no extra frequency deviations are induced. The control simulation shown in figure 4.33 where unit GEN3 follows only the HVDC ramping at busbar F3 (no transmission losses) confirms this.

System frequency (pu) 1.001 Dorn. + HVDC Domestic ramping ramp only 1.000

0.999

0.998

0.997

0.996 1------'---- '----- :----- '---- '------‘------'------'------1----- '----- 1----'------'------0 100 200 300 400 500 600 700 800 900 Time (s)

Figure 4.33 System frequency when GEN3 is following a 3x20 MW/min HVDC ramp (D/D/NL) at busbar F3 (PI: T = 10 s, $ = 2) w/droop compensation

In reality, there will always be some transmission losses and process non-lineari ­ ties between the controlled units and the HVDC terminals, and it will be very dif­ ficult to design a ramp following controller that is able to compensate completely for this. The HVDC ramping will most probably have some in fluence on the sys­ tem frequency no matter which controller is used.

4.6 Additional system faults

Automatic secondary control is deliberately designed as slow functions with large time constants to avoid influencing the primary control actions and thus increasing the danger of system instability. Additional system faults are not a central aspect in this chapter, but a few examples will be shown here.

83 4. Automatic secondary control

Figures 4.34a-b show the frequency response when 590 MW nuclear power is lost in Sweden while the HVDC ramps are running. (This fault is the same as shown in figure 4.14.) Note that the transient frequency deviation is nearly equal for both the RFC and LFC scheme, confirming the requirement that secondary control functions should not interfere with initial inertia/primary control response. After the fault the system operates as before.

The same observations can be made when one of the ramping HVDC connec ­ tions are lost, as shown in figures 4.34c-d. Also this time the (positive) transient deviation is nearly equal for the two controller schemes.

a) Loss of 590 MW at SV-STKH (RFC) b) Loss of 590 MW at SV-STKH (LFC)

Time (s) Time (s)

c) Loss of one HVDC (RFC) d) Loss of one HVDC (LFC)

Time (s) Time (s)

Figure 4.34 System response during additional faults

4.7 Summary

When at least 3 new HVDC connections from Norway to UCPTE are commis­ sioned early in the next decade it will be nearly impossible to handle total system load changes only with the current Regulating Power Market. Reducing the Spot Market bidding period from 1 hour to 30 minutes will probably not be sufficient. A typical peak load morning load ramp might be at least 160 MW/min (80 MW/ min domestic + 4x20 MW/min HVDC), twice the maximum load ramp of today. This extreme domestic load ramp might not last for 30 minutes, but in this period the HVDC connections alone will increase 2400 MW, and a possible total load increase is then approximately 4000 MW in 30 minutes.

Manually ramping power stations together with the HVDC connections outside

84 4.7 Summary both the Spot Market and the Regulating Power Market might be a dangerous and unreliable solution, as even small deviations or delays might have large con ­ sequences. Also, introducing some kind of ramping in the Spot Market bidding seems to be a rather impractical solution which is difficult to administer. Thus, introducing automatic control functions seems to be a better solution.

In this chapter the use of two alternative automatic secondary control schemes have been demonstrated in a simplified model of the Norwegian/Swedish power system, but of course other schemes are possible. One alternative is the general load-frequency control scheme. The LFC handles all system deviations, both faults, normal load changes and HVDC ramping. It will automatically adjust to any manual (‘tertiary’) control actions taken, and can thus be implemented both as a total substitution of, or as a supplement to, the current Regulating Power Market. One favourable solution might be to introduce a limited LFC system designed to aid the system operator for, say, 15 minutes until capacity offered at the Regulating Power Market can be activated.

However, as explained above general LFC based on the Area Control Error might be difficult to implement in a deregulated environment. It would also require that all interconnected systems introduced LFC together (Sweden, Finland and Zee- land) to ensure an unique ACE signal for the controllers. Note that for the same reason, it is not possible to introduce ‘local ’ LFC in area F3 with main task to handle the HVDC connections, based on the ACE of that area alone. A single LFC controller in one area is possible, but would have to be based on another control signal than the ACE.

Another solution is then to introduce ramp following control (RFC) where some units are selected to follow certain system load ramps (in this case the HVDC connections) outside the Regulating Power Market. It is shown above that such a control scheme can be implemented with a rather simple control structure, but it should nonetheless not be chosen without careful consideration.

Since the controller in this example responds only to HVDC load changes, it can ­ not be supplemented with manual tertiary control actions without a more compli ­ cated design, and if one of the selected units should fail, the rest of the controlled units might not be able to compensate for the missing capacity. Also, a lot of available transfer capacity directly between the HVDC terminals and the control ­ led units have to be available, but this might also be a problem for the LFC depending on the location of the controlled units.

Both LFC and RFC seem to fulfil the necessary system requirements. The selected simulations shown in this chapter indicate that generation and transmis ­ sion capacity limits might be a bigger problem than the ramping itself. The selec­

85 4. Automatic secondary control tion of units for any automatic secondary control actions thus have to be made from careful studies of unit and local grid characteristics, which is beyond the scope of this work. Of course, more complicated control schemes than those shown here might be designed, but the more complicated a control scheme is, the more difficult it is to implement safely. Although the LFC is a tempting solution due to its general and simple functioning, no final recommendation regarding choice of future secondary control in the Nordel system can, or should, be given at this stage of the work.

86 5. Cost of spinning reserve in thermal power systems

The previous chapters have shown that it is technically possible to supply pri ­ mary control reserves across the HVDC connections from Norway, and to handle the increased operational strain on the system with automatic control functions. The next question to be answered is of an economic nature: What is the value of a possible trade of primary and/or secondary control reserves across the HVDC connections as seen from the thermal power system?

In this chapter costs related to spinning reserves (primary and secondary control reserves) in thermal dominated power systems are estimated. First, the additional operational costs due to primary control reserve provision in thermal power units are estimated, then the so-called relocation costs and the secondary reserve costs are estimated by means of an unit commitment optimization program.

5.1 Primary control in thermal power units

Both provision and activation of primary control reserves from a thermal power unit affect the normal operating characteristics of the unit, in particular the heat rate. As described in Appendix 2 there are several possible ways to provide pri ­ mary control reserves in thermal power units. However, the currently most com­ mon method in the UCPTE system is by throttling of the HP turbine control valves in conventional steam power units, storing additional energy as increased main steam pressure in the boiler. The method of combined condensate stoppage is so far used in only a few newer power plant [36].

This section describes a method to estimate the costs of providing primary con ­ trol reserves in conventional steam power units, based on reference [37]. The basic method is 10 years old, but is still used and referred to [36,48].

5.1.1 Additional unit reserve costs

When calculating the additional costs of providing primary control reserves from a coal fired unit i, the following cost elements must be considered:

• Additional investments: (NOK)

87 5. Cost of spinning reserve in thermal power systems

• Additional maintenance and abrasion costs: AkMi (NOK/a)

• Additional fuel costs:

^kpi — ' cpi' Acfi (NOK/a) (5.1)

where: - rated load of unit i (MW) - rated load utilisation time for unit i (h/a) cFi - fuel costs at rated load for unit i (NOK/GJ) Aqt - heat rate increase due to reserve provision (MJ/kWh)

The heat rate increase Aqi is nearly constant over the load range when the unit is operated with constant throttling, eq. (A2.1a), but is dependent on the main steam pressure; decreasing with decreasing pressure. Units operating at constant main steam pressure have a “natural ” throttle reserve when operating below rated out­ put (see figure A2.5), but maximum allowable pressure reduction limits the use of this reserve. As these units generally have a higher heat rate than units operat ­ ing in sliding pressure mode, the choice of using constant main steam pressure operation is made from other reasons than the ability to provide primary control reserves [14, 33]. The costs of primary control reserves can thus be assumed to be related mainly to units operating in (modified) sliding pressure mode.

Figure 5.1 shows the empirical range of unit heat rate increase Aqi due to HP tur­ bine control valve throttling in German coal fired units as function of main steam pressure [30]. The difference between full arc admission turbines and turbines with partial arc admission via nozzle groups is small and is not considered here.

Unit heat rate increase (%) 2.0 -i

7.5S//' 1.5 -

1.0 -

0.5 -

0.0 J 150 200 250 150 200 250 150 200 250 Main steam pressure (bar) Dy = 5% Dy= 10% Dy = 15% Throttle degree

Figure 5.1 Empirical range of heat rate increase A qi due to throttling of HP turbine control valves in German coal fired units [30]

88 5.1 Primary control in thermal power units

Using the indicated values in figure 5.1, equation (5.1) gives additional fuel costs for the basic 600 MW coal fired unit with 200 bar main steam pressure from ref. [37]. These fuel costs are shown in figure 5.2. The rated load heat rate is chosen as a typical value of 9 MJ/kWh, while the fuel costs are typical current costs of German pit coal (3-3.5 DM/GJ) [5, 39,55]. The rated load utilization time is cho ­ sen as the intermediate value of 4000 h/a.

Additional fuel costs (MNOK/year) 6 -

5.12 5

4 3.40/

3 • 600 MW coal fired unit 282 • Main steam pressure: 200 bar 2 • Rated load utilisation time: 4000 h/a • Fuel costs: 3.3 DM/GJ = 15 NOK/GJ • Rated load heat rate: 9 MJ/kWh 1 0.97 0 5 10 15 Throttle degree Dy (%)

Figure 5.2 Additional fuel costs Akpi due to increased unit heat rate

To calculate additional specific fuel costs, the relation between throttle degree Dy and available output increase APi is needed. The power increase that can be achieved within seconds with conventional units equipped with a reheater is about 40-50% of the throttle reserve, as only the HP section of the turbine reacts spontaneously [15]. The simplest choice is then to use the assumption: Af, = 0.5 ■ Dy (%) (5.2a)

Reference [38] gives a number of measurements and simulations of available output increase after 5 and 30 seconds, respectively, for different throttle degrees of the 600 MW basic unit. Plotting these values in figure 5.3, the following approximation seems to be more appropriate:

0.3 • Dy < AP. < 0.6 • Dy (%) (5.2b)

To approximate a possible variation area for the additional specific fuel costs, the maximum values from figure 5.2 are divided by the minimum values from figure 5.3 and vice versa. The result is shown in figure 5.4, with all examples of HP tur­ bine valve throttling as single action from reference [38] plotted with the same values for utilisation time, fuel cost and rated load heat rate as above. The differ­ ence between additional output available after 5 sec. and 30 sec. is also indicated in the figure, but does not display any systematic structure. For comparison are also the costs calculated with eq. (5.2a) shown as a shaded area.

89 5. Cost of spinning reserve in thermal power systems

Available output increase (%) 12 i------I dP(t=5) »600 MW coal fired unit » Main steam pressure: 200 bar ! dP(t=30) Approximation 0.3Dy - 0.6Dy

0-^------i.i 0 5 10 15 20 Throttle degree Dy (%)

Figure 5.3 Measured and simulated available output increase A P. (t) vs. throttle degree for 600 MW basic unit [38]

In the figure is also shown the specific primary reserve cost from a German 700 MW coal fired unit [59]. However, this value is probably based on the special price of German domestic pit coal of 10 DM/GJ which was effective until Janu ­ ary 1 1996. This so-called ‘Kohle-Pfennig ’ obligation is no longer valid.

Specific costs (1000 NOK/MW/year) dP(t=5) O dP(t=30) ♦ Approximation dP = 0.5 Dy (%) 0.3Dy - 0.6Dy

700 MW pit coal

0 10 20 30 40 50 60 70 Additional output (MW)

Figure 5.4 Additional specific operational costs of 600 MW basic unit when throttling HP turbine control valves

The throttling method is fairly simple to use and requires no additional invest ­ ments in the unit, but due to the heat rate increase it is still the most expensive of the possible methods. At present, it is reasonable to assume that the typical costs of primary control reserves in the German power system are described by the dot­ ted polygon of figure 5.4, but when the newer and more cost-effective methods come into use, the costs of primary control reserves can be reduced considerably.

Figure 5.5 shows the additional operational costs of the throttling method (including maintenance and abrasion) compared to the costs and investments of

90 5.1 Primary control in thermal power units the other possible methods described in ref. [38]. Average investments for over ­ load valves and preheater/condensate shut-off are in the range of 3.5 to 4.0 mill. NOK in both cases. The combined methods require the same investments as the preheater/condensate shut-off method. The different methods are described in Appendix 2 Primary control in thermal power units.

Specific costs (1000 NOK/MW/year) Throttling of HP valves

Preheat/Cond. shut-off

Overload valves

Combined methods

0 20 40 60 80 100 120 Additional output (MW)

Figure 5.5 Additional specific operational costs and investments of different methods for providing primary control reserves with a 600 MW coal fired unit

The most important factor for the level of the costs is the rated load utilisation time TNi. Figure 5.6 shows the consequences if the utilisation time is reduced to 1000 h/a or increased to 8000 h/a.

Specific costs (1000 NOK/MW/year) 1 000

Utilisation time: 8 000 h/year

• Main steam pressure: 200 bar • Utilisation time: 4 000 h/year • Fuel costs: 3.3 DM/GJ = 15 NOK/GJ • Rated load heat rate: 9 MJ/kWh

• Utilisation time: 1 000 h/year

0 60 6 Additional output (MW)

Figure 5.6 Examples of variation of specific reserve costs 5. Cost of spinning reserve in thermal power systems

5.1.2 Relocation costs

If unit i is operating due to economic dispatching at part load, the costs of provid ­ ing primary control reserves are related only to the unit itself, as described above. However, if the optimal dispatching should require the unit to operate at rated load, the reduced output due to the reserve provision have to be relocated to some of the other m units with available capacity.

This results is the additional relocation costs which are usually at least as high as the additional costs of the unit itself. These costs will be further studied in the fol­ lowing sections.

If there is insufficient available capacity within the control area, the deficit must be purchased from neighbouring areas or new capacity might even have to be built. Relocation costs due to purchase or additional investments in capacity will however not be further studied.

5.2 10 unit test system

To further analyse the costs related to primary and secondary control reserves in a thermal power system, a test system with 10 thermal units is constructed in an unit commitment optimization program based on the Shortest Path algorithm [56]. This algorithm has some numerical weaknesses, and cases where the algo­ rithm will fail to find the optimal solution might be constructed [57]. The effi­ ciency of the algorithm is also strongly dependent on the problem size; the analysis is thus limited to 10 units and 25 hours. In spite of these deficiencies the program is considered to be sufficient for the analyses made in this chapter.

Characteristic data for the 10 available units are taken from selected units in the German system [55], and is presented in table 5.1. Note however that the cold start costs used in reference [55] are low compared to values used by other sources [5, 74]. The reason for this difference is not considered.

Some characteristic aspects of a thermal system are important to keep in mind during the following analysis. If the fuel costs of the 10 units are pictured together as in figure 5.7, it can be seen that the units are located at certain “clus­ ters”, one for each fuel type and each unit type. The nuclear unit is cheapest and has the biggest output capacity, then follow the coal fired and gas fired conven ­ tional units, and finally the gas and oil turbines with the most expensive fuel and the lowest capacity. As the layout of thermal units and also the international fuel prices are rather uniform throughout Europe, the location of these clusters are generally applicable for most thermal systems.

92 5.210 unit test system

Cold start Heat rate at P Fuel cost l*min rmax cost rated load (MW) (MW) (NOK/GJ) (NOK) (GJ/MWh)

Nuclear 627 1255 7.88 98 831 10.00 Coal fired 1 124 275 14.85 37 407 9.14 Coal fired 2 229 508 14.85 67 523 8.96 Coal fired 3 146 325 14.40 42 451 9.07 Coal fired 4 317 705 14.40 85 176 8.39 Gas fired 1 123 350 24.53 77 254 8.98 Gas fired 2 218 622 24.98 139 810 9.02 Gas turbine 1 18 51 24.53 3 188 12.93 Gas turbine 2 20 56 24.75 3 218 13.03 Oil turbine 30 87 40.50 4 374 10.72

Table 5.1 Main data for 10 unit test system (1 DM - 4.5 NOK) [55]

Fuel cost (1000 NOK/MWh) 0.60 r

T 87 MW Oil turbine • ~ 51 MW Gas turbine 1 56 MW Gas turbine 2 350 MW Gas fired 1 622 MW Gas fired 2 275 MW Coal fired 1 508 MW Coal fired 2 325 MW Coal fired 3 & A 705 MW Coal fired 4 0.20 1255 MW Nuclear

-e-e-

0.001—'------'------!----- 1------1------'------'------1------1 0 400 800 1200 1600 Unit capacity (MW)

Figure 5.7 Fuel costs of test system units

Thus, when the system is gradually loaded the system marginal cost shown in figure 5.8 is not a continuous curve, but has discrete steps each time a new kind of unit or fuel is committed. The size of the spinning reserve costs are thus strongly dependent on whether the reserve can be kept in units of a kind already committed, or if the reserve provision causes a new kind of unit to be committed.

93 5. Cost of spinning reserve in thermal power systems

Marginal cost (NOK/MWh) 500 Nuclear Coal fired Gas fired Gas turbine Oil turbine 1 ■ □ • O * ■ | 400 ■ 300

200 #######**#######$**** 100 mumrai 0 1000 1500 2000 2500 3000 3500 4000 4500 System load (MWh/h) Figure 5.8 Marginal cost of test system

In the following analyses load curves for both heavy load (winter Monday) and low load (summer Tuesday) situations are used. The curves are scaled down to the test system size (1:3) from actual load curves used in reference [55], and are shown in figure 5.9. Note that the load variation at heavy load and low load are nearly equal, only the level of the load is different. Note also that to get equal starting and ending conditions, the analyses comprise 25 hours instead of 24.

System load (MW) 3 500 Heavy load

Low load 3 000 -

2 500

2 000 -

1 500 -

1 000

Figure 5.9 Heavy and low load situations in test system

The results of an unit commitment optimization made for the two load situations without spinning reserve requirements are shown in figures 5.10 and 5.11. Dur­ ing heavy load all coal fired units and one gas fired unit have to be committed, while during low load it is sufficient to commit 3 coal units plus one gas turbine in the peak hour. The nuclear unit runs as base load in both cases. The total oper ­ ational costs for these two cases as indicated in the figures are chosen as base costs in the following sections.

94 5.2 10 unit test system

Unit load (MWh/h) 4 000

3 000

2 000

1 000

13 5 7 11 13 15 17 19 21 23 25 Hour Operational cost: 8 025.15 kNOK

Figure 5.10 Unit commitment for heavy load situation without spinning reserve

Unit load (MWh/h) 4 000 ■ Gas turbine 1 ■ Coal fired 2 □ Coal fired 3 3 000 □ Coal fired 4 ■ Nuclear

2 000

1 000

1 3 5 7 9 11 13 15 17 19 21 23 25 Hour Operational cost: 5 496.02 kNOK

Figure 5.11 Unit commitment for low load situation without spinning reserve

To verify the realism of these daily operational costs, a rough estimate of total annual operational cost for the 10 unit test system can be calculated as:

8025.15 + 5496.02 24 ■ 365 = 2368.9 (MNOK/year) (5.3) 2 ' 25 while estimated annual operational cost of the real German utility of reference [55] is 6903 MNOK/year, which scaled down to the test utility size (1:3) is 2301 MNOK/year.

The system marginal cost (MC) is plotted for these two load situations in figure 5.12 together with the respective load curves. Related to figure 5.8 the general observation can be made that the marginal cost steps between the coal unit range and the gas fired unit range one or more times each day. (In the low load situation

95 5. Cost of spinning reserve in thermal power systems the MC is actually down in the nuclear unit range during the night and up into the gas turbine range at the peak hour.) Note that the small load variation in the after­ noon in the heavy load case is enough to cause the MC to step down to the coal fired range for three hours.

The levels of the marginal cost ranges are thus not dependent on the system load, just the duration of the stay at each range and the frequency of the steps between the ranges. This observation is also confirmed by similar analyses made on a large German utility in reference [55], and by reference [74].

Heavy load Low load Marginal cost (NOK/MWh) Marginal cost (NOK/MWh)

150 '

100 -

Figure 5.12 Test system marginal costs without spinning reserve with daily load profile indicated

5.3 General spinning reserve requirements

In this section initial analyses will be made for what might be called general spinning reserve requirements. The general spinning reserve requirement is only stated as a percentage of load without considering whether it is relocated primary reserve or secondary reserve. In reality, the different “types ” of spinning reserve have to be committed in different ways, and will be treated in section 5.5.

If a utility have hydro power units available, normally as much as possible of the reserves are allocated to these as hydro power units are considered a nearly free production source with ideal control characteristics compared to thermal units (with the exception of run-of-river power plant). As the purpose of this section is to examine costs of spinning reserve in thermal power systems, no hydro units are included in the test utility used in this study.

96 5.3 General spinning reserve requirements

5.3.1 “Optimal ” dispatch of reserve

The traditional way for an unit commitment program to handle the reserve requirement is to ensure that the total committed generation capacity is a fixed percentage or fixed amount higher than the demand. Thus, presuming that the total generation equals total demand for each hour:

n E Pft) = D{t) (5.4) i = 1 where n - number of generation units Pt(t) - production in unit i in time interval t (MWh/h) D(t) - total power demand in time interval t (MWh/h), the spinning reserve requirement can be expressed as [56]:

J,PiN-Xi(t) > D(t)+R(t) = (1 +pR)-D(t) (5.5) i= 1 where PiN - rated output of unit i (MWh/h) Xrft) - decision variable of unit i in time interval t ('/'=> unit committed, ‘0’ => unit de-committed) R(t) - required spinning reserve in time interval t (MWh/h) pR - spinning reserve fraction.

A down ramping reserve can be specified in a similar way, but is normally not included in the optimization since there usually is sufficient down ramping capacity in the system. This can be ensured by manual inspection of the optimi ­ zation result.

When specifying the required reserve from 5 to 20% in the two load situations, the daily operational costs will increase as shown in figure 5.13, where the costs of figures 5.10 and 5.11 are used as reference.

As might be expected, the costs of the heavy load situation rises gradually as more and more units have to be committed to fulfil the reserve requirement, but the stepwise cost increase of the low load situation needs to be explained. The reason is however obvious when remembering the fuel cost clusters of figure 5.7.

In the low load situation, both the 5% and 10% reserve requirement can be ful­ filled with coal fired units of the same “cost cluster” as those already committed in the base case without reserve. Only at the 15% reserve case the first gas fired unit GF1 has to be committed, increasing the costs considerably. Also, at the

97 5. Cost of spinning reserve in thermal power systems

20% case the low load situation manages with the single gas fired unit, while at the heavy load situation both gas fired conventional units and a gas turbine have to be committed. Thus, the increase in operational costs due to reserve require­ ments is dependent on the number and size of units of each kind available in the system.

Note however that the relative increase in operational costs is fairly equal in both the heavy load and the low load situation.

Operational costs (pu) No reserve

Optimal dispatch: Heavy load

Low load

Spinning reserve (%)

Figure 5.13 Relative operational costs as function of general spinning reserve requirements

The required reserve is dispatched optimally between the units, resulting in the cheapest units being fully loaded while the most expensive units are operated at minimum or low load, carrying the reserve. As an example, figure 5.14 shows the situation for 10% spinning reserve at heavy load, presented such that the reserve is allocated to respective units. The 4 coal fired units are fully loaded most of the peak load period, while the reserve requirement is fulfilled by operating the large gas fired unit GF2 at minimum load. Similar figures could be shown for all val­ ues of reserve.

Plotting the system marginal cost for the 10% spinning reserve requirement at both load situations in figure 5.15, the same observation can be made as above: The levels of the MC ranges are not influenced by either the load level or the reserve requirement, only the duration of the stay at each range and the frequency of the steps between the ranges. In this particular case, the MC at low load actu­ ally avoids the step up to gas turbine range and stays down in the coal unit range, as one gas fired unit is instead committed during the peak load hours. As this unit runs on minimum load to carry the spinning reserve, it is not determinant for the MC.

98 5.3 General spinning reserve requirements

Unit load (MWh/h) 4 000 E3 Gas turbine 2 ■ Gas turbine 1 □ Gas fired 2 □ Coal fired 1 3 000 U Coal fired 2 G Coal fired 3 0 Coal fired 4 2 000 ■ Nuclear □ Spinning reserve

1 000

0 13 5 7 11 13 15 17 19 21 23 25 Hour Operational cost: 8225.82 kNOK

Figure 5.14 “Optimal ” dispatch of 10% spinning reserve at heavy load

Marginal cost (NOK/MWh) 10% reserve: Heavy load 220

200 - Low load

12° Vwt

Figure 5.15 Test system marginal cost at “optimal ” dispatch of 10% spinning reserve

The problem is that such an “optimal ” dispatch of the required reserve never will occur in a real system. As explained in Appendix 2, not all thermal units are suited for the provision of spinning reserve. Also, the reserve provision might require investments in the unit, and the reserve have to be available all the time. Thus, the reserve is usually allocated to intermediate load units which are in operation most of the time, usually coal or gas fired conventional units. In the case of secondary reserve, also ramping ability is an important factor in the choice of reserve units. E.g. gas turbines are never used for primary control, but might be used as fast startable tertiary reserve.

This implies that the “optimal ” dispatch of reserve which is made above with the unit commitment program does not give a correct picture of the operational costs related to spinning reserves. The values given in figure 5.13 might however be seen as an ideal, minimal value of the reserve costs in this system.

99 5. Cost of spinning reserve in thermal power systems

5.3.2 “Manual ” dispatch of reserve

To see how the reserve costs change when a more realistic dispatch of the reserve is used, a new series of analyses are made in which the necessary amount of reserve is allocated manually to the coal fired - and in some cases also the gas fired - conventional units. In the simulations this is done by reducing the maxi­ mum unit capacity given as input to the optimization program with a certain per ­ centage, ensuring manually that the resulting reserve capacity for each hour is sufficient, while the original general reserve requirement is set to zero. Some units now have to be manually committed to fulfil the reserve requirement for all hours, and the solutions found are no longer optimal. However, several reserve allocations are tried in each case to find a favourable solution.

As an example of this “manual ” reserve dispatch, the same situation of 10% spin ­ ning reserve at heavy load from figure 5.14 is shown again in figure 5.16. A cer­ tain capacity is now “reserved” in the coal fired units as spinning reserve, while the production deficit is relocated to the more expensive gas fired unit GF2. The increased operational costs compared to the “optimal ” dispatch solution is caused mainly by a relocation of the generation from coal to the already committed gas fired unit, but in some hours also the unit combination changes.

Unit load (MWh/h) Gas turbine 1 Gas fired 2 Coal fired 1 Coal fired 2 Coal fired 3 Coal fired 4 Nuclear Spinning resen/e

13 5 7 11 13 15 17 19 21 23 25 Hour Operational cost: 8 475.65 kNOK Figure 5.16 “Manual ” dispatch of 10% spinning reserve at heavy load

Again, the system marginal cost steps between the coal and gas fired unit ranges at heavy load, but stays in the coal fired range at low load. Thus, the MC levels are independent also of how the reserve is allocated in the system.

100 5.3 General spinning reserve requirements

Marginal cost (NOK/MWh) 10% reserve: Heavy load

Low load

0 0 0

Figure 5.17 Test system marginal cost at “manual ” dispatch of 10% spinning reserve

The relative increase in operational costs due to this “manual ” reserve dispatch is shown in figure 5.18. As expected, the costs at heavy load show a considerable increase as most of the reserve capacity now is relocated from the gas fired to the coal fired units. However, in the low load case there is still room for a lot of the reserve among the coal fired units, and a “manual ” redispatch does not increase the costs considerably compared to the previous “optimal ” dispatch.

Operational 1.08 ------No reserve

Optimal dispatch: Heavy load

Low load

Manual dispatch: Heavy load

Low load

0 5% 10% 15% 20% Spinning reserve (%)

Figure 5.18 Relative operational costs as Junction of spinning reserve requirements at “manual ”dispatch

Note also that as the reserve requirement increases, the increased costs at the two dispatching alternatives converge toward the same values as the possible alterna ­ tives for allocating the reserve are limited by the total system capacity.

101 5. Cost of spinning reserve in thermal power systems

5.4 Specific system reserve costs

For comparison with the specific additional unit reserve costs given in figure 5.5, it would have been beneficial to represent the additional system operational costs of figures 5.13 and 5.18 in a similar way. This has however proved to be difficult. The increase in operational costs due to the spinning reserve requirement is caused by the capacity relocation ; between already committed units or by com­ mitting new and more expensive units, but in general there is no correspondence between the reserve requirement and the amount of capacity which has to be relo­ cated in any specific hour. This will be explained in the following.

5.4.1 Specific reserve costs at “optimal” dispatch

A reference operational cost C°(t) in (NOK/h) without reserve requirement is found for each hour from the optimizations of figures 5.10 and 5.11. In the “opti ­ mal dispatch ” case a general reserve requirement pR is then set, and a new opti ­ mization is made to obtain a new operational cost 0(1). By studying the result hour by hour, it can bee seen how the capacity relocation decides the additional costs: a) The reserve requirement is already covered by the initial unit configuration, and there is no need to commit new units. Thus, there is no capacity reloca­ tion and no increase in operational cost:

I-P-AT• x)(t) = • x°(f) => Prel(t) = 0, c*(t) = d>(t) i i b) When the reserve requirement is not covered by the initial unit configura ­ tion, the most common alternative is to commit a new and more expensive unit j. This unit is committed only to carry the reserve, and the other units from the initial configuration has to reduce their output to allow this unit to operate at minimum load (“optimal ” dispatch). Thus, the minimum capacity of the new unit has to be relocated from the initial units to this more expen ­ sive unit, and the operational cost increases: gy . X°(f) + P.* => W C'W > i i Further alternatives are mostly variations of alternative b): Starting more than one new unit, starting one bigger unit while simultaneously stopping one of the initial units etc. In addition, some special cases might occur, e.g. when an unit has to run due to minimum up-time requirement in an hour where its capacity is not needed.

102 5.4 Specific system reserve costs

However, as stated initially, although the amount of relocation decides the increase in operational costs there is no correspondence between the reserve requirement and the relocated capacity. Thus, when the hourly additional costs are divided by the reserve requirement to obtain specific costs:

AC(f^(r)) A c(t) (NOK/MWh) (5.6) a(f) R(t) there is no systematic distribution of the costs, as can be seen in figure 5.19. Note also from eq. (5.6) that possible start-up costs are excluded from the hourly cost. Start of one or more units might be moved from one hour to another by the reserve requirement without changing the daily operational cost, while new units being committed would increase this cost. Thus, it does not make sense to include start-up costs when regarding the hourly costs.

Additional cost (NOK/MWh) 100

80

60 0 ©

40 o S

oo °«>o

% °o ..A... 0 o 20 ' 8% ...... : %% o % s % 0

-20 0 100 200 300 400 500 600 700 Reserve requirement (MWh/h)

Figure 5.19 Specific additional hourly system reserve costs at “optimal ” dispatch, heavy load

One could have expected that there were some connection between these specific reserve costs and the marginal cost of the units or the system, but this is not the case. If the costs of figure 5.19 are sorted in accordance with which kind of unit is the most expensive in that particular hour, this does not yield much additional information, as shown in figure 5.20. The only interesting observation is that as long as the capacity relocation stays among the coal fired units, the specific costs seem to stay mostly within the coal fired marginal cost range as indicated in the figure. (The difference in MC between the cheapest and the most expensive of the coal fired units from figure 5.8 is 18 NOK/MWh.) However, when some capacity is relocated from one kind of units to another, there is no systematic pat ­ tern observable.

103 5. Cost of spinning reserve in thermal power systems

Additional cost (NOK/MWh) Coal fired

MC range Coal

Gas fired

Gas/Oil turbine □

40 -

0 300 400 5 Reserve requirement (MWh/h)

Figure 5.20 Specific additional hourly system reserve costs at “optimal ” dispatch, heavy load

This observation is even more apparent for the low load case, as shown in figure 5.21. In this case, the necessary reserve stays mostly among the coal fired units as explained in the previous section, and the specific additional costs stays mainly within the coal fired MC range of 18 NOK/MWh.

Additional cost (NOK/MWh) Coal fired

MC range coal

Gas fired

Gas/Oil turbine

-20 -

-40 -

200 300 400 Reserve requirement (MWh/h)

Figure 5.21 Specific additional hourly system reserve costs at “optimal" dispatch, low load

In the low load case there are even some hours with negative additional cost. This is due to some specific hours where a new unit configuration is actually cheaper than the situation without reserve requirement (although the total daily cost increases). This is e.g the case with the peak load hour 12 (see figure 5.11) which requires a gas turbine in the no reserve case, but when a 5% reserve requirement is introduced a new coal fired unit is committed and run during hours 10-16.

104 5.4 Specific system reserve costs

5.4.2 Specific reserve costs at “manual” dispatch

Looking now at the “manual ” way of dispatching the reserve, the logic for decid­ ing the capacity relocation is quite different from the one explained above.

The same initial unit commitment optimization without reserve requirement is used as the hourly reference operational cost cP(t). However, instead of setting a general reserve requirement pR, the initial unit rated load given as input to the unit commitment program is reduced manually with a fixed amount P*f res to simulate the capacity which has to be reserved for reserve purposes:

Xp) N x}m = i x?«) (5.7)

A new optimization is then made to obtain a new operational cost C2(t) with reduced available capacity but without a general reserve requirement. Then the result is inspected manually to ensure that the available capacity for all hours is sufficient to cover the same reserve requirement as in the “optimal ” dispatch case:

(5.8)

There is not necessarily any change in unit configuration; the final set of commit­ ted units might be the same as the initial one:

{Pi{t)}2 = {?,(,)}! = {P;(t)}°

If the reserve requirement is not satisfied, the amount of reserved capacity '^_,P!fres is increased and a new optimization is made. Note that the amount of reserved capacity does not have to be equal to the reserve requirement for all hours, as there often are additional reserves in the system due to units operating below rated load.

By studying the result hour by hour, it can bee seen that the capacity relocation now occur quite differently than in the previous “optimal ” dispatch case: a) If the optimal output of a unit i carrying reserve is lower than the new rated capacity, there is no capacity relocation from that unit:

=> Pi,rel (X>=° b) If the optimization runs unit i at rated capacity, the optimal solution is lim­ ited by the reduced available capacity, and the reserved capacity have to be relocated to another unit:

105 5. Cost of spinning reserve in thermal power systems

P/(0 - Pm _> Pi,rel -rfres’

assuming that the initial optimal solution without reserve requirement does not lie between the reduced and the initial rated output. This has not been found to occur in these simulations:

e (P^.P%)

The total relocated capacity for that specific hour is then the sum of relocation from each controlled unit:

=X*W«)i (5-9) Although the capacity relocation occurs quite differently at “manual ” dispatch than “optimal ” dispatch, there is no new information to gain from a plot of spe ­ cific hourly values, as shown in figure 5.22.

Additional cost (NOK/MWh) Coal fired □ MC range Coal

Gas fired B * Gas turbine X □ * m * ^ 1 am n □ * < * V 'm ... 0 100 200 300 400 500 600 700 Reserve requirement (MWh/h)

Figure 5.22 Specific additional hourly system reserve costs at “manual ” dispatch, heavy load

5.4.3 Daily average costs

Another possible approach which has been tried is to compare the daily addi­ tional specific costs (total daily costs divided by the reserve requirement and 25 hours) to the daily average reserve requirement, as shown in figure 5.23. In this case are also the start-up costs included in the daily operational costs, but there is still no apparent connection between reserve requirement and additional opera ­ tional costs.

106 5.4 Specific system reserve costs

Additional cost (NOK/MWh) 80 Heavy load ♦ -....O* ■ Low load ♦ O ♦ ...... * ...... 0 ♦ ♦ ♦ 0 0...♦__ 0 0 0 __ 1______!__ ,__ 100 200 300 400 500 Average reserve req. (MWh/h)

Figure 5.23 Daily additional specific reserve costs incl. start-up costs at both heavy and low load and “optimal ” and “manual ” dispatch

Finally, to simulate the substitution of thermal spinning reserve by HVDC reserve capacity, the original spinning reserve requirements are reduced by a cer­ tain amount of MW which would be provided by the HVDC connection. New unit commitment analyses are then made with “manual ” dispatch of the reserve, fulfilling the reduced reserve requirement for each hour. The reserves are reduced in steps of 100 MW.

Dividing the reduced daily operational costs by the HVDC reserve capacity and 25 hours, the specific reduced costs as function of HVDC reserve capacity (not reserve requirement) are found as shown in figure 5.24. But also in this case no systematic connection between reduced costs and relocated capacity can be found. The falling tendency shows only that the cost reduction increases less than the amount of reserve capacity in the HVDC connection.

Reduced cost (NOK/MWh) 5 % reserve ♦ 10 % reserve O 15 % reserve * 20 % reserve

0 100 200 300 400 500 600 700 HVDC reserve capacity (MW)

Figure 5.24 Reduced operational costs due to HVDC reserve capacity

107 5. Cost of spinning reserve in thermal power systems

In all previous figures of operational costs vs. capacity there appear to be a con ­ vergence towards a value of 30-40 NOK/MWh (in the heavy load case). This is however only the maximum daily cost increase (at 20% spinning reserve) divided by maximum reserve requirement. These “maximum” values are summarised in table 5.2.

c (20%) -cr Ac (NOK/MWh) (5.10) max 25

Heavy load Low load (NOK/MWh) (NOK/MWh)

“Optimal” dispatch 27.75 19.29 “Manual” dispatch 35.04 20.15

Table 5.2 Values of maximum cost increase divided by maximum reserve requirement

As an additional comment, if the hourly additional operational costs are divided by the relocated capacity instead of the reserve requirement, the resulting spe ­ cific costs are as might be expected the difference in operational costs of the units between which the capacity is relocated.

5.4.4 Comparison of specific reserve costs

The somewhat disappointing conclusion to this section has to be that no direct connection between the reserve requirement and the increased operational costs due to this reserve requirement have been found in this study.

A very low estimate of the cost of general spinning reserves can be found by assuming that most of the reserve relocation occurs among the coal fired units (see figures 5.20 to 5.22). The specific cost can then be estimated to 18 NOK/ MWh. Similarly, a very high estimate of this cost is to use the highest value of 35.04 NOK/MWh from table 5.2. By calculating “low” and “high ” annual values based on these two alternatives (for 8760 h/year), the cost of general spinning reserve can be compared to specific unit costs from figure 5.5, as shown in figure 5.25. Note that the total additional operational cost is the sum of unit cost and spinning reserve cost.

In reference [55] extensive unit commitment optimizations are made with a large (hydro-) thermal German utility. By introducing a pumped storage co-operation with Norway with a capacity of 1000 MW, operational costs in the German utility are reduced typically 1.3 MDM/week, which amounts to 304.2 kNOK/MW/year,

108 5.5 Example: System reserve costs according to UCPTE recommendations nearly equal to the highest spinning reserve cost. Also, if 1000 MW capacity was used solely for import to the German utility, a typical reduction of operational costs is 5 MDM/week, or 1170 kNOK/MW/year. For comparison are also these specific values shown in figure 5.25. Note that increased or reduced investment costs are not considered in this comparison.

Specific costs (1000 NOK/MW/year) 2 000 Net import

1 000 Pumped storage

■High- spinning reserve

"Low- spinning reserve

Specific unit costs Primary reserves

Additional output (MW)

Figure 5.25 Comparison of specific operational costs

It seems that a net (contractual) export to the thermal system results in the largest reduction of operational costs. Note that the specific operational costs as shown in figure 5.25 are Calculated from the thermal system alone as rough estimates of the possible value of the HVDC capacity. Provision of one of more of these alter­ natives introduces costs also in the sending (Norwegian) system. In addition, the losses in the HVDC connection itself have to be covered by one or both of the interconnected partners. For the 1000 MW Skagerrak connection between Nor­ way and Denmark (124 km), the losses are calculated to 3-7 NOK/MWh [74].

5.5 Example: System reserve costs according to UCPTE recommendations

The approach of the previous section to find a general way to estimate spinning reserve costs in thermal power systems from unit commitment analyses was not very successful. Thus, in this section an attempt is made to use the unit commit­ ment framework as a tool to imitate the reserve allocation in a real power system to gain an understanding of the different cost elements and their respective sizes. The fact that the technical aspects of the different kinds of reserve are not very well handled by the unit commitment program, makes it necessary to include a lot of manual actions, which will be further explained below. The results obtained in this section must therefore be viewed only as illustrations, and cannot be trans ­

109 5. Cost of spinning reserve in thermal power systems ferred to other and larger systems without careful consideration.

5.5.1 Primary control reserves

According to current UCPTE recommendations as presented in Appendix 1 Interconnected system reserve recommendations each partner or control area has to provide at least 2.5% of instantaneous total generation as primary control reserve. Depending on how many units within a defined area which are actually taking part in primary control, the requirement for each unit might differ from area to area. In the 10 unit test system used in this analysis the degree of freedom when locating the required reserve is very limited.

Assuming that the method of providing primary control reserves by throttling HP turbine control valves is used, an unit which has to supply 2.5% of rated load as primary control reserve has to throttle approximately 5% of rated load for this purpose when the simplest relation between throttle degree and available output increase is used (eq. 5.2a). Note that the general spinning reserve requirement which is treated in section 5.3 is actually available unit capacity, which is not necessarily available for primary control in the seconds range. The unit will not be able to supply more than the 2.5% primary control reserve even when it is run ­ ning on 50% load. Actually, if the unit is operated with a constant throttle degree over the load range (eq. A2.1a) the available reserve is reduced when the unit load is reduced. This is however not considered in the following.

When the system requirement is 2.5% of instantaneous generation, the (general) reserve requirement to be fulfilled in the unit commitment program is thus approximately 5% throttle reserve for each hour. As much as possible of the reserve is placed in the coal fired units, and the few units running during low load hours have to carry a relatively large amount of reserve. The resulting reserve allocation for the heavy and low load cases are shown in table 5.3, where the relocated capacity from each unit range from 5% to 12% (2.5% to 6 % available for primary control). It is assumed that the throttle degrees are not changed dur­ ing the day. As an illustration, figure 5.26 shows the primary reserve allocation among the 10 units for the heavy load case.

The specific additional unit reserve costs occurring in each unit are estimated in section 5.1.1 (figure 5.5) for coal fired units, and lie typically between 50 and 200 kNOK/MW/year. From table 5.1 it can be seen that the heat rate of conventional gas fired units is fairly equal to the heat rate of coal fired units, while the fuel costs are related typically 25:15. Thus, assuming that the heat rate increase due to HP valve throttling is independent of type of fuel, specific additional costs for gas fired units lie typically between 80 and 330 kNOK/MW/year.

110 5.5 Example: System reserve costs according to UCPTE recommendations

To find a possible variation of the specific unit costs due to the reserve provision, both minimum and maximum values from the polygon of figure 5.5 are used to calculate the total annual costs. Note that the values from figure 5.5 as given in table 5.3 are related to the actual available primary reserve, while the relocation costs calculated below are related to the relocated capacity (shaded) due to the reserve provided in each unit.

Capacity (MW) 1 400 i------Legend:

1 200 H

1 000

800

600

400

200 0 N CF1 CF2 CF3 CF4 GF1 GF2 GT1 GT2 OT Units

Figure 5.26 Primary reserve allocation at heavy load

Heavy load Low load

Reserve Additional cost Reserve Additional cost (MW) (kNOK/MW/year) (MW) (kN OK/MW/year)

Rel. Prim Rel. Prim Min Max Min Max cap. res. cap. res.

Coal fired 1 20 10 201.54 218.31 26 13 146.17 213.25 Coal fired 2 24 12 164.63 214.94 - - - Coal fired 3 30 15 109.26 209.88 30 15 109.26 209.88 Coal fired 4 70 35 53.11 148.92 86 43 52.73 108.20 Gas fired 1 23 11 305.15 361.05 Bill - - - TOTAL 167 83 10845 17093 ' 142 71 5806 10573

Table 5.3 Primary control reserve allocation and possible variation of specific addi ­ tional unit costs due to the reserve

111 5. Cost of spinning reserve in thermal power systems

Without examining detailed annual load curves for European countries, it is very difficult to relate these two casually chosen heavy load and low load cases to total increased annual operational costs. For illustration, the two different load levels will be treated separately instead of making some kind of annual average.

Moving now to the relocation costs, the (shaded) relocated capacity of table 5.3 have to be considered. Unit commitment optimizations are now made with this relocated capacity manually dispatched. Using the no reserve operational costs of figures 5.10 and 5.11 as reference, table 5.4 shows total and additional daily costs which arise due to the reserve requirement.

Heavy load Low load (kNOK/day) (kNOK/day)

Operational cost w/Prim. reserve 8 216.68 5 554.46 Increased cost due to Prim, reserve 191.53 58.44

Table 5.4 Daily operational costs due to UCPTE primary reserve requirement

A very rough estimate of the annual relocation cost due to the UCPTE primary control recommendation could be found as an average of the two load situations. Instead, by calculating annual costs both based on the heavy load situation and the low load situation, “high ” and “low” values of annual costs can be found (corrected for the 25 hour simulation):

24 191.53 •365 = 67112.1 (kNOK/year) ' 25 (5.11a) 24 58.44 • • 365 = 20477.4 (kNOK/year) (5.11b) 25

As an additional comment related to the previous section; by calculating an approximate annual cost as the average of the values above and dividing by the average hourly reserve requirement of 126 MW, the specific cost of 39.68 NOK/ MWh is found.

It is important to remember that the total additional system operational costs due to the UCPTE primary control recommendations is found as the sum of the spe ­ cific unit costs and the system relocation costs. Figure 5.27 shows the different cost elements and the estimated variation in reserve costs when “high ” and “low” annual values are calculated both based on the low load and the heavy load case.

112 5.5 Example: System reserve costs according to UCPTE recommendations

Annual reserve cost (Mill NOK/year) 100 i------Primary reserve □ relocation cost Unit primary 80 77.96 reserve cost

60

40 31.05 26.59

20

0 Heavy load Low load

Figure 5.27 Additional annual operational costs due to UCPTE primary reserve recommendation

5.5.2 Secondary control reserves

In addition to primary control reserves, each control area in the UCPTE system has to provide a recommended amount of secondary control reserves of :

(MW) (5.12)

During periods with large load changes twice this value is recommended. Table 5.5 shows the respective values for the 10 unit test system.

^max min max Heavy load 3 333 173 346 Low load 2 844 160 320

Table 5.5 Maximum and minimum recommended values of secondary reserve (MW)

Generally, the secondary control reserve should also be able to compensate for loss of the largest production unit in the area. However, this requirement would be unrealistic as the biggest unit in the test system is the 1255 MW nuclear unit, covering more than 30% of the maximum load. If such a reserve deficit should occur in a real system, the missing capacity have to be covered by the tertiary reserve. As this reserve does not have to be spinning reserve, and does not have to be located within the actual control area, it will normally not contribute to the operational costs. The need for tertiary reserve might of course cause investment costs, and a possible stand-by compensation to neighbouring control areas, but this will not be further studied here.

113 5. Cost of spinning reserve in thermal power systems

Even more than the primary control reserve, the secondary control reserve requires technical installations in the unit. The ability of a unit to take part in sec­ ondary control cannot be turned on and off during the day, and the unit has to run in control mode for a longer period of time. The unit might however be stopped and started in the normal way according to system needs. This indicates that the typical unit commitment “optimal behaviour ” as illustrated in figure 5.14 where spinning reserve is moved from unit to unit during the day according to opera ­ tional costs is clearly unrealistic. Thus, an unit which is chosen for secondary control operation with available output reduced accordingly, have to run in this mode as long as it is in operation.

Another aspect when looking at the system demand curves of figure 5.9, is to decide when the load change is large enough to qualify for the double reserve requirement of table 5.5. The UCPTE recommendations do not give any measure or indication of how this can be decided, e.g. in a certain percentage of maximum load. Thus, in these simulations a “sensible rule of thumb ” has been used, between load change, reserve requirement and operational costs.

Looking first at the heavy load case the minimum secondary reserve requirement of 173 MW must be fulfilled for all hours. This reserve must be placed in one of the units which are running during the whole day, and the large coal fired unit CF2 is selected. (CF4 has slightly lower operational costs, and placing the reserve in CF4 would increase the reserve costs somewhat.) As opposed to the primary reserve, all available capacity of the unit can be counted as secondary reserve. Thus, in the low load hours the available secondary reserve might be considerably higher than the requirement.

From figure 5.9 it can be seen that the largest load changes occur during hours 6 - 8,17-18, 19-21 and 23-25, but are the changes large enough to require the double amount of reserve? Clearly, the hours 6-8 need the highest reserve, but in hour 6 unit CF2 already provides 250 MW reserve, while the amount is down to 173 MW in hour 7 due to the load increase. Thus, the large gas fired unit GF2 is com­ mitted in hour 7 (instead of unit GF1 in the only primary reserve case) and run through hours 7 to 24, carrying both primary and secondary reserves.

However, as most of the primary reserve is located in the coal fired units, the large gas fired unit also has to supply the relocated capacity. The secondary reserve of GF2 is thus counted as available capacity for each hour. Manual inspection ensures that sufficient secondary reserve is provided for each hour by the “base” reserve of 173 MW in CF2 and residual reserve in GF2. In hour 12 the secondary reserve left in GF2 is actually down to 17 MW, but as the load change in this hour is small, the minimum reserve of 173 MW in CF2 is sufficient.

114 5.5 Example: System reserve costs according to UCPTE recommendations

In the afternoon the available capacity of GF2 is far higher than the requirement. In reality, the reserve carried by CF2 could then have been reduced for some hours by manually dispatching the unit with higher load. This behaviour is how ­ ever not possible to imitate with the current unit commitment program, thus it is assumed that the reserve requirement is not changed during the day.

The same manual approach is used in the low load case, causing GF1 to be com­ mitted in hours 6-12 to carry both primary and secondary reserves. In this case the base reserve of 160 MW have to be placed in unit CF4 as this is the only unit running during the whole day except the nuclear unit - which should not be used for reserve purposes.

The total reserve allocation for both load cases are shown in table 5.6, while the figures 5.28 and 5.29 show the resulting system operation with both primary and secondary reserves indicated. Note that as the unit configuration is changed com­ pared to the previous case with primary reserve only, there are also some changes to the primary reserve allocation. Especially, in the low load case the sum of pri ­ mary reserve is higher than in table 5.3 because some of the units carrying the reserve will run for a few hours only.

Heavy load Low load

Primary res. Secondary res. Primary res. Secondary res. (MW) (MW) (MW) (MW)

Coal fired 1 - - 15 - Coal fired 2 25 173 25 - Coal fired 3 30 - 15 - Coal fired 4 70 - 85 160

Gas fired 1 - - 25 A P

Gas fired 2 42 A P - -

TOTAL 167 173 + A P 165 160+ A P

Table 5.6 Allocation of primary and secondary reserves

Table 5.7 shows the operational costs with both primary and secondary reserves included, compared to the previous case with only primary reserve and to the basic no reserve case.

115 5. Cost of spinning reserve in thermal power systems

Unit load (MWh/h) Gas fired 2 Coal fired 1 Coal fired 2 Coal fired 3 Coal fired 4 Nuclear Secondary reserve Primary reserve

1 3 5 7 9 11 13 15 17 19 21 23 25 Hours Operational cost 8 583.97 kNOK

Figure 5.28 Heavy load unit commitment with primary and secondary reserves according to UCPTE recommendations

Unit load (MWh/h) 4000 i------□ Gas fired 1 O Coal fired 1 H Coal fired 2 □ Coal fired 3 □ Coal fired 4 ■ Nuclear □ Secondary reserve IS Primary reserve

Operational cost: 5 770.81 kNOK

Figure 5.29 Low load unit commitment with primary and secondary reserves according to UCPTE recommendations

Heavy load Low load (kNOK/day) (kNOK/day)

Operational cost w/ P+S reserve 8 583.97 5 770.81 - Operational cost w/ P reserve 8 216.68 5 554.46

= Increased cost due to Sec. reserve 367.29 216.35 + Increased cost due to Prim, reserve 191.53 58.44 = Total increase due to P+S reserve 558.82 274.79

Table 5.7 Increased operational costs due to Primary and Secondary reserves

116 5.5 Example: System reserve costs according to UCPTE recommendations

As for the primary reserve case in eq. (5.11a/b), “high ” and “low” values of annual cost increase due to secondary reserve can now be calculated as:

367.29 • g • 365 = 128.70 (MNOK/year) (5.13a)

24 216.35 - g - 365 = 75.81 (MNOK/year) (5.13b)

Total “high ” and “low” increase of annual operational costs due to the UCPTE reserve recommendations applied to the 10 unit test system are shown in figure 5.30. More generally useful numbers can be found in figure 5.31 where these costs are given relative to the estimated total annual operational cost of:

8583.97 + 5770.81 24 365 = 2515.0 (MNOK/year) (5.14) 2 25

Annual reserve cost (Mill NOK/year) Secondary reserve cost 212.90 Primary reserve relocation cost 200 □ Unit primary reserve cost

102 40 106.86 100

Heavy load Low load

Figure 5.30 Total annual increase of operational costs due to UCPTE reserve recommendations applied to the 10 unit test system

Similar analyses made in reference [77] show relative reserve costs of compara ­ ble size: Annual costs of primary control reserves are calculated to approximately 1.3% of total annual operational costs, while costs of secondary control alone are calculated to approx. 2.8% at minimum reserve requirement (3 jDmax ), increas- ingto5.4%at5jD^.

117 5. Cost of spinning reserve in thermal power systems

Relative reserve cost (%) Secondary reserve cost Primary rese ■ relocation co □ Unit primary ■ reserve cost

Heavy load Low load

Figure 5.31 Total annual increase of operational costs relative to total annual operational cost

5.6 Summary

In this chapter costs of spinning reserves in thermal power systems have been estimated. The main tool which has been used for this purpose - a unit commit­ ment optimization program - is not very well suited to the kind of analyses that have been performed in this chapter. Thus, a high degree of manual interaction and assumptions have been necessary. On the other hand, this manual approach has the advantage that it can be used on any system and with any unit commit­ ment program, and does not require any specially designed analytical tool.

The provision of primary and secondary reserves causes increased costs both within the actual units used for control and in the system due to a redispatch of the system load. In the case of primary control, the increased unit costs are calcu­ lated from increase of unit heat rate since the reserve provision causes the unit to deviate from the optimal (sliding pressure) operation at a given load level. Provi ­ sion of secondary reserves, however, are changes in the operating point and the unit might still be operated in sliding pressure mode. Assuming that additional investments and maintenance and abrasion costs are negligible, unit cost increase due to secondary reserves can thus be found with unit commitment analyses, which normally assume sliding pressure heat rate curves. In both cases, the sys­ tem cost increase caused by relocation of load due to the reserve provision can be found with unit commitment analyses.

Although the analyses are performed with data from a real utility, the results found from the 10 unit model are strictly applicable for this model only. Thus,

118 5.6 Summary several approaches have been tried to generalized the results in such a way that the costs could be transferred to other and larger systems. This has been only partly successful, and the best conclusion that can be made is, based on figure 5.31, to say that typical costs of spinning reserve in a thermal power system might be in the range of 4% to 8% of total annual operational costs. Looking at the specific costs of figure 5.25, it seems that using part of the HVDC connec ­ tions for reserve purposes is not as ecomonically beneficial to the thermal system as net export or pumped storage co-operation. Including investment costs for the different alternatives will most probably not change this picture.

Note also that these analyses are performed on a purely thermal power system. Many power systems found in Europe today have some hydro power units with storage capacity included, making it a mixed hydro-thermal system. Introduction of such hydro power units - high pressure or pumped storage units - will influ ­ ence the reserve costs estimated in this chapter, but it will also influence the total annual operational costs. To what degree introduction of hydro power capacity might change the relative costs given in figure 5.31 is impossible to say without closer studies, but from equation (5.3) it can be seen that the total operational costs of the 10 unit purely thermal system does not deviate much from the (scaled) costs of the hydro-thermal utility used in reference [55].

119 5. Cost of spinning reserve in thermal power systems

120 6. Cost of spinning reserve in hydro power systems

The original intention of this work was to study the costs related to provision of spinning reserve in both thermal and hydro power systems. However, time has not allowed this goal to be reached. The costs of spinning reserves in thermal power systems are analysed in Chapter 5, while in this chapter only some general comments regarding hydro power systems can be given. The extensive analyses have to be left for later studies.

In power systems dominated by thermal capacity like the UCPTE system, the provision of spinning reserve introduces a substantial increase in operational costs, both due to increased heat rate in the units providing the reserve and in the system due to capacity relocation, as described in Chapter 5. In the Nordel sys­ tem, more than 75% of the total spinning reserve are supplied by hydro power units in Norway and Sweden, and the economic aspects of spinning reserve are quite different. Note that in the present situation, spinning reserve in the Nordel system is mainly primary control reserve as the secondary control is manual and also includes starting and stopping of units.

6.1 Primary control reserve

In general, there are no additional investments necessary to provide or activate primary control reserves from hydro power units. The control is made with the standard speed controller, and the small pressure variations caused by normal fre ­ quency control actions do not cause any need for additional pressure reducing equipment.

As opposed to thermal power units, the optimum performance point of high pres ­ sure hydro power units is typically around 80-90% of rated unit load, as illus­ trated with the energy equivalent (kWh/m 3) of two different plant in figure 6.1. This characteristic performance yields sufficient reserves for primary control as long as the units are operated close to the optimum performance point, which are normally done if there are no external limitations like critical hydrological condi ­ tions (danger of overflow etc.) or local capacity deficits. Note also the importance of the static head for the unit performance. 6. Cost of spinning reserve in hydro power systems

Plant A: 80 MW Plant B: 82 MW

Energy equivalent (kWh/m3) Energy equivalent (kWh/m3)

Ho = 464,5 m

Ho = 434,5 m

Ho = 300 m Ho = 270 m

10 70 8( Unit output (%) Unit output (%)

Figure 6.1 Energy equivalent of single unit hydro power plant for different values of static head

Unit droop 8 and unit frequency bias Kr are defined in eqs. (Al.l) and (A1.2). Normal values of droop for Norwegian hydro power plant are 4-6%, but values down to 2% are possible. In the case of a (normal) frequency deviation of -0.1 Hz, the required additional output of an unit with 5% droop would be [58]:

100 rN 100 PN -KrAf = A/ = ^-0.1 = 0.04 ^ (61 ) 5 /n

Similarly, an unit with 2% droop would contribute with 10% of rated load. Thus, looking at figure 6.1 it can be concluded that as long as the unit is operating at or near optimum, it also carries sufficient primary control reserves. There is no need for capacity relocation, and there are no costs related to the provision of the reserve.

As opposed to a thermal power system, in a hydro power system the activation of primary control reserves might cause the most additional operational costs instead of the reserve provision. This is mainly due to reduced efficiency for the whole unit production when the unit is leaving the optimum performance point, a situation which is applicable for both positive and negative reserves. However, the efficiency curve of hydro units is rather flat close to the optimum performance point, and since activated primary reserves should be re-established withi n 15 minutes the economic consequences are small.

Note that if the unit was operating outside the optimum performance point, acti­ vation of reserves in one direction would actually improve unit efficiency, depending on which side of the optimum the unit was operating.

122 6.1 Primary control reserve

Similarly, the additional maintenance and abrasion costs due to small deviations around an operating point are considered to be negligible compared to starting and stopping the unit.

The situation is more complicated when the power plant has more than one unit connected in parallel to a mutual penstock or tunnel. The net head of the turbines are then influenced by the total plant output, and starting and stopping units at the correct load level might be crucial for the overall plant efficiency, as illustrated in figure 6.2 [66 ]. As primary control does not include starting and stopping of units, controller actions might move the unit into an unfavourable operating point, but again, only for a limited period of time. The problem of selecting the correct unit configuration is much more important for the stationary optimal operation of the unit than for small excursions due to primary control.

Efficiency (%)

Unit 2

Unit 1 + 2

80 -

30 40 50 Total plant flow rate Q (m3/sec)

Figure 6.2 Overall plant efficiency of 2-unit hydro power plant [66]

Note that not all multi-unit hydro power plant are sensitive to choice of unit com­ bination. For instance, figure 6.3 shows measurements from a 2-unit plant where any operation of one single unit has better performance than 2 units running together. In such a case, the influence of the primary control will be similar to the single unit plant. It is not know which of the situations from figure 6.2 or figure 6.3 are applicable to most of the multi-unit hydro power plant in the Nordel sys­ tem.

Although operation at optimum performance today more or less automatically ensures sufficient primary control reserves in the Nordel system, there is now a tendency when installing new turbines to move the optimum performance point towards the rated output. Thus, the reserve situation might become more difficult in the future.

123 6. Cost of spinning reserve in hydro power systems

Energy equivalent (kWh/m3) Ho = 141.14 m

Ho = 147.14 m

I Unit 1 +

0.32 -

60 60 10 Plant total output (MW)

Figure 6.3 Energy equivalent of 2-unit hydro power plant for different values of static head

If the unit due to external limitations like danger of overflow has to operate at maximum load, allocating reserve to this unit might cause overflow and loss of water (although the unit performance actually increases). A nearly 100% hydro power system like in Norway is dimensioned for energy capacity and to handle large variations in inflow, giving a surplus in peak load capacity. As the Nordel power system is very wide-spread with great local variations in hydrological con ­ ditions, critical situations with danger of overflow very rarely occur at the same time for a main part of the system.

However, the water is not a fuel with a given price; it is stored energy with an expected future value. The possible cost of spinning reserve is then a very inter ­ esting and complicated question. For instance, if the power plant would have had overflow in any case also without reserve provision, then the water value gener ­ ally would be zero. How should a possible value of the additional overflow be calculated? On the other hand, if the overflow was caused solely by the reserve provision, which value should be used for the lost water?

6.2 Secondary control reserve

Secondary reserves are handled manually in the Norwegian system today with the aid of the Regulating Power Market. At present, a minimum capacity of 40 MW available for secondary control is required from objects offered to the Regu­ lating Power Market (25 MW in northern Norway) [58]. It is not clearly stated, however, whether this requirement is applicable to each unit or to the overall reserve in a (multi-unit) plant.

124 6.3 Summary

In the first case, both provision and activation of secondary reserves might have considerable impact on the unit efficiency, as 40 MW typically are several tens of percentage of rated load. In the latter case, a multi-unit plant might provide also secondary reserves without additional cost by operating several units at optimum performance.

Possible changes of unit configuration due to reserve activation are normally taken care of by the operator. In the case of automatic secondary control, modem micro-processor based control systems make it possible to introduce a total plant controller which also handles configuration changes, including starting and stop ­ ping of units in the secondary control system.

Due to the favourable dynamic characteristics of hydro power units, starting and stopping units can be made within the time frame of secondary control. Although secondary control actions might cause rather large variations in unit output, the costs related to these variations are assumed to be low compared to costs due to additional maintenance and abrasion and loss of water when starting and stop ­ ping a unit. Hydro unit start-up costs are estimated in Swedish power plant to typically 1000-2000 NOK per start [26], and similar figures are considered also for Norwegian units.

6.3 Summary

The general comments made about spinning reserves in this chapter are naturally insufficient to give any detailed conclusions, but it is argued that the cost of spin ­ ning reserves in hydro power dominated systems like the Nordel system are low. In any case, it can safely be assumed that these costs are of a totally different scale than in a thermal dominated system.

The question is nonetheless important and of current interest, as there is much work going on to analyse both the definitions and the values/prices of ancillary services in the Nordel system today, of which the spinning reserve is an impor ­ tant part [78]. The cost of spinning reserve in hydro power dominated systems should be an important theme in the continuation of the work done in this thesis.

125 6. Cost of spinning reserve in hydro power systems

126 7. Summary and conclusions

Following some years in the mid- and late 80 ’s with very high precipitation in the hydro power system of Norway, several projects for new HVDC connections between Norway and Continental Europe were initiated, soon to be followed by similar Swedish and Danish projects. According to present knowledge, all new agreements are based on the pumped storage principle, where Norwegian hydro power is exported during peak load hours while surplus thermal power can be imported during off-peak hours.

Of other possible ways to utilize an HVDC connection between Norway and Continental Europe, net energy export has not been allowed by the Norwegian government. At present, there is no energy surplus in the Norwegian system, and the government does not accept export agreements which might initiate the con ­ struction of new hydro power capacity.

However, short-term co-operation are at present not considered as far as the author knows. These alternatives can include both co-operation in the seconds range (primary control) and in the minutes range (secondary and tertiary control), as the high controllability of an HVDC connection makes it useable for all these alternatives. Thus, the initial ambition at the beginning of this study was to make an analysis of both technical and economic aspects of primary and secondary control in hydro and thermal power systems related to the present and future HVDC connections from Norway. By the aid of such an analysis, system charac ­ teristics could be studied and possible advantages and/or problems of a closer co­ operation could be identified. Note that the focus of this study has been system operation and operational costs, and that investment costs have not been consid ­ ered. Unfortunately, time has not allowed this goal to be fully reached.

7.1 Primary control

Primary control is fast control actions made by the speed governor due to fre­ quency deviations in the system to keep the instantaneous balance between pro ­ duction and consumption. Primary control is characterised by small excursions in unit output (2-5%) and short time-frame (30 seconds).

Thermal and hydro power systems are highly complimentary with respect to both technical and economic aspects of primary control. Activation of primary control reserve in thermal power units is very fast, but the reserve has limited duration

127 7. Summary and conclusions

and the cost of providing this reserve is estimated to 1-3% of total production cost. Hydro power units, on the other hand, provide a very cheap primary reserve compared to thermal units, although specific figures for cost of primary control reserve in hydro power units are not found in this work. Hydro power units are generally slower to respond during the first couple of seconds, but the reserve has nearly unlimited duration.

Thus, although it is economically interesting to substitute thermal primary con ­ trol reserves with hydro reserves, this it not necessarily a good technical solution. But since the two systems are interconnected with an HVDC connection, the high controllability of the connection itself can be utilized for primary control, with a response which is far better than any mechanical unit, either thermal or hydro. This concept is analysed in Chapter 3. High voltage DC connection with primary control.

By equipping the HVDC connection for primary control, the transient character ­ istics of the receiving system are considerably improved, and an amount of spin ­ ning reserve corresponding to the available HVDC capacity can be substituted. The problem is that disturbances are then transferred to the sending system and might even be magnified if the situation is unfavourable.

The concept of HVDC primary control co-operation is equally applicable in both directions between the hydro- and thermal power systems, but due to the eco­ nomic aspects only export of primary control reserves from the hydro- to the thermal system is analysed in this study. In that case, if the disturbance is large, the influence on the exporting (hydro) system can be worse than for the original disturbance in the importing (thermal) system. However, as the thermal system (UCPTE) is very large compared to the hydro system (Nordel), disturbances have to be extremely large to cause frequency deviations in the Nordel system which might violate current recommendations for normal operation.

Thus, expensive spinning reserves in the thermal system can be substituted by HVDC capacity at the expense of spinning reserves in the hydro system, without causing unacceptable disturbances in any system. There is however no particular interest in the UCPTE system for purchasing primary control reserves from Nor­ way today. There is no tradition for trading primary control reserves in the UCPTE, and the HVDC connections are only able to substitute reserves within a reasonable distance from the terminals.

128 7.2 Secondary control

7.2 Secondary control

Secondary control is slow control actions to re-establish nominal system fre­ quency and scheduled power interchanges after a deviation, and is characterised by large excursions in unit output, typically over the whole allowable operating range, but rather long time-frame (15 minutes). The general concept of secondary control might include different control functions, but in the UCPTE the term is unambiguously used for load-frequency control.

The cost of keeping spinning reserve for automatic secondary control in a ther ­ mal power system are higher than for the primary control, and are estimated to 3- 5% of total production cost. Thus, the possibility to purchase secondary control reserves from the hydro power system should be interesting for the thermal sys­ tem. This trading of secondary control reserves can be done without changing the current ACE-based secondary control system in the UCPTE. Note that in the time frame of secondary control (15 minutes), the high controllability of the HVDC connection is without interest.

If reserve carried by the HVDC connection is activated manually instead of auto­ matically, this would conceptually be considered tertiary reserve in the UCPTE system. Trading of tertiary reserves is usual today, but no attempt has been made in this study to estimate costs (or prices) for these reserves.

Technical analyses of secondary control in a thermal system are omitted, as these would not have yielded much new information. On the other hand, the concept of automatic secondary control is not very well known in the Nordel system, and in Chapter 4. Automatic secondary control simulation models have been created to study this in more detail. These simulations are carried out without representing neither the thermal system nor the HVDC connections themselves, and are thus not directly related to the co-operation frame of this study. However, even the already agreed pumped storage co-operation might necessitate automatic control functions in the Nordel system. A study of the Nordel system alone is therefore also important.

At present, there is some disagreement over whether the current manual second ­ ary control concept is sufficient or not when the new HVDC connections are commissioned early in the next decade. In the opinion of the author, the current system will not be sufficient, but the analyses show that several alternative auto­ matic control schemes are technically well suited to handle the increased system strain. Both a general ACE-based load-frequency control scheme, possibly in addition to the current Regulating Power Market, and a ramp controller dedicated to follow the HVDC connections have been tested with satisfactory result in the simulation model.

129 7. Summary and conclusions

It might actually be a more difficult question to find sufficient reserve capacity available in the system, a problem which must be solved whether an automatic secondary control scheme is introduced or not.

7.3 Conclusions

The main contributions of this thesis are a systematic analysis which leads to an increased knowledge and understanding of both technical and economic aspects of the operation of thermal dominated power systems, and the study of automatic secondary control in the hydro dominated power system of Scandinavia.

The study of HVDC primary control co-operation gave interesting insight into the control and operation of large power systems. This alternative is both techni ­ cally and economically feasible, but it does not seem to be a realistic possibility in the near future.

The alternative to sell secondary control reserve across the HVDC connection, on the other hand, seems much more interesting. The cost of keeping spinning reserve for automatic secondary control in a thermal power system is estimated to 3-5% of total annual operational cost. Secondary control reserves are probably not competitive to the value of the peak load export (note that investment costs are not considered in this work), but during off-peak hours with ‘price-dependent energy exchange ’, the alternative of using at least part of the HVDC capacity for secondary, or possibly tertiary, control reserves for the thermal system should be seriously considered.

Whether the present and future HVDC connections from Norway are to be used for some control purposes, or just manually operated according to the pumped storage principle, it will be necessary to introduce some additional automatic control functions to handle the increased operational strain on the Norwegian system. The analyses made in this thesis show that there are no special technical difficulties by doing this, it is more a question of deciding upon the type of con ­ trol which should be used.

One technically tempting solution is to introduce a limited load-frequency con ­ trol system as a supplement to the current Regulating Power Market to aid the system operator while the (main) reserves as offered at the market are activated. However, as any ACE-based load-frequency control system might be difficult to implement in a deregulated energy market, a dedicated ramp following controller is another possible solution.

130 7.4 Further work

The main problem which remains to be solved is then the question of providing sufficient reserves and to which units these should be allocated.

7.4 Further work

Similar to many other interesting research projects, for each question which is answered in this thesis at least two more arise. Thus, the main limitation of this study has been the time frame, not a lack of research themes.

At the end of this study, there are still numerous angles and themes which could - or should - be examined, both regarding the theoretical depth of the present work and the number of angles treated. There are however five main themes which the author wishes to emphasize as the possibly most interesting and important for future studies:

• The cost of spinning reserve in hydro power systems should be given a detailed and systematic analysis.

• Further work on the secondary control in the Nordel system should include both further technical analyses of different control structures and better system representations with respect to grid bottlenecks and reserve allocation, in addi­ tion to a more general discussion of the total operational concept.

• More complex non-linear hydraulic turbine models should be implemented and tested in a power system simulation program to examine their influence on the long-term simulations necessary to study secondary control functions.

• Operation of the HVDC connections during periods with low short circuit ratio and little spinning reserve in the hydro power system should be analysed, with special emphasis on possible problems related to multiple infeed HVDC sys­ tems.

• Finally, further attempts should be made to generalize the costs of spinning reserve in thermal systems, and perhaps modify an unit commitment program to avoid the manual interaction which was necessary in Chapter 5.

131 7. Summary and conclusions

132 References

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36. Radtke, U, Taube, W. et. al: Technical and economical aspects of SMES application to power system operation and control CIGRE 1994 Session, 28 August - 3 September

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38. Martin, P: Zusammenstellung der erzielten Ergebnisse VDI-Berichte 582: Wirkleistung- und Blindleistung-Sekundenreserve VDI-Verlag GmbH, Diisseldorf 1986, pp. 277-310 (in German)

39. Flechner, B.A: Die notwendige Modellierungsgenauigkeit bei der Energie- einsatzplanung in hydrothermischen Kraftwerkssystemen Ph. D. Thesis, preliminary version RWTH Aachen, 1995 (in German)

40. Gerstmeyer, R: Einsatz der moglichen Wirkleistungs-Sekundenreserve- MaBnahmen in Kemkraftwerken (Betrachtung aus Betreibersicht) VDI-Berichte 582: Wirkleistung- und Blindleistung-Sekundenreserve VDI-Verlag GmbH, Diisseldorf 1986, pp. 151-158 (in German)

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43. Amlov, B, Andersson, G.B.O. et.al: Aspects of the cooperation of three HVDC links between southern Denmark, southern Sweden and northern Germany/Jutland Paper 220-02 presented at the Cigre symposium, Tokyo 1995

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49. Empfehlungen zur primaren und sekundaren Frequenz- und Wirkleistungs- regelung in der UCPTE UCPTE February 1995 (in German)

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58. Grande, O.S, Hornnes, K.S: Klargjpring av fomtsetninger knyttet til produksjonspotensial og utvekslingsavtaler EFT Technical report F4391, 1996 (in Norgwegian, restricted)

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140 Appendices

Appendix 1

Interconnected system reserve recommendations

To ensure a stable and reliable operation of interconnected power systems, it is necessary to maintain a sufficient reserve capacity against contingencies. There are defined certain recommendations regarding the size, the quality and the com­ position of this reserve capacity. This appendix describes some of the most important reserve recommendations with respect to frequency control in the UCPTE and Nordel systems. Recommendations regarding voltage control are omitted as they are beyond the scope of this work.

It is beneficial to start with the UCPTE recommendations as these are the most structured ones and thus the simplest to understand.

Al.l UCPTE reserve recommendations

The national UCPTE networks are interconnected so as to enable the exchange of electric energy in large quantities and guarantee secure supply to consumers by mutual support and assistance in daily operation, with a view to optimum use of generating capacity [10]. The following is a short summary of some of the opera ­ tional recommendations of UCPTE based on reference [49] with additional infor ­ mation and confirmation from references [8, 9,10,11,12].

Al.1.1 Primary control

Primary control is the reaction of the speed governor to frequency deviations in the system. The required reserve capacity should be distributed as evenly as pos ­ sible among the connected power stations.

The interconnected UCPTE system should be able to handle a sudden loss of 2.5% of total generation capacity (minimum 2500 MW) without suffering a sta­ tionary frequency deviation of more that 150 mHz. Correspondingly, a loss of 2500 MW consumption should not lead to a stationary frequency rise of more than 150 mHz [49].

143 Appendix 1. Interconnected system reserve recommendations

Thus, each interconnected region have to supply a resulting primary control reserve of at least 2.5% of its instantaneous generation at any time within a sta­ tionary frequency deviation of 150 mHz, regardless of where the actual distur­ bance occurred. This is also reflected in the Principle of Solidarity [49]:

‘The primary control ensures the reliable supply of the interconnected system through simultaneous solidary actions from all interconnected partners. (...) Every partner has to take part in the response following a disturbance according to his part of the total generation at the time of the disturbance. ’

As many as possible of the running units should take part in the primary control. However, as some units normally do not supply primary control reserves, depending on which kind of units are available in a defined control area the requirements for each unit within the area might be different. For instance, each unit taking part in the primary control in Germany should be able to supply mini ­ mum ±5 % of rated output as primary reserves, while in Holland and Switzerland the required band is ±3%.

Of the total primary control reserve at least 50% must be activated within 5 sec­ onds, and the rest within 30 seconds (conventional units), as shown in figure A 1.1 [49]. This reserve is made available in suitable power stations; conventional thermal power stations and pumped storage and high pressure hydro power sta­ tions. In France and Germany are also some of the nuclear power stations used for primary control, and they have a much higher response requirement due to their special characteristics. Gas turbine units are however not used for frequency control. See also Appendix 2 Primary control in thermal power units.

Additional output {%) 100 f Nuclear units

Conventional units

'Hydro dominated

Time (s)

Figure Al.l UCPTE primary reserve response recommendation [49]

Note also that the recommendations for ‘hydro dominated systems’ are modified to 75% reserve in 15 seconds, indicating that especially low pressure hydro

144 Al.l UCPTE reserve recommendations power units might have problems fulfilling the recommendation of 50% reserve in 5 seconds. This modification is however not adopted by the Nordel recommen ­ dations.

The participation of each unit in primary control is governed by the unit droop 8 defined as the ratio between the relative change of frequency and the relative change of power due to the frequency change:

(Al.l)

The frequency bias is then defined as:

(A 1.2)

When the frequency deviation is known, the frequency bias defines the change of generation at each controlled unit. The frequency bias of a control area or the whole interconnected system is calculated as the sum of the frequency bias of each unit.

The speed controller of a conventional thermal or nuclear power unit normally has a droop of 4-6%, while hydro power units use a droop of 2-6%. However, nuclear units and some of the conventional thermal units are often operated with a primary controller dead band.

The current primary control recommendations of UCPTE will be revised in 2-3 years.

Al.1.2 Secondary control

In UCPTE the secondary control or load-frequency control are fully automatic control actions to enable a control region to regain the desired output after a dis­ turbance, returning the system frequency and the agreed exchange between inter ­ connected regions to their reference values.

The secondary control is implemented with a slow Pi-controller, represented by the following differential equation [10]:

APd = -pG-ljGdt (MW) (A1.3) r where: APd - additional power demand signal distributed to the control

145 Appendix 1. Interconnected system reserve recommendations

units in the network (3 - proportional gain (0.1 - 0.5) Tr - integration time constant (50 - 200 s) G - Area Control Error (ACE),

The Area Control Error (ACE) is defined by the following equation:

G = AP + KrAf (MW) (A 1.4) where: AP - net area interchange deviation (MW) Kr - frequency bias setting (MW/Hz) A/ - system frequency deviation (Hz)

Different system controllers are responsible for a defined control area of the interconnected UCPTE system and are operated in parallel. Utilization of equa­ tion (A1.4) ensures that a load change or generating failure is compensated by the system controller of the region in which the change or failure occurred. The nec ­ essary secondary control reserve should be fully activated within 15 minutes, returning system frequency and inter-regional exchanges to reference values (ACE = 0). Thus, although all interconnected partners would react to the distur­ bance through their primary control (the Principle of Solidarity), the responsibil ­ ity for returning the ACE to zero is placed solely on the control area in which the disturbance occurred.

The basic concept of automatic secondary control is explained and demonstrated in more detail in chapter 4 Automatic secondary control and Appendix 4 Basic theory of load-frequency control.

One purpose of the secondary reserve is to be able to handle sudden contingen ­ cies disturbing the balance between generation and consumption, but equally important is the continually load following control to handle ‘normal ’ load changes during each hour (which is a normal time step in the operational plan ­ ning). The recommended size of the secondary reserve APs (positive part of the secondary control band) is thus related to the expected maximum load during a given time period [49]: *r s2 3-jp^ (MW) (A1.5)

During periods with large load changes (morning and midday) twice this value is recommended.

There are great differences in size between the control regions. The maximum load of the control regions of the UCPTE system lies between 4 GW (Portugal) and 63 GW (Germany), and the number of generating units used for control

146 Al.l UCPTE reserve recommendations ranges from 14 (former Yugoslavia) to 313 (France). The reserve capacity required for secondary control amounts for all countries on average to only 4% of the aggregate peak load [10].

Normally, hydro power units are used for secondary control, provided such units are available in the region. If this does not result in sufficient reserve capacity, conventional thermal power units are also used. Only in the French and German control regions (the latter including the grids of Luxembourg and Jutland in Den ­ mark) are also nuclear power stations used for secondary control.

Adjustment of the parameters of the secondary controller depending on the load level is either not used at all, or only in two or three stages for some partners. The normal values of the proportional gain (3, the integration time constant Tr and the frequency bias setting Kr of the UCPTE partners are shown in table Al.l together with the necessary secondary control band [10].

Note that the values of (3 and Tr might differ from the recommended values indi ­ cated below equation (A1.3). The French and Italian control regions actually use an I-controller, and the national control level of the hierarchical secondary con ­ trol schemes of Spain and former Yugoslavia use only a proportional controller.

Necessary Proportional Integration time Frequency bias control band gain (3 constant Tr setting Kr

COUNTRY (MW) (MW/MW) (s) (MW/Hz)

B 1000 1 0 1000 D/LZDK 1060-2700 0.5 70 4000/5000/6000 E 900 3 0 2000 F 1000-2000 0 100/100/200 4500/6500/9500 GR 300 1 0 500 I 700-800 0 200 2200/3200/3800 YU 245 1 0 470/800/1100 NL 400 0.5 50 1500 A 250-500 0.2 150 900 P 250 0.1/1.0 16.7/100 600/800 CH 250-800 0.762 150 960

Table Al.l Values for proportional gain, integration time constant and frequency bias setting of the UCPTE partners [10]

147 Appendix 1. Interconnected system reserve recommendations

The frequency bias setting of the secondary controller need not correspond exactly to the (measured) specific area power-frequency characteristic X (MW/ Hz); it is sufficient if it corresponds to the spinning reserve of the area [10]. The actual power-frequency characteristics of the control areas and the frequency bias settings of the controllers should, however, not differ too much, since this might cause load changes also in countries without disturbances.

Any unit must be able to operate down to 40% of rated output, and units used for secondary control must fulfil the average load change rates given in table A 1.2 over the whole operational band from 40 to 100% of rated output.

Average load change rate

Oil/gas fired 8 (% PN/min) Pit coal fired 4-8 (% PN/min) Nuclear 5-10 (% PN/min) Hydro 1.5 - 2.5 (% PN/sec)

Table Al. 2 Average load change rate recommendations for secondary control units [49]

Al.1.3 Tertiary control

The concept of tertiary control is not defined unambiguously among the UCPTE partners. In some control regions it means fully automated optimum generation dispatch in failure-free condition. It is thus possible to combine secondary con ­ trol with optimization of thermal power stations by minimising variable generat ­ ing costs. For other UCPTE partners, tertiary control means manual control actions to re-establish the secondary control reserves after a failure.

Included in the tertiary control are also start-up (and stop) of fast startable units like gas turbines or hydro power units, manual adjustments of operating point of not controlled units and changes in inter-regional exchange programs. Figure A 1.2 illustrates how start of an unit without reserve capacity as a tertiary control action might re-establish a necessary amount of available reserve for the second ­ ary control.

If the secondary control reserves according to eq. (A1.5) are insufficient to han ­ dle loss of the biggest production unit in the area, the deficit should be included in the tertiary reserve [49]. Note that as opposed to the secondary reserve, this reserve does not have to be located within the actual control area.

148 Al.l UCPTE reserve recommendations

Secondary control reserve Secondary ■ control power Not Secondary □ controllable control reserve

■ Secondary System load - - control band

Secondary control power

Not controlable capacity

U1+U2 U1+U2+U3

Figure A1.2 Coordination between secondary and tertiary control

As a summary, figure A1.3 shows the three reserve levels in the UCPTE system. Note the hierarchical structure of the control actions, where slower reserves replace the fast ones. The primary task is to ensure the system stability through a balance between production and consumption {Primary control), then the fre­ quency and exchange deviations are corrected {Secondary control), and only at the third level is the question of economic dispatch taken into consideration (Ter­ tiary control).

Optimisation Tertiary reserve of reserve

30 sec. 15 min. Time after 150 mHz ACE = 0 contingency

Figure A1.3 Time frame of UCPTE reserve actions [49]

As an additional comment, according to guidelines for load-frequency control under disturbance conditions in the US as developed by the Operating Commit­ tee of NERC1, the secondary control should start within 1 minute following the start of the disturbance, and be fully activated (ACE = 0) within 10 minutes fol­ lowing the start of the disturbance [17].

1. NERC - North American Electric Reliability Council

149 Appendix 1. Interconnected system reserve recommendations

Al.1.4 Time deviation

The time deviation is defined as the deviation a synchronously running clock will acquire in proportion to correct time because of deviations from nominal system frequency of 50 Hz. There are no recommendations regarding the size of this deviation in the UCPTE system, but if it should become too large (20-30 s is allowed), the synchronous time is corrected by operating the secondary control at certain intervals at an offset reference frequency of 49.95 Hz or 50.05 Hz. This correction is made simultaneously in all control regions. The problem with this method is that operating the system at an offset frequency will utilise some of the primary control reserves. Only in French and German nuclear power stations is the time correction accompanied by a partly automatic adjustment of also the pri ­ mary control reference frequency.

Al.1.5 Start-uptime

The start-up time of an unit from standstill to rated output depends on the type of primary energy, the layout and the operation of the unit and the conditions under which the unit was stopped. The start-up times should not exceed the values given in table A 1.3.

Duration of Max. start-up State standstill time to full load

< 8 h hot 2h Conventional units 8 - 50h warm 3 h > 50 h cold 5 h < 8 h no load, hot 3 h Nuclear units 8 -120 h no load, hot 6 h > 120 h cold, subcrit. 25 h

Table A1.3 Maximum unit start-up times [8]

Al.1.6 Operation during frequency deviations

The system frequency might be critical for the operation of thermal power units. The following operational requirements during frequency deviations are valid for German power plant [8]. It is not known to what extent also other UCPTE part ­ ners follow these requirements.

150 A1.2 Nordel reserve recommendations

It must be possible to synchronize an unit to the grid at frequencies between 48.0 Hz and 51.5 Hz. However, the unit must be able to operate in the frequency band between 47.5 Hz and 52.5 Hz.

In the frequency band between 51.5 and 48.5 Hz all conventional units must be able to supply rated output; at 47.5 Hz at least 95% of rated output. Nuclear units must supply rated output between 51.5 and 49.0 Hz, and at least 95% at 47.5 Hz.

The units must be able to operate between 48.5 Hz and 48.0 Hz for 20 minutes and between 48.0 and 47.5 Hz for 10 minutes. At a frequency lower than 47.5 Hz the unit is automatically disconnected from the grid.

If the frequency exceeds 51.5 Hz without the primary control being able to reduce the load accordingly, the operational personnel must reduce the load of the unit until a safe operational situation is re-established. The unit must not be disconnected from the grid until critical speed is reached.

Unit output (%)

Conventional Nuclear

Frequency (Hz)

Figure Al. 4 Operational requirements during frequency deviations [8]

A1.2 Nordel reserve recommendations

The Nordel reserve recommendations are basically comparable to the UCPTE recommendations, although different terms are used to describe similar func ­ tions. The following presentation is based on reference [2].

Al.2.1 Primary control

While the UCPTE reserve recommendations mainly are aimed at control actions following a disturbance, there is a greater focus also on normal operation in the Nordel recommendations. Thus, the primary control reserves of Nordel - termed

151 Appendix 1. Interconnected system reserve recommendations

Instantaneous reserves - are split in two parts (see figure A 1.5):

- Frequency control reserve: The instantaneous active reserve (MW) availa­ ble withi n a frequency deviation of +0.1 Hz (between 49.9 and 50.1 Hz) during normal operation. - Contingency reserve: The instantaneous active reserve available at fre­ quency drops below 49.9 Hz. The reserve must be fully activated within a frequency drop of 0.5 Hz.

The frequency control reserve of the total Nordel system should not be lower than 600 MW. This amount is not included in the contingency reserve, which must at least correspond to the dimensioning fault.

Reserve (MW)

Contingency reserve ~ 1000 MW

Frequency control reserve: > 600 MW

Frequency (Hz)

Figure A1.5 Instantaneous active reserves in the Nordel grid [25]

The dimensioning fault is defined in the Nordel system as the single fault that leads to the largest loss of generation that can happen with a probability greater than once every third year. It is required from the instantaneous contingency reserve that no such fault should lead to loss of stability or a stationary frequency after the fault lower than 49.5 Hz.

The dimensioning fault depends on the actual operational situation, and is calcu­ lated for the Nordel grid every week. The most common dimensioning fault is the loss of generation in a Swedish nuclear power plant (1.100 MW) or a Norwegian 420 kY west to east transmission line (1.000 - 1.200 MW). Subtracting the sys­ tem power-frequency characteristic of approximately 400 MW/Hz, a typical size of the contingency reserve is 1000 MW (at 0.5 Hz).

As for the UCPTE system, it is required that after a sudden drop in frequency to 49.5 Hz the contingency reserve should be fully activated within 30 seconds, half

152 A1.2 Nordel reserve recommendations of which within 5 seconds. The special response of hydro power systems is not adopted in the Nordel recommendations . After a sudden drop in frequency to only 49.9 Hz, however, it is sufficient that the frequency control reserve is fully activated within 2-3 minutes.

In the Nordel grid most hydro power stations take part in the frequency control. Norwegian hydro power units taking part in the frequency control usually have a droop of 4 - 6 %. The upper limit is between 6 - 10%. The thermal power stations in the Nordel grid, on the other hand, usually have a frequency dead band and only contribute to the contingency reserve. The thermal power stations in Zee- land and Finland do to some extent take part also in the frequency control.

The HVDC connections within the Nordel grid are also used as contingency reserve in the frequency band from 49.5 to 49.85 Hz, and as emergency support between 49.0 to 49.5 Hz together with load shedding.

In the Nordel grid the total frequency bias should be between 6000 and 8000 MW/Hz, with 6000 MW/Hz as a lower limit. Both this requirement and the con ­ tingency reserve is distributed between the Nordel participants according to their total annual consumption. The frequency bias and frequency and contingency reserve requirements for 1995 are shown in table A 1.4.

Frequency bias Frequency control Contingency Country (MW/Hz) reserve (MW) reserve (MW)

Denmark/Zeeland 250 25 179 Finland 1 250 125 205 Norway 2 000 200 313 Sweden 2 500 250 303 NORDEL 6 000 600 1 000

Table A1.4 Frequency bias and frequency and contingency reserve requirements in the Nordel grid (1995) [2]

Al.2.2 Secondary control

The main difference between the UCPTE and Nordel systems can be found within the secondary control principles. While the secondaiy control in UCPTE is fully automated, it is handled by manual control actions in the Nordel system. However, in both systems the aim of the secondary control is to reduce the Area Control Error G to zero, re-establishing the system frequency and the agreed exchange levels.

153 Appendix 1. Interconnected system reserve recommendations

In the Nordel system, the secondary control reserves are called Fast reserves. Also in this case is in principle a partition made between Fast forecast reserves and Fast disturbance reserves, which must be large enough to re-establish the respective activated instantaneous reserves. However, during operation there is normally no distinction between these two categories. The size of the secondary control reserves are not specified by the Nordel recom­ mendations, but is left to each system operator to decide. In Norway, 1000 MW is normally requested for secondary control [58]. Due to the favourable operating characteristics of hydro power units, the secondary reserve might include both spinning and standing generation capacity.

The integrated ACE (MWh/h) should, unless otherwise agreed, be limited to a MWh/h value corresponding to the national frequency control reserve. The instantaneous ACE (MW) should then be limited to a MW value which is 1.5 times the integrated ACE, but not lower than 200 MW. The requirements for inte ­ grated and instantaneous ACE for 1995 are shown in table A 1.5.

Integrated ACE Instantaneous Country (MWh/h) ACE (MW)

Denmark/Zeeland 25 200 Finland 125 200 Norway 200 300 Sweden 250 375

Table Al. 5 Integrated and instantaneous ACE requirements for 1995 [2]

The secondary control in Norway is handled today by the Regulating Power Market, where producers (and in principle also large consumers) offer change of generation levels at certain prices. These bids are sorted by price, and are called upon manually by the system operator when the need arises. The producers must then have performed the regulation within 15 minutes, which is not exactly in accordance with the UCPTE secondary control recommendation: In the UCPTE system all control actions to return the ACE to zero should be finished within 15 minutes. In Nordel each control action should be performed within 15 minutes after being requested, and whether the ACE is returned to zero within 15 minutes after the disturbance is not known. However, also the Nordel recommendations do state that the primary control reserves should be re-established by the second ­ ary reserve within 15 minutes after a disturbance [2].

154 A1.2 Nordel reserve recommendations

Al.2.3 Tertiary control

The concept of tertiary control is normally not used in the Nordel system. There are however recommendations regarding Slow reserves, which are reserves avail­ able between 15 minutes to 4 hours. These reserves are intended to replace the secondary control reserves after a disturbance, and must also at least correspond to the dimensioning fault. However, since also standing units can be included in the secondary control reserve, there is generally no need to use this third reserve level in the hydro dominated countries in the Nordel system.

The different reserve recommendations are summarised for the Nordel system in figure A1.6. Note that although the terms are different, the hierarchical structure is very much the same as in the UCPTE recommendations of figure A1.3. The main difference is the Instantaneous frequency control reserve utilised during normal operation.

Slow Manual MUM reserve

Fast Re-establishing Manual reserve the fast reserve

Instantaneous - contingency Re-establishing the instantaneous DEES —______30 sec. 2-3 min. 77me after 500 mHz +/-100 mHz contingency

Figure A1.6 Time frame of Nordel reserve actions

Al.2.4 Time deviation

As opposed to the UCPTE system, the recommendation for time deviations is quite strict in the Nordel system: During normal operation the time deviation should be held as low as possible, and should not exceed ±10 seconds. Manual secondary control reserves are used to reduce the time deviation. As Sweden and Norway together carries 75% of the total Nordel frequency bias, they have the main responsibility to control both frequency and time deviation.

155 Appendix 1. Interconnected system reserve recommendations

Al.2.5 Load and production shedding

Load shedding is used in the Nordel system in steps of 0.2 Hz at frequencies between 49.0 and 47.0 Hz. The amount of the national load equipped with auto­ matic load shedding varies from 20% (Finland) to 50% (Denmark). Grid separa ­ tions should not occur until the frequency drops below 47.5 Hz. As mentioned, HVDC connections within Nordel are also used as emergency support between 49.0 and 49.5 Hz.

Thermal power stations are disconnected from the grid at low frequencies between 47.5 and 45.0 Hz.

156 Appendix 2

Primary control in thermal power units

Primary control is the reaction of the speed governor to frequency deviations in the system, intended to keep the balance between production and consumption. This appendix describes different methods to provide primary control reserves from thermal power units. As excess generation can normally be corrected with ­ out particular problems, the following sections deal with generation deficits only.

A2.1 Overview

The UCPTE interconnected system reserve recommendations are presented in Appendix 1 and summarized in figure A1.3. Looking at the idealized system fre­ quency response following a disturbance, the reserve provision from a thermal (steam) power unit can be allocated to the different components of the unit as shown in figure A2.1.

0 5 s 30 s 15 min Time

Figure A2.1 Reserve provision from thermal power unit [71]

The first couple of seconds the inertia of the rotating masses of the unit contrib ­ utes to the determination of the maximum transient frequency deviation (together with the power-frequency characteristics of other component is the system). Simultaneously, the primary reserves are activated by the speed governor within 30 seconds, freeing excess steam by dethrottling the HP turbine inlet valves and

157 Appendix 2. Primary control in thermal power units stabilizing the frequency at a stationary level. For a limited period of time this additional output is maintained by utilizing stored energy in the steam cycle, until finally the secondary controller increases the firing in the boiler to further increase the unit output and bring the system frequency back to nominal value.

According to the general UCPTE primary control recommendation each inter ­ connected partner or control area has to supply at least 2.5% of instantaneous generation within 30 seconds, half of which within 5 seconds (see also figure Al.l). The response requirement for each unit taking part in primary control might vary from region to region, depending on the production structure and the number of units providing primary control in the particular region. As shown in figure A2.2, the requirement for German conventional units is 5% additional out­ put within 30 seconds, while in Holland the requirement is only 3%.

Additional output (%) German Nuclear unit controlling units

Dutch Conventional unit controlling units

UCPTE system recommendation

Time (s)

Figure A2.2 Primary control recommendations for thermal power units [8]

However, looking at the frequency measurements of figure A2.3 one might sus­ pect that the provision of primary control reserves in the UCPTE system does not always follow the recommendations. The frequency responses from the 70’s and 80 ’s look very much like the idealized inertia/primary control response of the first minute of figure A2.1. But the responses from the 90 ’s show almost no sign of primary control actions; the frequency drops to the transient level given by the total system inertia and power-frequency characteristic and stays there.

In any case, the size of the interconnected UCPTE system is in most cases suffi­ cient to keep also the transient deviation within the recommended maximum sta­ tionary value of 150 mHz. Note also that the number of nuclear units taking part in primary control (in particular in France) will contribute to this response char ­ acteristic due to their fast primary control response. See also Section A2A Nuclear power plant.

158 A2.2 Overall unit control

M-j: Dienatoo. 15.4.1975 Mj: Fraitoa. 3.2.1984 M3: Fraltoa. 15.2.1985 APz*=W = 1-66% APz‘= W=°'63% Ap z*=^ = 2,63 %

M7: Somstaa. 4.7.1992 Mg: Mittwoeh. 19.10.1994 Mg: Somstaa. 9.9.1995 APz* = W=°-61% APz* = S 0,71%

Af ■ \ mHz _A1 mHz ■ ___ -100 L " -100L -100L

Figure A2.3 Typical frequency responses in the UCPTE system [68]

A2.2 Overall unit control

The provision of automatic controls at the power unit level enables the operator to meet the system reserve requirements in the most efficient manner. Consider ­ ing the overall thermal power unit control, it can usually be sorted in the follow ­ ing three main unit control modes [13]:

Turbine followine mode (TFM). Unit load commands adjust the boiler fuel sup ­ ply, and the turbine control valves control the boiler pressure. A special case where the turbine control valves are left wide open and the pressure is also con ­ trolled by the boiler, is called sliding pressure control mode.

Boiler followine mode (BFMi. Unit load commands are applied to the turbine control valves while a feedback from the steam pressure is controlling the boiler fuel supply.

159 Appendix 2. Primary control in thermal power units

Unit coordinated mode (UCM). Unit load commands are applied simultaneously both to turbine control valves and the fuel supply system. The steam pressure acts to trim the turbine control valves and/or the boiler fuel supply.

A2.3 Fossil fuelled steam power units

A2.3.1 Methods to meet fast power demands

Fast power demands of the grid can be provided by fossil fuelled steam power units by a number of possible methods. In all methods existing storage capacity in the water/steam cycle is used at short notice and for limited periods of time to increase unit output power. The methods shown schematically in figure A2.4 are:

• H - HP control valve dethrottling • V - Overload Valve opening • HS - Steam side trip of HP feedwater heaters • HW - FeedWater bypass of HP feedwater heaters • LS - Steam side trip of LP feedwater heaters • C - Condensate flow stoppage • T - Increase in boiler Thermal output

Load demand Unit load control

Condenser

HP preheater Feedwater Feedwater LP preheater pump tank

Figure A2.4 Possible methods of fast power increase in a fossil fuelled steam power plant [15]

160 A2.3 Fossil fuelled steam power units

Dethrottling of HP control valves (H)

The method of dethrottling HP control valves maintains a reserve by keeping the main steam control valves in front of the HP turbine slightly throttled during nor ­ mal operation. Additional output can then be achieved through fast opening of the valves to free extra steam from the stored volume of the boiler.

The amount of throttling is defined by the throttle degree, which is usually defined as a constant valve position over the load range, Dy, eq. (A2.1a), as illus­ trated in figure A2.5. It can also be defined as constant overpressure over the load range, DAp, eq. (A2.1b) [13, 30].

Dy = ?A~Pb- • 100% (A2.1a)

D. = —— • 100% (A2.1b) P msN where pA - initial pressure at desired output pB - full sliding pressure at desired output pmsN - main steam pressure at rated output

Main steam pressure PTO(%)

HP turbine control valve opening yt (%)

- 50

Unit output Pe (%)

Sliding pressure Constant pressure Modified sliding operation operation pressure operation

Figure A2.515% HP turbine control valve throttle reserve [14]

161 Appendix 2. Primary control in thermal power writs

The unit is operated at desired output in point A with an increased main steam pressure compared to sliding pressure operation (control valves fully opened). This increases the heat rate, causing a reduction of the thermal efficiency of the unit. When the frequency of the grid drops, the valves are opened, and the unit output increases very fast towards the sliding pressure operation line.

Once the valves have been fully opened, the duration of the increased generation is governed by the allowable pressure reduction, the size of the useable stored capacity of the boiler (see also fig. A2.1) and the time response of the firing sys­ tem. If no other actions are taken, the unit output will finally decrease to point B on the sliding pressure line.

The power increase that can be achieved within seconds with conventional tur­ bine units equipped with a reheater is about 40 - 50% of the throttled reserve since only the HP section of the turbine reacts spontaneously. The IP and LP tur­ bines contribute to the output increase only as a function of the time response of the reheater and crossover. Thus, to supply an increased power output reserve of 5%, a throttle degree of about 10% would be necessary [15].

Units operating at constant main steam pressure have a “natural ” throttle reserve when operating below rated output, but maximum allowable pressure reduction limits the use of this reserve. Also, as these units generally have a higher heat rate than units operating in sliding pressure mode, the choice of using constant main steam pressure operation is made from other reasons than the ability to provide primary control reserves [14, 33].

Opening of overload valves (V)

Overload valves are additional valves which might be installed to feed steam from the main steam system to downstream of the first stages of the HP turbine, as shown in figure A2.4. The fitting of these valves results in a slightly lowered turbine efficiency compared to a design without additional steam inlet, although the valves are closed in normal operation [14].

As illustrated in figure A2.6 this method has the advantage compared to the HP valve dethrottling, that the unit can normally be operated in sliding pressure mode (point V0) and still be able to supply the required additional output. How­ ever, when additional power is being generated by overload valves, the efficiency is considerably reduced, both because the extra steam does not use all turbine stages in the HP section, and because the stages up to the extra steam inlet oper ­ ate at a very reduced efficiency due to the low steam fill. After the extra steam has been utilized, the unit will therefore end up in an operating point V) with reduced output.

162 A2.3 Fossil fuelled steam power units

Main steam pressure p^(%)

Constant pressure operation

HP control valve dethroning

Sliding pressure HP overload Valve operation opening

Overload valve design

Unit output Pg (%)

Figure A2.6 Comparison of 5% HP turbine control valve dethrottling and open ­ ing of HP overload valve [30]

Due to the higher steam consumption compared to the HP throttling method, the same power vs. time characteristics can only be achieved by a greater utilization of the stored energy in the boiler. Assuming a constant boiler thermal output, a greater pressure reduction is necessary than by using the HP throttling method. Overload valves have to be designed for approximately double steam flow com­ pared to the HP control valves to achieve the same output increase as for the throttling method [14].

Cutting off HP feedwater heaters (HS, HW)

Cutting off high pressure feedwater heaters permits the extraction steam nor ­ mally bled to the HP feedwater heaters to be used to increase the turbine power. The time response depends on whether the feed heaters are cut off on the steam side by direct isolation of the extraction lines with valves (HS), or by bypassing the feedwater around the heaters (HW). In the latter case, the extraction lines are not physically closed, but the reduced flow of feedwater through the preheaters causes a counter-pressure to block the extraction of steam from the turbine [72]. However, neither method is as single action able to fulfil the UCPTE 5 sec. rec­ ommendation [14].

Cutting off HP feed heaters changes the feedwater temperature ahead of the boiler and causes thermal stressing of components and affects the temperature balance in the furnace. The frequency of use of this method therefore have to be limited.

163 Appendix 2. Primary control in thermal power units

LP feedwater heater shutoff and condensate stoppage (LS, C)

Similar to cutting off the HP feed heaters, cutting off the low pressure feedwater heaters (LS) also causes a power increase as a result of additional steam flow made available to the turbine. The flow of condensate is simultaneously also shut off (C) to avoid the colder condensate from reaching the feedwater tank. The blocked condensate flow is stored in the condenser or a condensate receiver, while the level of stored feedwater in the feedwater tank decreases. After the acti­ vation of the stored energy, the unit have to enter a “refill phase ” with increased firing in order to refill the storage in the feedwater tank.

For this method there are considerable restrictions on the duration of each activa­ tion. The periods for which this action can be taken depends on the useable water volumes stored in the condenser and the feedwater tank. Also the amount of reserve available is considerably reduced when the unit is operated below rated output. Simulations have shown that while the condensate stoppage supplies an additional output of 6.35% at rated unit output, this decreases to only 2% addi­ tional output at 50% unit load [31].

Combined condensate stoppage

Due to the insufficient reserve capability, the condensate stoppage is combined with a slight throttling of the HP control valves to fulfil the reserve recommenda ­ tions, a method termed Combined condensate stoppage [31, 32]. The necessary amount of throttling is then much less than by the throttle method alone, resulting in a considerable reduction of operational costs. Figure A2.7 shows an illustra­ tion of the method in a 550 MW German coal fired power plant operating at 80% of rated load.

Additional output dP (%) Additional boiler firing HP valve ___dethrottlingdethroning 5.0 □ Condensate ■ stoppage 2.5

0.0

0 10 20 30 200 400 600 800 1000 1200 Time (s)

Figure A2.7 Illustration of the method of Combined condensate stoppage for a 550 MW German coal fired power plant at 80% of rated load [32]

164 A2.3 Fossil fuelled steam power units

At reduced load, the contribution from the condensate stoppage (CONDSTOP) is reduced and the HP valve dethrottling have to supply a correspondingly larger part of the required additional output.

Extensive tests of a 550 MW pit coal unit commissioned in 1994 [73] equipped for combined condensate stoppage, show that the German primary control requirement of 5% additional output within 30 seconds can be realized without HP valve dethrottling down to 78% of rated unit load. However, the unit is oper ­ ated with a mini mum throttle degree of 2% also above 78% load to handle small frequency deviations. The CONDSTOP is activated only at larger deviations.

The unit is equipped for both primary and secondary control operation in the load range 50-100%. While operated with conventional HP valve throttling only, the unit would be unable to Mill the primary reserve requirement above 88% load to prevent violation of rated boiler pressure. However, with CONDSTOP active the reserve requirement can be fulfilled up to 100% load, as the CONDSTOP is able to handle 5% overload for a couple of minutes without increasing boiler load above 100%, until minimum water level of the feedwater tank is reached.

Figure A2.8 shows the considerable reduction in HP valve throttling when CONDSTOP is used. This reduces the problem with heat rate increase due to the throttled HP valve during normal operation, and reduces the operational costs. In comparison, the CONDSTOP requires additional investments of approximately 4.5 MNOK (1 MDM).

Main steam pressure Pms(%)

100 -

80 -

60 - \ Unit control range 40 - HP turbine control valve opening yt (%)

20 - - 50

Sliding pressure With Without operation CONDSTOP CONDSTOP

Figure A2.8 Reduction of necessary HP valve throttling by CONDSTOP [73]

165 Appendix 2. Primary control in thermal power units

Increasing boiler thermal output (T)

All actions described above are limited in duration by the size of the steam and/or water storage capacity. Thus, in every case it is necessary to increase the boiler output in parallel with these actions by raising the firing rate; not only to main ­ tain the power output increase but also to restore the original energy content of the boiler and the rest of the water/steam cycle.

A2.3.2 Operational comparison of different methods

Measurements of the different single actions made at a variety of power plant show that only the opening of throttled HP valves or the use of overload valves with an accordingly larger steam throughput reserve, are capable of providing an adequate increase in power generation within the period of up to 5 seconds [14]. All other actions do not induce a power increase until after 5 seconds; maximum increase is usually not reached until after about 40 seconds. Table A2.1 shows a qualitative comparison of characteristics and effects of the different (single) actions. A combination of HP throttling and condensate stoppage, however, not only fulfils the general recommendations for primary control, but also improves the response characteristics further, which is useful in smaller isolated systems.

LP feed HP valve Overload HP feed heater trip/ throttling valve heater trip Condensate stoppage

Additional investment costs - mech. engineering no yes yes yes - control/instr. systems no yes yes yes Increase in operational costs due to efficiency losses - during provision yes low no no - after activation no yes yes yes - Duration of use unlimited unlimited limited limited - Frequency of use unlimited unlimited limited restricted Usable within 5 s yes yes no yes Availability restrictions no no possible possible Special measures for reserve restoration no no yes yes

Table A2.1 Comparison of characteristics and effects of different single methods to meet fast power demands [14]

166 A2.3 Fossil fuelled steam power units

Extensive tests made at 30 conventional thermal power plant of different types in operation in Australia, Germany, Denmark, England, Ireland and South Africa [13] show that the short-term dynamic characteristics are influenced mainly by four factors:

• unit control configuration (TFM, BFM or UCM) • throttle degree Dy • stored energy characteristics (response of MW output and steam pressure to a movement of the turbine control valves at nominal constant heat input) • plant type and fuel

Units operating in the BF and UC control modes have the fastest response rates in the seconds range. The choice of steam pressure set-point affects both the speed and amplitude of the power response in the seconds range. Once-through boilers and CCGT plant show a faster response capability than drum type boiler units of similar rating. Coal fired units are the slowest to respond in the minutes range compared to gas- and oil fired units of similar rating.

A2.3.3 Combined heat and power plant (CHP)

Similar to the LP feedwater heater shutoff method, combined heat and power plant (CHP) provide a very efficient and cost-effective primary reserve by shut ­ ting off the extraction steam used for district heating purposes [62, 72]. In the crossover between the IP and LP turbines valves are installed to regulate the steam flow to the LP turbine according to the amount of steam required for the district heating. If the flow of steam to the district heating is completely shut off, the full amount of steam is made available to the LP turbine. Depending on the turbine design, this might induce an increased unit output of 20-30% at rated boiler output.

The water based district heating system provides a nearly unl imited heat storage capacity as seen from the primary control, as activated primary control reserves should be de-activated within 15 minutes. Measurements in the district heating system of Berlin have shown that the heat supply can be closed for nearly two hours before the cooling becomes ‘noticeable ’ by the customers [72]. This is of course highly dependent on factors as ambient temperature, room temperature and size, quality of the building and isolation, district heating distribution tem­ perature etc. More detailed analyses show as an illustration that a 4 minute shut off of the district heating at an ambient temperature of -15°C, causes a room tem­ perature decrease of 0.74°C [62].

The operational costs related to this method are also very low compared to the other methods described above. Among other things, it is not necessary to use a

167 Appendix 2. Primary control in thermal power units refill phase as for the condensate stoppage method.

However, the number of CHP plant with steam extraction in Europe is rather lim­ ited [64]. The countries which have the highest number of such units are Den ­ mark and England, and perhaps also the new UCPTE partners like former East Germany. The method is in principle also applicable for process industry counter ­ pressure steam extraction, provided the customer process can be shut off for a limited period of time.

A2.4 Nuclear power plant

Of all the UCPTE partners only France and Germany to some extent use also nuclear power plant for primary control. The UCPTE primary control recommen ­ dation for German nuclear power plant is shown in figure A2.2, where the full 5% additional output is requested within 5 seconds.

The possibilities for keeping primary control reserves in a nuclear power plant are in principle the same as in a conventional fossil fuelled plant. There are how ­ ever some important differences which will be briefly described, based on refer­ ences [17, 34, 40].

A2.4.1 Pressurized Water Reactor (PWR)

Reactor process dynamics

The reactor process of the PWR has in itself dynamic characteristics well suited to handle sudden changes in the unit load demand.

The coolant in a PWR acts as a nuclear reaction moderating medium as well as a heat transport medium. This coolant, or moderator, slows down high energy neu ­ trons to thermal energy levels to facilitate the nuclear fission reaction. An increase of reactor power causes an increase of the moderator temperature with a corresponding decrease of fluid density. This lowers the nuclear fission rate, act­ ing as a negative feedback in the process dynamics.

PWR units are operated in Reactor following mode (“BFM”) with load change commands being applied to the turbine, and the reactor automatically adjusting to the new load level. When the HP control valves open in response to a sudden increase in load demand, letting more steam into the turbine, the water level in the steam generator drops. To restore the water level the feed water flow is increased, and the mismatch between the original reactor power level and the

168 A2A Nuclear power plant

increased steam generator load results in a decrease of the moderator temperature and pressure, increasing the fluid’s density. This again causes an increase of the neutron multiplication rate which provides an initial increase in the reactor power level, followed by a withdrawal of absorber rods.

Thus, the reactor itself responds to changes in the load demand without the need of special primary control systems. The reactor primary control system only serves to further improve the speed of the reaction and to supervise important process variables.

The secondary water/steam cycle

As opposed to conventional steam power units, the German KWU-PWR units (manufactured by Kraftwerk Union, KWU) are operated with a main steam pres ­ sure characteristic which decreases with increasing load, as illustrated in figure A2.9. This means that due to the reduced main steam pressure the units stays at the new increased output level after the utilization of excess steam in the steam generator, and less additional reactor output is needed. Almost any “normal ” part load operation gives a sufficient storage of excess steam in the steam generator to fulfil the primary control recommendations.

Also, the reheater is small compared to conventional steam power units, causing a much faster response of the IP and LP turbines.

Temperature (°C) Coolant temperature at steam generator inlet 320 -

Mean coolant temperature 300 -

Coolant temperature at steam generator outlet 280 -

Main steam pressure p ^(bar) - 90

Main steam pressure at steam generator outlet

60

0 20 40 60 80 100 Unit output P0 (%)

Figure A2.9 Stationary load characteristic of German KWU-PWR unit [34]

169 Appendix 2. Primary control in thermal power units

Operational limitations

Tests made at a 1300 MW German PWR unit illustrate the excellent control char ­ acteristics of these units by supplying an additional stationary generator output of 12.2% of rated load within 5 seconds without exceeding any limitations [34].

Figure A2.9 shows that for the normal load range the mean coolant temperature is constant, causing minimal thermal stresses in the components. In principle there are no important limitations based on the type and frequency of the load changes for PWR units, especially not for small stepwise changes of 5-10% of rated load. The most important operational limitations are

• not exceeding maximum reactor thermal load (typically 103%) when returning to rated load operation by activation of reserves, • not exceeding minimum main steam pressure at fast load increases, but • practically no limitations due to end of fuel cycle.

One reason that causes nuclear power plant owners to restrict the primary control operation of their units, is the danger of so-called Pellet-Cladding-Interaction (PCI). When the load level is reduced, the pellets within the fuel rods contract due to the reduced temperature, creating fissures in the pellet and between the pellet and the cladding. When the load is increased again, a more or less large and sudden contact (interaction) between pellet and cladding occurs, causing tensions in the cladding. These tensions together with a possible creation of fissure gases give rise to corrosion and danger of fuel rod damage.

The possibility of an actual fuel rod defect due to PCI is not thoroughly researched, but it is believed that frequent and fast load changes over time will cause damages to the rods. This problem is however expected to be reduced or even removed completely in the next generation of nuclear power units [40].

A2.4.2 Boiling water reactor (BWR)

Reactor process dynamics

As opposed to PWR units, the BWR units are operated with constant main steam pressure over the load range, controlled by the turbine valves (Turbine following mode, TFM). The reactor output is controlled with the coolant circulation pump and the control rods, relying on the moderating effect of the steam generated in the reactor to adjust the neutron multiplication rate. The power level is deter­ mined by a balance established between the amount of fuel in the core, the amount of neutron-absorbing material in the control rods and the core steam/ water volume ratio.

170 A2.4 Nuclear power plant

When the load demand is suddenly increased, the unit controller increases the coolant circulation to increase the steam production, and the reactor power level rises to the ordered level. However, in spite of the very fast output increase (typi ­ cally 40%/min) there is a fuel dependent time delay of about 5 seconds between load demand and output increase, making the BWR unit unable to fulfil the UCPTE recommendations.

To enable the BWR unit to fulfil the UCPTE recommendations a special control scheme can be applied in which the initial output increase is taken from the steam storage in the reactor, allowing a certain drop in the steam pressure [30]. Allowa­ ble pressure change is typically between +1 and -2.5 bar. This special control scheme is however normally not in operation, as the dynamic characteristics of the unit are found to be sufficient for the interconnected grid operation without the scheme.

Operational limitations

Similar to the PWR unit, the most important operational limitations for the BWR (in addition to the danger of PCI damages) are:

• not exceeding maximum reactor thermal load (typically 102%) for more than one minute, • not exceeding transient neutron flow with more than 15% above the original load at fast load increases, but • practically no limitations due to end of fuel cycle as for PWR.

A2.4.3 Economic aspects

Despite the excellent primary control characteristics of nuclear power units, they are mostly for economic reasons normally not taking part in primary control. Even German nuclear power units are often operated with a frequency deadband of ±50-100 mHz.

Compared to conventional units with superheated steam turbines, the saturated steam turbines of the nuclear power units have a larger efficiency reduction when operating at part load. This alone is however not an important economic aspect, as the fuel costs are low. The main reason for not keeping primary control reserves in nuclear power units is the fact that the necessary output reduction during normal operation causes a less utilisation of the high capital costs [34]. In addition, the large unit ratings cause substantial relocation costs, as described in Chapter 5. However, if a nuclear unit was running on part load due to other reasons, it could provide a very cheap and effective primary control reserve [38].

171 Appendix 2. Primary control in thermal power units

Other possible methods to meet fast power demands without having to reduce unit output are also not feasible in nuclear units today:

Throttling of IP valves only serves to reduce the possible response characteris ­ tics, as they have a very bad control characteristic, there is very little storage vol ­ ume in the reheater, and the unit efficiency would be considerably reduced. Overload valves are not applicable due to construction and boundary problems. Due to the decreasing main steam pressure characteristic they would in any case result in a much less utilization of the stored steam volume than the HP control valves of PWR units.

Possible methods on the feedwater side of a nuclear unit influences the operation of the reactor. Especially temperature gradients are undesirable due to the reactor dynamics, excluding feedwater heater shutoff . The only possibility left is then condensate stoppage, but simulations have shown that this method is also not applicable, both because the resulting increased output is not sufficient to fulfil the recommendations, and because the storage capacity of the condenser and the feedwater tank is too small. Increasing this capacity is also not economically fea­ sible in the present unit construction.

A2.5 Gas turbine units

Gas turbine units are usually not used for primary control in the UCPTE system [10]. Due to the high operational costs the reserve would be far too expensive, and they are normally in operation during peak load hours only.

However, gas turbines do have an excellent response characteristic and are useful e.g. in smaller island systems, although the number of stepwise load changes has to be limited to avoid reductions in unit life time. The capability for fast load changes in gas turbines is based on the following possible methods [35]:

• Increasing the fuel supply and thereby also the turbine inlet temperature • Adjusting the compressor guide vanes to increase the air/fuel ratio • Combined water injection and fuel supply increase, keeping the turbine inlet temperature nearly constant

As an illustration of the gas turbine response capability, the overtemperature method typically enables a load change rate of 10%/second, while the water injection method typically enables a load change rate of 1-2%/second.

172 Appendix 3

Standard SIMPOW components

This appendix presents the standard SIMPOW components used for the simula­ tions in Chapter 3. High voltage DC connection with primary control and in Chapter 4. Automatic secondary control.

The simulation model of Chapter 3 includes a detailed representation of the 500 MW Skagerrak 3 DC cable [3] connecting a hydro power system with 2 units and a thermal power system with 3 conventional units. For the phase compensator and the 90 MVAr capacitor bank at the converter terminals, actual data from the Norwegian side of the Skagerrak installation are used [19]. The additional reac­ tive supply from the harmonic filter installations at the converter terminals is not needed in these simulations, and is therefore not included in the model.

The model used in Chapter 4 includes also several new components programmed in the DSL programming language of SIMPOW [24]. These components are defined in Chapter 4 and in Appendix 6 Hydraulic turbine models.

A3.1 Loads

A conventional way to model loads is with voltage and frequency dependency as shown in eq. (A3.1) and (A3.2) [16, 24]:

(A3.1)

77 Afg f NQ Q - Qo ■ (jj~ ) ' (A (A3.2) UN JN

A typical Norwegian winter load includes a lot of lighting and electric space heating, with a load factor of cos9 ~ 0.995 (tan 9 ~ 0.1), while loads in the European thermal power system are of a mixed type with very little electrical space heating. A typical load factor could be cos 9 ~ 0.95.

Table A3.1 gives typical values which could be applied in the two systems:

173 Appendix 3. Standard SIMPOW components

MP NP MQ NQ costp

Hydro 1.5 0 2.5 0 0.995 Thermal 1.0 0.5 2.0 -1.0 0.950

Table A3.1 Load parameters for hydro- and thermal power systems [16]

In the simulations in Chapter 3 all loads are actually modelled as voltage and fre­ quency independent to get a clearer picture of the interaction between the DC connection and the generating units. This causes a slightly reduced damping of the transients. In Chapter 4 the values for a hydro system as given in table A3.1 are used.

A3.2 Synchronous machines

Thermal power units are equipped with turbo rotor generators due to the high rotational speed, while the hydro power units operate at a lower speed and require a relatively large number of poles to produce rated frequency. These units therefore use salient pole generators which are better suited mechanically to the larger number of poles.

A3.2.1 Synchronous machine models

The exact mathematical structure of the synchronous machine models used in SIMPOW are not known, but all synchronous machines are represented with “standard models” [24]. In Chapter 3 where the short-term transients are of pri ­ mary interest, the most detailed model is used with field winding and armature and damper windings in d- and q-axis. The round rotor machines with a solid steel rotor are represented with one field winding and one damper winding in the d-axis, and two damper windings in the q-axis as the solid steel rotor body creates an additional damping effect. Salient pole hydro power machines, on the other hand, are modelled with only one damper winding in the q-axis.

The dqO-transform gives the following general voltage equations for a synchro ­ nous machine model in per unit values; with field winding voltage efd , short circuited damper windings and d- and q-axis armature winding voltages ed and eq, as shown in eq. (A3.3) to (A3.8) [17]:

d\\f M efd ----- Jf +Rfd ifd (A3.3) A3.2 Synchronous machines

dy, 6d " dt ™rVq-Ra ld (A3.4)

dy ei = dt + (A3.5)

e» dt *«'» (A3.6 )

o= * “+*««« (A3.7)

(A3.8) where oor - rotor angular velocity (rad/s) k - number of damper windings used in the model.

The corresponding flux linkage equations for a round rotor machine with 2 damper windings in the q-axis are given in eq. (A3.9) to (A3.15):

Y/a = Lffjfd ~ LaJd + L/idhd (A3.9)

Va = Lad ifd - (Lad + Lt) id + Lad ild (A3.10)

Vq = _ (Laq + V {q + Laqhq + Laq ilq (A3.11)

Vo = -Vo (A3.12)

Via - Lfid ifd ~ LaJd + Ludhd (A3.13)

Vi9 = ~ Laq iq + LUqilq + Laq i2q (A3.14)

V2? = ~Laq iq + Laq ilq + L22qi2q (A3.15)

In the case of a salient pole machine, eq. (A3.15) is omitted. For the simplified synchronous machines used in Chapter 4 all terms related to the damper wind ­ ings are omitted.

The air-gap torque of the synchronous machine is defined as:

Te = Vjq ~ Vq'd (A3.16)

175 Appendix 3. Standard SIMPOW components

A3.2.2 Equation of motion

The equation of motion (swing equation) can be written as [17]:

2H^S+D_dS =T _T (A3.17) tojV dt 2 “jsdt m e where H - inertia constant [MWs/MVA] D - damping constant [pu/pu] Tm - mechanical torque [pu] 5 - rotor angle with respect to synchronously rotating ref­ erence [rad]

d& Setting Aror (A3.18) dt o> - toN equation (A3.17) can be represented in block diagram form in the s-domain as shown in figure A3.1:

Te I 1 ®0 Tm ) 2Hs + D S

Figure A3.1 Block diagram of equation of motion [17]

In Chapter 3 casually chosen typical data are used for the synchronous machines, taken from examples in reference [18] while data for selected Norwegian power plant are used in Chapter 4.

A3.2.3 Exciters

Exciters for the different synchronous machines used in chapter 3 are chosen according to reference [18]. The thermal swing bus unit is equipped with a DC generator-commutator exciter with a structure as shown in figure A3.2, while the two smaller units are equipped with a potential source controlled rectifier exciter as shown in figure A3.3, where the excitation power is supplied through a trans ­ former from generator terminals.

176 A3.2 Synchronous machines

Controller Exciter VRLIM 1 + sTC 1 + sTB 1 + sTA -VRLIM

KE + SE

1 + sTF Stabilizer

Figure A3.2 DC generator-commutator exciter (SIMPOW type 1) [24]

Figure A3.3 Potential source controlled rectifier exciter (SIMPOW type WJ) [24]

For the hydro power units and the phase compensators a static voltage exciter with a structure as shown in figure A3.4 is used. This rather simple exciter model is used also in the long-term simulations of Chapter 4.

u UEMAX (1 + sT1)(1 + sT2) (1 + ST3)(1 + sT4) UEMIN

Figure A3.4 Static voltage exciter (SIMPOW type BBC1) [24]

A3.2.4 Power system stabilizers

Some of the units are equipped with a power system stabilizer which provides feedback from unit output power Pe to the voltage exciter, in order to reduce sys­ tem oscillations [20]. No optimization of the PSS parameters are made. The power system stabilizer used in Chapter 3 is shown in figure A3.5, while the sta­ bilizer used in Chapter 4 is shown in figure A3.6. Appendix 3. Standard SIMPOW components

VsLIM STW1 sTW2 (1 + sT1)(1 + sT3) 1 + STW1 (1 + sT2)(1 + sT4) -VsLIM

Figure A3.5 Power system stabilizer (Simplified structure of SIMPOW type PSS1) [24]

VsMAX 1 +ST1 1 +sT3 1 + sT2 1 + sT4 1 +ST6 VsMIN

Figure A3.6 Power system stabilizer (SIMPOW type PSS3) [24]

The PSS of figure A3.6 can be extended with several additional poles and zeros with the general transfer function:

1 + sA5 + s2A6 A(,) (A3.19) (1 +sAl + s2A2) (1 +sA3 + s2AA)

A3.3 Turbines and governors

Unfortunately, the number and types of turbine and governor models available as standard models in SIMPOW are rather limited. This section describes the mod­ els which are used in the simulations in Chapter 3. For the long-term simulations of Chapter 4 new turbine models were designed in the SIMPOW programming language DSL.

A3.3.1 Steam turbines

The two steam turbine models available in SIMPOW are based on the simplified IEEE model structures [21, 22], where flows into and out of any steam vessel are assumed to be related by a simple time constant. The simplest model (SIMPOW type ST1) representing a single reheat steam turbine, is shown in figure A3.7 with explanatory remarks. The other model is a more general structure as shown in figure A3.8 (SIMPOW type ST2).

When applying these turbine models, it is assumed that the steam pressure some­ where in the steam generator remains constant during the time interval of the simulation. This could typically be the drum pressure of a drum-type boiler, while for a once-through boiler the point of constant pressure could be deter-

178 A3.3 Turbines and governors mined by tests or simulations of the boiler. Boiler process dynamics does not influence short term dynamic simulations, and are thus not included in the repre ­ sentation. The boiler tube drop is also ignored.

HP-turbine power fraction Tm 1 +sTC Steam chest time constant 1 -KH 1 + sTR Reheater time constant

Figure A3.7 Simplified model of single reheat steam turbine [24] (SIMPOW type ST1)

The input variable Y is to be interpreted as the flow area of the control valves. Any non-linearities between control signals and valve flow areas are assumed to be included in the turbine governor module. Intercept valves between the reheater and the second turbine stage are omitted in these models.

Extraction steam taken at various turbine stages to heat feedwater usually does not have significance for stability studies, and are not included in the models.

1 + sT4 1 + sT3 1 +sT2 1 + sT1

Figure A3.8 General model of double reheat tandem compound steam tur ­ bine [21, 24]; Kj+K2+K3+K4 = 1.0 (SIMPOW type ST2)

As illustrated, the general model of figure A3.8 is applicable to a double reheat tandem compound (one shaft) steam turbine, but by setting the appropriate con ­ stants to zero the structure can be applied to most common turbine types. In most

179 Appendix 3. Standard SIMPOW components cases, the turbine response is adequately modelled by three time constants; the steam chest T4, the reheater T3 and the crossover T2 [22]. The sum of the power fraction parameters has to be unity; Kj + K2 + K3 + K4 = 1.0.

Models for cross compound steam turbines (turbines mounted on two separate shafts with two generators) are not available in SIMPOW.

In Chapter 3 it is chosen to represent the smallest thermal unit with the simplified two stage turbine model of figure A3.7, while the two larger units are represented with the general model of figure A3.8 as a three stage turbine (HP, IP and LP tur­ bines) with one reheat. Also, in Chapter 4 two units in the “Swedish ring ” are represented with the simplest two stage turbine model.

A3.3.2 Steam turbine governor

Like the steam turbine models, the steam turbine governor representation availa­ ble in SIMPOW (SG2) is based on the IEEE governor model [21], as shown in figure A3.9. With the exception of rate and position limits are other non-lineari ­ ties in the mechanism neglected in this model. (Pqref is the load reference used as initial power P0.)

POREF YPMAX YMAX

K*(1 + sT2) 1 +sT1

Governor YPMIN YMIN

Valve servo mechanism

Figure A3.9 Steam turbine governor (SIMPOW type SG2) [21, 24]

This model can represent both mechanical-hydraulic and electro-hydraulic gov ­ ernors in normal primary control operation. For problems involving large accel­ erations with discrete and non-linear actions provided in a particular design, the speed/load control block should be defined by the manufacturer. Reference [22] describes some specific examples of more advanced governor representations.

A3.3.3 Hydro turbines

Hydro turbines are represented in SIMPOW only with the classic linearized model for turbine and penstock [21], with turbine damping included. The model is shown in figure A3.10.

180 A3.3 Turbines and governors

1 - s*YO*TW 1 + s*Y0*TW/2 + Turbine and penstock Turbine damping

o 0) +

Figure A3.10 Simplified model of hydro turbine and penstock [24] (SIMPOW type HT1)

The classic linear transfer function for an ideal lossless turbine (which can also be found from equations (A6.31) - (A6.34) in Appendix 6 ):

(A3.20) AY l+0.5Fo7> where Y0 - initial gate opening Tw - water starting time, is derived using the following simplifications:

- Hydraulic resistance is neglected - Non-elastic water column (non-elastic penstock pipe and incompressible fluid) - Operation at nominal head (Hq = 1.0 pu) and efficiency (r|0=1.0 pu) - Velocity of water varies directly with gate opening and with the square root of the net head - No or very large surge chamber - Very large reservoir

Mathematically, the ‘damping constant ’ KD in figure A3.10 is a result of the line ­ arization of the mechanical torque/power equation:

to,'o Ago A P,m (PU) (A3.21) CO'N where

181 Appendix 3. Standard SIMPOW components

The damping constant KD is therefore set equal to the per unit initial turbine load.

A linear turbine model as shown in figure A3.10 is useful for system studies using linear analysis tools (frequency response, eigenvaules etc.). Its use in time domain simulations is however now discouraged, since it is limited to small per ­ turbations around an operating point, and it does not offer any computational simplicity relative to a more complicated non-linear model. A linear turbine model is thus adequate for small signal stability studies, but is not recommended for transient stability studies involving large excursions in turbine loading. Already at a 0.2 pu gate position step the difference in mechanical power response between the linear and a non-linear model is significant [23]. A number of different turbine models of varying complexity to be used for power system studies are presented in references [17] and [23].

The linear hydro turbine model of figure A3.10 is used in the simulations of Chapter 3, while for the long-term simulations with large variations in turbine loading a 1. order non-linear turbine model is implemented in DSL code. This turbine model is described in Appendix 6 .

A3.3.4 Hydro turbine governor

The hydro turbine governor is also represented in SIMPOW only with the general IEEE governor model [21], as shown in figure A3.11. The standard model (SG3) is used in Chapter 3, while in Chapter 4 a modified governor with similar struc­ ture is implemented in DSL (see figure 4.19).

This general model is derived from an approximate non-linear model of a mechanical-hydraulic speed governor by neglecting the pilot valve time constant and the gate servo motor rate limits. The latter simplification is made under the assumption that the transient droop feedback of the non-linear model reduces the likelihood of rate limiting in stability analyses. Gate servomotor position and effective valve position is also assumed to be equal, making it possible to impose gate position limits outside the feedback loops.

POREF

REF K*(1 + sT2) +( ) o (1 +sT1)(1 + sT3) Governor Valve servo mechanism

Figure A3.11 Hydro turbine governor [21, 24]

182 A3.4 The HVDC system

A number of turbine governors models of greater complexity are also presented in references [17] and [23].

A3.4 The HVDC system

The HVDC system used in the simulations in Chapter 3 is a detailed SIMPOW representation of the 500 MW Skagerrak 3 connection, including phase compen ­ sators and capacitor banks [3, 19].

A3.4.1 AC/DC converter terminals

Again, the exact mathematical structure of the HVDC system as implemented in SIMPOW is not known. Instead, this section will present the converter equations as given in reference [27].

An AC/DC converter terminal can be modelled in SIMPOW with an arbitrary number of 6 -pulse converters as shown in figure A3.12, connected in series on the DC side and in parallel on the AC side. The converter transformer is included in the converter model, with the OLTC used to keep the firing angles within the desired range. For transient stability simulations, however, the tap-changer action is too slow and hence not considered.

Figure A3.12 6-pulse AC/DC converter model [27]

Assuming that the influence on the electro-mechanical transients from the AC- side harmonic currents and voltages are negligible, it is sufficient to consider the fundamental frequency components of AC currents and voltages. The HVDC converter then interacts with the AC network by the phasors of the fundamental frequency component of its AC current, which is injected at the AC bus.

The AC-side harmonic filters can be represented at 50 Hz by their admittance, and the DC-side filters are neglected as they only absorb harmonics.

The voltage equation of a 6 -pulse converter can then be written as [27]:

183 Appendix 3. Standard SIMPOW components

dL Ud6 = Udo cosa ~RcId- Lc dt (A3.22) where U, - ideal no-load direct current dO 7T n

u.dON Rc — (^r + <5U ~J - equivalent commutating resistance dN

J K, d x UdON L„ - —L - equivalent commutating inductance 3 cC0 /.dN and where lc is a constant reflecting the resulting transformer inductance of a 6 - pulse converter seen from the DC terminals (1.5

The total DC voltage of a converter station with k 6 -pulse converters is:

Ud ~ k ' Ud6 (A3.23)

The fundamental frequency components of the AC current in phase and quadra­ ture to the commutation voltage is given by [27]:

V6 , 4ciCOS(p = — V p(a,p) (A3.24)

AzciSintP = ^d ■ X(«, p) (A3.25) where p(a, p) = ^ [ cos a + cos (a + p) ]

X(a, p) = \ [sina + sin (a + p) ] + Z ^a x UdON ld

% and the overlap angle p, p < - , is given by:

UdON h cosa- cos (a + p) =2d x— (A3.26) dN UdO

The total fundamental frequency component of the AC current for a converter station with k 6 -pulse converters is then: A3.4 The HVDC system

/j = k • ^ (A3.27)

The DC reactor is modelled by its inductance, and overhead lines and cables are modelled by their II-equivalents.

A3.4.2 Control system

SIMPOW uses a detailed representation of the HVDC control system. Figure A3.13 shows the control system structure, which includes the following control ­ lers: CR - current controller COR - current order controller GR - voltage or gamma controller (at inverter) CC - central controller DCR - power-frequency controller FPD - power-frequency measure transducer

Gamma (voltage) controller Current order controller/ Current controller

Central controller Pref------

Power-frequency contoller

Power-frequency measure transducer

Figure A3.13 HVDC control system [24]

The current controller CR shown in figure A3.14 controls the thyristor firing angle a according to the current order IO from the current order controller for both rectifier and inverter.

The current order is corrected with the current margin Im (0.1-0.15 IdN ) before being fed to the controller, which is of Pi-type. In normal operation the rectifier controls the DC current Id (constant current control mode CC) and the inverter controls the voltage Ud (constant extinction angle control mode CEA).

185 Appendix 3. Standard SIMPOW components

The converter itself is represented with a time constant 72 and angle and angle change rate limits.

DAMAX AMAX

AMAX DAMIN AMIN

AMIN

Ud

Figure A3.14 Current controller (SIMPOW type CR) [24]

In case of a pole to earth fault on the DC line, the rectifier is also forced into inverter operation to discharge the DC network and make all DC currents zero. This is done by applying a large signal to the current controller forcing the firing angle to its maximum limit when the DC voltage decreases below Ul. This signal is reset to zero when the DC voltage increases above U2. Typical values are 0.1 pu for Ul and 0.8 pu for U2 [27].

Other correction signals can also be added to the current controller, but are not used in this case.

The current order controller COR shown in figure A3.15 gives voltage depend ­ ent limits for the ordered current IO fed to the current controller. Maximum cur­ rent is limited to avoid thermal damage to the valves, while minimum limit is imposed to prevent the overlap angle from becoming too small and to avoid dis­ continuous DC current. Under low voltage conditions it is not desirable to main ­ tain rated DC current, both due to increased reactive power demand by the converters and due to risk of commutation failure. Allowable DC current is there ­ fore reduced under low voltage conditions by using a voltage dependent current order limiter (VDCOL). The structure of the VDCOL function is shown in figure A3.16.

The DC voltage (or current) input to the VDCOL function is filtered with a time constant TV which is switched between a smaller value TV1 for a decreasing voltage to ensure a fast current order reduction in case of a fault, and a larger value 7V2 for an increasing voltage to ensure a smooth start up. Sample and hold time TSH and delay time TDEAD might also be represented.

186 A3.4 The HVDC system

)------RV

1 + sTV

-sTDEAD VDCOL

Sample & hold

Figure A3.15 Current order controller (SIMPOW type COR) [24]

For normal voltages >UMAX the current order IO is independent of the voltage and equal to its reference value IOX, limited by upper limit UMAX and lower limit I2MIN. (The voltage UMAX indicates the voltage level at which maximum current order starts to decrease, typically 0.6 pu.)

For very low voltages (

In the voltage dependent area below UMAX there is also set a minimum slope KUMIN of the current characteristic (IO = KUMIN ■ UDV).

UMAX IO = UMAX

IO = 11 MAX'UDVAJMAX IO = IOX

IO = IOX*‘UDV/UMAX

I1MIN

KI * IOX IO = KUMIN*UDV I2MIN

Figure A3.16 Voltage dependent current order limiter (VDCOL) [24]

The commutation margin angle y may be modified in different ways. In this case, the following expression is applied, with yN the nominal commutation margin angle [24]:

Y = (l+dy c + dy R) • yN (A3.28)

187 Appendix 3. Standard SIMPOW components

where dy c = (10 - Id)

dy R = Ay from the voltage controller. DGO - constant, valid only for inverters

The structure of the voltage (or gamma) controller GR applied to the inverter terminal is shown in figure A3.17, where the gain KG < 0 to achieve the desired gamma control.

Udc MAX2

MIN2

Figure A3.17 Voltage controller (SIMPOW type GR) [24]

The central controller CC shown in figure A3.18 gives the output signal 101 to the current order controller.

TAB1

STCM TAB2

MODE

TAB2

1+sTU

TAB1

Figure A3.18 Central controller (SIMPOW type CC) [24]

Input to the central controller are, in addition to feedback of DC current and volt ­ age, signals from the DCR controller (DI or DP). The tables TAB1 and TAB2 are input tables for changing initial current/power order and total current/power order, respectively, as functions of time during the simulation. The function val­ ues are multiplied with the initial or total value.

The mode switch decides whether the controller should operate at constant cur­

188 A3.4 The HVDC system rent or constant power control. In constant power control mode (mode 1), there is a voltage setting influencing the voltage UDX with which the power order is divided to prevent overload at low voltages. If the DC voltage Udl is less than UDMIN (typically 0.7 pu), the power order is divided by UDO (typically initial DC voltage) and the control is changed from constant power to constant current mode. When the voltage Udl rises above UDRES (typically 0.85 pu), the control is changed back to constant power, with the power order being divided by Udl. A current margin controller with time constant TCM can also be included.

The power-frequency controller DCR giving input to the central controller has a structure as shown in figure A3.19. The controller includes a deadband DF, KF, a proportional gain kDC, output limiter and a filter transfer function F(s). The MODE switch of the central controller decides whether the output of the DCR controller is interpreted as AP or AI.

The filter transfer function can be chosen among several types of varying com­ plexity. Due to numerical problems with the frequency measurement of the FPD controller, the following transfer function was chosen [28]:

F(S) = (A3.29)

MAX/k,

AP/AI

Figure A3.19 Power-frequency controller (SIMPOW type DCR) [24]

The last element of the HVDC control system is the power-frequency measure transducer FPD as shown in figure A3.20. This transducer measures AC fre­ quency/, synchronous machi ne speed ro or AC line power transfer Pe. The trans ­ ducer includes a sample and hold function block and delay time TDEAD. The output Af is fed to the DCR controller.

Neither DCR- nor FPD-controllers are used on the Skagerrak HVDC connection today.

189 Appendix 3. Standard SIMPOW components

REF + -STDEAD 1 +sTM

Sample & hold

Figure A3.20 Power-frequency measure controller (SIMPOW type FPD) [24]

A3.5 SVC equipment

In some of the simulations SVC equipment is installed in the hydro system to reduce voltage fluctuations, replacing the original phase compensator. The rating of the SVC is chosen equal to the rating of the new SVC planned installed on the Norwegian side of the Skagerrak connection due to the increased reactive con ­ sumption after the commissioning of the thir d pole of this connection (±200 MVAr). The SVC is equipped with a PI controller, as shown in figure A3.21.

Voltage Positive sequence phasors transducer Scalars VPMAX BMAX

1 + STF VIMAX VPMIN BMIN

7777 VIMIN Figure A3.21 SVC controller (SIMPOW type SVS) [24]

The controlled voltage VC derived by the voltage transducer is given by:

VC = J(UR +1{ ■ Xc)2 + (Uj-IR XC)2 (A3.30)

190 Appendix 4

Basic theory of load-frequency control

In chapter 4 simulations are done to illustrate the use of automatic secondary control, or load-frequency control, in the Nordel system. With emphasis on the basic centralized LFC, the most important mathematical aspects of this control function are shown in this appendix. The general mathematical theory of both centralized and hierarchical load-frequency control is treated in detail in refer­ ence [29].

A4.1 Load-frequency control schemes

The classical load-frequency controller is shown in figure A4.1, giving the Area Control Error (ACE) as input to an integrating I or /Y-controller:

(A4.1) where G - area control error [MW] Px - sum of area interchange [MW] Pxo - area interchange set point [MW] Kr - area frequency bias setting [MW/Hz]

Pl-controller

Figure A4.1 Classical load-frequency controller [10] Appendix 4. Basic theory of load-frequency control

When one such controller alone is responsible for the ACE for a whole country, the control scheme is termed centralized LFC. In the UCPTE system, this scheme can be found in Belgium, Luxembourg, France, Greece, Italy, Holland, Austria and Portugal.

Another common scheme is the hierarchical LFC, where several regions have their own (centralized) controllers, but these are subordinate to a superior national controller. In such a hierarchical structure each region is responsible for its own deviation with respect to the neighbouring regions, while the national controller handles the interchange with other countries. A two-level LFC struc­ ture is shown in figure A4.2, but the principle is applicable to any number of lev­ els.

T0i

Figure A4.2 Two-level hierarchical load-frequency control [ 10]

For the national level of country i, the ACE has the same structure as for the cen ­ tralized LFC scheme:

G, = + (A4.2a) where index x for area interchange is omitted for simplicity, while for each subor ­ dinated region ij there exists an analogue ACE equation:

Gij = Pfj — Pyo — Cy ' AP

As will be seen below, the hierarchical LFC scheme is more redundant and secure than the centralized LFC, but it is also considerably more complicated to

192 A4.2 Frequency and power interchange implement. The hierarchical LFC scheme can be found in Switzerland, Spain and former Yugoslavia. See also section 4.2 for a discussion of different LFC schemes.

In Germany a special LFC scheme termed pluralistic LFC is used, where each region is responsible for the interchange with its neighbours while one region (RWE) is in addition responsible for the international interchange of all the Ger­ man regions.

A4.2 Frequency and power interchange

In a closed interconnected system, the sum of all area interchanges on the national level must be zero:

1^ = 0 (A4.3) U - 1

Similarly, the sum of interchanges between the regions ij within a country i is equal to the total national interchange:

m 1 C = (A4.4) V = 1

A4.2.1 Centralized LFC

As a basic case, an interconnected system with n centrally controlled countries is considered. Each country then has one centralized load-frequency controller of the classical type, as shown in figure A4.1.

The area control errors (ACE) Gt and the interchange equation for the n countries are:

G\ ~ Pl~ P10 + Krl ' (f-fio)

G2 = P2 ~ P20 + Kr2 ‘ /20) : (A4.5) G* = fa -f,0 + ' (f-Ao) 0 = P^+ P2 + ••• + Pn

Written as a matrix equation:

193 Appendix 4. Basic theory of load-frequency control

1 0 ... 0 Kr[ Pi P\Q + Kr\ ‘/l0 + G1 o i p2 P20 + Kr2 ' f20 + G2 (A4.6) 0 ... 1 Km Pn PnO + Krn ' fn0 + Gn 1 1 ... 1 0 J. 0

Under the condition that ^ 0, eq. (A4.6) has an unique solution:

£ p«o+ i «™/.o+ i f = K = 1______U = 1______W = 1 (A4.7)

M = 1

= ^0 + ' C/iO -j0 + Gi

= Pi0-Kri- ~fi0 + G: (A4.8) Z^r

The stationary situation (Gi = 0) is given by:

n n !?,.+ o

/ = n (A4.9) J.Kr,

£^o+ £ u — 1______u= 1______e* - r,o r,, iO (A4.10) Z^n, u = 1

Based on eq. (A4.9) and (A4.10) the following observations can be made for the stationary situation [29]:

1. A consistent set of reference values gives a solution in accordance with the ref­ erences:

194 A4.2 Frequency and power interchange

1, ...,n n (A4.11) X ^uO ~ 0 U — 1

In the case of a co-ordinated time correction (fiQ = /0 + A/0), the power inter ­ change will thus not be influenced.

2. An error e in the sum of power interchange reference values causes errors in frequency and power interchanges proportional to e:

1 f-fo + n ■ e fiO - fo ’ V K n (A4.12)

■ £

3. Wrong reference values for the frequency f0j in one or more countries causes a stationary frequency which is the arithmetic mean value of the settings weighted with the frequency bias setting:

n

(A4.13)

4. Any set of reference values will give an unique solution for frequency and power interchanges.

A4.2.2 Hierarchical LFC

Without showing the somewhat rigorous mathematical deductions, the following additional observations can be made if the countries where equipped with a hier ­ archical LFC scheme [29]:

1. The solutions of the superior hierarchical level (the national level) are func ­ tions only of the reference values and the parameters at the superior level. This implies that the frequency and the interchange of the country are defined only by the settings of the national controller. Possible regional setting errors are thus compensated.

195 Appendix 4. Basic theory of load-frequency control

2. The stationary solutions are identical with the solutions (A4.9)-(A4.10) for the centrally controlled system. This shows that for the stationary situation it does not matter whether one or more countries are using centralized or hierarchical LFC.

3. The regional values are functions of both regional settings as well as national settings, implying that a setting error on the national level causes deviations in the regional values, even if the regional settings themselves are correct.

4. A consistent set of reference values at the national as well as the regional level gives a solution in accordance with the frequency and area interchange refer­ ences.

5. If the frequency settings of the national controllers f0i are adjusted for time correction while the regional controllers are not adjusted, the regional inter ­ changes within a country are changed, while the total interchange for the coun ­ try is not influenced. This error is however eliminated when the regional participation factors and the frequency bias settings Krij are balanced:

n. (A4.14) X V = 1

6 . An error in the sum of regional interchange reference values within a country k (X^otv = P0k + efc) is shared between the regions according to the participa ­ tion factors ckj. Regions not belonging to country k are not influenced.

7. An error in the national interchange reference values (X^Ou ^ 0) will influ ­ ence the frequency and the interchanges in the whole interconnected grid.

8. Any set of reference values will give an unique solution for frequency and power interchanges.

A4.2.3 Controller failure in centralized LFC

When the central LFC in one or more countries fail, the line describing the ACE in eq. (A4.5) will be replaced by each country ’s primary control response:

APGi - APxi + APLi

=> "V (f~f) = P„-^, + APti (A4.15)

196 A4.2 Frequency and power interchange where X. - power-frequency characteristic of country i [MW/Hz] f - system frequency before the load change [Hz] Pxi - country interchanges before the load change [MW] APLi - load change or fault in the country [MW]

Equation (A4.15) can now be written in the same form as the ACE equations:

"APLi = Px,-f°+ \ ■ IJ-f) (A4.16)

Omitting the index x for country interchanges, the system equations become:

Gi = p\-pm + Kr\' (f~/io) = + ^ (/-/) : (A4.17) Gn ~ Pn~ PnO + Krn ' 0 = Py+ P2 + ... + Pn

Written as a matrix equation:

1 0 ... 0 Kr 1 P10 + Krl 'flO + Gl 0 1 (A4.18) 0 K 1 If.

Let a - the set of countries with intact LFC (3 - the set of countries with faulted LFC Q = a + (3 - all countries

Under the condition that £ Kru + ^ Xu ^ 0, equation (A4.18) has an unique solution: “€ a “e P

2 [P,o+^, /,o+GJ + 2 L^+K fu-U’LJ us a ue P f = (A4.19) 2«.»+ 2 A uea ue p i e a: P; - P,o + +Gi (A4.20)

197 Appendix 4. Basic theory of load-frequency control

ieP: Pt = PQi+X.- {fi-f)-APu (A4.21)

The stationary situation (Gi = 0) is given by:

2 [P,o+^, /»o) + 2

, _ me a m e p (A4.22) X ^r» + X A, « € a M € p i e a: Pi = P,o + Kri' C/)o “/) (A4.23)

,'eP: P, = P« + X,. (/)-/)-AP^, (A4.24)

Based on equations (A4.22) to (A4.24) the following observations can be made:

1. When all controllers are intact (a = Q) the same result as before is obtained:

2-p,o +2V,o ' 2*^ u *

Pi = PiO + Kri ■ (fiO ~f)

2. If all the load-frequency controllers should fail (P = Q), only the primary controllers would respond to the load change: 2^+2V2-2 . 2Af„ Frequency: / = X^M 2>T u u

XA/% U => A/ = f-f (A4.25) X\ u

Interchange power: AP, = Pz - p9 = A,. • (/9 -/) - APL.

=> AP, = ^ (*4-26)

198 A4.2 Frequency and power interchange

Generation: APGi = A Pt + A PLi = —— • ^APLh (A4.27) XX„ “

3. When suddenly one or more load-frequency controllers fail from normal oper ­ ation, the following deviations will result: fio - /o /=/„ Initial conditions: X^iiO - 0 f > P? = p„ iO

me a M E p => /■ = X*™- x> M E a M E P

X ^„o+ X f.o+ X •/«+ X -/o- X ME a ME P ME a M E P UE P X^+X/, ME a ME P

I APLu ME p => f = fo~ (A4.28) X + X A, ME a ME p

XA^« U E P «g a: Pi — Pi0 + Kri ■ (fio f) — PiQ + Kri ■ (A4.29) X ^r«+ X X« IE a ME p

i€ P: P, = P° + X,- (/-f) = Pi0 + X,.— -APl, (A4.30) IK X *,«+ ME p

The loss of one single load-frequency controller results in deviations in fre­ quency and interchanges that are functions only of the load change in the country where the controller has failed.

199 Appendix 4. Basic theory of load-frequency control

4. Finally, any set of reference values will give an unique solution for frequency and power interchanges.

If one or more of the countries are equipped with hierarchical LFC, the superior controller handles the interchanges on the national level. If one or more of these national controllers should fail, the corresponding regional controllers will “rise” to the national control level. This system then has the following advantages com­ pared to the classical centralized control scheme:

1. If one or more of the national controllers should fail, all system values stay correct, both on the national and the regional level.

2. If one or more of the subordinate regional controllers should fail, the system values on the national level still stay correct, but the generation in the affected regions will be redistributed.

3. If both the national controller and one or more of the regional controllers in the same country should fail, also system values at the national level will be dis­ turbed.

A4.2.4 Insufficient reserves

Even though the total reserves available for LFC in a country are bigger than a given fault, this does not necessarily guarantee that the country is able to replace the missing capacity. A poor co-ordination of limiters, participation factors and reserves in each controlled unit might reduce the available reserves. The reserves of a given area are said to be optimal when all reserves are available for replacing a fault, no matter where this fault might happen within the area [29].

Figure A4.3 shows possible limitations to the available reserves of the central ­ ized LFC of the country i. The maximum available control band of this country is

(A4.31) U = 1

The activated reserve at any time can be written as

R, = APdr I C,„+ % *,» (A4.32) «e a; P,- where a. - set of still controllable units P. - set of units at maximum load

200 A4.2 Frequency and power interchange

Figure A4.3 Available reserves with centralized load-frequency controller [29]

Normally, the limiter is set equal to the possible control band:

n i ±DPmax = ± Riu (A4.33) U = 1

To obtain an optimal reserve provision the participation factors then have to be chosen in proportion to the available reserves:

Rv (A4.34) "i I c,„

If a fault APLk should happen in country k which was bigger than the available reserve Ricmax , the following residual capacity deficit would result:

AP L = &PLk ~ Rkmax (A4.35)

Mathematically, the new stationary situation of the interconnected system would then be given by the equations (A4.28) to (A4.30) as if the residual fault APL had occurred in a country with controller failure:

A/ = /-/(, = — (^PLk Rkmax ) (A4.36)

APr ^ -Afz. = -X, A^- (Af^-^) L Kru + \ ue a (A4.37)

201 Appendix 4. Basic theory of load-frequency control

APGk = APk + APLk = -\'Af+Rkmax, (A4.38)

The country k will thus import the resulting capacity deficit (residual fault minus primary control response) from the other countries in the interconnected system.

In the case of hierarchical LFC a reserve deficit in one region will be compen ­ sated by the other regions within the country, maintaining system frequency and national interchanges at reference values. Only if the fault should exceed the total national reserves would the system frequency and national interchanges be influ ­ enced.

A4.3 Time and energy deviations

Deviations in system frequency and area interchanges will over a time interval x lead to time and energy deviations [29]: % (A4.39)

T Inadvertent interchange: IIt = J (Pt (f) -Pi0)dt (A4.40) o

In an interconnected power system the additional power demand signal distrib ­ uted to the control units in region i can be written as [29]:

T (A4.41) where Ap% ~ additional power demand signal at start of the considered time interval APxdi - additional power demand signal at end of the considered time interval (t = x) G\ - Area Control Error at time t = x Tri - area controller settings (Pi-controller)

Integrating the basic equation (A4.1) yields: A4.3 Time and energy deviations

T T Jg ; (?) dt J(P,(()-P,o)+Xri -1 (/«)-/,„) o o o r/(0 -//v . f/w_/io => Jg,(0* = ]>,•(') -fm) + *„■/*■ J —Ndt + ^ /,AT

=> Jg ,.(0* = Ili + Krt-fx-TD + Kri-T- (fN-fi0) (A4.42) 0

Equation (A4.41) can be written as:

T Jo, «) * = Trt ■ (AP»dl - API) - Tri • P, • Gj 0

Inserted in eq. (A4.42):

Trt- (ApS,-Ap;,) - rri • P, ■ G' = IIj + Krj -fN ■ TD + Krj-x- %,-/;«)

=> IIi + Kri ■ fN ■ TD = r„- (AP»,-AP’,)-^PjCJ + ^t.

In addition, in a closed interconnected power system the inadvertent interchange have the following property [29]:

i"„= ij(p„(t)-p„ 0) dt U = 1 M = 1

= fsp» (') * - riv = -t' IP„0 (A4.44) « » M 1/

Equation (A4.43) for all n interconnected regions can now be written in the well known matrix form:

203 Appendix 4. Basic theory of load-frequency control

TV, (APS, - AP;,) - (fm -/„) 1 0 ... 0 KrifN X Tr2 (AP^ - AP;2) - Tr2P2G’ + Krf. (Z20 -/„) 0 1 Kti/n Ih

0 ... Un Tm (API - API) - + K,„r

(A4.45)

Solving the time deviation TD and the inadvertent interchanges If from eq. (A4.45) yields:

5X- (APS„-AP’„) + n _ w______u ______u u

“ (A4.46)

//, = 7^ ( Af- A^) - r,,p.G^ + -/*) - (A4.47)

It is here worth noting that the time deviation TD and the inadvertent inter ­ changes If are only functions of system variables at the beginning and the end of the considered time interval.

204 Appendix 5

Relation between HVDC gainand thermal spinning reserve

In this appendix the mathematical relation between the gain of the HVDC power- frequency controller and the reduction of thermal spinning reserve is deduced for the stationary situation following a fault, as used in Chapter 3. High voltage DC connection with frequency control . First, an expression for the reduction of sta­ tionary thermal reserves APfh (MW) as function of HVDC frequency controller gain kDC is deduced (eq. A5.14), then the relation between stationary frequency deviation A/ (%) and HVDC frequency controller gain at constant thermal reserve (eq. A5.18). Note that in order to get a clearer picture of the interaction between the HVDC connection and the generating units, all loads are modelled as constant power loads.

As the equations are deduced from the SIMPOW models, other control systems might follow slightly different relations. The structure of the SIMPOW HVDC control system is shown in figure A3.13.

A5.1 Unconstrained operation

A5.1.1 Reduction of thermal spinning reserve

When the HVDC is operating without frequency controller, a fault APy in the thermal system is compensated by utilizing reserve from the thermal units. This causes a redistribution of unit loading which again causes a change in the transfer losses in the system. Defining all variables positive when feeding into the system, the following equation applies for the stationary power balance:

A P“h + A Pf+ AP“oss = 0 (MW) (A5.1) where AP“h - in itial reserve activated from thermal units (MW) APj - system fault (MW)

AP^qss - additional system losses due to activated reserves (MW)

205 Appendix 5. Relation betweenHVDC gain and thermal spinning reserve

When the HVDC frequency controller is activated, the DC connection will sup ­ ply some of the necessary change in the power balance:

AP»+AP£ + AP/+A/>?„, = 0 (MW) (A5.2) where APbth - residual activated thermal reserve when the HVDC con ­ nection supplies some of the reserve (MW) AP^c - AC power fed into the system from the HVDC connec ­ tion (MW) APj - system fault (MW) APbloss - additional system losses due to thermal and HVDC reserves (MW)

Subtracting these two equations, the stationary thermal reserve reduction APth can be found:

(An - APf») -AP* DCc + (AP?„„ - APf„.) = 0 (A5.3)

=> SP,h = APfh - APf, = AP%. - Ai>,„„ (MW) (A5.4)

The stationary AC power Afed into the system from the HVDC connection (from the inverter) can be approximated with the DC power APDC:

- APdc AP (MW), (A5.5) since the converter losses APloss conv are in the order of 0.1-0.5% of HVDC load.

For simplicity, the following notations are now introduced:

- Initial value: - Stationary value: x(r) |( = *°°

As long as the HVDC connection is operating unconstrained without reaching any limitations, equation (A5.5) can be further developed:

(A5.6)

[ ZDC ’ [ UDC ^UDC^ '^DN'^DN ^DC (MW) (A5.7)

206 A5.1 Unconstrained operation

Note that equation (A5.7) is valid for the total 12-pulse converter. Referred to section A3.4.1, IDN = IdN , while UDN = 350 kV, which is the nominal operating voltage of the inverter.

Referring to figures A3.13 and A3.19, the following relations apply to the sta­ tionary DC current and voltage increments in SIMPOW when the HVDC con ­ nection is operating in current control mode [24, 47]:

(pu) (A5.8) DN

Au dc = ~(d r + d x) • AiDC (pu) (A5.9) where kDC - DCR controller gain (kA/pu Hz) IDN - rated DC current (kA) A/ - thermal system frequency deviation (pu) d p d x - resistive and inductive DC voltage drops across con ­ verter (pu)

Equation (A5.9) is strictly applicable only when the AC voltage at the inverter terminal is unchanged and the inverter operates at y . . The equation is however found to be valid when looking at the stationary situation after a disturbance. Similar expressions can also be deduced for unconstrained operation in power control mode, in which case the DCR controller gain kDC must be given in (MW/ PuHz)-

In addition: u°DC = 1.0 pu (A5.10)

(Pu) (A5.ll)

Inserting equations (A5.8) - (A5.ll) in equation (A5.7) yields:

207 Appendix 5. Relation between HVDC gain and thermal spinning reserve

=> Ap oc = -«+

Using the same sign convention as above, the frequency deviation A/ after a fault as function of the size of the fault and the total frequency bias of the system Ktnt (MW/Hz) is:

(pu) (A5.13) where the change in grid losses APbloss (MW) must be decided from simulations or calculations for each case.

The system is adjusted for each simulated case such that Ktot = Kth = const. The expression of the stationary thermal reserve reduction from equation (A5.4) as function of HVDC frequency controller gain kDC is then:

~ &Pd C ^Pio SS

*DC-AP,.„ (MW) (A5.14)

As the 2nd-degree coefficient in equation (A5.14) is in the order of 10~5, the ther ­ mal reserve reduction can also be approximated with a straight line.

A5.1.2 Reduction of stationary frequency deviation

In addition to simulations of thermal reserve reduction as function of HVDC fre­ quency controller gain, also reduction of stationary frequency deviation A/ with constant thermal reserve is simulated. The equation for the stationary frequency deviation A/ as function of kDC can be deduced from the total frequency bias Ktot (MW/Hz) for the thermal system when the size of the fault APy (MW) is known and the change in the grid losses AP\oss (MW) is found from simulations:

208 A5.1 Unconstrained operation

K -K +K - AP>+A (MW/Hz) (A5.15) <" ~ DC » a TTT

The contribution from the HVDC connection is:

K - -APdc (MW/Hz) (A5.16) DC~ AT7,N where

A/ ,_2 DC APDC = ~(d r + d x) ■ kdc U Dn~ (d r+d x) ' Af-kDC (A5.ll) ADN lDN

The resulting thermal frequency bias is supplied by the swing bus:

r _ °N,SW Kth ~ kSW ' ------(MW/Hz) (A5.17) JN where ksw - swing bus speed governor gain SN>sw - swing bus rating (MVA)

Inserted in equation (A5.15):

U d N ' &DC (d r + d x) • A/+ (^r + 4) 7^ ■ ^DC + &SW ' ^N, sw lDN A/ (A5.18)

The equation for the stationary frequency deviation Af as function of HVDC fre­ quency controller gain kDC is then the standard solution of a 2nd degree equation:

- P + J$ 2 - 4 ■ a ■ y Af (&ac) — (PU) (A5.19) 2 • a

Ur where a (kDC) = (d r + d x) ■ ■ k^c (A5.20a) *DN 3o i DC P (^dc ) — u dn ~ (d r + d x) ■ j kdc "I" k$w ' $n, sw (A5.20b) DN Y = -(SPf+APlj (A5.20c)

The use of the positive square root in equation (A5.19) can be explained by the following approach:

209 Appendix 5. Relation between HVDC gain and thermal spinning reserve

kDc —* 0 —> a —> 0 P —> ksw ■ SN> sw Y~ const.

^ lim ^ (A/) -» °° does not correspond to the simulation results, and the positive sign is therefore used. The limit of A/ can be found from equation (A5.18):

(A5.21) where APfoss have to be decided by simulations or calculations. This expression could also have been found by inserting equation (A5.17) in equation (A5.13).

A5.2 Operation at current limit

When the HVDC frequency controller gain kDC is increased, the COR controller eventually reaches current order limit UMAX. The HVDC connection is then unable to substitute more thermal reserves, and the stationary reduction APth becomes constant; no longer a function of kDC.

The continuous overload capacity of HVDC converters are normally 1.2-1.3 times normal rated load current. For the used Skagerak 3 connection the overload capacity is set to 20%: ioc = 1-2 pu (A5.22)

The voltage at current limit operation is still following equation (A5.9):

Au dc ~ (d r + d x) ■ AiDC — (d r + dx ) ■ (ipc idc ) (Pu) (A5.23)

Equation (A5.14) can then be simplified to:

h ~ zdc ' Idn ' U DN' [1 ~ zdc ’ (<4 + d x) 1

+ Udc ‘ (d r + d x) -1 ] • P°DC - APloss (MW) (A5.24) Appendix 6

Hydraulic turbine models

When analyzing the principles of secondary control with simulations over several minutes, the standard SIMPOW linearized turbine model of figure A3.10 have to be replaced with a non-linear model able to handle large variations in turbine out­ put with sufficient accuracy. In the case of long-term dynamic simulations, a rather complex model including traveling wave effects and surge chamber dynamics is recommended [23]. However, the data necessary to implement such models for Norwegian hydro power units are at present not available.

To be able to evaluate how the choice of turbine model might influence the results, several different non-linear turbine models should have been imple ­ mented and tested, but time has not allowed such a comprehensive analysis. In the simulations in chapter 4 is therefore used the 1. order non-linear turbine as decribed in section A6.3.

A6.1 Basic hydrodynamic equations

A6.1.1 Equation of motion

P

Figure A6.1 Wavefront moving upwards in pipeline [65]

Figure A6.1 illustrates a wavefront moving upwards {towards the flow of the fluid) in a pipeline (tunnel, penstock) with velocity a. Newton ’s 2. law applied to the wavefront can be expressed as [65]:

(A6.1)

211 Appendix 6. Hydraulic turbinemodels where p = p gh - hydraulic pressure (N/m2) p - density of fluid (kg/m3) g - acc. of gravity (9.81 m/s2) A - internal pipeline cross section (m2) U - velocity of fluid (m/s) a - wave velocity (m/s) z - static head (m) h - net head (m)

The chain rule yields:

dU(x(t),t ) _dU dx dU _ dt dx dt dt

dU Assuming constant cross section A: => = 0

Inserted in (A6.1): pAAxr-^- = -pgAAi

Setting h + z = H yields the Equation of motion'.

dU dH W - 15F

A6.1.2 Continuity equation

Applying the continuity equation to a section Ax of the pipe line in figure A6.1 yields [65]:

(A6.4) where V - water volume (m3) Q - water flow rate (m3/s)

The chain rule yields: dV{x(t),t) _ dV dx dV _ dV dV dt dx'dt+Tt ~ u te+di

212 A6.2 Travelling wave model

dV Assuming a rigid conduit => ^- = 0

Equation (A6.4) then yields: 92 3^A ~_ di (A6 .6 )

The compressibility of water can be expressed as [65]:

ay = ' a (p+Pfz) (A6.7) where K - bulk modulus of fluid

dQ _ A Ax d O + pgz) Inserted in eq. (A6 .6 ): - —R------s— dU _ 1 d O + pgz) => (A6 .8) dx ~ K' dt

Setting p = p gh and H = h + z yields the Continuity equation, the second basic hydrodynamic equation:

(A6.9)

where a = Pg

The wave velocity is defined as: a = —

A6.2 Travelling wave model

The solution of the basic hydrodynamic equations (A6.3) and (A6.9) results in the well-known hyperbolic travelling wave function of references [17, 23]:

(A6.10)

213 Appendix 6. Hydraulic turbinemodels

Q.N 1 where Z0 - - surge impedance hn Ajag L Te = - wave travel time

For the interested reader, the calculation of equation (A6.10) from eqs. (A6.3) and (A6.9) is shown below.

Linearizing the two functions U(x,t) and H(x,t) yields:

dU dU dH dH At7=

Differensiating eq. (A6.11b) with respect to t and substituting from eq. (A6.3) and (A6.9):

dAH d 2H d 2H 3 2H 3 2H • Ax + ■ At = ■ Ax + — ■ • At (A6.12) 31 3x31 dt 2 3x31 a ^x2

Similarly, differensiating eq. (A6 .Ha) with respect to x yields:

3A U 3 2H . 3 2H a Ax — g ■ At (A6.13) 3x 3x31 3x"

Thus, comparing eq. (A6.12) to (A6.13), the first basic equation is found on line ­ arized form: 3A U dAH ~3x ~a ~3T (A6.14a)

The second equation can be found in the same way:

dAH l 3A U (A6.14b) 3x 8 dr

Introducing the wave velocity a = Jg/a and the flow rate AQ = A • At/, the basic hydrodynamic equations can be written:

dAQ _ gA dAH (A6.15a) dx a 2 31

214 A6.2 Travelling wave model

dAH _ _J_ dAQ (A6.15b) dx gA dt

These equations are most conveniently solved in the s-domain. Using the Laplace transform: dAQ (s) = -Cq [sAH( s) - AH (r= 0 ) ] (A6.16a) dx dAH(s) = ~Ch[sAQ(s) -A<2(f=0+)] (A6.16b) where CQ ~ ^ andC n ~ JA

Assuming an initial steady state situation, AH (f=0+) = AQ (z=0+) =0

=> = -sCq AH (s) (A6.17a) d* dAH(s) -fa — = ~sChAQ (s) (A6.17b)

Differentiating eq. (A6.17a) once more with respect to x yields:

- -ce^> = s2Ca CHAQ(s) (A6.18)

This is a 2nd order differential equation for AQ (s) with characteristic equation r2- s2CqCh = 0. The solution has the following form:

sJCq Chx AQ (s) = CA ■ H +CB-e s^J CQ0 CHX = CA ■ ea + CB ■ e a (A6.19)

Differentiating eq. (A6.19) and substituting (A6.17a) yields:

CA £* C» —* AH(s) =----- 4=e° + —^=e a (A6.20) Ajag Ajag

Solving these two equations with respect to the integration constants yields:

CA = \e“XAQ {s) -^le~~aX AH(s) (A6.21a)

215 Appendix 6. Hydraulic turbine models

i ~x ^4 /oCj? Cg = If" AG (^) + f" A^(f) (A6.21b)

At each end of the pipe line (tunnel/penstock) with length L the following values are applicable: xj = 0

x2 = L

In addition, at the beginning of the pipe line (at the reservoir): AH1 (s) = 0

Solving eq. (A6.21a)-(A6.21b) at the beginning of the pipe line then yields:

Q = Q, = ^AGi(a) (A6.22)

Inserting these constants in equations (A6.19)-(A6.20), the functions can be cal­ culated at the end of the pipe line (x2 = L):

L -s a AQi (s) (A6.23a)

AH2 (f) = - AGi (f) (A6.23b)

Introducing the wave travel time, Te = L/a, and the surge impedance Zc = 1/(A Jag) the transfer function between flow and head at the end of the pipe line (at the turbine) can be found as:

AH2(s) e'T--e-T- = ~Zr -ZctmhsTe (A6.24) AQ2 (s) \eT‘ + e~,T‘

Or using pu values:

Ah2 (s) -Z0tanh5re (A6.25) Aq2 (s)

, _ O n 1 where 0 H n Ajag

216 A6.3 Non-linear turbinemodel with inelastic water column

Unfortunately, time did not allow implementation and testing of eq. (A6.25) in SEMPOW. Instead, a simpler non-linear model is chosen for the long-term simu­ lations in Chapter 4.

A6.3 Non-linear turbine model with inelastic water column

By neglecting the elasticity of the water column, a in equation (A6.9) is zero. Setting dH AH _ H0-He (A6.26) dx Ax L and introducing the turbine flow rate Q = U ■ A (m3/s), equation (A6.3) becomes: dQ He-HL) (A6.27) dt - %(*o where the friction losses are included as a 2nd order function of flow rate:

HL=fpQ2 (m) (A6.28) and where L - length of penstock (m) H0 - static turbine head (m) He - effective turbine head (m) fp - friction coefficient

In addition, the model uses the two basic turbine equations [17, 23]:

Turbine flow rate: Q = KQY ■ (m3/s) (A6.29)

Turbine power: P = Kp He- Q (MW) (A6.30) where Y - gate opening Kq, KP - constants

In pu values, using rated flow QN and rated head HN as base values:

dq _ AgH N 5S-0 (h0 ~he- hL) (A6.31) dt LQn 2w

(A6.32)

217 Appendix 6. Hydraulic turbinemodels

<1 = y- JK (A6.33)

p = qhe (A6.34)

. _ where is the water starting time (s) at rated load *

The model includes two types of turbine losses [23]: First, the no-load losses due to the fact that the turbine flow has to reach a certain level qNL before it can pro ­ duce any mechanical power, as illustrated in fig. A6.2. Second, the turbine self­ regulating effect due to speed deviations (friction, impact loss and centrifugal force), which is assumed to be proportional to gate opening. The turbine mechan ­ ical power can then be expressed as:

Pm = P ~Pnl~Pd = (9-<1ni) ■ he — D ■ y • Ato (A6.35) where qNL = At-y* NL-Jh~0

For more detailed studies of single specific power plant also the turbine effi­ ciency should be included. This can be done by multiplying equation (A6.34) with a function r\ = r\(q,he) (A6.36) where the function r\{q,he) can have a chosen complexity as suited to the cur­ rent analytical needs, ranging from a simple 2nd order function rj (q) to more advanced 3-dimentional polynomial approximations [66 ]. However, as the simu­ lations of Chapter 4 uses aggregated single bus area approximations, including an efficiency function in each aggregated turbine would be inappropriate.

The mechanical torque of the turbine can be found as:

tm=^-Pm (A6.37)

Finally, the gate opening - which is the connection between the governor and the turbine - have to be scaled. This is due to the fact that the real turbine opening y* as given from the governor has a movement of 1.0 pu from closed to fully open, while the ideal turbine opening y as used in equation (A6.33) assumes that the change from no load to full load is equal to 1.0 pu. This scaling is done by multi­ plying the real turbine opening with the factor At as illustrated in figure A6.2.

218 A6.3 Non-linear turbine model with inelastic water column

y = Ary*, At = ------j- (A6.38) ypL y nl

Turbine gate opening y y = At y*

Full load

No load No-load losses

NL 1 Governor gate opening y' Figure A6.2 Scaling of gate opening [17]

The complete non-linear model transfered to the s-plane is given by equations (A6.39) to (A6.43) and is shown in figure A6.3.

y = At-y* (A6.39) *«= <-p2 (A6.40)

hL=fp ■ (A6.41)

Pm = (9- <1nl) K-D y- Aco (A6.42)

9 (A6.43) = -?f-W-K-SJ w hi)

Figure A6.3 Non-linear turbine with inelastic water column [17, 23]

219 Appendix 6. Hydraulic turbine models

A6.4 Further model improvements

Attempts have been made to improve the 1. order model of figure A6.3 by including a surge tank and two basic water conduit equations. However, the implemented SIMPOW model proved to be unstable unless the turbine governor gain was set very low, and the model was discarded after some attempts of stabi ­ lizing. In any case, the model structure as given in reference [23] is included here for the benefit of further examinations.

A6.4.1 Model with surge tank and inelastic water column

Improving the model of figure A6.3 by including a surge tank introduces an addi­ tional equation on the form of eq. (A6.43), as the elasticity of the water is still neglected. According to the physical sturcture as shown in figure A6.4, the model can be described by equations (A6.44) to (A6.53). The complete block diagram is shown in figure A6.5.

Surge chamber

Figure A6.4 Structure of hydro power plant with surge chamber * II (A6.44) *.= 2 (A6.45) ''fcH Jr II

” (A6.46)

^L2 ~ fp2 '

9, = *2 - (A6.48)

hp = hs-fps-(ls-\(ls\ (A6.49)

220 A6.4 Further model improvements

Pm= (q- Qni) he-DyA(Q (A6.50)

q2 = (1.0 ~h - hL2) (A6.52) SI W2

hs = ~ qs (A6.53)

Tunnel dynamics

STW2

Penstock dynamics

STW1

Figure A6.5 Non-linear model with inelastic water column including surge tank [23] Appendix 6. Hydraulic turbine models

222