2 Hvdc Transmission

Modeling and investigation of the NorNed HVDC link with RTDS

MASTER OF SCIENCE THESIS

Electrical Power Systems

DELFT UNIVERSITY OF TECHNOLOGY FACULTY OF ELECTRICAL ENGINEERING, MATHEMATICS AND COMPUTER SCIENCE

Vikaash Sookha # 1530291 Delft, M ay 2011

Modeling and investigation of the NorNed HVDC link with RTDS

MASTER OF SCIENCE THESIS

Electrical Power Systems

DELFT UNIVERSITY OF TECHNOLOGY FACULTY OF ELECTRICAL ENGINEERING, MATHEMATICS AND COMPUTER SCIENCE

Vikaash Sookha # 1530291 Delft, M ay 2011

Thesis committee:

Prof. Ir. L. van der Sluis Delft University of Technology, Thesis supervisor Dr. Ir. M. Popov Delft University of Technology, Daily supervisor Ir. E. Wierenga TenneT TSO B.V., Daily supervisor Dr. Ir. D. Djairam Delft University of Technology

Preface

As part of completing the Master of Electrical Power Engineering track at the Delft University of Technology, the student must show his capacities and abilities gained during the period in classrooms with the final objective: the thesis. The period spent on the thesis is not only a period where the student spends time in gaining and applying knowledge, but it is a period where personal development also is gained. I have done my thesis at TenneT TSO in Arnhem, The Netherlands, at the department of Transport & Infra in close collaboration with the department of Electrical Power Systems (“Netmodellering”) of the TU Delft where the RTDS is installed. I did the project at TenneT with much pleasure and I have tried my best to get good results. Being in a professional environment, getting along with everyday activities in a company was very educative for me. Being in such a professional company I learned a lot and I wanted to be of some value for the company too by means of this thesis project. The work carried out here is more than one persons effort, therefore I wish to express my sincere gratitude to the ones who contributed to this task. I thank Dr. Ir. Marjan Popov for bringing me in contact with TenneT and his supervision during the period of the thesis. From TenneT I thank Ir. Frank Koers and Ir. Ernst Wierenga for giving me the opportunity to be at TenneT. I thank Ir. Ernst Wierenga for his support and experienced way of supervision and advising at points where I ran out of ideas and of course his professional guide concerning the technical part. From the department Asset Management I thank Ir. Kees Koreman for the very experienced and skillful guidance in the field of HVDC. I thank TenneT as a whole. I also thank TU Delft as a whole. This project would have been a lot more difficult without the fast and professional responses and explanation about RSCAD of Onyinyechi Nzimako from RTDS, Canada. Thank you Onyi.

Finally, I thank my entire family for their enduring support and love. I thank all my friends for their support and great moments during my study period. I thank my father Ivan and mother Sabitrie, sisters and brother for always being there for me. Thanks to my uncle Rabin and special thanks to my aunt Lalita who still encourages me. Last but not least I thank my girlfriend Shariska for her constant support and love and believing in me.

Vikaash Sookha

Delft, Netherlands May 2011

Summary

To be successful in operating and maintaining most challenges in electric power system, understanding is important of the grid. Present-day the application of HVDC technology is growing, because it proves to be beneficial for long distance and bulk transmission. This is also the case in The Netherlands. Investigation of networks can be done with the aid of simulations. The RTDS is a powerful tool to perform Electro Magnetic Transient simulations, the RTDS has the strong property to carry out real-time simulations. For TenneT having a model which can be used for investigation is beneficial. This report is the result of a thesis of which title is formulated as: Modeling and investigation of the NorNed HVDC link with RTDS After the short introduction, the fundamentals of HVDC technology is explored. Here the important advantages of DC over AC are given, which include lower transmission losses but higher substation costs which results from expensive filters and reactive power compensation equipment. The operating principles of classic HVDC from a technical point of view are analyzed. Further the developments of HVDC from Netherlands point of view is given. Currently there are two HVDC connection in the Netherlands. One HVDC link between Netherlands and Norway is operational: The NorNed, this is a 580 kilometers submarine cable operating at +450kV/-450kV with a rated transport capacity of 600 Megawatts and the other is the BritNed between Netherlands and the UK. This HVDC connection is implemented in the RTDS. The steps needed to simulate a HVDC connection are described in some detail to understand the operation and for future examination. The implementation process begins with providing a description of the complete model. The primary circuit is described, some detail is given on the controls as this is a key feature of fast regulation for HVDC and finally the disturbances controls is explained. Because of some shortcoming in the represented models in the RSCAD library, not all the actual equipments are exactly modeled as installed. Some modifications are made. Once the model has been created, simulations can be started. A number of simulations are carried out showing the steady state performance of the HVDC model. With this model now other cases can be studied to understand specific situations at points in the grid. Such an case involved a single phase fault in April 2009 which resulted in the NorNed being offline for a month. Some oscillogram recordings were made at the fault location. These are used to replicate the fault in the RTDS with the model. The task of replicating the responses of the actual recordings proved to be a difficult task. The results in the simulations show differences. The effect however, of the events in the network is clear. A possible solution to prevent the unwished phenomena after fault occurrence is to disconnect the capacitor banks present in the filter building where the fault occurred. With this action the magnitude of the voltage swings decrease. The exact responses compared to the recording were not found during simulations. This is the result of the model being modified because of the limitations of RSCAD. Nevertheless, an important step was set for the investigation of HVDC links. This should be set forward in better understanding and prevent interruptions. But with updated and enhanced models, and more because of the strong feature of RTDS to perform real-time simulation which TenneT in cooperation with the TU Delft can use in the future. In order to verify the models and the case studied here, another simulation tool can also be used. This can be done with DIgSILENT PowerFactory which is used at TenneT.

Contents

PREFACE ...... 4

SUMMARY ...... 5

1 INTRODUCTION ...... 10 1.1 Background of the work ...... 10 1.2 Definition and scope ...... 11 1.3 Approach ...... 11

2 HVDC TRANSMISSION ...... 12 2.1 Transmission by DC instead of AC ...... 12 2.1.1 Justification ...... 12 2.1.2 Converter types ...... 15 2.2 Converter theory fundamentals ...... 18 2.3 Reactive power and harmonics ...... 25

3. HVDC DEVELOPMENTS ...... 30 3.1 Practical HVDC connections ...... 30 3.2 Trends in HVDC technology ...... 32 3.3 HVDC from TenneT point of view ...... 34 3.4 NorNed at Eemshaven ...... 36

4. NETWORK MODELING ...... 43 4.1 The simulator ...... 44 4.2 Modeling the primary circuit ...... 48 4.2.1 The components ...... 48 4.2.2 Transmission...... 53

5 MODELING THE CONTROLS ...... 55 5.1 Control properties of model ...... 55 5.1.1 Master control ...... 56 5.1.2 Rectifier ...... 57 5.1.3 Inverter ...... 61 5.2 Full control properties ...... 64 5.3 Disturbances controls ...... 68

6 SIMULATION ...... 73 6.1 Part I ...... 74 6.1.1 Faults types ...... 74 6.1.2 Steady state ...... 74 6.1.3 Faults ...... 79 6.2 Part II ...... 80 6.2.1 Case AM...... 80 6.2.2 Results studied case ...... 83

7. CONCLUSIONS & RECOMMENDATIONS ...... 87 7.1 Conclusions ...... 87 7.2 Recommendations ...... 89

REFERENCES ...... 90

APPENDICES ...... 92 Appendix A. Comparison example AC and DC cable transmission ...... 92 Appendix B. Rectifier and Inverter operation signals ...... 93 Appendix C. HVDC projects ...... 95 Appendix D. Data for network model in chapter 4 ...... 100 Appendix E. Network in RTDS ( RSCAD ) ...... 104 Appendix F. Full HVDC rectifier and inverter controls ...... 106 Appendix G. Steady state properties NorNed ...... 109 Appendix H. Oscillogram recordings of Case ...... 110 Appendix I. Case simulated in RTDS ...... 113

Terminology

ABB The ABB group- Automation and Power Technologies AOR1 Alpha Order Rectifier- pole 1 CB Circuit Breaker CINV2 Current Inverter- pole 2 Csn: Snubber Capacitance DGE Delta Gamma Error DIO Digital Input/Output card DITS DIgital Time Stamp card DSP Digital Signal Processor EDC: DC Substation Eemshaven EEMS substation Eemshaven (AC) EMT Electro Magnetic Transient FPG Firing Pulse Generator GIS Gas Insulated Switchgear GPC Giga Processor Card GUI Graphical User Interface HVAC High Voltage AC HVDC High Voltage DC Hz Hertz IGBTs Insulated-Gate Bipolar Transistor Iord I order IRC Inter-Rack Communications Card LCC Line Commutated Converters PID Proportional Integral Derivative controller PLL Phase Locked Loop POW Point On Wave PWM Pulse Width Modulation RISC Reduced Instruction Set Computer RMS Root Mean Square RPC Risc Processor Cards Rsn Snubber Resistance RSCAD GUI through which the user is able to construct, run and analyze simulation cases RTDS Real Time Digital Simulator SCC Short Circuit Capacity TSO Transmission System Operator UCTE Union for the Coordination of Production and Transmission of Electricity VDCOL Voltage Dependant Current Order Limiter VGB Valve Group Block VSC Voltage Source Converters WIF Workstation Interface Card XLPE Cross Linked Poly Ethylene

1 Introduction

1.1 Background of the work

Present-day the HVDC technology is applied and still developing because it proves to be beneficial for long distance and bulk transmission. This is also the case in The Netherlands. Examples are the already existing and operational HVDC link NorNed, connecting Norway and Netherlands, BritNed between England and Netherlands, almost operational and more HVDC connections planned to be built. Once a connection is made and implemented in the grid, it can have failures, which in many cases need to be investigated and possibly mutated to prevent this occurrence. Investigation of networks can be done with the aid of simulations. But first the network needs to be implemented in a proper simulation tool. There are several types of simulation tools to carry out specific types of investigations, such as Electro Magnetic Transient, Power System Dynamic and load flow studies. The RTDS is such a simulator which is capable to perform dynamic simulations, the advantage of RTDS being to do real-time simulations. To implement a real network into a model knowledge is needed how the network is built and operated in practice, so theoretical background is essential. Especially for HVDC, where the controls are an important tool for regulation. Once the network is set up, simulations can be carried out and situation & cases where interest is can be studied. The NorNed is a 580 kilometers submarine cable operating at +450kV/-450kV with a rated transport capacity of 600 Megawatts. The converter station is situated in Eemshaven. In 2009 NorNed went offline for a month as a result of a fault, this needed closer examination to understand and possibly prevent such events.

1.2 Definition and scope

With the focus on the HVDC transmission the goal is to investigate what the effects of several faults is at certain points in the network. These faults include: AC line-to-line/line-to-ground faults at both ends of the DC cable connection, Converter faults and DC faults. The subject is formulated as:

Modeling and investigation of the NorNed HVDC link with the RTDS

The report produced here describes the essential theoretical background of HVDC technology with the developments from TenneT`s point of view. The modeling will be described in some detail to understand the HVDC operation and for future examination. The HVDC controls also have special attention which can be used to develop a model in other simulation tools.

Once the tool ready, investigations can be done at certain points in the network. TenneT will have more insight in the network in relation to HVDC in the Eemshaven area.

1.3 Approach

The thesis work as discussed is divided in several parts which follow the sequence of:

• Theoretical background HVDC and developments • Network and control modeling, followed by • Some basic simulations showing the model functioning, and • Investigation of an earlier occurred fault • Finally the conclusions and some recommendations are given

2 HVDC transmission

“Why use direct current transmission?” This is a question often asked and often the response is that losses are lower. But this is not correct. The level of losses is designed into a transmission system and is regulated by the size of the conductor selected. DC and AC conductors, either as overhead transmission lines or submarine cables can have lower losses but at higher expenses since the larger cross-sectional area will generally result in lower losses but cost more . This chapter deals with the fundamental aspects of HVDC transmission. The reasons behind HVDC technology is briefly mentioned, followed by the operation of the converter and an overview is given to the future of this technology further on.

2.1 Transmission by DC instead of AC

2.1.1 Justification Since the first commercial HVDC link went in operation in 1954 connecting the island of Gotland and the Swedish mainland with a 96 km long 100 kV submarine cable with a capacity of 20MW, it is fair to say that at present HVDC technology is booming worldwide with an installed capacity of over 80 GW. This is 1.8 % of the worldwide installed generation capacity. This can be explained by looking at two major trends in the development of power systems[1][2]. 1. Transition of the traditional power systems, where generation is done by a small number of large units to a new situation where a large amount of small(er) units are responsible for generation of the power. 2. Increasing distance between sites where large scale generation is taking place and the load centers where vast amounts of electrical energy is consumed.

Most striking is perhaps the difference between these two trends. The first requires a system that is flexible in terms of control of both active and reactive power. Whereas for the second, the ability of handling the high voltages and currents typically associated with large amounts of power is much more of an issue. Thanks to advances in power electronic technology, HVDC can provide solutions in both areas.

The main advantages generally claimed in favour of the DC alternative are: • Economic considerations; DC transmission results in lower losses and costs than equivalent AC lines, but the costs and losses at the DC terminal can be higher An overhead dc transmission line with its towers can be designed to be less costly per unit of length than an equivalent ac line designed to transmit the same level of electric power. However the dc converter stations at each end are more costly than the terminating stations of an AC line and so there is a breakeven distance above which the total cost of dc transmission is less than its ac transmission alternative. For ac infrastructure it can be argued that the costs are mainly determined by the lines and to a much less extent by the substations. AC lines usually consist of at least two, three-phase circuits where often one phase if formed by a bundle of multiple conductors. In all, many conductors are required to construct an AC connection. DC connections on the other hand, usually consist of only two poles each of which is carried out as a bundle of multiple conductors. Still, a DC connection requires much less conductors when compared to its AC counterpart. Furthermore, due to the impedance of AC overhead lines the loadability of the

12 line decreases as the transmission distance increases. To avoid the loadability becoming small for long(er) lines, expensive series- and shunt compensation have to be installed along the line. Since for DC the impedance of the line equals the resistance, no such compensation is required. However, the converter stations needed in the latter case for the conversion of AC into DC vice versa, are due to their complexity very expensive. Substations found in AC networks on the other hand, are less complex and as such, cheaper to built. The graph below gives an indication of the economical benefits from a certain transmission distance.

Figure 2.1.1 AC-DC cost comparison [3]

The break-even distance is in the range of 500 – 800 km depending on a number of other factors, like country-specific cost elements, rates for project financing, loss evaluation, cost of right way etc. [3][4].

• Technical merits; AC transmission via cable is impractical over long distances, such a restriction does not exist with DC, at DC the conductor cross section is fully utilized, because there is no skin effect If transmission is by submarine or underground cable, the breakeven distance is much less than overhead transmission. The capacitance of an AC high-voltage cable gives rise to a charging current. This charging current is effectively reducing the amount of power that the cable is able to transfer. The capacitance of the cable, and thus its charging current is proportional to the length of the cable. From this it follows that the longer the cable is, the more its ability to transfer power is compromised. For a certain length the charging current equals the rated current and the cable is no longer capable of transferring power. In practice this situation arises for cable lengths of approximately 60 to 100 kilometers depending on the type of cable. Since for DC the

13 capacitive reactance of the cable is infinite, no charging currents exists. This makes the transmission distance virtually unlimited[5]. See Appendix A for comparison [6]. Power transmitted over an AC line given by the power-angle equation: V V P = S R sin Θ X SR SR (2.1) P - Transmitted power

VS - Voltage sending end, with cos φ 1

VR - Voltage receiving end, with cos φ 2 X - Series resistance

Θ - Voltage phase shift(or load angle), Θ = φ 1 - φ 2

Figure 2.1.2 AC power transmission

• Interconnection; DC stations with or without transmission distance, can be justified for the interconnection of AC systems of different frequencies or different control philosophies. Some ac electric power systems are not synchronized to neighboring networks even though their physical distances between them is quite small. This occurs for example in Japan where half the country is a 60 hz network and the other is a 50 hz system. It is physically impossible to connect the two together by direct ac methods in order to exchange electric power between them. However, if a dc converter station is located in each system with an interconnecting dc link between them, it is possible to transfer the required power flow even though the ac systems so connected remain asynchronous. This is used at several locations present day[7].

• Environmental aspects; The dc transmission line can have a lower visual profile than an equivalent ac line and so contributes to a lower environmental impact. Its improved energy transmission possibility contributes to a more efficient utilization of land coverage for transmission towers. See figure 2.1.3 for a comparison There are also advantages to a dc transmission line through the electric and magnetic fields being dc instead of ac.

Figure 2.1.3 Typical line structures for approximately 1000MW

Furthermore, • DC constitutes an asynchronous interconnection and does not raise the fault level appreciably

• The power flow in a DC scheme can easily be controlled at high speed, and thus with appropriate controls a dc link can be used to improve AC-system stability

2.1.2 Converter types Before moving forward, it is important to know what types of AC-DC conversion methods are used today. Basically two methods are developed & used intensively, these are line commutated converters and voltage source converters[8]. Line commutated converters (LCC) are based on current source conversion with naturally commutated thyristors, so called Classical HVDC transmission systems. The name LCC originates from the fact that the applied thyristors need an AC voltage source in order to commutate. Figure 2.1.4 [9] shows the schematic of an LCC based HVDC transmission system. Because classical HVDC transmission is a well established technology, it offers high reliability and requires little maintenance. Compared to its counterpart, LCC based HVDC transmission has much lower power losses (i.e. only 2-3% converter losses) and for high ratings it has comparably low capital costs. However, based on the overall system economics, LCC based HVDC transmission becomes only interesting for transmission capacities above the break-even distance as shown earlier in figure 2.1.5. Since the first commercial LCC based HVDC link was installed it has been installed frequently, primarily for bulk power transmission over long geographical distances and for interconnecting non-synchronized or isolated power systems. Major disadvantage of LCC based HVDC transmission system is that it cannot provide independent control of the active and reactive powers. Instead, the LCC scheme consumes a certain amount of reactive power. This is further explained in the next paragraph. Because of this drawback, capacitor banks are needed for compensation when transporting energy. Also large amounts of harmonics are produced which makes the use of large filters inevitable.

Figure 2.1.4 Line commutated converters and voltage source converters

Voltage source converters (VSC) based HVDC transmission is comparatively a new technology (first commercial installation in 1999) and has only become possible by the development of the IGBTs, which can switch off currents. This means that there is no need for an active commutation voltage. Therefore, VSC based HVDC transmission does not require a strong AC network and can even start up against a dead network (black-start capability). VSC based HVDC transmission systems are gaining more and more attention. Today, VSC based solutions are marketed by ABB under the name “HVDC Light” and by Siemens under the name “HVDC Plus”. Figure 2.1.4 shows the schematic of a VSC based HVDC transmission system. The active and reactive power can be controlled independently, which may reduce the need for reactive power compensation and can contribute to stabilize the AC network at their connection points. In addition, the IGBT semiconductors allow for much higher switching frequencies which reduces the harmonic content of VSC based systems. Therefore, the filter requirements on the AC side are considerably reduced compared to conventional HVDC converters. However, the high- frequency PWM switching results in comparatively high converter losses. The total efficiency of the two converter stations of a VSC based HVDC transmission system is therefore less than that of an LCC based system(99.3% efficiency per terminal for LCC HVDC versus 98.2% efficiency per terminal for VSC terminal[18]). Furthermore, the cost of VSC based systems is still high due to the more advanced semiconductor valves required. In order to handle the high voltage, multiple IGBTs have to be connected in series, which makes the valves expensive. Looking at the overall system economics, VSC based HVDC transmission systems are most competitive at transmission distances over 100 km or power levels of between approximately 200 and 900MW, as depicted in figure 2.1.5 below, which shows a comparison of different transmission technologies. However, the application of VSC based systems may already be advantageous for shorter transmission distances depending on the specific project conditions. A list of HVDC projects in the course of time is included in Appendix C. In this study the VSC configuration will not be investigated, therefore only the LCC converter operation is discussed[8].

Figure 2.1.5 Power transmission capacity with different technologies

2.2 Converter theory fundamentals

This section outlines the most important theoretical background of thyristor based, or classic HVDC converters. It contains however by no means a full and in-depth description of such converters; for this, the reader is referred to other literature on this topic. Figure 2.2.1 shows an impression of the conversion procedure from ac to dc at rectifier, visa versa at inverter. At first glimpse it seems a lot, but starting with the thyristor the entire process will be considered.

SIX -PULSE BRIDGE TRANSFORMER

REACTOR

THYRISTOR

Figure 2.2.1 Conversion procedure from ac to dc at rectifier, visa versa at inverter

The thyristor valve is the most important building block for LCC. Thyristor valves operate as switches which turn on and conduct current when fired on receiving a gate pulse and are forward biased. A thyristor valve will conduct current in one direction and once it conducts, will only turn off when it is reverse biased and the current falls to zero. This process is known as line commutation. An important (unwanted) property of the thyristor valve is that once its conducting current falls to zero when it is reverse biased and the gate pulse is removed too rapid, an increase in the magnitude of the forward biased voltage will cause the thyristor to inadvertently turn on and conduct. The design of the thyristor valve and converter bridge must ensure such a condition is avoided for useful inverter operation. This event called commutation failure is considered later. The six-pulse converter bridge of figure 2.2.1 as the basic converter unit of HVDC transmission is used equally well for rectification where electric power flows from the ac side to the dc side and inversion where the power flow is from the dc side to the ac side. As figure 2.2.2 shows, two valves are connected to each phase terminal, one with anode connected to it(shown on the upper side of the bridge) and the other with the cathode connected to it(shown on the lower side of the bridge). The need for two valves conducting in series is not a 18 drawback in high-voltage applications, because of the need for many series- connected units to withstand voltage levels used.

Figure 2.2.2 Operation six-pulse bridge

To understand the operation of a three-phase bridge rectifier let us consider the idealized case of a converter bridge(i.e. source impedance is zero). Under these condition, the transfer of current(commutation) between valves on the same side of bridge takes place instaneously. The switching sequence and the rectified voltage waveform illustrated in figure x for the case of an uncontrolled bridge rectifier(i.e. diode operation); valves1, 3, 5 at the top, and 4, 6, 2 at the bottom are connected to phases R, Y and B(red, yellow & blue) respectively. With reference to figure 2.2.2 a to g, and starting at instant A, phases R and Y are involved through conducting valves 1 and 6. This operating state continues up to point B, after which valve 2 becomes forward biased, since its anode, directly connected to that of valve 6 , is positive with respect to its cathode(connected to phase B); therefore at point B the current commutates naturally from valve 6 to valve 2 seen in figure 2.2.2b. A similar argument applies at point C, with reference to valves 1 and 3 on the upper half of the bridge. The anode of valve 3(connected to phase Y) begins to be positive with respect to its

19 cathode(connected to phase R through conducting valve 1) and a commutation takes places from valve 1 to valve 3,figure 2.2.2c). This is followed from valve 2 to valve 4 at point D, valve 3 to valve 5 at point E, valve 4 to valve 6 at point F, and valve 5 to valve 1 at point G. This completes the switching cycle sequence, and the sequence is repeated. The output waveform in figure 2.2.2g shows the voltage variation of the positive(common cathode) and the negative (common anode) poles with respect to the transformer neutral. Figure 2.2.2h shows the output voltage, i.e. the voltage of the positive pole with respect to the negative pole. It is seen that the output voltage has a ripple, or harmonic frequency, of six times the main frequency. Each valve carries the full value of the direct current for one third of the cycle, and there are always two valves conducting in series.

Gate control Before explaining the effect of varying the firing angle, it is important to know what the following angles mean: • Firing delay angle α; is the interval between the moment the commutation voltage becomes positive and the actual firing(R) • Overlap angle µ; is the interval between the firing of the incoming valve and the cessation of the current in the outgoing valve(R) • Advance angle β; is the interval between the firing of the incoming valve and the moment the commutation voltage is going negative(I) • Extinction angle γ is the interval between cessation of the current in the outgoing valve and the moment the commutation voltage is going negative(I). Visualizing these angles can be done by figure 2.2.3.

Rectifier Inverter

Figure 2.2.3 Gate control angles

By delaying the firing instants of the valves with respect to the voltage crossings, the commencement of the natural commutations described above can be delayed by a definite time interval and the effect of this action on the direct-voltage waveforms is illustrated in figure 2.2.4a and b. It is noticeable that the voltage area, and therefore the mean direct voltage, is reduced in proportion to the magnitude of the delay. The voltage waveforms for a delay of 90º illustrated in figure 2.2.4 shows equal positive and negative voltage regions, the mean direct voltage is

20 therefore zero with a delay of 90º. Beyond 90º the mean voltage is negative and bridge operation can only be maintained in the presence of a DC voltage supply. This indicates the power being supplied to the ac system, i.e. the converter is inverting. Figures 2.2.4 also illustrates the full inversion at a delay angle of 180º.

Figure 2.2.4 Effect of delay angle α on the voltage

In the presence of a large smoothing reactor on the DC side, the voltage waveform of figure 2.2.4 will produce a constant direct current, the level of which depends on the mean voltages at both ends of the link and the link resistance. For the idealized commutation the valve current will be a rectangular pulse lasting 120º, its relative position with reference to the corresponding voltage waveform being determined by the firing delay α. From figure 2.2.4 the equation for the average DC voltage can be derived as follows.

π π 1 6 6 Vd = ⋅[{ ∫ 2 ⋅Vac⋅ cos(ωt) ⋅ d(ωt)}−{ ∫ 2 ⋅Vac⋅sin(ωt) ⋅ d(ωt)}] → π 3 π π − − 6 6 (2.2) 3 2 Vd = ⋅Vac ⋅ cosα = .1 35⋅Vac ⋅ cosα →Vdo ⋅ cosα [26] (2.3) π With Vd = DC output voltage Vac = AC r.m.s. line-to-line voltage ω = angular frequency (2πf)

3 2 Vdo=ideal no-load direct voltage(with α=0) Vd = ⋅Vac π (2.4) α = firing delay Note the direct voltage being positive for 0º < α < 90º and negative for 90º < α < 180º.

Moving on to the practical commutation process, the zero-impedance supply required to produce the voltage and current waveforms described, does not exist. Even if the AC system impedance were negligible, there is considerable transformer leakage reactance between the converter and the AC system. In theory, the converter transformer is not essential to the process of static power conversion. However, there are practical reasons for using converter transformers, like the possibility of phase shifting multiple bridges and the availability of on-load tap changing, which will become apparent when discussing harmonics and reactive-power compensation later on. The main effect of the AC system reactance is the reduction of rate of change of current, or in other words, to lengthen the commutation time. During the commutation, the magnetic energy stored in the reactance of the previously-conducting phase has to be transferred to the reactance of the incoming phase.

To understand the entire conversion, let us first consider the commutation process between valves 1 and 3 of the converter bridge, connected to a system with a source voltage v c, a commutation reactance per phase Xc(and negligible source resistance). With reference to figure 3.2.5a, commutation from valve 1 to valve 3 can start(by the firing of 3) any time after the upper voltage crossing between v CR and v CY (and must be completed before the lower crossing of these two voltages. Since v CY > v CR , a commutating current i c(=i c3 ) builds up at the expense of i 1 so that all times i 1+i 3=I d. The instaneous expression for the commutating current is: Vac ic = [cosα − cos(ωt)] 2Xc (2.5) The average direct current I dR at ωt = α + µ yields Vac Id R = [cosα − cos(α + µ)] 2Xc (2.6)

Figure 2.2.5 Commutation proces with series reactance X per phase

Typical voltage and current waveforms of an entire six-pulse bridge operating as a rectifier with the commutation effect included are shown in figure 2.2.6, where P indicates a firing instant(P 1 is the firing instant of valve 1), S indicates the end of a commutation(at S 5 valve 5 stops conducting) and C is the crossing(C 1 indicates the positive crossing between phases B and R). Figure 2.2.6a illustrates the positive(determined by the conduction of valves 1, 3 & 5) and the negative (determined by the conduction of valves 2, 4 & 6) potentials with respect to the transformer neutral. Figure 2.2.6b shows the direct voltage output waveform. The potential across valve 1 depends on the conducting valves, is also shown in 2.2.6b. Figures c and d illustrate the individual valve currents at the cathode(1, 3 & 5) and anode(2, 4 & 6), respectively. From figure 2.2.6 the derived average output voltage or the mean direct voltage is: 1 Vd = Vdo[cosα + cos(α + µ)] (2.7) R 2 Where V d0 is maximum average dc voltage(at no load without firing delay) 3 2 For three-phase bridge configuration Vdo = ( )Vac (2.8) π and V ac is the line to line r.m.s. commutating voltage referred to the secondary or the valve side of the converter transformer. The value of the commutation angle is normally not available and a more useful expression for the DC voltage, as a function of the DC current, can be derived from (2.7) and (2.8), resulting in 3Xc Vd = Vdo cosα − Id (2.9) R π Where the last part of (2.9) compared to (2.3) represents the reduction due to commutation reactance Xc.

Figure 2.2.6 Typical six-pulse rectifier operation signals a. Positive and negative voltyages with respect to transformer nuetral b. direct bridge voltage V d and voltage across valve 1 c, d. Valve currents i 1 to i 6

The inverter operation signals are given in Appendix B. For inverter operation the expression for the direct voltage Vd and currents Id in terms of β and γ are: 1 Vd = Vdo[cos β + cosγ ] (2.10) I 2 Vac Id I = [cosγ − cos β ] 2Xc (2.11)

2.3 Reactive power and harmonics

Owing to the firing delay and commutation angles, the converter current in each phase always lags its voltage, see figure 2.3.1. The rectifier therefore absorbs lagging current: consumes VARs. In the presence of the perfect filters, no distorting current flows beyond the filtering point, and the power factor can be approximated by the displacement factor(cos φ), where φ is the phase difference between the fundamental frequency of the voltage and current. Under these idealized conditions, with losses neglected, the active fundamental AC power is the same as the DC power, i.e.: Pdc = Vdc ⋅ Idc and (2.12) Pac = 3Vac ⋅ Iac ⋅ cosϕ (2.13) Pac = Pdc ⇔ Vdc ⋅ Idc cosϕ = (2.14) 3 ⋅Vac ⋅ Iac Where Iac is the ac current without harmonics. This AC current can be obtained from the r.m.s. π 3 1 2 2 ⋅ Idc of the rectangular current waveform through [( ) ⋅ ∫ I dc ⋅ d(ωt)] = (2.15) π π 3 − 3 Id 6 With Fourier analysis applied, the fundamental current is Iac = (2.16) π Substituting (2.7) and (2.16) in (2.14) gives cosϕ = 1 [cosα + cos(α + µ)] (2.17) 2 The reactive power is often expressed in terms of the active power i.e. Q = P ⋅ tanϕ (2.18) Similarly for (2.17) the following expression can be written for the power factor of the inverter cosϕ = 1 [cosγ + cos β ] (2.19) 2

Figure 2.3.1 Voltage and current displacement as a result of α

Referring again to the AC-voltage and valve current waveforms in figure 2.3.1 it is clear that the current supplied by the inverter to the AC system lags the positive half of the corresponding phase-voltage waveform more than 90º, or leads the negative half of the same voltage by less than 90º . It can either be said that the inverter absorbs lagging current or provides leading current, both concepts indicating that the inverter, like the rectifier, acts as a sink of reactive power. This point is made clear in vector diagram of figure 2.3.2a. Equations (2.13), (2.17) and (2.18) show that the active and reactive powers of a controlled rectifier vary with the cosine and sine of the control angle, respectively.

Figure 2.3.2a Vector diagrams of current and P&Q at rectifier and inverter b. Q demand at different P

Thus, when operating on constant current, the reactive power demand at low powers (φ= 90º) can be very high. However, such an operating condition is prevented in HVDC converters by the addition of on-load transformers tap changers, which try to reduce the steady-state control angle(or the extinction angle γ) to the minimum specified. Under such controlled conditions, figure 2.3.2b shows a typical variation of the reactive power demand against the active power of an HVDC converter; the reactive power demand is shown to be approximately 60% of the full active power transmitted.

In analogy with equation (2.18), for the reactive power that is consumed by the converter can be written: Q = 3⋅Vac ⋅ Iac ⋅sinϕ (2.20) Q = three - phase reactive power

This would suggest that in case of no firing delay, the converter does not consume reactive power. This suggestion will only hold for as long as the theoretical case of no source inductance is considered. In practice, due to the presence of source inductance and the subsequent fact that commutation takes a finite amount of time, the current waveform is no longer perfectly rectangular but the front and tail are slanted, already shown in figure 2.2.6c and d. From this it can be concluded that the converter will always consume a certain amount of reactive power, even in the case of α = 0. A realistic equation for the reactive power consumption is given by (2.23), which is derived from: Vdc ⋅ Idc Pdc = Vdc ⋅ Idc = 3⋅Vac ⋅ Iac ⋅ cos −1 (ϕ) → cosϕ = 3 ⋅Vac ⋅ Iac (2.21) Id 6 Vdc ⋅π Vd Iac = → cosϕ = = → (2.22) π 3 ⋅Vac ⋅ 6 Vdo  Vd  Q = 3⋅Vac ⋅ Iac ⋅cos−1  Vdo  (2.23)

Equation (2.23) is valid regardless whether the bridge operates in rectifier or inverter mode.

The reactive power consumed at the converter is at expense of the voltage regulation for the AC network, which can result in instabilities at AC side. To compensate the reactive power compensation capacitor banks are used. With the application of shunt capacitor banks for reactive power compensation or power factor correction, there is always the inrush current issue during energization. Also, the outrush current from the capacitor bank is a concern when a line circuit breaker closes in to nearby fault. In order to limit both the inrush and outrush currents series reactors can be used.

Harmonics The term harmonics is used to define the sinusoidal components of a repetitive waveform and these consist exclusively of frequencies which are exact multiples( harmonic orders) of the basic repetition frequency(i.e. the fundamental). HVDC converters generate harmonic voltages and currents on the DC and AC sides, respectively. Since the commutation reactance is low in relation to the DC smoothing reactance, an HVDC converter acts, from the AC point of view, as a source of harmonic currents(high internal impedance) and from the DC point of view, as a source of harmonic voltage(low internal impedance). Excessive levels of harmonic current must be prevented as they will cause voltage distortion, extra losses and overheating, as well as interference with external services(e.g. communication). The obvious place to eliminate the harmonics is the source itself. The line currents at the AC side of a six-pulse converter have a rectangular shape, figure 2.3.3a, which results in a significant harmonic content. Since these harmonics are undesired, they should be avoided as much as possible. By making a shift in the primary and secondary voltages of the transformer, a more sinusoidal waveform is achieved as seen in figure b. This shows the AC line- current drawn by the converter together with the momentary AC voltage has a more sinusoidal shape and the ripple in the DC voltage is reduced. By putting two six-pulse bridges in series with a 30° phase-shift between them(one YY, the other YD), a more sinusoidal current is drawn and, less harmonics are produced(figure 2.3.4c). This is the 12-pulse converter bridge which is covered in the next paragraph. 27

Figure 2.3.3 Voltage and current waveforms of a 12-pulse converter.

With the setting of figure 2.3.3c the 5 th and 7 th harmonics are effectively eliminated on AC side and on DC side the 6 th and 18 th are eliminated. The switching pattern of the converter is synchronized with the AC-side fundamental frequency, and as such contains a large fundamental component. As switching is an on-off process, harmonics of the fundamental are present as well. These manifest themselves as the characteristic harmonics on both sides of 12-pulse converter bridge, i.e. on the DC side, harmonics 12n, and on the AC side, harmonics 12n+1 in positive sequence, and 12n-1 in negative sequence, where n is an integer. These components are always present, even under ideal(undistorted AC voltage and DC current) operating conditions. Figure 2.3.4 shows the DC- side voltages and AC-side currents that could be expected.

Figure 2.3.4 a. AC-side and b. DC-side harmonics

To eliminate the harmonics further filters can be used. Filters are networks of passive network elements(RLC) tuned in such a way that only for specific frequencies they form a path of low impedance to ground. Although many types of filters exist, the following are discussed in this study: • Single-tuned filter; sharply tuned to one of the lower order harmonic frequencies • Double-tuned filter; nearly the same as the single-tuned filter, but tuned for two frequencies • High-pass filter; used to eliminate the higher-order harmonics.

Figure 3.3.5 Basic topology a. single tuned, b. double tuned and c. high pass filters

Commutation failure

Under normal circumstances, the voltage across the valve being turned off has to remain negative for a certain period of time after the extinction of its current (after γ) so that it becomes capable of blocking the forward voltage. Should the valve voltage become positive prematurely, the valve may turn on even without a firing pulse, resulting in the failure of the commutation process[22]. The application of forward voltage across a thyristor too soon after it has stopped conducting will cause the thyristor to re−conduct and lead to a commutation failure. Commutation failures normally occur at the inverter when there is a sudden drop in magnitude or phase shift in one or more phases of the AC commutating voltage. Recovery from a commutation failure depends on many factors. For long DC lines and cables the inverter dc current may become quite large due to the stored charge in the line/cable capacitance. The rectifier current controller will increase the rectifier firing angle in order to maintain the DC current at its set−point. To assist in the recovery, the inverter DC control may include a circuit which transiently reduces the inverter firing angle upon detection of a commutation failure. Reducing the inverter firing angle increases the extinction angle and as such provides a longer time between turn−off and application of forward voltage to the thyristors in the valve group. Detection of a commutation failure may be done by comparing the DC current with the current flowing in converter transformer secondary windings. During a commutation failure the DC current will be much larger than converter transformer secondary windings.

3. HVDC developments

3.1 Practical HVDC connections From recent paragraph it is seen which components build a HVDC connection, but still the most important is the 6-pulse thyristor bridge(fig 3.1.1a). This 6-pulse thyristor bridge can be connected in several ways to convert from ac to dc visa versa. Today's power systems are almost exclusively AC systems. At places where HVDC is used, it is only because at that particular place AC connections are technically not feasible or economical unattractive. Thus the DC connection serves as a hub for ac networks, which means practical HVDC connections always terminate at an AC bus. Taking this reasoning one step further it follows that for the integration of a HVDC connection in an AC network, two converter stations are required: one that operates as a rectifier and the other operates as an inverter. In this way, a power flow from rectifier to inverter is established. With the 6-pulse bridge as main component, two basic configurations are available to construct a HVDC link. Both configurations are shown in figure 3.1.1. Note also that since thyristors cannot conduct reverse current, the direction of the current flow through the connection is determined by the design (orientation of the bridges i.e.) of the connection and thus is unalterable. • Mono-polar system. This system consists of a single pole elevated at the DC voltage with respect to ground, figure 3.1.1b. As a return in principle the ground or a metallic return (conductor) may be used. In case of a ground return however, care should be taken since high ground currents can have undesired side-effects like corrosion of nearby installed pipelines. Because of this, the mono-polar system is not recommended. • Bi-polar system. For each converter station in this system, two converters are connected in the way depicted in figure 3.1.1c. With respect to ground the two poles are at a DC voltage equal in amplitude, but opposite in polarity. This configuration offers numerous advantages when compared to the mono-polar system. These include higher ratings while using the same infrastructure, absence of ground currents under balanced conditions and the possibility to continue operation at half of the rated power in case of a pole outage .

Figure 3.1.1 a. Six-pulse thyristor group b. mono-polar and c. bi-polar configuration

Depending on the requirements of a certain HVDC link, these two basic configurations can be connected geographically in different ways, such as: 1. Back-to-back; for interconnections between power system networks of different frequencies (50 and 60 Hz)

2. Two-terminal; Transmitting power from a rectifier terminal to an inverter terminal, typical of most HVDC transmission systems 3. Multi-terminal; When three or more HVDC substations are geographically separated with interconnecting transmission lines or cables, the HVDC transmission system is multi- terminal, which can further categorized as: i. Series multi-terminal ii. Parallel multi-terminal iii. Hybrid 4. Unit connection; right at the point of generation, the converter transformer of the rectifier is connected directly to the generator(for example hydro and wind).

Figure 3.1.2 Connection types HVDC link

A converter station can be roughly divided into two main sections, namely AC and DC part. Figure 3.1.3 shows a HVDC converter station indicating the main components areas.

Figure 3.1.3 Typical HVDC converter station 31

The valve hall of a converter station actually forms the bridge between the AC and the DC voltage since it houses the converter bridges. Up until now, a valve was treated as if it was just one single unit Because of the limited voltage rating of the individual thyristors, many of them must be connected in series to constitute a HVDC valve. The series connection of thyristors requires additional passive components to distribute the OFF state voltage uniformly between them and to protect the individual thyristors from excessive rate-of-rise of voltage( dv dt ) and rate-of-inrush current( di dt ). The thyristor, together with its local voltage-grading and thyristor-triggering circuits, known as a thyristor level, is the building block of the valve architecture. The circuit of a typical thyristor level is shown in figure 3.1.4a. It contains several parallel en series components but for simplicity the thyristor level can be as given in figure 3.1.4b. By connecting a suitable number of thyristor levels in series, a valve of the necessary voltage can be constructed.

Figure 3.1.4 a. Thyristor level b. Simplified

3.2 Trends in HVDC technology

HVDC has become the dominating technology for long distance transmission of bulk power. The use of 800 kV HVAC that was introduced in several countries during the 1960´s and 1970´s has come to a halt [10]. The HVDC development started with the transmission of power in an order of magnitude of a few hundred MW and was continuously increased to transmission ratings up to 3 - 4 GW over long distances. The rapid development and the increased confidence in the HVDC technology have caused the transition from ac to dc as transmission alternative. Almost 80 GW HVDC transmission capacities have been installed worldwide by 2005 and the expectation is that the growing trend will continue. Over 104 GW are expected from China only[1].

Figure 3.2.1 Growth HVDC connections worldwide [11]

As mentioned earlier, several reasons are there to use the HVDC option. One of them worthwhile repeating and going into some detail is the connection of different widespread small networks into one large power system. This is important from every transmission system operator (TSO) point of view. Such a large power system is the UCTE system in western Europe, which has been extended step by step to the today very complex configuration. The UCTE(Union for the Coordination of Production and Transmission of Electricity) is further connected to the surrounding networks and discussions are in progress for further connections. It can easily be concluded this extension surely will continue[1][13]. Other existing large interconnected systems are the western and eastern USA and USA with Canada. Large blackouts in America and Europe confirm clearly, that the favorable close electrical coupling by AC might include a strong risk of uncontrollable cascading effects in large and heavily loaded interconnected systems. Here HVDC might play an important role. This because of the major benefit of an HVDC link`s ability to control the power flow and its flexibility to adapt to different AC system characteristics at both sides of the interconnection[1].

Among the development of HVDC systems in the last 10 years the main avenues compared with the technology of 1990 is: The traditional classic HVDC technology(LLC) is still dominating but with improved equipment and sub-systems(e.g. valves, dc-bushings, AC-filters, DC-filters etc.). The new HVDC using (VSC) using IGBTs instead of thyristors is still in its research and experimental phase with only few operational links[10]. The trend due to these developments, is that LCC will still evolve and will be installed intensively[11]. Therefore the operation of HVDC must be well understood.

At present, the largest thyristors available, can withstand voltages of > 7 kV and are able to conduct currents well over 3 kA[5]. From this point of view it is not surprising that the thyristor is used extensively in HVDC applications since whenever used, these installations are typically 33 designed for the transmission of bulk power at considerably high voltage levels. Appendix C shows an overview of the HVDC projects operated and planned in the course of time.

3.3 HVDC from TenneT point of view

Presently one HVDC link is in operation in Netherlands, one is under construction and studies are carried out to build more HVDC links connecting the Dutch grid with other distant grids. The HVDC connection in operation is the NorNed, which connects Netherlands and Norway, the connection under construction is the BritNed, between the Netherlands and Britain. The other possible future connections are Cobra(Netherlands and Denmark) and a second link between Netherlands and Norway, viz NorNed II.

NorNed With a total length of 580 kilometers, the NorNed cable has a capacity to transmit 700 MW electricity from the Netherlands to Norway, vice versa- enough to supply power to half of Amsterdam or Oslo[12]. The cable was completed in May of 2008. The great advantage of the NorNed cable for TenneT and Statnett(TSO of Norway) is the fact that the cable enhances the security of supply of electricity in the Netherlands and Norway. This has strengthened TenneT’s position in the Northwestern European electricity market and Statnett’s position in Scandinavia.

Figure 3.3.1 Dutch grid (Red- 380kV;Green- 220 kV Purple- HVDC)

The connecting points of the NorNed cable is situated in Feda, on Norway’s south coast, and Eemshaven in the very north of the Netherlands. The Dutch electricity grid already had AC interconnections to Germany and Belgium before the completion of the NorNed project, while Statnett had cables linked to Sweden, Finland, Denmark and Russia. The NorNed cable contributes to the overall security of supply. This point makes the Eemshaven area an import node in the Dutch transmission grid.

Britned The BritNed is a bipolar configuration, and is the first power transmission project establishing a link between Great Britain and the Netherlands. The interconnection is rated to 1000 MW, but capable to transmit 1200 MW power in both directions. The converter stations are connected by a submarine DC cable of about 250 km length. The converter station in Great Britain is located at the Isle of Grain near London and the converter station in the Netherlands is located at Maasvlakte near Rotterdam. The project is a joint venture between National Grid (large international electricity and gas company in Great Britain) and TenneT. From environmental point of view, it is now possible to exchange green electricity between both power systems depending on actual generation and demand. The link will go into commercial operation in the first half of 2011. With the BritNed HVDC coming online it is shown, along the already existing HVDC interconnection Cross-Channel between Great Britain and France, the interconnection of different grids is continuing[10][12][14][15].

Cobra A feasibility study has been carried out concerning another link connecting Denmark and Netherlands, which`s converter station probably will be in Eemshaven. It is expected that a 700 MW interconnector between the Netherlands and Denmark will improve the accessibility of the electricity market and the security of supply. Integration of additional renewable energy sources (wind power) will be possible. The utilization of the transmission capacity is expected to be high. Endrup in Denmark and Eemshaven in Netherlands are the preferred locations for the HVDC converter stations. In the feasibility study both LCC and VSC have been considered from the perspective of investment costs, capitalized losses, risks and the added-value of ancillary services[16][24]. Results were slightly in favour of LCC. The Cobra Cable is scheduled to be ready for operation in 2016.

NorNed II Cobra is not the only link which is evaluated to be placed in Eemshaven. Another possible link to enforce the exchange of power between Norway and Netherlands is the Norned II[17]. This link might be placed in Eemshaven too. Recent developments are that large generation units are to be placed at Eemshaven. Studies are still carried out.

With large generators situated in Eemshaven and yet more to come, together with planned HVDC links, the Eemshaven area plays a significant role from stability point of view. Therefore investigating in the already existing network, aiming at the existing NorNed HVDC link, is an important tool to foresee congestions in the grid.

Using the fast controllability of the HVDC, it is possible to enhance the stability of both power systems. As the need for more flexible networks grows, HVDC will play an important role from a control point of view for stabilization and most importantly to connect widespread networks economically advantageously. Therefore investigation is needed in HVDC systems already existing, new more attractive DC technologies and of course the interaction between these two.

3.4 NorNed at Eemshaven Some plots are given showing the actual situation at Eemshaven around the DC substation EDC. Substation EDC in Eemshaven is situated in the North of Netherlands, also seen in figure 3.4.1.

Figure 3.4.1 Eemshaven area; EEMS and EDC

In the figure above it is seen two AC high voltage transmission lines end at substation Eemshaven(EEMS), these are 220kV and 380 kV lines, green and red lines respectively. From the 380kV AC substation the connection is made to the DC substation(EDC) with an underground cable at a distance of 1500 meters, dashed red line. Here the conversion is made from AC to DC(vice versa), and from here on the transmission is done by DC to(from) FEDA, shown in purple line. See figure 3.4.1, here a floor plan is shown, in figure 3.4.2 the actual situation is depicted. 36

Figure 3.4.2 Actual layout EEMS and EDC

In figure 3.4.2 the AC substation EEMS is seen at the near and at the far end EDC is seen. EDC actually consists of two buildings. One building where the filters are situated, known as the filter building and the other where the thyristors are for de AC-DC vice versa conversion known as the thyristor hall. In figure 3.4.3 both buildings are shown at EDC, the flat low building is the filter building, the higher building is the thyristor hall.

Figure 3.4.3 Filter building and Thyristor hall EDC

As the name indicates, in the filter building the filters for the elimination of the harmonics are installed. Besides the filters, also the capacitor banks needed for reactive power compensation are here. In the thyristor hall the thyristors are installed. These two buildings are separated by some distance. The equipments in these two buildings are connected by a 50 meters underground cable again, of the type used for connection between EEMS and EDC. The incoming point in the filterhal of the three phase AC cables are seen in figure 3.4.7.

Filter building

Figure 3.4.4 Snapshot 1

Figure 3.4.5 Snapshot 2

Figure 3.4.6 Snapshot 3

Figure 3.4.7 Snapshot 4 Incoming three phase AC cables in Filter hall

Thyristor hall

Figure 3.4.8 Snapshot 1, Thyristor valves 41

Figure 3.4.9 Snapshot 2

Figure 3.4.10 Snapshot 3

4. Network modeling The behavior of power systems is related to its ability of responding to the change in energy/power balance of a system, i.e. the ability to store a fraction of energy change into its electrical and mechanical components during power unbalance. Depending on the response time for the power unbalance there are three ways in which the power system can store a fraction of the energy; primary energy conversion, mechanical inertia and passive electrical components (LC parameters of the grid). As a result of this energy storing and transferring, there are three phenomena that occur in power system [19]. 1. Electromagnetic phenomena Electrical transient of the network are within time scale of 10 -6 seconds to 10 -3 seconds. In this phenomenon the system tries to store the fraction of energy in its electrical components like the inductors and capacitors. But the charging and discharging time constants of these components are very small. Hence, the resulted transient phenomena can have large oscillation within this time frame. 2. Electromechanical phenomena Dynamic response of system generators due to their rotating inertia is within time scale of 10 -3 seconds to 10 seconds. In this phenomenon the system tries to store a fraction of the energy into its mechanical component (the rotor of the machines) in terms of its rotor angle δ. Compared to the electrical components the mechanical component has larger time constant to store the energy change. 3. Thermodynamic phenomena The energy conversion process from primary energy sources within time scale of seconds to hours. In this phenomenon the large fraction of energy change can be controlled by monitoring the conversion of the primary energy source. The response time is longer compared to the other phenomena.

Corresponding to the above there are at least three types of simulation methods to investigate power system phenomena: electromagnetic transient, power system dynamic and power dispatch (load flow) simulations. 1. Electromagnetic Transient (EMT) simulation It is also called instantaneous value simulation, it is used to simulate an electromagnetic transient phenomena. For this simulation method the model of the power system components is complex as smaller time constant parameters are considered. To solve the equations of the network model the required time step is in µs.

2. Power System Dynamic (RMS) simulation This simulation method deals with electromechanical transients and neglects the electromagnetic transients of the network. Hence, it considers only the fundamental frequency components of voltage and current. The complexity of the component models is reduced by neglecting differential equations that involve smaller time constant parameters. Hence, compared to EMT simulation longer time step can be used to solve the network equation. A typical time step used for power system dynamic simulation is 10 ms.

3. Load flow and power dispatch simulation This simulation method is used to solve the steady state power flow equations of the network. The time constant for the steady state operation (thermodynamic process of primary energy conversion) is in the order of several seconds to minutes. So all the differential equations involved in the network model are assumed to be constant. Hence the power flow equations become algebraic equations that can be solved using an iteration method like Newton-Raphson method.

The understanding of electrical power systems in the µseconds area is still developing. With the development of power electronics which are more and more incorporated in grids, the investigation at smaller time scales becomes essential. In this study the Real Time Digital Simulator-RTDS installed at Delft University of Technology is used. The RTDS is a digital system built to perform real time simulations on electrical power systems. This is a strong property compared to many other simulation tools which are only able to perform off-line simulations. The simulation tool is enlarged in the following section together with de operation. Followed by the modeling of the investigated network.

4.1 The simulator

The RTDS is a special purpose computer, initially designed to study Electro Magnetic Transient (EMT) Phenomena in real-time [20]. This digital simulator is comprised of both specially designed hardware and software. In other words, it is a sophisticated digital simulator both in computing hardware and detailed models of power system components. RTDS hardware is Digital Signal Processor (DSP) and Reduced Instruction Set Computer (RISC) based, and utilizes advanced parallel processing techniques in order to achieve the computation speeds required to maintain continuous real-time operation. The software called RSCAD has a power system component model library and Graphical User Interface (GUI) environment to assemble a given network.

Hardware Unlike analogue simulators, which output continuous signals with respect to time, digital simulators compute the state of the power system model only at discrete instants in time. The time between these discrete instants is referred to as the simulation time-step (∆t). Many hundreds of thousands of calculations must be performed during each time-step in order to compute the state of the system at that instant. The temporary transients class of studies for which the RTDS is most often used requires ∆t to be in the order of 50 to 75 µsec (frequency response accurate to approximately 3000 Hz). By definition, the entire network calculations are completed in less than 50 µsec of actual time[20].

The RTDS is a modular concept where multiple 19" processor cards are combined to form a single rack. In turn, a complete simulator consists out of one or more racks. There are different cards that contain the digital signal processors. These different types of processor cards are each suited to perform specific tasks. Qua functionality the cards can be categorized in processing and communicational card.

Processing cards • 3PC- Triple Processor Cards; are used to run the simulation. The number of power system and control system component models that can be included in the simulation is determined by the available number of these processors. The processors need 25 ns to perform each instruction cycle of a component model • RPC-Risc Processor Cards; are only used to solve the network during simulation. They need 1.67 ns to perform each instruction cycle of a component model. • GPC-Giga Processor Cards; can be used to solve the network during simulation. Plus they have analogue output channels for signal exchange with external equipment. They need 1 ns to perform each instruction cycle of the component model, mostly these processors are used for small time model of power system components that need small time steps up to 2.5 µs[19].

Communication cards There are two communication cards; that facilitate data exchange between racks and between racks and the work station computer. • Inter-Rack Communications Card (IRC): In multi-rack simulation cases the data exchange between processors residing on separate racks is accomplished through high speed communication channel mounted on the IRC. • Workstation Interface Card (WIF): In addition to IRC, each rack has one WIF card that facilitates the communication between the RTDS and the host computer workstation through ethernet cable based local area network. WIF do not have any effect on network solution, it regulates and facilitates data package exchange both between racks and between racks and the workstation computer during simulation. Furthermore there are cards for digital and analog input/output which are: • Digital Input/Output card (DIO) • Optical Analogue-Digital Converter card (OADC16). • DIgital Time Stamp card (DITS) But no real-time connection and simulation were done in this study, so the last category was not used.

The specific functions of the cards can be found in reference [20].

Figure 4.1 RTDS installed at the Delft University of Technology

The RTDS at the Delft University of Technology that is used for the simulations consists out of a total of eight racks. Each of these eight racks is composed of a WIF card, seven 3PC cards, a RPC card and one DIO card. With this configuration each rack is capable to solve 54 single phase nodes and 56 breakers.

The RTDS is operated by means of workstations on which the dedicated software package is installed. For communication between the workstations and the RTDS a standard 10/100 Mbit Ethernet connection in combination with the TCP/IP protocol are used.

Software The RTDS software includes accurate power system component models required to represent many of the complex elements which make up physical power systems. The overall network solution technique employed in the RTDS is based on nodal analysis. The software package developed to provide a fully graphical interface is RSCAD. The RSCAD software suit is built around four separate modules that provide specific functionalities for modeling and simulation of power system equipment. • Draft module. The Draft module is very much comparable to other (off-line) simulation tools. It consist of a sheet on which the model can be drawn and a library where a variety of power system components are available. After having copied a component from the library into the model, the user is then able to modify its parameters to match them with those of the component to be modeled. • Cable module. In contrast to other components, the parameters for high-voltage cables used in the model are not entered directly in the draft module. Instead this is done in a

separate cable module. The cable module outputs a file containing all the properties of the cable per unit of its length. This file can then be linked to the connections in the model where the type of cable defined by the output file is used. A single file can thus be used for multiple connections. • T-line module. Is essentially the same as the cable module except that it applies to overhead lines instead of high-voltage cables. As such, in addition to the properties of the conductors, also the geometry of the pylons must be defined. • Runtime module. Serves as the link between RSCAD and the RTDS. Through the Runtime module a compiled version of the model can be uploaded to the RTDS and data produced by the simulation can be downloaded from it. The downloaded data is presented to the user in a graphical way. Furthermore the user can interact with the model while it is running by means of runtime controls. With software versions of buttons, switches and sliders the user can simulate a whole array of events and observe their impact on the simulated system in real time[5].

Once the network is assembled, compiled to map each component to the processors, the low level machine language for the Runtime module is generated, the simulation can be started.

Before going to the modeling of the network a little clarification is needed concerning the time step (∆t) of a simulation. In RSCAD there are two types of transmission line models; travelling wave transmission line model and PI section models. For the travelling wave transmission line model there is a separate data entry module in RSCAD. In this module it is possible to enter either physical parameter data or equivalent RLC values. One of the constraints using the T-Line module relates to the overall length of the line being represented. When the modal propagation time (or “travel time”) of a line is less than the chosen simulation time-step ∆t, the line cannot be represented using these general travelling wave models. This limitation is a result of the calculation algorithm. The travel time of the line is directly related to the line length, and hence it may found that, for short transmission lines, PI section representation will be required to represent length accurately. Normally as lines become shorter, the approximations resulting from using PI section modeling become less significant. Although using PI sections made up of R,L and C components is not normally the recommended method for line representation on the RTDS, there are instances where length of the line of a network dictates that such modeling techniques must be used.

Generally, the propagation velocity of an electromagnetic wave through a transmission line or a cable depends on the inductance and capacitance values. For a given value of L and C, the propagation velocity of the electromagnetic wave[21] is given by: 1 v p = L ⋅ C (4.1) Where v p is the propagation velocity in m/s. Therefore, the travelling time t p of the electromagnetic wave is given by t = L ⋅C p (4.2) Assuming propagation velocity is equivalent to the speed of light, a 50 µsec time step would see the waveform travel a total distance of approximately 15 km. This means that if the chosen simulation time step ∆t is 50 µsec, any line of length less than about 15 km would have to be represented using a PI section.

4.2 Modeling the primary circuit The NorNed HVDC link is as depicted in figure 4.2.1. The model is based on documentation available at TenneT. The HVDC transmission is designed to operate in the following operation mode: The converter system is a bi-directional bipolar system without electrodes. Each converter system is equipped with two times 6 pulse valve bridges and can be considered as a 12-pulse system at the ac-side. The dc cable connecting the two converter stations is a 580 km submarine cable at each pole. The system is designed to transport a nominal dc power of 600MW, with a minimum of 60MW and maximum of 1000MW. These powers are reached with an operating dc voltage of +450 and -450 kV, with currents ranging from 670A to 1252A for the earlier mentioned powers, where the nominal current is 686A. The basic control mode is constant power control, achieved by controlling the dc current to a current order. The dc current is controlled by the firing angle α at the rectifier. The dc voltage is controlled by the extinction angle γ of the inverter. When the dc voltage is not controllable by γ (so called dead band), the tap-changer of the converter transformers are used to reach the desired voltage range and γ is then used to fine-tune to achieve the steady state. The nominal firing angles α and γ are 15º & 20º respectively.

Figure 4.2.1 The NorNed configuration from Eemshaven to Feda

4.2.1 The components Source models As with most simulation studies, the entire network cannot be included in the simulator. But the impact the entire network has on the studied network, vice versa, is important and cannot be neglected. Therefore the network part that is not included in the simulator, is modeled as an infinite source with a certain short circuit capacity(SCC). This SCC is translated to an internal source impedance Zi in the source(Zi series to the infinite source). The short circuit capacity of a network is given by: SCC = 3 ⋅Vac ⋅ Isc (4.3) And the short circuit impedance: Zi = Ri + jXi (4.4) (Vac) 2 Zi = SCC (4.5) The data which is used for the modeling, is included in Appendix D. From the available data sheets, the normal short circuit capacities was used for substation Eemshaven and substation Feda. The related X/R ratio were also given. See table 4.2.1.

The calculated internal impedance with the data of table 4.2.1 for Eemshaven and Feda are given in table 4.2.2.

The problem encountered while modeling this directly in the RTDS was that a resistor series to an inductor as internal impedance was not possible. Though it was possible to use a resistor parallel to an inductor, a conversion was needed. Conversion from the series to parallel impedance was done and the values of the parallel resistor Rp and inductor Xp for substations Eemshaven and Feda are given in table 4.2.3. Now the parallel circuit of resistor Rp and inductor Xp form the internal impedance Zi.

Valve group For modeling classic HVDC converters in RSCAD, the valve group block is available in the library of the Draft module. The valve group block comprises a converter transformer, six-pulse bridge and an (optional) smoothing reactor. Although the user is able to define the parameters for each of the three components individually, no changes whatsoever can be made to the way they are interconnected, nor can components be added or be removed.

Converter transformer Modeling the NorNed converter transformers as it is configured in real was not possible. Each converter substation at both ends (rectifier and inverter) has one converter transformer. This transformer consists of three single phase three-winding transformers. One single phase three- winding transformer feeds one phase of each valve group. See figure 4.2.2a. Table 4.2.4 summarizes the nominal ratings of one single phase three-winding.

Figure 4.2.2 a. Real configuration- (one) single phase three-winding transformer b. Modeled configuration- (two) three phase two-winding transformer

The hurdle encountered while building the network was that the converter transformer included in the valve group block(VGB) model, cannot be changed from a three phase two-winding transformer to a one single phase three-winding transformer. Therefore a three phase two- winding converter transformer was modeled. So the parameters of the transformers in the VGB were changed to match the real transformers configuration. Figure 4.2.1 shows the conversion from real configuration to the model. Another option tried during modeling, was to change the converter transformer parameters in the VGB to an ideal transformer and use a separate three phase three winding transformer from the RSCAD library to feed the ideal transformers which are connected to the converters. This option was omitted because of limitations present in the model of the single phase three-winding transformer where no tapchangers were present. The converted ratings used for each of the converter transformers in the VGB is given in table 4.2.5.

It should be noted that the nominal rating given in table 4.2.5 is for one converter transformer. Two valve group blocks were used in each converter station. The converter transformer of one of the VGB is connected in Y-Y and the other in Y-D. See figure 4.2.3. Tap changers for controls are also included in the model. The full control of tap changers is discussed in chapter 5.

Figure 4.2.3 Six-pulse bridge in each converter station

Valve group As mentioned earlier, to reduce operational stresses, the so-called turn-off snubbers are placed across each thyristor. In essence these snubbers are a series connection of a capacitor and a resistor so that during turn-off, the voltage across the thyristor is clamped to the capacitor voltage. In practice, a number of thyristors are placed in series and combined with the necessary electronics, snubber circuit and grading capacitors to form a complete valve. A schematic representation of a thyristor with its electronics, called thyristor level was shown in figure 3.1.4.

In the NorNed case 120 of these thyristor levels were connected in series to form a valve group. Data was available of this valve group, given in table 4.2.6.

Unfortunately the VGB in the RSCAD library is modeled as a single thyristor level as shown in figure 4.2.4. These thyristors are modeled as control switches which have a ON state resistance, OFF state resistance and its snubber circuit, with its a resistance and a capacitance Rsn and Csn respectively.

Figure 4.2.4 Valve group model as one thyristor level with Rsn and Csn in RSCAD

It proved these snubber circuit values have a great impact on the precision of the simulation. The data provided in table 4.2.6 for the snubber circuit did not produce correct signals. Various attempts to fit the real data into the model failed. Finally the choice was made to use values of Rsn and Csn calculated from the RTDS tutorial case which`s rated DC voltage was 28.4 kV what is used as the base. This is in fact an interpolation. Formulas[20] used for calculating Rsn and Csn:

121.67 ⋅Vdc _ rated Rsn = 28.4 (4.6) 2.1( ⋅10−6 ) ⋅ 28 4. Csn = Vdc _ rated (4.7)

Where Vdc_rated is the rated DC voltage of NorNed. The calculated values used in the model for the thyristor level are presented in table 4.2.6.

The “gmmin” parameter defines the amount of time required for the thyristor to re-acquire forward voltage carrying capability after commutating to the off state. This parameter is usually only of interest at the inverter where the HVDC controller must ensure that valve firing is such that this minimum extinction angle is maintained. If forward voltage appears too soon after turn- off the valve will begin to re-conduct resulting in a commutation failure. If a positive voltage appears across one of the thyristors in the valve group within the time specified by “gmmin” the thyristor will put back into the on state by the model. The minimum gamma for NorNed is 435µs (table 4.2.7), which is equal to 7.83º, calculated from seconds to degrees with γdeg =γ sec • f • 360 (4.8)

Reactor The last component in the VGB is the optional reactor. To reduce the ripple component on the DC bus voltages and currents, at each end of both DC cables a smoothing reactor is present. These reactors serve the following purposes: • Decrease harmonic voltages and currents in the DC line • Prevent commutation failure in inverters • Prevent current from being discontinuous at light load • Limit the crest current in the rectifier during short-circuit on the DC line.

Neutral bus reactor The midpoint between the two valve groups at Eemshaven is not directly grounded unlike the midpoint at FEDA. Here a reactor is used at the neutral bus. The rating of the reactors are given in table 4.2.7

AC Filters For the Norned (12-pulse) converter bridge, only harmonics of the order 12 n ±1 (with n= 1,2,3...) are still present in the harmonic spectrum. It is desirable to further reduce the harmonic content, this is done by the application of filters. Filters are networks of passive network elements tuned in such a way that only for specific frequencies they form a path of low impedance to ground. Two types of filters are used in the NorNed link: • double-tuned band-filters • high-pass band-filters

To remove the two harmonics with the highest amplitude from the spectrum (i.e. the 11 th and the 13 th ), a double-tuned filter is used, at Eemshaven and Feda. The topology of the filter is depicted in the figures of Appendix E. The values for the resistance, inductance, and capacitance were drawn from data sheets, which are given for both stations in table 4.2.8

For the harmonics of the order 12 n ±1 (with n= 2,3,4...) high-pass band-filters are used. This th rd high-pass filter is tuned around the 24 harmonic and will filter out all harmonics from the 23 onwards. The topology of the high-pass filter is shown in the figures in Appendix E. The data is given in table 4.2.9.

Because of the low short-circuit power (and hence high inductive impedance at 3 rd harmonic), a 3rd harmonic filter bank is required at higher levels of DC power at Feda. The topology of this high-pass 3 rd harmonic filter is also given in Appendix E and table 4.2.10.

Reactive power compensation

Due to the excessive reactive power consumption by line commutated HVDC converters explained in chapter 2.3, it is necessary to provide additional voltage-support by the local injection of reactive power. Although there are several ways to achieve this, such as with synchronous condensers or static compensators, in the NorNed case capacitor banks are used. Furthermore, the capacitors which are part of the AC filters also deliver a certain amount of the required reactive power. For redundancy each converter station has two sets capacitor banks. To prevent high frequency transients currents when switching on the second bank, a current limiting

52 reactor is placed in one of the sets capacitor banks. At Eemshaven as well as at Feda. The ratings of the capacitor banks used is given in table 4.2.11.

The total reactive power injected at the ac sides of the converter stations by all the capacitor banks and the filters, is given in table 4.2.12.

Note that each converter station has two sets of filters and banks installed, except the 3 rd harmonic filter at Feda. The entire network is found in Appendix E.

4.2.2 Transmission

Cables and transmission line To model a transmission line there are two possibilities in RSCAD, either the distributed parameter (travelling wave) line model or the lumped (PI equivalent circuit) can be used. When the travelling time of the signal over the transmission line is less than the simulation time step, the PI equivalent circuit must be used. For example, for integration time step of 50 µs and propagation velocity of 3•10 8 m/s, all transmission lines with a length of less than 15 km are represented by the PI equivalent circuit. When the travelling time of the signal is larger than the integration time step, it is better to use the travelling wave line model. Using the travelling wave line model was not possible for two pieces of cables of 50 meters and 1500 meters. These are two pieces of XLPE cables of type EYLKrvlwd 220/380kV 1x1600CuMil from Prysmian.

PI section In the DRAFT the cable base frequency, the positive and zero sequence quantities of the cable which represents the PI section must be provided. Parameters are entered as the total impedance of the PI section. The positive and zero sequence impedances of the XLPE cable are Z1 = 0.015 + j0.245 and Z0 = 0.070 + j0.032 per km respectively. Data entered for the PI sections is summarized in table 4.2.13 below. The values of the zero sequence reactance’s Xz and Xcz were modified. This was necessary for successful compilation of the circuit in RSCAD. While compiling with the original data there was an error generated, which required the “Xz must be larger than Xp” and “Xcz must be larger than Xcp”. So these values were made slightly higher than the positive sequence reactance’s, as seen in the table.

Positive seq. series resistance (Rp) Positive seq. series inductive reactance (Xp) Positive seq. shunt capacitive reactance (Xcp) Zero seq. series resistance (Rz) Zero seq. series inductive reactance (Xz) Zero sequence shunt capacitive reactance (Xcz) Table 4.2.13 Rating of XLPE cable(Short and Long)

The situation where the two pieces of cables are used, is illustrated in the figures of chapter 3.4 and later on in figure 5.1.0. The DC converter station is located at some distance from the AC substation Eemshaven. Here the 1500 cable is used to connect the AC network to the filterhal in the converter station. In the filterhal the required filters and capacitor banks are connected. From here another piece of 50 meters cable connects the filterhal with the converters.

Travelling wave model

DC cable By using the T-Line software module, the DC cables connecting the two converter stations were modeled with a frequency depended travelling wave model. Using travelling wave model produces more accurate results, especially where transient situations are concerned. Table 4.2.14 gives an overview of the parameters that characterize the cable. Noteworthy is that the total length of de DC transmission is 580.5 km from both converter stations, this length is a composite of different types of cables. First both ends are land cables, with a length of 3 km and 1.5 km at Eemshaven and Feda respectively. The centre and most important part is a submarine cable of 576 km. This submarine has two parts, one of type ABB and the other of type Nexan. As the major part of the cable was of type ABB, the cable model was based on the ABB data. Two sets of these cable model were used, one for the +450kV cable and the other for -450kV. The inner distance between these two cables was averaged and chosen to be 2 meters.

5 Modeling the controls

In this section the HVDC controller used to control the HVDC and other controls in the RSCAD is explained. The control of the HVDC system described here is based on a generic HVDC system. This generic control scheme was derived from the case in the tutorial of the RSCAD library(version 1.02). The HVDC case was based on the monopolar HVDC Blackwater system in USA. The term generic is used since each manufacturer of HVDC controls apply their own proprietary concepts for HVDC control functions. The controls used in the tutorial[20] was not based on any particular manufacturer’s control scheme, but rather on well documented control concepts. If there is access to detailed schematics of a particular HVDC controller then the model can be built in the RSCAD. This was not available for the NorNed link. From various literature[6][23] it was found that the chosen generic control scheme in the tutorial is general enough to be applicable to other HVDC systems. And from the documentation of NorNed it was found this control scheme was specific enough to use it for investigation. Another study based on the HVDC tutorial for the HVDC mentioned here, was used earlier for a study at the TU Delft[5].

5.1 Control properties of model

Key advantage of a HVDC transmission system is that the power flow from sending to the receiving end is fully controllable. By assigning the proper firing delay angles to both of the converters, a voltage difference is created across a resistance with a fixed value. Following Ohm's law, this gives rise to a current, and thus a power flow as is illustrated by figure 5.1.1 given by equation (5.1)

(V −V ) Id = dA dB (5.1) Rdc

Figure 5.1.1 Fundamental principle of power transfer using a HVDC transmission system

Control of the converters is done by setting the firing delay angle (alpha-α) of the thyristor valves with respect to the AC system voltage. In most HVDC systems the rectifier’s firing angle is chosen so that the DC current is maintained at a set-point. The inverter’s firing angle is chosen so that its extinction angle (gamma-γ) is maintained at a set-point. Measured values of dc current

55 and extinction angle are provided to regulators whose output are the rectifier and inverter firing angle respectively. The extinction angle set-point is normally fixed at a certain point. The dc current set-point may be altered depending on the dc power requirements for the system. Instead of directly entering the DC current set-point, sometimes the DC power order is entered. In this case the measured DC voltage is used to compute the current set-point as Pset Iset = (5.2) Vdc The entire control scheme is based on per unit calculation of the variables (measured variables and variables to be altered). The basic HVDC control structure is illustrated in 5.1.2, which is further elaborated in this chapter.

Figure 5.1.2 Basic HVDC control structure

From figure 5.1.2 it is seen that there are three major parts in the controls circled in red, these are: 1. Master controller, 2. Rectifier controller, and 3. Inverter controller. Furthermore a division can be made regarding input and output of the controller. The important variables are: 1. Input variables, a. User input: power set point and gamma set point b. Measured input: operated current and operated gamma, additionally operated dc voltage 2. Output variables, Firing pulses for rectifier and inverter

5.1.1 Master control Control functions that are related to both the rectifier and inverter are performed by the master control. These functions comprise the blocking and de-blocking of the converters as well as giving the current order to the current controller of either of the two station controls. Since it is desirable to have the two poles operating in a balanced condition, the current ordered by the master control is calculated in the following way:

Pset Iord = (5.3) DCV1 + DCV 2

Figure 5.1.3 depicts the master control scheme. The important input variable is the DC power set-point entered by the user, from this the current order is calculated using DCV1 and DCV2 which are measured dc voltages at positive and negative polarity. Note that all the values are converted to per unit values. Once the current order Iord is produced using by means of (5.3), it is used in the entire control concept. The rate at which the current order is changed after a change in the power set-point is limited by the rate-limiter to 0.1 p.u. per second (ramp up/ramp down speed). This improves the system stability and reduces the stresses experienced by system components. Once the current order is determined, the steady state condition is maintained by keeping the current constant by the rectifier translated by α, whereas the voltage is kept constant by the inverter translated by γ.

Figure 5.1.3 Master controller

The option to control the current is also added. First the user switches with a control button from power to current set-point, followed by setting the current set-point with a slider in the runtime window.

5.1.2 Rectifier Recalling the basic control structure from figure 5.1.2, the rectifier consists of two important blocks, the current regulator and the firing pulse generator. Under normal circumstances the rectifier is operating in a constant current mode, thus controlling the current through the DC link.

Current controller The rectifier is equipped with a PI current controller which has the function to eliminate the difference between the current order and the actual current. The input for this block is the output of the master controller Iord, and the actual current Crect1. The actual current is measured between converter and smoothing reactor. This signal is passed through a first-order low-pass filter first to prevent erratic behavior by the controller, and also converted to a per unit value. The integrator output is limited to a value between 5° and 90°. Moreover, the output of the

57 controller is also limited to these exact same values by the application of a limiter. See figure 5.1.4. Note that the current order which is coming from the master controller is not directly compared with the measured current signal to serve the PI controller. The current order is first compared with a signal coming from the so called Voltage Dependant Current Order Limiter block (VDCOL).

Figure 5.1.4 Rectifier current controller

The VDCOL block is added to the earlier mentioned two blocks for the rectifier controller. What the VDCOL does is explained below.

Figure 5.1.5 Voltage Dependent Current Order Limiter, VDCOL

The voltage dependent current order limit block is shown in figure 5.1.5. As is indicated by the name this control limits the current order in the event of low voltage levels . Reduced voltage on the inverter terminals may lead to continuous commutation failure. As some valves stay in continuous conduction it is important to reduce the current order so as not to overstress the valves. Also, the voltage level at the inverter being low, the reactive power consumption by the converter will be higher than at rated voltages. As the DC current increases the amount of reactive power required also increases which in turn may lead to a further reduction of the voltage. In addition, the reactive power compensation provided by the capacitor banks and AC filters falls as a square of the voltage. When the inverter terminal voltage is greater than the rated voltage, the VDCOL output is equal to 1.0 and thus does not affect the current order issued by

58 the master controller. But if the input to the VDCOL drops below the threshold (0.9 pu), the output falls according to the characteristic shown in figure 5.1.6. The current order is now the minimum of the value ordered by the master control and the output of the VDCOL. Appendix F shows the full rectifier and inverter control characteristics. The AC bus voltage at the inverter or the DC bus voltage can serve as input to the VDCOL. In this study the AC bus voltage was used (N3, N4, N5). Again the rated values are converted to per unit first to be used in the control scheme.

Figure 5.1.6 VDCOL characteristic

Finally the minimum of the VDCOL and the Iord is chose and given to de PI current controller. The resulting signal is the alpha order rectifier: AOR1, where 1 is indicating the upper pole. This alpha order is given to the next control block.

Firing pulse generator The second block of the rectifier controller is the firing pulse generator. Within this block there are two functions. The phase locked loop (PLL) and the actual firing pulse generator (FPG). To ensure correct bridge operation the thyristors in the rectifier must be fired exactly at α degrees after they have obtained a positive forward voltage. This is achieved by supplying the FPG with a synchronization signal. This synchronization signal is provided by a control system that generates a signal that has a fixed relation to the phase of a reference signal, called a phase locked loop. A PLL automatically raises or lowers the frequency of a controlled oscillator until it matches the frequency and phase of a reference signal. The AC bus voltages at the rectifier serve as the reference signals for the three-phase PLL, in this case(N1, N2, N3), because the signals within the valve group are highly distorted. The firing pulse generator is depicted in figure 5.1.7.

Figure 5.1.7 Firing pulse generator with a PLL to determine the actual firing pulse instants

FPG With the firing angle for the rectifier known from the controls, it remains to generate the firing pulses for the six thyristors in each valve group. The firing angle refers to the delay in firing the thyristors relative to the time at which the voltage across the thyristor becomes positive. A firing angle of zero is equivalent to diode operation. Normally two thyristors are conducting with firing sequence 6,1 −1,2 −2,3 –3,4 −4,5 −5,6 −6,1 −1,2… During the commutation period three thyristors conduct. For example, between the 6,1 and 1,2 conduction periods the three thyristors 6,1,2 conduct for a short period (overlap time µ). The current through thyristor 6 decreases from Idc to zero while the current through thyristor 1 increases from zero to Idc. Depending on the type of transformer YY or YD, the FPG is configured with or without a lag of 0° or 30° respectively. Finally the output are the pulse words for the valve groups. The full rectifier control scheme is given in Appendix F.

Figure 5.1.8 Firing sequence in steady state is 6,1 −1,2 −2,3 –3,4 −4,5 −5,6 −6,1 −1,2 . . .

The control described above is just for one pole of the rectifier. A copy of the same blocks and functions is present for the other pole. The same variable from the master controller Iord is used here as input. Furthermore the measured valve current of pole 2 is used here as comparison and 60 the output from the FPG is given to the valve group of pole 2. The scheme for pole 2 is also included in Appendix F.

5.1.3 Inverter

In order to comprehend operation of HVDC valve groups in inverter mode, it is important that the concept of extinction angle(γ) be well understood. The extinction angle is a measure of the time between the current through a particular thyristor becomes zero and the time at which forward voltage appears across the thyristor (i.e. voltage across thyristor > 0). If a forward voltage is applied to the thyristor too soon after the thyristor current has become zero (i.e. the thyristor stopped conducting) the thyristor may begin to re-conduct even though no firing pulse is present. This event of commutation failure is already explained in section 2.3. The fact that the thyristor may re-conduct when γ is too small is a physical characteristic of the thyristor. Of course this is a unwanted property. Figure 5.1.9 shows the voltage across a thyristor within an HVDC converter operating as an inverter. The value of gamma shown in the figure is measured in seconds. To convert from seconds to degrees (4.8) is used.

Figure 5.1.9 Commutation failure

Note that the extinction angle is not a continuous value, but may only be measured whenever a thyristor stops conducting. For one 6-pulse valve group, 6 distinct values of γ can be measured each cycle. The minimum value for the six measured values of γ for a cycle may be monitored in the VGB. Although modern thyristors may be able to operate with γ values of a few degrees the operating set-point is usually set higher so as to have some margin of safety. A sudden drop in AC voltage will tend to reduce the actual value of γ. There is a trade-off, however, since the higher the value of γ the more reactive power consumed by the valve group. The minimum value of the extinction angle required for the proper operation of a valve is specified by the valve manufacturer; however, at the inverter side of HVDC systems the extinction angle is regulated to a value higher than the valve specifications to allow control adjustments and also leave an adequate safety margin for unforeseen events in the power system, such as faults. Severe faults such as the voltage drops, phase shifts, or sudden increase in dc current may cause the commutation process to fail[23]. Recall from table 4.2.6 the minimum gamma for NorNed is specified to 7.83°. But the operational γ is kept above 20º for NorNed.

Inverter control The inverter controls are somewhat more complex than the rectifier controls. In the illustration of the basic HVDC control structure (like the rectifier) two important blocks are included for the inverter. At the inverter the first block is the gamma controller whereas at the rectifier it was the current controller. The second block is the same firing pulse generator. Like there was an addition for stability reasons at the rectifier (VDCOL), at the inverter there are also additions.

Gamma controller This block is called gamma controller because the basis for this inverter controller is the gamma. The inputs are the gamma set by the user and measured gamma from the VGB. Within this block two modification functions exist. But even before the control signal coming from the master controller reaches the gamma controller, it is compared to the VDCOL.

Under normal operating conditions the inverter is controlling the voltage on the DC link. To keep this voltage at its rated value the inverter is controlled on the principle of a constant extinction angle γ. That is, the controller generates a firing delay angle such that the extinction angle remains constant. To reduce the amount of reactive power drawn by the HVDC system a fairly low value for the extinction angle is chosen. The minimum is set to 20° determined from documentations of NorNed and the max set to 30° to limit the reactive power consumption. This set-point for gamma is called GAMORDR, see figure 5.1.10. The difference between this signal and the minimum of all of the extinction angles both in pole 1 and pole 2 is eliminated by a PI gamma controller to reach the stable point, set by the user. The integrator as well as the output of the controller is limited from 90° to 155°. A margin angle of 25° is thus maintained to avoid

commutation failures.

Figure 5.1.10 Gamma controller

In addition to the gamma controller, also a current controller is present at the inverter controller. This is one of the earlier mentioned extra functions at the gamma controller block. Under normal conditions the current controller’s output is not used. However, if the dc current error is greater than a pre-determined amount (which is chosen to be 0.1 p.u. as in the base case) the inverter’s current controller is used instead of the extinction angle controller. A current margin is created by subtracting ten percent (CMARG=0.1 p.u.) of the rated current from the current ordered by the master controls. The reason for this current controller with a decreased current order is to

62 ensure a stable operating point in case the inverter terminal voltage exceeds that of the rectifier. Apart from the current order and limits, which in this case are 110° to 155°, it functions in the same way as was described for the rectifier current controller. The output of the current controller becomes active when the firing delay angle generated by it, is smaller than that of the gamma controller. The minimum function selects this from the gamma PI and the current PI controllers. Figure 5.1.11 illustrates the current controller of the inverter.

Figure 5.1.11 Inverter current controller

The second function added to the gamma controller block is the Inverter Delta Gamma Error. Under certain conditions (caused by the gamma PI controller and the current controller PI, explained later) there may exist two valid operating points, which can cause oscillations. To eradicate this oscillation, the delta gamma error (DGE) is added before the Iord reaches the gamma PI controller. The delta gamma error function is given in figure 5.1.12.

Figure 5.1.12 Delta Gamma Error controller

There is also a VDCOL included at the inverter. The Iord which was coming earlier from the master controller, is first compared to the AC voltage at the inverter, with the same reason as at the rectifier: to limit the current order in the event of low voltage levels at the inverter. See figure 5.1.13 This function is executed according to figure 5.1.6. Whenever the AC voltage falls below 0.9 pu, the current ordered decreases proportionally towards 0.5 pu, else the Iord from master controller is used.

Figure 5.1.13 VDCOL at the inverter

Firing pulse generators Now the inverter firing angle order (AOR2) known from the gamma controller(or inverter current controller) the signal is transferred to the second block of the inverter controller(from figure 5.1.2). This is the firing pulse generator. The firing pulse generator at the inverter is exactly the same as it is at the rectifier. Within this block there are again two functions, the phase locked loop (PLL) and the actual firing pulse generator (FPG). The AC bus voltages serve as the reference signals for the three-phase PLL, and the FPG for the VGB with the YD transformer is has a lag of 30°.

The entire control diagram is given in Appendix F inverter pole 1 pole 2. Note that there are two complete sets of rectifier and inverter controls, each for one pole. Before moving further, the full control properties is briefly explained using graphs.

5.2 Full control properties Under steady-state conditions with rated AC voltages at both the rectifier and inverter commutating buses the inverter firing angle is obtained using the PI regulator operating on the error between the extinction angle set-point and the measured extinction angle. In this case the HVDC system comes to a stable operating point defined by the intersection of the rectifier and inverter characteristics as shown in figure 5.2.1a. The rectifier characteristic’s segment labeled R1-R2 is due to the minimum firing angle. The vertical segment R2-R3 is due to the rectifier’s constant current controller. The inverter segment I1-I2 represents constant extinction angle control.

Figure 5.2.1 a. Rectifier characteristics b. Inverter characteristics

The rectifier R1-R2 characteristic portion is highly dependent upon the AC voltage available at the rectifier commutating bus. If this voltage decreases so that the segment R1-R2 falls below that of I1-I2 no stable operating point would exist and the dc current would fall to 0. In order to avoid such a situation the inverter controls are equipped with both a constant extinction angle controller and current controller. Under normal conditions the current controller’s output is not used. However, if the dc current error is greater than the pre-determined amount (0.1 pu for example) the inverter’s current controller is used rather than the extinction angle controller’s output. Figure 5.2.1b shows the structure of the inverter extinction angle and current controllers.

Under normal operating conditions the current error signal (Inverr2 in figure 5.1.13) will be zero. The input to the inverter’s current controller is offset by a constant value (CMARG 0.1 pu). The PI current controller for the inverter thus sees a constant value of 0.1 as its input and the integrator output ramps up to the maximum value. The minimum selection gate will then choose the firing angle determined by the inverter’s gamma controller. So long as the measured DC current(CINV2 in figure 5.1.13) is not less than 90% of the set-point current, the inverter’s current controller output is not used. In the case where the DC current falls below 90% of the set- point, the inverter’s current controller output will fall until its stable operating point is reached. Such a new operating point is not optimum since the reactive power consumed by the inverter will be greater than when operated in extinction angle control. Figure 5.2.2 shows the rectifier- inverter operating characteristic with both the inverter’s current and gamma controllers included. The new inverter segment labeled I1-I3 is due to the inverter current controller, figure 5.2.2a. Under rectifier low AC voltage conditions the operating point will be set by the inverter current controller as shown in the right hand side graph of figure 5.2.2b.

Figure 5.2.2 a. Current controller added b. Current controller active when AC voltage is low

If the AC voltage at the rectifier drops there is a potential situation where two valid operating points may exist. In this case the operation of the HVDC system may oscillate between these two points. Figure 5.2.3 shows the rectifier-inverter characteristic when the segments R1−R2 and I1−I2 are near the same values.

Figure 5.2.3 Two valid operating points: oscillation risk

A modification to the inverter controls is used to change the operating characteristic of the inverter so that there is a positive slope segment added between the constant current control and constant extinction angle control. The positive slope segment is created by subtracting a signal proportional to current error when creating the gamma controller error signal. The gain and limits for this control section are chosen so that the controller is active when the current error is in the range : 0,0 < CMARG < 0,1. Another approach that is often used to solve the two operating point problem is to include the voltage control loop at the inverter. The voltage controller adds a horizontal line segment to the inverter characteristic as shown in figure 5.2.4.

Figure 5.2.4 Alternate voltage control loop to eliminate oscillation risk

The VDCOL function was not shown in the preceding rectifier-inverter characteristics. This function is applied to both the rectifier and inverter. The full rectifier-inverter characteristics are shown in figure 5.2.5.

Figure 5.2.5 Full Rectifier-Inverter characteristic Idc vs Vdc

Tap-changers Finally the tap-changers play an important role to reach a desired steady state. When the dc voltage is not controllable by γ, the tap-changer of the converter transformers are used to reach the desired voltage range and γ is then used to fine-tune to achieve the steady state. Also to have adequate control over de voltage while keeping the firing delay angles at a value where the reactive power drawn by the converters is acceptable, the tap-changers of the converter transformers are used. Table 5.1 lists the data that was available on the tap-changers. To control the tap-changers, a value corresponding to a percentage of the rated voltage of the transformer is assigned to a specific variable of the valve group block. A tap position of +1 means that the rated voltage of the secondary winding is 1.0125 times the value entered in Draft for the secondary base voltage.

Eemshaven Feda Number of steps tap-changer +10 / -13 +11 / -9

Step size (% of U nom ) 1.25 1.25 Table 5.1 Number of steps transformer tap-changer

To control the tap position during simulation, sliders were used. After having converted the real values outputted by the sliders to integers it served as an input to a small control circuit. This control circuit converted the desired tap position into a value relative to the transformer's rated voltage so it could be assigned to the variable of the valve group block. Figure 5.2.6 shows this circuit. Two sliders are included. Each slider controls both converter transformers at rectifier or inverter.

Figure 5.2.6 Circuit for controlling the tap-changers

While modeling the circuit, it proved the sliders to adjust the ABC magnitude of the “sources” at both sides of the HVDC link was important to reach a stable point of operation. So these sliders were included in the runtime module. With the rated voltage at Eemshaven at 380kV and rated voltage at Feda at 300kV it was difficult(not possible) to reach the rated operation conditions for NorNed. Therefore the ABC magnitudes were altered and then other variables were tuned for a desired steady state. Other control functions used in this study are explained in the next paragraph.

5.3 Disturbances controls

Interaction with the network can be done from the runtime page/module. With switches, push buttons and sliders the parameters of the circuit can be changed and modified, and if wished the effects of these modifications can be observed graphically. But first these switches, push buttons and sliders have to be modeled in the RSCAD module in the network with specific functions.

In the three phase AC system different types of faults can be created. Such as single phase-to- ground faults to phase-to-phase faults, in short all types of faults. In the network model, on three locations AC faults were modeled. In RSCAD this is done by a fault branch. Known as “fault

68 point 1”, “fault point 2” and “fault point 3”, illustrated in figure 5.3.1. The exact location of the fault points is discussed in chapter 6. The fault branch consists of a switch whose open resistance is very large and whose closed resistance is specified by the user. In the menu of the fault branch the value of the resistance of the single phase to ground can be changed by means of a preprocessor variable slider, which was set to vary between 1µΩ to 10Ω. Furthermore each fault type in the fault branch menu must be assigned a specified bit number which correspondents to an integer from the logic. In this way from the logic(explained below) a specific fault type can be triggered.

Figure 5.3.1 Fault branch at different locations

A fault can be triggered from the runtime page which correspondents to the specified type of fault at a arbitrary moment, but during this study it was desirable to have the fault triggered at a specific time or at a certain location on the sinusoidal voltage wave. This is realized by the logic function of figure 5.3.2. This is the first part of the entire logic. This circuit is used to control the point on wave(POW) upon which the fault is applied, or the fault inception point. Node voltage N10 is used as a reference point for the point on wave delay. An If-Then-Else logic gate with a positive edge detector determines when N10 voltage has crossed the X-axis and is positive going (zero-crossing detector). The fault button when pressed produces a 22ms pulse which is slightly longer than one cycle at 50 Hz base. A pulse is then produced by the AND gate that combines the zero-crossing detector and fault button. The pulse drives the point on wave logic, which is comprised of a slider, a gain block, and a pulse duration timer set to detect a rising edge. When the pulse rises to logic one, the output of the duration timer is set to logic one equaling the time it takes to rotate the number of degrees from the zero crossing detection, set by the POW slider control. The pulse from the first duration timer is used to drive the fault duration logic, which is comprised of a slider, a pulse duration timer set to detect a falling edge. When the pulse falls to logic zero, the output of the duration timer is set to logic one for the specified time which is determined again by a slider.

Figure 5.3.2 Fault control part I, Inception point

The second part of the fault control logic circuit is used to control the fault type and location. Fault switches for the phase-to-phase and phase-to-ground fault types are combined to create the necessary integer value. This value is multiplied by the pulse from the first part of the logic, thereby creating a pulse width with an integer value that can control the fault branches. A dial component is used to control selector control switches that will determine where the fault will be applied: fault point. For example, the dial component is set to 1, and the B phase-to-ground fault type is selected, the corresponding fault signal “FLTSIGI” will have an integer value of “2’. All other fault signals will have an integer value of “0”. In this way the user can determine where and when a fault is made in the network. The second part of the fault control is shown in figure 5.3.2.

Figure 5.3.2 Fault control part II, fault location and fault type

Also DC faults can be made in the network. This includes DC cable to ground faults and faults in the valve group block. The faults in the VGB can be internal or external i.e. within the phases in the block, or from the phases in the block to other point outside the block. These types need to be selected first in the VGB and then be triggered from push buttons in runtime. The DC line to ground faults are triggered by a push button and the duration of the fault can be varied. One more additional fault type added is the voltage drop at the source. The duration and percentage of the voltage drop can be selected and the effect can be monitored. The push buttons, sliders and switches from the runtime page are shown in figure 5.3.3.

Figure 5.3.3 Control buttons, sliders and switches in Runtime

For a particular simulation case it was necessary to include a circuit breaker in the model. This was easily used from the components library. But the logic to trip the circuit breaker was done differently than in practice. In practice a fault is detected by a relay, which signals the circuit breaker to trip and the network(part) is isolated by the breaker action. The relay/protection model can be incorporated in the model from the RSCAD library. Here a different way was used to trip the CB in that sense that there was no relay used. Instead a small control logic was used. This control uses the signal to trigger the fault(given by the user), but with a delay sent to the circuit breaker. This time delay can be specified. Also the time which the breaker remains open can be specified. The option if the user wishes to open the breaker manually, is possible by changing a switch from fault control to manual control. The logic function is given in figure 5.3.4.

Figure 5.3.4 Control for the circuit breaker

Full control scheme and remarks The full control scheme is presented in Appendix F. Regarding this scheme, some important remarks have to be made. • The scheme is based on general control principles applicable to two-terminal HVDC transmission systems rather than that is based on manufacturer specific data used in practice.

• In practice, the controls are more elaborate then presented here. This due to the fact that, amongst other things practical schemes comprise automated controls for the capacitor banks and tapchangers. Something which in the model is done manually.

6 Simulation

In this part simulations with the model are carried out to investigate problems and results are presented using graphs. The effect of certain action and or failures in the network is explored. The main work until now was modeling the HVDC network. Of course the DC network can be elaborated with addition of the AC part. With the addition of the AC network, combination of faults are studied here. Desired situations can be studied and based on the responses statements can be made. This is divided in two parts. In part I various basic simulations are carried out with the AC and DC network to prove that the model is functioning as it should be at its rated properties. In part II a case is studied which occurred in the past, here attention still was necessary to investigate the cause of the occurrence and possibly enhance the network to prevent the event.

The AC network is not extended at the Norwegian side (FEDA). Feda is represented as a bus with a certain SCC. The AC network there was not important for this study. The AC network at EEMS is extended from the DC converter till the 380 kV substation, which is further explained in part II of this chapter.

In figure 6.1.0a the Valve Group Blocks in RTDS are shown, together with its controls in figure b. These controls are very important for the HVDC operation. The elaborated controls are given in Appendix F.

Figure 6.1.0 a. Valve Group Blocks in RTDS b. HVDC controls

6.1 Part I

6.1.1 Faults types First the steady state situation must be reached from where on faults can be triggered. The steady state properties of the NorNed HVDC link is given in Appendix G. Using the controls these points are reached. Then the following faults are triggered. These faults are:

• AC Faults § Single phase to ground faults § Phase to phase § Three phase § Sudden voltage drop at rectifier/inverter • DC faults § Positive polarity cable to ground § Negative polarity cable to ground • Converter faults § Combination Several type faults in the Valve Group Blocks

6.1.2 Steady state Steady state Rectifier mode In steady state the ratings of the HVDC link is given in table 6.1.1. The following plots show the steady state operating point.

Figure 6.1.1 DC power EEMS and FEDA (rectifier and inverter resp.)

Figure 6.1.2 AC power EEMS and FEDA

Figure 6.1.3 AC voltages EEMS and FEDA

Figure 6.1.4 DC voltage at EEMS and FEDA both at positive and negative polarity

Figure 6.1.5 DC current in valve group blocks EEMS and FEDA

Figure 6.1.6 DC cable currents at positive(upper plot) and negative polarity(lower plot)

Figure 6.1.7 Currents in capacitor banks, high pass filters and double tuned filters at EEMS

Figure 6.1.8 Control buttons and ABC voltage magnitudes EEMS and FEDA

Steady state Inverter mode

Figure 6.1.9 DC power EEMS and FEDA (inverter and rectifier resp.)

Figure 6.1.10 AC power EEMS and FEDA

Figure 6.1.2 AC voltages EEMS and FEDA

Figure 6.1.11 DC voltages EEMS and FEDA at positive and negative polarity

Figure 6.1.12 DC currents in valve group blocks at EEMS and FEDA

Figure 6.1.13 DC cable currents at positive (upper plot) and negative polarity (lower plot)

Figure 6.1.14 Currents in capacitor banks, high pass filter and double tuned filters at EEMS

Figure 6.1.15 Control buttons and ABC voltage magnitudes EEMS and FEDA

6.1.3 Results Faults

The faults mentioned earlier were triggered using the Runtime module. These fault types were initiated from steady state. Once a fault occurred, the responses were recorded and presented with graphs. The system kept on running on the background and returned to steady state. Because of the many types of faults carried out, these are not given here. The system reacts well and returns to the steady state after a fault is removed. One certain type of fault is thoroughly investigated in the next paragraph.

6.2 Part II

6.2.1 Case AM The network is considered ready now to do some other simulations and investigate practical problems. Real cases and events can be studied now. One such an event occurred in the past (April 11 th 2009)[25] was present at the department Asset Management(AM). This case needed attention in order to have better understanding concerning the effects of this case if reoccurred in the future. This case was placed at department Transport & Infra (TI) for examination.

Case

Between the AC substation and DC converter station at Eemshaven is the Filterhal where the harmonic filters and the capacitor banks are installed. At the end of the 1500 meter cable from the 380AC substation EEMS a single line-to-ground fault occurred. Power systems are designed to isolate the fault location or the faulted equipment as much accurately is possible with the actions of circuit breakers. This is also the case with the mentioned line-to-ground fault at the cable connection. After the single line-to-ground fault occurred, it was detected and the Gas Insulated Switchgear opened and the AC substation was disconnected from the HVDC transmission. The normal response of the fault current after disconnection is extinguishment, because it is not anymore fed from “sources”. The term sources include the inertia of generators still connected to the fault from either side.

The problem in this certain case is, that after switching the faulted part of the network, there was a damage (caused by an explosion and fire) probably AFTER the disconnection. This event should not have occurred. During the fault while the connection from phase to ground is sustained, the fault current will be large, whereas the voltage is almost zero. After detection and disconnection, there must have been some other reasons to cause the explosion. Oscillogram records from this case of the actual fault for some of the currents and the voltage of the fault point were available. Figure 6.2.2a shows the phase voltages of the three phases at the fault location (filter building). In figure 6.2.2b the faulted phase is zoomed. Furthermore the available current graphs at both ends of the 1500 meter cable are given in 6.2.3a and 6.2.3b. For the ease of reading, the graphs will be mentioned as graph A, B, C and D further in the text. Another current measurement was made at the far end of the 1500 meter cable, at the same location as figure 6.2.3b. All these pictures are included in Appendix H in larger format.

The situation from the 380kV AC substation with the two pieces underground cables, filter building and thyristor hall is shown in figure 6.1.1, this all together with converter transformers and converters in Eemshaven is shown in figure 6.1.4, a view in RTDS.

Figure 6.2.1 Situation at Eemshaven-EDC, fault occurred at the end of the long cable

Figure 6.2.2 a. Three phase voltages at fault location-A b. Faulted phase voltage-B

The information extracted from the oscillogram above and below(voltage and current), is that at a certain time, t = 0.24 seconds a short circuit occurs from phase B to ground. This fault is sustained till the end of the recording. The fault is in the filter building, at the end of the long cable. The voltage of phase B swings around zero while the current in the cable(fault current) increases. At t = 0.29 seconds the detected fault is disconnected at the beginning of the long cable by the action of the circuit breaker(GIS), this is approximately 50 milliseconds after the ground fault occurs. After disconnection the voltages in the other phases have swings with higher frequencies, figure 6.2.2a. The currents in the other phases also swing larger but not as large as in phase B, see figure 6.2.3.

Figure 6.2.3 a. Current at the near end long cable-C b. Current at the far end long cable-D

Figure 6.2.4 Situation at Eemshaven-EDC in RTDS

Figure 6.2.5 Capacitor banks and Filters in Eemshaven

6.2.2 Results studied case Starting point for this case study was a steady state situation. The chosen point was a DC power transmission of 600MW at rated voltages +450/-450 kV. Snapshots of the responses at steady state are already given in part I of this chapter. Because it was unknown in which mode the substation EDC was operated when the fault occurred, both modes of operation were investigated.

In the following text the concept of “Rectifier mode” and “Inverter mode” is used to indicate in which mode the substation EDC in Eemshaven is functioning. In rectifier mode power is transmitted from Netherlands to Norway through the HVDC link. In inverter mode from Norway to Netherlands.

For determination of the mode of operation at the moment of fault occurrence the voltage and current signals from the oscillogram at the fault were taken as reference. These were compared with the voltage and current signals made in the simulation. The fault is made at the moment the voltage is negative in the filter building, as seen in figure 6.2.2a. The controls were used for this, the slider was set to 240º after zero crossing. This is seen in figures 6.2.6 in both rectifier and inverter mode. The voltages just after the fault are more or less the same as the voltages from plot A, but the emphasis is on the moment the fault occurs. For the current signals plot C(at near end of long cable, figure 6.2.3a) was chosen as the reference. In figure 6.2.7 these currents of both modes are given.

Figure 6.2.6a. Voltages Rectifier mode b. Voltages Inverter mode

Figure 6.2.7a. Currents Rectifier mode b. Currents Inverter mode

In plot C the current at the near end of long cable is positive at the moment of fault occurrence. This is the case when the EDC is in inverter mode, that is seen in figure 6.2.7b. So the simulations were carried out using inverter mode, but the rectifier mode was explored too, this was done to know what the effect is of the entire system in both modes.

Once the determined mode of operation is determined, the goal is to replicate the plots A through D. After this, a possible solution can be worked out. This can be incorporated in the network to prevent the occurrence of fire/explosion after disconnection of the faulted part.

Using the Runtime in RTDS several signals were observed. Not all of them are included in the results here. These can be found in Appendix I. Some of them however are shortly mentioned and given here. Numerous simulations were carried out in the attempt to replicate the signals of plots A, B, C & D.

Figure 6.2.8 a. Simulated plot A Rectifier mode b. Simulated plot A Inverter mode

The voltages in filter building achieved during simulations are as in figure 6.2.8. The first difference between the actual recording and the simulation is that the magnitude of the voltage swings of the unfaulted phases are not as large as in plot A after the CB has tripped. Furthermore a distinct difference is the made in the mode of operation. In inverter mode, when the main circuit breaker has disconnected the fault after 50 ms, after a period of 30 ms the swings increase. This occurs possibly because the rectifier(FEDA) keeps operating, and the inverter(EDC) is also active. In practice whenever a fault occurs, the HVDC controls react fast on this by stopping the firing of the valves even before the fault is disconnected by the main CB. This control function is lacking in the present controls of the HVDC model.

The solution to eliminate the swings of phases A and B is to trip the capacitor banks together with the main circuit breaker. With this action the phenomena of L-C swings between the converter transformer and the capacitor banks is eliminated.

With the addition of circuit breakers to the capacitor banks and switching them together off at the moment the main CB opens(50 ms after fault occurs), the results are as in figure 6.2.9

Figure 6.2.9 a. Cap. banks off- Rectifier mode b. Cap. Banks off- Inverter mode

It is clear that the swings are reduced. In both modes the swings after disconnecting the capacitor banks are smaller than the 100 kV. This is a reduction of approximately 25%.

When the capacitor banks are tripped, the discharges of the charges over the ground fault are stopped. This is seen in figures 6.2.12 & 6.2.13 in rectifier mode and in figures 6.2.18 & 6.2.19 in inverter mode.

The exact signals are not obtained with the simulations. This is a drawback. Other variables altered in the course to get the replica of plots A and B are:

• Variation of the ground fault resistance • Variation of Zero sequence reactance of Y-D transformer • Saturation of converter transformer

In figure 6.2.22 and 6.2.23 the actual recording is compared with the simulation of the phase voltage of the faulted phase. In 6.2.22 before and after the fault is cleared spikes appear in the voltage signal. This is not found in the simulation 6.2.23. For the simulation a ground fault resistance(R on , as explained in chapter 5.3) of 0.01Ω was chosen. It was an fault from an underground cable to ground fault, so the resistance was quite low. This R on was varied from -6 1•10 Ω to 10Ω. It is found when R on is very low, the phase voltage stays constant approximately zero. When R on is high there is an sinusoidal response of the phase B voltage with a higher amplitude. When the fault occurred, the ground resistance varied in practice, which`s value is difficult to know exactly, this is seen as the spikes in figure 6.2.2b. The model of the ground fault(resistance) is quite simply modeled, getting the exact response as in6.2.2b was not possible.

Another step undertaken to reach get the signals as in plot A is the variation of the zero sequence reactance of the converter transformer. In the YY transformer it was not possible to change this parameter. The YD transformer however had the option. The best results were found with 0.01 pu. The YY transformer model did not have the option to change/alter or even enter the zero sequence reactance.

The model in the first step was modified here from one single phase three-winding transformers to two three phase two-winding transformer.

Furthermore, the option to activate saturation of the converter transformer is not enabled in the present model of the HVDC Valve Group Block.

All of these inadequacies of the present model and controls resulted in not replicating the exact signals during simulation. But the results achieved above do have strong resemblance of the responses.

7. Conclusions & Recommendations Following the work done here during theoretical study, the modeling and the simulations, several conclusions can be made. According to the hurdles and experiences some recommendations are made.

7.1 Conclusions

• The HVDC model was created for the NorNed link; This was done as much as possible through (control)standards in available software to carry out dynamic simulations. The HVDC basics, procedure followed for modeling network and its control are reported.

• Various simulations were carried out with this model, including AC 1-2-3 phase and Ground faults, DC cable faults and converter faults; From the results achieved during simulations, the model can be used for studies for more insight in the NorNed HVDC link, because the response from basic fault simulations is as expected.

• The case which was to be investigated is discussed below; The aim during the simulations was to replicate the signals from the recorded fault. To some extend it is replicated. From the responses using this model it is clear what the effect is of the events occurred in the past and solutions can be proposed using these results.

• The exact signals which were recorded at the moment of fault are not obtained with the built model, this was because of some modifications while modeling the actual equipment and some limitations in the simulation tool; The parameters of these models were thoroughly altered during simulations to achieve the response which were available from the fault recording oscillogram o transformer configuration ; The change was made from one single phase three-winding transformers to two three phase two-winding transformer model, the attempt to use a single phase three-winding transformer to investigate the effect of it remained unsuccessful. o pi-section cable models; With a simulation time step of 50 micro-sec no cables/lines can be modeled using travelling wave model, the pi section was therefore used, which is limited in its accuracy o model which represents the ground fault; The actual fault was a single phase to ground fault in the cable from which the oscillogram was present, this showed a response that is unsteady/irregular. Various values for the ground fault resistance were simulated, this resulted in changes in the phase to ground fault, but also in the other phases, which indicates the right representation of the ground fault could have showed the desired response.

• The necessary modification according to the responses is formulated; Possible solutions were incorporated in the model and it is found from the responses of the simulation a way of preventing what happened in the past, is to disconnect the capacitor banks together with the main GIS which disconnects the HVDC link. With this action the swings of the unfaulted phases is decreased.

7.2 Recommendations

Based on the hurdles encountered and results found the following recommendation is formulated:

The results found here for the studied case are not convincing enough for adjustments in the grid, the exact replica of recorded oscillogram were not obtained. Nevertheless, an important step was set for the investigation of HVDC. TenneT is encouraged to investigate the problem of the fault and if possible enhance the network to prevent such events, which results in long interruption of the NorNed. This can be done with RTDS and/or other simulation tools. RTDS is limited in its modeling which obstruct the exact modeling of actual equipment. Therefore the exact responses were not found during the simulations. So using updated models in RSCAD is strongly recommended. RTDS has the strong feature to perform real-time simulation which TenneT in cooperation with the TU Delft can use in the future, where HVDC will play an important role for bulk transmission. Fine-tuning is need for the present controls and model. In order to verify the models and the case studied here, another simulation tool can also be used. This can be done with DIgSILENT PowerFactory which is used at TenneT.

References

1. Role of HVDC and FACTS in future Power Systems, W. Breuer, D. Povh, D. Retzmann, E. Teltsch 2004

2. UHV DC 800 kV Bulk Transmission, IEEE T&D Latin America –São Paulo,Brazil - November 10th, 2010

3. High Voltage Direct Current Transmission- Proven technology for power exchange, Siemens

4. High Voltage Direct Current (HVDC)Transmission Systems Technology Review Paper, ABB

5. Dielectric stresses on 800 kV HVDC Converter Transformers and Thyristor Valves, Mark Louwerse 2008

6. High Voltage Direct Current Transmission, 2 nd edition, Jos Arrillaga

7. HVDC Transmission, Dennis A. Woodford, Manitoba HVDC Research Centre Canada, 18 march 1998

8. Novel Voltage Source Converter based HVDC Transmission System for Offshore Wind Farms, Stephan Meier, Stockholm 2005

9. VSC-Based HVDC Power Transmission Systems: An Overview , Nikolas Flourentzou, Vassilios G. Agelidis, and Georgios D. Demetriades, march 2009

10. Recent classic HVDC development, Lennart Carlsson and Gunnar Flisberg, ABB Utilities

11. Recent and future trends in HVDC converter station design, Lennart Carlsson, Gunnar Asplund, Hans Bjorlilund, Henrik Stomherg ABB

12. NorNed project Technische beschrijving, TenneT 2004

13. Trends for future HVDC applications, W. Breuer, D. Povh, D. Retzmann, E. Teltsch, Siemens 2006

14. Future of hvdc power grid in Europe, Vojtech Straka, TU Delft

15. Modern HVDC: State of the art and development trends , Víctor F. Lescale, ABB

16. The Cobra Cable - A feasibility study regarding an HVDC submarine cable between the Netherlands and Denmark, TenneT & Energinet.dk

17. http://www.statnett.no/en/

18. 8th AC/DC Conference, London IEEE, March 2006

19. Implementation of Noord-Holland Grid in RTDS, A. G. Ejigu 2009

20. Real Tim Digital Simulator power system users manual , February 2005

21. Transients in power systems, Lou van der Sluis 2001

22. Commutation Failure Analysis in HVDC Systems Using Advanced Multiple-Run Methods , E. Rahimi, S. Filizadeh, A. M. Gole, IEEE

23. Power System Stability and Control, P. Kundur

24. The Cobra Cable -A feasibility study regarding an HVDC submarine cable between the Netherlands and Denmark, TenneT-Energinet 2009

25. TenneT

26. Power electronics: Converters, Applications and Design, Mohan, Undeland and Robbins

27. HVDC Projects Listing Prepared for the DC and Flexible AC Transmission Subcommittee of the IEEE Transmission and Distribution Committee, Working Group on HVDC and FACTS Bibliography and Records, July 2009

APPENDICES

Appendix A. Comparison example AC and DC cable transmission

High voltage transmission by cable is rarely used because of the higher cost and longer repair times; it is normally restricted to underwater crossings and infeed to urban centers. The high voltage cables have a low series inductance and a large shunt capacitance. Moreover their loading, owing to the lower surge impedance and thermal limitations, is usually below 0.3 times the surge-impedance level. Therefore, high charging reactive powers are required, which considerably limit the length of AC cable transmission. For instance, at 50 Hz the charging current varies typically from 5.5 A/km for a 132 kV cable to about 15 A/km for a 380 kV cable. With a 4.52 cm 2, 380 kV cable of 600 A thermal limit, the charging current for a 40 km length equals the thermal limit and no useful load can therefore be carried. Similarly, a 2.58 cm 2, 450 A, 132 kV cable has a critical length of about 80 km.

These critical lengths may be extended by inserting shunt reactors. Even with 100% compensation by means of two reactors, one at each end, the power transmission capacity is only 86.6% at critical length and reduces to zero at twice the critical length. With two intermediate reactors, each providing 100% compensation, deciding the line in three equal parts, the critical length will increase to three times. Moreover intermediate compensation is impractical in the case of underwater links.[6]

Appendix B. Rectifier and Inverter operation signals

Typical six-pulse rectifier operation signals a. Positive and negative voltyages with respect to transformer nuetral b. direct bridge voltage V d and voltage across valve 1 c, d. Valve currents i 1 to i 6 e. AC line current of phase R

Typical six-pulse inverter operation signals a. Positive and negative voltyages with respect to transformer nuetral b. direct bridge voltage V d and voltage across valve 1 c, d. Valve currents i 1 to i 6 e. AC line current of phase R

Appendix C. HVDC projects HVDC Projects Listing [27]

Appendix D. Data for network model in chapter 4 Empty

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Empty

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Empty

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Empty

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Appendix E. Network in RTDS ( RSCAD )

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Filters and capacitor banks at Netherlands (EDC) and Norway (FEDA)

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Appendix F. Full HVDC rectifier and inverter controls Master controls

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Rectifier controls

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Inverter controls

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Appendix G. Steady state properties NorNed

Main circuit parameters for the NorNed HVDC Cable transmission

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Appendix H. Oscillogram recordings of Case

Voltages filter building

Voltage phase B filter building

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Currents short end long cable

Currents long end long cable

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Currents short end long cable (meting II)

Currents long end minus short end

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Appendix I. Case simulated in RTDS

Figure 6.2.10 Currents long cable, short cable, phase voltages Rectifier mode

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Figure 6.2.11 Capacitor banks disconnected Rectifier mode

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Figure 6.2.12 Currents Capacitor banks, High pass filters, Double tuned filters Rectifier mode

Figure 6.2.13 Capacitor banks disconnected Rectifier mode

Figure 6.2.14 Fault current phase B to ground Rectifier mode

Figure 6.2.15 Capacitor banks disconnected Rectifier mode

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Figure 6.2.16 Currents long cable, short cable, phase voltages Inverter mode

Figure 6.2.17 Capacitor banks disconnected Inverter mode

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Figure 6.2.18 Currents Capacitor banks, High pass filters, Double tuned filters Inverter mode

Figure 6.2.19 Capacitor banks disconnected Inverter mode

Figure 6.2.20 Fault current phase B to ground Inverter mode

Figure 6.2.21 Capacitor banks disconnected Inverter mode

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Figure 6.2.22 Faulted phase voltage- plot B

b. Ron= 1•10 -6Ω

Figure 6.2.23a. Simulated faulted phase voltage

c. Ron= 10Ω

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