Cover
Preface
About the Book
Acknowledgements
About the Companion Website
1 Flexible Electrical Energy Systems
1. 1.1 Introduction
2. 1.2 Classification of Flexible Transmission System Equipment
3. 1.3 Flexible Systems Vs Conventional Systems
4. 1.4 Phasor Measurement Units
5. 1.5 Future Developments and Challenges
6. References
2 Power Electronics for VSC‐Based Bridges
1. 2.1 Introduction
2. 2.2 Power Semiconductor Switches
3. 2.3 Voltage Source Converters
4. 2.4 HVDC Systems Based on VSC
5. 2.5 Conclusions
6. References
3 Power Flows
1. 3.1 Introduction
2. 3.2 Power Network Modelling
3. 3.3 Peculiarities of the Power Flow Formulation
4. 3.4 The Nodal Power Flow Equations
5. 3.5 The Newton‐Raphson Method in Rectangular Coordinates
6. 3.6 The Voltage Source Converter Model
7. 3.7 The STATCOM Model
8. 3.8 VSC‐HVDC Systems Modelling
9. 3.9 Three‐Terminal VSC‐HVDC System Model
10. 3.10 Multi‐Terminal VSC‐HVDC System Model
11. 3.11 Conclusions
12. References
13. 3.A Appendix
14. 3.B Appendix
4 Optimal Power Flows
1. 4.1 Introduction
2. 4.2 Power Flows in Polar Coordinates
3. 4.3 Optimal Power Flow Formulation
4. 4.4 The Lagrangian Methods
5. 4.5 AC OPF Formulation
6. 4.6 Generalization of the OPF Formulation for AC‐DC Networks
7. 4.7 Inclusion of the VSC Model in OPF
8. 4.8 The Point‐to‐Point and Back‐to‐Back VSC‐HVDC Links Models in OPF
9. 4.9 Multi‐Terminal VSC‐HVDC Systems in OPF
10. DC Network
11. AC Network
12. 4.10 Conclusion
13. References
5 State Estimation
1. 5.1 Introduction
2. 5.2 State Estimation of Electrical Networks
3. 5.3 Network Model and Measurement System
4. 5.4 Calculation of the Estimated State
5. 5.5 Bad Data Identification
6. 5.6 FACTS Device State Estimation Modelling in Electrical Power Grids
7. 5.7 Incorporation of Measurements Furnished by PMUs
8. Appendix
9. References
6 Dynamic Simulations of Power Systems
1. 6.1 Introduction
2. 6.2 Modelling of Conventional Power System Components
3. 6.3 Time Domain Solution Philosophy
4. 6.4 Modelling of the STATCOM for Dynamic Simulations
5. 6.5 Modelling of VSC‐HVDC Links for Dynamic Simulations
6. 6.6 Modelling of Multi‐terminal VSC‐HVDC Systems for Dynamic Simulations
7. 6.7 Conclusion
8. References
7 Electromagnetic Transient Studies and Simulation of FACTS‐HVDC‐VSC Equipment
1. 7.1 Introduction
2. 7.2 The STATCOM Case
3. 7.3 STATCOM Based on Multilevel VSC
4. 7.4 Example of HVDC based on Multilevel FC Converter
5. 7.5 Example of a Multi‐Terminal HVDC System Using Multilevel FC Converters
6. 7.6 Conclusions
7. References
Index
End User License Agreement

List of Tables

Chapter 1
1. Table 1.1 FTS equipment and the respective areas of power systems applications.
2. Table 1.2 Classification of FTS equipment according to converter type.
3. Table 1.3 STATCOM operating modes.
Chapter 2
1. Table 2.1 Three‐level NPC VSC: output voltage as a function of the switch states...
2. Table 2.2 Three‐level FC VSC: output voltage as a function of the switch states.
3. Table 2.3 VSC‐HVDC installations in operation.
4. Table 2.4 VSC‐HVDC installation due for commissioning in the period 2019–2020.
5. Table 2.5 The 10 largest CSC‐HVDC installations in the world.
Chapter 3
1. Table 3.1 Voltage magnitudes at the compensated buses in the 30‐bus system for t...
2. Table 3.2 Power loss at the compensated buses in the 30‐bus system for two compe...
3. Table 3.3 Parameter data for the VSC‐HVDC system of Test Case 6.
4. Table 3.4 Power flow voltage solution.
5. Table 3.5 Tap values for the two VSCs and the two LTCs.
6. Table 3.6 Power flow voltage solution.
7. Table 3.7 Tap values for the two VSCs and the two LTCs.
8. Table 3.8 Power flow voltage solution.
9. Table 3.9 Tap values for the two VSCs and the two LTCs.
10. Table 3.10 Type of VSCs and their control variables.
11. Table 3.11 Parameters of the VSCs, AC₁, AC₃, AC₅ and DC networks, with electrica...
12. Table 3.12 State variables solution per VSC.
13. Table 3.13 Voltages and powers injected at the AC networks.
14. Table 3.14 Power flows in the DC ring.
Chapter 4
1. Table 4.1 Generator cost function coefficients.
2. Table 4.2 Transformer data (load tap changers).
3. Table 4.3 Shunt devices.
4. Table 4.4 Generator limits.
5. Table 4.5 Optimal power flow solution: real powers (benchmark test).
6. Table 4.6 Optimal power flow solution: reactive powers (benchmark test).
7. Table 4.7 Voltage regulation at transformer buses – controlled test II.
8. Table 4.8 Voltage regulation at transformer buses – controlled test III.
9. Table 4.9 OPF summary results – IEEE 30‐bus system.
10. Table 4.10 VSC data.
11. Table 4.11 DC lines data.
12. Table 4.12 DC bus data.
13. Table 4.13 VSC constraints.
14. Table 4.14 AC voltage magnitude constraints.
15. Table 4.15 Generator constraints.
16. Table 4.16 A summary of the hybrid test system results.
17. Table 4.17 Converters outputs summary.
18. Table 4.18 DC power lines.
19. Table 4.19 Converters PWM performance.
20. Table 4.20 Converters outputs summary.
21. Table 4.21 DC lines.
22. Table 4.22 Converters PWM performance.
23. Table 4.23 Generators outputs.
24. Table 4.24 Active power flows in the AC network.
25. Table 4.27 Reactive power flows in the AC network.
Chapter 5
1. Table 5.1 WLS‐SE tutorial network parameters.
2. Table 5.2 WLS‐SE results for the tutorial network with exact measurements.
3. Table 5.3 STATCOM measurements.
4. Table 5.4 Extended STATCOM measurements.
5. Table 5.5 UPFC measurements.
6. Table 5.6 VSC‐HVDC measurements.
7. Table 5.7 Multi‐terminal measurements.
8. Table 5.A.1 Data files.
9. Table 5.A.2 Variable ‘ac_node’ format.
10. Table 5.A.3 Variable ‘ac_branch’ format.
11. Table 5.A.4 Variable ‘z’ format.
12. Table 5.A.5 : Variable ‘c’ format.
Chapter 6
1. Table 6.1 Synchronous machine parameters.
2. Table 6.4 Load parameters.
3. Table 6.5 STATCOM parameters.
4. Table 6.6 Computed STATCOMs variables by the power flow solution.
5. Table 6.7 Initial values of the STATCOM variables for the dynamic simulation.
6. Table 6.8 VSC‐HVDC parameters.
7. Table 6.9 VSC‐HVDC variables for the RMS‐type model and Simulink model.
8. Table 6.10 VSC‐HVDC parameters.
9. Table 6.11 VSC‐HVDC results given by the power flow solution.
10. Table 6.12 Initial VSC‐HVDC's control variables for the dynamic simulation.
11. Table 6.13 Parameters of the VSC‐HVDC link with frequency regulation capabilitie...
12. Table 6.14 VSC‐HVDC results given by the power flow solution.
13. Table 6.15 Different gains for the frequency controller.
14. Table 6.16 Parameters of the three‐terminal VSC‐HVDC link.
Chapter 7
1. Table 7.1 Main parameters of the coupling transformers.
2. Table 7.2 Electric parameters of the different grids.
3. Table 7.3 Parameters of the inner control loop for each terminal.
4. Table 7.4 Parameters of the DC voltage control loop for each terminal.

List of Illustrations

Chapter 1
1. Figure 1.1 Flexible transmission system with renewable energy sources.
2. Figure 1.2 (a) An SVC (©MPCE, 2017) and (b) its equivalent circuit representati...
3. Figure 1.3 (a) A STATCOM (©MPCE, 2017) and (b) its equivalent circuit represent...
4. Figure 1.4 Static V‐I characteristics of the VSC and the STATCOM.
5. Figure 1.5 SSSC schematic representation (©MPCE, 2017).
6. Figure 1.6 The most popular VSC‐based equipment, placed, clockwise, in the orde...
7. Figure 1.7 Two CSC‐HVDC links: (a) back‐to‐back, monopolar HVDC; (b) point‐to‐p...
8. Figure 1.8 Point‐to‐point, bipolar VSC‐HVDC system.
9. Figure 1.9 Radial, bipolar VSC‐HVDC system with tappings.
10. Figure 1.10 Four‐terminal VSC‐HVDC system.
11. Figure 1.11 AC power transmission reinforcement/conversion using DC technology:...
12. Figure 1.12 Symmetrical transmission system with midpoint dynamic shunt compens...
13. Figure 1.13 Power‐angle characteristic for the transmission system shown in Fig...
14. Figure 1.14 Dynamic SVC and STATCOM simplified representations: (a) schematic r...
15. Figure 1.15 Fault ride‐through capability of the STATCOM: (a) voltage performan...
16. Figure 1.16 An application of the equal area criterion used to illustrate the s...
17. Figure 1.17 Structure of a BESS.
18. Figure 1.18 (a) A conventional turbine‐governor control of a synchronous genera...
19. Figure 1.19 Test circuit to assess the frequency response of a BESS.
20. Figure 1.20 Frequency response of the BESS in the transmission circuit in Figur...
21. Figure 1.21 Frequency response of the BESS in the transmission circuit in Figur...
22. Figure 1.22 Schematic description of (a) FSIG, (b) DFIG and (c) PMSG with fully...
23. Figure 1.23 Fault ride‐through capability tested for a (a) FSIG‐based wind farm...
24. Figure 1.24 Structure of a PV generator.
25. Figure 1.25 Structure of a PV generator with storage.
26. Figure 1.26 Power responses of (a) PV generator with varying solar irradiance c...
27. Figure 1.27 Upstream PQ disturbances and actions.
28. Figure 1.28 Equivalent circuit of a shielded sensitive load against upstream sh...
29. Figure 1.29 RMS voltage response at Node 2 of Figure 1.28 when a three‐phase...
30. Figure 1.30 Distribution feeders with enhanced functionality with the use of po...
31. Figure 1.31 (a) Example of 1 kV AC distribution feeders and (b) LVDC bipoles in...
32. Figure 1.32 A DC‐DC converter based on VSCs (©MPCE, 2017).
33. Figure 1.33 Structure of a DC microgrid (©PSCC, 2016).
34. Figure 1.34 Functional block diagram of the elements in a phasor measurement un...
Chapter 2
1. Figure 2.1 Electronic symbols of the most popular semiconductor switches.
2. Figure 2.2 Compound symbols. (a) GTO with series diode. One limitation of the G...
3. Figure 2.3 Diode (^©Wiley, 2002), (a) electrical symbol; (b) ideal i‐v...
4. Figure 2.4 Diode reverse‐recovery time (^©Wiley, 2002).
5. Figure 2.5 Thyristor (a) electrical symbol of the SCR; (b) ideal i‐v char...
6. Figure 2.6 Bipolar transistor (NPN) (^©Wiley, 2002) (a) electrical symbol; ...
7. Figure 2.7 N‐channel MOSFET (©Wiley, 2002) (a) electrical symbol; (b) ideal i‐v...
8. Figure 2.8 An IGBT (^©Wiley, 2002) (a) electrical symbol; (b) ideal i‐v...
9. Figure 2.9 A GTO (^©Wiley, 2002) (a) electrical symbol; (b) ideal i‐v
10. Figure 2.10 An MCT (^©Wiley, 2002) (a) N‐channel MCT electrical symbol; (b)...
11. Figure 2.11 Single‐phase half‐bridge VSC.
12. Figure 2.12 PWM method for a half‐bridge VSC (^©Wiley, 2002), (a) modulatin...
13. Figure 2.13 PWM scheme operating in the overmodulation region, (a) modulating a...
14. Figure 2.14 Normalized amplitude of fundamental component of the output voltage...
15. Figure 2.15 Square‐wave operation of the VSC, (a) output voltage of the VSC v _o (...
16. Figure 2.16 Single‐phase full‐bridge VSC.
17. Figure 2.17 PWM with bipolar switching for a full‐bridge VSC (^©Wiley, 2002...
18. Figure 2.18 PWM with unipolar switching for a full‐bridge VSC (^©Wiley, 200...
19. Figure 2.19 Waveforms obtained in the VSC using the phase‐shift control (^©
20. Figure 2.20 Normalized harmonic components of the output voltage (from h = 1...
21. Figure 2.21 Three‐phase two‐level VSC.
22. Figure 2.22 PWM process for a three‐phase VSC (^©Wiley, 2002), (a) modulati...
23. Figure 2.23 Normalized fundamental‐component amplitude of the line‐to‐line outp...
24. Figure 2.24 Square‐wave operation of a three‐phase VSC, (a) output voltage v _AN ;...
25. Figure 2.25 Three‐level three‐phase NPC VSC.
26. Figure 2.26 Output voltage of a three‐level NPC VSC using square‐wave operation...
27. Figure 2.27 Five‐level NPC configuration.
28. Figure 2.28 Three‐level three‐phase FC VSC.
29. Figure 2.29 Five‐level FC configuration.
30. Figure 2.30 Phase A of a seven‐level cascaded H‐bridge VSC.
31. Figure 2.31 Output voltage of a seven‐level cascaded H‐bridge VSC using the pha...
32. Figure 2.32 SPWM for the three‐level three‐phase FC VSC for ma = 0.8...
33. Figure 2.33 Two SMs connected in series.
34. Figure 2.34 Schematic representation of a three‐phase MMC.
35. Figure 2.35 Schematic representation of a three‐phase hybrid VSC.
Chapter 3
1. Figure 3.1 LTC representation, with the per‐unit impedance in the primary side...
2. Figure 3.2 Current and power balances in bus l.
3. Figure 3.3 Flow diagram for the Newton‐Raphson power flow in rectangular coordi...
4. Figure 3.4 Convergence characteristic of the Newton‐Raphson method.
5. Figure 3.5 (a) VSC schematic representation, (b) VSC equivalent circuit..
6. Figure 3.6 VSC station i with ancillary elements connected to node k through a ...
7. Figure 3.7 VSC providing voltage support at Node 2.
8. Figure 3.8 Test network uses the same circuit parameters as in Test Case 1 but ...
9. Figure 3.9 Test network with a battery load on its DC bus.
10. Figure 3.10 Upgraded network used in Test Case 1 to include the LTC transformer...
11. Figure 3.11 Two STATCOM supplying reactive power at buses 10 and 24 of the modi...
12. Figure 3.12 Monopolar VSC‐HVDC schematic representation: (a) back-to-back circu...
13. Figure 3.13 VSC‐DC cable schematic representation..
14. Figure 3.14 Point‐to‐point VSC‐HVDC linking two equivalent AC subsystems.
15. Figure 3.15 Back‐to‐back VSC‐HVDC linking two equivalent AC subsystems.
16. Figure 3.16 One point‐to‐point VSC‐HVDC system linking buses 4 and 6 in the mod...
17. Figure 3.17 A three‐terminal VSC‐HVDC system..
18. Figure 3.18 Flow diagram of a true unified solution of the multi‐terminal VSC‐H...
19. Figure 3.19 Multi‐terminal VSC‐HVDC system with a DC ring..
Chapter 4
1. Figure 4.1 Transmission system planning framework.
2. Figure 4.2 A contrived power system diagram.
3. Figure 4.3 IEEE 30‐bus test results: nodal voltage magnitudes.
4. Figure 4.4 Generators' power outputs at optimum.
5. Figure 4.5 Network model for AC‐DC unified formulations.
6. Figure 4.6 VSC converter station with its unified equivalent circuit.
7. Figure 4.7 Power balances in VSC‐HVDC links: (a) point‐to‐point, (b) back‐to‐ba...
8. Figure 4.8 The VSC‐HVDC link for a point‐to‐point configuration with the DC lin...
9. Figure 4.9 Hybrid AC‐DC network model with the full set of coupled AC‐DC constr...
10. Figure 4.10 Multi‐terminal VSC‐HVDC system with n‐VSC stations.
11. Figure 4.11 Modified five‐bus power system [3] to include a tree‐terminal VS...
12. Figure 4.12 DC network voltage profile.
Chapter 5
1. Figure 5.1 State estimation process.
2. Figure 5.2 Nodal power balances at a generic node i.
3. Figure 5.3 Phase reference selection.
4. Figure 5.4 Tutorial network for WLS‐SE.
5. Figure 5.5 Schematic representation of the VSC and its coupling transformer.
6. Figure 5.6 Representation of the VSC model in state estimation.
7. Figure 5.7 Tutorial network including one STATCOM.
8. Figure 5.8 State estimation UPFC model.
9. Figure 5.9 Tutorial network including a UPFC.
10. Figure 5.10 VSC‐HVDC model.
11. Figure 5.11 Tutorial network including VSC‐HVDC.
12. Figure 5.12 Multi‐terminal network.
13. Figure 5.13 Multi‐terminal DC network and coupling transformers.
Chapter 6
1. Figure 6.1 Phasor diagram of the synchronous generator: (a) transient state, (...
2. Figure 6.2 Simplified IEEE speed governor model for a (a) steam turbine, (b) hy...
3. Figure 6.3 Simplified IEEE steam‐turbine model.
4. Figure 6.4 IEEE hydro‐turbine model.
5. Figure 6.5 Simplified IEEE‐type I AVR model.
6. Figure 6.6 New England test system.
7. Figure 6.7 Synchronous generators' angular speed.
8. Figure 6.8Figure 6.8 Active power flow behaviour in selected transmission lines...
9. Figure 6.9 Reactive power flow behaviour in selected transmission lines.
10. Figure 6.10 Voltage performance at different nodes of the network.
11. Figure 6.11 A STATCOM and its control variables.
12. Figure 6.12 DC voltage controller.
13. Figure 6.13 DC power controller for the VSC's DC side.
14. Figure 6.14 AC‐bus voltage controller.
15. Figure 6.15 Test system used to incorporate two STATCOMs.
16. Figure 6.16 Reactive power provided by the STATCOMs.
17. Figure 6.17 Voltage performance at the VSCs' AC network nodes.
18. Figure 6.18 Voltage performance at several nodes of the network.
19. Figure 6.19 STATCOM's DC‐bus voltages.
20. Figure 6.20 STATCOM's DC current.
21. Figure 6.21 STATCOM's angle γ.
22. Figure 6.22 Total active power losses incurred by the STATCOMs.
23. Figure 6.23 Dynamic behaviour of the modulation index of the STATCOMs.
24. Figure 6.24 DC‐bus voltages for different ratings of the capacitors.
25. Figure 6.25 Modulation ratios for different ratings of the capacitors.
26. Figure 6.26 Reactive power provided by the VSCs for different ratings of the ca...
27. Figure 6.27 Dynamic model of the VSC‐HVDC link with control variables.
28. Figure 6.28 VSC‐HVDC dynamic controller for the DC voltage.
29. Figure 6.29 DC power transfer controller of the VSC‐HVDC link model.
30. Figure 6.30 AC bus voltage controllers. (a) Rectifier station and (b) inverter ...
31. Figure 6.31 Test system used to validate the VSC‐HVDC model.
32. Figure 6.32 DC voltage performance for the RMS-type and Simulink models.
33. Figure 6.33 DC power performance for the RMS-type and Simulink models.
34. Figure 6.34 Modulation indices performance for the RMS-type and Simulink models...
35. Figure 6.35 Modified New England test system to incorporate a VSC‐HVDC link.
36. Figure 6.36 Voltage performance at different nodes of the network.
37. Figure 6.37 Dynamic behaviour of the converters' modulation index.
38. Figure 6.38 Reactive power generated by the HVDC link.
39. Figure 6.39 DC current behaviour of the rectifier and the inverter.
40. Figure 6.40 Voltage behaviour in the DC link.
41. Figure 6.41 VSC‐HVDC's AC active powers and DC power transfer behaviour.
42. Figure 6.42 Dynamic performance of various angles involved in the VSC‐HVDC link...
43. Figure 6.43 Frequency controller of the VSC‐HVDC.
44. Figure 6.44 Dynamic behaviour of the frequency at the inverter's AC terminal an...
45. Figure 6.45 Dynamic performance of the DC voltages and modulation indices. (a) ...
46. Figure 6.46 VSC‐HVDC link feeding into a low‐inertia AC network.
47. Figure 6.47 Voltage behaviour in the low‐inertia AC network.
48. Figure 6.48 Frequency behaviour in the low‐inertia AC network.
49. Figure 6.49 Performance of VSC‐HVDC link's DC and AC powers.
50. Figure 6.50 Dynamic performances of γ _R and I _DCI.
51. Figure 6.51 Performance of the DC voltages and modulation indices.
52. Figure 6.52 Frequency in the low‐inertia network and DC voltage of the inverter...
53. Figure 6.53 Representation of a three‐terminal VSC‐HVDC link with its control v...
54. Figure 6.54 Dynamic controller for the DC voltage of the slack converter VSC_Sla...
55. Figure 6.55 (a) DC power controller of the station VSC_Psch. (b) Frequency cont...
56. Figure 6.56 Modulation index controllers of the three‐terminal HVDC system.
57. Figure 6.57 Three‐terminal VSC‐HVDC link used to carry out the validation test.
58. Figure 6.58 DC voltages of the VSC units comprising the three‐terminal VSC‐HVDC...
59. Figure 6.59 DC power behaviour at the DC bus of the three VSC stations. (a) EMT...
60. Figure 6.60 Modulation ratio of the three VSC stations. (a) EMT‐type model. (b)...
61. Figure 6.61 DC voltages and power flows in the DC grid.
62. Figure 6.62 Modulation ratio of the VSCs and frequency of the passive grids fed...
63. Figure 6.63 AC voltages and AC powers during the three‐phase fault.
64. Figure 6.64 Voltages and powers in the DC network during the three‐phase fault.
65. Figure 6.65 Modulation ratio of the converters and reactive power injected by V...
Chapter 7
1. Figure 7.1 Basic scheme of a STATCOM connected to a distribution system.
2. Figure 7.2 One‐line equivalent circuit of the STATCOM connected at PCC.
3. Figure 7.3 Control system scheme for the DSTATCOM case.
4. Figure 7.4 Pole location for the inner control loop.
5. Figure 7.5 Time response of the inner loop obtained for a step reference.
6. Figure 7.6 Location of the poles for DC voltage control loop.
7. Figure 7.7 Time response of the DC voltage control loop for a step reference.
8. Figure 7.8 Circuit of a VSC‐based STATCOM implemented in PSCAD/EMTDC.
9. Figure 7.9 Implementation of the two‐level VSC using IGBTs and diodes from the ...
10. Figure 7.10 Inner control loop (current controllers) for the STATCOM implemente...
11. Figure 7.11 Control system of the voltage of the DC capacitor implem...
12. Figure 7.12 Control system of the PCC voltage implemented in PSCAD/EMTDC.
13. Figure 7.13 Sinusoidal PWM modulation scheme for two‐level VSC of the STATCOM i...
14. Figure 7.14 RMS voltage at the PCC in p.u.
15. Figure 7.15 Line‐to‐neutral voltage at the PCC in kV.
16. Figure 7.16 STATCOM waveforms: (a) d and q components of the current injected i...
17. Figure 7.17 DC capacitor voltage in kV.
18. Figure 7.18 Topology of a three‐phase, three‐level flying capacitor converter.
19. Figure 7.19 STATCOM based on the three‐level FC converter implemented in PSCAD/...
20. Figure 7.20 Three‐level flying capacitor converter implemented in PSCAD/EMTDC.
21. Figure 7.21 Voltage‐balance method for the flying capacitors implemented in PSC...
22. Figure 7.22 Phase‐shifted PWM modulation scheme for the three‐level FC converte...
23. Figure 7.23 RMS voltage at the PCC obtained with the three‐level FC converter.
24. Figure 7.24 Instantaneous line‐to‐neutral voltage at the PCC.
25. Figure 7.25 Detail of the spectrum of the line‐to‐neutral voltage at the PCC wi...
26. Figure 7.26 Line‐to‐line output voltage of the VSC obtained with: (a) conventio...
27. Figure 7.27 Waveforms of the STATCOM obtained with the three‐level FC converter...
28. Figure 7.28 Voltage of the DC capacitor in kV.
29. Figure 7.29 Voltages of the three flying capacitors: (a) phase A, (b) phase B, ...
30. Figure 7.30 Basic scheme of an HVDC system.
31. Figure 7.31 Control system for terminal 1 of the HVDC.
32. Figure 7.32 Control system for terminal 2 of the HVDC.
33. Figure 7.33 Two‐terminal HVDC system implemented in PSCAD/EMTDC.
34. Figure 7.34 Main electrical magnitudes of grid 1: (a) RMS voltage at PCC, (b) a...
35. Figure 7.35 Main electrical magnitudes of grid 2: (a) RMS voltage at PCC, (b) a...
36. Figure 7.36 Detail of the PCC voltages for the time interval 0.6 s < t < 0.8 s:...
37. Figure 7.37 Detail of the PCC voltages for the time interval 0.6 s < t < 0.8 s:...
38. Figure 7.38 Voltages of the three flying capacitors of terminal 1: (a) phase A,...
39. Figure 7.39 Voltages of the three flying capacitors of terminal 2: (a) phase A,...
40. Figure 7.40 Scheme of a multi‐terminal HVDC system.
41. Figure 7.41 Control scheme of a terminal with active‐power reference.
42. Figure 7.42 Four‐terminal HVDC system implemented in PSCAD/EMTDC.
43. Figure 7.43 Measured active powers of the four terminals: (a) active power of t...
44. Figure 7.44 Voltage at the DC side of each terminal: (a) DC voltage of terminal...
45. Figure 7.45 Electrical magnitudes of grid 1: (a) RMS voltage at PCC, (b) reacti...
46. Figure 7.46 Electrical magnitudes of grid 2: (a) RMS voltage at PCC, (b) reacti...
47. Figure 7.47 Electrical magnitudes of grid 3: (a) RMS voltage at PCC,...
48. Figure 7.48 Electrical magnitudes of grid 4: (a) RMS voltage at PCC, (b) reacti...
49. Figure 7.49 d and q components of the currents injected by: (a) terminal 1, (b)...
50. Figure 7.50 Voltages of the three flying capacitors of terminal 1: (a) phase A,...
51. Figure 7.51 Voltages of the three flying capacitors of terminal 2: (...
52. Figure 7.52 Voltages of the three flying capacitors of terminal 3: (...
53. Figure 7.53 Voltages of the three flying capacitors of terminal 4: (a) phase A,...

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Library of Congress Cataloging‐in‐Publication Data

Names: Acha, Enrique, author.

Title: VSC-FACTS-HVDC : analysis, modelling and simulation in power

grids / Professor Dr Enrique Acha, Tampere University,

Tampere, Finland, Dr Pedro Roncero-Sanchez, Universidad de Castilla-La

Mancha, Ciudad Real, Espana Dr Antonio de la Villa Jan, Universidad de

Sevilla, Sevilla, Espana, Dr Luis M Castro, Universidad Nacional

Autonoma de Mexico (UNAM), Mexico City, Mexico, Dr Behzad Kazemtabrizi,

Durham University, Durham, England.

Description: First edition. | Hoboken, NJ : John Wiley & Sons Ltd, 2019. |

Includes bibliographical references and index. |

Identifiers: LCCN 2018051883 (print) | LCCN 2018055480 (ebook) | ISBN

9781118965801 (Adobe PDF) | ISBN 9781118965849 (ePub) | ISBN 9781119973980

(hardcover)

Subjects: LCSH: Smart power grids. | Flexible AC transmission systems. |

Electric power transmission--Direct current.

Classification: LCC TK3105 (ebook) | LCC TK3105 .A25 2019 (print) | DDC

621.319-dc23

LC record available at https://lccn.loc.gov/2018051883

Cover Design: Wiley

Preface

Electrical power transmission using high voltage direct current (HVDC) is a well‐established practice. There is common agreement that the world's first commercial HVDC link was the Gotland link, built in 1954, designed to carry undersea power from the east coast of Sweden to the Island of Gotland, some 90 km away. The original design was rated at 20 MW, 100 kV and used mercury‐arc valve converters. Its power and voltage ratings were increased in 1970 to 30 MW and 150 kV, respectively. Solid‐state electronic valves were used for the first time in the upgrade, with the new type of valve, termed silicon‐controlled rectifier (SCR) or thyristor, being connected in series with the mercury‐arc valves. This kind of HVDC link, and ancillary technology, has been magnificently described in earlier treatises by Adamson and Hingorani, Kimbark, Uhlmann and Arrillaga.

By the turn of the second millennium, there had been 56 HVDC links of various topologies and capacities built around the world: 22 in North and South America, 14 in Europe, 2 in Africa and 18 in Australasia. They ranged from the small, 25 MW, Corsica tapping of the Sardinia–Italy HVDC link to the large, 6300 MW HVDC link, a part of the awesome Itaipu hydro‐electric development on the Brazil–Paraguay border. At the time, three other large capacity HVDC links were at the planning/construction stage in China, to transport hydro‐electric power from the Three Gorges to the east and southeast of the country, each spanning distances of around 1000 km, rated at 3000 MW – the Three Gorges is a gigantic hydro resource in central China, with an estimated power capacity of 22 MW. Heretofore all the HVDC links in the world had employed either mercury‐arc rectifier or thyristor bridges and phase control to enable the rectification/inversion process. These converters are said to be line commutated and when applied to HVDC transmission are termed LCC‐HVDC converters. The LCC‐HVDC technology has continued its upward trend and five other high‐power, high‐voltage, long‐distance DC links have been built in China since 2010. The most recent LCC‐HVDC in operation was commissioned in 2012; it is the Jinping‐Sunan link in East China, rated at 7200 MW and ±800 kV, spanning a distance of 2100 km.

In LCC‐HVDC systems the current is unidirectional, flowing from the rectifier to the inverter stations. Such a fundamental physical constraint in thyristor‐based converters limits applicability to the following HVDC system topologies: point‐to‐point, back‐to‐back and radial, multi‐terminal links. In this context, the conventional, or classical, HVDC transmission technology is not a meshed grid maker; rather, its role has been to interconnect AC systems where an AC interconnection is deemed too expensive or technically infeasible.

However, one has to bear in mind that nowadays, in many situations, robust AC interconnections may be achieved more economically using one or more of the options afforded by the Flexible Alternating Current Transmission Systems (FACTS) technology, an array of power electronics‐based equipment and control methods which became commercially available in around 1990. It is widely acknowledged that N.G. Hingorani and L. Gyugyi stand out prominently as the intellectual driving force behind the development of the FACTS technology.

The main aim of the FACTS technology is to enable almost instantaneous control of the nodal voltages and power flows in the vicinity of where the FACTS equipment has been installed. We should not forget that power flows over an AC line can be manipulated very effectively by controlling the line impedance, or the phase angles, or the voltages, or a combination of these parameters up to the thermal rating of the equipment. A key element of the FACTS technology is the so‐called static compensator (STATCOM), which, in the parlance of a power electronics engineer, is a voltage source converter (VSC) and serves the purpose of injecting/absorbing reactive power to enable tight voltage magnitude regulation at its point of connection with the AC power grid. The advent of the STATCOM in the mid‐1990s was made possible by the development of power semiconductor valves with forced turn‐off capabilities, like the gate turn‐off (GTO) first and the insulated gate bi‐polar transistor (IGBT) soon afterwards. GTOs are like thyristors, which can be turned on by a positive gate pulse when the anode–cathode voltage is positive, and, unlike thyristors, can be turned off by a negative gate pulse. This turn‐off feature led to new circuit concepts and methods such as self‐commutated, pulse‐width‐modulated, soft‐switching, voltage‐driven and multi‐level converters. These circuits may be made to operate at higher internal switching frequencies than the fundamental level, at several hundreds of hertz, which, in turn, reduces low‐order harmonics and allows operation at unity and leading power factors. This contrasts sharply with what can be achieved with the normal thyristors.

Advances in the design of the power GTO and its applications in Japan and the USA continued apace by virtue of strategic collaborative R&D projects funded by utilities, manufacturers and governments. In Japan there was a target to develop 300 MW GTO converters for back‐to‐back HVDC interconnections, while in the USA a 100 MVAR GTO‐STATCOM was commissioned in 1996 for the Tennessee Valley Authority. Meanwhile, similar efforts were conducted in Europe in the design of the power IGBT. It is reported that on 10 March 1997, power was first transmitted between Hellsjön and Grängesberg in central Sweden using an HVDC link employing IGBT converters driven by pulse‐width‐modulation (PWM) control. The link is 10 km long, rated at 3 MW, 10 kV and is used to test new components for HVDC.

In spite of the great many technical advantages and operational flexibility of the VSC compared with the thyristor bridge, the GTO‐based converters did not make inroads into HVDC applications because of the much higher power losses and cost of GTOs compared with thyristors. A further reason is that the ratings of GTOs are low compared with those of thyristors. All this conspired to make VSC‐HVDC installations expensive. The impasse was broken with the use of IGBT valves, which exhibit lower switching losses than GTO valves, and decreasing manufacturing costs. Three years after the commissioning of the Hellsjön‐Grängesberg, four other VSC‐HVDC links had been commissioned in very distant parts of the world: a 50 MVA DC link in the emblematic Island of Gotland to evacuate wind power, an 8 MVA DC link in West Denmark to link an offshore wind farm, the 180 MVA Directlink or Terranora project in Australia for power export from New South Wales into Southern Queensland, and a 36 MVA DC link for system interconnection on the Mexican–Texan border. The undersea Estlink 1, linking the Estonian and Finnish power grids, was commissioned in 2006, rated at 350 MW and using VSC stations. Intriguingly, the Estlink 2, rated at 650 MW and commissioned in 2014, uses the classical thyristor‐converter technology.

It should be noted that all the VSC stations used in HVDC projects until 2010 had been of the so‐called two‐ and three‐level power converters. In around 2008, a new breed of VSCs was introduced into the market, the modular multilevel converters (MMCs), which switch at low frequencies, yield minimum harmonic production and have power losses just above those of the classical thyristor‐based HVDC converters. Equally important is the fact that it has been possible to increase the capacity of VSC‐HVDC links using MMC, by a very considerable margin, say 1000 MW per circuit, such as in the INELFE DC link between Baixas, France, and Santa Llogaia, Spain. Two identical circuits make up for a transmission capacity of 2000 MW. The link was commissioned at the end of 2013. Note that this application comes into the realm of bulk power transmission and is already eating into the niche area of classical thyristor‐based HVDC technology, namely asynchronous bulk power transmission, an area until recently thought to be unassailable. The Trans Bay Cable link was the first MMC VSC‐HVDC, commissioned in 2010, transmitting up to 400 MW of power from Pittsburg in the East Bay to Potrero Hill in the centre of San Francisco, California.

Furthermore, there are new application areas in which VSC‐HVDC transmission does not seem to have a competitor in sight – the connection of wind sites lying more than 70 km away from the shore is one of the most obvious applications, but there are a few others. For instance, the connection of microgrids with insufficient local generation and little or no inertia (inertia‐less power grids), the electricity supply of oil and gas rigs in deep waters, the infeed of densely populated urban centres with power grids already experiencing high short‐circuit ratios. Moreover, the unassailable characteristic of the HVDC transmission using the VSC technology is that it is a natural enabler of meshed DC power grids, with such a high level of operational flexibility, reliability and efficiency that one day may surpass that of the meshed AC power grids. To get to this point, though, further technological breakthroughs are still awaited in the ancillary areas of DC circuit breaker technology and high‐temperature superconductor cables and circuit breakers, as well as more affordable VSCs.

VSC-FACTS-HVDC

Analysis, Modelling and Simulation in Power Grids

Copyright

Dedication

Preface