2018 International High Voltage Direct Current Conference in Korea October 30(Tue) - November 2(Fri) 2018, Gwangju, Korea

http://hvdc2018.org

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Time table

Date Plan Time Topic Speaker Co-chair/Moderator Oct.30 Welcome Party 18:00 - 20:00 Event with BIXPO 2018 Opening Ceremony 13:30 - 13:40 Chairman KOO, Ja-Yoon Opening Welcome Address Chair: Ceremony 13:40 - 13:50 Congratulation Address CESS President Dr. KIM, Byung-Geol 13:50 - 14:00 Congratulation Address KEPCO President Plenary session 1: Arman Hassanpoor 14:00 - 14:40 On Development of VSCs for HVDC Applications (ABB) Plenary session 2: Oct.31 14:40 - 15:20 Shawn SJ.Chen Introductionof China HVDC Development (NR Electric Co., Ltd) Co-chair: Plenary 15:20 - 15:30 Coffee Break Arman Hassanpoor Session Plenary session 3: Prof. KIM, Seong-Min 15:30 - 16:10 Introduction of KEPCO’s HVDC East-West Power KIM, Jong-Hwa Grid Project (KEPCO) Plenary session 4: Prof. Jose ANTONIO JARDINI 16:10-16:50 The Brazilian Interconnected Transmission System (ERUSP University) Oral Session 1: Testing experiences on extruded cable systems Giacomo Tronconi 09:10-09:40 up to 525kVdc in the first third party worldwide (CESI) laboratory Oral Session 2: An optimal Converter Transformer and Valves Yogesh Gupta (GE T&D INDIA Ltd) 09:40 - 10:10 arrangement & Challenges in Open Circuit Test for B Srikanta Achary (GE T&D INDIA Ltd) Parallel Bipole LCC HVDC System with its Mitigation 10:10 - 10:20 Coffee Break Co-chair: Conference Oral Session 3: Mats Andersson 10:20 - 10:50 Overvoltages experienced by extruded cables in Mansoor Asif Prof. KIM, Seong-Min LCC and VSC HVDC systems (Hanyang University) Oral Session 4: 10:50 - 11:20 Research on the Control Factors of Polarity He Yan (Northwest Electric Power Distance for ±1100kV Transmission Line Design Institute Co., Ltd) Oral Session 5: 11:20-11:50 Dynamic and steady state performance of a Mats Andersson 2-terminal Hybrid HVDC transmission (ABB) Nov.01 11:50 - 14:00 Lunch Chairman CHANG, Jae-Won 14:00 - 14:10 Opennig Ceremony (KNC of CIGRE) Super-Grid Forum session 1: 14:10 - 14:40 Strategy for Northeast Asia Power System Philippe LIENHART Interconnection EDF Technical Assistance to Mongolia (EDF) Super-Grid Forum session 2: Prof. GILSOO JANG 14:40-15:00 Northeast Asia Super Grid Current Status & Future (Korea University) Prospects Co-chair: Super Grid Super-Grid Forum session 3: Romain Zissler Philippe LIENHART Forum 15:00 - 15:20 Second Report Summary of Asia International Grid Dr. LEE, Dong-Il Connection Study Group (Renewable Energy Institute) Super-Grid Forum session 4: KIM, Seong-Weon 15:20 - 15:40 HVDC cable Present & Future & NEA Super Grid (KEPCO) Super-Grid Forum session 5: João BGF da Silva 15:40 - 16:10 Update on Latin America Super Grids (Paranaíba Transmissora de Energia) 16:10 - 16:20 Rearrange Time 16:20 - 16:50 QnA 7:00 Move to the DMZ 12:00 - 13:00 Lunch 13:00 - 15:30 DMZ Tour Move to the Gyungin Construction Headquarters of Nov.02 Technical Tour 15:30 - 17:00 KEPCO Visit the Gyungin Construction Headquarters of 17:00 - 20:00 KEPCO/ Farewell Party 20:00 - 21:00 Move to the hotel Nov.03 10:00 Incheon Airport limousine bus guide Conference Oral Session 1

Testing experiences on extruded cable systems up to 525kVdc in the first third party worldwide laboratory

Giacomo Tronconi (CESI) 2018 International High Voltage Direct Current Conference in Korea LIMITED USE LIMITED – CONFIDENTIAL

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14 15 Conference Oral Session 2

An optimal Converter Transformer and Valves arrangement & Challenges in Open Circuit Test for Parallel Bipole LCC HVDC System with its Mitigation

Yogesh Gupta(GE T&D INDIA Ltd) B Srikanta Achary(GE T&D INDIA Ltd) 2018 International High Voltage Direct Current Conference in Korea

An Optimal Converter Transformer and Valves Arrangement in LCC-HVDC Converter Station

October 10, 2018

Authors

Yogesh Gupta1 (Lead Author), Anil Kumar Upadhyay1 (Co-Author), Amit Kumar1 (Co-Author) 1HVDC, Centre of Excellence, Noida, India GE T&D India Ltd.

Gearoid O’hEidhin2 (Co-Author) 2 HVDC, Centre of Excellence, Stafford, UK GE, UK GRID Solution Ltd.

19 2018 International High Voltage Direct Current Conference in Korea

Introduction – A Brief Note on Presentation

All figures and values shown above are approximate figures and values and are not 5 © 2018, General Electric Company. All rights reserved. definite in nature. © 2018, General Electric Company. All rights reserved.

Table of Contents –

• Introduction – A Brief Note on Presentation • • Converter Transformer Arrangement • Valves Arrangement • • Conventional Arrangement • • Optimal Arrangement • • Conclusion

•

All figures and values shown above are approximate figures © 2018, General Electric Company. All rights reserved. 4 © 2018, General Electric Company. All rights reserved. and values and are not definite in nature.

20 21 2018 International High Voltage Direct Current Conference in Korea

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26 27 2018 International High Voltage Direct Current Conference in Korea

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28 29 2018 International High Voltage Direct Current Conference in Korea

Thank You !!

All figures and values shown above are approximate figures and values and are not definite in nature. © 2018, General Electric Company. All rights reserved. © 2018, General Electric Company. All rights reserved. © 2018, General Electric Company. All rights reserved.

30 31 2018 International High Voltage Direct Current Conference in Korea

Challenges in Open Circuit Test for Parallel Bipole LCC HVDC System 1. Introduction : A Brief on and its Mitigation Presentation

B Srikanta Achary, Firoz Ahmed HVDC, Centre of Excellence, Noida, India GE T&D India Ltd.

October 25, 2018 Confidential. Not to be copied, distributed, or reproduced without prior approval. ©2018, General Electric Company. All rights reserved. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in ©2018, General Electric Company. All rights reserved. nature

CONTENTS 1. INTRODUCTION

• High Voltage Direct Current(HVDC) transmission is a way to feed electricity to remote corners of the world. 1. Introduction : A Brief on Presentation • It is popular due to its wide economic benefit and reliable power evacuation, cutting edge controllability and proven technology . 2. System Description • LCC based HVDC can operate in various operating modes like monopole(MP), bipole(BP) with ground and/or metallic return and their combinations, helping to achieve maximum availability of HVDC link throughout the year[1]. 3. OCT and Challenges • Large HVDC projects usually consist of several poles/bipole operating in parallel, which are typically commissioned in stages staggered power generation, unavailability of loads, bring forward revenue generation, etc. 4. Conclusion • These systems may operate in parallel with separate or shared DC transmission line to accommodate the need of bulk power flow and transmission asset financial model. References

Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 2 All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 4

32 33 2018 International High Voltage Direct Current Conference in Korea

1. INTRODUCTION 2. SYSTEM DESCRIPTION P1XHVCB Line 1 P1YHVCB • 6000 MW ± 800 kV LCC 1

• Prior energization of a Pole, its insulation parameter & complex gate circuitry firing 1 based Parallel Bipole HVDC DC DC Filter Filter Pole several hundreds of Thyristors need to be checked thoroughly for appropriate Pole system [2]. functioning. Bipole 1

P1XCB1 P12XCB2 P1YCB1 P12XCB4 DMR Line P12YCB4 • Bipole 1 is running in Stage • Open Circuit Test(OCT) of converter station helps in meeting such requirements.

1 & Bipole 2 is to be 3

XCB

P2XCB1 12 P2YCB1 commissioned in Stage 2. P 2 • OCT of upcoming pole for a Parallel Bipole HVDC sharing a common DC line will 2 DC DC Filter Filter

Pole have many additional challenges as follows: Pole • Poles 1 & 3 will share Line 1 Line 2 in parallel, similarly Poles 2 P2XHVCB P2YHVCB  Complex Switchgear Arrangement & 4 will share Line 2 in P3XHVCB P3YHVCB SIDE X SIDE Y  Voltage Order Adjustment of OCT Pole x parallel.  Special Requirement of High Voltage Switching arrangement for DC Side 3 3 DC DC Filter Filter Pole  Protection Strategy and Fault Cases Pole • Dedicated metallic return

• This paper attempts to discuss above challenges and their mitigation procedure with (DMR) line as common x x x P3XCB1 P34XCB2 P3YCB1 simulation results in PSCAD/EMTDC Software. return. P34XCB4 P34YCB4

x 3 x XCB P4XCB1 x P4YCB1 • AC System: 400kV, 50Hz 34

P Bipole 2 4 4 DC DC Filter Filter Pole Pole • Side Y of both Bipoles solidly

x x

grounded for reference. P4XHVCB P4YHVCB Energized 6000 MW ± 800 kV LCC based Parallel Bipole HVDC systemIsolated Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 5 All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 7

2. System Description 3. OCT and Challenges

Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in ©2018, General Electric Company. All rights reserved. All figures and values shown above are approximate figures and values and are not definite in ©2018, General Electric Company. All rights reserved. nature nature

34 35 2018 International High Voltage Direct Current Conference in Korea

3. OCT AND CHALLENGES 3.1 Switchgear Arrangement

• OCT mode permits verification of voltage insulation, firing controls and valve- Simulation 1: based electronics of a new pole. Balanced Bipole 1 is running i.e. Pole 1 at 1500MW and +800kV on Line 1. Pole 2 at 1500MW and -800kV on Line 2. Return is through DMR. • Here, poles of Bipole 2 under OCT operate in independent control mode (ICM) [3], which helps switching and protection strategy to have minimal effect on the running • Switchgear arrangement as per Case 1 of Table 1. OCT is performed at Pole 3 Side X with NBG. Bipole 1 and vice versa. • Switchgear arrangement as per Case 3 of Table 1. OCT is performed at Pole 3 Side Y. • Prerequisites and verification of OCT for an upcoming pole shall be as per [4].

Commissioning engineer has to configure DC yard switchgear appropriately. Simulation 2: • Facility shall be provided to the operator to deblock the converter, to change Balanced Bipole 1 is running i.e. Pole 1 at 1500MW and +800kV at Line 1. Pole 2 at voltage order (0 to 800kV) and ramp rate(10 to 100kV/min). 1500MW and -800kV at Line 2. Also Pole 3 running at 1500MW and connected in parallel to Pole 1. Return is through DMR. • During OCT of upcoming pole while the parallel bipole is running, challenges • Switchgear arrangement as per Case 4 of Table 1. OCT is performed at Pole 4 Side X related to equipment specification, control and operation may be encountered. with DMR. • Switchgear arrangement as per Case 5 of Table 1. OCT is performed at Pole 4 Side Y.

Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 9 All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 11

3.1 Switchgear Arrangement 3.1 Switchgear Arrangement Pole 3 Pole 4 Switchgear Arrangement for Pole 1 Pole 2 X side Y Side X side Y Side OCT Pole P3XCB1, P34XCB3 Closed; OCT with 1 Balanced BP Isolated Isolated Isolated P3XHVCB, P3XCB2, P34XCB4 NBG Open P3XCB1, P34XCB4 Closed; OCT with 2 Balanced BP Isolated Isolated Isolated P3XHVCB, P3XCB2, P34XCB3 DMR Open P3YCB1 Closed; 3 Balanced BP Isolated OCT Isolated Isolated P3YHVCB, P3YCB2, P34YCB4 Open P4XCB1, P34XCB3 Closed; 4 Balanced BP Isolated Isolated OCT with NBG Isolated P4XHVCB, P4XCB2, P34XCB4 Open P4XCB1, P34XCB4 Closed; 5 Balanced BP Isolated Isolated OCT with DMR Isolated P4XHVCB, P4XCB2, P34XCB3 Open P4YCB1 Closed; 6 Balanced BP Isolated Isolated Isolated OCT P4YHVCB, P4YCB2, P34YCB4 Open P3XCB1, P34XCB4 Closed; OCT with 7 Unbalanced BP Isolated Isolated Isolated P3XHVCB, P3XCB2, P34XCB3 DMR Open OCT with 8 MP with DMR Isolated Isolated Isolated Isolated Same as Case 2 DMR OCT with 9 Isolated MP With DMR Isolated Isolated Isolated Same as Case 2 DMR 10 MP With DMR Isolated Isolated Isolated OCT with DMR Isolated Same as Case 5 (a) (b) OCT for Pole 3 (a) X Side with NBG, (b) Y side 11 Confidential.Isolated Not to beMP copied, With distributed, DMR or reproducedIsolated without priorIsolated approval. OCT with DMR Isolated Same as Case 5 Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in nature All figures and values shown above are approximate figures and values and are not definite in nature OCT with ©2018, General Electric Company. All rights reserved. 10 ©2018, General Electric Company. All rights reserved. 12 12 Balanced BP Isolated MP With DMR Same as Case 2 DMR

36 37 2018 International High Voltage Direct Current Conference in Korea

3.1 Switchgear Arrangement 3.2 Voltage Order Adjustment

• Case 8 shows OCT for Pole 3 side • Case 9 shows OCT for Pole 3 X while Pole 1 is in monopole side X while Pole 2 is in mode with DMR. monopole mode with DMR.

• To achieve +800 kV across Pole 3, • To achieve +800 kV across Pole voltage order provided to the 4, voltage order provided to the controller shall include LV end - controller shall include LV end - 60kV voltage i.e. +740 kV. 60kV voltage i.e. -860 kV. Line 1 +800 kV -60 kV DMR Line 1 2 DC DC DC DC Filter Fil ter Filter Fil ter Pole Pole

DMR Line Line 2 -60 kV -800 kV SIDE Y SIDE X SIDE Y SIDE X -60 kV +740 kV 3 4 DC +800 kV DC +800 kV Filter Filter Pole Pole

-60 kV (a) (b) -860 kV OCT for Pole 4 (a) X Side with NBG, (b) Y side Voltage Order Adjustment Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 13 All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 15

3.2 Voltage Order Adjustment 3.2 Voltage Order Adjustment Simulation 3 • For Balanced Bipole mode (i.e. cases 1 to 6), no voltage is developed at the LV Simulation 4 • Monopole Pole 1 at 1500MW with DMR • Monopole Pole 2 at 1500MW with end of X side. and +800kV at Line 1. Pole 2 is isolated. DMR and -800kV at Line 2. Pole 1 is

• Switchgear arrangement done as per isolated. • For Unbalanced Bipole mode (i.e. case 7) and monopole mode (i.e. case 8 to Case 8 of Table 1. OCT is performed at • Switchgear arrangement done as 12), significant neutral voltage will be developed. Pole 3 Side X with DMR. per Case 11 of Table 1. OCT is

performed at Pole 4 Side X with • To achieve rated 800kV across the poles, HV pole voltage of OCT Pole needs to Vdc With Voltage Adjustment Vdc With Voltage Adjustment Vdc Without Voltage Adjustment DMR. Vdc Without Voltage Adjustment be adjusted considering LV end voltage. 1.2 1.2

• This voltage adjustment is not required for OCT at side Y, as the neutral is 1 1

permanently grounded 0.8 0.8

0.6 0.6 Voltage in in pu Voltage • Two possible cases of voltage adjustment considered for analysis. in pu Voltage

0.4 0.4

0.2 0.2

0 0 0 1 2 3 4 5 0 1 2 3 4 5

Time in sec Time in sec

(a) (b) Voltage order adjustment with (a) Pole 3 DC Voltage, (b) Pole 4 DC Voltage Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 14 All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 16

38 39 2018 International High Voltage Direct Current Conference in Korea

3.3 Special Req. of HV Switching arrangement 3.4 Protection Strategy and Fault Cases for DC • Generally, OCT of a converter is performed for 2-3 hours. During this time there • While OCT for side Y of Bipole may be a chance of fault in OCT pole. Line 1 2, the voltage developed at the +780 kV HV pole during testing will be • For such cases protection system should ensure that it will block and isolate OCT opposite to the normal running. pole without affecting running bipole. 1 DC DC Pole Filter Fil ter • Similarly fault on the running pole should also not affect OCT pole. • +800 kV and -800 kV DMR Line • Important protections active during OCT include AC greater than DC(ACGDC), AC developed at the Line 1 & 2 respectively due to operating Overcurrent(ACOC) and DC Overcurrent(DCOC) protections. 1600 kV -800 kV SIDE Y

poles of Bipole 1. SIDE X x

• Such cases (i.e. case 3 and 6) 3 DC lead to development of Fil ter Pole approximate double of the pole voltage across the isolating switches on side Y.

Special Requirement of Circuit Breaker on HV DC Side • Hence the rating of the breaker and disconnector arrangement needs to be done for this Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figurespurpose and values. shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 17 All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 19

3.3 Special Req. of HV Switching arrangement for DC 3.4 Protection Strategy and Fault Cases Simulation 6 Simulation 5 • Balanced Bipole 1 is • Balanced Bipole 1 is running i.e. Pole 1 at 1500MW and +800kV at Line 1. Pole 2 running at 1500MW and -800kV at Line 2. Return is through DMR for both poles. • Switchgear arrangement • Switchgear arrangement done as per as per Case 3 of Table 1. OCT is performed as per Case 1. at Side Y of Pole 3. • OCT is performed at Pole 3 Side X with DMR.

• During OCT, flashover across the valves is simulated.

• AC current greater than DC(ACGDC) acts during the simulated valve fault, triggering the pole block.

Voltage across the HV switchgear arrangement during the OCT side Y of Pole 3 DC Voltage and protection during a fault case at OCT for Pole 3

Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 18 All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 20

40 41 2018 International High Voltage Direct Current Conference in Korea

REFERENCES 1. J. A. R. Monteiro, G. Mendiratta, R. A. Mukhedkar, "Champa Kurukshetra an 800kV HVDC Scheme - Design Challenges", CE B4 Brazil, October 2013 2. F. Ahmed and R. Mishra, "LCC HVDC bipoles configurations and their comparison with same and separate line," 2015 Annual IEEE India Conference (INDICON), New Delhi, 2015, pp. 1-6. 4. Conclusion 3. Direct current transmission, Vol I, Edward Wilson Kimbark, Portland, Oregn 4. System test for HVDC installations, CIGRE Working Group 14.12, Aug 1995,

Confidential. Not to be copied, distributed, or reproduced without prior approval. Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in ©2018, General Electric Company. All rights reserved. All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 23 nature

4. CONCLUSION

• Important challenges associated in performing OCT of an upcoming pole for a Parallel Bipole HVDC system sharing common DC transmission line are addressed. • OCT plays an important part in testing of an upcoming pole during commissioning. Thus, shall be performed appropriately, to improve overall reliability and availability of HVDC system. • Possible mitigations for the challenges faced during OCT are discussed and verified with simulation in PSCAD/EMTDC software. • Discussed mitigation procedure can be adopted for performing actual OCT in site prior to deblock the pole for power transfer for a parallel bipole system. • However, various complexities in transferring power for a parallel bipole system such as Power Balancing, control and protection sequences during normal and emergency condition need to be studied further.

Confidential. Not to be copied, distributed, or reproduced without prior approval. All figures and values shown above are approximate figures and values and are not definite in nature ©2018, General Electric Company. All rights reserved. 22

42 43 Conference Oral Session 3

Overvoltages experienced by extruded cables in LCC and VSC HVDC systems

Mansoor Asif (Hanyang University) 2018 International High Voltage Direct Current Conference in Korea

47 2018 International High Voltage Direct Current Conference in Korea

LCC and VSC Grid: Overvoltage types

External Disturbance Internal Disturbance

o Direct Stroke o Fault in AC Grid

• Flashover • Rectifier Side • No Flashover • Inverter Side

o Indirect Stroke o DC Pole to Ground Faults

• Backflashover • Magnetic Coupling

 Lightning Overvoltage can not enter a  Faults on AC sides of HVDC converter as pure HVDC cable transmission line, well as fault on DC line can lead to however it can be a serious concern in overvoltage in a cable. mixed overhead and cable based transmission lines.

LCC and VSC Grid: Direct Lightning Stroke

Lightning is the most significant cause of overvoltage in exposed power grid. Cable Length Current Magnitude

Lightning related overvoltage is independent of type of DC grid i.e. LCC or VSC. Cable Length: 6.25 km

Lightning overvoltage depends on a number of factors.

5 kA -1.25 p.u.  Magnitude of Lightning Stroke current 100 km -1.6 p.u.

 Length of cable segments . 6.25 km  -2.09 p.u. 25 kA  -2.25 p.u.

 Number of Conductors per pole  Footing Impedance of Transmission Towers The magnitude of overvoltage is inversely The magnitude of overvoltage is directly related to the length of cable. related to the magnitude of current stroke.  Relative impedance of cable and overhead line  In shorter cable, reflections from remote  According to ohms law, the magnitude of end of the cable will arrive sooner and voltage will be proportional to the current result in higher overvoltage magnitude. magnitude. 4 6

48 49 2018 International High Voltage Direct Current Conference in Korea

LCC and VSC Grid: Indirect Lightning Stroke

Back-flashover Induced Voltage

 In case of indirect stroke, the back flashover may occur if the tower footing impedance is very poor.  We calculated the critical resistance to cause back flashover for indirect stroke of 200 kA for various tower locations.

Critical Footing Resistance Location (ohms)

Twr2S 61

Twr3S 67

Twr4S 69  Magnetic Coupling: farthest lightning

Twr5S 72 stroke from cable will cause highest magnitude of voltage transient in the  Stroke on Twr1S (transition tower) do not cable. cause flashover even for very high values of footing impedance. 8

50 51 2018 International High Voltage Direct Current Conference in Korea

LCC & VSC Grid: Parametric Overvoltage Comparison Rectifier Side PheA : rn Inception Angle

AC Side Fault Fault Inception Instant

 Type of Fault

(PhaseAG, PhaseAB, PhaseABC G).  Location of Fault (Rectifier Side/ Inverter Side).

 Fault inception Instant (Angle of Current at time of occurrence of fault).

 Fault Resistance.

Extreme Voltage (max/min) er nn f f Extreme Voltage (max/min) er nn f f DC Line Fault  nfcn ere.  ere eceen 1.7 p.u. ere  n fre rn recer n n ce. re er voltage dips -0.9 p.u.  nfcn e ccr.  Distance from Rectifier End. < Fault Inception Instant with Reference to AC Current> re eece.  Fault Resistance.

LCC & VSC Grid: Overvoltage Analysis Methodology Rectifier Side PheA : worst case ncen ne

AC Side Fault DC Line Fault

Introduce ground Fault at ncen nn Introduce Faults at 10 degree h ne ce re ere ncen nn different Locations on h ne ce interval (0360 degree) re ere Transmission Line Reference: Ph. ‘A’ Reference: Ph. ‘A’ Recfer e Fault Resist: 0 ohms AC CB’s open Fault Resist: 0 ohms Fault Location: AC bus Recfer e AC CB’s Reclose

Determine the angle at which the Determine the Location where Recfer e AC CB’s Reclose

overvoltage is maximum Overvoltage is Maximum e e: . ecn e e: . ecn nerrn e: ce nerrn e: ce

Introduce Variable Resistance Introduce Variable Resistance Faults (0  50 ohms) Faults (0  50 ohms) Time domain voltage waveform re f f Time domain voltage waveform re f f

 r ce f ne f ’ e’ e.  ere eceen 1.7 p.u. ere n ce. Determine the maximum Determine the maximum  Commutation failure occurs rn recer overvoltage overvoltage hch ce e .  nfcn e ccr.

52 53 2018 International High Voltage Direct Current Conference in Korea

Rectifier Side seAB l n Resistance seAB l os s ncepon nle

CC C CC C

l ncepon nsn

l ncepon nsn s nle cses s nle cses les oeole les oeole nee se AC CB’s open nee se AC CB’s Reclose

nee se AC CB’s Reclose

CB e e secon CB e e secon CB l nepon e Ccles CB l nepon e Ccles

Extreme Voltage (max/min) s pe l essnce Extreme Voltage (max/min) s pe l essnce m om o om s esl o l m om o om s esl o l

 essnce seAB ls o no  e oeole ne o  os cse l nle o ’ e’ s se  eole ecees epeence ole p essnce ls o no ecee 1.74  Coon le n een pol  o sncn ole p occs  e overvoltage ne s highest o p.u. cne s epeence l ncepon l essnce o ‘2.5 ohms’.  o sncn ole p occs

seAB l n o seAB l n ss

CC C CC C

m o mm s pe nsn o l m o mm s pe nsn o l m o mm s pe l essnce m o mm s pe l essnce

 o sncn oeole  e oeole ne o  As oppose o ece se seAB ls  o ne eceses  Coon le n ecoe n s essnce ls s o o ll l ommo n s esl ole s ss esl seos o s p o nsnces ps e possle een o essnce  ole p ece ncesn l

e epece  o sncn ole p occs s hs s essnce

54 55 2018 International High Voltage Direct Current Conference in Korea

olen l n s o ole l ss

CC C CC C

m o mm s pe snce o ece m o mm s pe snce o ece m o mm s e l essce m o mm s e l essce

 o oo occs n cse o   o cle senn en s  o oeole s osee o le o  e e o oeole ss n locon hhs o s s l essce l essce eoe s  e ole p epeence e cle  e ole p epeence e cle  e o o ss ohms senn en s ees n cse o nee senn en s ees n cse o nee s l ss  e o o ss en  l en  l s l ss

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CC C ole Ces ole o e o Ces

l ncepon nsn

DC CB’s Reclose

Rece se Fault at 140 km Fault at 140 km AC CB’s Reclose

AC CB e e s AC CB l nepon e CB e e s Conee Conol l on e s C CB ensn n nepon e s mm o cse o cse el o m o oeole el el Dsces el Dsces eo    m om o om s esl o l m om o om s esl o l AC DC ls C ee se ls eole e esl e cse seee ole s e o ces o  o oeole occs n cse o  l  eee o o s oeole CC e o coo s s epeence l occence  l oeole le ce c e  e o epeence e cle  Ae eclosn o C CB n ecoe o cle C s  ol eesl C c oe sessl o senn en s o C sse eenc oeole o e ol cse o DC cle slo om oe n cn e epeence eole e ls o h oo

lo cles

56 57 2018 International High Voltage Direct Current Conference in Korea

CC s C Cle ole ses

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ossl o coleel loc e e cool o B se coee coee se o so sces esece o ee eel oes Thank-you for attention

Re olCe cool o CC esece o DC se cco coee  o c occ ol o s  o s c occ cse o s De o esece o DC se ccos o AC l c cse ole AC ls cool o e ee e cle se soe cses o e ece se le o coo le DC se ls ll cse ole seee ole s

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58 59 Conference Oral Session 4

Research on the Control Factors of Polarity Distance for ±1100kV Transmission Line

He Yan (Northwest Electric Power Design Institute Co., Ltd) 2018 International High Voltage Direct Current Conference in Korea

Research on the Control Factors of Polarity Distance for 1100kV Transmission Line

HE Yan, ZHU Yongping, TAN Haowen, ZHANG Xiaoli Northwest Electric Power Design Institute Co., Ltd of China Power Engineering Consulting Group, China

Super Grid

HVDC

Polarity distance

63 2018 International High Voltage Direct Current Conference in Korea

1 Relationship between electromagnetic enviroment and polarity distance

32 90 85 30 80 ) 2 28 75 Dry Conductor Dry Conductor Wet Conductor 70 Wet Conductor 26 65 60 24 Polarity distance 55 22 50

Ion current density (nA/m 45 20 40 Total field strength above (kV/cm) ground 18 35 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Polarity distance (m) Polarity distance (m)

Limits of total field strength and ion current density Total field strength limit Ion current density limit Weather (kV/m) (nA/m2) Sunny day 30 100

Rainy day 36 150

Contents 1 Relationship between electromagnetic enviroment and polarity distance 66 58 65 57 Altitude 0m Altitude 0m 56 64 Altitude 1000m 63 Altitude 1000m 55 1. Electromagnetic enviroment 54 Altitude 2000m 62 Altitude 2000m 61 53 Altitude 3000m 60 Altitude 3000m 52 59 51 58 50 2. Insulation configuration 57 49 Minimum polarity distance 56 48 55 47 of suspension tower 54 46 53 45 52 44 3. Clearance to ground 51 43 50 Audible noise (dB(A)) 42 49 41 Radio interference (dB(μV/m)) 48 40 47 39 4. Corridor width Polarity distance 46 38 45 37 44 36 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Polarity distance (m) Polarity distance (m) 5. Tower weight Limits of radio interference and audible noise Minimum polarity distance under the requirement Minimum polarity distance of Electromagnetic environment of tension tower 6. Corona loss RI limit AN limit Altitude (m) Altitude (m) 1000 2000 3000 (dB(mV/m)) (dB/A) 7. Economical analysis 58 45 AN limit (dB/A) 45 50 50 >1000 58+ 50 Polarity distance (m) 22 18 20 =3dB/1000m

64 65 2018 International High Voltage Direct Current Conference in Korea

2 Relationship between insulation configuration and polarity distance 3 Relationship between clearance to ground and polarity distance

D1 27.0 Altitude 0m 26.5 Altitude 1000m 26.0 Altitude 2000m Altitude 3000m 25.5 R D2 R 25.0 24.5 24.0 Air clearance of ±1100kV OHTL 23.5 23.0

Altitude (m) 1000 2000 3000 Minimum clearance to (m) ground 22.5 22.0 Operating voltage clearance (m) 3.2 3.7 4.2 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Polarity distance (m)

Switching overvoltage 1.50p.u. 8.1 8.7 9.2 clearance (m) 1.58p.u. 8.9 9.5 9.9 Minimum polarity distance under the requirement of • Total field strength is the main controlling factor for clearance to ground. air clearance • Minimum clearance to ground increases with polarity distance. For every 1m increase Altitude (m) 1000 2000 3000 in polarity distance, minimum clearance to ground increases by about 0.05-0.08m, the 1.50p.u. 24.0 25.2 26.2 increase is very small. Polarity distance (m) 1.58p.u. 25.6 26.8 27.6

4 Relationship between corridor width and polarity distance 2 Relationship between insulation configuration and polarity distance Composite insulator length of ±1100kV OHTL 120 Altitude 0m Altitude (m) 1000 2000 3000 Alititud 1000m 115 Altitude 2000m 12.30 12.30 13.90 Altitude 3000m 110 Length of composite 12.30 13.90 15.40 insulator (m) 105 13.90 15.40 16.60 100 Corridor width (m) Minimum polarity distance under the requirement of composite 95 insulator lenght Altitude (m) 1000 2000 3000 90 Light 22 24 26 28 30 32 34 36 21.4 21.4 23.4 Polarity distance (m) contamination area Medium a=75° 21.4 23.4 25.2 contamination area Heavy a • Total field strength is the main controlling factor for corridor width. 23.4 25.2 26.7 contamination area • Corridor width increases with polarity distance. For every 1m increase in polarity distance, Light 26.4 26.4 29.0 contamination area corridor width increases by about 1.11-1.26m. Medium a=105° 26.4 29.0 31.3 contamination area Heavy 29.0 31.3 33.2 contamination area

66 67 2018 International High Voltage Direct Current Conference in Korea

5 Relationship between tower weight and polarity distance 7 Economical analysis

95 Tower weight Initial investment of tower 22m 23m 90 24m increase increase 25m 26m 85 27m 28m Polarity distance Overall annual 29m 30m ？ 80 increase cost

75 Corona loss Annual cost of corona loss

Tower weight (m) decrease decrease 70

60 P—Initial investment of tower 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 Tower height (m) Atn—Annual cost converted from • For every 1m increase in polarity distance, the tower weight increases by an average of initial investment of tower

2%. For every 1m increase in tower height, the tower weight increases by an average of Acn—Annual cost of corona loss 1%. • Polarity distance has greater impact on tower weight.

6 Relationship between corona loss and polarity distance 7 Economical analysis

24.0 12 0.30 yuan/kW·h 23.5 21 11 0.35 yuan/kW·h 23.0 0.40 yuan/kW·h 20 10 0.45 yuan/kW·h 22.5 9 19 22.0 8 18 21.5 7 21.0 Acn (ten thousand yuan/km) 17 Atn (ten thousand yuan/km) 20.5 6

16 20.0 5 22 23 24 25 26 27 28 29 30 22 23 24 25 26 27 28 29 30 Polarity distance (m) Corona lossCorona (kW/km) Polarity distance (m) 15

14 21 0.30 RMB yuan/kW·h 13 20 0.35 RMB yuan/kW·h 22 24 26 28 30 32 34 36 19 0.40 RMB yuan/kW·h Polarity distance (m) 18 0.45 RMB yuan/kW·h 17 16 15 • When polarity distance increases, the corona loss decreases. Overall annual cost increases 14 Reducing the polarity distance with polarity distance. 13 can reduce the overall annual • For every 1m increase in polarity distance, corona loss decreases by 3%. Decreasing 12 11 cost, more economical. trend becomes gradually smaller. 10 9 Overall annual cost (ten thousand yuan/km) 8 22 23 24 25 26 27 28 29 30 Polarity diatance (m)

68 69 Conference Oral Session 5

8 Minimum polarity distance under the requirements of comprehensive factors

38 Minimum polarity distance of Electromagnetic enviroment controlled 36 Air clearance controlled（1.50p.u） suspension tower (α=75°) Air clearance controlled（1.58p.u） 34 Insulator length controlled (α=75°) Insulator length controlled (α=105°) Altitude (m) 1000 2000 3000 32 1.50p.u. 24.0 25.2 26.7 30 Polarity Dynamic and steady state performance of 28 distance (m) 1.58p.u. 25.6 26.8 27.6 26 Minimum polarity distance of a 2-terminal Hybrid HVDC transmission 24 Polarity distance (m) tension tower 22 Altitude (m) 1000 2000 3000 20 18 Polarity distance (m) 22.0 18.0 20.0 1000 2000 3000 Altitude (m) • For suspension tower, composite insulator length and air clearance are main controlling factors for polarity distance. • For tension tower, audible noise is main controlling factor for polarity distance. • It is advisable to carry out follow-up study from the aspect of insulation configuration so as to reduce the entire life cycle cost of the project.

Mats Andersson (ABB)

70 2018 International High Voltage Direct Current Conference in Korea

Dynamic and steady state performance of a 2-terminal Hybrid HVDC transmission

Mats Andersson, Qinan Li Corporate Research, Power and Control department ABB (China) Ltd. Beijing, China

Abstract—2-terminal Hybrid HVDC consisting of a Line- decrease is quite limited, but the DC voltage can be increased Commutated Converter (LCC) in the sending end, and a Voltage significantly by lowering the modulation index. Based on Source Converter (VSC) in the receiving end, is a compromise these differences, a novel control method called CDVOL between cost, loss and performance. A Hybrid system has lower (Current Dependent Voltage Order Limiter) was developed cost and somewhat lower losses than a pure VSC HVDC system. and applied at the VSC. By dynamically lowering the DC Yet it can provide reactive power support and black start voltage reference at the VSC, the whole HVDC transmission capability at the receiving end, which a pure LCC system simply can recover to the pre-fault DC power level significantly faster. cannot. Another thing to consider in a Hybrid HVDC system is The focus of this paper is optimizing dynamic performance. A steady state control. One station needs to control the DC novel control method called CDVOL (Current Dependent current (Mode 1), while the other station needs to control the Voltage Order Limiter) was developed and applied at the VSC. DC voltage (Mode 2). In this paper it is shown that both ways By dynamically lowering the DC voltage reference at the VSC, of controlling the system are feasible, during steady state the whole HVDC transmission can recover to the pre-fault DC operation and during transients. An optimization (Mode 3) is power level significantly faster. possible when LCC is controlling DC voltage, which lowers losses, cost and the overall LCC station footprint. Two control modes are also compared, namely LCC controlling DC current, and LCC controlling DC voltage. It is Yet another thing to consider in a Hybrid HVDC system is shown that both control modes are feasible, during steady state DC fault handling. LCC inherently has an ability to stop fault operation and also during transients. An optimization is possible current, which VSC does not. So far there is only one VSC when LCC is controlling DC voltage, which lowers losses, cost HVDC transmission using OHL (Over Head Lines) in and the overall LCC station footprint. commercial operation, namely the Zambezi Link [4]. It uses AC breakers to clear DC line faults, which is a very cost- Keywords— HVDC transmission; Hybrid power systems; Power effective way. But the fault clearing time for that system is system control relatively long since re-energization of the VSC converter is necessary. There are other alternative ways that DC faults can I. INTRODUCTION be cleared, by for instance using a Hybrid DC breaker [5], or 2-terminal Hybrid HVDC consisting of a Line- full bridge MMC [6]. Considering that in many HVDC Commutated Converter (LCC) in the sending end, and a applications the power is transferred in only one direction, half Voltage Source Converter (VSC) in the receiving end, is a bridge MMC together with a diode valve for blocking DC compromise between cost, loss and performance. A Hybrid fault current turns out to be the most cost-effective solution [7]. system has lower cost and somewhat lower losses than a pure Since one of the major reasons to use a Hybrid HVDC system VSC HVDC system. Yet it can provide excellent AC network is overall system cost-effectiveness, the diode alternative is performance at the receiving end, which a pure LCC system used in this paper. simply cannot. Typical situations where the excellent AC This paper has the following layout: In section II, the network performance may motivate or justify the installation CDVOL control function is introduced, and the improvements of VSC HVDC are for example: HVDC multi infeed and the in fault recovery is demonstrated with time domain related stability issues [1], too high short circuit AC current simulations. In section III, two different steady state control due to synchronous condensers [2], too weak AC grid due to modes are compared with each other. An optimization is the integration of large amount of renewable energy [3]. possible when LCC is controlling DC voltage. Conclusions are When mixing LCC and VSC technology in a Hybrid drawn in section IV. HVDC transmission, there are many things to consider. One such thing is the dynamic performance. An LCC rectifier can II. CDVOL FOR IMPROVED DYNAMIC PERFORMANCE rapidly decrease its DC voltage down to zero by increasing its In this section, the CDVOL function is introduced, and its firing angle. However, it is quite limited in how much it can increase the DC voltage. With typical design the DC voltage effectiveness is demonstrated using time domain simulations. increase is limited to around 3%. A VSC inverter equipped with Half Bridge is the complete opposite: Rapid DC voltage

73 2018 International High Voltage Direct Current Conference in Korea

A. Differences in dynamic performance between LCC and Reduced DC voltage (kV) ±400 1 Uorder 0.95 VSC converters 0.9 Nominal DC current (A) 3000 0.85

The key to having good dynamic performance in any type 0.8 of HVDC system, is good cooperation between the converters. Length of transmission line (km) 1000 0.75 VSC DC voltage Ud Ref 0.7 For a Hybrid system, this becomes even more important since 0.65 1.2 the converters are of different types. An overview of how the 1 DC voltage can be rapidly controlled is shown in TABLE I. Since this is an OHL HVDC transmission, it is capable of 0.8 0.6 rapidly reducing the DC voltage. The reduced DC voltage 0.4 Ud Min level is set to 80%, or 400 kV. To achieve reduced DC voltage, 0.2 VSC DC current TABLE I. COMPARISON OF RAPID DC VOLTAGE CONTROL ABILITY no special precautions are necessary for the LCC system. 0 -0.2 VSC with Half Bridge However, for the VSC system a lower than normal modulation 1.4 LCC (rectifier) 1.2 (inverter) index is used. The modulation index is chosen so that the VSC 1 Can increase the DC 0.8 Ability to Typically limited, a converter will be close to its upper modulation index voltage significantly, by Id 0.6 rapidly increase normal design only limitation at the instant it enters reduced DC voltage. Shortly 0.4 lowering the the DC voltage allows for around 3% after entering reduced DC voltage, the VSC converter Id low Id high 0.2 LCC DC power modulation index 0 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 Can rapidly be Typically limited, the transformer tap changer will start to bring down the Time [s] Ability to Figure 2. CDVOL function overview decreased down to modulation index modulation index to a lower value again. rapidly decrease Figure 5. DC Line fault, Mode 3 zero, or even change cannot be increased too the DC voltage polarity high Hence, the VSC converter will have some ability to rapidly 1.1 TABLE III. CDVOL INFLUNCE ON RECOVERY TIME decrease the DC voltage. This is then used in the CDVOL. 1 0.9 LCC 3-phase to VSC 1-phase to DC line

For recovery after fault clearance, the ability to rapidly C. CDVOL function 0.8 ground AC fault ground AC fault fault increase the DC voltage is the most important factor. Hence, 0.7 VSC DC voltage Recovery to 90% the LCC converter will place the basic limitation in this A core control functionality in LCC HVDC is the VDCOL of prefault DC (Voltage Dependent Current Order Limiter). It rapidly lowers 1.2 power at the LCC 100/230 120/390 100/380 system. If the VSC converter puts up too high DC voltage for 1 with/without the DC current order when the measured DC voltage dips. 0.8 the LCC, then the DC current will not build up quickly, 0.6 CDVOL (ms) When the DC voltage starts to build up again, the DC current ultimately leading to a relatively slow active power recovery. 0.4 Steady state Mode 2 Mode 1 Mode 3 order is increased in a controlled manner. 0.2 VSC DC current control mode 0 B. System used for all testing in this paper -0.2 For the VSC converter in the tested Hybrid system, a 1.4 III. STEADY STATE CONTROL METHODS An overview of the system used for all testing is shown in CDVOL was developed. It rapidly lowers the DC voltage 1.2 1 In this section two different ways of controlling the HVDC order when the measured DC current dips. When the DC 0.8 Figure 1. Key data is shown in TABLE II. current starts to build up again, the DC voltage order is 0.6 system are discussed, namely rectifier controlling DC voltage 0.4 Diode increased in a controlled manner. Due to the lower counter DC 0.2 LCC DC power (called Mode 1), and rectifier controlling DC current (called 0 voltage from the VSC converter, the LCC converter can start 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 Mode 2). An optimization of Mode 1 was made, which both Pole 1 Time [s] to drive DC current sooner. Thus, the whole active power lowers steady state losses and the overall LCC station Y Y recovery becomes significantly faster. An overview of the Figure 3. LCC 3-phase to ground AC fault, Mode 2 footprint. Δ Y CDVOL function is shown in Figure 2. 1.2 A. Comparison between Mode 1 and Mode 2 To verify the CDVOL, several tests were made. Time 1.1 VSC DC voltage

Y Δ In a point-to-point HVDC system one station needs to domain simulations are shown in Figure 3, Figure 4 and 1 control the DC current, while the other station needs to control Figure 5. Curves in blue color shows the results with CDVOL, 0.9 LCC VSC the DC voltage. For a typical pure LCC HVDC transmission, and curves in green color shows the results without. The figure 0.8 legend is the same in all simulations and are as follows: Top 1.4 Mode 2 is used. For a typical pure VSC HVDC system there is Y Δ 1.2 no general preference, but in many cases the converter that is curve shows DC voltage at the VSC station; Middle curve 1 0.8

connected to the strongest AC network controls the DC Δ shows DC current at the VSC station. Bottom curve shows DC 0.6 Y voltage. This is because a stronger AC network can easier power at the LCC station. All quantities are in p.u. 0.4 VSC DC current 0.2 handle rapid changes in active power flow. Y Y 0 The results are summarized in TABLE III. The CDVOL 1.4 Pole 2 improves the dynamic performance significantly for post-fault 1.2 A basic comparison of advantages and disadvantages 1 between the two control modes are made in TABLE IV. A recovery. The different steady state control modes are 0.8 Diode mentioned already in this section, just to show that the 0.6 mode shift means that the AC voltage drops very suddenly at Figure 1. overview of the tested system 0.4 the DC current controlling converter, so that the other CDVOL works well in all different conditions. The steady 0.2 LCC DC power 0 converter temporarily needs to take over DC current control. state control modes will be discussed further in section III. 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 TABLE II. KEY SYSTEM DATA Time [s] Figure 4. VSC 1-phase to ground AC fault, Mode 1 Parameter LCC VSC TABLE IV. COMPARISON OF CONTROL MODES Nominal AC voltage (kV) 525 525 Mode 1 (LCC controls DC Mode 2 (LCC controls DC voltage) current) AC network short circuit capacity 15000 15000 Main Telecommunication not Decreased DC current at (MVA) advantage really needed mode shift Increased DC current at System works better with Frequency (Hz) 50 50 Main mode shift, which might telecommunication, since disadvantage Nominal DC voltage (kV) ±500 cause slight over- DC current order needs to

74 75 Mode 1 (LCC controls DC Mode 2 (LCC controls DC IV. CONCLUSIONS voltage) current) dimensioning of the VSC be coordinated between For recovery after fault clearance, the ability to rapidly valve stations increase the DC voltage is the most important factor. Hence, the LCC converter will place the basic limitation in this B. Optimization based on Mode 1 system. To improve the dynamic performance, a new function To lower the cost, footprint and losses of the whole LCC called CDVOL was developed. It rapidly lowers the DC station, some further steady state optimization was possible voltage order when the measured DC current dips. When the based on Mode 1. Instead of using a firing angle at a typical DC current starts to build up again, the DC voltage order is 15±2.5°, it is possible to bring down the firing angle to the increased in a controlled manner. Due to the lower counter DC minimum allowed of 5° and just use the tap changer to voltage from the VSC converter, the LCC converter can start regulate the DC voltage [8]. This optimization is called Mode to drive DC current sooner. Thus, the whole active power 3. recovery becomes significantly faster. Operation with Mode 3 brings significant advantages. A Two control modes were also compared, namely LCC comparison is made in TABLE V. controlling DC current, and LCC controlling DC voltage. It was shown that both control modes are feasible, during steady TABLE V. COMPARISON BETWEEN MODE 3 AND MODE 1 state operation and also during transients. By using the minimum allowed firing angle of 5° together with transformer Mode 3 (5° firing Mode 1 (15° firing angle) angle) tap changer to perform DC voltage control with the LCC, Bipolar reactive power 1320 1640 significant optimization of the whole LCC converter station is consumption (MVAr) possible, namely: lower losses, cost and footprint. Number of AC filters and 9 11 shunt capacitors Apparent power through the 3278 3419 References converter transformers (MVA) [1] P. Fischer de Toledo et al, “Multiple infeed short circuit ratio - aspects Total Harmonic Distortion in 18.9 21.2 related to multiple HVDC into one AC network”, IEEE/PES transformer valve currents (%) Transmission and Distribution Conference and Exhibition Asia Pacific, Dalian, China 2005-08-14--18. To get a better comparison between the three steady state [2] D. Jacobson et al, ‘‘Planning the Next Nelson River HVDC Development Phase Considering LCC vs. VSC’’, paper B4-103, CIGRÉ control modes, recovery after a 3-phase to ground low 2012. impedance AC fault at the LCC is shown in Figure 6. Out of [3] M. De Simone et al, “Commutation failures mitigation in multi-infeed all tested cases, this is the post-fault recovery that shows the network with high renewable penetration: TERNA’s experience”, paper biggest difference. Voltage and power are in p.u, and firing B4-125, CIGRÉ 2016. angle is in electrical degrees. Mode 1 is in green color, Mode [4] T. Magg et al, ‘‘Zambezi (previously Caprivi) Link HVDC 2 is in blue color and Mode 3 is in red color. Both Mode 1 and Interconnector - Review of Operational Performance in the First Five 2 has some control margin left since the steady state firing Years’’, paper B4-108, CIGRÉ 2016. angle is higher. Somewhat simplified, an LCC rectifier has a [5] J. Häfner et al, “Proactive Hybrid HVDC Breakers - A key innovation control margin that is cosine (5°) – cosine (steady state firing for reliable HVDC grids”, paper 264, CIGRÉ Bologna 2011. angle), or around 3% in this case. Therefore, the firing angle is [6] T. Jonsson et al, “Converter technologies and functional requirements for reliable and economical HVDC grid design”, paper 266, CIGRÉ pushed down to 5° at around 1.45s, which in turn transmits Canada 2013. some additional DC power. In Mode 3 there is no control [7] M. Andersson, X. Yang, C. Yuan, "2-Terminal Hybrid HVDC - Cost margin, hence the DC active power recovery will basically Effective Alternatives for Clearing Temporary DC Line Faults", 2017 follow the AC voltage amplitude recovery. IEEE PES Asia-Pacific Power and Energy Engineering Conference (APPEEC), Bangalore, India, 8-10 Nov. 2017 1.4 [8] M. Andersson, X. Yang, Y.J. Häfner "A cost effective hybrid HVDC 1.2

1 transmission system with high performance in DC line fault handling", 0.8 paper B4-117, CIGRÉ 2018.

0.6 0.4 LCC RMS AC voltage 0.2

0 1.4

1.2

0.8

0.6 0.4 LCC Active Power 0.2

0 40 30 LCC Firing Angle

0 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 Time [s] Figure 6. comparison of the three control modes