Hvdc Transmission Fundamentals: Sponsor: Hvdc And Facts Subcommittee

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HVDC Transmission Fundamentals Sponsor: HVDC and FACTS Subcommittee

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Session Overview • Introduce fundamentals of HVDC transmission systems • The presentations are tutorial in nature • Will provide background for other sessions at this conference

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Presentations • Planning for HVDC Projects, – Mike Henderson, ISO-New England

• Overview of VSC HVDC – Neil Kirby, GE Grid Solutions

• Overview of LCC HVDC – Brian Johnson, University of Idaho

• Changing/Optimizing Electric Power Networks by Using Flexible HVDC Technologies – Taixun Fang, Nr Electrc USA, LLC

4

Power Electronics for Solving AC Transmission Problems

• Transmission Bottlenecks have one or more of – Steady-state Stability Limits – Transient Stability Limits – Power System Oscillation Limit – Inadvertent Flows – Short Circuit Current Limits – Thermal Limits

• Bulk Power Transfer Over Long Distances

5

Some Conventional Solutions • • • • • • •

Series Capacitors Switched Shunt Capacitors or Reactors Power System Stabilizers Transformer Tap Changers Special Stability Controls Phase Angle Regulators Synchronous Condensers

6

When to Apply Power Electronic Solutions

• Apply where power converters matter – Dynamic reactive compensation – Conversion to/from DC for transmission – Interface to generation or storage

• Concerns: cost, losses, complexity, reliability

7

High Voltage Direct Current (HVDC) Transmission

• Update to Edison’s Vision • AC Power Generation at Relatively Lower Voltage – Step Voltage Up to High Levels

• Convert From AC to DC and Back – DC Voltages Pole to Ground up to 800 kV – Currents up to about 3000A

• Most Systems Presently Point to Point—Evolving • Multiterminal Grids

HVDC Power Transmission • • • •

No distance limitation for stability No distance limit for underground/sea cables Controlled power flow High power transfer, fewer lines, – Narrower ROW – Lower losses

• Firewall against cascading outages

8

9

Basic Concepts with HVDC • Overhead Lines – Bulk Power Transfer Over Long Distances – Possibly Connecting Asynchronous Systems

• Underwater or Underground Cables – Distance Limits Underwater Cables – Longer Distances Where Overhead Lines Infeasible

• Back-to-back interconnections – Asynchronous systems –same or different frequency

10

Fast Controls Again Available • Control Power Flow on DC Link – Control DC Voltage – Control DC Current

• Damp AC Power Systems Oscillations • VSC HVDC Converters Can Control AC Side Voltage or Reactive Power

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Development History • First “Static” VAR Compensator (1930’s) – Saturated reactors in combination with capacitors

• First HVDC projects (Mercury Arc Valves): – Berlin-Charlottenburg early 1940’s – Moscow early 1950’s – Gotland Island: 1954 (first operating project)

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Development History (continued) • Thyristor Based Converter Applications – HVDC Transmission (early 1970’s) – Static Var Compensators (early 1970’s)

– Thyristor Controlled Series Capacitor (late 1980’s)

• Voltage Sourced Converter (VSC) Applications – FACTS Devices (late 1980’s) – VSC HVDC Transmission (late 1990’s)

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Overview of LCC HVDC Brian Johnson University of Idaho

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Topics • • • • • • •

Introduction Circuit Configurations Converter Operation Real / Reactive Power Harmonics Converter Arrangements Control

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LCC HVDC Transmission •

Applications • • • • •

•

Long-distance, bulk-power transmission Sea and land cable transmission Asynchronous interconnections Power flow control Congestion relief

Ratings •

Power range up to 4000 MW at ± 500 kV • Power range up to 4800 MW at ± 600 kV • Voltage range increasing to ± 800 kV with Power range up to 6400 MW

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What is LCC HVDC? • Line commutated converter • Bridge connected converter – Originally mercury arc valves, later thyristors – Inductive filter on dc side – current stiff

uR uS uT

• Reverse direction of power flow by reversing voltage polarity

Id

IR

1

3

5

IS Ud

IT 4

6

2

• 6-pulse bridge

Berlin Mercury Arc Valves 1942

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Gotland Mercury Arc Valve

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HVDC Operating Configurations

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LCC Converter Operation

Id

IR uR

IS

uS

IT

u a

uT

IR

1

5

IS Ud

IT 4

20

3

6

2

21

LCC Reactive power characteristics • • • LCC HVDC

Reactive compensation by switched filters and shunt capacitor banks

•

•

•

Converter operates at lagging power factor Both rectifier and inverter operation – Current lags voltage Lagging power factor is due to phase control and commutating reactance Typically reactive power demand = 55% of station real power rating at full load Reactive power compensation – typically 35% of station rating from ac filters the balance from shunt banks Shunt reactors sometimes used at light load to absorb excess from filters

22

Harmonic Characteristics AC characteristic current harmonics at fh = 12n +/- 1 • Shunt filters: band pass, high pass, double-tuned • Typical ac filter performance criteria: THD<1.5%, TIF < 45 • DC side voltage harmonics: fh=12n • Typically 35% of station rating in installed ac filters • Harmonic magnitudes diminish with increasing harmonic number •

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Commutation in a controlled bridge

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Short Circuit Ratio AC Network

SN

QHF ± QSH

QHF ± QSH T

G

SG SC

SSC

• • • • • • •

Commutation performance Voltage stability Dynamic performance Dynamic overvoltage Low order harmonic resonance, Rule of thumb – ESCR > 2 for LCC ESCR = (SN+SG+SSC+-Q)/PDC

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LCC HVDC converter physical arrangements Thyristor Module

Gate Unit

Single

Double

Valve

Valve

Quadruple Valve

Thyristor

Heat Sink

• Thyristor valves • Thyristor modules • Triggered

LCC Converter Station Transmission line or cable

Converter station

Smoothing reactor Converter

AC bus

DC filter

Shunt capacitors AC filters or other reactive equipment

Telecommunication Control system

26

~~

LCC HVDC Converter Station HVDC-CSC

Converter Transformers AC

DC Filters

AC Filters

DC

Outdoor Indoor

Thyristor Valves

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Modular Back-toBack CCC Asynchronous Tie

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Generator Outlet Transmission  More

power on fewer lines  Improved stability  Lower installed cost  Reduced losses  Double circuit (bipolar line)  Reduced ROW  One line vs. two 29

ITAIPU 2 x 6300 MW

3 x 800 kV AC 6300 MW

345 kV AC 400 MW

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2 x ± 600 kV DC 6300 MW

± 500 kV DC 3000 MW

Long-Distance Bulk Power Transmission

Interconnections •

• • • • •

Firm capacity Bypass congestion Avoid loop flow No limit due to parallel paths Interconnect diverse regions Asynchronous

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Asynchronous Interconnections •

Economic •

Firm transactions • Shared reserves • Increase diversity • Economy energy trade Asynchonous borders

•

Reliability • • • •

HVDC in North America

32

•

Emergency power support Mutual assistance Isolate disturbances ‘Fire-wall’ against cascading outages Reserve sharing

Control Principles •

• •

• 33

Two independent control inputs at each terminal • Firing angle  fast • AC voltage  slow (LTC) One terminal controls DC voltage (fast) One terminal controls DC current (slower) • Current order from higher order power command Synchronized firing with PLL

Handling Firing Angle Limits •

•

•

Alpha min for rectifier • Disturbance Gamma min at inverter • Commutation failure VDCOL 34

Summary •

• • •

• •

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Overview of LCC operation Circuit Configurations Real / Reactive Power Harmonics Converter Arrangements Control

Planning and integration of Flexible HVDC into Today’s Grid The planning process and required studies

Michael I. Henderson ISO New England Inc. PES General Meeting May 2016

Disclaimer • Properly Presented Information – Accurately represents the positions of ISO New England

• Inaccurate Information or Opinions that May Not Fully Agree with ISO New England – My private views and are not meant to represent any organization with which I am affiliated

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Planning HVDC and FACTS - Overview • • • • • •

Background and Planning Process Study Requirements Refurbishment Issues HVDC and FACTS Lessons Learned Future Applications Summary and Conclusions

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Background and Planning Process

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What Is Planning? • Identify need for future power system infrastructure • Meet reliability, economical, and policy requirements and constraints • Know your objectives – – – –

Transmission owner – rate base considerations Generator owner – minimize cost and maximize revenues Regulator – keep rates low and meet policy objectives Environmental community – meet air, water, and land management requirements – Market resource alternatives – effect on bottom line – Load – rates and environmental impact

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Reliability Guides Regional Transmission Planning Requirements • North American Electric Reliability Corporation

NPCC

– Reliability Standards for the Bulk Power System in North America

• Northeast Power Coordinating Council – Regional Reliability Reference Directory #1 – Design and Operation of the Bulk Power System

• ISO New England – Reliability requirements for the regional power system

Standards are used to ensure that the regional transmission system can reliably deliver power to consumers under a wide range of future system conditions.

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Types of Transmission Upgrades • • • •

Generation Interconnection Elective Transmission Merchant Transmission Local Benefit Upgrades

Generally funded by the entity proposing the project

• Regional Benefit Upgrades – Reliability and Market Efficiency Upgrades • Localized Costs excluded from regional cost support

– Policy Upgrades on the way!

Often funded through the regional Open Access Transmission Tariff

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Overall Transmission Development Process for Regional Upgrades* • • • • • •

Identify needs Derive possible solutions Define project Achieve Reliability and Cost approvals Begin state siting Stakeholder input throughout

* The transmission planning process also provides information to developers of generation, demand resources, and merchant transmission

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Meeting US FERC Order 1000 Requirements • Changes are underway! – Competitive process to determine longer-term transmission infrastructure projects – Transmission projects for meeting public policy objectives – Build on the interregional planning process and change interregional cost allocation for transmission projects

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System Capacity Factor versus Reliability Upgraded System

A

Existing System

Reliability 1 0

Economic? Higher Risk Requires Higher Return

RETURN

RISK INVESTMENT

$ 11

Winners and Losers Money is the key driver Balance reliability and investment

Reliability

Economy

1 2

Planning Process • Drivers  physical and commercial • Feasibility Studies  determine need • Detailed modeling  develop final network plan • Field tests  confirm models

• Commercial operation  monitor performance and adjust

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Planning in a Deregulated Market Requires Robust Solutions to Deal with Uncertainty •

Markets and bid strategies increase variability – – – –

•

Unit dispatch Unit commitment Ancillary services Network flows

Market power issues – Load pockets – Dependency on generating units affect transfer limits

•

Independent owners and decisions for capital investment – Resource amounts, locations, and types – Load serving entities – Transmission owners

•

Technology and physical changes – – – –

Wind and fuel constraints Environmental restrictions and targets Distributed resources Availability and maintenance

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The Planner’s Job Identifies • Benefits, costs, and risks • Basis for application • Applications meeting corporate, regional, and physical requirements • Solutions for flow control and asset utilization • Reactive supply and voltage control issues • Acceptable dynamic and transient stability performance – Speed of response and settings for controls

• Economics of alternative solutions • Plans with enhanced system performance under a wide variety of system conditions, including maintenance

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Possible HVDC Applications • Network Controllability – Control of real power – Voltage control – Auxiliary control • Frequency regulation • Damp dynamic oscillations • Stabilize transient stability swings

• • • • • •

Asynchronous interconnections Transmission over long distances Bypass network congestion and inject power Submarine applications Right-of-way of constraints Short circuit restrictions

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Study Requirements

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Planning Considerations • Base case assumptions must assess flexibility under a wide variety of system conditions • Contingency Considerations • Losses • Coordination with neighboring systems • System protection, engineering, and design • Siting and regulatory requirements 18

Conventional versus HVDC and FACTS Control? • Modeling and planning studies are required to address the three C’s – Controllability application • Steady state • Dynamic

– Coordination of plans and operations • Existing and planned facilities • Interface with other entities (facility owners, ISO/RTO, etc.)

– Commercial aspects and cost recovery • Market issues • Transmission tariff

• Need for dynamic control is a key driver for FACTS versus conventional applications – Dynamic reactive support is the most common application of FACTS – SVCs and STATCOMs are often found near traditional HVDC installations

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Technical Study Considerations – HVDC and FACTS • Recognize control system interactions • Types of studies – – – – – –

Steady state Short circuit Harmonic Transient Stability analyses Protection and Control

• Consider normal and maintenance system conditions • Examine extreme contingencies

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Power Flow Analysis • • • • • • • •

Normal and contingency system transfer capability Loop flow Consistency with long-term system expansion needs Voltage performance Static and dynamic voltage control performance Losses Tap ranges for converter transformers Others

21

Short Circuit, Harmonic, Transient Studies • Short circuit – Short circuit ratio is critical for HVDC control design – Key driver of FACTS control design – Auxiliary transformers, etc. can contribute to short circuit

• Harmonic – Controls to reduce harmonics – Filtering requirements

• Transient – Insulation coordination – HVDC and FACTS response to contingencies and system recovery • Vital input to develop transient stability models, including unbalanced faults

– Subsynchronous torsional interactions 22

Stability Studies and Controls • Protect HVDC and FACTS – Converter blocks – Commutation failures – Integrity of station service

• Enhance system performance with auxiliary controls – – – –

Linear and non-linear controls Transient stability Dynamic stability Frequency response

• Auxiliary stability controls require proper settings – System swings are becoming more problematic as generators with significant inertia and reactive capability are displaced by low inertia, low reactive capability wind generators distant from the transmission network – Provide system damping – Reflect changes in the system

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Control System Issues • • • • • • • • •

Accurate models Acceptable system topologies Ramp rates Availability and failure modes Need for redundancy and monitoring of the status of key control systems Maintenance conditions Training of operating personnel Field tests Continued performance monitoring and adjustment

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Economic Evaluation • Compare HVDC and FACTS with other alternatives • Availability of facilities • Wholesale market and transmission tariff – – – –

• • • •

Who pays and who benefits? Energy Capacity Ancillary services

Related system improvements Regulated and merchant system improvements Operating and maintenance costs Load and no-load losses

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HVDC and FACTS Issues as Compared with Conventional Solutions • Cost Benefit Analysis – – – – –

Winners and Losers Energy Capacity Ancillary services Consider system improvements required for the HVDC

• Environmental impact • Reliability and Availability – Unwanted trips of controllers • Multiple controllers could trip for a common contingency

– Valve and other equipment failures – Maintenance and need for spare parts – System performance and robustness

• Operating Issues

26

Alternatives to HVDC and FACTS • Wire! – Isolate load and generation through radial interconnections of asynchronous systems – Transmission circuit additions

• Real power control – Phase angle regulators – Variable Frequency Transformers – Special protection systems, such as generation rejection and reactor insertions to achieve flow control

• Reactive power control – – – –

Switchable shunts Synchronous Condensers Generator clutch technology Special stability controls , such as Power System Stabilizers

27

HVDC Converter Stations contain components with varying design lives. To obtain the maximum life of the station, we must consider each element independently.

28

Typical HVdc Station Costs Valve & Controls 15% 5%

Filters 20%

Transformer 10% 15%

Civil Works & Installation Proj. Eng + Mangmnt Other

25%

29

Refurbishment and Replacement

30

Need for Refurbishments • System changes require updates – Short circuit availability

– System flows – Stability performance – Potential control system interactions – Harmonic performance

• Life of control systems – Issues with manufacturers support – Qualified personnel – Physical life of equipment – Desire for open architecture – Human – machine interface 31

Need for Refurbishments, cont. • Life of valves – Availability of spare equipment – Improved technologies

• Other considerations – state of the equipment – – – – – – – –

Firing and protection systems Transformers Filters Smoothing reactors Environmental Cooling systems Maintenance costs Outage coordination

• Monitor performance and lost opportunity costs 32

Typical Life of Components Component

Expected Lifetime (Years)

Converter and SVC Transformers

40

Thyristor Valves

30

HVDC Controls and Protection (Analog)

25

HVDC Controls and Protection (Digital)

15

Valve Hall Cooling

20

Thyristor Valve Cooling Systems (Wet Surface Cooling Tower)

15

Thyristor Valve Cooling Systems (Dry Surface Cooling Tower)

20

DC Smoothing Reactors (Air Core)

25

DC Smoothing Reactors (Oil Filled)

35

DC Filters

20

Ground Electrode

40

33

The Plan

34

Be Careful! Compare lifetime costs and performance with alternative plans

• • • •

Converter station costs Harmonics Losses in the converter Space for converter station and associated equipment • VAR consumption for line commutated converters • Control • Training of personnel

35

36

37

38

Source: ABB 39

40

HVDC and FACTS Lessons Learned

41

42

Lessons Learned •

Effective communication is required for: – – – –

•

Planning Engineering Constructing Operating

Extensive planning studies and adequate modeling of the control systems are required – The AC and DC systems interact – Contingencies on one side of an asynchronous tie can affect the remote system

• • •

Field Tests are necessary to verify the design and performance of the installation Shakedown Period is required prior to declaring commercial operation System Events and Future System Improvements should be captured – Verify and Update models – Revisit Operating Procedures

•

Watch System Protection and Control System designs and responses, especially as the system evolves – Ensure consistency with desired performance 43

Lessons Learned, cont. • Studies require extremely detailed evaluations of multiple system conditions • Increased use of power electronics on the system is giving rise to new interactions • Many system changes will require transient studies prior to approving final system plans • Additional system upgrades may be necessary to supplement the HVDC and FACTS projects 44

Applications • Chateauguay – Asynchronous interconnection between NY and Quebec – Weak AC system  need for special stability controls

• Phase I/II – Asynchronous interconnection between NY and Quebec – Long distance – over 900 miles long

• Cross Sound Cable – Merchant HVdc facility between CT and LI

• Highgate – Asynchronous interconnection between New England and Quebec – Refurbishment

45

Chateauguay • Field tests and system events demonstrated need to: – – – – – –

Remain mindful of DC/AC system interactions Fully understand system controls Continue monitoring performance Have proper models Modify controls Coordinate the planning and operation of the facility

• Controls have since been replaced with the same functionality

46

Sandy Pond Phase II HVDC Interconnection

47

System Inertia Results in Power Swing towards New England for l/o Phase II HQ Phase II 2000 MW

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Summary and Conclusions

49

Summary •

HVDC and FACTS Controllers have been applied successfully – – – – –

• •

Transient and Dynamic Stability Voltage Control Asynchronous and Synchronous HVDC interconnections Submarine installations Over long distances and in areas with limited rights-of-way (ROW)

Compare costs and performance of HVDC and FACTS with conventional solutions Many potential future system needs will likely be met with conventional solutions rather than HVDC and FACTS – Damp Dynamic Oscillations – Dynamic Voltage Support – Steady State MW Control

•

HVDC and FACTS Controllers have many potential applications – HVDC is a likely solution to gain access to renewable resources in Northern New England and Canada – HVDC has potential use underground and underwater – Shunt FACTS solutions are likely to be realized – Few applications of series FACTS controllers anticipated 50

Conclusions •

Deregulated structure of the electric power industry results in – Increased variability in network conditions – Need for robust solutions – Better use of existing infrastructure

•

Apply HVDC when – – – –

•

Need for control of real power Interconnecting asynchronous systems Power is transmitted over long distances Less expensive option, such as long submarine ties and areas with limited ROWs

Apply FACTS when – Dynamic control, typically voltage control, is required – Cost and performance are favorable compared with conventional options

•

Study process – Feasibility studies – Detailed modeling of the HVDC and FACTS facility – Finalize network plan

51

Conclusions, cont. • Coordination between planning and operating personnel is critical – Implement procedures that are as simple as possible – Maximize the secure and economical operation of the facility and the overall network

• Account for network, HVDC, and FACTS control system interactions • Conduct field tests and continue monitoring of key parameters – Confirm models 52

“Prediction is very difficult, especially with respect to the future!” Yogi Berra

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May all of your happy plans be fulfilled!

Thank you for your time and attention!

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1

HVDC Technology Voltage Source Converters Neil Kirby – General Electric – IEEE PES T&D Expo, Dallas, May 2016

2

Voltage Source Converters • • • • • • • • •

Introduction Circuit Configurations Converter Operation Converter Fault Response Real / Reactive Power Converter Arrangements Main Circuit Equipment Station Layouts Multi-Terminal HVDC

3

Introduction • Voltage Source Converter HVDC – GE HVDC MaxSine™ – ABB HVDC Light™ – Siemens HVDC Plus™

• Based on Transistor rather than Thyristor – IGBT or similar

• Simpler Transformers – No DC Stress – Reduced Harmonics

• Simple Buildings

4

VSC Circuit Configurations Symmetrical Monopole

~

Asymmetrical Monopole

~

Asymmetrical Monopole with Earth Return

~

= = = ~

=

= =

= =

~ ~

~ ~

Bipole

~ =

=

~

VSC-HVDC 2 Basic Approaches •Series-Connected IGBTs Conceptually simple circuit Requires PWM  High switching losses  Harmonic problems from PWM +V

•Multi-level circuit Low switching losses Easily “scaleable” Virtually no harmonics More complex controls +V

+V

+V

-V -V -V

+½Udc

+½Udc

U

U

-½Udc

-½Udc

-V = chain link module

6

VSC Converter Operation • Modular Multilevel Converter (MMC) • Individually switched modules • Synthesized/Generated AC Waveform Inverter Operation

Rectifier Operation

LCC Valve Winding Voltage

V

V

+Idc/3 +Idc IGBT1 or D2 0

I IGBT1 or D2

IGBT1 or D2

I

IGBT2 or D1

0 IGBT2 or D1 -Idc -Idc/3

Current reverses polarity for 120°. This is ESSENTIAL for capacitor charge balancing!

Current reverses polarity for 120°. This is ESSENTIAL for capacitor charge balancing!

IGBT2 or D1

7

VSC Converter Operation 1

1

/3IDC

1

/2IAC(pk)

1

/2IAC(pk)

AC Current DC Current

/3IDC

1

/2IAC(pk)

1

/2IAC(pk)

Idc I valve  3 1

/2IAC(pk)

1

/2IAC(pk)



ˆIac  sin (  t ) 2

{

/3IDC

{

1

Real Power Only

Real + Reactive Power

VSC versus LCC HVDC Line-Commutated Converter (LCC) HVDC VDC_B

VDC_A IDC

Converter A

Voltage-Sourced Converter (VSC) HVDC

IDC

RDC

Converter B

Converter A VDC_A

IDC

Power flow B → A

IDC

VDC_B

RDC

Converter B

VDC_B

VDC_A

VDC_A

VDC_B

Power flow A → B

Power flow B → A

VDC_A VDC_B

VDC_B

VDC_A

IDC

Power flow A → B

Clearance of DC Side Faults - Today Line Commutated Converters use the power electronics as the Primary Protection

Voltage Source Converters use the mechanical AC breaker as the Primary Protection

Converter DC Side Faults 1.50 1.00

DC Pole 1 Voltage

0.00 -0.50 -1.00 -1.50 -2.00

DC Pole 2 Voltage

20.0

DC Current

(kA)

1. Faults across high impedance ground = High voltage

(pu)

0.50

0.00 0.0990

0.1000

0.1010

0.1020

0.1030

0.1040

0.1050

0.1060

0.1050

0.1060

1.50 1.00

DC Pole 1 Voltage

(pu)

0.50 0.00 -0.50

DC Pole 2 Voltage

-1.00 -1.50

-2.00 20.0

2. Fault across the converter = High current

(kA)

DC Current 0.00 0.0990

0.1000

0.1010

0.1020

0.1030

0.1040

Clearance of DC Side Faults - Future Full-Bridge Voltage source Converters use the power electronics as the Primary Protection

Half-Bridge Voltage Source Converters can use a hybrid DC breaker as the Primary Protection

12

Real / Reactive Power ΔV

XT ICONV

XLIMB 2

VAC

I

Vvsc VVSC

Equivalent Circuit

Im

d

Phasor Diagram

V Re Vac

13

Real / Reactive Power Reactive Generation Mode IAC

.

IAC XTX

Reactive Absorption Mode

.

IAC XLIMB

V3

V1

.

V2

.

IAC XLIMB IAC XTX

V2 V3

V1 IAC

XTX

XLIMB

IAC

Line-to-Ground AC System Voltage

Line-to-Ground Transformer Secondary Voltage

Line-to-Ground Valve Voltage

V1

V2

V3

DC Voltage

14

Real / Reactive Power +P (Inverter) Low AC Voltage High AC Voltage

Constant MVA

-Q

+Q

(inductive)

(capacitive)

-P (Rectifier)

15

Main Circuit Equipment • IGBT Converter Capacitor +ve Test Connection

Main Terminal 1

Capacitor -ve Main Terminal

HALF-BRIDGE POWER MODULE

Capacitor +ve Test Connection

Main Terminal 1

Main Terminal 2

Capacitor -ve Test Terminal

FULL-BRIDGE POWER MODULE

16

Converter Arrangements • Modular Flexibility

17

Main Circuit Equipment • Transformer – Galvanic isolation between the AC and DC systems – Provides voltage at a suitable level for the converter – Provide circuit impedance to facilitate load flow – Fault current limiting impedance – Limits effects of AC voltage variation on converter operation (tapchanger) – Extends range of var output at selected DC voltage and power electronic module current rating (tapchanger)

18

Main Circuit Equipment • Limb / Arm Reactor – Minimize bridge switching circulating current – Provide circuit impedance to facilitate load flow – Limit fault current – Air Core – Normally Outdoors

19

Main Circuit Equipment • Soft-Start Circuit – Energization Inrush Current Limit

20

Station Layouts

21

Station Layouts

South-West HVDC Converter Station – GE

Caprivi HVDC Converter Station – ABB

TransBay Cable HVDC Converter Station – Siemens

22

Multi-terminal HVDC • South-West Link (Sweden) Phase 2:

2 Converters

2 Converters (Sweden)

• 2 x VSC Converter Station in north • Connection of Barkeryd Converters to North

Phase 1: South West Link

2 Converters (Sweden)

•

4 x VSC Converter Stations

•

2 x 720MV links, +/- 300kV DC, Line+Cable

23

Multi-Terminal • Creating a Future DC Grid – DC Breakers – Alternative Converters • Full Bridge, etc

24

Questions?