Testing and commissioning of VSC HVDC systems

697
TESTING AND COMMISSIONING
OF VSC HVDC SYSTEMS
WORKING GROUP
B4.63
AUGUST 2017

Members
L. BRAND, Convenor AU J. LEMAN, Secretary US
J. LONCLE FR T. MAGG SA
A. ALEFRAGKIS NE T. MIDTSUND NO
P. BERMEL DE M. MINCHIN UK
S. COLE BE K. OU CN
G. DROBNJAK DE D. RUSSELL US
A. GUNATILAKE UK T. SAKAI JP
D. KELL CA K. SHARIFABADI NO
N. KIRBY US J. VARNANDER SE
Corresponding Members
M. MIHALCHUK CA
J. VELASQUEZ DE
R. POOLE UK
D.W. YOO KR
B.D. RAILING US
WG B4.63
Copyright © 2017
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TESTING AND
COMMISSIONING OF VSC
HVDC SYSTEMS
ISBN : 978-2-85873-400-9

TESTING AND COMMISSIONING OF VSC HVDC SYSTEMS
ISBN : 978-2-85873-400-9

3
EXECUTIVE SUMMARY
Voltage Source Converter (VSC) technology has emerged as a commercially viable alternative to Line
Commutated Converter (LCC) technology for certain applications of HVDC power transmission. With
the first commercial VSC projects commissioned in the late 1990s, at the time of the development of
this Technical Brochure there is over fifteen years of project and operational experience with this
technology. VSC has become the preferred, if not the only, choice of technology for specific
applications, including low power transfer applications, the connection of weak networks, offshore
wind farm connections and d.c. grid developments.
Commissioning occurs during the latter stages of an HVDC project. It allows the HVDC supplier to
verify and demonstrate the suitability of the installed equipment, the functional completeness of the
system and compliance with the requirements of the relevant contracts and specifications.
Commissioning also allows adjustments and optimisation to the HVDC system to be made and allows
the owners, developers and/or end-user of the HVDC system to witness and be satisfied that the
project and operational requirements have been demonstrated.
The process for the commissioning of VSC projects has developed over the first fifteen years of its
commercial operation, based initially on a similar process for commissioning LCC HVDC projects (i.e.
Cigre Technical Brochure 97) and expanded upon and modified by the suppliers of VSC technology.
Whilst there are many similarities in the processes and procedures for commissioning the two
technologies, there are some notable and significant differences that justify the need for a separate
technical brochure covering the commissioning requirements for VSC projects.
The activities of the working group are focused on a typical two terminal, “point to point” VSC HVDC
system. Some commentary regarding multi-terminal systems is included, although at the time of the
development of this technical brochure there has been limited experience with the commissioning of
multi-terminal VSC HVDC systems.
During commissioning of a VSC HVDC project, the HVDC equipment is verified in groups and in
conjunction with the C&P systems. Usually, this commissioning process can be divided into four major
parts:
 Factory tests - the verification of internal connections within the control cabinets and the
functional verification testing of the software performed off-site in the supplier’s factory prior
to the C&P equipment being sent tosite.
 Pre-commissioning tests – the equipment tests which are the electrical and mechanical tests
and simple functional tests performed on all installed items of equipment or plant.
 Subsystem tests – the proving of interconnection and functioning of all individual items of
equipment within a functional group (or subsystem) and that these items operate and interact
correctly.
 System tests - the start-up and testing of the complete HVDC System in operation starting
with the initial energisation of the equipment and ending with the total system in operation
and at full active and reactive power transfer.
Prior to delivering the HVDC C&P system to site the correct functioning and performance of the C&P
system hardware and software need to be verified before connection to the actual a.c. system.
Testing is carried out in two stages namely:
 Dynamic Performance Study (DPS) – the DPS is completed prior to testing, but simulations
and results are used as a benchmark during testing. The DPS typically comprises various
energisation scenarios, transient cases and fault cases and evaluates how the HVDC system
interacts with the simulated a.c.system.
 Factory testing of the control and protection systems - a series of tests of the project specific
control and protection hardware and software performed in the factory focusing on both
switching sequences, signal verifications and dynamic performance. The performance of the
control and protection system is tested in full at the factory whereas on site only a subset of
the performance can be demonstrated as it is impractical to initiate the full range of

4
operational and dynamic conditions, such as a.c. system faults, on an operational power
network.
Typical subsystems which are tested include cabling systems, a.c. protections and interlocking, main
circuit equipment, VSC valves, control and protection systems and other auxiliary systems (including
valve cooling, auxiliary power, fire systems, air handling systems and ground electrode systems). The
scope of subsystem testing, test procedures and acceptance criteria are supplier specific and the
recommendations of the supplier will drive these elements.
System testing is typically comprised of the following key testing activities:
 High voltage energisation - the staged energisation of the HVDC system. The total number of
stages during the initial high voltage energisation will depend on the location of high voltage
disconnectors and circuit breakers within the HVDC converter circuit.
 Terminal tests - also referred to as STATCOM tests, these tests are performed on the
converter terminal, disconnected from the d.c. cable/line and from the opposite converter
terminal. The terminal tests include a set of verifications in a.c. voltage control or reactive
power control mode that are conducted when the converter terminal is connected to the
adjacent a.c. network and deblocked for the first time.
 Transmission system tests - performed with the converter terminals interconnected via a d.c.
cable/line, these tests cover the verification of deblocking and blocking sequences as part of
the active power transmission configuration, the verification of active power control in
conjunction with the reactive power capability of each converter terminal, verifications of the
P-Q characteristic and step responses to verify stability of the transmission. Many of the
transmission system tests may be performed entirely at low active power, typically at around
0.2 p.u. of the rated power of the HVDC system. Some tests will however require high power
transmission, such as the performance testing, verification of the PQ characteristic and heat
run tests.
 Operation and integration tests – these tests cover control system changeovers, change of
control location, operation from a remote location, loss of telecommunications, loss of
auxiliary power and operation under black start conditions (if applicable).
 Power quality and interference tests – tests that include testing of harmonics, audible noise
and interference.
 A.c. network and remote generation interaction tests - including verifications of staged fault
scenarios, run-back schemes, special protection schemes, islanded mode of operation,
voltage/frequency control, damping controls and other interactions. Any special tests to verify
compliance with the grid code and/or the requirements of the owner and/or operator of the
nearby a.c. network may also be required.
For VSC HVDC systems, it is typical for a period of trial operation to take place following the
completion of the system tests. The duration, purpose and requirements of the trial operation period
is typically as agreed between the owner and the supplier and is usually defined in the contract
documents and/or the technical specifications.
A key element of the commissioning of VSC HVDC systems is the management of the commissioning
process and coordination with external stakeholders. The challenges can include ensuring sufficient
testing is performed to enable customer acceptance and/or demonstration of compliance to
transmission grid codes, ensuring that the relevant stakeholders are informed of progress and notified
of changes to the commissioning program and coordinating the availability of the required power
flows and test energy to enable commissioning tests to be performed.
Some key issues associated with practical approaches to the commissioning of VSC HVDC systems in
today’s environment are covered at a high level within this Technical Brochure including guidelines on
determining the site test matrix and how to select a subset of the factory testing program to be
repeated on site, some practical limitations to performing site testing and how these can be addressed
and some commissioning issues specific to certain applications (such as off-shore wind, multi-terminal
systems, offshore platform loads and interactions with parallel power lines).
The scope, test procedures and acceptance criteria detailed within this Technical Brochure should be
considered as guidelines only.

5
CONTENTS
EXECUTIVE SUMMARY .............................................................................................................................3
1. INTRODUCTION.............................................................................................................................9
1.1 STATEMENT OF PURPOSE ...............................................................................................................................................9
1.2 TERMS OF REFERENCE....................................................................................................................................................10
2. OVERVIEW OF VSC HVDC TRANSMISSION ........................................................................ 13
2.1 VSC CIRCUIT CONFIGURATIONS................................................................................................................................13
2.2 CONTROL MODES AND OPERATING STATES..........................................................................................................14
3. STAGES AND SEQUENCE OF VSC COMMISSIONING....................................................... 17
3.1 OVERVIEW OF VSC TESTING AND COMMISSIONING PROCESS......................................................................17
3.2 FACTORY TESTS...............................................................................................................................................................19
3.3 PRE-COMMISSIONING ..................................................................................................................................................19
3.4 SUBSYSTEM TESTS...........................................................................................................................................................19
3.5 SYSTEM TESTS ..................................................................................................................................................................20
3.6 CUSTOMER ACCEPTANCE TESTS AND GRID CODE COMPLIANCE TESTS.........................................................21
3.7 EXPECTED CHALLENGES ................................................................................................................................................22
4. OFF-SITE TESTING OF THE HVDC CONTROL AND PROTECTION SYSTEM ……………25
4.1 DYNAMIC PERFORMANCE STUDY (DPS) ...................................................................................................................25
4.2 FACTORY TESTS OF THE C&P SYSTEMS....................................................................................................................25
4.3 INTERACTION STUDIES...................................................................................................................................................27
5. SUBSYSTEM TESTING................................................................................................................. 31
5.1 POWER, CONTROL AND COMMUNICATION CABLING SYSTEMS.....................................................................31
5.2 A.C. PROTECTIONS AND INTERLOCKING.................................................................................................................32
5.3 MAIN CIRCUIT EQUIPMENT...........................................................................................................................................32
5.4 HVDC CONTROL AND PROTECTION SYSTEM .........................................................................................................33
5.5 AUXILIARY SYSTEMS.......................................................................................................................................................34
6. SYSTEM TESTING – GENERAL REQUIREMENTS.................................................................... 37
7. HIGH VOLTAGE ENERGISATION ............................................................................................ 39
7.1 INTRODUCTION...............................................................................................................................................................39
7.2 A.C. SWITCHYARD ENERGISATION............................................................................................................................39
7.3 A.C. FILTER ENERGISATION...........................................................................................................................................40

6
7.4 INTERFACE TRANSFORMER ENERGISATION.............................................................................................................41
7.5 BLOCKED CONVERTER ENERGISATION.....................................................................................................................42
7.6 ENERGISATION FROM D.C. SIDE (WHERE APPLICABLE) ........................................................................................43
8. TERMINAL TESTS ......................................................................................................................... 45
8.1 INTRODUCTION...............................................................................................................................................................45
8.2 FIRST DEBLOCK ................................................................................................................................................................46
8.3 PROTECTIVE ACTION TESTS..........................................................................................................................................47
8.4 CHANGE OF CONTROL MODES.................................................................................................................................48
8.5 REACTIVE POWER CONTROL (RPC)............................................................................................................................49
8.6 A.C. VOLTAGE CONTROL (ACVC) ..............................................................................................................................50
8.7 STEP RESPONSES.............................................................................................................................................................51
9. TRANSMISSION TESTS............................................................................................................... 53
9.1 INTRODUCTION...............................................................................................................................................................53
9.2 ENERGISATION OF D.C. CABLE/LINE .........................................................................................................................54
9.3 FIRST POWER TRANSMISSION.....................................................................................................................................55
9.4 TEST OF ACTIVE POWER CONTROL AND STEADY STATE TESTS ........................................................................56
9.5 TEST OF A.C. VOLTAGE CONTROL AND REACTIVE POWER CONTROL MODES AT LOW ACTIVE
POWER ...........................................................................................................................................................................57
9.6 STEP RESPONSES.............................................................................................................................................................59
9.7 HIGH POWER TRANSMISSION TESTS........................................................................................................................60
9.8 CHANGES OF D.C. CONFIGURATION.......................................................................................................................62
9.9 HEAT RUN TEST (INCLUDING OVERLOAD)................................................................................................................63
10. OPERATION AND INTEGRATION TESTS ................................................................................ 67
10.1 CONTROL SYSTEM CHANGEOVERS (LOSS OF REDUNDANT EQUIPMENT).....................................................67
10.2 CHANGE OF CONTROL LOCATION...........................................................................................................................68
10.3 REMOTE CONTROL APPLICATION ..............................................................................................................................70
10.4 LOSS OF TELECOMMUNICATIONS TESTS - GENERAL ...........................................................................................71
10.5 STATION-STATION COMMUNICATIONS FAILURE TEST.........................................................................................71
10.6 REMOTE CONTROL CENTRE – CONVERTER STATION COMMUNICATIONS FAILURE TEST ………………72
10.7 LOSS OF AUXILIARY POWER SUPPLIES.....................................................................................................................73
10.8 BLACK START (IF APPLICABLE)......................................................................................................................................74
11. POWER QUALITY AND INTERFERENCE TESTS ...................................................................... 77
11.1 A.C. AND D.C. HARMONIC MEASUREMENTS...........................................................................................................77

7
11.2 AUDIBLE NOISE ................................................................................................................................................................79
11.3 INTERFERENCE MEASUREMENTS..................................................................................................................................80
12. A.C. NETWORK INTERACTION TESTS..................................................................................... 83
12.1 PRECONDITIONS OF A.C. NETWORK AND REMOTE GENERATION INTERACTION TESTS ……………….83
12.2 TRANSMISSION NETWORK SWITCHING AND STAGED FAULTS........................................................................83
12.3 SPECIAL PROTECTION SCHEMES.................................................................................................................................84
12.4 TESTING OF A.C. NETWORK AND CONTROL INTERACTIONS............................................................................84
12.5 TESTING POWER OSCILLATION DAMPING .............................................................................................................85
12.6 TEST OF SSR DAMPING CONTROLS ..........................................................................................................................85
12.7 VERIFICATION OF NON-EXISTENT CONTROL INTERACTIONS............................................................................85
12.8 INTERACTIONS WITH OTHER HVDC LINKS (AND OTHER FACTS DEVICES)......................................................85
13. TRIAL OPERATION ...................................................................................................................... 87
13.1 INTRODUCTION...............................................................................................................................................................87
13.2 PURPOSE OF TEST...........................................................................................................................................................87
13.3 TEST PRECONDITIONS....................................................................................................................................................87
13.4 TEST PROCEDURE.............................................................................................................................................................88
13.5 TEST ACCEPTANCE CRITERIA ........................................................................................................................................89
14. COMMISSIONING MANAGEMENT AND COORDINATION .............................................. 91
14.1 COMMISSIONING PLANNING.....................................................................................................................................91
14.2 CUSTOMER ACCEPTANCE / GRID CODES................................................................................................................92
14.3 SPECIAL PROTECTION SCHEME AND/OR RUN-BACK SCHEMES ........................................................................93
14.4 COORDINATION OF TEST ENERGY............................................................................................................................93
14.5 SITE MANAGEMENT DURING COMMISSIONING...................................................................................................94
14.6 HEALTH AND SAFETY AND ENVIRONMENT..............................................................................................................95
14.7 TRAINING OPPORTUNITIES FOR OWNER STAFF....................................................................................................96
15. DOCUMENTATION..................................................................................................................... 97
15.1 SITE TEST OUTLINE...........................................................................................................................................................97
15.2 TEST PLAN..........................................................................................................................................................................98
15.3 TEST SCHEDULE................................................................................................................................................................98
15.4 TEST PROCEDURES ..........................................................................................................................................................98
15.5 TEST RECORDS ................................................................................................................................................................ 99
15.6 FINAL REPORT...................................................................................................................................................................99

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16. KEY ISSUES AND CHALLENGES ............................................................................................... 101
16.1 RELATIONSHIP BETWEEN FACTORY TESTS AND COMMISSIONING TESTS......................................................101
16.2 PRACTICAL LIMITATIONS OF SITE TESTING..............................................................................................................102
16.3 COMMISSIONING ISSUES SPECIFIC TO CERTAIN APPLICATIONS......................................................................104
APPENDIX A – DEFINITIONS AND ABREVATIONS…………………………………………109
A.1. SPECIFIC TERMS ............................................................................................................................................................109
A.2. ABBREVIATIONS............................................................................................................................................................109
APPENDIX B – REFERENCES………………………...………………………………………111
APPENDIX C – SAMPLE TEST MATRIX…………………………………………………....…112
APPENDIX D – TEMPLATE OF FINAL COMMISSIONING REPORT………………………….117
FIGURES AND ILLUSTRATIONS
Figure 2-1 - Symmetrical Monopole Configuration......................................................................... 13
Figure 2-2 - AsymmetricalMonopole Configuration....................................................................... 13
Figure 2-3 - Bipole Configuration ................................................................................................ 14
Figure 3-1 - Overview diagram of the VSC Testing and Commissioning Process .............................. 18
Figure 3-2 - VSC HVDC System Structure and Definition of Terms ................................................. 18
Figure 6-1 – Scope of System Testing......................................................................................... 37
Figure 8-1 – Typical Terminal tests ............................................................................................. 45
Figure 9-1 -Typical Transmission Tests........................................................................................ 54
Figure 15-1 - Typical On-Site Commissioning Documentation........................................................ 97
TABLES
Table 3-1 - Typical Structure ofSystem Tests .............................................................................. 20
Table 5-1 - Typical Subsystem Testing of Main Circuit Equipment .................................................. 32
Table 10-1 – Typical Operation and Integration Tests .................................................................. 67
Table 10-2 - Control Location Combinations ................................................................................ 69

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1. INTRODUCTION
Voltage Source Converter (VSC) technology has emerged as a commercially viable alternative to Line
Commutated Converter (LCC) technology for certain applications of HVDC power transmission. With
the first commercial VSC projects commissioned in the late 1990s, at the time of the development of
this Technical Brochure there is over fifteen years of project and operational experience with this
technology. VSC has become the preferred, if not the only, choice of technology for specific
applications, including low power transfer applications, the connection of weak networks, offshore
wind farm connections and d.c. grid developments.
The scope of testing, test procedures and acceptance criteria are often project and supplier specific
and the recommendations of the supplier will often drive these elements. The types of tests
performed, objectives, procedures and acceptance criteria for a particular HVDC system may deviate
from the guidance presented in this Technical Brochure, depending on the particular application, the
HVDC system topology, the a.c. network conditions and/or the technology applied. The scope, test
procedures and acceptance criteria detailed within this Technical Brochure should be considered as
guidelines only.
1.1 STATEMENT OF PURPOSE
Commissioning occurs during the latter stages of an HVDC project. It allows the HVDC supplier to
verify and demonstrate the suitability of the installed equipment, the functional completeness of the
system and compliance with the requirements of the relevant contracts and specifications.
Commissioning also allows adjustments and optimisation to the HVDC control and protection system
to be made and allows the owners, developers and/or end-user of the HVDC system to witness and be
satisfied that the project and operational requirements have been demonstrated.
The process for the commissioning of VSC projects has developed over the first fifteen years of its
commercial operation, based initially on a similar process for commissioning LCC HVDC projects (i.e.
Cigre Technical Brochure 97 [1] and expanded upon and modified by the suppliers of VSC technology.
Whilst there are many similarities in the processes and procedures for commissioning the two
technologies, there are some notable and significant differences that justify the need for a separate
Technical Brochure covering the commissioning requirements for VSC projects.
This Technical Brochure summarises the work of Cigre Working Group B4.63 “Commissioning of VSC
HVDC Systems” and is intended to provide guidelines for the commissioning of VSC projects. As far as
possible, the Technical Brochure is independent of the specific VSC technology and the topology of
the HVDC system. A detailed description of the various topologies and technologies available for VSC
HVDC transmission is available in other Cigre technical brochures, for example TB-492 [2]. Whilst the
focus is on the VSC system, the separate testing of the d.c. cables and their accessories and d.c.
overhead lines is excluded from the scope of this Technical Brochure.
Whilst a significant portion of the guide deals with on-site commissioning activities, such as subsystem
testing, terminal testing and transmission testing, this Technical Brochure also addresses off-site
testing and the relationship between the on-site and off-site tests.
This document starts out by explaining, at a high level, the commissioning process for a typical VSC
HVDC system and introduces some of the particular challenges associated with commissioning VSC
projects which are explored in greater detail in Chapter 16. Chapter 2 provides an overview of key
concepts with regards to VSC HVDC systems and Chapter 3 explains the various stages and sequences
of commissioning a VSC HVDC system at a high level.
Chapter 4 provides an introduction to the off-site testing of the C&P system – a key part of the
commissioning process – and provides guidance on setting up the VSC simulation and factory tests
and the performance of the factory tests and EMT-type studies.
Chapters 5 through to 12 deal with the various stages of on-site testing, from the first energisation of
the VSC converters through to power quality, interference and a.c. network tests. Each stage is
broken down further into the key tests which would be expected to be undertaken, and for each of
these tests, the Working Group has sought to define the test objectives, procedure and, where
possible, acceptance criteria.

10
Chapter 13 deals with the issue of trial operation, including defining what the new owner and/or
operator seeks to achieve from the trial operation and suggested durations. Chapters 14 and 15 cover
the topics of commissioning management, coordination and documentation. In the regulatory
environment currently being experienced by developers and owners of HVDC systems, the importance
of keeping accurate and detailed records of the commissioning outcomes has increased whilst the
existence of electricity markets and multiple participants means that the coordination and
communication of commissioning activities is of vital importance.
Finally, Chapter 16 discusses some key issues and challenges associated with commissioning VSC
HVDC systems, including understanding the relationship between the off-site and on-site tests that
are undertaken and issues associated with specific applications for which VSC technology is often
implemented. This chapter also deals with how to verify or otherwise accept the handover of a facility
for which the maximum active and/or reactive power levels were not able to be achieved during
commissioning, for either a.c. network or market reasons.
1.2 TERMS OF REFERENCE
The Terms of Reference for Cigre Working Group B4.63 “Commissioning of VSC HVDC Systems” is
summarised below.
1. Review the work done by CIGRE and other relevant bodies related to the commissioning
of HVDC converter stations (e.g. WG14-12, TB 97) with a view to identifying significant
differences between commissioning of VSC projects and LCC projects. Review work done
to date on VSC commissioning, including the work done by WG B4-37 (TB 269).
2. Identify and develop the stages, sequence and structure for the commissioning of a VSC
project, focusing on the on-site system and acceptance test elements for commissioning
and also VSC specific equipment and subsystems (e.g. IGBTs and IGBT modules, phase
reactors etc.). Off-site tests shall also be covered at a high level and from the point of
view of its relationship with on-site testing.
3. Develop each stage of commissioning, including development of test objectives,
procedure and acceptance criteria and preferred location in the commissioning Related
CIGRE WG and TB structure. Stages will include:
a. Off-site testing (e.g. factory performance/system tests, dynamic tests);
b. Equipment and subsystem testing (only for VSC specific equipment);
c. Energisation tests;
d. Terminal (reactive power only) tests;
e. End to end / systemtests;
f. Steady state tests;
g. Power quality and interference tests;
h. Operation, black start and loss of auxiliary (disturbance) tests;
i. a.c. network interaction tests (e.g. staged faults, run-back and special protection
schemes);
j. Customer acceptancetests;
k. Trial operation;
and any other test stages identified by the WG members.
4. Develop guidelines and recommendations for:
a. Documentation of the commissioning plan and commissioning test results;
b. The relationship between the off-site and the site commissioning tests, including
selection of on-site test “cases” and the cross-correlation/verification of site
commissioning test results to the factory test results;
c. The specification of commissioning tests for VSC projects;

11
d. Demonstrating compliance with specifications in situations where actual power
flow conditions cannot be achieved in-situ (e.g. demonstration of the PQ curve at
high active and reactive powerlevels);
e. High level commissioning issues specific to certain applications including offshore
VSC converter stations and commissioning of d.c. grids;
f. Site management processes during commissioning and training opportunities for
owner staff.

12

13
2. OVERVIEW OF VSC HVDC TRANSMISSION
A number of Cigre publications and technical brochures related to VSC HVDC transmission provide
detail as to the operation of the VSC converters, how they differ from LCC converters and the various
technologies and topologies available (for example, TB 269 [3] and TB492 [2]). This chapter
summarises some key concepts that are referenced during or somehow affect the testing and
commissioning of the HVDC system – namely circuit configurations, control modes and operating
states.
2.1 VSC CIRCUIT CONFIGURATIONS
The range of circuit configurations in VSC HVDC is similar to that of the LCC. In a similar way to LCC
HVDC systems, VSC HVDC transmission systems use overhead line, submarine cable or underground
cable to connect the converters on the d.c. side. In the back-to-back configuration, the two converters
are located in the same converter station, and commissioning activity is localised to a single converter
station.
The following sections highlight the main circuit configurations for two-terminal, or point-to-point
systems, as covered in this Technical Brochure.
2.1.1 Symmetrical Monopole
At the time of the publication of this technical Brochure, the most common circuit configuration for
VSC HVDC transmission is the symmetrical monopole, as illustrated in Figure 2-1, where the d.c.
terminals of the converters are symmetrical with equal voltage and opposite polarity.
The failure of one part of the system, either in a d.c. conductor or the converters will result in total
loss of transmission capacity on the HVDC system.
Figure 2-1 - Symmetrical Monopole Configuration
2.1.2 Asymmetrical Monopole
The asymmetrical monopole configuration is illustrated in Figure 2-2, in which the d.c. side has a solid
ground connection at one converter, similar to the common LCC monopole circuit. The d.c. side of the
converters are therefore asymmetrical, with one at HVDC potential and the other at ground potential.
The failure of one part of the system, either in the d.c. conductor or the converters will result in total
loss of transmission capacity.
2.1.3 Bipole
The VSC-based bipole configuration is similar to the LCC Bipole circuit, utilising two independently
controlled asymmetrical monopoles, as illustrated in Figure 2-3.
Figure 2-2 - Asymmetrical Monopole Configuration

14
For a bipole circuit there is a need to provide either two or three conduction paths, one for each of
the HVDC pole converters, and one for the remainder of the current. In normal bipole operation, the
transmitted power is shared equally between the two converter poles. This means that the current
flowing in the low voltage neutral conductor is at, or rather near, zero, i.e. a balanced bipole. If the
power is shared unequally between the poles, then this unbalanced bipole operation leads to current
flowing in the neutral conductor.
In the event of the removal of one pole converter (either for maintenance or as the result of a fault),
the remaining converter will continue in operation, allowing the link to continue with 50% of the
nominal power transfer capability. This is the primary reason for selection of the bipole configuration
in many HVDC systems.
Any fault occurring in one converter will result in the removal of that converter and the corresponding
pole converter at the other end of the system.
2.2 CONTROL MODES AND OPERATING STATES
2.2.1 CommonControlModes
The control of the voltage presented by the converter on the a.c. terminals is enabled by the control
of energy flowing through the converter to or from the d.c. capacitance. This gives rise to several
modes of control through adjustment of both the phase angle and the magnitude of the a.c. voltage
relative to the a.c. network. These control modes are defined in Cigre Publication 269 [3], and are
summarised in the following sections.
There may be other control modes required for a specific project, such as a.c. network damping
controls, reduced d.c. voltage control, angle difference control and islanded operation mode, which
tend to be variations or modifications of these common control modes.
2.2.1.1 Active PowerControl
To control active power into or out of the a.c. system, the VSC HVDC system must have a means of
transferring active power into or out of the d.c. side. In a VSC HVDC system, this means that the
control of the converters at the two ends of the HVDC system must be coordinated and, generally,
one of the two converters will be responsible for the control of the active power.
Active power control is achieved by regulating the phase angle of the fundamental frequency
component of the a.c. voltage at the converter side of the interface reactance. Active power is drawn
from or pushed into the a.c. system depending on whether this phase angle lags or leads that of the
a.c. bus voltage.
2.2.1.2 D.C. Voltage Control
While one converter will be operating in active power control, the other will need to operate in a
control mode that sets and holds the d.c. voltage at a specific level. The d.c. voltage control sets the
d.c. voltage at one end of the VSC HVDC system to a specified d.c. voltage level, which allows the
Figure 2-3 - Bipole Configuration

15
converter in active power control (at the other end of the VSC HVDC system) to cause power to flow
on the d.c. side by adjusting its own d.c. voltage relative to the specified d.c. voltage at the other end.
2.2.1.3 A.C. Voltage Control
A.c voltage control regulates the flow of reactive power to or from the converter to achieve an a.c.
voltage level defined by a setpoint provided by the operator. This is achieved by regulating the
magnitude of the fundamental frequency component of the a.c. voltage generated at the VSC side of
the interface reactor and/or transformer.
If the VSC HVDC system is feeding into an isolated a.c. system with no other significant form of active
power source, the a.c. voltage controller will automatically control power to the load, assuming that
another converter terminal in the d.c. system independently controls the d.c. side voltage.
2.2.1.4 Reactive Power Control
The VSC HVDC converters can either generate or consume reactive power. This is done independently
of the other converters in the scheme and independently of the active power transfer, within the
bounds of the PQ characteristic. This is achieved by the converter adjusting its internal voltage until
the desired reactive power exchange is equal to requested setpoint values. Once a reactive power
control setpoint is entered, the converter will absorb or generate that amount of reactive power
independent of voltage variations of the a.c. network.
2.2.1.5 Frequency Control
Frequency control in VSC HVDC systems is normally either applied through the use of an internal
oscillator or using a phase locked loop control, according to whether it is the only source of generation
or contributing to maintenance of frequency along with other sources. In situations where no external
a.c. reference exists (such as in an islanded a.c. system or a “black start”) the internal control system
oscillator is used as the fundamental frequency reference, and the power flow through the converter
is varied dynamically in order to maintain constant frequency as a.c. network load is increased or
decreased.
Frequency control where the VSC HVDC system is sharing in the control of the a.c. system frequency,
is commonly applied in the form of a slope characteristic, where power flow through the converter is
controlled dynamically in magnitude and direction to maintain constant a.c. system frequency. The
ability of the VSC HVDC converter to have an influence on the a.c. system frequency is clearly
dependent on the relative capacities of the a.c. system and the d.c. link rating.
The on-site testing of frequency control is not specifically covered in this Technical Brochure. The
process for testing will be similar to those used for a.c. voltage control and reactive power control,
however as the operation of frequency control will affect the entire a.c. network, such test will require
careful coordination amongst stakeholders.
2.2.1.6 Power factor Control
Another way to regulate the reactive power flow is the power factor control mode, where the HVDC
converters are coordinated by the HVDC C&P systems in such a way that the HVDC converter stations
are capable of controlling the power factor at the connection point within the required reactive power
range at a target power factor.
The on-site testing of power factor control is not specifically covered in this Technical Brochure.
However, the process for testing will be similar to those used for a.c. voltage control and reactive
power control.
2.2.2 Operating States
The VSC HVDC transmission system may be capable of operating in any or all the following distinct
and mutually exclusive states:
 Earthed: pole/converter is isolated and earthed on the a.c. and d.c. sides, normally used for
safe maintenance work. The converter is not operational.

16
 Stopped/Isolated: Converter is isolated on both a.c. and d.c. sides, with all earthing switches
open.
 Standby/De-energised: Converter is not transmitting power, the auxiliary circuits and
secondary systems are all operational, the converter is not yet receiving control commands,
there is no high voltage feed from either the a.c. or d.c. side.
 Blocked: pole/converter is fully energised from either the a.c. or the d.c. side, the converter is
not yet receiving control commands. In many converter designs operation in the blocked state
is permitted only as a temporary condition as part of the energisation sequence.
 Deblocked: converter is energised from either the a.c. side or the d.c. side and receives
control commands to enable the VSC valves to be switched to allow where appropriate control
of the a.c. and d.c. terminal voltages of the converter.
 STATCOM mode: the converter is deblocked and fully energised from the a.c. side but the d.c.
side is either isolated or configured such that no active power is transmitted. The reactive
power can be controlled at the converter’s a.c. side and the d.c. bus voltage can be
controlled.
 Islanded/ d.c. connected mode: the converter at one end is connected via the d.c. system to
another converter which is connected to an islanded a.c. network. The converter connected
to the islanded network is able to control its a.c. voltage and frequency.
 Transmission Mode: the converter is deblocked and fully energised from the a.c. side and is
joined to one or more other converters via d.c. interconnections. The active and reactive
power and a.c. and d.c. voltages can be controlled.

17
3. STAGES AND SEQUENCE OF VSC COMMISSIONING
This section provides a descriptive overview of the stages and sequences of performing the
commissioning of a VSC HVDC system. It also provides a brief discussion on various challenges to be
expected during the commissioning process.
HVDC commissioning is the process of confirming that all systems and components in the HVDC
system are designed, installed, tested and can be operated in accordance with their functional and
operational requirements and that the behaviour of the HVDC system and its various components act
as expected.
The complexity of an HVDC system, and the diversified areas involved in the commissioning process,
require thorough planning and scheduling, cooperation of all involved parties and complete and
structured documentation. Commissioning management and coordination is covered in Chapter 14
and documentation in Chapter 15 of this Technical Brochure.
3.1 OVERVIEW OF VSC TESTING AND COMMISSIONING PROCESS
During the testing and commissioning of an HVDC project, the HVDC equipment is verified in groups
and in conjunction with the C&P systems. Usually, this testing and commissioning process can be
divided into four major parts; factory tests, pre-commissioning tests, subsystem tests and system
tests as shown in Figure 3-1.

18
Figure 3-1 - Overview diagram of the VSC Testing and Commissioning Process
The structure and sequence of the VSC commissioning process requires an understanding of the
overall VSC system structure and a definition of various components within this structure. Figure 3-2
shows an example of two parallel VSC HVDC systems along with a graphical representation of various
terms used in commissioning.
Figure 3-2 - VSC HVDC System Structure and Definition of Terms
Converter Station
HVDC System
Converter Terminal PCC
~
=
Converter
incorporating VSC valves
and phase reactors
~
=
~
=
a.c. yard
Interface
Transformer
PCC
d.c. line/cable
or d.c. grid
a.c.
system
~
=
HVDC Link

19
3.2 FACTORY TESTS
Whilst a significant amount of commissioning activity normally takes place on-site toward the end of
the project (and after equipment installation), there is one element that takes place off-site and prior
to installation. Factory tests can include the partial commissioning of the HVDC C&P systems in the
factory, as well as some other subsystems or components such as valve cooling systems, major items
of high voltage equipment and external protection systems. The part of factory testing covered by this
Technical Brochure, is the partial commissioning of the HVDC C&P systems in the factory.
The factory testing of the C&P systems covers the verification of internal connections within the
control cabinets and the functional verification testing of the software and is performed in the factory
prior to the C&P equipment being sent to site. This factory testing may also be referred to as the
factory system test (FST) or functional / dynamic performance test (FPT / DPT).
During the factory testing, the complete C&P systems are tested. External standalone equipment,
such as external protection relays, are typically excluded. Where other external interfaces are present,
the testing should be performed as completely as possible, to determine with as much confidence as
is practical that the C&P systems will operate correctly in terms of the expected input and output
signals. Such external interfaces include auxiliary power systems, converter cooling systems, fire
systems etc.
Finding and correcting hardware and software errors in the C&P systems is an important function of
factory testing. Such faults are easier to find and correct in the factory than during on-site testing and
commissioning. Correcting such faults reduces the probability and consequences of disturbing the
power system during the commissioning tests.
The factory testing of the C&P systems provides an opportunity to set up the parameters of the
control systems and to obtain a proof of performance and response of the equipment relative to the
specified requirements. The factory testing may also verify various protective functions of the HVDC
system under a.c. and d.c. fault conditions that may cause unacceptable disturbances on the a.c.
network if tested on site. Having this verification performed in the factory, with the system connected
to a real-time simulator, provides the opportunity to test functions of the C&P systems that would not
be practically or economically motivated to perform during the on-site testing.
The final stages of the factory testing may affect the development of the test schedule for system
testing. There may be some tests that have been identified as requiring specific consideration during
on-site testing or conversely the results of the factory tests may eliminate the need for a test to be
performed on-site. There may also be a requirement for future validation, particularly of the EMT-type
studies performed in the factory, and any such requirements identified during factory testing will drive
what system tests need to be done to perform this validation.
3.3 PRE-COMMISSIONING
The pre-commissioning phase commences on-site and covers the equipment tests.
Equipment tests are the electrical and mechanical tests and simple functional tests performed on a
single installed item of equipment or plant. The requirements for this testing typically apply to that
item of equipment regardless of the specific application and therefore the tests to be performed are
driven by the requirements of the supplier and/or the specific standards and guidelines applicable to
that type of equipment.
For this Technical Brochure, commissioning is considered to commence at the start of the subsystem
tests, and therefore this Technical Brochure does not cover pre-commissioning.
3.4 SUBSYSTEM TESTS
Subsystem tests prove the correct interconnection and functioning of all individual items of equipment
within a functional group (or subsystem) and that these items operate and interact correctly. A
subsystem can include groups of main circuit equipment and associated measurement systems (for
example, the IGBT valves, a filter yard, d.c. yard or interface transformer), C&P systems (for example,
pole controls, valve controls or cooling controls) or auxiliary systems (for example, equipment cooling
systems, auxiliary power systems, heating and ventilation and fire systems).

20
The objective of this stage of the commissioning process is to verify correct signals, values and
readings, the correct operation of control functions and the parameterisation of protective settings. It
can also include the dry-run of automated switching sequences, testing of cooling fans and systems,
testing of cooling systems and verification of the correct installation of cables and connections.
Subsystem testing is generally performed per functional group and consequently all equipment and
elements within that functional group must be ready for testing before that particular subsystem test
can commence.
3.5 SYSTEM TESTS
System tests cover the start-up and testing of the complete HVDC System in operation. System tests
are required to prove that the performance of the HVDC system meets certain technical requirements
when connected to the a.c. network. The structure of the system tests will typically follow the
structure of the HVDC system, starting from the smallest, least complex, operational unit, and end
with the total system in operation.
Table 3-1 provides an overview of the various components of systems tests for an HVDC system,
including the typical test groups which make up the system tests, the typical tests performed within
each test group and the parts of the HVDC system under test. These commissioning test groups will
be typically performed in the order as shown in Table 3-1. The sequence would typically start at the
local level with tests within each converter terminal performed and completed before moving on to
the remote converter terminal, the complete HVDC transmission system and any interfaces such as
SCADA and remote control systems. The order and sequence of the test groups as shown in Table 3-1
follows these principles.
Table 3-1 - Typical Structure of System Tests
Tests Equipment Under Test
High Voltage Energisation Tests
1) Supplier specific preparation tests
2) Final trip tests
3) A.c switchyard energisation
4) Interface transformerenergisation
5) Blocked converter energisation
Terminal Tests
1) First Deblock
2) Protective Action Tests
3) Change of Control Modes
4) Reactive Power Control (RPC)
5) A.c. Voltage Control (ACVC)
Transmission Tests
1) Energisation of d.c. Cable/Line
2) First Power Transmission
3) Test of Active Power Control (APC)
and Steady State Tests
4) Test of Reactive Power Control
Modes at Low Active Power
5) High Power Transmission
6) Step Responses
7) Remote Control Application
8) Heat Run Test
Operation and Integration Tests

21
Tests Equipment Under Test
1) System Changeover
2) Change of Control Location
3) Loss of Telecommunication
4) Loss of Auxiliary PowerSupplies
5) Loss of Redundant Equipment
6) Black Start (if applicable)
Power Quality and Interference Tests
1) A.c. and d.c. Harmonic
Measurements
2) Audible Noise
3) Interference Measurements
Trial Operation
After all preconditions for system testing are fulfilled (refer Chapter 6), system testing commences
with the performance of the energisation tests at the converter unit level, which includes final trip
tests and the energisation of the a.c. and d.c. yards, valves and filters (if any).
Following a successful start-up and energisation of the converter terminal, terminal tests may begin.
Terminal tests are performed at each terminal, with the converter terminal being connected to the
adjacent a.c. network but disconnected from the d.c. cable/line. The terminal tests will verify the
majority of C&P modes and functions for the HVDC converter and successful operation of the
converter terminal in STATCOM mode.
The transmission tests (sometimes referred to as end-to-end tests) start when both converter
terminals have completed their terminal tests. These start with the energisation of the d.c. cable/line
and move on to first active power transmission and operation in various combinations of control
modes at various power levels. If the HVDC system is a bipolar system, the transmission tests should
be performed on a monopolar basis first and then move on to bipolar operation. The transmission
tests conclude with full power transmission at various operating positions on the PQ Characteristic and
a final heat run test if possible.
With the complete system verified as running correctly, the performance of the HVDC system in
steady state operation is verified. With normal operating ramp settings and automatic switching
sequences in place, the operation, network interaction, power quality, interference and disturbance
tests can be performed. In some cases, the transient performance and behaviour during faults may be
verified. Some disturbance testing, such as staged faults, are dependent on approval from regulatory
bodies and the nearby utility and the availability of the a.c. network to accommodate such testing and
is not always practical to perform on-site.
3.6 CUSTOMER ACCEPTANCE TESTS AND GRID CODE COMPLIANCE TESTS
Any customer acceptance tests and grid code compliance tests that have not been covered in earlier
stages of the commissioning process are typically performed during the final stages of system testing.
Depending on the commercial requirements of the project, this could be prior to commencement of
trial operation or during trial operation.
Typically, customer acceptance testing is a compilation of tests which are designed to demonstrate
particular specification and/or jurisdictional requirements and are performed at various stages of the
commissioning process. These may relate to the demonstration of certain requirements for connection
to the a.c. network and/or of the local grid code, or may be tests requested by other parties as a part
of the connection process. Grid code compliance testing is often a requirement for the HVDC system

22
to be connected to the adjacent a.c. network in commercial operation. These requirements differ
between jurisdictions and transmission grids and therefore tend to be specific requirements for a
particular project.
Customer acceptance tests could also include the verification measurements of audible noise,
harmonics, interference and heat/load run tests.
Some components of customer acceptance testing may have been performed wholly or in part during
factory testing and pre-commissioning testing and in some cases during design and manufacturing. To
avoid the unnecessary duplication of tests, careful consideration should be given in advance as to
when and at what stage in the project and/or commissioning process certain customer acceptance
tests are carried out.
Customer acceptance typically concludes on completion of a trial operation period. After the successful
completion of all other test groups related to commissioning, and in some cases the achievement of
certain technical or commercial pre-requisites, the trial operation commences. During trial operation,
the new HVDC system is operated by owner’s personnel and utilised in the manner as anticipated by
the design and technical specification and as intended by the owner. Various performance
measurements may be conducted during trial operation. The extent of the trial operation is
determined in contractualagreements.
Depending on contractual agreements, some customer acceptance tests may also be performed
during the trial operation where normal operation of the HVDC system is required.
3.7 EXPECTED CHALLENGES
This section provides some commentary on some challenges which may be faced by the owners and
developers of HVDC systems during the commissioning process.
3.7.1 ExternalPartyRequirements
The commissioning of an HVDC system demands planning and coordination between several parties,
and it is not unusual that an external party is required to be a part of the detailed commissioning
planning. This external party could be, for example, the owner and/or operator of the adjacent a.c.
network to which the HVDC system is to be connected. Depending on the jurisdiction, the external
party could impose limitations in terms of the availability of power transfer, the timing of certain tests
and which tests can be performed on-site to ensure their network remains stable during the
commissioning and operation of the HVDC system.
Another example may be the case of interconnection of an offshore wind farm to the onshore grid
through an HVDC system. In this case, the configuration and commissioning of the wind farm should
be coordinated with the commissioning of the HVDC system.
In both of these examples, the external parties may need to be included in the planning of the
commissioning process and in the specification and coordination of particular tests.
In order to assist with overcoming the above challenges, the affected external parties should be
identified early in the project and/or commissioning process and consideration should be made very
early in the commissioning planning process regarding meeting the requirements of these parties.
This will assist in defining and reaching agreement on the specific procedures that need to be
followed, overall coordination process and the development of the commissioning program. For
example, for some HVDC projects in certain jurisdictions, there may be a requirement to form a
commissioning panel or working group in the planning stages which includes the supplier, owner,
developer, the owners and operators of the adjacent a.c. networks, and any other parties which need
to be consulted in the planning stages of the project to ensure successful execution of the
commissioning process.
During the coordination process and the planning of the commissioning for the HVDC link, the owner,
developer and/or supplier may need to exchange certain information with the external parties to
facilitate reaching agreement, including:
 Technical data to identify the operating parameters of the HVDC system;
 HV switching processes and schedules;

23
 PQ characteristic of the HVDCsystem;
 Test approach andmethodology;
 Active and reactive power profiles; and
 Test acceptance criteria.
The management of this issue is discussed further in Chapter 14 of this Technical Brochure.
3.7.2 Availability of Power
The system testing stage, particularly low and high power transmission testing, presents the highest
risk to the connected a.c. network. During this period, it is possible for the system to block and/or trip
unexpectedly, at various levels of both active and reactive power, which may adversely affect the a.c.
network. These risks can be managed through the limitation and careful selection of the number and
types of tests which are performed on-site to minimise risks to the stability of the adjacent a.c.
network in the event of a failure of a block or trip during the commissioning tests. Generally, these
power transmission tests will be a subset of those performed during the factory testing. This topic is
addressed in more detail in Section 16.1.
The commissioning tests also introduce a new factor in that the amount of active and/or reactive
power that the HVDC system can transfer and/or absorb may be limited by constraints in the adjacent
a.c. networks. These constraints can be driven by thermal limitations of the connecting a.c. lines,
stability concerns or, in the case of reactive power transfer, concerns regarding high or low a.c.
voltage levels.
These active and reactive power limitations create challenges when undertaking commissioning tests
to demonstrate the PQ Characteristic of the HVDC system. Demonstrating that the HVDC system can
operate at the extremes of its PQ Characteristic is one of the fundamental requirements of the
commissioning process for a VSC HVDC system. In some instances, the owner and/or operator of the
adjacent a.c. network may not be able to permit the active or reactive power flows (or both at the
same time) required to allow a verification of the PQ Characteristic on-site. In the case of HVDC
systems connecting remote generation, this situation is exasperated if the remote power stations or
wind turbine generators are not yet installed to the final rating at the time the power is required for
the HVDC system commissioning.
The management of this issue is discussed further in Chapter 14 and Chapter 16 of this Technical
Brochure.
3.7.3 Commissioning in an Electricity Market
Many HVDC systems are being connected either within an electricity market or energy exchange or
connecting two markets/exchanges. This introduces a complexity and potential limitation to the
commissioning process that was not evident during the commissioning of earlier HVDC systems.
Experience has shown that if electric power is traded in an electric power market, it may not be
possible to secure enough power for the required time period to perform certain high power
transmission tests due to market constraints, even where the a.c. networks are technically able to
deliver the required power flow. This can particularly affect transmission tests where high power flows
are required to be held at a certain level for a period of time, such as the heat run test.
The management of power flows within the energy market requires careful coordination. Often the
required power levels for testing purposes are to be scheduled in the market in advance and in some
cases any shortage of power transmission in the event that the HVDC system under commissioning
can either not achieve the level or trips/blocks during testing is subject to penalties. There is also a
cost implication where a team is mobilised at multiple locations to perform a commissioning test but
the power flows cannot be achieved, requiring demobilisation and later re-mobilisation of the
commissioning team.
These market restraints may have an impact on the economical and practical execution of the
commissioning process. The management of this issue is discussed further in Chapter 14 and Chapter
16 of this Technical Brochure.

24

25
4. OFF-SITE TESTING OF THE HVDC CONTROL AND
PROTECTION SYSTEM
Prior to delivering the HVDC C&P system to site, the correct functioning and performance of the C&P
system hardware and software needs to be verified before connection to the actual a.c. system. This
is achieved through off-site factory tests that incorporate simulations and results from the Dynamic
Performance Study (DPS) completed prior to testing.
4.1 DYNAMIC PERFORMANCE STUDY (DPS)
One key stage of testing the HVDC C&P system is to compare its performance to simulated results
from the Dynamic Performance Study (DPS). The DPS is completed prior to testing, but simulations
and results are used as a benchmark during testing. The DPS typically comprises various energisation
scenarios, transient cases and fault cases and evaluates how the HVDC system interacts with the
simulated a.c. system.
Whilst not necessarily a commissioning test in itself, the DPS is an important stage in the verification
of the C&P system and the outputs of the DPS are often used for comparison at a later stage to verify
system test results.
The DPS is carried out using EMT-type software together with a comprehensive EMT-type model, in
which the equivalent a.c. system and the HVDC system, including a representation of the actual C&P
software, are modelled.
A great deal of work is put into ensuring that the EMT-type model of the C&P system represents the
actual hardware and software as accurately as is practical. The EMT-type model is used for the initial
design and tuning of the C&P system, with the settings determined during the DPS being used directly
in the final C&P software.
The EMT-type software is typically an electromagnetic transient simulation tool that runs the same
EMT-type models as used on the real-time simulator, just not in real-time.
The use of an accurate EMT-type model facilitates the off-line study of events expected during the on-
site testing (and later commercial operation) to allow the verification of C&P system performance
during these events and find faster solutions for any unexpected behaviour.
4.2 FACTORY TESTS OF THE C&P SYSTEMS
The factory tests of the C&P systems are a series of tests of the project specific C&P hardware and
software focusing on switching sequences, signal verifications and dynamic performance.
The factory testing of the C&P system is considered an important part of the overall commissioning
process, in the sense that the performance of the C&P system is tested in full at the factory whereas
on site only a subset of the performance can be demonstrated as it is impractical to initiate the full
range of operational and dynamic conditions such as a.c. system faults on an operational power
network.
4.2.1 Equipment Used for Factory Tests
In order to perform the factory tests, the following equipment will be used;
 The actual HVDC C&P systems hardware or equivalent replica of the hardware;
 The actual HVDC C&P systemsoftware;
 A real-time simulator;
 A detailed EMT-type model of the HVDC system on real-time simulator; and
 An EMT-type representation of the a.c. system on the real-time simulator.

26
4.2.1.1 HVDC Control and Protection
The actual C&P hardware and C&P software to be shipped to the site will typically be connected to a
real-time simulator and tested in real-time during the factory testing. In some cases, a replica of the
C&P hardware can also be used to accelerate the factory testing schedule.
The testing of external interfaces and cubicles that do not participate in the factory testing is carried
out separately, either as a part of other factory tests by the respective supplier or as part of the
equipment or subsystem tests performed on-site. Common external interfaces or items that are not
covered in the factory testing include a.c. protection relays, ventilation, cooling systems and fire
protection systems.
4.2.1.2 Real-time Simulator
The real-time simulator is a set of test laboratory equipment with integral software that enables
representation in real time of the a.c. system and the HVDC system using an EMT-type model. For
the purpose of carrying out factory tests, the real-time simulator is connected to the C&P system and
provides signals representing all the voltages, currents etc. that the C&P system would receive when
installed on-site.
The real-time simulator equipment includes facilities to model a wide range of system conditions
including faults. Transient recording functions are normally incorporated as part of the software of
this equipment.
4.2.1.3 A.C. System Representation
The a.c. system may be represented within the real time simulator in one of two ways, usually
depending on what testing is to be performed:
Simplified Thevenin Equivalent
A simplified Thevenin equivalent model of the a.c. system to which the HVDC system is connected is
helpful in producing extreme operating conditions (in terms of voltage, system strength, negative
sequence, harmonics) which are difficult to create with an a.c. system equivalent.
This simplified Thevenin equivalent model is generally used to test the functionality of all the C&P
functions to determine how the HVDC system responds without interactions with external controllers
on devices such as generator exciters, dynamic voltage devices etc.
A.C System Equivalent
An a.c. system equivalent simulates a reduced a.c. system, including dynamics and system resonances
due to generator exciters, dynamic voltage devices, the capacitive and inductive properties of the a.c
system including transmission lines, shunt and series compensation etc.. This a.c. system equivalent
should be based on the model used for the DPS and should be benchmarked to ensure they exhibit
the same performance.
The a.c. system equivalent model, which is more complex than the simplified Thevenin equivalent
model, enables a study of the interactions of the a.c. and HVDC systems and is used for dynamic tests
of the C&P system.
4.2.1.4 HVDC System
With the exception of the C&P system to be tested, the complete electrical circuit of the HVDC system
is modelled on the real-time simulator. Whereas most parts of the HVDC system can be modelled in
EMT-type software, the VSC valve is, in some cases, modelled in hardware connected to the simulator
or represented in software but by a variable voltage source.
For reliable results it is important that non-linear aspects such as interface transformer saturation and
surge arresters are realistically modelled.
4.2.2 Model Validation
Throughout the HVDC project, a number of simulation models will be developed that will represent
the HVDC system to varying degrees.

27
During the DPS and factory tests, the EMT-type software and real-time analysis software models
should be benchmarked against each other in order to ensure a high degree of correlation between
results. If any setting changes due to a real-time analysis software test, the EMT-type software case
should be updated accordingly. The owner's representative may choose to witness and observe this
procedure to verify the validity of those intermediate steps and ensure the delivery of the most up-to-
date models from the supplier to the owner.
At the beginning of the project, a lot of initial studies would have been done using load flow analysis
software and the C&P representations in these software models also need to be validated.
4.2.3 Factory Test Outcomes
The intention of carrying out factory tests is to verify the C&P system performance and behaviour in
response to a.c. and d.c. system events in accordance with the performance requirements of the
project whilst in the factory and before connection to a real power system.
Whether tests are performed during the factory tests only or if they will be carried out or repeated on-
site can be defined in a test matrix. An example of a test matrix is provided in Appendix C. It is
recommended that the owner and the supplier discuss and agree the scope of these tests prior to
commencement of the testing.
After the factory testing is completed, the results should be retained and made available to compare
to the results that are obtained during the performance of the on-site testing. The results may differ
though, as the a.c. system conditions during on-site testing may be different than those provided by
the owner and simulated during the factory testing.
The factory testing is also a time where owner training can take place as discussed in Section 14.7.
4.3 INTERACTION STUDIES
This section identifies some interaction studies which may be required depending on the requirements
of the specific project. Such interaction studies are typically performed at about the same time as the
Dynamic Performance Study phase and the results are used to update the C&P System, particularly
where interactions are found that require damping. The C&P System changes will be tested through
further studies and during the factory tests as appropriate.
These tests are considered to be a part of design, although the outcomes will be useful while
performing factory tests and site commissioning tests, and to demonstrate the performance of the
HVDC System.
4.3.1 Subsynchronous Torsional Interactions (SSTI)
Subsynchronous torsional interactions (SSTI) can occur due to the interaction between the electrical
system and mechanical systems of rotating masses if the interaction yields a negative damping that
exceeds the natural mechanical damping. The risk of SSTI is driven by interactions between the
converter controller and the a.c. system.
The risk of SSTI occurring as a consequence of a VSC connection to an a.c. system is similar to the
risk as a consequence of the connection of an LCC HVDC system.
It is imperative that all SSTI studies have been fully completed prior to any commissioning activities
commencing. Accurate generator data must be made available for accurate SSTI studies to be carried
out. Results could vary from project to project depending on control modes and frequency response in
the torsional range of interest.
The power level or direction does not have any significant impact on the damping characteristic. This
is provided when the HVDC system is operating in active and reactive power control modes (APC-RPC)
with less significant damping behaviour. However, when the converter is operating in DCVC and RPC
mode the variation of reactive power will result in a significant change on the damping characteristic
[4]. When the converter is operated in either DCVC-RPC or DCVC-ACVC control mode combinations
the damping is less effective. For APC-RPC or APC-ACVC control mode combinations, the damping is
highly effective.

28
Given the limited experience with VSC HVDC technology and SSTI, this phenomenon needs to be
investigated for each specific project as a part of the design process [4]. There is the potential for
negative electrical damping in the torsional range from the controls if not designed properly. This is
especially important when Transmission Tests are performed on a VSC HVDC system. Failure to fully
cover SSTI during the design phase could result in unexpected interaction with nearby generators and
delays to the commissioning process while a mitigation is determined.
4.3.2 Power Oscillation Damping (POD)
Many a.c. grid codes require power oscillation damping (POD) to be demonstrated by grid
interconnecting projects including offshore wind power plants connected via an HVDC system. POD is
a control function acting to dampen power oscillations on interconnecting a.c transmission lines.
These oscillations are slow inter-area oscillations typically under 1 Hz. Power electronic based
equipment, including VSC converters, are capable of providing this functionality if specified and
properly designed.
The testing of POD functions is difficult to do on-site, since this involves inter-area power oscillation,
and is typically verified by performing specific simulations at the design stage. The testing would
typically involve utilisation of the real-time simulator with the actual converter controls in the
simulation loop.
4.3.3 SSR Damping
Some HVDC systems are in close electrical proximity to a.c. transmission lines compensated with
series capacitors. At the same time, these transmission lines can sometimes be radially connected to
the local power generation plants. The resonant frequency of the series compensated line can
potentially excite torsional frequencies on the generator shafts that could contribute to its loss of life
and eventually to shaft damage.
The HVDC C&P systems can be designed with additional auxiliary control loops to provide a degree of
damping of these sub-synchronous resonances (SSR). This functionality is typically requested in the
project specifications based on the specific location and would be considered a grid support function.
Simulations and studies are typically necessary for the design and performance verification of SSR
damping controls.
4.3.4 Potential Control Interactions with Other Devices
Other devices connected to the same busbar as the VSC HVDC scheme, or in close proximity to it, that
could cause control interactions with the VSC HVDC scheme include other HVDC schemes (VSC or
LCC), FACTS devices (SVC’s and STATCOM’s) or nearby wind generators.
The control systems of these devices may have control loops with the same/similar frequency
response as the control loops of the VSC HVDC scheme, which creates a risk for adverse
consequences such as control instability and excessive component stresses. Additionally, some
disturbances and unbalanced a.c. network conditions can contribute to harmonic voltage distortion
which, depending on the a.c. network strength and the harmonic properties of the a.c. network, can
be further amplified. This is usually problematic at low harmonic orders. The offshore collector
systems represent networks that can feature a range from low to high order of resonances.
Such control interactions are difficult to test on-site and are typically verified by performing dedicated
studies early in the project studies/design stage. The analysis of the control system interactions
requires the availability of detailed and accurate models of the device and its control system for all
devices adjacent or in close proximity to the HVDC system. The objective of the studies should be to
investigate possible control interactions between the VSC HVDC system and these other devices.
From a DPS perspective, the neighbouring HVDC system/s or other devices should be represented as
accurately as possible in order to fulfil the requirements of proper tuning of the new VSC’s HVDC C&P
system. The post fault recovery voltage waveform will influence the VSC C&P parameters. However,
the collection of the different C&P modelling parameters used by different suppliers may pose
additional challenges to performing fully representative studies. Special attention should be paid to
the following areas:
 Interaction with offshore wind HVDC connections and/or LCC-based converter terminals:

29
 Power/voltage stability during steady state operation; and
 A.c. faults (focus on susceptibility to commutation failures), d.c. faults, load rejection
cases, control system failures, normal/fast power ramping in the same or other HVDC
systems and stepresponses.
 Interaction and coordination with FACTS devices installed on the a.c. network, including SVCs,
STATCOMs and synchronous condensers installed in the vicinity of the converter station.
 Switching of reactive power elements (from LCC-based stations) including coordination of
reactive power control actions for minimising voltage steps during switching of capacitor/filter
banks.
 Settings of overvoltage relays and other affected protective functions in the case of d.c. cable
discharge current penetrating into the a.c. system through a neighbouring HVDC station and
any possible effect to the converter transformer as well (saturation effect).
 Black start with multiple VSC systems and the synchronisation of different islanded grids.
Identified control interactions could be resolved by coordinating and tuning the relevant controls and
utilising for example droop control, master-slave or fast-slow control strategies. It may be difficult to
modify the control loops of the other devices as these may have been commissioned several years
prior or the owners/operators of these devices may not be willing to make changes to the control
systems. In these cases, mitigation measures may need to be implemented in the control loops of the
new VSC HVDC system.
Based on these studies, some convenient tests to be executed during on-site commissioning could be
identified. These should confirm that there are no adverse effects due to control interactions with
other devices. However, these tests may be difficult to arrange on site, and the C&P system design
and its settings should be verified and if necessary adjusted during the DPS.

30

31
5. SUBSYSTEM TESTING
Subsystem testing proves the correct interconnection and functioning of all individual items of
equipment within a functional group (subsystem) and that these items operate and interact correctly.
A subsystem can include groups of main circuit equipment and associated measurement systems (for
example, the IGBT valves, a filter yard, d.c. yard or interface transformer), C&P systems (for example,
pole controls, valve controls or cooling controls) or auxiliary systems (for example, equipment cooling
systems, auxiliary power systems, heating and ventilation and fire systems).
This section covers subsystem testing to be performed on subsystems and equipment that are
commonly part of a VSC HVDC system. The subsystem testing is preceded by pre-commissioning, also
known as equipment testing which, while being a precondition for the start of subsystem testing, is
not covered in this Technical Brochure as it is often considered to be a part of the installation phase of
the site activities.
The scope of subsystem testing described in this chapter is based on a typical VSC HVDC installation.
Some aspects may not apply to a particular project or installation. In addition, the scope, test
procedures and acceptance criteria of subsystem testing are typically supplier specific and the
recommendations of the supplier will drive these elements. The scope, test procedures and
acceptance criteria provided here should be considered as guidelines only.
Subsystems to be tested for a typical VSC converter terminal comprises the following key elements:
 Power, control and communication cabling systems;
 A.c. protections andinterlocking;
 Main circuitequipment;
 HVDC C&P systems; and
 Auxiliary systems.
The following preconditions would typically need to be satisfied before subsystem testing of a
particular subsystem can commence:
 Installation (assembly) of all equipment within the subsystem is complete.
 Equipment testing of all individual equipment within the subsystem is complete.
 The installation and equipment testing of the C&P systems need to be complete for the areas
concerned so as to allow primary injection and signal verifications of the equipment within the
subsystem.
 All necessary test and measurement equipment have been calibrated and are in service.
Typically, all subsystem testing is completed before the system tests can commence, with some
exceptions depending on the particular project (for example, certain non-critical auxiliary systems).
5.1 POWER, CONTROL AND COMMUNICATION CABLING SYSTEMS
The subsystem testing of cabling systems involves the point-to-point testing and identification of each
power, control and communication cable within the converter terminal.
The precondition to this subsystem test is that all cabling installation, termination and insulation
testing have been completed.
The test procedure to be followed will vary between suppliers, however this typically involves the
identification of each cable in either a plant circuit schematic diagram or cable schedule, and the
marking off of each cable on these documents after the cable is confirmed to originate and terminate
at the correct terminals.
Where the cables are found not to originate or terminate as per the drawings and/or schedule, the
underlying cause of this discrepancy will be investigated and rectified, either by correcting the
discrepancy in the field or modifying the drawings and/or schedule.

32
The test acceptance criteria for this subsystem test is the verification that all cables originate and
terminate as per the plant circuit schematic diagram or cable schedule.
5.2 A.C. PROTECTIONS AND INTERLOCKING
There may be a requirement to test any a.c. protection relays at the interfaces to the a.c. network
(connection points), any required interlocking at the connection points as well as any other discrete
relays used throughout the HVDC system, such as interface transformer protection. The subsystem
testing of these a.c. protections and interlocking involves the point-to-point testing and the functional
tests typically required for a.c. protection relays (and as specified by the relay supplier).
The precondition to this subsystem test is that the a.c. protection relays have been installed and
configured, all telecommunications between relays are in service and tested (for example, for a.c.
cable differential protection) and the logic for any required interlocking has been implemented.
The test procedure to be followed will vary depending on the particular types of a.c. protection, the
protection relay type and supplier and the arrangements for interlocking with the nearby connecting
utility. The a.c. protection relay testing will need to be performed in accordance with normal practices
and the supplier’s recommendations.
For interlocking, test arrangements and plans should be agreed with the nearby connecting utility.
The various configurations of a.c. switchgear (disconnectors, ground switches and circuit breakers)
shall be modified by either physically opening and closing each switch or simulating this as close to
the device as possible where actual operation is not possible. For each configuration, the correct
operation or non-operation of the interlocked switchgear or function should be demonstrated in
accordance with the design.
The test acceptance criteria for a.c. protection relays shall be as defined by the protection design and
settings and the supplier’s recommendations.
The test acceptance criteria for any interlocking tests is that all switchgear or functions that are a part
of the interlocking system are either allowed to operate or prevented from doing so in accordance
with the interlocking design.
5.3 MAIN CIRCUIT EQUIPMENT
The subsystem testing of main circuit equipment represents those tests required after the pre-
commissioning tests are completed on the individual elements, to demonstrate that all main circuit,
control, protection and auxiliary systems within the subsystem operate correctly.
The areas covered by these subsystem tests include, where applicable, the a.c. yard, interface
transformers, converter a.c. and d.c. yards and converter area. Typical subsystem tests for these
areas are provided in Table 5-1.
Table 5-1 - Typical Subsystem Testing of Main Circuit Equipment
Area Typical Subsystem Tests
Interface Transformers  Verification of alarms and trips from transformer
protections.
 Polarity and loop resistance measurements for
transformer CTs.
 Secondary injection testing from transformer CTs.
 Checking of signals and indications up to the HMI
display.
A.c. and d.c. Yards  Circuit breakers, disconnectors and earth switches.
 Check local and remote operation.
 Trip circuit checks.
 Interlocking checks.

33
Area Typical Subsystem Tests
 Voltage transformers – Primary measurement
checks, insulation resistance checks.
 Current transformers – Loop resistance
measurement, insulation resistancechecks.
 Primary and secondary injection testing of
measurement devices whererequired.
 Tuning of filters.
 Primary and secondary injection testing of
measurement devices such as d.c. voltage dividers,
Rogowski coils and other d.c. current measurement
systems where required.
 Pressure measurement andalarms for SF6 filled
equipment such as wall bushings and voltage
dividers.
 Checking of signals and indications up to the HMI
display.
VSC Valves Fibre optic system checks.
Control and communicationtests.
Supplier and project specific tests.
5.4 HVDC CONTROL AND PROTECTION SYSTEM
The subsystem testing of the HVDC C&P systems are divided into the following test types:
1. System supervision;
2. C&P sequences; and
3. SCADA/remote control.
5.4.1 System Supervision
The system supervision checks test the correct supervision of the active and standby C&P systems,
and correct operation of switchover logic to switch from active to standby systems in the event of a
failure of the activesystem.
The indications in the operator workstations are checked to ensure they are reporting the correct
status of each C&P panel. Samples of alarms and events at the operator workstation are confirmed as
correct.
5.4.2 Control and Protection Sequences
This subsystem test involves the operation of C&P sequences with the converter terminal offline.
Typical sequences include:
 Automatic starting up of auxiliary systems, such as cooling fans, exhaust fans etc.
 Operating sequences – checks of any automated and/or manual switching sequences involved
in taking a converter terminal from one operational status to another where such sequences
are possible with the converter terminal offline.
 Interlocking – checks of all interlocks for the operation of switching devices and the allowance
to deblock and block the converter terminals.

34
5.4.3 SCADA/Remote Control
Where a converter terminal requires operation from a location remote from the converter terminal
location, a remote operator workstation will typically be required. These subsystem tests will ensure
correct connection to the remote operator workstation, including the remote control and operation of
the converter terminal and the receipt of alarms and status indications.
In some cases, there is a requirement for signals from the converter terminal to be transmitted via a
SCADA system to either another control room and/or an external party, such as a system and/or
market operator. These systems must be end to end tested to ensure the integrity of the signals being
transmitted to these SCADA systems, from the converter C&P system to the final destination.
It is worth noting that it may not be possible to verify some SCADA functionality during subsystem
testing, particularly functions that are only available while the converter is energised and in operation,
such as power level and direction. Planning for complementary SCADA testing during the system tests
is therefore recommended.
5.5 AUXILIARY SYSTEMS
The subsystem testing of the converter’s auxiliary systems will typically include the testing of the
items of auxiliary equipment listed below (where applicable). The subsystem testing of these systems
is performed as per the supplier’s instructions.
5.5.1 Valve Cooling System
The IGBT valve cooling subsystem includes such equipment as the cooling pumps, cooling fans,
radiators, heat exchangers, water piping, filters, purifiers, ion exchangers, meters, transducers,
valves, heaters, cooling control systems and any other equipment associated with the water cooling of
the IGBTs.
Valve cooling systems are normally pre-mounted, functionally tested in the factory, and
interconnected at the site. The completeness and correctness of the overall system installation at the
site should be verified visually with the aid of checklists, diagrams, drawings, and instructions.
The subsystem testing of the valve cooling system will typically include:
 Check of all measurement devices and transducers – This involves checking the signals from
flow meters, conductivity meters, pressure transducers and temperature transducers back to
the converter C&P equipment.
 Functional test of pumps – Check of the operation of valve cooling pumps, including control
from the converter C&P system and the operation of pump protections. This will include
operation of the changeover from active to standby pumps.
 Functional test of cooling fans – Check of the operation of each cooling fan, and the control of
these fans from the converter C&P system. This will include the operation of any motor
operated valves, water temperature measurement and the correct starting/stopping of cooling
fans.
 Functional test of other cooling system elements – including any water pressure systems,
makeup/filling systems, deionisation systems, oxygen management systems, heaters etc.
 Overall check of cooling system from C&P system – test of coordinated operation of pump and
fans to ensure correct water regulation and check of valve cooling protection including flow,
pressure, water level, leakage detection, conductivity sensing, alarms and trips.
5.5.2 Auxiliary Power
These tests involve the progressive energisation and commissioning of the auxiliary power system,
including:
 The main incomer and transfer switch – verification of transition from the primary auxiliary
power supply to any standby supplies, and of the switchover times.

35
 Power distribution boards and sub-boards throughout the converter terminals and in the a.c.
and d.c. yards – verification of satisfactory voltage at the switchboards and correct operation
of protective devices.
 C&P power supplies – verification of satisfactory voltage and operation of all a.c. and d.c.
power supplies within the C&P system, including any power rectifiers.
 Battery systems and UPS – verification of correct operation of all battery systems and
uninterruptible power supplies(UPS).
 Diesel generators and backup power – verification of correct start-up of generators and
smooth transition.
5.5.3 Fire Systems
The fire system will typically involve one or more fire detection methods/systems and in some cases,
fire suppression systems. The subsystem testing of the fire systems will ensure the correct operation
of both the individual systems and the interaction between them, as well as verification of alarming
and control actions within the converter C&P system.
5.5.4 Air Handling and Conditioning Systems
The subsystem testing of the air handling and conditioning systems cover the correct operation and
interaction and the monitoring and interface to the HVDC C&P system of any of the following systems:
 Converter reactor coolingsystems;
 Valve hall air conditioning and handling systems;
 Air conditioners in controlrooms;
 Dehumidifiers;
 Air filtration systems;and/or
 Air evacuation systems.
5.5.5 D.c. Line/Cable Monitoring Systems
Some VSC HVDC systems may have fault location systems or cable temperature measurement
systems installed. In some cases, these systems trigger operations within the converter terminal’s C&P
systems, including the running back, blocking or tripping of the HVDC system. The subsystem testing
for these auxiliary systems will need to verify the correct measurement and operation by these
systems before they are allowed to operate “live”.
5.5.6 Earth Electrode and Earth Electrode Line Monitoring System
An earth electrode and earth electrode line monitoring system may be installed for a monopolar HVDC
system or a bipolar HVDC system which is capable of operating in monopolar mode. The subsystem
testing for these should be completed in accordance with the supplier’s recommendations.

36

Testing and commissioning of VSC HVDC systems

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