Guidelines for life extension of existing HVDC systems

649
Guidelines for life extension of
existing HVDC systems
Working Group
B4.54
February 2016

GUIDELINES FOR LIFE
EXTENSION OF EXISTING
HVDC SYSTEMS
WG B4.54
Members
L.D. Recksiedler, Convenor (CA), Rajesh Suri, Secretary (IN),,
Leena Abdul‐Latif (FR), Les Brand (AU), Phil Devine (UK), Malcolm Eccles (AU), Abhay Kumar (SE),
Mikael O Persson (SE), Maurice Smith (SE), Stefan Frendrup Sörensen (DK), Marcio Szechtman
(BR), Takehisa Sakai (JP), Rick Valiquette (CA), Andrew Williamson (ZA)
Corresponding Members
Hans Björklund (SE), John Chan (US), Richard Michaud (US), Predrag Milosevic (NZ), Van
Nhi Nguyen (CA), Randy Wachal (CA)
Copyright © 2016
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right of use for personal purposes. Unless explicitly agreed by CIGRE in writing, total or partial
reproduction of the publication and/or transfer to a third party is prohibited other than for personal
use by CIGRE Individual Members or for use within CIGRE Collective Member organisations.
Circulation on any intranet or other company network is forbidden for all persons. As an exception,
CIGRE Collective Members only are allowed to reproduce the publication”.
Disclaimer notice
“CIGRE gives no warranty or assurance about the contents of this publication, nor does it accept
any responsibility, as to the accuracy or exhaustiveness of the information. All implied warranties
and conditions are excluded to the maximum extent permitted by law”.
ISBN : 978-2-85873-352-1

Guidelines for Life Extension of Existing HVDC Systems
Page 3
Guidelines for Life Extension of
Existing HVDC Systems
W G B 4 - 5 4
Table of Contents
DEFINITIONS...................................................................................................................................... 5
EXECUTIVE SUMMARY..................................................................................................................... 6
1. Chapter 1 – General Procedure for Performing a Life Assessment........................................... 9
1.1. Introduction ......................................................................................................................... 9
1.2. Preparation.......................................................................................................................... 9
1.3. Team................................................................................................................................... 9
1.4. Assessment Process......................................................................................................... 10
1.5. Deliverable ........................................................................................................................ 11
1.6. Life Assessment Timetable............................................................................................... 11
2. Chapter 2 – Thyristor Based HVDC Systems Performance Issues ......................................... 13
2.1. Survey of availability and reliability (over all HVDC systems in the world)........................ 13
2.2. Operating History .............................................................................................................. 14
2.3. Major equipment/system/sub-system failure/refurbishment summary .............................. 14
2.4. Alternatives and justification.............................................................................................. 15
2.5. Methods for assessing reliability, availability and maintainability of existing components 16
2.6. Basis for replacement/refurbishment of equipment........................................................... 17
2.7. Performance after replacement and refurbishment........................................................... 17
3. Chapter 3 – Life Assessment and Life Extension Measures of Equipment.............................. 19
3.1. DC Switchyard Equipment ................................................................................................ 20
3.2. Valves ............................................................................................................................... 32
3.3. Converter Transformers.................................................................................................... 42
3.4. DC Control and Protection ................................................................................................ 61
3.5. References:....................................................................................................................... 79
3.6. Valve Cooling.................................................................................................................... 80
3.7. Station Auxiliary Supplies.................................................................................................. 84
3.8. Ground Electrodes and Electrode Lines (does not include sea electrodes) ..................... 85
3.9. Reliability Centered Maintenance ..................................................................................... 89
3.10. References........................................................................................................................ 89
4. Chapter 4 – Guideline for assessing Techno-Economic Life of Major Equipment ................... 91
4.1. Operational Issues – Maintenance Cost / Management and Availability of Spares.......... 91
5. Chapter 5 – Reccomendation for Specification of Refurbishing HVDC System....................... 94
5.1. Introduction ....................................................................................................................... 94
5.2. Main Components of a Converter Station: Guideline for the Specification ....................... 94
5.3. Interfaces ........................................................................................................................ 101

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5.4. Maintainability including spares requirement .................................................................. 102
5.5. Cost minimization............................................................................................................ 103
5.6. Replacement time minimization ...................................................................................... 103
5.7. Operation outage minimization ....................................................................................... 104
6. Chapter 6 – Testing of Refurbish/Replacement Equipment...................................................... 106
6.1. Introduction ..................................................................................................................... 106
6.2. High Voltage Equipment ................................................................................................. 106
6.3. Low Voltage Equipment .................................................................................................. 110
6.4. Auxiliaries........................................................................................................................ 110
6.5. Fire detection .................................................................................................................. 111
6.6. Tests of the connection with the existing equipment....................................................... 112
6.7. Example of commissioning procedures: IFA 2000 refurbishment................................... 112
7. Chapter 7 – Environmental Issues ......................................................................................... 115
7.1. Insulating Oil ................................................................................................................... 115
7.2. Polychlorinated Biphenyl................................................................................................. 116
7.3. Sulfur Hexafluoride Gas.................................................................................................. 117
7.4. Halon Gas ....................................................................................................................... 117
7.5. Refrigerants..................................................................................................................... 118
7.6. Abestos .......................................................................................................................... 119
7.7. Audible Noise.................................................................................................................. 119
7.8. Electromagnetic Effects .................................................................................................. 120
7.9. Mitigation of Environmental Issues ................................................................................. 120
Chapter 8 – Regulatory Issues...................................................................................................... 122
8.1. Renovation & Modernization........................................................................................... 123
8.2. Conclusion ...................................................................................................................... 123
9. Chapter 9 – Techno Economics............................................................................................. 124
9.1. Financial analysis of refurbishment options .................................................................... 124
Appendix A – Basslink Case Study............................................................................................... 127

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DEFINITIONS
Life Extension
Life extension requires a life assessment and the final result will be a life extension of the HVDC.
However as a result of the life assessment it may be decided not to extend the life and this would be
outside the scope of this document
Design Lifetime
The Design Life time of a component is the time during which the device is commercially available or is
commercially viable in its original supplied form.
Operational Life
The Operational Life is the period of time over which a product will operate correctly, assuming that it
has been maintained in accordance with its maintenance instructions.
Independent Expert
An Independent Expert is a person or person having an expert knowledge of a part or many parts of a
HVDC link and may be a Consultant or not.
Maintenance spares
Within the system there will be components that are expected to wear out or have a limited lifetime,
either in terms of operational (or storage) time or usage. These components, known as maintenance
spares, need to be replaced at predictable and specified intervals.
Strategic spares
All components (including components that are maintenances spares) exhibit random failures that have
to be treated in a statistical manner; every year it is expected that a small proportion of components to
fail but cannot predict which component will fail or when it will need to be replaced. These are known as
strategic spares.
One vendor spares
Some spares such as capacitors are available from many different suppliers and thus large quantities do
not have to be stocked. Other spares are available only from the Original Equipment Manufacturer OEM
and thus may or may not be available in about 15 years. For example, a HVDC control system has a life
of approximately 15 years before a new generation is developed. If it is purchased in year 14, the spares
may not be available for very long. Even if the OEM guarantees the availability, many of the parts from
sub-suppliers may not be available any more. Thus the number of spares may influence the usable life of
the equipment.
Resin Impregnated Paper (RIP)
The condenser paper in a bushing is impregnated with an epoxy resin compound.

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EXECUTIVE SUMMARY
In today's complex environment, energy players face growing demands to improve energy efficiency
while reducing costs. Energy shortages and increased ecological awareness have resulted in great
expectations for grid stability and reliability. Utilities and industries need to find eco-efficient solutions to
maintain secure, safe and uninterrupted operations. A number of regulatory changes in the electricity
market have led to increased efforts by utilities and grid operators for optimized utilization of their
existing networks with respect to technical and economic aspects. As the electric power transmission
system ages, the topics of life assessment and life extension have become predominant concerns. At
the same time, cost pressures have increased the desire to minimize maintenance. The goals of
minimum maintenance and extended life are often diametrically opposed.
The concept of simple replacement of power equipment in the system, considering it as weak or a
potential source of trouble, is no longer valid in the present scenario of financial constraints. Today the
paradigm has changed and efforts are being directed to explore new approaches and techniques of
monitoring, diagnosis, life assessment and condition evaluation, and possibility of extending the life of
existing assets.
A major challenge for grid operators worldwide is to assure sufficient power with quality and reliability. In
this regard High Voltage Direct Current (HVDC) systems play a major role in bulk power transmission,
system stability, integrating remote renewables and ride through of disturbances. Therefore HVDC
systems represent an indispensable part of the electricity grid in the countries where they are installed.
HVDC has been in commercial use since 1954, and most of the systems are still in operation. However,
the early mercury arc valve systems have been phased out and replaced by Thyristor Valves. This has
extended the life of many of the early systems, but the Thyristor based systems are also approaching an
age where the Thyristor Valves may require replacement or refurbishment. Operation and maintenance
issues of these aging systems have become a challenge. The situation is further complicated by the fact
that all of the HVDC systems are custom built by a relatively small number of Original Equipment
Manufacturers (OEM).The HVDC manufacturers have supplied several different generations of
equipment and these differences have to be considered in any life extension assessment.
Disclaimer: This Technical Brochure is about life extension of HVDC Converter Stations only.
Upgrading the converter stations or operating them beyond its design specifications is out of the scope
of this document. However for both of these it is highly recommended that the OEM is consulted as
these are complex and a custom built installation and the normal design rules will likely not apply.
With the aging of the equipment, measures to extend the life of the equipment have to be considered by
utilities and grid operators. Renovation, modernization and life extension of HVDC stations is usually
one of the most cost effective options for maintaining continuity and reliability of the power supply to the
consumers. These life extension measures have to be implemented with minimum impact on the HVDC
system and the associated networks whilst maintaining an acceptable level of reliability and availability.
If life extension is not economical, the systems may be disposed of in an environmentally acceptable
way. Also, environmental issues need to be considered prior to a life extension project to avoid any
inadvertent environmental damage.
The cost of outages to do a refurbishment must be considered as part of the overall cost. This may then
dictate a Greenfield option where a new converter station can be built and only short switch overtime is
required. An example of this is the Oklaunion Converter Station (CS) in the USA, where the outage costs
tipped the scale towards a Greenfield versus a Brownfield option for refurbishment. The definition of the

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interfaces in the case of a Brownfield project is critical and more complicated than in a Greenfield
project.
Most utilities are interested in better understanding and projecting service life of HVDC equipment to
help manage risk; however, generic reliability data is inadequate for current decision support needs. It is
important to establish industry-wide equipment performance databases to establish a broad-based
repository of equipment performance data. With proper care and analysis, this data can provide
information about the past performance of equipment groups and subgroups, and the factors that
influence that performance. With enough data, projections can be made about future performance. Both
past and future performance information can be useful for operations, maintenance, and asset
management decisions.
However, for some components it is more difficult than most to determine the useful life and the actual
end of life failure modes. The Thyristors themselves are an example, as they have been around for some
35 or more years and yet are showing little sign reaching end of life, except where some design or
quality issues have been uncovered.
The life-extension may involve any of the following actions:
• Refurbishing the systems or subsystems
• Selectively replacing aging components
• Combination of the above
In some cases life extension is not economically feasible and a Greenfield replacement may have to be
considered.
The following steps need to be taken to arrive at a decision:
• Review the past performance of the major HVDC equipment and systems
• Identify the future performance issues associated with the ageing of special components of
the HVDC systems. There may be equipment that has not shown performance issues in the
past but still may need an extension and should also be considered.
• Determine economic life of various components in the converter station and for making
replacement versus life extension decisions. The consideration of economic life will include
capital cost, reliability and availability, cost of maintenance and the cost of outages and power
losses.
• The usable life of a refurbishment is likely in the average of 15 to 20 year range whereas a
Greenfield option is likely 35 to 40 years and this needs to be factored into the evaluation but
it is recognized that some components may have a different year range.
One way of going about this activity could be to develop criteria, weightings and methodology for
determining near-term action and forecasting the technical and financial effect due to system ageing.
This should follow an approach based on condition replacement cost and importance of the equipment
and components. Assessment of condition parameters could be in terms of equipment age, technology,
service experience (e. g. after sales service quality, maintenance costs) and future performance,
individual failure rates, and so on. A viable duration for the life extension should be determined and
usually 15 to 20 years is achievable. Longer durations may be more difficult to assess with any degree of
accuracy.
Evaluation of the possibility of extending the service life of electrical equipment is a techno-economic
compromise which must lead to “run-refurbish-replace” decisions. Once the expected service life period
has expired, refurbishment of such equipment falls within the life extension program. The investment at

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the initial stage is very capital intensive to the utility concerned, as the devices to be installed in the
system for Residual Life Assessment (RLA) and condition evaluation purpose, are very costly. However,
the decision to refurbish or to replace should be based on the study of comparable costs and benefits
over the same potential life time of the asset.
Therefore, it can be concluded that the need for life extension and replacement of equipment in HVDC
system arises due to:
• Arresting the deterioration in performance
• Improving the availability, reliability, maintainability, efficiency and safety of the equipment
• Regaining lost capacity
• Extending the useful life beyond originally designed life of 35 to 40 years
• Saving investment on new equipment
• Not having availability of new spares due to obsolescence
These CIGRE Working Group objectives help utilities as follows:
• design refurbishment strategies for their existing HVDC systems to extend equipment life,
• evaluate O&M and reliability performance improvement strategies for their existing HVDC
systems,
• provide a guideline for determining economic life of various components in the converter
station and for making replacement versus life extension decisions. The consideration of
economic life should capital cost, reliability and availability, cost of maintenance and the cost
of power losses.
This technical brochure (TB) provides guidelines for the general procedure for performing life
assessment (chapter 1). Following this, a more detailed description of performance issues of the thyristor
based HVDC systems (chapter 2) is given and the life assessment measures of equipment (chapter 3)
and guidelines for accessing the techno-economic life of equipment (chapter 4). Chapter 5 deals with the
recommendation for specification of refurbishing HVDC system and chapter 6 follows with the testing of
the refurbished and replaced equipment. Lastly, this brochure will outline environmental issues (chapter
7) and regulatory issues (chapter 8) involved in the life assessment and finalize with a financial analysis
of the refurbishment options (chapter 9).

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1. Chapter 1 – General Procedure for Performing a Life
Assessment
1.1. Introduction
Each assessment will be slightly different depending on the needs and expectations of the Owner as well
as the information available. In many cases, only high level information will be available, in some cases
detailed information will be available and in others only high level information is required by the Owner.
In most cases, only a technical evaluation is required but in others a commercial justification may also be
required. This guide is only intended to describe the technical procedure.
Only the HVDC equipment will be considered here as the AC equipment is outside the scope of this
procedure and there are several sources of existing literature already covering this topic. This excludes
AC and DC filters and Synchronous Condenser and SVC’s or Statcom’s
1.2. Preparation
In preparation for performing the life assessment, it is critical to define the needs and expectations of the
Owner as much as possible. The next step is to produce a written proposal detailing the scope of work,
information available and to be provided by the Owner, deliverables and estimated cost. The proposal
needs to be discussed with the Owner and modified as required and agreed upon. It is also critical to
determine the amount of time that a life assessment should be good for. The average is 15 to 20 years
whereas a replacement would have a life of approximately 35 to 40 years. A life assessment or
refurbishment is normally referred to as a Brownfield where as a replacement is called a Greenfield.
1.3. Team
A team needs to be established which may consist of the Owners’ staff, Suppliers’ staff and Independent
Experts, or any combination thereof. The team may be different if only a piece of equipment is being
evaluated or if the entire HVDC Stations is being considered. Formal communications should be through
a leader on both the Independent Experts’ and Owners’ sides only. Formal communications is anything
that affects price, schedule or quality. Informal communications are still encouraged.
In general, a specialist or expert should be employed for each of the areas but some areas are critical
because of the importance, complexity, or cost:
• Converter Transformers and smoothing reactors– Critical because they are normally the
highest cost item in a life assessment endeavor and are very complex.
• Thyristor Valves – Critical as they are the next highest cost and a very specialized area.
• HVDC Control and Protection – Critical as they are very complex even though not that costly
• Cooling Systems - HVAC – not as critical but still needs proper evaluation
• Auxiliary Systems – Not critical, it is usually a source of many operating problems
• Other DC equipment – includes DCCT, VDR, disconnects and breakers and switches
• Civil – Aging of structures’ and foundation’s – usually overlooked in assessments but should
not be
• Miscellaneous - Wiring, Fire protection, security buildings and ground grid. These items are
usually overlooked in an assessment but should not be.

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1.4. Assessment Process
A kick off meeting with the team is recommended to obtain the information and discuss the format that it
will be provided in, as well as any software required to open the flies and interpret the results. This
should be provided in a standard format such as word, excel or pdf wherever possible.
Several visits to the station(s) are a must for discussions with the maintenance staff. Also discussion
should take place with the operating staff to determine if the equipment is meeting their expectations.
Also determine if there are any additional requirements that the existing equipment cannot provide and
possible benefits.
The following should be part of the analysis:
• Operating problems or changes in the mode of operation
• Maintenance records for the last 5 years
• Any modifications performed and why
• Any failures and failure reports
• Original quality or design issues
• Any equipment replaced and when
• Spare or replacements parts or obsolescence for major or critical equipment. An example
may be Thyristor failures per year, spares on hand and whether they are still available from a
supplier.
• Status of spares – questions to consider are whether they are usable? Have they been
maintained? Have they been in service and removed because they were gassing such as the
converter transformer? Have they never been in service?
• Technical skills of staff to continue operating and maintaining the equipment. Is additional
training required?
• Normal life of each piece of equipment
• Drill down to the smallest subsystem or components possible as it may be possible to replace
only some components and not the larger equipment subsystem or system. This could save a
lot of cost but requires that the detailed information be available.
• Criticality of the HVDC link to the system and consequences if it is unreliable or out of service.
• Risk assessment – is there a way to prevent or mitigate a risk. What would you do if the risk
happened?
• Some equipment may not have a history of problem and failures but consideration should be
given that some of this will occur if the life assessment is long enough and should be
considered as a contingency.
• Replacement costs, wherever possible, should be obtained from a supplier. Where this is not
possible estimated costs based on previous experience is required.
• An implementation schedule will also likely be required. Wherever possible the schedule
should be obtained from a supplier. Where this is not possible, a rough schedule based on
previous experience is required.
As equipment is costly it may be beneficial to use an Independent Expert to review an assessment
provided by a Supplier.
Regular status update meetings between the Owner and the involved parties should be held to ensure
everyone is on track and to disseminate any new information, if available.

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1.5. Deliverable
The deliverable is usually a report with recommendations and conclusions. A preliminary copy of the
report should be reviewed with the Owner incorporating any comments or concerns. In some cases the
Owner will request additional work in a specific area requiring additional analysis, modifying the report
and another preliminary meeting.
Eventually a final report will be issued. The Owner will then combine this with the commercial analysis
and make a final recommendation for Brownfield or Greenfield.
In the case that the Owner also wants a commercial analysis, it is necessary to understand these
requirements and follow the standard way or format that the company produces the information and if
the project is to be financed by a bank what is necessary for the bank to do its risk assessments.
1.6. Life Assessment Timetable
Note: Life Assessment should begin 5 years before the time indicated in the table below or if there are
high failure rates or maintenance issues.
The reality is that there is no piece of equipment where a firm number is accurate. The idea of coming
up with a number is that if this piece of equipment has not caused any major problems up to the point in
time, a life assessment should be done to determine the remaining life, refurbishment and replacement
of that piece of equipment, subsystem or system, or if replacement is done, then the entire HVDC project
may be the best option. Manitoba Hydro has had analogue controls in-service for over 42 years and it
could be 45 or even 50 years before they are replaced for a HVDC station with a design life of 35 years.
But it has been assessed many times over the last 15 or so years. This is certainly not the average.
Manitoba Hydro also has some air core AC and DC filter reactors in-service for 37 years with no failures;
another converter station has had many AC filter air core reactor failures in a much shorter lifetime. Only
major items are considered here and not subcomponents.
HVDC Equipment Lifetimes
Note: Excludes design and production run quality issues
HVDC Station Design life 35 to 40 years
Equipment Lifetime (Years) Comments
Converter Transformer 40
AC Bushings 25-30 25 OIP , 30 RIP
DC Bushings 30-35 30 OIP, 35 RIP - DC bushings have more insulation
Tapchanger 30 or 350 000 Operations, Seals and springs
Coolers 25
Thyristor Valves 35
Thyristors 35
Valve Reactors 30
Tubing 25
Fiber Optics 35
Damping Capacitor 30
Damping Resistor 30

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Electronic cards 25 - 30
Coolers 25
HVDC Controls ( analogue) 35
HVDC Controls ( digital ) 12 - 15
HMI 7
DC Smoothing Reactor (oil) 35 Bushing may have a shorter life
DC Smoothing Reactor (air
core) 35
Optical DCCT 30 Electronics may have a shorter life
DC Voltage Divider 30
DC Surge Arrestors 35
DC Insulators 35
DC Wall Bushings 30-35 30 OIP, 35 RIP - DC bushings have more insulation
DC Switching Equipment 35
DC Buswork, structures 50
Ground Electrode 40 - 50 Normal Design Life
Civil Work 50
Communications Systems 15

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2. Chapter 2 – Thyristor Based HVDC Systems Performance Issues
HVDC technology has experienced enormous growth worldwide in the past 50 or more years, and many
HVDC systems are currently in operation. As these systems age, asset management questions of what
to refurbish, what to replace and the scope of equipment repair and replacement is becoming
increasingly important to extend the life of all HVDC links.
A HVDC System will likely have a Computerized Maintenance Management System (CMMS) which will
contain more detailed records than that which is necessary for reporting to CIGRE or internally to high
level management within an organization. Modern day CMMS also have asset management systems
integrated into them to assist with Life Assessment decisions.
The following is some information about the collection of data from HVDC Schemes throughout the world
from those HVDC schemes that have submitted the information. This information can be useful for
benchmarking or for discussions with staff from HVDC schemes that are similar.
2.1. Survey of availability and reliability (over all HVDC systems in the world)
CIGRE B4 collects operational performance and reliability data of all HVDC systems in commercial
service in the form of annual reports. Such reports are prepared in accordance with a standardized
protocol published in accordance with CIGRE publication 346 Protocol for reporting the operational
performance of HVDC transmission systems: (note: please refer to the current version of the protocol as
details may have changed since this publications).
Performance data includes reliability, availability and maintenance statistics.
Reliability data is confined to failures or events which result in loss or reduction of transfer capability.
Statistics are categorized in order to indicate which type of equipment caused the reduction in
transmission capacity.
Advisory Group B4.04 of CIGRE Study Committee B4 (HVDC and Power Electronics) summarizes the
performance statistics for all reporting schemes every two years in a CIGRÉ paper entitled “A Survey of
the Reliability of HVDC Systems Throughout the World.”
High levels of equipment reliability for individual HVDC links are also visible from the CIGRE
performance reports. The CIGRÉ performance report also contains sections with the yearly number of
forced outages and duration of forced outages (in equivalent outage hours) for each equipment category.
Convertor station equipment is classified into six major categories: AC and Auxiliary Equipment (AC-E),
Valves (V), Control and Protection (C&P), DC Equipment (DC-E), Other (O) and Transmission Line or
Cable (TL).
2.1.1 A.C. and Auxiliary Equipment AC-E
This major category covers all ac main circuit equipment at the station (from the incoming ac connection
to the external connecting clamp on the valve winding bushing of the convertor transformer). This
category also covers low voltage auxiliary power, auxiliary valve cooling equipment and ac control and
protection. It is subdivided into following subcategories:
• A.C. Filter and Shunt Bank AC-E.F
Types of components included in this subcategory would be capacitors, reactors, and resistors which are
included in the ac filtering or shunt compensation of the converter station.
• A.C. Control and Protection AC-E.CP

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Assigned to this subcategory are ac protection, ac controls, and ac current and voltage transformers. AC
protection or controls could be for the main circuit equipment, for the auxiliary power equipment or for the
valve cooling equipment.
• Converter Transformer AC-E.TX
The converter transformers and any equipment integral to the converter transformer such as tap
changers, bushings or transformer cooling equipment is assigned to this subcategory.
• Synchronous Condenser (Compensator) AC-E.SC
The synchronous condenser (compensator) and anything integral or directly related to the synchronous
machine such as its cooling system or exciter is included in this subcategory.
• Auxiliary Equipment & Auxiliary Power AC-E.AX
This subcategory includes auxiliary transformers, pumps, battery chargers, heat exchangers, cooling
system process instrumentation, low voltage switchgear, motor control centers, fire protection and civil
works.
• Other A.C. Switchyard Equipment AC-E.SW
This subcategory includes ac circuit breakers, disconnect switches, isolating switches or grounding
switches.
The classification of other groups can be found in CIGRE publication 346 protocol for reporting the
operational performance of HVDC transmission systems.
2.2. Operating History
Records of equipment operating history are an integral part of equipment maintenance, and are required
to verify the suitability of maintenance practices, in order to achieve the design life of the HVDC
equipment.
Equipment operating history should contain basic equipment technical data, maintenance intervals,
detailed records of maintenance activities completed during the scheduled outages, components
replaced to keep the equipment operational, forced outages caused by the equipment, results of
scheduled inspections and diagnostic tests and results of tests done after replacement of components.
The data collected is used to assemble equipment condition assessment reports which assist in
identifying any requirements to increase and change maintenance, repair or replace equipment.
2.3. Major equipment/system/sub-system failure/refurbishment summary
While Mercury Arc Valve (MAV) based HVDC links were designed to last at least 35 years with major
overhauls, very few achieved this figure but Thyristor based HVDC links are designed to last at least 35-
40 years.
Not all converter stations will have a lifetime of 35 to 40 years. Therefore if running the equipment to
failure is not an option due to expensive consequential equipment damage and long unplanned outages,
midlife replacement and refurbishment of HVDC equipment is a valid option.

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The major HVDC equipment requiring life assessment activities are: converter transformers, valves,
valve electronics, controls and protection, valve cooling, AC filters, DC filters, smoothing reactors and
circuit breakers.
For HVDC links constructed in the 1970’s (early Thyristor links) the following life assessment activities
were undertaken:
• Valve controls and valve electronics upgrade: between 15 and 23 years in service after
commissioning. (some analogue systems are still in-service)
• Control and protection system upgrade: between 26 and 30 years in service after
commissioning.
• Replacement of MAVs with Thyristor Valves was normally done after 20-35 years of MAVs in
service. The replacement of Thyristors was completed after 21 to 30 years of Thyristors in
service.
• Cooling systems have been upgraded or replaced after some 25 years of service
• Replacement of oil filled Smoothing Reactors (with air core or oil) and oil filed Direct Current
Current Transducers (DCCT’s) after some 35 or more years of service.
• Refurbishment of converter transformers after about 30 years of service.
For the HVDC links constructed in the 1980’s, the following life extension activities were undertaken:
• control and protection system upgrade: between 23 and 27 years in service
• valve cooling system upgrade: after 24 years in service
• valve upgrade (together with valve cooling) after 27 years in service.
2.4. Alternatives and justification
In order not to degrade the performance of the HVDC link when some equipment is approaching its
design life the following alternatives are available:
a) selective repair and refurbishment or replacement of HVDC equipment
It is very important that equipment can be repaired as spare parts remain available, and the knowledge
base (engineering and technical staff) is being retained.
Equipment replacement is required if spare parts are not available (OEM’s are no longer in business.
Either the parts are phased out, discontinued, cannot be remade or they are reverse engineered locally),
or the knowledge base is lost (maintenance personnel familiar with the equipment are retired).
Selective equipment replacement is an excellent method to achieve the design life of the HVDC link if
other components that are not refurbished or replaced can last till the end of HVDC converter station
extended life.
As this document is not covering any increased ratings, the rating of the converter station will remain the
same.
b) complete replacement of HVDC converter stations
Complete converter station replacement is required when the majority of the equipment is at the end of
its design life; the HVDC link is still required for power transfer, or AC system performance improvement.
This can ultimately be a combined economic or technical decision as to how extensive the complete
replacement may be.

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Complete replacement of HVDC converter stations is also an opportunity to increase the steady state
power transfer capability, dynamic power transfer capacity of the link or where a lengthy outage to the
existing converter stations is not acceptable.
In any case, actions for extending converter station life need to be addressed before HVDC link reliability
and availability are impacted.
2.5. Methods for assessing reliability, availability and maintainability of existing
components
CIGRE’s Survey of the Reliability of HVDC Systems throughout the world enables HVDC link asset
owners and operators to compare the performance of their own HVDC link against the performance of
similar HVDC links in the world. It is recommended for owners seeking to access the reliability,
availability and maintainability of components, to actively participate in CIGRE HVDC user groups.
The goal is that the accumulated data from several systems would establish a basis against which
performance of individual HVDC links could be judged.
Performance of any HVDC system can be evaluated using data on energy availability (EA), energy
utilisation (EU), forced energy unavailability (FEU), scheduled energy unavailability (SEU) and thyristor
failure rates, as well as examining equipment categories causing forced outages or reduction of HVDC
system capacity.
In the CIGRE Survey and statistics carried out by Advisory Group B4.04, the following definitions are
used:
• Outage - The state in which the HVDC System is unavailable for operation at its maximum
continuous capacity due to an event directly related to the converter station equipment or DC
transmission line is referred to as an outage.
• Scheduled Outage - An outage, which is either planned or which can be deferred until a
suitable time, is called a scheduled outage. Scheduled outages can be planned well in
advance, primarily for preventive maintenance purposes, such as annual maintenance
programs.
• Forced Outage - The state in which equipment is unavailable for normal operation but is not in
the Scheduled Outage state is referred to as a Forced Outage.
• Forced Outages can be caused by trips - sudden interruption in HVDC transmission by
automatic protective action, manual emergency shutdown, or unexpected HVDC equipment
problems that force immediate reduction in capacity of HVDC stations or system but do not
cause or require a trip.
• Energy Availability (EA) - A measure of the energy which could have been transmitted except
for limitations of capacity due to outages is referred to as Energy Availability.
• Energy Unavailability (EU) - A measure of the energy which could not have been transmitted
due to outages is referred to as the Energy Unavailability.
• Energy Utilization (U) - A factor giving a measure of the energy actually transmitted over the
system.
For example, comparing the performance of one HVDC link against similar pairs:
Scheduled Equipment Unavailability (SEU) has less significance than Forced Equipment Unavailability
(FEU) in comparing different systems since scheduled outages may be taken during reduced system
loading conditions or when some reduction in power transfer capability is acceptable. Discretionary
outages for maintaining redundant equipment are also considered within the SEU category.

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2.6. Basis for replacement/refurbishment of equipment
HVDC converter station equipment (and subsystems) are complex and have varying design life times.
Each piece of equipment, system or subsystem should be assigned a “normal” life time which, as it
approaches, could trigger a life assessment
The criteria for the equipment replacement and refurbishment are related to the risks the asset owner is
ready to take and potential lost revenue which is correlated to equipment performance.
For example, capacitors can be replaced after design life is exceeded. However they can also be
replaced after the number of failures exceeds a percentage of installed capacitors per year (e.g. 2%).
The latter option implies a number of filter bank trips or loss of redundancy (maintenance outage), which
are the consequence of failed capacitor cans.
A conservative approach would be not to run the equipment beyond the manufacturers recommended
design life. An assumption is that the spare parts and skilled maintenance personnel are still available.
The following conditions could require equipment replacement or refurbishment even before the design
life is exceeded:
• Poor performance of equipment. An unacceptable number of HVDC trips caused by this
equipment reducing HVDC availability, or long scheduled outages required to keep the
equipment in a serviceable condition.
• The type of equipment is not manufactured any more (for example circuit breaker) and there
are no spare parts available. It is possible to postpone the replacement of the whole
equipment fleet, say of circuit breakers, by replacing one or more circuit breakers, and using
the parts from the units removed from service as a source of spares. In some cases the parts
can be reverse engineered by the utility if it has the knowledge or by other firms such as
tapchanger parts which specialize in this field
• Engineering and maintenance staff retiring and the knowledge base of how to maintain some
equipment is being lost and the supplier also cannot support maintenance of the equipment.
• The results of equipment condition assessments showing poor or deteriorating equipment
conditions (for example very low degree of polymerization paper inside converter
transformers), could justify earlier replacement, even before equipment design life is
exceeded.
• Failures of the same type of equipment at other HVDC links, could justify unscheduled
equipment condition assessment, and if required, early replacement
• Manufacturer instructions to remove equipment from service due to production defect (e.g.
use of unsuitable material for components during production) could result in early equipment
refurbishment.
• Under direction from an outside regulatory body (safety or environmental issues for example)
• Technical obsolescence – older software versions are no longer supported by the OEM and
the new software requires new hardware
• High Cost of Operations Maintenance and Administration. OP-EX stands for Operating
Expense. COMA – Stands for Cost of operations, Maintenance and Administration
2.7. Performance after replacement and refurbishment
Reliability performance data collected for CIGRE reporting purposes (data on energy availability, energy
utilization, forced and scheduled outages and other data in accordance with the reporting protocol
developed by the Advisory Group B4) can be used to evaluate success of equipment replacement.

Page 18
Performance improvement should be visible by comparing HVDC reliability data and loss of redundancy
data (number of forced outage events and the equivalent forced outage hours relevant to replaced
equipment category) two years before replacement and two years after replacement.
However if the equipment was performing well and had enough spare parts (for example the control and
protection system), but was replaced with the new model due to obsolescence, then good performance
in the future will be the sign of successful equipment replacement. If equipment is replaced as result of
condition assessments identifying poor or deteriorating equipment, prior to the equipment actually
affecting performance indicators. There could be an expectation of a reduction in maintenance and that
should be reflected in maintenance records and maintenance hours required.

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3. Chapter 3 – Life Assessment and Life Extension Measures of
Equipment
Chapter 3 comprises the following sections, each addressing performance issues and technical life
assessment, including:
• Remaining life (where feasible)
• Refurbishment
• Maintenance
• Possible tests after a fault (converter transformer only)
Maintenance is a critical part of achieving the ability to extend the life of the DC equipment. If proper
maintenance is not performed life extension may not be possible or severely limited.
Most converter stations employ some kind of Computerized Maintenance Management System (CMMS).
It can be part of a larger system, a standalone system or a home grown system. There is continuing
pressure on reducing maintenance costs and outage times and some utilities have gone to Reliability
Centered Maintenance (RCM) Systems and away from time based systems. RCM generally relies on
doing maintenance based on levels of inspections, importance of equipment, is condition based and
relies on appropriate and timely maintenance intervention. This has the effect of improving reliability and
availability and reducing maintenance costs. This can be a hard sell to existing converter station staff
that are used to a time based system.
During the warranty period the OEM’s maintenance requirements must be followed and well documented
to prove that the maintenance has been completed. After this period condition based maintenance or
RCM can be adopted.
It is very important to have good maintenance records to analyse the equipment performance with the
Root Cause Analysis of any failures. Complete systems have been replaced by utilities because the root
cause of the problem was not identified and thus the problem was still there after replacement. Trend
analysis is also very important as a bad reading or information or statistical analysis can skew an
analysis with very little data. Good records are also very important to assist in justifying any
refurbishment or replacement as it can be readily shown how much improvement is possible and what
the benefit could be in increased revenue.
Spares
The number of spares that are available especially for items such as the DC controls can impact the
usable life of the equipment. Spares can be broken down in many ways, one way is as follows:
 RAM and performance guarantees spares – Spares required to meet the RAM, and performance
guarantees requirement of the contract usually 2 years.
 Initial spares- Spares for the first 10 to 15 years to get a record of the failure rates and then to
order more. The supplier will usually guarantee availability for that period
 Insurance spares – Spares to cater for infrequent failure ( e.g. DC wall bushing)
 Consumable spares – Items to be consumed due to normal failure rates (e.g. fan, motors)
 One supplier items – Some items are only available from the OEM, control cards are an example
whereas AC filter capacitors are available from many vendors on relatively shorter notice, and
thus stocking levels will likely be different. In most instances exact replacements should be
available; however in certain instances a re-design of the bank may be required.

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Some utilities are starting to specify that enough spare parts be supplied to last the 35 to 40 year life of
the project. This could help ensure the viable life of 40 years of these types of devices but may be
difficult to estimate the requirements.
3.1. DC Switchyard Equipment
DC Switchyard equipment has both AC and DC voltages imposed on it. Oil and paper is an effective
insulator for AC voltages and the dielectric stresses in the insulation remain relatively constant over a
fairly large temperature range. DC voltages must be constrained by paper and pressboard in what has
been called a “DC Cocoon” by one supplier. The dielectric stresses for DC Voltages vary more with
temperature and with different types of materials. Over the years this has caused problems even with
established suppliers. Another issue is that DC ions and charges do not dissipate for many hours and
this must be considered especially for a polarity reversal. This is a particular concern when designing oil
filled smoothing reactors as well as converter transformers.
Laboratory testing has shown that shed profile and material types are important for HVDC equipment
airside performance especially at higher HVDC voltages over 300 kV DC.
3.1.1 Oil Filled and Air Core Smoothing Reactors (SR)
Description:
The first used Smoothing Reactors were oil filled and had relatively large inductance values to limit the
fault current on the line side of the Smoothing Reactor to that which the Thyristor’s could still maintain full
control and or avoid a DC Line resonance. As Thyristor capability advanced, this, in most cases,
permitted the reduction in the inductance value. Advances in air core reactor technology have allowed
their use as Smoothing Reactor, virtually replacing the oil filled reactor. The advantage being lower cost,
simple design, low maintenance, no oil spill containment required and less risk of fire. Smoothing
reactors perform a number of functions:
• Reduce the probability of valve commutation failures
• Prevent discontinuous current at low power levels
• Allow the valves to remain in full control for a fault on the line side of the SR
• Reduce front of wave DC line surge
• Reduce the DC harmonic voltages seen by the DC filters
• May be used to de-tune the DC transmission line resonances
Performance Issues:
Both oil filled and air core have faced failures and problems, but these issues are generally different.
The oil filled SR’s contain large amounts of paper insulation and at least one SR has failed due to
inadequate drying of the oil after maintenance and refurbishment. DC bushings are another source of
failures. Replacement DC bushings are not available in some instances if the original equipment
manufacturer (OEM) is no longer in business and the replacement must be the exact same make and
model. The DC barriers at the oil end of the bushing combined with the matching foils of the DC bushing
capacitance core and the “special” low sodium porcelain make this problematic. This type of porcelain is
no longer made by NGK and the one supplier ABB has done away from an HVDC oil end porcelain all
together. Others have gone to RIP Bushings with or without SF6 gas insulation depending on the
voltage. Another option is foam insulation instead of SF6 gas and the foam can contain SF6 bubbles or

Page 21
nitrogen bubbles. Oil spill containment and fire protection is now usually required, but because of this
risk and cost, has accelerated the replacement of oil filled reactors with air core ones.
Air Core SR’s have an exterior coating of paint or RTV which protects the insulation from the sun and
Ultraviolet (UV) rays. Cracks in this coating have allowed sun and moisture to get in causing failures.
These coatings have to be re-applied or renewed approximately every 10 years depending on
environmental, sun and pollution conditions. Some air core reactors have been lifted improperly during
installation also causing failure later. When they are tested in the factory, Air core SR’s pass the noise
test because there are no harmonics. However, in the field with harmonics present, they may or may not
be acceptable. If they become too noisy then they are outfitted with noise barriers. Conversely, if they
were not designed for this and the increased temperature causes shorter life and has resulted in failures
and fires. Some air core SR’s have “Black Spots” on them but no failures have been reported to date. An
addition of corona rings may eliminate the black spots.
Technical Life Assessment:
The average life of oil filled or air core Smoothing Reactor is 35 to 40 years but could be more or less
depending on the issues faced by a particular HVDC system. The oldest in-service air core smoothing
reactor as reported by Trench Canada was built in 1980. The DC bushings on the oil filled reactor may
limit the life of the oil filled SR with oil filled bushings having a life of 25 years and RIP bushings 30
years. This number of 25 years was derived from statistics for AC bushings. Thus they may not be
directly usable for DC Bushings which have a bit more insulation and appear to have a longer life. But
this life assessment number merely suggests that an assessment would be prudent at that time. DC
bushing failures were fairly common in the past and an analysis of the failures led to implementation of
new test levels of 115% of the level that the SR is tested at. DC bushings have a shorter life than the SR
itself and if replacement DC bushings are not available for any reason this becomes a major issue. The
IEC/IEEE Standard 65700-19-03 (Issued July 10, 2014) is a joint Standard with IEC and IEEE on DC
Bushings. It highlights that the DC bushings are not interchangeable, and while not required by the
standard, it would be beneficial if the supplier provided sufficient information so any DC bushing
manufacturer can supply the bushings. It is possible to replace the DC bushings, the DC barriers, DC
bushing leads and field test but this is risky, very expensive and may still result in the SR replacement.
Loose blocking is another concern because of the large amount of paper involved in oil filled SR. If there
is sufficient room, it is possible to place jacks in the support beam area and add insulation. The blocking
should be checked by internal inspection every 20 years. The internal inspection can detect loose core
laminations. For the remainder of the assessment, it is treated the same as a converter transformer (see
section 3.3 below).
For air core SR’s, the support insulators are critical for mechanical support and dielectric support. Shed
profile, such as long short or anti-fog, is important. After 25 to 30 years, two of the insulators should be
removed from service and tested both mechanically and electrically. Failure of the grout between the
metal flange and the porcelain is a common cause of problems. Deterioration of the outer coating of the
SR itself such that the aluminium conductors are corroded would be a cause for immediate replacement.
If a noise barrier is installed in the field the difference in the temperatures from the factory tests and field
test would allow for a calculation of loss of life as every 6 to 8 o
C is a half-life. This has been the problem
of premature air core SR failures.

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Refurbishment:
For an oil filled reactor it is likely that the DC bushings will have to be replaced as oil filled bushings have
a 25 year life and RIP has a 30 year life (according to the DC bushing suppliers) whereas the SR itself
has a 40 year life. DC bushings noted above has approximately 150 kV DC may have an oil end DC
barrier requiring the DC bushings to be replaced with the exact same type, make and model. DGA
sampling on all bushings (this must be done with care not to introduce contaminants or moisture into the
bushing and some DC Bushings may require re-pressurizing with nitrogen) and dielectric tests at
reduced test levels on at least two DC bushings will determine the end of life. The dielectric test level
should be at least 10% above the protective level of the associated lightning arrestors. DC Bushings at
or below 150 kV do not normally have the oil end DC barrier and can be supplied from a supplier other
than the OEM. However, after this period of time the original supplied DC bushings of higher voltage
may no longer be available. Then the oil filled SR will have to be replaced and it will likely be replaced
with an air core SR. The DC smoothing reactors have large amounts of insulation, especially at higher
voltages. This insulation gets squeezed or settles down over a period of 20 to 25 years. If there is
sufficient room, consideration should be given to do a field repacking of the insulation with small jacks
and oil impregnated pressboard to extend the life of the SR. There does not appear to be any economic
benefit to replacing the winding on an oil filled SR as this cost will likely be as great or greater than that
of a new air core SR. Most of the gasket materials and O-rings have a life of 40 years (nitrile) used in the
SR’s and oil filled bushings will likely require replacement. Various sealants have been used successfully
to seal oil leaks to defer the cost of replacing the gaskets or O-rings which can be very expensive when
oil processing and outage costs are considered.
For an air core smoothing reactor the most critical area is the outer coating of paint or silicone RTV. This
coating has to be refurbished every 10 years (more or less) to protect the SR insulation and applies to
both outdoor and indoor installations as most indoor lights emit ultra-violet (UV) radiation. Owners of the
air core SR’s may not be aware of this requirement. This coating keeps out UV radiation and moisture
which if not refurbished will result in insulation failure, corrosion of the winding and require replacement.
Remaining Life:
The remaining life of a SR is dependent on many items such as years of service, operating conditions,
design temperatures, DGA availability of spare/replacement parts, internal inspections of oil filled SR,
test results and maintenance records. This usually requires the services of an Independent Expert in that
area to determine what may also be required by the management in a company to lend credibility to any
decision. Because outage of an SR is a pole outage, outage costs can be very expensive, so the amount
of risk (if any) that a company is willing to tolerate is limited. While any decision to refurbish or replace
also depends on the cost of outages and economics of a company, only the technical aspects will be
considered here. The only economic consideration will be the fact that oil filled SR’s are more expensive
than air core reactors both in capital cost and maintenance costs.
The DGA results are very important in making this decision but will be discussed under the Converter
Transformer section. The other major factor is the condition of the DC bushings and availability of
replacements. Oil filled SR’s have a risk of environment contamination and risk of fire which, if oil
containment and fire protection is not provided on the existing equipment, may also assist to justify
replacement rather than refurbishment.
Items to consider when determining whether or not to refurbish or replace
Oil filled SR’s and the DC bushings with the following problems are probably best replaced:

Page 23
 bad capacitance measurement of power factor measurement,
• or critical DGA of the oil,
• or DC bushings are no longer available from the OEM and the DC bushing has an oil end DC
barrier,
• and is over 25 years old.
When considering the replacement, it may be possible to reduce the milli-henry inductance of the SR
making it more economical. If the DC Bushings are the problem, it may possible to refurbish the SR by
replacing the DC leads, DC barriers and DC bushings with RIP and may be considered if the SR is less
than 25 years old. However this is costly and you still have an aged SR. Usually these oil filled reactors
do not have oil spill containment and fire deluge protection making it easier to justify replacement with air
core units. Other problems that could cause immediate replacement is failure of the spare due to
unknown causes and high DGA gassing results indicating temperature over 150 o
C and paper
degradation by CO2/CO ratio. See Converter Transformer DGA Results for further details.
For the air core reactors the deterioration of the outer protective coating, such that the insulation and
aluminium conductors are visible, would be cause for immediate replacement. If the outer coating is only
slightly cracked or the areas are splotchy; they can be refurbished by recoating, which extends the life of
the air core reactor. Another concern is if the air core reactor has a noise shield and it was not required
in the factory but was installed afterwards in the field. It is likely that the units will have a reduced life and
require replacement sooner than the expected 40 years.
After 25 to 30 years two of the support insulators should be replaced with spares and tested dielectrically
and mechanically, for remaining life. Depending on the number of insulators and the cost, it may be
advisable just to replace them.
When replacing SR’s, consideration could be given to installing multiple reactors in series to form the
design value but providing some installed redundancy to allow for removal of single reactors for future
maintenance and/or repair. The allowable tolerance for sizing of reactors needs to be determined
through appropriate study.
Remaining life 10 years or more:
If the units are less than 25 to 30 years of age, there will likely be a remaining life of 10 years or more.
For oil filled SR, it is likely that these units will survive 10 years or more:
 if the DC bushings are in good condition and/or spares are still available from the OEM,
 the SR itself is not gassing, or at least not badly
 an internal inspection shows it to be in generally good condition.
For the air core reactors, if the outer coating is in good condition and has been regularly recoated
throughout its life and the noise barrier was factory installed it is likely that these units will survive 10
years or more.
Further Assessment Required:
For all other conditions further assessment is required as the number of combinations get complicated.
Additionally, company management may require an outside opinion for various reasons. The best option
would be an independent analysis with assistance from the OEM supplier.

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Maintenance:
The most important maintenance aspects of the oil filled reactors are regular Dissolved Gas Analysis
(DGA) sampling and capacitance and Dissipation Factor (DF) tests on the DC bushings. Other tests
such a resistance and Swept Frequency Response Analysis (SFRA) should be performed if the DGA
results indicate some possible problems. An initial or prior SFRA test is necessary to have a “signature”
to compare with. All the auxiliaries such as fans, pumps and instrumentation should be checked
periodically.
A visual inspection of both types of SR is recommended, to look for oil leaks, broken bushing sheds and
anything abnormal. Infrared and Corona scope tests are also recommended yearly for both types as
well, looking for hot spots on the reactor and any associated bus work and bus connections. All
insulators should be checked for cracking or damage and contamination.
For the air core SR keeping the air cooling vents clear of debris and blockage is most important as well
as inspection of the outer coating to protect the insulation.
FIGURE 1 OIL FILLED SMOOTHING REACTOR

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FIGURE 2 AIR CORE SMOOTHING REACTOR
3.1.2 Voltage Divider (VDR)
Description:
The voltage divider can be either oil or gas filled device consisting of a non-inductive wound resistor with
a capacitance in parallel. There is voltage measuring electronics at the base of the unit for sending the
signal to the control room via “special” wire or fiber optics. The VDR for higher voltages may be made
with two or more sections joined together and the outer housing can be composite or porcelain.
Performance Issues:
The VDR is used in the control of the HVDC system such that any problems with the VDR result in a
system disturbance and is quickly noticed. Corona discharges on the exterior of the porcelain have
resulted in erratic DC readings and disturbances. Coating with Silicone RTV should eliminate this
problem. If more than one section is used there can be and have been problems with the electrical
connection between the two sections. While this will again show up as a disturbance, this type of fault is
difficult to ascertain as it is intermittent. An oil leak, if severe or unnoticed, can cause a unit to fail.
Overall the VDR’s are very reliable. Newer units may have silicone rubber sheds.
A VDR is considered to have a life of 40 or more years. Degradation of the capacitance will likely occur
at the end of life, and because of the relative low cost, replacement should be considered. While these
are normally sealed units, if there is a filling port, an oil sample may be taken for DGA analysis. Again
care must be taken to prevent contamination of the oil with moisture or other. Any replacement decisions
should consider the advantages of moving from oil to gas or solid insulation filled units.
When fiber optics is used to send the signals to the control room, the associated electronics will likely
require repair or replacement prior to the end of life of the actual VDR. Replacement can be avoided by
carrying appropriate spares or sourcing identical replacements as required.

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Refurbishment:
In the case of an oil leak and it is not near its end of life, the unit can be refurbished. This is likely cost
effective at higher voltages, but is less likely at lower voltages.
Maintenance: The following maintenance should be performed:
 Visual Inspection for oil leaks, tracking on the insulator, corrosion, broken sheds, etc. If gas filled,
check for pressure, check and replacement of anti-moisture silica gel in the secondary terminal
box.
 On a less regular basis the voltage divider scaling and ratio should be checked by primary
injection. The procedure should be provided by the OEM.
 Corona scope. Initially after installation, after each maintenance and periodically thereafter the
unit should be checked for corona especially during fog or light rain
 Resistance and Capacitance measurements – During the periodic maintenance outages the
resistance and capacitance should be measured.
3.1.3 DC Current Transducer or Transductor (DCCT) or DC Optical Current
Transducer (DCOCT)
FIGURE 3 KRAEMER STYLE DCCT
Description:
DCCT‘s have evolved the most of any of the DC measuring devices. The most common ones will be
described here but it is most likely others will be encountered. The first one was called the Kraemer type
and required a voltage such as 600 Vac to chop up the current wave-form so it could be brought to
ground potential via a transformer. The chopped up waveform then was rectified and scaled to represent
the DC Current. This required a no-break AC supply usually from a motor generator (MG) set or a
battery bank inverter. The next type of DCCT was the Hall Effect where the flux was measured in the
DCCT core, which produced a voltage that scaled to represent the DC Current. An improved version of
the Hall Effect is the Zero Flux DCCT. This used electronics to produce an equal but opposite flux to

Page 27
that produced by the Hall Effect. The measurement of the electronic current was scaled to represent the
DC Current.
The next type is the DCOCT or Optical DCCT, which is a bit of a misnomer as it is not completely optical.
The DC Current is measured by a DC shunt and the millivolt signal is measured by electronics in the
head of the DCOCT. The signal is then transmitted via fiber optics to ground potential and to the HVDC
controls. The electronics and fibers are duplicated for redundancy and are powered by another fiber
optic and laser diode from ground potential. This type of DCOCT can be a free standing device
supported by a porcelain insulator or in a fiber glass tube with silicone rubber sheds. It can also be an in-
line device supported by the conductor itself and a small thin insulator string housing the fiber optics. The
final type of DCOCT is a true fiber optic device and uses the Faraday principle. This is comprised of a
fiber optic cable that is wrapped many times around the conductor. A polarized light is injected into the
cable at ground potential and the change in the polar angle of the light is detected and measured upon
its return. The amount of the angle change corresponds to the amount of DC current. The advantage of
this type of DCOCT is that the fibers can be wrapped around the ground flange of a bushing so there is
no expensive high voltage to deal with and corresponding reduction in cost. It is highly accurate even at
low currents.
There are a number of lower voltages high current DCCT’s which are not discussed here.
The cost of these devices continues to come down and it is possible to have a combined device with a
voltage divider, which can potentially further reduce costs if both are required.
Performance Issues:
The porcelain insulator has been a problem with tracking and flashovers. This has caused gassing in the
oil and eventual failures of the devices themselves. The application of Silicone RTV has largely resolved
this issue. Oil leaks are a continuing problem as the device ages and the paper insulation of
transformers in the Kraemer style units show up with age as well. The Kraemer style DCCT’s also
require the MG sets or battery bank inverter. However, with lack of spare parts for these devices as well;
it soon becomes economical to replace the unit if over 25 to 30 years old once they show signs of
problems.
Other problems have been with the electronics and the fiber optic connectors and are relatively easily
resolved but the forced outages they cause can be significant.
Once the Kraemer style DCCT starts showing signs of aging it is likely best to replace. This allows the
removal of the MG sets or battery bank inverter, improving reliability (fewer parts) and reducing
maintenance costs. The availability of spare parts and optical fiber (fiber connectors) will determine the
technical life of the equipment. The fiber optic outer sheath will deteriorate with age as will the laser
diodes. As long as the parts and fibers optic connectors are still available they can likely be kept in-
service.
Refurbishment:
In most cases, it is not likely that the devices can be successfully refurbished and considering the cost
may also not be economical. Exceptions may be the fiber optic cables and some electronic cards.
Removal of the Silicone RTV from porcelain sheds by blasting with walnut shells or dry ice and
replacement of the silicone RTV may be necessary in high pollution areas.
Maintenance:

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Periodic testing of the fiber optic cables and laser diodes is necessary. DGA analysis of the oil filled
devices should only be done if there is a problem suspected as contamination of the oil is a serious
concern. Protecting the fiber optic cable from light can increase the life of the outer sheath in the control
room, cable trays and in the cable termination boxes.
 Visual inspection.
 Cleaning as necessary
FIGURE 4 DC OPTICAL CURRENT TRANSDUCER
3.1.4 DC Surge Arrestors
Description:
DC Surge Arrestors are very similar to AC arrestors but contain about 20% more discs. However, they
are a lot more expensive than an equivalent AC arrestor. The number, location and energy ratings vary
depending on the insulation co-ordination study for that particular DC scheme. The older units were a
porcelain housing and gapped silicon carbide discs. The newer ones are gapless zinc metal oxide and
the housing may be made of fiberglass with silicone rubber sheds instead of porcelain.
Performance Issues:
Moisture ingress is one of the most important issues as a surge can then cause the unit to fail and it may
fail catastrophically in spite of venting devices. A similar problem can occur in the counter and if it is
located at ground level can be a safety hazard as it fails catastrophically.
The DC surge arresters should last for 40 or more years. A lot will depend on the number of switching
operations and the sealing against moisture. High voltage tests are done periodically on the gapped
silicon carbide arrestors and if defective they are replaced. For the gapless metal oxide the leakage

Page 29
current is measured in-service or during a test and if out of range the unit can be replaced and tested. If
several units of a similar type are replaced; consideration should be given to replacing them all. The life
of silicone rubber sheds is currently not known as they have not been in-service for very long. However
silicone RTV has been in-service for over 25 years without recoating, so it is expected the silicone rubber
sheds will last at least that long and possibly longer.
Refurbishment:
DC arresters are not normally refurbished.
Maintenance:
• Visual inspection
• Cleaning as necessary
• Testing as outlined above
3.1.5 DC Support insulators and Bus work
Description:
The DC support insulators may also be called post insulators and look very similar to AC support
insulators. They support the DC bus work and other equipment such as the air core type SR. DC support
insulators fabricated with a fiber glass core and silicone rubber sheds have shown improvements in
voltage withstand, increased mechanical strength, less weight and less cost. They are new to the market
but have been adopted as a replacement in one instance.
Performance Issues:
The DC support insulator is affected by more than just creepage and strike distance such as the case for
AC support insulators. It is affected by shed profile, insulator material and voltage stress in kV/mm. This
is not always appreciated even by the HVDC suppliers but has become better known since 800 kV
HVDC was achieved. As an example a rectifier HVDC Converter Station built in the 1970’s had an
increased creepage applied for the DC switchyard design. Yet in service they experienced an average of
14 DC side flashovers per year and likely as many at the Inverter Station. All the support insulators were
coated with silicone RTV and no flashovers have been recorded in the 3 years since. A higher DC test
voltage was obtained in laboratory tests with an alternating long short shed profile or an anti-fog shed
profile than sheds that are uniform in length or helicoidal (spiral). Silicone rubber has performed better in
the field and in tests it supports a higher voltage before flashover than porcelain. Corona scope
measurements in the field also show an improvement.
Deterioration of the grout between the metal flange and the porcelain is an issue and can go unnoticed
until a failure occurs or the bus work is removed and the metal flange separates from the porcelain at
that time. Vibration and/or contaminants in the grout can weaken the support insulator and cause
failures.
Green glass support insulators were produced with a contaminant in the glass. This contaminant grows
with time and eventually shatters the sheds. This becomes a safety issue as well as a performance issue
and will likely require their replacement. This problem has not appeared in the glass DC transmission
line insulators.
The life of a support insulator should be 40 years. Flashover performance of porcelain insulators is an
issue in some HVDC schemes. Spraying on silicone RTV has solved the problem and can have a

Page 30
service life of over 25 years depending on pollution levels. Silicone RTV can then be removed by
blasting with walnut shells or dry ice so as to not damage the porcelain. The insulator can then be re-
coated with silicone RTV coating. It is also noted that silicone RTV has been applied on porcelain
support insulators for a new 800 kV DC station in China.
After about 20 to 25 years, it is advisable to remove 2 or 3 representative support insulators and test
them mechanically and electrically.
Refurbishment:
Apply an RTV coating on porcelain support insulators if DC side flashovers are a problem.
Maintenance:
• Visual inspection.
• Cleaning as necessary
FIGURE 5 DC POST INSULATOR AND DCCT RED CAP DEVICE
3.1.6 DC Switches – See also AC Switchyard
Description:
The DC switches are for the most part just AC equipment but a single phase complete with operating
mechanism. The high speed switches are AC breakers which are interlocked such that the DC current
must be below 50 Amperes before they can open. There are also some “specialty” devices called

Page 31
Metallic Return Transfer Breaker (MRTB) and Ground Return Transfer Breaker (GRTB) which
commutates the current into the DC line conductors or back into the ground electrode as required. The
specialty devices comprise an inductance and capacitance which create an oscillatory circuit for a
current zero. This allows the breaker to open at a current zero and transfer or commutate the current.
The older converter stations and some of the new high voltage 800 kV have more than one valve group
in a pole and require Bypass Switches (BPS) (AC breaker) and disconnects. The newer BPS is also a
special SF6 breaker which must be able to commutate the current into the Thyristor Valve. The older
BPS’s were air blast devices. There was also a bypass vacuum switch (BPVS) used in at least one
HVDC link.
DC breakers are not covered by this TB

Page 32
3.2. Valves
Description:
The first HVDC Valves were mercury arc valves which started in 1954 with a link between the island of
Gotland and Sweden. Virtually all mercury arc valves have been removed from service and replaced with
Thyristor Valves. In the early 1970’s the HVDC valve design switched over to Thyristor valves. Many of
the early schemes had lower power schemes, were air cooled and air insulated but as higher power
levels were required the design shifted to air insulated and de-ionized water cooled starting in the late
1970’s. There was even one scheme, the Cahora Bassa project between Mozambique and South
Africa, which was oil insulated and oil cooled. The South African end, called Apollo Converter Station,
was converted to air insulated and de-ionized water cooled, while the Mozambique end called Songo
Converter Station remains oil cooled at this time. Also for higher current levels, there were two or more
matched (for forward voltage drop) Thyristors in parallel, but Thyristors developed quickly and soon only
one Thyristor in parallel was required for most ratings. There were many Thyristor in series to achieve
the voltage level required with a high of 280 devices for the early Thyristors to a low of 48 or less for
more modern ones with most being in between. In about the year 2000, light triggered Thyristors
became available, which reduces the amount of valve electronics that are normally required by the
electrically triggered Thyristors.
Each valve hall has either six Thyristor Valves for 6 pulse operation or 12 Thyristor Valves for 12 pulse
operation. They can be arranged in single unit, two in a unit called a Bi-Valve (double valves) or four in a
unit called a Quadra-Valve (quadruple valves). The units can be floor mounted if there are no seismic
concerns or hung from the ceiling if there are seismic concerns.
Each Thyristor Valve is broken down into “representative sections” which allows some of the factory
tests to be done on a “representative section” rather than the full Thyristor Valves, reducing the cost of
testing. As an example in the case of 280 Thyristors it is broken up into 20 sections, so 14 Thyristors per
section. Included in each section is a Valve Reactor and two Thyristor Modules with 7 Thyristors in
series and two in parallel in each module. The Thyristor is susceptible to excessive rate of change of
voltage (dv/dt) and rate of change of current (di/dt), both must be kept below a stated value in order not
to cause thyristor failures. The valve reactor is designed to limit the rate of change of current (di/dt) when
the Thyristor Valve is turned on or off to a level below that which the Thyristor itself is capable of
surviving. The valve reactor contains a number of iron cores which saturate at different current levels
providing high impedance during turn on or turn off and yet low impedance when the Thyristor is fully
conducting. For water cooled valves the valve reactor is also usually water cooled with the cooling
circuit buried in the reactor winding. The valve reactors also have a damper winding or a resistor across
it to damp out any resonances that may be associated with in the circuit.

Page 33
FIGURE 6 50 MM THYRISTOR AND 100 MM THYRISTOR
FIGURE 7 A DISSECTED VIEW OF A 100 MM THYRISTOR
Across each Thyristor level is a damping circuit (also called snubber circuit) consisting of a non-inductive
wound resistor and a capacitor. The capacitor was oil filled in the older valves but is more likely SF6
filled or dry type in newer valves to reduce the risk of fire. The snubber circuit is required to limit the rate
of change of voltage (dv/dt) across a Thyristor to a level below that which the Thyristor itself is capable of
surviving. There may be another damping circuit across each valve section or across the entire valve
assembly. Also, there may be a Voltage Divider across each Thyristor level to measure the voltage
across the Thyristor when it is not conducting which is another non-inductive wound resistor. If the
Thyristor fails it is short circuited; this is then used to determine that a Thyristor has failed as there is no
reverse voltage across it when the voltage reverses. Across each Thyristor Valve section may have a
capacitor which provides transient and temporary voltage grading across the entire Thyristor Valve
structure.
While there are a number of important parameters in choosing a Thyristor for a valve design, one very
important parameter is Qrr or the stored charge when a Thyristor turns off. The stored charge for each
Thyristor is measured in the factory and assigned to a band or range of stored charge. Each band is then

Page 34
assigned a color number or letter. Each Thyristor Valve has the same Qrr band and replacement
Thyristors must have the same color as an example. In some cases a Thyristor from a neighboring band
are allowed as well. For example if the required Thyristor is a B level Qrr it may be acceptable to use an
A or C level but not a D level. In modern day Thyristors there is a large variation in Qrr that is acceptable
and matching may no longer be required
The Thyristors and some of the components listed above are usually installed in a module. It may be
possible to remove a module from service and replace the defective module with a good module or
repairs completed in place without removing the module. If the module is fixed in place it usually
becomes part of the valve structure. The advantage of the removable module was that it could be
replaced quickly allowing the valve group to be quickly returned to service. The disadvantage was the
increased cost and the risk of bad electrical and water connections which have to be reconnected each
time. Most of the more modern designs now have the module fixed in place. Each Thyristor is triggered
either electronically from some electronic cards or from an optical fiber connected directly to the Thyristor
gating terminal. The electronic cards are called many different names by the different suppliers and have
even changed names over time for the same supplier. They will be generically referred to in this
document as Thyristor Control Unit (TCU). The TCU has optical receivers to convert the optical signal
received from the Valve Base Electronics (VBE) via the optical fibers to an electrical signal to trigger the
Thyristors. The function of the VBE is discussed in the DC Controls and Protection Section 4.5 below.
The fiber optics can be glass fiber or “plastics” fibers. The TCU will also provide power to the electrical
cards usually via the DC voltage across the Thyristor when it is not conducting and stored in a capacitor.
The capacitor energy storage allows it to ride through AC system faults of typically 100 milliseconds but
may be longer in the case of breaker failure.
FIGURE 8 NELSON RIVER BIPOLE II REACTOR MODULE

Page 35
FIGURE 9 NELSON RIVER BIPOLE II THYRISTOR MODULE WITH TWO 50 MM THYRISTORS IN PARALLEL, A WATER COOLED
RESISTOR AND CAPACITOR DAMPING CIRCUIT. THIS MODULE IS REMOVABLE FROM THE VALVE STRUCTURE.
FIGURE 10 LAMAR THYRISTOR MODULE WHICH IS PART OF THE VALVE STRUCTURE INCLUDES A SINGLE THYRISTOR IN SERIES
AND A DAMPING CIRCUIT
In the case of a DC side fault in the converter station the amount of energy that the Thyristor can handle
is limited. This requires the tripping of the AC breakers in a relative short period of time such as 2 to 3
cycles. To achieve this speed, a Thyristor or other solid state device direct tripping of the AC breakers, is
provided instead of relays.
The control of the triggering point in the waveform determines if it is used in the rectifier mode or the
inverter mode. In the rectifier mode the thyristor is triggered with an alpha between 12 and 18 degrees
electrical whereas in the inverter mode it is triggered with an alpha of about 135 degrees electrical.
The Thyristor modules are stacked in tiers with post insulators between the tiers. There is corona
shielding on the top and bottom and around each tier as required. There are usually fire barriers between

Page 36
tiers to prevent the “chimney effect” (which is for the fire to race upward) in the event of a fire as there
have been a number of Thyristor Valve fires over the years. There may also be fire barriers in the tiers to
separate components such as the oil filled capacitor.
FIGURE 11 NELSON RIVER POLE II VALVES
The fiber optics is installed in a channel with a cover on it making it difficult to inspect for defective fiber
optics. The outer coating of the fiber optics for the early fibers will deteriorate with ultraviolet light. Many
HVDC schemes operate with the lights out in the valve hall for that reason and to save energy.
Thyristor Valve Hall:
The Thyristor Valve hall is sized to provide adequate air gap clearance for the voltage that it is operating
at. The valve hall will normally be air conditioned for the older water cooled Thyristor Valves and not air
conditioned for the more modern ones. In the case of non-air conditioned valve halls, the temperature
can reach 50 or 60 o
C. This has an impact on personnel that may be working in the valve hall for
maintenance and has a design impact on all the components in the valve halls such as wall bushings,
bus-work, as they historically were designed for lower temperatures. Other components in the valve hall
include converter transformer bushings which stick through the wall and are sometimes mistakenly
called wall bushings. For the DC wall bushings, they normally have a DCCT at the flange or there may
be a free standing DCCT to measure the DC current into or out of the valve hall. In some older projects,
a capacitor connected across the valve group for transient voltage grading for multiple Valve Groups in a
pole. The capacitor is usually placed inside the porcelain housing so it may not be obvious that it is a
capacitor. There is also a DC valve arrestor across each Thyristor Valve which may or may not be part of
the Thyristor Valve structure. The valve arrestor is part of the insulation co-ordination study for the
converter station and the highest voltage valve DC arrestor may have a higher energy rating than the
remaining ones in the valve hall.
There may be more than one valve group in series in a pole (4 in the case of Cahora Bassa) but one is
typical for more modern schemes up to 500 kV DC. With the advent of 800 kV there are one or two

Page 37
valve groups per pole and it is anticipated this will be two valve groups per pole for 1100 kV DC which is
currently under development.
The valve hall is usually equipped with fire detection systems but very rarely a fire suppression system.
Fire suppression systems within the valve hall, if considered, should be manual action with at least two
deluge valves in series of different manufacture. The system should not be pre-charged. The fire
detection system can be regular smoke or ion detectors, air sampling systems and/or beam detectors.
The air sampling systems, of which there are two different types, provide the quickest response. A
thermal barrier during a fire at the ceiling can prevent regular smoke or ion detectors from operating
properly. The high air flow rates of the air cooled valves will make fire detection even more challenging.
Thyristor Valve Cooling systems:
The Thyristor Valves generate heat from the losses associated with the forward voltage drop and load
current through the Thyristors and valve reactors when they conduct and from the snubber circuits when
they operate during turn on and turn off. Heat from the other components in the valve hall will make up
the remaining heat loss but this is usually minimal.
In the case of water cooled valves approximately 5 to 10% of the heat is removed by the air cooling
system and 90 to 95 % by the De-ionized Water (DIW) cooling system.
The cooling air is routed via channels through the valve structure and normally comes from outside air.
In colder climates there will be some air recirculation and heaters. This is discussed in more detail in
section 3.6 below. The air must be highly filtered to prevent dust accumulation and the valve hall is
usually pressurized to further prevent dust infiltration.
In the case of air cooled valves, there are usually fans to direct the air through the valve structure to
ensure adequate cooling throughout the valve and 100% of the valve is cooled by air.
The deionized water cooled Thyristors have a heat sink on each side of the thyristor “puck” which are
tightly clamped at a high contact pressure and may include a grease or similar compound to prevent
oxidation and enhance thermal conduction. The heat sinks must have a low thermal resistance. The
snubber resistors are also likely water cooled as are the valve reactors modules. The valve reactor
modules will have the cooling circuit imbedded in the main reactor winding.
De-ionized Water (DIW) is a very efficient heat transfer media and has become the norm for modern
Thyristor Valves. It allows for a more compact design, higher power levels and is used in closed loop
systems. The Thyristor heat sinks are fed from manifolds in parallel from Siemens and Alston Grid but in
series in each module from ABB. The water needs to be deionized to remove free ions and minimize
electric current flow in the water in the tubes. This is accomplished with cation and anion resin beds,
which require regular maintenance. One supplier, ABB does not vent the deionized water system and
thus has oxygen scavengers in the resin beds as well. The other two suppliers vent to air as breakdown
of the water into Hydrogen and Oxygen occurs at high voltage. In addition there are sacrificial anodes in
the water circuit made of stainless steel (Alstom Grid) or sacrificial anodes of platinum (ABB and
Siemens) to prevent corrosion. These must be checked periodically for corrosion or deposits.
The water circuit may be a single loop system (includes industrial grade glycol for cooler regions) or a
double loop system. The double loop system will have DIW in the Thyristor Valve circuit and regular
water or glycol in the outdoor cooling circuit, glycol for cooler regions. A single loop system brings the
DIW to an outdoor water to air cooler whereas the double loop system has an intermediate heat
exchanger. The Thyristor Valve cooling water pipes must be made of a material which has very high
electrical insulating properties and to have a long life (25 years or more) must withstand continuous

Page 38
temperatures in excess of 60 o
C. These cooling pipes were a problem in older valves as they had a
short life but newer materials made of cross linked polyethylene (XLPE) and Teflon which have much
longer useful lives have been used in modern valve cooling circuits.
Note that the remainder of the cooling circuit will be discussed separately.
Performance issues:
The cooling circuits have been and still continue to be a source of problems in Thyristor Valves.
Deterioration of the older plastic tubing is a significant problem in some HVDC schemes such as Nelson
River Bipole 2. Main issues verified in the past include:
 Corrosion
 Fouling of the platinum electrodes, resulting in additional scheduled outages to clean them
 O-rings and gasket material deterioration from DIW exposure
Problems with the resin beds, bad resin and contamination of the resins are common and a major
consideration should be a proven supplier and not price alone.
Thyristor aging:
There have been cases where thyristors have suffered from premature aging issues (not necessarily
thyristor failure), either from inadequate design, manufacturing defects or operational stresses. The
thyristor is the fundamental component of the HVDC system. Any aging issues that could affect the
design parameters could ultimately lead to a cascading failure of the series connected thyristors [6]. As a
HVDC scheme ages, it is likely that it can no longer get Thyristors from the OEM, or the cost of
replacements is extremely high. There may be other suppliers which can fill the void but careful matching
must be adhered to, especially with the Qrr or stored charge on turn off. To ensure an owner is prepared
to handle any thyristor issues, a full data specification for the thyristor device as well as documented
testing should be provided as part of the station documentation.
Some schemes are experiencing higher than normal failure rates of the Thyristors and the causes are
not always known. Some are associated with mixing new Thyristors with old ones from different
suppliers. In one particular case of Thyristor failures is that they always occurred after testing the
Thyristor in the OEM supplied test set. The testing in the OEM supplied test set was discontinued and no
more failures occurred.
Failure of valve reactor modules is fairly common with age due to lack of cooling flow (plugging) and
severe vibration causing deterioration of the iron cores.
The fiber optic outer coating has deteriorated due to ultraviolet light in some schemes. Replacements
can usually be found but can be a challenge because the connectors are obsolete. Also, the laser diode
transmitter and receivers can be a challenge to find replacements for.
DC wall bushing failures increase with age, requiring their replacement. Flashover of the outside portion
of the DC wall bushings is quite common due to the rain effect from the converter building, where a part
of the bushing is dry as it was shielded by the building during a rain storm and the other part is wet. This
causes voltage stress across the bushing, resulting in a flashover. Increasing the DC wall bushing
length or creepage alone does not work as anticipated. An alternating long short shed profile or “booster
sheds” or silicone rubber sheds may be required depending on the voltage level and pollution. There is
an opportunity to move away from porcelain oil filled bushing to either gas filled or composite solid core
bushings.

Guidelines for life extension of existing HVDC systems

Guidelines for life extension of existing HVDC systems

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