IEC TR 62672:2018
(Main)Reliability and availability evaluation of HVDC systems
Reliability and availability evaluation of HVDC systems
IEC TR 62672:2018(E) applies to all line-commutated and voltage-sourced high-voltage direct current (HVDC) transmission systems used for power exchange in utility systems. The purpose of this document is to define a standardized reporting protocol so that data collected from different HVDC transmission systems can be compared on an equitable basis. This document covers point-to-point transmission systems, back-to-back interconnections and multi-terminal transmission systems.
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IEC TR 62672 ®
Edition 1.0 2018-09
TECHNICAL
REPORT
Reliability and availability evaluation of HVDC systems
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IEC TR 62672 ®
Edition 1.0 2018-09
TECHNICAL
REPORT
Reliability and availability evaluation of HVDC systems
INTERNATIONAL
ELECTROTECHNICAL
COMMISSION
ICS 29.240.01 ISBN 978-2-8322-6065-4
– 2 – IEC TR 62672:2018 IEC 2018
CONTENTS
FOREWORD . 5
1 Scope . 7
2 Normative references . 7
3 Terms, definitions, abbreviated terms and symbols . 7
3.1 Outage terms . 8
3.2 Capacity terms . 8
3.3 Outage duration terms . 9
3.4 Time categories . 9
3.5 Availability and utilization terms . 10
3.6 Commutation failure performance terms . 11
3.7 Abbreviated terms and symbols . 11
4 Classification of HVDC transmission system equipment . 12
4.1 General . 12
4.2 AC and auxiliary equipment (AC-E) . 13
4.2.1 General . 13
4.2.2 AC filter and other reactive power equipment (AC-E.F) . 13
4.2.3 AC control and protection (AC-E.CP) . 13
4.2.4 Converter/interface transformer (AC-E.TX) . 13
4.2.5 Synchronous compensator (AC-E.SC) . 13
4.2.6 Auxiliary equipment and auxiliary power (AC-E.AX) . 14
4.2.7 Other AC switchyard equipment (AC-E.SW) . 14
4.3 Valves (V) . 14
4.3.1 General . 14
4.3.2 Valve electrical (V.E) . 14
4.3.3 Valve cooling (V.VC) . 14
4.3.4 Valve capacitor (V.C) . 14
4.3.5 Phase reactor (V.PR) . 14
4.4 DC control and protection equipment (C-P) . 14
4.4.1 General . 14
4.4.2 Local control and protection (C-P.L) . 15
4.4.3 Master control and protection (C-P.M) . 15
4.4.4 Telecommunication equipment (C-P.T) . 15
4.5 Primary DC equipment (DC-E) . 15
4.5.1 General . 15
4.5.2 DC filters (DC-E.F) . 15
4.5.3 DC smoothing reactors (DC-E.SR) . 15
4.5.4 DC switching equipment (DC-E.SW) . 15
4.5.5 DC measuring equipment (DC-E.ME) . 16
4.5.6 DC earth electrode (DC-E.GE) . 16
4.5.7 DC earth electrode line (DC-E.EL) . 16
4.5.8 Other DC switchyard and valve hall equipment (DC-E.O) . 16
4.6 Other (O) . 16
4.7 DC transmission line (TL). 16
4.7.1 General . 16
4.7.2 DC overhead transmission line (TL-OH) . 16
4.7.3 DC underground/submarine cable (TL-C) . 17
4.8 External (EXT) . 17
5 Classification and severity of fault events and restoration codes . 17
5.1 Classification of fault events . 17
5.2 Severity codes . 18
5.3 Restoration codes . 19
6 Instructions for compilation of report . 19
6.1 General . 19
6.2 General instructions . 19
6.3 Instructions for Table 2 and Table 3 . 20
6.3.1 Section 1 . 20
6.3.2 Section 2 . 20
6.3.3 Sections 3, 4 and 5 . 20
6.3.4 Section 6 . 21
6.3.5 Section 7 . 21
6.4 Instructions for Table 4 and Table 5 . 24
6.4.1 Forced outages – Table 4 . 24
6.4.2 Scheduled outages – Table 5 . 24
6.5 Instructions for Table 6 . 26
6.6 Instructions for Table 7 . 27
6.7 Instructions for Table 8 . 28
6.8 Instructions for Table 9 . 29
7 Interpretation and evaluation of reports . 29
7.1 Calculation of outage duration . 29
7.2 External events . 29
7.3 Protective operation . 30
7.4 Performance of special controls . 30
Annex A (informative) Outage log form and examples . 33
A.1 Example of an outage log . 33
A.2 Examples of application of rule f) of 6.3.3 – Scheduled outage during a
forced outage . 34
A.2.1 Case 1: Scheduled outage does not increase ODF or extends outage
duration . 34
A.2.2 Case 2: Scheduled outage increases ODF . 35
A.3 Examples of application of rule g) of 6.3.3 – Second outage during an
outage . 36
A.3.1 Case 1: Second outage does not increase ODF or extends outage
duration . 36
A.3.2 Case 2: Second outage extends duration . 37
A.3.3 Case 3: Second outage with variable ODF . 38
Annex B (informative) Sample annual report . 39
Bibliography . 45
Figure A.1 – Scheduled outage does not increase ODF or extends outage duration . 35
Figure A.2 – Scheduled outage increases ODF . 35
Figure A.3 – Second outage does not increase ODF or extends outage duration . 36
Figure A.4 – Second outage extends duration . 37
Figure A.5 – Second outage with variable ODF . 38
– 4 – IEC TR 62672:2018 IEC 2018
Table 1 – Classification of fault events . 18
Table 2 – DC system performance for back-to-back systems and for two-terminal
systems reporting jointly (corresponding to Table 1 of Cigré TB 590:2014) . 22
Table 3 – DC system performance for multi-terminal systems and for stations reporting
separately as part of two-terminal systems (corresponding to Table 1 M/S of Cigré TB
590:2014) . 23
Table 4 – Forced outages of HVDC substation (corresponding to Table 2FS of Cigré
TB 590:2014) . 25
Table 5 – Scheduled outages of HVDC substation (corresponding to Table 2 SS of
Cigré TB 590:2014). 26
Table 6 – HVDC overhead line protection operations (corresponding to Table 3 of
Cigré TB 590:2014). 27
Table 7 – AC system faults and commutation failure starts (back-to-back, two-terminal
or multi-terminal LCC systems) (corresponding to Table 4 of Cigré TB 590:2014) . 28
Table 8 – Converter unit hours and semiconductor devices that failed (corresponding
to Table 5 of Cigré TB 590:2014) . 29
Table 9 – Forced outage summary (corresponding to Table 6 of Cigré TB 590:2014) . 31
Table A.1 – Example of an outage log. 33
Table B.1 – DC system performance for two-terminal systems reporting jointly . 39
Table B.2 – Forced outages of HVDC substation . 40
Table B.3 – Scheduled outages of HVDC substation . 41
Table B.4 – HVDC overhead line protection operations . 41
Table B.5 – AC system faults and commutation failure starts . 42
Table B.6 – Converter unit hours and semiconductor devices failed . 42
Table B.7 – Forced outage summary . 43
INTERNATIONAL ELECTROTECHNICAL COMMISSION
____________
RELIABILITY AND AVAILABILITY EVALUATION OF HVDC SYSTEMS
FOREWORD
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The main task of IEC technical committees is to prepare International Standards. However, a
technical committee may propose the publication of a technical report when it has collected
data of a different kind from that which is normally published as an International Standard, for
example "state of the art".
IEC TR 62672, which is a Technical Report, has been prepared by IEC technical committee
115: High Voltage Direct Current (HVDC) transmission for DC voltages above 100 kV.
This first edition cancels and replaces the first edition of IEC 62672-1 published in 2013. This
edition constitutes a technical revision.
This edition includes the following significant technical changes with respect to the previous
edition:
a) HVDC stations with voltage sourced converters have been included;
b) this document has been aligned with latest Cigré TB 590:2014, which has superseded the
previous Cigré TB 346:2008.
– 6 – IEC TR 62672:2018 IEC 2018
The text of this technical report is based on the following documents:
Enquiry draft Report on voting
115/177/DTR 115/185/RVDTR
Full information on the voting for the approval of this technical report can be found in the
report on voting indicated in the above table.
This document has been drafted in accordance with the ISO/IEC Directives, Part 2.
The committee has decided that the contents of this document will remain unchanged until the
stability date indicated on the IEC website under "http://webstore.iec.ch" in the data related to
the specific document. At this date, the document will be
• reconfirmed,
• withdrawn,
• replaced by a revised edition, or
• amended.
A bilingual version of this publication may be issued at a later date.
RELIABILITY AND AVAILABILITY EVALUATION OF HVDC SYSTEMS
1 Scope
This document applies to all line-commutated and voltage-sourced high-voltage direct current
(HVDC) transmission systems used for power exchange in utility systems.
In order to assess the operational performance of HVDC transmission systems, reliability and
availability are evaluated. The intention of the performance evaluation is to identify further
design improvements. For this purpose the HVDC users/owners are encouraged to compile
reports on an annual basis based on the recommendations given in this document. The
purpose of this document is to define a standardized reporting protocol so that data collected
from different HVDC transmission systems can be compared on an equitable basis. Such
reports can be sent to Cigré SC B4, “HVDC and Power Electronics” (http://b4.cigre.org) which
collects such data and publishes it in a survey of HVDC systems throughout the world on a bi-
annual basis.
This document covers point-to-point transmission systems, back-to-back interconnections and
multi-terminal transmission systems. For point-to-point systems and back-to-back
interconnections, i.e. two-terminal systems, statistics are reported based on the total
transmission capability from the sending end to the receiving end measured at a given point.
If, however, the two terminals are operated by different users/owners, or are composed of
equipment of a different vintage or of equipment from different suppliers, statistics can be
reported on an individual station basis if so desired by those responsible for reporting. In such
a case, the outage is only reported under the originating converter station, taking care not to
report the same event twice. For multi-terminal systems, i.e. systems with more than two
terminals, statistics are reported separately for each converter station based on its own
individual capability.
Multi-terminal systems, incorporating parallel converters but having only two converter
stations on the DC line, can be considered as either point-to-point systems or as multi-
terminal systems for purpose of reporting. Therefore, statistics for this special type of multi-
terminal system can be reported based on either total transmission capability or on individual
station capability. If the converters at one station use different technology, converter station
statistics can be reported separately for each different type of capacity if desired. Multiple
bipoles are also reported individually. Special mention is given in the text and in the
tabulations to any common events resulting in bipolar outages.
NOTE Usually the agreement between the purchaser and the turnkey suppliers of the HVDC converter station
includes specific requirements regarding contractual evaluation. Such specific requirements will prevail over this
document.
2 Normative references
There are no normative references in this document.
3 Terms, definitions, abbreviated terms and symbols
For the purposes of this document, the following terms, definitions, abbreviated terms and
symbols apply.
ISO and IEC maintain terminological databases for use in standardization at the following
addresses:
• IEC Electropedia: available at http://www.electropedia.org/
• ISO Online browsing platform: available at http://www.iso.org/obp
– 8 – IEC TR 62672:2018 IEC 2018
3.1 Outage terms
3.1.1
outage
state in which the HVDC system is unavailable for operation at its rated continuous capacity
due to an event directly related to the converter station equipment or DC transmission line
Note 1 to entry: Failure of equipment not needed for power transmission is not to be considered as an outage for
purposes of this evaluation. AC system related outages are to be recorded but not included in HVDC system
reliability calculations.
Note 2 to entry: For purposes of this evaluation, outages taken for major reconfiguration or upgrading, such as
the addition of converters, are not to be reported.
3.1.2
scheduled outage
outage, which is either planned or which can be deferred until a suitable time
Note 1 to entry: Scheduled outages can be planned well in advance, primarily for preventive maintenance
purposes such as an annual maintenance program. During such planned maintenance outage, it is usual to work
on several different equipment or systems concurrently. It is not necessary to allocate such outage time to
individual equipment categories. Only the elapsed time should be reported in Table 5 as “PM”.
Note 2 to entry: Classified under the scheduled outage category are also outages for work which could be
postponed until a suitable time (usually night or weekend) but cannot be postponed until the next planned outage.
Equipment category code in Table 5 should be used to identify the affected equipment. This includes discretionary
outages based on operating policies, user/owner’s preference and maintenance of redundant equipment.
Note 3 to entry: If the scheduled outage is extended due to additional work which would otherwise have
necessitated a forced outage, the excess period is to be counted as a forced outage.
3.1.3
forced outage
state in which equipment is unavailable for normal operation but is not in the scheduled
outage state
3.1.3.1
trip
sudden interruption in transmission by automatic protective action or manual emergency
shutdown
3.1.3.2
other forced outage
other unexpected HVDC equipment problems that force immediate reduction in capacity of
HVDC converter stations or system but do not cause or require a trip
Note 1 to entry: Also in this category are outages caused by start-up or de-block delays caused by HVDC
equipment.
Note 2 to entry: In some cases the opportunity exists during forced outages to perform some of the repairs or
maintenance that would otherwise be performed during the next scheduled outage. See 6.3.3, rule (f).
3.2 Capacity terms
3.2.1
rated capacity
P
m
maximum capacity (MW), excluding the added capacity available through means of redundant
equipment, for which continuous operation under designed conditions is possible
Note 1 to entry: For two-terminal systems reporting jointly, the rated capacity refers to a particular point in the
system, usually at one or the other converter station. For multi-terminal systems or two-terminal systems reporting
separately, the rated capacity refers to the rating of the individual converter station.
Note 2 to entry: When the maximum continuous capacity varies according to seasonal conditions, the highest
value can be used as the capacity when reports are prepared according to this document for simplicity's sake.
However this excludes over-load capability such as is available during low ambient temperature.
3.2.2
outage capacity
P
o
capacity reduction (MW) which the outage would have caused if the system was operating at
its rated capacity (P ) at the time of the outage
m
Note 1 to entry: The outage capacity is calculated based on the same point in the system as that used for defining
P .
m
3.2.3
outage derating factor
ODF
ratio of outage capacity to rated capacity, expressed as
ODF = P / P
o m
3.3 Outage duration terms
3.3.1
actual outage duration
AOD
time elapsed in decimal hours between the start and the end of an outage
Note 1 to entry: It is expressed for example as follows: 6 h:30 min = 6,50 h.
Note 2 to entry: The start of an outage is typically the first switching action related to the outage. The end of an
outage is typically the last switching action related to the return of the equipment to operational readiness.
Note 3 to entry: In some contractual evaluations between purchaser and supplier, AOD can be subjected to
correction to adjust for long waiting times, administrative delays, non-availability of tools and tackles, non-
availability of spare parts or other needed resources including trained man power, delay in permits etc.
3.3.2
equivalent outage duration
EOD
actual outage duration (AOD) in decimal hours, multiplied by the outage derating factor (ODF),
so as to take account of partial loss of capacity, and expressed as
EOD = AOD × ODF
Note 1 to entry: Each equivalent outage duration (EOD) may be classified according to the type of outage
involved: equivalent forced outage duration (EFOD) and equivalent scheduled outage duration (ESOD).
3.4 Time categories
3.4.1
period hours, pl.
PH
number of calendar hours in the reporting period
Note 1 to entry: In a full calendar year the period hours are 8 760, or 8 784 in leap years.
Note 2 to entry: If the equipment is commissioned part way through a year, the period hours will be
proportionately less.
3.4.2
actual outage hours, pl.
AOH
sum of actual outage durations within the reporting period, expressed as
AOH = Σ AOD
– 10 – IEC TR 62672:2018 IEC 2018
Note 1 to entry: The actual outage hour (AOH) may be classified according to the type of outage involved: actual
forced outage hours (AFOH) and, actual scheduled outage hours (ASOH). AFOH and ASOH are expressed,
respectively, as
AFOH = Σ AFOD
ASOH = Σ ASOD
3.4.3
equivalent outage hours, pl.
EOH
sum of equivalent outage durations within the reporting period, expressed as
EOH = Σ EOD
Note 1 to entry: The equivalent outage hours (EOH) may be classified according to the type of outage involved:
equivalent forced outage hours (EFOH) and equivalent scheduled outage hours (ESOH). EFOH and ESOH are
expressed, respectively, as
EFOH = Σ EFOD
ESOH = Σ ESOD
3.5 Availability and utilization terms
3.5.1
energy unavailability
EU
measure of the energy which could not have been transmitted due to outages
Note 1 to entry: The energy unavailability is calculated based on the same point in the system as that used for
defining P .
m
Note 2 to entry: The energy unavailability (EU) may be classified according to the type of outage involved: forced
energy unavailability (FEU) and scheduled energy unavailability (SEU). EU, FEU and SEU are expressed,
respectively, as
EU = (EOH / PH) × 100 (%)
FEU = (EFOH / PH) × 100 (%)
SEU = (ESOH / PH) × 100 (%)
Note 3 to entry: SEU covers both scheduled energy unavailability due to planned outage (SEUP) as well as
scheduled energy unavailability due to deferred outage (SEUD).
3.5.2
energy availability
EA
measure of the energy which could have been transmitted except for limitations of capacity
due to outages
Note 1 to entry: The energy availability is calculated based on the same point in the system as that used for
defining P . EA is expressed as
m
EA = 100 – EU (%)
3.5.3
energy utilization
U
factor giving a measure of the energy actually transmitted over the system
Note 1 to entry: The energy utilization is calculated based on the same point in the system as that used for
defining P . It is expressed as follows:
m
E
total
U ×100 %
P ⋅ PH
m
where
E is the total energy transmitted (MWh) during the reporting period;
total
is the rated capacity (MW);
P
m
PH is the period hours (h).
Note 2 to entry: The total energy transmitted is the sum of energy exported and energy imported (expressed in
MWh), both calculated based on the same point in the system as that used for defining P .
m
3.6 Commutation failure performance terms
NOTE This is not applicable to VSC HVDC systems.
3.6.1
recordable AC system fault
AC system fault, which causes one or more of the inverter AC bus phase voltages at the
terminals of the harmonic filter to drop immediately following the fault initiation below 90 % of
the voltage prior to the fault
Note 1 to entry: AC system faults at, or near, the rectifier are not relevant in this context and are not required to
be included in this reporting. An exception to this rule is a special case where the network topology dictates that an
AC fault near the rectifier also produces a simultaneous recordable fault at the inverter or where specific converter
configuration (e.g. no smoothing reactor) is susceptible to a commutation failure in a rectifier operation.
3.6.2
commutation failure start
CFS(A)
initiation or onset of commutation failure(s) in any valve group immediately following the
occurrence of an AC system fault, regardless of whether or not the AC fault is “recordable” as
defined in 3.6.1
Note 1 to entry: Commutation failures as a result of control problems or switching events are not to be included.
3.6.3
commutation failure start
CFS(B)
initiation or onset of commutation failure(s) in any valve group as a result of control problems,
switching events or other causes, but excluding those initiated by AC system faults under
3.6.2
3.7 Abbreviated terms and symbols
AC alternating current
AFOD actual forced outage duration
AFOH actual forced outage hours
AOD actual outage duration
AOH actual outage hours
ASOD actual scheduled outage duration
ASOH actual scheduled outage hours
CFS commutation failure start
CT current transformer
DC direct current
DMR dedicated metallic (conductor) return
EA energy availability
EFOD equivalent forced outage duration
=
– 12 – IEC TR 62672:2018 IEC 2018
EFOH equivalent forced outage hours
EOD equivalent outage duration
EOH equivalent outage hours
ESOD equivalent scheduled outage duration
ESOH equivalent schedules outage hours
EU energy unavailability
FEU forced energy unavailability
HVDC high voltage direct current
IGBT insulated gate bipolar transistor
LCC line-commutated converter (also current-commutated converter)
MMC modular multi-level (VSC) converter
OH overhead (line)
PH period hours
PLC power line carrier
P rated capacity
m
P outage capacity
o
ODF outage derating factor
RAM reliability, availability, maintainability
RI radio interference
SEU scheduled energy unavailability
SEUD scheduled energy unavailability deferred
SEUP scheduled energy unavailability planned
STATCOM static synchronous compensator
SVC static var compensator
U (energy) utilization
VBE valve based electronics
VSC voltage-sourced converter
4 Classification of HVDC transmission system equipment
4.1 General
For the purpose of reporting the cause of capacity reduction or converter outages, converter
station equipment is classified into major categories. Failure of equipment resulting in an
outage or loss of converter capacity is to be charged to the category to which the failed
equipment belongs. The outage may be forced as a direct consequence of the failure or mis-
operation, or the outage may be scheduled due to maintenance requirements. Only scheduled
outages classified as deferred are categorized according to the equipment type.
The major categories are listed in the following subclauses and are as follows:
a) AC and auxiliary equipment (AC-E): 4.2
b) Valves (V): 4.3
c) DC control and protection equipment (C-P): 4.4
d) Primary DC equipment (DC-E): 4.5
e) Other (O): 4.6
f) DC transmission line (TL): 4.7
g) External (EXT): 4.8
The above major categories are further divided into subcategories.
4.2 AC and auxiliary equipment (AC-E)
4.2.1 General
This major category covers all AC main circuit equipment at the converter station. This
includes everything from the incoming AC connection to the AC connection of the converter
valve. This category also covers low voltage auxiliary power, valve cooling equipment
(including pumps, fans, electrical auxiliaries, etc., but excluding parts at high potential integral
within the valve, see 4.3.3) and AC control and protection.
NOTE This category does not apply to capacity outages resulting from events in the AC network external to the
converter station.
The "AC and auxiliary equipment" category is divided into six subcategories described in 4.2.2
to 4.2.7.
4.2.2 AC filter and other reactive power equipment (AC-E.F)
Loss of converter station capacity due to failure of AC filters (passive and/or active) or other
reactive power compensation equipment is to be assigned to this subcategory. The types of
components included in this subcategory are capacitors, reactors, resistors, CTs and
arresters comprised within the AC filtering or reactive power compensation equipment of the
converter station.
NOTE Associated disconnectors/breakers, etc., with filters/reactive compensated equipment are excluded from
this subcategory, as they are included in 4.2.7.
AC PLC/RI filters, SVCs, series capacitors (including those between converter transformers
and valves), STATCOM, etc., when included in a converter station are also to be reported
under this subcategory.
4.2.3 AC control and protection (AC-E.CP)
Loss of converter station capacity due to failure of AC protections, AC controls, or AC current
and voltage measuring devices is to be assigned to this subcategory. AC protections or
control could be for the main circuit equipment, for the auxiliary power equipment or for the
valve cooling equipment.
NOTE CTs with AC filters or CTs on transformer bushings are not reported in this subcategory.
4.2.4 Converter/interface transformer (AC-E.TX)
Loss of converter station capacity due to failure of a converter transformer or interface
transformer is to be assigned to this subcategory. Any equipment integral with the
converter/interface transformer such as tap changers, bushings, bushing CTs or transformer
cooling equipment is included in this subcategory.
4.2.5 Synchronous compensator (AC-E.SC)
Loss of converter station capacity due to failure of a synchronous compensator is to be
charged to this subcategory. Anything integral or directly related to the synchronous machine
such as its cooling system or exciter is included in this subcategory.
– 14 – IEC TR 62672:2018 IEC 2018
4.2.6 Auxiliary equipment and auxiliary power (AC-E.AX)
Loss of converter station capacity due to failure or mis-operation of any auxiliary equipment is
to be assigned to this subcategory. Such equipment includes auxiliary transformers, pumps,
battery chargers, heat exchangers, cooling system process instrumentation, low voltage
switchgear, motor control centres, fire protection and civil works.
4.2.7 Other AC switchyard equipment (AC-E.SW)
Loss of converter station capacity due to failure of circuit breakers, pre-insertion resistors,
disconnect switches or earthing switches in the AC switchyard (including for AC filtering and
reactive power compensation) is to be assigned to this subcategory. Also included is other AC
switchyard equipment such as AC surge arresters, bus-work or insulators.
4.3 Valves (V)
4.3.1 General
This major category covers all parts of the thyristor/IGBT valve itself. The valve is the
complete operative array forming an arm, or part of an arm of the converter bridge. It includes
all auxiliaries and components integral with the valve and forming part of the operative array.
The "valves" category is divided into four subcategories described in 4.3.2 to 4.3.5, where
4.3.4 and 4.3.5 are only applicable to VSC HVDC systems.
4.3.2 Valve electrical (V.E)
Loss of converter station capacity due to any failure of the valve except for failure related to
the part of the valve cooling system integral with the valve is to be assigned to this
subcategory.
NOTE The VBE (valve base electronics) equipment is also included in this subcategory.
4.3.3 Valve cooling (V.VC)
Loss of converter station capacity due to any failure of the valve, related to the valve cooling
system at high potential integral with the valve, is to be assigned to this subcategory.
4.3.4 Valve capacitor (V.C)
Loss of converter station capacity due to any failure of the valve capacitor (e.g. power module
or cell capacitor) is to be assigned to this subcategory.
4.3.5 Phase reactor (V.PR)
Loss of converter station capacity due to any failure of the phase reactor is to be assigned to
this subcategory.
4.4 DC control and protection equipment (C-P)
4.4.1 General
This major category covers the equipment used for control of the overall HVDC system and
for the control, monitoring and protection of each HVDC substation excluding control and
protection of a conventional type which is included in 4.2.3. This also excludes the AC
measuring transducers which are included in 4.2.3 as well as DC measuring transducers
which are included in 4.5.5.
NOTE The equipment provided for the coding of control and indication information to be sent over a
telecommunication circuit and the circuit itself is included. Devices such as disconnectors, circuit-breakers and
transformer tap changers which can actually perform the control or protection action are excluded from this
subcategory.
The "DC control and protection equipment" category is divided into three subcategories
described in 4.4.2 to 4.4.4.
4.4.2 Local control and protection (C-P.L)
Loss of converter station capacity due to any failure of the control, protection or monitoring
equipment of the local HVDC station is to be assigned to this subcategory. Examples would
include failures of the converter firing control, current and voltage regulators, converter and
DC yard protections, valve control and protection, and local station control sequences.
4.4.3 Master control and protection (C-P.M)
Loss of converter station capacity due to any failure of the master control equipment is to be
assigned to this subcategory. The master control equipment usually includes bipolar control,
inter-station coordination of current and voltage orders, inter-station sequences, auxiliary
controls such as damping controls or higher level controls such as run-back/run-up, power
control or frequency control.
4.4.4 Telecommunication equipment (C-P.T)
Loss of converter station capacity due to any failure of the equipment provided for the coding
of control and indication information to be sent over a telecommunication circuit as well as the
telecommunication circuit itself, for example, optical communication
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