Availability analysis 2.1

VSC-HVDC Availability Analysis

Antony Beddard

Dr Mike Barnes

November 2011

Revision 2.1

Table of Contents

1 Introduction ................................................................................................................................ 1

2 Radial System Overview .............................................................................................................. 1

3 Methodology ............................................................................................................................... 2

4 Component Availability ............................................................................................................... 3

4.1 Converter Reactor ............................................................................................................... 6

4.2 MMC, Cooling System and Ventilation System ................................................................... 6

4.3 Control System .................................................................................................................... 7

4.4 Transformer and GIS ........................................................................................................... 7

4.5 DC Switchyard ..................................................................................................................... 8

4.6 DC Cable .............................................................................................................................. 9

5 Radial VSC-HVDC Scheme availability analysis ......................................................................... 10

5.1 Offshore system availability analysis ................................................................................ 10

5.2 Onshore system availability analysis................................................................................. 12

5.3 DC system availability analysis .......................................................................................... 13

5.4 Radial VSC-HVDC Availability ............................................................................................ 14

6 Regional HVDC Grid .................................................................................................................. 16

7 Cost-benefit analysis ................................................................................................................. 21

8 Summary ................................................................................................................................... 23

9 Conclusion ................................................................................................................................. 24

10 References ............................................................................................................................ 25

1

1 Introduction

The UK government has signed a legally binding contract for 15% of its energy consumption to be

produced from renewable energy sources by 2020[1]. The government’s 2009 Renewable energy

strategy has identified that to met this target 30% of the UK’s electricity generation must come from

renewable energy sources, of which nearly half is likely to come from offshore wind[1]. This

translates to nearly 15% of the UK’s electricity generation being produced from offshore wind in less

than 9 years. Therefore the reliability of the offshore windfarms and their connection which

facilitates the power transfer back to shore are extremely important.

The connection for the offshore windfarm can be via either a high voltage alternating current (HVAC)

transmission system or a high voltage direct current (HVDC) transmission system. The choice of

transmission system is largely dependent upon how far the windfarm is located from shore.

Generally speaking HVDC technology is more favourable for windfarms located more than 50km

from shore. This is primarily because in a HVAC system a large proportion of a cable’s current

carrying capacity is required to charge and discharge the cable’s capacitance every cycle. Whereas in

a HVDC system, once the cable is charged almost its entire current carrying capacity is available for

real power transfer.

Current Source Converters (CSC) and Voltage Source Converters (VSC) are the two main types of

converter technology used in HVDC transmission systems. VSC-HVDC is more suited for offshore

windfarms because it does not require a strong AC system and has a smaller footprint in comparison

to CSC-HVDC. Therefore this research focuses on assessing the availability of the VSC-HVDC link.

2 Radial System Overview

National Grid has presented three different strategies for the connection of the UK’s Round 3

offshore windfarms in their Offshore Development Information Statement (ODIS)[2, 3]. The radial

strategy requires more than twenty five 1000MW VSC-HVDC point-to-point schemes. A simplified

diagram for the offshore connection design of a Round 3 windfarm employing a 1000MW VSC-HVDC

point-to-point scheme is shown in Figure 1.

Wind Farm

500MW AC

Substation

500MW AC

Substation

1000MW VSC-

HVDC Scheme

400kV AC Grid

220kV AC

36kV AC

Figure 1 – 1000MW VSC-HVDC point-to-point offshore connection diagram

This paper assesses the availability of the VSC-HVDC link which is shown in Figure 2. Proposed

1000MW VSC-HVDC schemes as shown in Figure 1 have HVDC cable lengths ranging approximately

60km to 275km with an average cable length of approximately 165km [2]. Therefore the DC cable

length will be 165km for this study.

2

All of the three major HVDC manufacturers offer a VSC-HVDC product. Siemens and Alstom Grid’s

VSC-HVDC technology is based on a multi-modular converter (MMC); whereas ABB’s current VSC-

HVDC product utilizes a two-level converter topology. However ABB have developed a VSC-HVDC

product which employs a form of MMC known as a cascaded two-level converter (CTL). The CTL is

likely to be first used on the Dolwin 2 project which is expected to be commissioned in 2015.

Therefore it is fair to say all future orders for VSC-HVDC schemes will employ a MMC. Hence the

availability analysis in this paper will be based on a MMC VSC-HVDC scheme.

Figure 2 – point to point VSC-HVDC scheme

MMC VSC-HVDC schemes produce a very low harmonic content and as such no AC filters are

required in most MMC schemes[4]. It is also unlikely any DC filtering would be required1. Therefore

no filters are employed in this scheme. An MCC can operate without a phase reactor. However they

do require limb/converter reactors which are connected in series to each arm of the converter but

are normally located outside the valve hall. In this availability analysis the converter reactor and

MMC are analysed as separate components. The AC converter voltage is likely to be in the vicinity of

275kV2. A transformer steps this voltage up to 400kV onshore as shown in Figure 2.

3 Methodology

The VSC-HVDC transmission scheme is broken down into three subsystems as shown in Figure 2 and

Figure 3. The scheme can only facilitate power transmission if all of the three subsystems are in

service. The failure of any one of the series connected subsystems results in an outage. This is the

concept of series dependent systems.

Subsystem 2 -

DC System

Subsystem 3 -

Onshore System

Subsystem 1 –

Offshore System

VSC-HVDC Availability Diagram

Figure 3 – VSC-HVDC Reliability Model

1 Harmonic content in most cases is likely to be so low that no DC filter would be required. Also in [5] there are

no DC filters shown for the HVDC Plus converter. 2 This value is based on the peak AC converter voltage being 0.75 times half the DC voltage (0.75*300kV) which

gives a converter side line-to-line voltage of 275.57kV rms. The 0.75 is based on simulation results from the

Trans Bay cable project which has a peak AC converter voltage of 150kV and a DC voltage of ±200kV[4].

3

The overall availability of the VSC-HVDC scheme can be calculated by multiplying the availability of

the three subsystems together. In order to do this the availability of each component in each

subsystem must be calculated. The availability of each component can be calculated directly from

equation (1.1).

MTTF

AMTTF MTTR

=+

(1.1)

Equation (1.1) requires the mean time to failure (MTTF) and mean time to repair (MTTR) of each

component. The MTTF and MTTR values for each component have been estimated from several

sources of information.

4 Component Availability

A brief explanation of each component and their reliability indices will be discussed here. A thorough

explanation for the derivation of the MTTF and MTTR of each component is contained in the

appendix. The components in the offshore system are very similar to the components in the onshore

system. The key difference is that the transformers and gas insulated switchgear (GIS) bays for the

onshore are connected to the 400kV grid whereas the offshore transformer and GIS bays are

connected at 220kV as shown in Figure 2. The voltage rating of equipment could affect their

likelihood to fail and the time it takes to repair the component in the event of a failure. This is taken

into consideration in this availability analysis.

The crucial difference between a component being located offshore or onshore is the take it takes to

repair the component. This is because it takes longer to access the offshore platform. The time it

takes varies significantly depending on the following factors:-

• Method of transport (small vessel/large vessel/helicopter)

• Availability of transport

• Weather conditions

• Location of offshore platform

• Location of air field/port/offshore maintenance platform

• Availability of required personnel

The access time could be as little as one day (24 hours) based on travel via a helicopter in good

weather conditions with the correct administration procedures in place to enable rapid deployment

of personnel and equipment. However it could also be as long as three months or more due to very

bad weather conditions and unavailability of a large suitable vessel.

The mean time to access the offshore platform (MTTAOP) with different sized components or spare

parts has been estimated as shown in Table 1. Pictures of the example components/spare parts in

Table 1 are shown below to give an indication for their size.

Table 1 – Mean Time to Access the Offshore Platform with Different Sized Components / Spare Parts

Component/Spare Part Size Example Component / Spare Part MTTAOP (hr) Transportation Method

Small MMC Submodule 48 Helicopter/small vessel

Medium Gas-insulated Switchgear 168 Medium Vessel

Large Transformer 504 Large Vessel

4

In order to accurately estimate the MTTR for an offshore component, the size of the spare part the

component would require in the event of a failure must be estimated. From estimating the size of

spare parts a component is likely to require in the event of a failure, the mean offshore access time

(MOAT) for the component can be calculated. Calculating the MTTR for a component located

offshore is not as simple as adding the MTTR for the component located onshore together with the

MOAT for that component. This is because some tasks which affect the MOAT may be performed in

parallel with tasks included in the MTTR for the onshore component. To give greater clarity to these

two aspects consider the following example.

In this availability analysis it is estimated that 70% of GIS failures require a small sized part and 30%

require a medium sized part. From Table 1 the mean offshore access time (MOAT) to repair a GIS

switchbay would be 84 hours (70% helicopter/small vessel and 30% medium vessel). The MTTR for a

GIS bay located onshore is estimated to be 120 hours. It is estimated that 20 hours of the offshore

access time is spent performing administration related tasks which could be done concurrently with

the time spent obtaining spare parts (included in the onshore MTTR). Therefore the MTTR of an

offshore GIS is the MTTR of an onshore GIS switchbay plus the MOAT minus the mean time spent

performing concurrent tasks (MTPCT) (i.e. 120+84-20). Further information is contained in the

appendix.

Figure 4 – MMC sub-module from [6]

The MMC sub-module is approximately 0.6x1.5x0.3m (HxWxD) and weighs approximately 165kg [6].

5

Figure 5 – Picture of a 245kV Gas Insulated Switchgear (GIS) from [7]

A 245kV gas insulated switchgear bay has a footprint of about 12m2 and weighs approximately 5-6

tonnes [8].

Figure 6 – 150kV 140MVA offshore transformer modified from [9]

6

A 150kV 140MVA transformer as shown in is a relatively small transformer in terms of its rating, but

still weighs approximately 90 tonnes[8]. Larger transformers are significantly heavier.

4.1 Converter Reactor

The converter reactors also known as limb reactors are connected in series with each arm of the

MMC. There is only one MMC currently in operation (commissioned 2010) and it is not for an

offshore system and therefore reliability indices for converter reactors are non-existent. Det Norske

Veritas (DNV) is the only known source to have published reliability indices for a VSC-HVDC

converter reactor. These reliability indices are likely to be for the converter reactors employed on

two-level voltage source scheme. Never the less the reliability indices for the reactor are taken to be

similar to the converter reactors used in MMC VSC-HVDC schemes. The reliability indices published

by DNV was used to estimate the reliability indices for a converter reactor as given in Table 2.

Table 2 - Estimated Reliability Indices for Converter Reactors

4.2 MMC, Cooling System and Ventilation System

The cooling system is required to ensure the components within the MMC such as the IGBT’s do not

exceed their rated temperature. The ventilation system amongst other functions is needed to ensure

the valve hall temperature and moisture does not exceed set limits. Failure of either the cooling

system or ventilation system is likely to result in the converter being tripped fairly quickly. It is for

these reasons critical parts in the cooling system are duplicated [10].

As mentioned previously, failure statistics for MMCs are non-existent because there is only one MCC

HVDC scheme in operation which was commissioned in 2010. The first two-level VSC-HVDC scheme

was commissioned in 1997 and since then many more schemes have been commissioned. That said

no VSC-HVDC schemes have been included in the Cigre world survey of HVDC schemes which is

published biannually. There are a small number of sources which have published reliability indices

for HVDC VSC’s3. One of these sources estimated the VSC’s reliability indices based on data from the

Cigre survey of LCC-HVDC schemes. This survey publishes reliability indices for the HVDC converter

with the cooling system and the ventilation system included. It is expected although not explicitly

stated that reliability indices for the converter from the other sources included the cooling system

and the ventilation system. Therefore estimating the reliability indices for the MMC from these

sources would also include the cooling system and the ventilation system. The disadvantage of this,

would be that the individual effect of the cooling system and ventilation system on the schemes

availability would be obscured.

A paper published by industry did analyse the converter, cooling system and ventilation system as

individual components [11]. However the components used in the offshore cooling system and

onshore cooling system seemed to be somewhat inconsistent with each other and with a real

cooling system. As an example the offshore cooling system did not account for instrumentation

whereas the onshore cooling system did and neither accounted for the failure rates of the cooling

3 Although it is not stated explicitly it appears that the reliability indices are for two-level VSC’s.

Component MTTF (yr) MTTR (hr) Availability

Onshore Converter Reactor 7 24 0.99961

Offshore Converter Reactor 7 192 0.99688

7

systems control system. The same inconsistency seems to apply to the ventilation systems. There

may well be very good reasons to explain these inconsistencies. However without this knowledge it

would be unwise to use the data from this paper for the cooling system and ventilation system as

the resultant availability could be very inaccurate. It is therefore believed more accurate reliability

indices would be obtained by estimating the MTTF and MTTR for the MMC from the other sources

which have factored in the cooling system and ventilation system4. It is for these reasons the cooling

system and ventilation system will be factored into the reliability indices for the MCC as one

component.

Table 3 - Estimated Reliability Indices for MMC, Ventilation System and Cooling System

4.3 Control System

The HVDC control system is fully duplicated to ensure a high level of reliability. The reliability indices

for HVDC control systems used in academic and industry publications are for two-level VSC-HVDC

schemes and LCC-HVDC schemes. The control algorithms for MCC VSC-HVDC schemes are more

complex than other HVDC schemes. The hardware, with the exception of the valve based

electronics, is similar. These were two of the factors which were taken into consideration when

estimating the MTTF and MTTR for the control system.

Table 4 - Estimated Reliability Indices for Control System

4.4 Transformer and GIS

Figure 7 – Subsystem 4

The reliability indices for the GIS have been mainly estimated from the GIS failure statistics from the

1996 Cigre GIS survey. Cigre surveys for AC circuit breakers and reliability indices for AC circuit

breakers from other sources were also used. GIS failure statistics are categorised based on the

voltage rating of the equipment. The GIS voltage ratings are determined by the busbar to which they

4 Sources 1 and 2 have not explicitly stated they have included the cooling and ventilation system. However it

is very likely they were included.


MMC Onshore 1.9 12 0.99928

MMC Offshore 1.9 60 0.99641


Onshore Control System 1.6 3 0.99979

Offshore Control System 1.6 17 0.99879

GISSwitchbay

500MW

500MW

1000MW

T1

T2

GIS 1

GIS 3

GIS 2

GIS 4

Busbar 1

Busbar 2

8

are connected. The offshore GIS connected to the windfarm side (busbar1) would need to be rated

at 220kV whereas the GIS connected to the converter side (busbar2) would need to be rated at

about 275kV. This places the offshore GIS in the 200-300kV category.


The onshore GIS connected to the converter side (busbar3) would need to be rated at about 275kV

whereas the GIS connected to the AC grid (busbar 4) would need to be rated at 400kV. Therefore the

GIS connected to busbar1 are in the 200-300kV category and the GIS connected to busbar 4 are in

the 300-500kV category.

Table 5 – Estimated Reliability Indices for GIS

The reliability indices for the power transformer have been estimated from a number of sources

including Cigre surveys, academic and industry publications. The failure statistics are categorised

based on the transformer’s highest winding voltage. The highest winding voltage for the offshore

transformers is within the 100-300kV category irrespective of whether a delta or star connected

transformer is employed. However a delta connected onshore transformer would have a winding

voltage of 400kV, whereas a star connected transformer would have a winding voltage of

approximately 230kV. This availability analysis assumes the onshore transformer is connected to the

grid via a star winding. This also places the onshore transformers in the 100-300kV category.

Table 6 - Estimated Reliability Indices for Transformers

4.5 DC Switchyard

The major equipment in a DC VSC switchyard consists of HV capacitor banks, line reactors,

measurement transducers and switchgear[12]. The major equipment in a LCC DC switchyard consists

of DC harmonic filters, smoothing reactors, measurement transducers and switchgear[13].

GISSwitchbay

1000MW1000MW

T1

T2

GIS 1

GIS 3

GIS 2

GIS 4

Busbar 3

Busbar 4

Component MTTF (yr) MTTR(hr) Availability

Offshore switchbay 250 184 0.99992

400kV onshore switchbay 100 120 0.99986


Component MTTF(yr) MTTR(hr) Availability

Offshore Transformer 95.00 1512.00 0.99819

Onshore Transformer 95.00 1008.00 0.99879

9

Figure 9 – MMC VSC DC Switchyard (left, modified from[12]) LCC DC Switchyard (right modified from[14])

Since there is significant similarity between the DC switchyards, the failure statistics from the world

HVDC survey (LCC) is used to estimate the reliability indices for the MMC VSC-HVDC DC switchyard.

The latest World HVDC survey was published in 2010 for data collected on LCC-HVDC schemes

during 2007-2008. Back-to-back HVDC schemes do not normally require smoothing reactors or DC

filters [13]. Therefore only the data from transmission schemes is considered. The estimated

reliability indices for a DC switchyard are given in Table 7.

Table 7 - Estimated Reliability Indices for DC Switchyard

4.6 DC Cable

Submarine cable failures rates are very subjective. They are heavily influenced by many factors

including, fishing activity, installation protection method, awareness of cable routes, water depth,

and hardness of the sea bed. Therefore reliability indices for submarine cables should be used with a

high level of caution and ideally estimated on a case by case basis.

The latest survey for failures of submarine cables was published in 2009 by Cigre for data collected

between 1990 and 2005. Unfortunately failure rates for the most common type of submarine cable

used in VSC-HVDC schemes (DC-XLPE) was not given in the report. The very high majority of known

cable failures were due to external damage, which is likely to be independent of cable type and

voltage rating5. Therefore the average failure rate of all cable types and voltages was used to

estimate failure for DC-XLPE submarine cable. The average failure rate of submarine cable with some

form of installation protection was calculated to be 0.096. Based on this figure and the value given

by DNV it was estimated that the annual failure of a submarine cable is 0.07 failures per 100km. The

circuit length in this report is defined as the distance between the onshore and offshore converter

(i.e. 165km not 330km).

5 Only 4 of the 49 reported failures were classed as internal failures which were all for one type of cable

(SCOF).

Componenet MTTF(yr) MTTR(hr) Availability

Onshore DC Switchyard 4.02 26.06 0.99926

Offshore DC Switchyard 4.02 98.06 0.99723

Line Reactor

10

The average repair time for submarine cables in the Cigre survey was approximately 60 days which is

the same as the MTTR used by DNV in their availability analysis. Therefore a MTTR of 60 days will be

assumed in this report.

Table 8 – Estimated Submarine Cable Reliability Indices

5 Radial VSC-HVDC Scheme availability analysis

The availability for the radial VSC-HVDC scheme will be calculated in this section.

5.1 Offshore system availability analysis

The offshore system is broken down into subsystems and components. The offshore system has

series dependency as shown in Figure 10. The failure of any one component from subsystem 4 to the

control system will result in the failure of the offshore system and therefore the failure of the

transmission scheme. Subsystem 4 can operate at 100% or 50% capacity. Due to the series

dependency if subsystem 4 is operating at 50% capacity the offshore subsystem and consequently

the transmission scheme can only operate at 50% capacity.

Figure 10 – Reliability Model for Subsystem 1

The availability of all the components in the offshore subsystem is given in Table 9.

Table 9– Availability of offshore components

The simplified offshore subsystem availability diagram is shown in Figure 11.

Figure 11 – Reliability Model for Subsystem 1

Component Failure rate (occ/yr/100km) Circuit Length (km) MTTF (yr) MTTR (hr) Availability

DC Cable 0.07 165 8.493625 1440 0.98101


Offshore GIS switchbay 250 184 0.99992

Offshore Transformer 95 1512 0.99819

Offshore Converter Reactor 7 192 0.99688

MMC Offshore 1.9 60 0.99641

Offshore Control System 1.6 17 0.99879

11

Subsystem 4 contains two parallel branches as shown in Figure 2 and Figure 12 . If both branches are

in service subsystem 4 operates at full capacity. If only one branch is in service subsystem 4 operates

at 50% capacity.


The protection of the equipment before, and including, busbar1 is assumed to be the responsibility

of the AC substation manufacturer. Therefore the failure of this equipment will not be included in

this availability analysis. It is also assumed permanent faults on busbar2 are very rare and can

therefore be neglected.

There are many components which make up a GIS switchbay including circuit breakers,

disconnectors and instrumentation. The component which fails and the mode in which that

component has failed determines the available capacity of the system. To demonstrate this three

example GIS failure modes and consequences are shown in Table 10.

Table 10 – Example GIS failure modes and consequences

There are many different failure modes of a GIS switchbay. In order to take into account each failure

mode and its effect on the capacity of the system complex analysis could be conducted. However

without accurate failure mode input data even the most sophisticated availability analysis method

will produce inaccurate results.

Data to determine the failure rate of a GIS switchbay as a single unit is limited. In fact for this report

the failure data for a GIS switchbay was estimated from a number of sources some of which were

15-25 years old and others which were for AC circuit breaker rather than a GIS switchbay. The data

used to estimate with any real degree of accuracy what component within a 2011 GIS switchbay and

how that component will fail is near enough non-existent. It is worth noting that in [15] there is

some data from the Cigre 1996 GIS survey for the symptoms of GIS failures. This includes symptoms

such as “loss of mechanical function” and “failure to operate switching device”. However such

symptoms do not indicate the failure mode of the GIS. The biggest single failure symptom (>30%)

was an insulation breakdown to earth, which indicates the third failure mode in Table 10. It is also

worth noting the survey was for GIS which was commissioned some 15-25 years ago and therefore

failure symptoms of modern day GIS could be very different.

GISSwitchbay

500MW

500MW

1000MW

T1

T2

GIS 1

GIS 3

GIS 2

GIS 4

Busbar 1

Busbar 2

Failure Mode Immediate effect Branches Effected Capacity Outage (MW)

Disconnector opens inadvertently Isolates the connected branch 1 500

Circuit fails to open on command Cannot clear transformer fault 2 1000

Insulation breakdown to earth Short circuit connected busbar 2 1000

12

Due to the lack of any credible failure mode statistics for GIS and that the biggest single failure

symptom for GIS was a “breakdown to earth” it is assumed the failure of any GIS switchbay results in

full capacity outage, which is the worst case scenario. There are 64 possible combinations of

components in Figure 12 considering each component as being available and unavailable. Rather

than go through each possible combination it is significantly less time consuming to go through any

combination of component which results in some available capacity. This is because the very high

majority of the combinations result in zero available capacity due to the assumption that any GIS

failure results in full capacity outage.

In order to operate at full capacity all the components (GIS1-4 and T1-2) must be available. The

failure of any one transformer providing all the GIS switchbays are available would result in an

available capacity of 500MW. All other component combinations result in full capacity outage.

Table 11 – Available capacity table for subsystem 4

From equation(1.2) the available capacity of subsystem 1 can be calculated.

1(100%) 4(100%) Re (100%) (100%) (100%)

1(50%) 4(50%) Re (100%) (100%) (100%)

1(0%) 1(100%) 1(50%)1

Sub Sub actor MMC Control


Sub Sub Sub

A A A A A

A A A A A

A A A

= × × ×

= × × ×

= − −

(1.2)

Table 12 – Available Capacity Table for the Offshore Subsystem (Subsystem 1)

Table 12 shows the offshore subsystem is operating at full capacity approximately 98.8% of the time,

half capacity 0.4% of the time and completely out of service 0.8% of the time.

5.2 Onshore system availability analysis

The analysis of the onshore system is the same as the offshore system. The availability of all the

components in the onshore system is given in Table 13.

Available Capacity GIS1 GIS2 GIS3 GIS4 T1 T2 Probability Availability

100% 1 1 1 1 1 1 0.99604 0.99604

1 1 1 1 1 0 0.00181

1 1 1 1 0 1 0.00181

0 0.00034 0.00034

50% 0.00362

All other combinations

1= available, 0= unavailable

Capacity Availability

100% 0.98817

50% 0.00359

0% 0.00824

Subsystem 1

13

Table 13 - Availability of onshore components

The available capacity of subsystem 5 is given in Table 14.

Table 14 - Available capacity of subsystem5

From equation(1.3) the available capacity of subsystem 3 can be calculated.

3(100%) 5(100%) Re (100%) (100%) (100%)

3(50%) 5(50%) Re (100%) (100%) (100%)

3(0%) 3(100%) 3(50%)1



Sub Sub Sub

A A A A A

A A A A A

A A A

= × × ×

= × × ×

= − −

(1.3)

Table 15 – Available Capacity Table for the Onshore System (Subsystem 3)

Table 15 shows the onshore system is operating at full capacity approximately 99.6% of the time,

half capacity 0.2% of the time and completely out of service 0.2% of the time.

5.3 DC system availability analysis

The DC system is broken down into three series dependent components as shown in Figure 13.

Figure 13 – Reliability Model of Subsystem 2




Onshore Transformer 95 1008 0.99879

Onshore Converter Reactor 7 24 0.99961

MMC Onshore 1.9 12 0.99928

Onshore Control System 1.6 3 0.99979

Available Capacity GIS1 GIS2 GIS3 GIS4 T1 T2 Probability Availability

100% 1 1 1 1 1 1 0.99720 0.99720

1 1 1 1 1 0 0.00121

1 1 1 1 0 1 0.00121

0% 0.00038 0.00038

50% 0.00242

All other combinations

1= available, 0= unavailable


100% 0.99588

50% 0.00241

0% 0.00171

Subsystem 3

Offshore DC Switchyard

(100%)DC Cable (100%)

Onshore DC Switchyard

(100%)

14

Subsystem 2 operates at full capacity if all three series dependent components are in service. If any

one component is out of service, subsystem 2 is completely unavailable.

Table 16 - Available Capacity Table for the DC System (Subsystem 2)

5.4 Radial VSC-HVDC Availability

The availability diagram of the VSC-HVDC scheme is shown in Figure 14. The available capacity of the

overall VSC-HVDC scheme is calculated in Table 17.

Figure 14 – Reliability Model of the VSC-HVDC Scheme

Table 17 - Available capacity of Radial VSC-HVDC Scheme

The radial VSC-HVDC scheme operates at full capacity approximately 96.2% of the time, half capacity

0.6% of the time and zero capacity 3.2% of the time. Therefore the schemes energy availability is

approximately 96.5%6. The target annual scheduled outage for maintenance is typically 0.82% (72

hours) for a VSC-HVDC scheme7. Therefore the overall energy availability for the VSC-HVDC scheme

analysed in this report would be approximately 95.7%8. The only known VSC-HVDC availability

statistics for VSC-HVDC schemes are for the Murraylink and Cross Sound Cable project. The average

energy availability for the Murraylink and Cross Sound Cable project are 96.5 and 96.9% respectively

[16]. These figures include forced and scheduled outages. Considering that the VSC-HVDC scheme in

this report was for an offshore windfarm, an overall energy availability of 95.7% seems rational.

The key component which influences the availability of the scheme can be assessed by calculating

the unavailability of each subsystem9.

6 “Energy Availability” is defined in this paper as “the maximum amount of energy which could have been

transmitted except for forced outages”. 7 The manufacturers target scheduled outage rate for the VSC-HVDC Cross Sound Cable project was 0.82%[16].

8 (0.964935-0.0082)*100=95.67%

9 The reader should be aware that adding the individual unavailability in hours (outage) for subsystems 1-3 is

not equal to the total VSC-HVDC scheme outage. This is because outages of individual subsystems can overlap.

Furthermore the unavailability of subsystem1 and subsystem 3 is calculated based on its equivalent energy


100% 0.97757

0% 0.02243

Subsystem 2

Capacity (%) Subsystem1 Subsystem 2 Subsystem 3 Probability Availability

100 1 1 1 0.96202 0.96202

0.5 1 1 0.00350

1 1 0.5 0.00233

0.5 1 0.5 0.00001

0 0.03215 0.03215Any Other Combination

50 0.00583

15

Figure 15 – Pie chart to show each subsystem’s unavailability

Figure 15 clearly shows that the DC system (subsystem 2) has the least availability. Therefore the

unavailability of each component in subsystem 2 is calculated and the results are displayed in Figure

16.

Figure 16 - Pie chart to show each component’s unavailability in subsystem 2

Figure 16 shows the DC cable has the greatest effect on the availability of subsystem2 and

subsequently the VSC-HVDC. As mentioned previously the failure rate of submarine cables is

dependent upon many factors. The annual failure rate used in this availability analysis was 0.07

failures per 100km circuit. The effect of the submarine cable failure rate on the energy availability of

the VSC-HVDC scheme excluding scheduled maintenance is shown in Table 18 .

Table 18 – Cable Sensitivity Analysis

availability. Therefore the subsystems energy unavailability is equal to the probability of the subsystem having

no capacity plus 0.5 times the probability of the subsystem operating at 50% capacity.

28%

64%

8%

Subsystem Unavailability

Subsystem 1 Subsystem 2 Subsystem 3

12%

85%

3%

Unavailability of Subsystem 2

Components

Offshore DC Switchyard DC Cable Onshore DC Switchyard

Cable Failure Rate (occ/yr/100km) Energy Availability (%)

0.007 98.2

0.07 96.5

0.7 79.7

16

Table 18 indicates that if the true failure rate of submarine VSC-HVDC cables is in the vicinity of 0.7

failures per 100km of circuit then VSC-HVDC schemes for the connections of the UKs Round 3

offshore windfarms are commercially unviable. This would in fact make the Round 3 windfarms

altogether unviable as any technology which requires submarine cables would have a similar

availability.

6 Regional HVDC Grid

Many potential benefits have been identified from interconnecting offshore windfarms via a multi-

terminal DC (MTDC) network. These benefits include a reduction in the volume of assets installed

offshore, improved operational flexibility and network security. A simplified diagram of the HVDC

grid which will be analysed in this report is shown in Figure 17.

Figure 17 – Regional HVDC Grid

The three offshore nodes are rated at 600MW each, giving a total grid capacity of 1800MW. This is

the maximum infeed loss permitted by NETS SQSS10

[3]. A fault on the DC grid could temporally

cause the entire 1800MW to be disconnected from the AC grid, while the faulty section of the grid is

isolated. The installation of HVDC circuit breakers would enable DC faults to be cleared without de-

energising the entire DC grid and therefore the grid’s maximum capacity could be greater than

1800MW. However there are currently no HVDC circuit breakers commercially available. Therefore

the HVDC grid analysed in this report does not contain HVDC circuit breakers and hence its

maximum capacity is limited to 1800MW.

The DC cables connected between the onshore and offshore converters have a length of 165km. This

length of cable is approximately the average straight line connection distance for the radial HVDC

10

NETS SQSS is the National Electricity Transmission System Security and Quality of Supply Standard.

Wind

Farm 3

165km DC Cable

AC Grid

Wind

Farm 1

DC

Shore

Wind

Farm 2

165km DC Cable

600MW Offshore

AC Substation

600MW Offshore

AC Substation

600MW Offshore

AC Substation

600MW Offshore

Node C (OFNC)

600MW Offshore

Node B (OFNB)

600MW Offshore

Node A (OFNC)

Onshore Node A

(OFNC)

Onshore Node B

(OFNC)

60km DC Cable

60km DC Cable

17

schemes outlined in ODIS. The offshore converters are connected together via 60km of DC cable.

This length of DC cable was chosen as it may be more suitable to connect the windfarms together

using HVAC for connection distances less than 60km.

This paper assesses the availability of the HVDC grid shown in Figure 17 and Figure 19. This analysis

neglects the grid’s downtime due to isolating a DC side fault, as this time is insignificant for the

calculation of grid’s availability.

Each offshore node consists of an offshore DC switchyard connected in series with subsystem 1 and

each onshore node contains an onshore DC switchyard connected in series with subsystem 3, as

shown in Figure 18.

Figure 18 – Onshore and Offshore Nodes

Figure 19 –Block Diagram of Regional HVDC Grid

The onshore nodes and their series connected DC cable can be combined into a single subsystem as

shown in Figure 20. The offshore nodes as well as subsystem 6 and subsystem 7 can be in one of

three states (100%, 50% or 0%), due to the dual transformers in subsystems 1 and 3. The DC cables

(C1 and C2) can be in one of two states (100% or 0%). Therefore the HVDC grid as shown in figure 4

has 972 (5 23 2× ) possible states. Simplifying these nodes/subsystems to two states would reduce

the number of possible HVDC grid states to 128 (27). The probability that subsystem 1 or subsystem

3 is operating at 50% capacity is very small. Therefore in this case, the 50% state may be eliminated

without introducing any significant error in the overall availability analysis of the HVDC grid. The

18

probability of the subsystem operating at 100% capacity is increased accordingly to account for the

exclusion of the 50% state. As an example subsystem 1 which has three states will be simplified to

two states of equivalent available capacity.

Table 19 – Equivalent Available Capacity Table for Subsystem 1

Subsystem 1 in the MTDC grid is rated at 600MW. Therefore the equivalent capacity of subsystem 1

can be calculated as follows:-

3

2

1 600 0.988167 300 0.003591 593.978

1 600 0.98996 593.978

Cap State

Cap State

Sub MW MW MW

Sub MW MW

= × + × =

= × = (1.4)

Equation (1.4) shows that there is no difference between the 3 state and the simplified 2 state

model in terms of the overall capacity of subsystem 1. Therefore the energy transmitted through

subsystem 1 when considered as a standalone system is exactly the same whether it is represented

by a 3 state model or a 2 state model. However the calculated availability of a system containing

several 3 state models is not strictly equal to the calculated availability of a system with equivalent

simplified 2 state models. Nevertheless since the probability of the node/subsystem operating in

the eliminated state is very small, the error is insignificant for the cases analysed in this report.

Figure 20 – Simplified Block Diagram of an HVDC Grid

The simplified two state capacity availability tables for the offshore node as well as subsystem 6 and

subsystem 7 are shown in Table 20.

Capacity Availability Equivalent Availability

100% 0.988167 0.989963

50% 0.003591

0% 0.008242 0.010037

Subsystem 1

19

Table 20 – Available Capacity Tables

The seven components/nodes/subsystems in Figure 20 operate in one of two states giving a possible

128 grid states. VBA code was written in excel to produce a 7x128 truth table. Only the first four

states are shown here. The full table is contained in the appendix.

Table 21 – Truth Table for Regional HVDC Grid

Each ‘1’ and ‘0’ in the truth table is replaced with the probability of that subsystem/node being

available (100%) and unavailable (0%) respectively. The probability of each state is then calculated

by multiplying the seven columns together.

Table 22 – Probability Table for The First Four Grid States

In order to calculate the HVDC grid’s overall availability, the grid’s capacity associated with each of

the 128 states must be deduced. VBA code was written to calculate the grid’s capacity for each of

the 128 states. Table 23 shows the grids available capacity for the first 4 states with subsystem 6 and

subsystem 7 having a capacity rating of 900MW each.

Table 23 – Capacity Table for Regional HVDC Grid with Sub6=Sub7=900MW

Summing the probabilities of each state for each grid capacity level gives the grid’s available capacity

as shown in Table 24.


100% 0.98721

0% 0.01279

Offshore Node


100% 0.99635

0% 0.00365

Onshore Node


100% 0.97743

0% 0.02257

Subsystem 6 and7

State OFNA OFNB OFNC C1 C2 Sub 6 Sub 71 1 1 1 1 1 1 12 1 1 1 1 1 1 03 1 1 1 1 1 0 14 1 1 1 1 1 0 0

State OFNA OFNB OFNC C1 C2 Sub 6 Sub 7 Probability1 0.98721 0.98721 0.98721 0.99310 0.99310 0.97743 0.97743 0.906542 0.98721 0.98721 0.98721 0.99310 0.99310 0.97743 0.02257 0.020933 0.98721 0.98721 0.98721 0.99310 0.99310 0.02257 0.97743 0.020934 0.98721 0.98721 0.98721 0.99310 0.99310 0.02257 0.02257 0.00048

State OFNA OFNB OFNC C1 C2 Sub 6 Sub 7 Capacity (MW)1 1 1 1 1 1 1 1 18002 1 1 1 1 1 1 0 9003 1 1 1 1 1 0 1 9004 1 1 1 1 1 0 0 0

20

Table 24 – Capacity Availability Table for Regional HVDC Grid with Sub6=Sub7=900MW

The HVDC grid shown in Figure 20 with each path to shore (sub6 & sub7) rated at 900MW has an

energy availability of 0.96302 compared to a energy availability of 0.964935 for a radial HVDC link.

This indicates that three 600MW radial links would have a higher energy availability than an

1800MW HVDC grid with each path to shore rated at 900MW. Upgrading subsystem 6 and 7 to

1200MW increases the grid’s availability as shown in Table 25.

Table 25– Capacity Availability Table for Regional HVDC Grid with Sub6=Sub7=1200MW

The grids availability can be increased further by rating each path to shore, equal to the grid’s

maximum capacity as shown in Table 26.

Table 26 - – Capacity Availability Table for Regional HVDC Grid with Sub6=Sub7=1800MW

The reader should be aware that the availability figures given in Table 26 are calculated from

component reliability indices for a DC voltage of ±300kV however it is likely any 1800MW VSC-HVDC

scheme will be built at a voltage greater than this. However data on such systems is even sparser

than for ±300kV systems.

Capacity (MW) Availability Energy Availability1800 0.90654 0.963021500 0.012601200 0.03560900 0.04395600 0.000790 0.00052

Sub 6&7 =900MW

Capacity (MW) Availability Energy Availability1800 0.91915 0.972441200 0.07954600 0.000790 0.00052

Sub6 & Sub 7 = 1200MW

Capacity (MW) Availability Energy Availability1800 0.96101 0.986401200 0.03768600 0.000790 0.00052

Sub 6 & Sub 7=1800MW

21

7 Cost-benefit analysis

This section of the document compares the required capital investment against the calculated

availability of each of the following schemes:-

1. 1800MW Regional HVDC grid with each path to shore rated at 900MW

2. Three 600MW radial HVDC links

3. 1800MW Regional HVDC grid with each path to shore rated at 1200MW

Since the schemes are being compared with one another, the components which are common to all

schemes can be ignored as the cost of these components would be the same for each scheme. All of

the schemes require three 600MW offshore nodes; hence the cost of these items is neglected. The

costs of components used in this cost benefit analysis are from the ODIS 2011 annex and are for

indicative purposes only.

Table 27 – VSC Converter Costs11

Table 28 – HVDC Extruded Cable Costs12

Table 29 – Cable Installation Costs

From the above tables the cost of the three transmission schemes (excluding the offshore nodes)

can be estimated. The required cross sectional area for HVDC submarine cable of different power

ratings was estimated from data given in [17]. It is estimated that the 600MW, 900MW and

11

It is assumed the VSC converter cost is for a single converter including AC and DC switchyard. 12

It is assumed the cost is per km of cable not per km of route (i.e one radial link requires 2x165km of cable).

Rating Min Max Average

300kV 500MW 65 80 72.5

320kV 850MW 85 105 95

500kV 1250MW 105 130 117.5

500kV 2000MW 125 175 150

VSC Converter Costs (£m)

Cross sec Area

Min Max Average Min Max Average

1200 200 400 300 300 450 375

1500 250 400 325 300 450 375

1800 300 450 375 300 500 400

2000 300 500 400 350 550 450

±150kV ±320kV

HVDC Extruded Cable Costs (£k/km)

Cable Installation Type Min Max Average

Twin Cable in Single Trench 0.5 0.9 0.7

Cable Installation Costs (£m/km)

22

1200MW cable would require cross sectional area of about 630mm2, 1400mm

2 and 2200mm

2

respectively13

. The costs of each scheme excluding the offshore nodes are given in Table 30.

Table 30 – HVDC transmission Scheme Costs Excluding Offshore Nodes

The HVDC grid with each path back to shore rated at 900MW (scheme 1) is the least expensive

scheme, but also has the lowest energy availability. The radial scheme (scheme 2) and the HVDC grid

with each path back to shore are rated at 1200MW (scheme 3) are more expensive than scheme 1,

but their energy availability is higher. Since higher availability equates to greater revenue, it may

make more economic sense to invest a greater amount of capital to obtain a scheme with a higher

availability.

The amount of revenue lost each year due to a transmission scheme being unavailable can be

calculated using equation(1.5).

8760( )R F pLoss U P C hrs S= × × × × (1.5)

£ /

R

F p

U Unavailability P Rated power in MW

C Capacity factor S Electricty sale pricein MW

− −− −

The capacity factor for the three schemes is assumed to be 0.414

. This means that over the course of

the year the transmission scheme is only required to operate at 40% of its rated power. The

electricity sale price is assumed to be £150/MWh15

.

The annual saving for scheme 2 and scheme 3 is calculated by subtracting the annual loss of that

scheme from the annual loss of scheme 1.

13

Figures are based on a ±300kV submarine cable with a copper conductor in a moderate climate spaced

closely together. These figures are indicative only. 14

Capacity factors of 0.35-0.45 are typical for offshore windfarms. 15

This figure is based on one MWh of energy generated by an offshore windfarm being equal to the electricity

wholesale price plus two renewable obligations certificates (ROC) plus one levy exemption certificate (LEC).

The electricity wholesale price is approximately £60/MWh [18]. Accredited offshore windfarms are currently

awarded 2 ROC’s per MWh [19], where each ROC is worth £38.69 plus 10% for headroom [20]. One LEC has a

value of £4.85 [21].

Scheme Item Cost £m Total Cost £m

240km ±300kV 1200MW Cable 114

660km ±300kV 900MW Cable 247.5

Cable Installation 315

2 x 900MW Onshore Converter 200

990km ±300kV 600MW Cable 321.75

Cable Installation 346.5

3 x 600MW Onshore Converter 240

900km ±300kV 1200MW Cable 427.5

Cable Installation 315

2 X1200MW Onshore Converter 240

2. Radial 908.25

3. 1200MW 982.5

1. 900MW 876.50

23

Table 31 – Economic Cost Benefit Analysis

Dividing the additional capital investment of a scheme by that scheme’s additional annual revenue is

one way to calculate the number of years it takes to repay the investment. If the number of years to

repay the investment is less that the life expectancy of the scheme, then it may be worth investing

the additional capital.

HVDC schemes can have a life expectancy in excess of 40 years [22]. Therefore this cost-benefit

availability analysis indicates that scheme 3 offers the best potential return for the investor.

Variations in capital costs, capacity factor and electricity price could significantly impact on these

results. This type of economic cost-benefit analysis is simplistic and should only be used as an

indication. An extensive cost-benefit analysis would need to consider the projected inflation rates,

interest rates, and electricity prices over the next 40 years as well as taxation, exchange rates and

commodity prices such as copper. This type of economic forecasting is at best loose and out of the

scope of this report.

The purpose of this cost-benefit availability analysis is to clearly show the strong link between

transmission schemes availability and its economic feasibility. Other factors such as system losses

must be taken into consideration when evaluating which transmission scheme configuration offers

the greatest financially reward.

8 Summary

The most suitable transmission technology for the connection of large offshore windfarms located

more than approximately 50km from shore is VSC-HVDC. The technical and commercial viability of

connecting vast amounts of the UK’s generating capacity long distances from shore is dependent

upon the availability of VSC-HVDC schemes.

A radial VSC-HVDC scheme has been constructed for the purpose of performing availability analysis.

The scheme was based on the potential radial VSC-HVDC designs outlined in National Grid’s ODIS, to

ensure the scheme represents a typical VSC-HVDC link. Availability analysis, independent of

methodology, can only ever be as good as the input data. Unfortunately there are no true failure

statistics for VSC-HVDC components available in the public domain. Therefore the reliability indices

for each component within the scheme have been estimated based on the most credible

information available.

The availability analysis for the radial VSC-HVDC scheme has shown the energy availability due to

forced outages to be approximately 96.5%. The DC submarine cable was identified to be the key

component which affects the availability of the transmission scheme. Therefore every effort must

be made to ensure failures of submarine cables are minimised.

Availability analysis was carried out on a regional HVDC grid with each of its two paths back to shore

rated at 900, 1200 and 1800MW. This analysis shown that the availability of the grid was highly

Scheme Capital Cost £m Availability Loss £m/yr Saving £m /yr Additional Capital Cost £m Payback (yr)

1 876.5 0.963 34.990 0 0 0

2 908.25 0.965 33.174 1.816 31.75 17

3 982.5 0.972 26.073 8.917 106 12

24

dependent upon the rating of the grid’s paths back to shore and that the grid with paths rated at

1200MW and 1800MW had a significantly higher availability than an equivalent radial system.

The strong link between a HVDC transmission schemes availability and economic feasibility has also

been established in this report.

9 Conclusion

Connecting large amounts of offshore wind far from the shore is a sure way to increase renewable

energy generation. However if the availability of the transmission systems which facilitates the

power transfer back to shore is poor, the cost of energy to the consumer will increase and have a

negative impact on the economy. Therefore work to ensure a high availability of these transmission

schemes is of paramount importance. Availability analysis is a good tool to calculate the availability

of these schemes and to identify key components which have the greatest impact on the scheme.

This would allow mitigation strategies to improve the schemes availability to be put in place before

the schemes are built. However with the current lack of reliability data for VSC-HVDC components

conclusive availability analysis cannot be performed, although the key importance of the cable’s

availability is highlighted. Furthermore HVDC grids with additional capacity have been shown to

have a higher availability than an equivalent radial HVDC scheme and consequently could provide a

more cost-effective solution for the connection offshore windfarms.

25

10 References

[1] The Crown Estate, "Offshore wind: Opportunities for the composites industry", 2011, http://www.thecrownestate.co.uk/opportunities_composites_industry.pdf [accessed: July 2011]

[2] National Grid, "2010 Offshore Development Information Statement " 2010.

[3] National Grid, "Offshore Development Information Statement," 2011.

[4] Siemens, "HVDC PLUS – Basics and Principle of Operation," Siemens, 2008.

[5] K. Friedrich, "Modern HVDC Plus application of VSC in Modular Multilevel Converter Topology," 2010.

[6] N. MacLeod, "HVDC Max Sine : VSC Demonstrator," 2011.

[7] ABB, "Product Brochure - Gas-insulated Switchgear ELK-14, 245kV," 2011.

[8] National Grid, "2011 Offshore Development Information Statement Appendices," 2011.

[9] ABB, "Liquid-filled power transformers," 2009.

[10] Alstom, "Voltage Source Converter - Cooling Plant", 2010, http://www.alstom.com/assetmanagement/DownloadAsset.aspx?ID=a5030f88-1638-4874-a92f-b51cc294d9d2&version=9978ae5698e8433aa9283c2bee3ca94a1.pdf&lang=1036 [accessed:

[11] C. Ö. Ø. Rui, J. Solvik, J. Thon, K. Karijord, T. Gjengedal, "Design, operation and availability analysis of a multi-terminal HVDC grid - A case study of a possible Offshore Grid in the Norwegian Sea " in IEEE Trondheim PowerTech, 2011.

[12] Alstom, "Voltage Source Converter Switchyard," 2011.

[13] Alstom, HVDC - Connecting to the future: Alstom, 2010.

[14] Alstom, "HVDC for beginners and beyond," 2009.

[15] F. H. T.M. Chan, D. Kopejtkova*, P. O’Connell, J.-P. Taillebois, I. Welch, "Report on the second International Survey on High Voltage Gas Insulated Substations (GIS) Service Experience," 1998.

[16] S. Dodds, B. Railing, K. Akman, B. Jacobson, T. Worzyk, and B. Nilsson, "HVDC VSC (HVDC light) transmission – operating experiences," Cigre 2010, 2010.

[17] ABB, "Its time to connect," 2008.

[18] Ofgem, "Electricity and Gas Supply Market Report," Oct 2011.

[19] Department of Energy and Climate Change, "Eligible renewable sources and banding levels", http://www.decc.gov.uk/en/content/cms/meeting_energy/renewable_ener/renew_obs/eligibility/eligibility.aspx [accessed: Novemeber 2011]

26

[20] Ofgem, "The Renewables Obligation Buy-Out price and Mutualisation Ceiling 2011-2012," 2011.

[21] Ofgem, "Climate Change Levy: Renewables Exemption", http://www.ofgem.gov.uk/Sustainability/Environment/cclrenexem/Pages/CCLRenewablesExemption.aspx [accessed: November 2011]

[22] J. E. Skog, "HVDC Transmission and Lifetime Expectancy," 2004.

[23] S. Zadkhast, M. Fotuhi-Firuzabad, F. Aminifar, R. Billinton, S. O. Faried, and A.-A. A. Edris, "Reliability Evaluation of an HVDC Transmission System Tapped by a VSC Station," IEEE Transactions on Power Delivery, 2010.

[24] K. Linden, B. Jacobson, M. H. J. Bollen, and J.Lundquist, "Reliability study methodology for HVDC grids," Cigre 2010, 2010.

[25] ABB, "The evolution of GIS (Gas Insulated Switchgears)", 2011, http://www.abb.com/cawp/db0003db002698/38508bb5b1291fa7c12572ec003304ca.aspx [accessed: 20/10/11]

[26] ABB, "ABB Review - Extreme maintenance", http://www05.abb.com/global/scot/scot271.nsf/veritydisplay/e01a592d15046c26c1256f030033b6bc/$file/abb%20sp%204-04.pdf [accessed:

[27] ABB, "ABB’s on-site transformer repair service provides rapid return to full production for Corus’ Scunthorpe steelworks ", http://www.abb.co.uk/cawp/seitp202/0786ec54259901cec12576b3003a2d67.aspx [accessed: 20/10/11]

[28] R. V. Narinder S. Dhaliwal* and M. H. Astrid Keste, Peter Kuffel, , "Nelson River Pole 2 Mercury Arc Valve Replacement," Cigre, 2004.

[29] R. D. R.-C. U. Cigre Working Group B1.10, "Update of Service Experience of HV Underground and Submarine Cable Systems," 2009.

[30] National Grid, "2010 Offshore Development Information Statement Appendices," 2010.

[31] R. A. R. Billinton, Reliability Evaluation of Engineering Systems - Concepts and Techniques: Plenum Press, 1992.

[32] S. Stanley, "MTBF, MTTR, MTTF & FIT Explanation of Terms," IMC Networks, 2011.

27

Appendix A

Component Reliability Indices

Reliability statistics for the components in a VSC-HVDC scheme are extremely sparse. The following

papers/reports produced by academic institutions and industry will be used as the basis for the

derivation of reliability statistics for the VSC-HVDC scheme used in this report:-

1. LCC-HVDC data from academic paper [23] [Billinton et al, “Reliability Evaluation of an HVDC

Transmission System Tapped by a VSC Station"]

2. VSC-HVDC data from academic paper [23]

3. VSC-HVDC data from industrial paper report [11] [Statnett and DNV, “Design, operation and

availability analysis of a multi-terminal HVDC grid - A case study of a possible Offshore Grid

in the Norwegian Sea”]

4. VSC-HVDC data from Cigre paper [24] [ ABB and STRI, “Reliability study methodology for

HVDC grids”]

Source 1 and 2 are recent IEEE transactions paper produced by respected authors in the area of

power systems reliability including Roy Billinton. The third source is a report produced by Statnett

and Det Norske Veritas (DNV). The fourth source is a Cigre paper written by authors from ABB and

STRI. Therefore the data from these papers is expected to be credible. Due to the limited data

available some degree of estimation is unavoidable. Where this has been done the rational used is

explained.

Gas Insulated Switchgear (GIS) Failure Statistics

Unfortunately sources 1-4 only gave failure statistics for an AC circuit breaker. However since the

circuit breaker is the main component of a GIS switchbay, it is worth analysing the failure statistics

used in sources 1-4 to give an indication of the failure statistics for the GIS.

Table 32 shows the reliability statistics for AC circuit breakers given in academic and industrial

papers.

Table 32 – Circuit Breaker MTTF and MTTR values given in Academic and Industrial Papers

It is clear from Table 32 that the circuit breaker reliability statistics used for reliability studies in

academic and industrial papers varies very significantly. Source 3 and 4 reference Cigre publications

Source MTTF(yr) MTTR(hr) Scheme

1 66.7 50 500kV

2 1000 40 500kV

3 405 190 132kV Offshore

4 50 200 >500kV

28

for their reliability statistics. The last known high voltage circuit breaker survey was published by

Cigre in 1994. This publication presented results from two surveys one conducted between 1974 and

1977 (all circuit breaker technologies) and the other conducted between 1988 and 1991 (only SF6).

Table 33 – Cigre High Voltage Circuit Breaker Reliability Data

The MTTF values for the survey conducted in 1988-1991 survey are more than 3 times higher than

the values from the 1974-1977 survey. This increase in MTTF for the circuit breakers in the 1988-

1991 survey is thought to be due to improvements in circuit breaker technology and due to the

utilities doing a better job of collecting statistics. The increase in downtime for the MTTR for circuit

breakers in the 1988-1991 survey was cited as being primarily due to the time taken to obtain a

specific spare part, for the SF6 circuit breakers.

According to the ODIS 2011 document, gas insulated switchgear (GIS) bays will be installed on all

offshore platforms and onshore platforms located less than 5km from the sea. The final results for

two surveys on the reliability of gas insulated substations have been published. The first

international survey was circulated in 1991 and the second survey was circulated in 1996 [15]. The

major failure statistics results from the 2nd

international survey for GIS commissioned after 1985 are

shown in Table 34.

Table 34 –Failure statistics from the 1996 survey for GIS commissioned after 198516

Comparing the values from the Cigre 1988-1991 survey in Table 33 with Table 34, it is clear that a

GIS bay tends to take longer to repair than an AC circuit breaker and that the higher voltage (300-

500kV) GIS has a shorter MTTF than an AC circuit breaker. This is not particularly surprising

considering a GIS bay contains an AC circuit breaker as well as other equipment such as

disconnectors.

The data given in Table 32, Table 33 and Table 34 can be used to estimate the failure statistics for a

220/275kV GIS switchbay and a 400kV switchbay commissioned in 2011. It is fair to assume that the

MTTF of a GIS switchbay in 2011 would be much higher than a GIS switchbay commissioned

between 1985 and 1996. In fact the MTTF from the 1996 survey for 200-300kV GIS commissioned

after 1985 was 45% higher than the GIS commissioned after 1985 from the 1991 survey. The MTTF

for AC circuit breakers 1988 survey was more than 300% higher than the values given in the 1974

16

MTTF is calculated by taking the reciprocal of the failure rate. It is assumed the failure rate is based on the

number of Circuit breaker bay-years in service. (I.e. the reciprocal of the failure rate is the MTTF not the

MTBF). In any case difference between MTTF and MTBF will be very small.

Survey Voltage(kV) MTTF (yr) MTTR(hr)

200-300 38.760 58.5

300-500 21.978 83.8

200-300 122.850 54.6

300-500 82.645 162.5

Cigre 1974-1977

Cigre 1988-1991

Component MTTF (yr) MTTR(hr)

200-300kV GIS 149 192

300-500kV GIS 39 192

29

survey. Therefore it is justifiable to assume the MTTF for a 220/275kV GIS switchbay and a 400kV

switchbay commissioned in 2011 would be 250 years and 100 years respectively. These figures lie

within reasonable ranges as shown by the figures used in academic and industrial papers in Table 32.

It is also worth mentioning that ABB have quoted a mean time between failure (MTBF) figure of up

to 1000 bay-years for their gas insulated switchgear[25].

Based on the assumption that GIS today would be somewhat easier to fix than 15-25 years ago and

that the spare parts are more readily available, the MTTR values will be reduced. Furthermore the

supply chain is computerised with modern telecoms which would help to improve service levels.

Therefore the MTTR for modern GIS is assumed to be 120 hours.

As mentioned previously access times for offshore platforms vary massively depending on a number

of factors. The 1996 GIS survey stated at about 70% of repairs could be carried out on site and

required a spare part and/or enclosure [15]. It is assumed that the high majority of spare parts could

be transported by helicopter. Therefore the time to access the offshore platform to repair a GIS

switchbay is taken as 84 hours (70% helicopter, 30% medium vessel). Approximately 40% of 192

hours down time (Table 34) is the time it takes to get spare parts and tools. It is estimated about 20

hours of the offshore access time is spent performing administration related tasks which could be

done concurrently with the time spent obtaining spare parts. Therefore the MTTR for the offshore

gas insulated switchgear offshore used is 184 hours.

Figure 21 – Estimated Reliability Values for GIS

Transformer Failure Statistics

Table 35 shows the reliability statistics for transformers given in academic and industrial papers.

Table 35 – Transformer Failure Statistics given in Academic and Industrial Papers

The transformers used in LCC-HVDC schemes (source1) are more complex and experience greater

stress than the transformers in the VSC-HVDC schemes (source 2). This would explain the better

reliability statistics for the transformer from source 2.

The reliability statistics provided by source 4 are from the latest transformer failure statistics survey

published by Cigre in 1983 for transformers between 300-700kV. After analysing the 1983 report it is

clear that the statistics from source 4 are based on an autotransformer with and without an on load

tap changer (OLTC). Analysis of the 1983 report shows that for an autotransformer with an OLTC the

Component MTTF (yr) MTTR(hr)

Offshore switchbay 250 184

400kV onshore switchbay 100 120

275kV onshore switchbay 250 120

Source MTTF (yr) MTTR (hr) Scheme

1 14.29 1200 500kV

2 20 1000 500kV

3 225 672 132kV Offshore

4 41.67 2160 >500kV

30

MTTF is 98.33 years and for an autotransformer without OLTC the MTTF is 17.2 years17

. This is

somewhat surprising and the report noted that the abnormally high failure rate of autotransformers

without OLTC could be in part explained by the failure of the transformers belonging to a certain

network. In other words the MTTF of 17.2 years for an autotransformer without OLTC should be

used with a degree of caution and therefore the figure with and without OLTC as used in source 4

should also be used with a degree of caution. In any case HVDC schemes use transformers with an

OLTC and tend not to use autotransformers, because they cannot provide galvanic isolation between

the AC and DC sides. Therefore the statistic given in source 4 may not be representative of a

transformer used in an HVDC scheme.

The 1983 Cigre report also gave statistics for substation station transformers. The MTTF for a 100-

300kV substation transformer with an OLTC and a 300-700kV transformer is 62.5 years and 50.85

years respectively. Considering the survey was conducted more than 30 years ago. It is reasonable to

suggest the MTTF for a modern transformer is much improved. Therefore an estimated MTTF of 95

years for 100-300kV transformer and 80 years a 300-700kV transformer will be used in this

availability analysis. These values are still much less than the estimated values given by DNV.

Unfortunately the 1983 Cigre report did not publish the mean downtime for non-autotransformers

in the 300-700kV range as it was deemed not significant. However the mean downtime with a 95%

confidence level for a 100-300kV transformer with an OLTC was reported as being between 46 and

76 days. Therefore the MTTR is taken as the mean, 61 days (1464 hrs). Considering it is now more

than 30 years since the survey was conducted, an estimated MTTR value of 42 days (1008 hrs) will be

assumed. This figure is based on the assumption that technology today allows a quicker diagnosis

and repair of the transformer failure.

In the event a transformer fails it is normally shipped back to the factory for repair [26]. There have

been situations where it is so difficult to send the transformer back to the factory that a fully

equipped workshop has been constructed on site. It is difficult to send an offshore transformer back

to the factory, but due to the lack of space on an offshore platform it would be extremely rare if not

impossible to construct a workshop on the platform. Therefore in the event a transformer fails it is

expected it would need to be shipped back to the factory for repair.

In this report the time it takes to access an offshore platform with a transformer has been estimated

at 3 weeks (504 hours) as shown in Table 1. This figure was based on the transportation of a large

item such as a transformer to the offshore platform. The offshore access time required for repairing

an offshore transformer would be split into two parts. The first part would be to transport the

transformer back to shore. The second part would occur once the transformer is repaired and must

be transported back to the offshore platform. Therefore the offshore access time for repairing the

transformer must at least be greater than 3 weeks. A significant portion of the three weeks access

time would be due to delays in acquiring the large vessel at very short notice. However the vessel

could be booked well in advance for returning the transformer back to the offshore platform.

Therefore the access time to transport the transformer to the offshore platform will be reduced to

17

MTTF is calculated by taking the reciprocal of the failure rate. According to the Cigre report the failure rate is

calculated based on the number of transformer-years in service (i.e. the reciprocal of the failure rate is the

MTTF not the MTBF).

31

one week. Therefore the total access time to repair the offshore transformer is estimated to be 4

weeks.

It is assumed one week of the MTTR for the onshore transformer is spent sourcing spare parts. It is

feasible that the transformer could be diagnosed using non-invasive tests on the offshore platform

[27]. This would allow the spare part to be sourced while the transformer is being transported back

to the factory. Therefore the MTTR for the offshore transformer will be 3 weeks longer than the

MTTR for the onshore transformer. For comparison DNV increased the MTTR for the offshore

transformer by 3 weeks in their availability analysis.

Table 36 – Reliability Values for Transformer

Converter Reactor Failure Statistics

Table 37 shows the reliability statistics for phase reactors given in academic and industrial papers.

Table 37 – Converter reactor reliability values given in Academic and Industrial Papers

Only source 3 has stated reliability values for the converter reactor. Unfortunately there no other

known author publications which have given reliability values for the converter phase reactor. It is

worth noting that availability statistics for the Murraylink VSC-HVDC scheme have been published by

ABB in a Cigre paper [16] as shown in Table 38.

Table 38 – Murraylink Energy Availability

The very low availability of the scheme in 2007 was due to a fault in the phase reactor, which was

most likely caused by a fault in an external light fitting which lead to a fire on the reactor. It was

noted that one of the reasons the repair took so long was because the building was not designed to

accommodate an easy replacement. That said the Murray link went into service in 2003 and it is

expected new schemes would be designed to allow easy replacement of components.

The values from DNV seem reasonable, after all DNV is a well respected risk management company

and therefore their values are expected to be credible. The only slight concern is that the MTTR

values for both the onshore and offshore converters are the same. In the event a converter reactor

fails it is assumed it would need to be replaced rather than repaired on site because it is a single unit

and has no moving parts. A converter reactor is too large to be shipped via a helicopter therefore a

medium sized vessel would be required. The offshore access time for the converter reactor is 168

Component MTTF(yr) MTTR(hr)

Offshore Transformer 95.00 1512.00

Onshore Transformer 95.00 1008.00

Source MTTF (yr) MTTR (hr)

3 7 24

Energy 2003 2004 2005 2006 2007 2008 2009 Average

Total 95.18 97.08 95.39 98.92 90.56 99.17 99.37 96.52429

Scheduled 96.49 98.77 97.96 98.51 97.91 99.12 99.13 98.27

Forced 98.21 98.04 97.11 99.33 90.98 99.86 100 97.64714

Murray Link

32

hours. It is expected that a converter reactor is readily available to allow replacement within 24

hours. Since there is no time delay in sourcing the component the offshore MTTR is equal to the

onshore MTTR plus the offshore access time.

Table 39 – Phase Reactor Reliability Values

MMC Failure Statistics

Table 40 shows the reliability statistics for MMCs given in academic and industrial papers.

Table 40 – MMC Failure Statistics given in Academic and Industrial Papers

It is unclear if sources 1 and 2 have included the control and protection (C&P) systems as well as the

cooling and ventilation systems in the reliability values for the converter. However it is assumed they

have since these systems are not considered separately and the converter would be the most

appropriate component in which to include these systems. Sources 2 and 3 do not explicitly state

that their reliability statistics are for a two level VSC converter, however, since both systems include

AC filters it is fair to assume they are for a two-level converter. Source 3 has considered the C&P as

well as the cooling and ventilation systems separately. Therefore the values given by source are

purely for the IGBT converter system.

The reliability statistics given for a voltage source converter in source 4 are based on actual forced

outage statistics collected for LCC-HVDC schemes between 2005 and 2006 [24]. However the value

for source 4 given in Table 40 is a combined value for the converter, C&P and DC equipment. Based

on the same analysis method used in source 4 the MTTF and MTTR for only the converter is 2.1 years

and 3 hours respectively. These values account for the cooling and ventilation systems, but not the

C&P and DC equipment.

There has been no actual reliability statistics published for converters used in VSC-HVDC schemes.

However based on the values given in Table 40 it is assumed that the MTTF and MTTR for a two-level

VSC are 2 years and 12 hours respectively. The MMC has a significantly higher component count

than a two-level VSC, which is likely to reduce the reliability of the converter. However it does not

suffer the high stress of switching all IGBTs in the valve simultaneously. It is reasonable to assume

that the MMC at this time will be slightly less reliable than the two-level converter due to the lack of

Component MTTF (yr) MTTR (hr)

Onshore Converter Reactor 7 24

Offshore Converter Reactor 7 192

Source MTTF (yr) MTTR (hr) Comment

1 1 5 LCC

2 2 4 2-level VSC

3 2 24 2-level VSC

4 0.71 4.1 VSC*

*Value based on LCC and includes the C&P and the DC Equipment

33

experience with this type of converter in HVDC schemes and the higher component count. Therefore

the MTTF will be reduced to 1.9 years as a placeholder to reflect the expected increase in failure

rates for MMC. The MTTR will be kept the same at 12 hours for an onshore converter. The reliability

indices for the MMC account for the cooling and ventilation systems.

The failure of a MMC is likely to require a sub-module replacing. It is justifiably assumed that spare

sub-modules would be readily available since they require minimum storage space and are critical

for converter operation. Sub-modules are fairly small components and could be transported by a

helicopter with the engineer. Since the reliability indices for the MMC includes the cooling and

ventilation systems, the size of spare parts for these systems must also be taken into account. The

critical components which have high failure rates in a cooling plant are electrical motors. It is

expected that electrical motors could be transported by helicopter/small vessel. The offshore access

time for such a component has been estimated at 48 hours (Table 1) and as such the MTTR for the

offshore converter is 60 hours.

Table 41 – MMC Reliability Values

Control System

Table 42 shows the reliability statistics for the control system given in academic and industrial

papers.

Table 42 – Control and Protection Failure Statistics given in Academic and Industrial Papers

The reliability statistics from source 3 are a DNV internal estimate for a single VSC control system.

The control and protection systems for HVDC schemes are normally duplicated [13]. Therefore the

availability of the duplicated control system must be calculated.

Table 43 – Availability of DNV duplicated control system

Providing the repair time for the DNV duplicated C&P system is fixed at 9 hours the MTTF for the

duplicated control system would be approximately 930 years. This value has been calculated by

rearranging equation (1.1)


MMC Onshore 1.9 12

MMC Offshore 1.9 60

Source MTTF (yr) MTTR (hr)

3 1 9

4 1.60 3

Capacity Control 1 Control 2 Probability Availability

1 1 0.99795

1 0 0.00103

0 1 0.00103

0 0 0 0.00000 0.0000011

100% 0.9999989

34

(1 )

(1 )

MTTFA

MTTF MTTRMTTF

MTTF MTTRA

MTTF A A MTTR

A MTTRMTTF

A

=+

= +

− = ××=

−

(1.6)

0.9999989 9

8181809 930(1 0.9999989)

hrs or yrs× ≈

− (1.7)

The values given in source 4 are from the actual forced outage statistics collected for LCC-HVDC

schemes between 2005 and 2006. Therefore the MTTF statistic is actually the mean time to failure

of both C&P systems as the scheme could operate if only one of the two C&P systems failed.

Therefore the availability of the duplicated C&P system is 0.99979 which is significantly less than the

availability of the duplicated control system from the DNV reliability data. This is further highlighted

by the difference between the calculated MTTF value from the DNV data and the MTTF value from

source 4. It is expected the reliability data given in source 4 is more realistic than source 3 since this

is actual HVDC C&P failure data.

The hardware for the C&P system for a LCC-HVDC system is similar to an MMC VSC-HVDC system.

Therefore the data given in source 4 would provide a good basis for estimating the reliability indices

for the MMC VSC-HVDC C&P system. The MMC valve based electronics (VBE), the interface between

the C&P system and the converter, is different from that of an LCC-HVDC scheme due to the higher

number of levels. The software is also more complex, because the control system must balance the

capacitor voltages in the MMC valve and turn each level on and off individually. However it is

expected that a modern C&P system would be more reliable than an older C&P system. The world

HVDC survey obtains data from many schemes using C&P systems of different ages. Therefore all

things considered a MTTF and MTTR of 1.6 years and 3 hours will be used in this availability analysis.

It is assumed many control system faults could be solved without attending the site (i.e. via remote

access). In the event that the problem cannot be solved via remote access an engineer would have

to attend site. Spare parts for controls systems such as digital signal processing cards are very small

and therefore access via helicopter is suitable. It is assumed that 30 % of faults on the offshore

control system require an on-site visit. Therefore the MTTR of the offshore control system is equal to

MTTR for the onshore control system plus 30% of the time required to access the offshore platform

with a small component (3+48*0.3=17hours).

Table 44 – Control System Reliability Values


Onshore Control System 1.6 3

Offshore Control System 1.6 17

35

DC Switchyard

Table 45 contains the reliability indices for the DC equipment from sources 1-4.

Table 45 – DC Equipment Failure Statistics given in Academic and Industrial Papers

There is significant difference between the DC filter reliability indices between sources 1 and 2. The

DC filters are for different schemes but it is unlikely that the VSC DC filter is 400 times more reliable

than an LCC filter based on the MTTF. The DNV (source 3) reliability indices for the VSC DC filter

appear to be more realistic than source 2. Sources 1-3 have appear to have included what they

consider the key components for their analysis, whereas source 4 has accounted for an entire DC

switchyard. Source 4 has accounted for all the VSC DC equipment by analysing the failure statistics

for DC equipment in the 2006-2007 world HVDC survey (LCC) published in 2008.

The major equipment in a MMC DC VSC switchyard consists of HV capacitor banks, line reactors,

measurement transducers and switchgear [12]. The major equipment in a LCC DC switchyard

consists of DC harmonic filters, smoothing reactors, measurement transducers and switchgear [13].

Figure 22 – MMC VSC DC Switchyard (left, modified from[12]) LCC DC Switchyard (right modified from[14])

Since there is significant similarity between the DC switchyards, the failure statistics from the world

HVDC survey (LCC) could be used to estimate the reliability indices for the MMC VSC-HVDC DC

switchyard. The latest World HVDC survey was published in 2010 for data collected on LCC-HVDC

schemes during 2007-2008. Back-to-back HVDC schemes do not normally require smoothing

reactors or DC filters [13]. Therefore only the data for transmission schemes should be considered.

In the 2007-2008 HVDC survey data was collected from 18 transmission schemes (8 monopole and

Source MTTF (yr) MTTR (hr) Scheme

20 300 Smoothing Reactor

2.5 12 LCC DC Filter

1 4 VSC HVDC Switch/breaker

1000 5 VSC DC Filter

7 24 HV DC Bus

6 24 VSC DC Filter

4 3.333 6.4 Based on Data from 2005-2006 LCC Survey

1

2

3

Line Reactor

36

10 bipole). Monopole schemes have one DC switchyard at each end of the scheme, whereas bipole

schemes have the equivalent of two DC switchyards at each end of the scheme. The failure rate for a

single DC switchyard can be calculated by summing the number of failures for the 18 transmission

schemes and dividing by the number of DC switchyards (56). The MTTR is obtained by dividing the

total number of outage hours by the number of failures. The reciprocal of the failure rate is the

mean time between failures (MTBF). The MTTF is the MTBF minus the MTTR. The average MTTF and

MTTR has been calculated and is shown in Table 46.

Table 46 – Analysis of the DC equipment failure statistics from the world 2007-2008 HVDC survey

Comparing the MTTF and MTTR calculated here from the 2007-2008 with the reliability indices

calculated in source 4 from the 2005-2006 shows some significant difference. However source 4

calculated the reliability indices for a DC switchyard from both back-to-back and transmission

schemes. Source 4 also assumed that 50% of the HVDC schemes in the 2005-2006 were monopole

and 50% were bipole. Since the 2007-2008 survey is the most recent and the analysis of the

reliability indices is more accurate for a transmission scheme these indices will be used in this report.

It is worth noting that although there are 18 transmission schemes which would normally equate to

56 converters (8*2+4*10) further analysis of the data shows that there are actually 80 converters.

This is because a number of schemes contain more than 1 converter per pole. Nelson River BP 2 for

example has 3 six-pulse converters connected in series per pole giving 12 converters for the bipole

instead of the usual 4 [28]. This is unlikely to affect the reliability indices for DC switchyards as there

should still be about the same amount of DC equipment for standard HVDC schemes with one

converter per pole. However calculating the reliability indices for the HVDC converters from the

world HVDC surveys should take the number of converters per pole into consideration to ensure a

high degree of accuracy.

In order to adjust the MTTR for the offshore DC switchyard, the most common types of repair and

size of spare parts would be needed. Unfortunately the HVDC surveys do not give this level of detail.

However by analysing the outage statistics due to DC equipment failures it may be possible to get an

indication of the size of component required for the most common failures. In 2007 there were 12

DC Equipment failures causing a total of 368 outage hours of which a single failure accounted for

314 hours. Therefore the MTTR excluding the single major failure was only 4.9 hours. Such a small

repair time is likely to indicate that only small parts which were readily available if any were

required. The 314 hour outage indicates the repair required a large component. The 314 hour

Parameters 2007 2008 Average

No of schemes 19 19

Number of monopoles 9 9

Number of bipoles 10 10

No of Failures 12 18

Failure per scheme year 0.63 0.95

Failures per Switchyard 0.21 0.31

MTBF (yr) 4.8333 3.22 4.03

Repair time (hr) 367.50 386.80

MTTR (hr) 30.63 21.49 26.06

MTTF (yr) 4.83 3.22 4.02

37

outage was due to a smoothing reactor failure, which is a large component as shown in Figure 22.

Only five of the 18 failures in 2008 required a repair time in excess of 10 hours. This analysis

indicates that the high majority of DC switchyard repairs require a small spare part if any and that

the spare part is readily available. Therefore it is estimated 80% of offshore DC switchyard repair

could be carried out via helicopter/small vessel and the remaining 20% via a small vessel18

.

Furthermore since the analysis indicates the majority of spare parts are readily available it is

assumed very little time could be saved performing parallel tasks and it is therefore neglected.

Hence the MTTR for the offshore DC switchyard is the MTTR for the onshore DC switchyard plus the

offshore access time for the DC switchyard. From Table 1 the offshore access time to the DC

switchyard is estimated to be 72 hours. (0.8*48+0.2*168).

Table 47 – Estimated reliability indices for DC switchyard

DC Cable

Only source 3 contained reliability indices for cables as shown in Table 48.

Table 48 - DC Cable Failure Statistics given in Academic and Industrial Papers

The results from the latest reliability survey for cable systems were published by Cigre in 2009 [29].

The survey ended in 2005 and was for a 15 year period. At the end of 2005 approximately 7000

circuit km of submarine cable was identified as being in service.

DC-XLPE cable is the type of cable which is most likely to be used for VSC-HVDC schemes.

Unfortunately the failure rates for DC-XLPE cables were not given in the report. The failure rates for

all submarine cable types with the exception of DC self contained oil filled (SCOF) cables due to

internal faults was zero. Therefore the failure rate due to internal faults for DC-XLPE cable will be

assumed to be zero.

The average failure rate for all types of cable technology and voltage ratings due to

external/unknown damage gives a failure rate of 0.217 failures per year per 100km of circuit.

Approximately 55% of these submarine cable failures were reported to be at a location where the

cable was unprotected19

. Submarine HVDC cables are normally buried at depths of 1m to offer

protection [30]. For cable routes where direct burial is unsuitable due to the sea bed conditions (e.g.

solid rock) other protection methods such as concrete mattressing may be employed [30].

Considering that HVDC submarine cables will have installation protection, the failure rate is

calculated to be 0.096 failures per year per 100km circuit. This failure rate is nearly double the

18

Based on the assumption that an outage time of less than 10 hours for a single fault indicates a small spare

was required. In 2007, 2 of the 12 failures caused outages in excess of 10 hours while in 2008, 5 of the 18

failures caused outages in excess of 10 hours. Therefore approximately 80% of failures required a small part. 19

There were a total of 49 submarine cable failures recorded of which 4 were internal failures. 25 of the 45

(55%) external/unknown failures occurred at a location the cable was unprotected.

Componenet MTTF(yr) MTTR(hr)

Onshore DC Switchyard 4.02 26.06

Offshore DC Switchyard 4.02 98.06

Component Failure rate (occ/yr/100km) MTTR (hr)

DC Cable 0.05 1440

38

failure rate used in the DNV report. It is important to note that submarine cable failures rates are

very subjective. They are heavily influenced by many factors including, fishing activity, installation

protection method, awareness of cable routes, water depth, and hardness of the sea bed. In this

availability analysis it will be assumed the annually failure rate is 0.07 failures per 100km of circuit.

This is a reasonable assumption based on the data from the DNV report and the Cigre survey.

The offshore converter and onshore converter are located 165km apart. Therefore the total cable

length is 330km, but the circuit length/route length is assumed to be 165km20

. The average repair

time for submarine cables in the Cigre 2009 was 60 days [29] which is the same as the DNV MTTR.

Therefore this availability analysis will assume a MTTR of 60 days (1440hrs) for submarine cables.

Table 49 – Estimated Reliability Indices for Submarine Cable21

20

The questionnaire for the Cigre survey gives an example of how the circuit length is calculated. “A 5 km long

double-circuit connection with 3 phases and two cables per phase should be reported as 10 circuit km even

though it has 60 km of cable core”. Therefore from this example 330km of core cable has a circuit length of

165km.

21 The reciprocal of the failure rate was assumed to be the MTBF. MTTF=MTBF-MTTR.

Component Failure rate (occ/yr/100km) Circuit Length (km) MTTF (yr) MTTR (hr)

DC Cable 0.07 165 8.493625 1440

39

Appendix B

Reliability Concepts & Definitions

Reliability – is the probability of a device performing its purpose adequately for the period of time

intended under the operating conditions encountered [31].

Maintainability – is the probability that a component/device/system will be retained or restored to

specified working condition.

Mean Time To Failure – is the average time from the instance a component/device/system enters a

working state until a component/device/system enters a failed state. This may also be defined as the

component/device/systems uptime.

Mean Time To Repair - is the average time it takes to restore a component/device/system to a

specified working condition from the instance the component/device/system failed. This may also

be defined at the component/device/systems downtime.

Mean Time Between Failures – is the average time elapsed between a component/device/system

entering a working state until component/device/system re-enters a working state. This may also be

defined as the cycle time, which is the uptime plus the downtime.

Availability – is the probability of finding the component/device/system in the operating state at

some time into the future [31]. The availability of a component with two states can be calculated by

equation (1.8).

Uptime MTTF MTTF

AUptime Downtime MTTF MTTR MTBF

= = =+ +

(1.8)

Failure rate – is the number of times a component/device/system is expected to fail per unit of time

or the number of times a component/device/system is expected to fail per unit of time the

component/device/system is in a working condition. The failure rate in this report has two

definitions because different reliability surveys determine the failure rate from one of two methods.

Some surveys record the number of failures for a sample of components for a specified period time

without suspending time for a component upon failure, whereas other surveys suspend time when a

component enters a failed state.

As an example, consider a fictitious reliability survey which collected failure statistics from 10

transformers for 10 years during their useful life, giving 100 transformer-years of data. The survey

concluded that there were 4 failures in that time and that the average time to repair each failure

was 3 months. The number of times a transformer is expected to fail per unit of time is calculated as

follows:-

4

0.04( / )10 10

occ yrλ = =×

(1.9)

40

Equation (1.9) states that the failure rate for a transformer is 0.04 failures per year. However this

method for determining the failure rate did not stop suspend time when each transformer was in a

failed condition. The number of times the transformer is expected to fail per unit of time when the

transformer is in a working condition is calculated as follows:-

4

0.0404040( / )10 10 (4 3 )

occ yrmonth

λ = =× − ×

(1.10)

Failure rates in this report are assumed to be constant (see bath-tub curve). The reciprocal of

equation (1.9) is the MTBF whereas the reciprocal of equation (1.10) is the MTTF.

Therefore the MTTF and MTBF:-

1

24.750.0404040

MTTF years= = (1.11)

1

250.04

MTBF years= = (1.12)

24.75 3 25MTBF MTTF MTTR months years= + = + = (1.13)

Reliability surveys normally specify the failure rate and MTTR. Therefore if the reliability survey has

calculated the failure rate for a component without suspending time for failed components, the

MTTF may be obtained from equation(1.14).

1

MTTF MTTRλ

= − (1.14)

It is not always clear which method the reliability survey has used to calculate the failure rate.

However, in many cases this will not significantly impact on the calculated availability of the

component since the MTTF is typically much greater than the MTTR.

Bath-tub Curve

The lifecycle of a product can be described by three distinct phases as shown by the bath-tub curve

in Figure 23. The infant mortality phase is characterized by a high failure rate which decreases with

MTBF

MTTR

MTTF time

1

0

41

time, and could be due to manufacturing errors or improper design. Product failures in the second

region (useful life) occur purely by chance and as such the failure rate is constant. The third region

(end of life) of the bath-tub curve shows the product is wearing out.

Figure 23 – Product Lifecycle from [32]

The failures rates in this report are assumed to be constant with time (i.e. phase 1 and 3 are

neglected). This is a fair assumption since components go through an extensive testing process

before they are installed at site and it is expected that the life of the product has been designed to

be equal to or less than the useful life of the product. In other words, it is expected that

manufacturing errors or improper design issues would be discovered in the testing phase and that if

a product is expected to be in operation for 25 years the manufacture would have designed the

product to have a useful life of at least 25 years.

Mean Time to Access Offshore Platform – is the average estimated time it takes to reach an

offshore platform with a component of a particular size.

Mean Offshore Access Time – is the average estimated offshore access time for a particular

component.

Mean Time Performing Concurrent Tasks – is the average time spent performing tasks associated

with repairing a component located onshore which can be conducted in parallel with tasks related to

the MOAT for the component.

42

Example

A GIS switchbay located onshore has an estimated MTTR of 120 hours. It is estimated that 70% of

GIS failures require a small sized spare part and 30% require a medium sized spare part (see Table 1).

0.7 ( ) 0.3 ( )

0.7 48 0.3 168 84

MOAT MOTTAOP small MOTTAOP medium

MOAT hours

= × + ×= × + × =

(1.15)

In addition it is estimated that 20 hours of the MOAT is spent on administration related tasks which

can be performed in parallel with the time spent obtaining spare parts (accounted for in the onshore

MTTR).

20MTPCT hours= (1.16)

120 84 20 184offshore onshoreMTTR MTTR MOAT MTPCT hours= + − = + − = (1.17)

43

Appendix C

Cost-benefit Analysis

The full truth table for 7 variables is shown below:-

State OFNA OFNB OFNC C1 C2 Sub 6 Sub 7

1 1 1 1 1 1 1 12 1 1 1 1 1 1 03 1 1 1 1 1 0 14 1 1 1 1 1 0 05 1 1 1 1 0 1 16 1 1 1 1 0 1 07 1 1 1 1 0 0 18 1 1 1 1 0 0 09 1 1 1 0 1 1 110 1 1 1 0 1 1 011 1 1 1 0 1 0 112 1 1 1 0 1 0 013 1 1 1 0 0 1 114 1 1 1 0 0 1 015 1 1 1 0 0 0 116 1 1 1 0 0 0 017 1 1 0 1 1 1 118 1 1 0 1 1 1 019 1 1 0 1 1 0 120 1 1 0 1 1 0 021 1 1 0 1 0 1 122 1 1 0 1 0 1 023 1 1 0 1 0 0 124 1 1 0 1 0 0 025 1 1 0 0 1 1 126 1 1 0 0 1 1 027 1 1 0 0 1 0 128 1 1 0 0 1 0 029 1 1 0 0 0 1 130 1 1 0 0 0 1 031 1 1 0 0 0 0 132 1 1 0 0 0 0 033 1 0 1 1 1 1 134 1 0 1 1 1 1 035 1 0 1 1 1 0 136 1 0 1 1 1 0 037 1 0 1 1 0 1 138 1 0 1 1 0 1 039 1 0 1 1 0 0 140 1 0 1 1 0 0 041 1 0 1 0 1 1 142 1 0 1 0 1 1 043 1 0 1 0 1 0 144 1 0 1 0 1 0 045 1 0 1 0 0 1 146 1 0 1 0 0 1 047 1 0 1 0 0 0 148 1 0 1 0 0 0 049 1 0 0 1 1 1 150 1 0 0 1 1 1 051 1 0 0 1 1 0 152 1 0 0 1 1 0 053 1 0 0 1 0 1 154 1 0 0 1 0 1 055 1 0 0 1 0 0 156 1 0 0 1 0 0 057 1 0 0 0 1 1 158 1 0 0 0 1 1 059 1 0 0 0 1 0 160 1 0 0 0 1 0 061 1 0 0 0 0 1 162 1 0 0 0 0 1 063 1 0 0 0 0 0 164 1 0 0 0 0 0 0

44

65 0 1 1 1 1 1 166 0 1 1 1 1 1 067 0 1 1 1 1 0 168 0 1 1 1 1 0 069 0 1 1 1 0 1 170 0 1 1 1 0 1 071 0 1 1 1 0 0 172 0 1 1 1 0 0 073 0 1 1 0 1 1 174 0 1 1 0 1 1 075 0 1 1 0 1 0 176 0 1 1 0 1 0 077 0 1 1 0 0 1 178 0 1 1 0 0 1 079 0 1 1 0 0 0 180 0 1 1 0 0 0 081 0 1 0 1 1 1 182 0 1 0 1 1 1 083 0 1 0 1 1 0 184 0 1 0 1 1 0 085 0 1 0 1 0 1 186 0 1 0 1 0 1 087 0 1 0 1 0 0 188 0 1 0 1 0 0 089 0 1 0 0 1 1 190 0 1 0 0 1 1 091 0 1 0 0 1 0 192 0 1 0 0 1 0 093 0 1 0 0 0 1 194 0 1 0 0 0 1 095 0 1 0 0 0 0 196 0 1 0 0 0 0 097 0 0 1 1 1 1 198 0 0 1 1 1 1 099 0 0 1 1 1 0 1

100 0 0 1 1 1 0 0101 0 0 1 1 0 1 1102 0 0 1 1 0 1 0103 0 0 1 1 0 0 1104 0 0 1 1 0 0 0105 0 0 1 0 1 1 1106 0 0 1 0 1 1 0107 0 0 1 0 1 0 1108 0 0 1 0 1 0 0109 0 0 1 0 0 1 1110 0 0 1 0 0 1 0111 0 0 1 0 0 0 1112 0 0 1 0 0 0 0113 0 0 0 1 1 1 1114 0 0 0 1 1 1 0115 0 0 0 1 1 0 1116 0 0 0 1 1 0 0117 0 0 0 1 0 1 1118 0 0 0 1 0 1 0119 0 0 0 1 0 0 1120 0 0 0 1 0 0 0121 0 0 0 0 1 1 1122 0 0 0 0 1 1 0123 0 0 0 0 1 0 1124 0 0 0 0 1 0 0125 0 0 0 0 0 1 1126 0 0 0 0 0 1 0127 0 0 0 0 0 0 1128 0 0 0 0 0 0 0

45

The capacity probability table for the HVDC grid with each path to shore rated at 900MW is shown

below:-

State OFNA OFNB OFNC C1 C2 Sub 6 Sub 7 Probability Capacity1 0.98721 0.98721 0.98721 0.99310 0.99310 0.97743 0.97743 0.90654 18002 0.98721 0.98721 0.98721 0.99310 0.99310 0.97743 0.02257 0.02093 9003 0.98721 0.98721 0.98721 0.99310 0.99310 0.02257 0.97743 0.02093 9004 0.98721 0.98721 0.98721 0.99310 0.99310 0.02257 0.02257 0.00048 05 0.98721 0.98721 0.98721 0.99310 0.00690 0.97743 0.97743 0.00630 15006 0.98721 0.98721 0.98721 0.99310 0.00690 0.97743 0.02257 0.00015 9007 0.98721 0.98721 0.98721 0.99310 0.00690 0.02257 0.97743 0.00015 6008 0.98721 0.98721 0.98721 0.99310 0.00690 0.02257 0.02257 0.00000 09 0.98721 0.98721 0.98721 0.00690 0.99310 0.97743 0.97743 0.00630 150010 0.98721 0.98721 0.98721 0.00690 0.99310 0.97743 0.02257 0.00015 60011 0.98721 0.98721 0.98721 0.00690 0.99310 0.02257 0.97743 0.00015 90012 0.98721 0.98721 0.98721 0.00690 0.99310 0.02257 0.02257 0.00000 013 0.98721 0.98721 0.98721 0.00690 0.00690 0.97743 0.97743 0.00004 120014 0.98721 0.98721 0.98721 0.00690 0.00690 0.97743 0.02257 0.00000 60015 0.98721 0.98721 0.98721 0.00690 0.00690 0.02257 0.97743 0.00000 60016 0.98721 0.98721 0.98721 0.00690 0.00690 0.02257 0.02257 0.00000 017 0.98721 0.98721 0.01279 0.99310 0.99310 0.97743 0.97743 0.01174 120018 0.98721 0.98721 0.01279 0.99310 0.99310 0.97743 0.02257 0.00027 90019 0.98721 0.98721 0.01279 0.99310 0.99310 0.02257 0.97743 0.00027 90020 0.98721 0.98721 0.01279 0.99310 0.99310 0.02257 0.02257 0.00001 021 0.98721 0.98721 0.01279 0.99310 0.00690 0.97743 0.97743 0.00008 90022 0.98721 0.98721 0.01279 0.99310 0.00690 0.97743 0.02257 0.00000 90023 0.98721 0.98721 0.01279 0.99310 0.00690 0.02257 0.97743 0.00000 024 0.98721 0.98721 0.01279 0.99310 0.00690 0.02257 0.02257 0.00000 025 0.98721 0.98721 0.01279 0.00690 0.99310 0.97743 0.97743 0.00008 120026 0.98721 0.98721 0.01279 0.00690 0.99310 0.97743 0.02257 0.00000 60027 0.98721 0.98721 0.01279 0.00690 0.99310 0.02257 0.97743 0.00000 60028 0.98721 0.98721 0.01279 0.00690 0.99310 0.02257 0.02257 0.00000 029 0.98721 0.98721 0.01279 0.00690 0.00690 0.97743 0.97743 0.00000 60030 0.98721 0.98721 0.01279 0.00690 0.00690 0.97743 0.02257 0.00000 60031 0.98721 0.98721 0.01279 0.00690 0.00690 0.02257 0.97743 0.00000 032 0.98721 0.98721 0.01279 0.00690 0.00690 0.02257 0.02257 0.00000 033 0.98721 0.01279 0.98721 0.99310 0.99310 0.97743 0.97743 0.01174 120034 0.98721 0.01279 0.98721 0.99310 0.99310 0.97743 0.02257 0.00027 90035 0.98721 0.01279 0.98721 0.99310 0.99310 0.02257 0.97743 0.00027 90036 0.98721 0.01279 0.98721 0.99310 0.99310 0.02257 0.02257 0.00001 037 0.98721 0.01279 0.98721 0.99310 0.00690 0.97743 0.97743 0.00008 120038 0.98721 0.01279 0.98721 0.99310 0.00690 0.97743 0.02257 0.00000 60039 0.98721 0.01279 0.98721 0.99310 0.00690 0.02257 0.97743 0.00000 60040 0.98721 0.01279 0.98721 0.99310 0.00690 0.02257 0.02257 0.00000 041 0.98721 0.01279 0.98721 0.00690 0.99310 0.97743 0.97743 0.00008 120042 0.98721 0.01279 0.98721 0.00690 0.99310 0.97743 0.02257 0.00000 60043 0.98721 0.01279 0.98721 0.00690 0.99310 0.02257 0.97743 0.00000 60044 0.98721 0.01279 0.98721 0.00690 0.99310 0.02257 0.02257 0.00000 045 0.98721 0.01279 0.98721 0.00690 0.00690 0.97743 0.97743 0.00000 120046 0.98721 0.01279 0.98721 0.00690 0.00690 0.97743 0.02257 0.00000 60047 0.98721 0.01279 0.98721 0.00690 0.00690 0.02257 0.97743 0.00000 60048 0.98721 0.01279 0.98721 0.00690 0.00690 0.02257 0.02257 0.00000 049 0.98721 0.01279 0.01279 0.99310 0.99310 0.97743 0.97743 0.00015 60050 0.98721 0.01279 0.01279 0.99310 0.99310 0.97743 0.02257 0.00000 60051 0.98721 0.01279 0.01279 0.99310 0.99310 0.02257 0.97743 0.00000 60052 0.98721 0.01279 0.01279 0.99310 0.99310 0.02257 0.02257 0.00000 053 0.98721 0.01279 0.01279 0.99310 0.00690 0.97743 0.97743 0.00000 60054 0.98721 0.01279 0.01279 0.99310 0.00690 0.97743 0.02257 0.00000 60055 0.98721 0.01279 0.01279 0.99310 0.00690 0.02257 0.97743 0.00000 056 0.98721 0.01279 0.01279 0.99310 0.00690 0.02257 0.02257 0.00000 057 0.98721 0.01279 0.01279 0.00690 0.99310 0.97743 0.97743 0.00000 60058 0.98721 0.01279 0.01279 0.00690 0.99310 0.97743 0.02257 0.00000 60059 0.98721 0.01279 0.01279 0.00690 0.99310 0.02257 0.97743 0.00000 060 0.98721 0.01279 0.01279 0.00690 0.99310 0.02257 0.02257 0.00000 061 0.98721 0.01279 0.01279 0.00690 0.00690 0.97743 0.97743 0.00000 60062 0.98721 0.01279 0.01279 0.00690 0.00690 0.97743 0.02257 0.00000 60063 0.98721 0.01279 0.01279 0.00690 0.00690 0.02257 0.97743 0.00000 064 0.98721 0.01279 0.01279 0.00690 0.00690 0.02257 0.02257 0.00000 0

46

65 0.01279 0.98721 0.98721 0.99310 0.99310 0.97743 0.97743 0.01174 120066 0.01279 0.98721 0.98721 0.99310 0.99310 0.97743 0.02257 0.00027 90067 0.01279 0.98721 0.98721 0.99310 0.99310 0.02257 0.97743 0.00027 90068 0.01279 0.98721 0.98721 0.99310 0.99310 0.02257 0.02257 0.00001 069 0.01279 0.98721 0.98721 0.99310 0.00690 0.97743 0.97743 0.00008 120070 0.01279 0.98721 0.98721 0.99310 0.00690 0.97743 0.02257 0.00000 60071 0.01279 0.98721 0.98721 0.99310 0.00690 0.02257 0.97743 0.00000 60072 0.01279 0.98721 0.98721 0.99310 0.00690 0.02257 0.02257 0.00000 073 0.01279 0.98721 0.98721 0.00690 0.99310 0.97743 0.97743 0.00008 90074 0.01279 0.98721 0.98721 0.00690 0.99310 0.97743 0.02257 0.00000 075 0.01279 0.98721 0.98721 0.00690 0.99310 0.02257 0.97743 0.00000 90076 0.01279 0.98721 0.98721 0.00690 0.99310 0.02257 0.02257 0.00000 077 0.01279 0.98721 0.98721 0.00690 0.00690 0.97743 0.97743 0.00000 60078 0.01279 0.98721 0.98721 0.00690 0.00690 0.97743 0.02257 0.00000 079 0.01279 0.98721 0.98721 0.00690 0.00690 0.02257 0.97743 0.00000 60080 0.01279 0.98721 0.98721 0.00690 0.00690 0.02257 0.02257 0.00000 081 0.01279 0.98721 0.01279 0.99310 0.99310 0.97743 0.97743 0.00015 60082 0.01279 0.98721 0.01279 0.99310 0.99310 0.97743 0.02257 0.00000 60083 0.01279 0.98721 0.01279 0.99310 0.99310 0.02257 0.97743 0.00000 60084 0.01279 0.98721 0.01279 0.99310 0.99310 0.02257 0.02257 0.00000 085 0.01279 0.98721 0.01279 0.99310 0.00690 0.97743 0.97743 0.00000 60086 0.01279 0.98721 0.01279 0.99310 0.00690 0.97743 0.02257 0.00000 60087 0.01279 0.98721 0.01279 0.99310 0.00690 0.02257 0.97743 0.00000 088 0.01279 0.98721 0.01279 0.99310 0.00690 0.02257 0.02257 0.00000 089 0.01279 0.98721 0.01279 0.00690 0.99310 0.97743 0.97743 0.00000 60090 0.01279 0.98721 0.01279 0.00690 0.99310 0.97743 0.02257 0.00000 091 0.01279 0.98721 0.01279 0.00690 0.99310 0.02257 0.97743 0.00000 60092 0.01279 0.98721 0.01279 0.00690 0.99310 0.02257 0.02257 0.00000 093 0.01279 0.98721 0.01279 0.00690 0.00690 0.97743 0.97743 0.00000 094 0.01279 0.98721 0.01279 0.00690 0.00690 0.97743 0.02257 0.00000 095 0.01279 0.98721 0.01279 0.00690 0.00690 0.02257 0.97743 0.00000 096 0.01279 0.98721 0.01279 0.00690 0.00690 0.02257 0.02257 0.00000 097 0.01279 0.01279 0.98721 0.99310 0.99310 0.97743 0.97743 0.00015 60098 0.01279 0.01279 0.98721 0.99310 0.99310 0.97743 0.02257 0.00000 60099 0.01279 0.01279 0.98721 0.99310 0.99310 0.02257 0.97743 0.00000 600

100 0.01279 0.01279 0.98721 0.99310 0.99310 0.02257 0.02257 0.00000 0101 0.01279 0.01279 0.98721 0.99310 0.00690 0.97743 0.97743 0.00000 600102 0.01279 0.01279 0.98721 0.99310 0.00690 0.97743 0.02257 0.00000 0103 0.01279 0.01279 0.98721 0.99310 0.00690 0.02257 0.97743 0.00000 600104 0.01279 0.01279 0.98721 0.99310 0.00690 0.02257 0.02257 0.00000 0105 0.01279 0.01279 0.98721 0.00690 0.99310 0.97743 0.97743 0.00000 600106 0.01279 0.01279 0.98721 0.00690 0.99310 0.97743 0.02257 0.00000 0107 0.01279 0.01279 0.98721 0.00690 0.99310 0.02257 0.97743 0.00000 600108 0.01279 0.01279 0.98721 0.00690 0.99310 0.02257 0.02257 0.00000 0109 0.01279 0.01279 0.98721 0.00690 0.00690 0.97743 0.97743 0.00000 600110 0.01279 0.01279 0.98721 0.00690 0.00690 0.97743 0.02257 0.00000 0111 0.01279 0.01279 0.98721 0.00690 0.00690 0.02257 0.97743 0.00000 600112 0.01279 0.01279 0.98721 0.00690 0.00690 0.02257 0.02257 0.00000 0113 0.01279 0.01279 0.01279 0.99310 0.99310 0.97743 0.97743 0.00000 0114 0.01279 0.01279 0.01279 0.99310 0.99310 0.97743 0.02257 0.00000 0115 0.01279 0.01279 0.01279 0.99310 0.99310 0.02257 0.97743 0.00000 0116 0.01279 0.01279 0.01279 0.99310 0.99310 0.02257 0.02257 0.00000 0117 0.01279 0.01279 0.01279 0.99310 0.00690 0.97743 0.97743 0.00000 0118 0.01279 0.01279 0.01279 0.99310 0.00690 0.97743 0.02257 0.00000 0119 0.01279 0.01279 0.01279 0.99310 0.00690 0.02257 0.97743 0.00000 0120 0.01279 0.01279 0.01279 0.99310 0.00690 0.02257 0.02257 0.00000 0121 0.01279 0.01279 0.01279 0.00690 0.99310 0.97743 0.97743 0.00000 0122 0.01279 0.01279 0.01279 0.00690 0.99310 0.97743 0.02257 0.00000 0123 0.01279 0.01279 0.01279 0.00690 0.99310 0.02257 0.97743 0.00000 0124 0.01279 0.01279 0.01279 0.00690 0.99310 0.02257 0.02257 0.00000 0125 0.01279 0.01279 0.01279 0.00690 0.00690 0.97743 0.97743 0.00000 0126 0.01279 0.01279 0.01279 0.00690 0.00690 0.97743 0.02257 0.00000 0127 0.01279 0.01279 0.01279 0.00690 0.00690 0.02257 0.97743 0.00000 0128 0.01279 0.01279 0.01279 0.00690 0.00690 0.02257 0.02257 0.00000 0

47

Acronyms

HVDC - High Voltage Direct Current

VSC – Voltage Source Converter

LCC - Line Commutated Converter

ODIS - Offshore Development Information Statement

MMC – Multi-modular Converter

Subsystem 1 – Offshore System

Subsystem 2 – DC System

Subsystem 3 – Onshore System

MTTF – Mean time to failure

MTBF – Mean time between failures

MTTR – Mean time to repair

GIS – Gas Insulated Switchgear

DNV – Det Norske Veritas

XLPE – Cross Linked Polyethylene

SCOF – Self Contained Oil Filled

MTTAOP – Mean time to Access offshore platform

MOAT – Mean Offshore Access Time

MTPCT - Mean Time Performing Concurrent Tasks

Date post:	02-Jan-2017
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