Life Cycle of GIS

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End of li fe estimation and optimisation of maintenance of HVswitchgearand GIS substations

A study based on probabilistic data analysis, diagnostic measurementsand service experience

SUMMARY

Efficiency is an important driving force for network operators in the field of operative asset

management. Hence, condition and lifetime considerations as well as reflection of the effect of

preventive maintenance are important issues with this respect. In this Paper new methods and tools are

presented for support of the network operator in the decision making process to find an optimal

balance between costs reduction and supply quality. Service experience and diagnostic measurementscan provide the basis for this assessment. With this respect gas-insulated substations as well as

conventional switchgear are subject to investigations.

With a view to GIS the objective of this paper is to analyse the service experience gained during more

than four decades with particular regard to dielectric failures and to assess the residual life based on

mentioned analysis and on additional diagnostic measurements after nearly 40 years service time.

The conclusions from the investigations are as follows: With respect to the insulation performance a

service life of 50 years for GIS of the first and second generation is achievable, if some few measures

for lifetime extension are introduced. The modern GIS generation seems to be more reliable as the first

and second generation since certain deficiencies were overcome by design improvements, application

of better material and advanced manufacturing technology. The results of the inquiry of CIGRE WG

A3.06 show a similar tendency.

With regard to conventional switchgear a condition based maintenance strategy is regarded as an

optimal application in terms of overall costs, for planned maintenance measures and unplanned out-

ages (repair). Enabling this strategy, a condition assessment has to be performed. By application of

sophisticated methods like probabilistic data analysis the optimal maintenance can be obtained.

Starting point is a general condition assessment model which is applicable for all assets. In the

following, the asset condition is the degree of ability of each grid component to run the function or

functions for which it is created without any major failures. The model considers the results of previ-

ous service periods combined with the damage occurrences of other assets of the same type. To predict

future damage occurrences and to avoid that by adequate maintenance is the main aim in this content.

KEYWORDS

HV switchgear, GIS substation, end of life, maintenance, diagnostic measurements, service

experience, probabilistic data analysis

C. NEUMANN, B. RUSEK

Amprion GmbH, [email protected]

G. BALZER, I. JEROMIN

TU Darmstadt, Darmstadt

C. HILLE, A. SCHNETTLERRWTH Aachen University, Aachen

Germany

21, rue dArtois, F-75008 PARIS CIGRE 2012

http : //www.cigre.org A3_202


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1 Introduction

Efficiency is an important driving force for power system operators in the field of operative asset management.Hence, condition and lifetime considerations as well as reflection of the effect of preventive maintenance areimportant issues in this respect. This Paper deals with new methods and tools to support system operators in thedecision making process to find an optimal balance between costs reduction and supply quality. Service experi-ence and diagnostic measurements can provide the basis for this assessment. Consequently, gas-insulated sub-

stations as well as conventional switchgears are under consideration.

Gas-insulated switchgear (GIS) technology was introduced in the late 1960th. Today GIS technology is availablefor all voltage ranges up to the UHV range. GIS is characterised by high service reliability, low maintenance

expenditure and long lifetime. GIS technology requires more investment costs compared to air-insulated sub-stations (AIS), however, due to its space saving features this technology often offers the only solution, if the

constructive surface available is small. The technology was continuously developed further during the last threeand four decades. Thus improvements in reliability, decrease in maintenance expenditure, reduction in switch-gear dimensions and improvements in cost effectiveness could be obtained [1, 2, 3]. To achieve technical exper-tise on the life performance of the GIS technology over this period of time, the GIS service experience of a group

of grid operators (GIS Userforum) is analysed, in particular with special regard to dielectric failures.

Regarding conventional switchgear a condition based maintenance strategy is generally considered as the opti-

mal application in terms of overall costs, for planned maintenance measures and unplanned outages (repair dueto failures) [4]. Enabling this strategy, a condition assessment has to be performed. The installation of online-monitoring systems is not economical for all types of assets. If a probabilistic data analysis is applied, a data

driven condition based maintenance strategy can be derived. The core of this method is the usage of an equip-ment ageing model. Historical minor failure records are analysed to predict their development and to derive thecurrent and future asset condition with a high degree of accuracy. Using maintenance protocols, calculatedfailure rates and additional general information of assets, the application of a sophisticated statistical approach in

terms of cluster and trend analysis enables an optimised setting of future measure dates without additionalmonitoring.

2 Analysis of the service experience with GIS over four decades

2.1 GIS population under consideration

The service experience under consideration has been collected by the GIS Userforum which is a non-profitorganisation of 17 German and Austrian grid operators. The failure data of up to four decades are stored andaccumulated at the Institute for Electrical Power Supply of the Technical University of Darmstadt. The data basecomprises about 350 substations and more than 2 560 bays of the 123 kV, 245 kV and 420 kV voltage levels. Inthis paper the 123 kV and 420 kV data are analysed. Fig. 1 presents the 123 kV and 420 kV populations.

The first 123 kV substation was installed in 1967 and about 2 350 bays in total were installed in 2011. Theservice experience collected is related to about 62 200 bay years.At 420 kV the first substation in GIS technology was erected in 1977. Until 2011 nearly 200 bays were installed.

The service experience gained up to now amounts to more than 10 000 bay years.

Fig. 1: Number of installed bays and accumulated bay service years

a) 123 kV GIS population b) 420 kV population

0

15000

30000

45000

60000

75000

0

500

1000

1500

2000

2500

bay

years

bays

installed

year

bays

bay years

2 350

62 200

0

3000

6000

9000

12000

0

50

100

150

200

bay

years

bays

installed

year

bays

bay years

185

10 100

a) b)


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2.2 Dielectric failures depending on service time

2.2.1 Total Population

Dielectric failures are caused due to insufficient insulating strength [5]. Failures in the early stage of operation,so called teething faults, are mostly a sign of a lacking dielectric integrity when putting into service. The reasonmight be a inadequate commissioning procedure. An increasing failure rate during the operating time indicates

ageing processes at certain components or at the installation in general. In case of components a replacement ofthe components in question might be reasonable. If the complete installation is affected, the end of service live isreached and the system has to be renewed. Therefore the failure rate is an important indication of the service

performance of a system like GIS [6].

First information of the service performance can be derived from the failure rate per year. In Fig. 2 the failurerate in the respective service year is given related to the number of bay years and to the number of bays.

It can be seen that the failure rate distinctly decreases in the course of time at which the failure rates of 123 kV

GIS and 420 kV GIS are similar. After introduction of GIS technology a lot of teething faults obviously occurred

to be seen in particular at 123 kV GIS. A second increase of failures can be detected after 15 up 20 years afterinstallation of the first GIS. The reason for that will be analysed later.

The presentation in Fig. 2 is suited for consideration of insulation coordination issues where the yearly failurerate, i. e. the outage rate due insulation failures has to be reflected. However, this diagram does not provideinformation on the development of the insulation properties of the individual GIS installations in the course oftime. Therefore, the failure rate will be analysed in dependence of the faultless service time. That means, if adielectric failure in a GIS bay occurs in 11thyear after putting into service, the faultless service time will be 10years. This failure is related to the population of bays being in service for 11 years and more.

The corresponding evaluation is presented in Fig. 3. The failure rates comprise the total 123 kV and 420 kV GISpopulation respectively, i. e. all manufactures are taken into account. In average the failure rate of 123 kV

population amounts half of that of the 420 kV population. In both populations an increase of the failure rate is tobe observed after about 20 or 15 years respectively. A second increase is to be seen at 123 kV population after

about 30 years. That might indicate certain ageing effects which reasons have still to be clarified.

Fig. 2: Failure rates of 123 kV and 420 kV GIS in the different service years related to bay years or number of

bays installed

0,00

0,15

0,30

0,45

0,60

0,75

0,90

0,00

0,05

0,10

0,15

0,20

0,25

0,30

1971 1976 1981 1986 1991 1996 2001 2006 2011

Failurerate/

100bays

Failurerate/10

0bayyears

year

bay years, mean value per year bay years, mean value for 3 years

bays, mean value per year bays, mean value for 3 years

0,00

0,40

0,80

1,20

1,60

2,00

2,40

0,00

0,10

0,20

0,30

0,40

0,50

0,60

1981 1986 1991 1996 2001 2006 2011

Failurerate/

100bays

Failurerate/10

0bayyears

year

bay years, mean value per year bay years, mean value for 3 years

bays, mean value per year bays, mean value for 3 years

123 kV 420 kV

Fig. 3: Failure rates of 123 kV and 420 kV GIS installations depending on the faultless service time

0,00

0,02

0,04

0,06

0,08

0,10

0 5 10 15 20 25 30 35 40

Failurerate/100ba

yyears

service years

mean value per year mean value of 3 years

mean value of 5 years

0,00

0,05

0,10

0,15

0,20

0,25

0 5 10 15 20 25 30

Failurerate/100ba

yyears

service years

mean value per year mean value of 3 years


123 kV 420 kV


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2.2.2 Different GIS generations

As to be seen from Fig. 2, the first GIS installations obviously exhibit some teething faults. Therefore the first

generation of GIS technology up to 1978 regarding 123 kV GIS and up to 1988 regarding 420 kV GIS areconsidered separately. The population in question amounts 700 bays and 3 750 bay years at the 123 kV level and130 bays and about 800 bays years at the 420 kV level. The failure rate depending on the faultless service time ispresented in Fig. 4.

The figure clearly indicates that teething faults mainly occurred at the first GIS generation. Furthermore, theincrease of failures after 20 or 15 years of service is also correlated to this GIS generation. It is of interest, if thebehaviour can also be observed at the generation installed after 1978 and 1988 respectively. A consideration ofthe subsequent generations is given in Fig. 5.

Fig. 5 does not indicate a performance comparable to that given in Fig. 4 for the first GIS generation. It points

out that the reliability of the GIS generations installed after 1978 or 1988 respectively is much better. Obviously

the teething faults could significantly be reduced by increasing the design, the quality assurance measures in thefactory and onsite. Also the distinct increase of the failure rate after a certain service period cannot be noticed.However, it should be observed, if this tendency is also confirmed in future with increasing service time of thesecond and following GIS generations.

2.2.3 Different GIS manufactures

From practical experience it is known that some GIS manufactures are more reliable than others. This issue wasinvestigated more in details by means of the data collected. Five different 123 kV and three different 420 kV

manufactures could be considered. The results for two manufactures in each case can be taken from Fig. 6.

The outcome is that in particular at 123 kV a considerable deviation in failure rates between manufacture A andB can be stated (note the different scaling). The failure rate of manufacture A is nearly one order of magnitude

higher as of manufacture B. Both manufactures show an increase of the failure rate after a certain period of

operation. At manufacture A this increase takes place after about 2025 service years and is rather pronounced.At manufacture B an increasing failure rate after about 3035 service years can also be stated, but less distinctas at manufacture B.

Fig. 4 : Failure rates of 123 kV and 420 kV GIS installed before 1979 or 1989 respectively depending on thefaultless service time

0,00

0,02

0,04

0,06

0,08

0,10

0 5 10 15 20 25 30 35 40

Failurerate/100bayyears

service years

mean value per year mean value for 3 years

mean value for 5 years

1978

0,00

0,05

0,10

0,15

0,20

0,25

0 5 10 15 20 25 30

Failurer

ate/

100b

ayy

ears

service years

mean value per year meanvalue of 3 years


1988

123 kV

Fig. 5 : Failure rates of 123 kV and 420 kV GIS installed after 1978 or 1988 respectively depending on thefaultless service time

0,00

0,02

0,04

0,06

0,08

0,10

0 5 10 15 20 25 30 35

Failurer

ate/1

00b

ayy

ears

service years



> 1978

0,00

0,05

0,10

0,15

0,20

0,25

0,30

0 5 10 15 20

Failurerate/1

00bayyears

service years

mean value per year

meanvalue of 3 years


> 1988

123 kV 420 kV

420 kV

Fig. 4 : Failure rates of 123 kV and 420 kV GIS installed before 1979 and 1989 respectively depending on the

faultless service time

0,00

0,02

0,04

0,06

0,08

0,10

0 5 10 15 20 25 30 35 40


service years



1978

0,00

0,05

0,10

0,15

0,20

0,25

0 5 10 15 20 25 30

Failurer

ate/

100b

ayy

ears

service years

mean value per year meanvalue of 3 years


1988

123 kV 420 kV


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Fig. 7 : Main origins of failures in 123 kV and 420 kV GIS

others, e. g.circuit

breakers14%

disconnec-tors,earth.

switches33%

instrumenttransform.

21%

busbar,bus ducts

32%

others, e. g.circuit

breakers18%

disconnec-tors,

earth.switches

46%

instrumenttransform.

9%

busbar,bus ducts

27%

420 kV123 kV

2.3 Main failure cause and consequences for maintenance

As to be recognised from Fig. 3 and 4, after a certain period of service time some ageing phenomena cannot be

excluded, because an increase of the failure rate is observed. Therefore it is of interest to find out which compo-nents are the root cause for these failures and to analyse by which measures these failures can be avoided in

future. With this regard the failure data are analysed. Fig. 7 shows a breakdown of the main origins of failures.

Fig. 7 makes evident that themajority of failures are

initiated in disconnectors orearthing switches. It can beassumed that these failureswere caused by particleswhich were produced in thecourse of time by abrasion

during switching operations.At 123 kV GIS a definiteamount of failures areoriginated in instrumenttransformers. In the first

123 kV GIS generation voltage transformers and even current transformers were made in cast epoxy resin

technology. However, at that time the complete manufacturing process was not sufficiently developed tomanufacture defect free bulky pieces of cast resin material. Thus, being in service for a certain period of time abreakdown occurred in the cast material. Failures in bus bars or bus ducts are in the range of 30% and mainlyoccurred in the vicinity of spacers.

These findings and the increase of failure rate after about 20 to 25 years should be taken into account at themaintenance process [7]. Compartments containing disconnectors and/or earthing switches should be inspectedand cleaned after about 20 to 25 years, in particular those pieces of equipment with higher number of switchingoperations. Beyond that epoxy resin insulated instrument transformers should be replaced by SF6 insulatedcurrent transformers or SF6 and foil insulated voltage transformers respectively, as it is today common practice

in all voltage ranges. Further failure causes are particles adhering on the surface of spacers. Therefore, bus ductscomprising horizontally arranged spacers should be checked with this regard.

3 Diagnostic measurements after nearly 40 years of service

The aim of the diagnostic measurements was to determine the remaining life of GIS installations being servicefor nearly 40 years, to draw conclusions for operation of stations of same or similar type and to provide feedbackfor the further development of GIS [8].

The investigations were carried out on two 123 kV GIS installed in the early 1970thwhich correspond to manu-

facture A and B respectively mentioned in chapter 2.2.3. These stations had to be dismounted, since the shortcircuit current level had increased due to further grid extension and the existing short circuit strength andswitching capability was not sufficient enough. Improving the short circuit strength and switching capability of

the GIS in question turned out to be uneconomical.

The tests comprised PD measurements recording the PD inception and extinction voltage and the PD pattern, avoltage withstand test and a visual inspection of selected parts and components.

Fig. 6 : Failure rates of 123 kV and 420 kV GIS of different manufacture depending on the faultless service time

0,000

0,005

0,010

0,015

0,020

0,025

0,030

0,00

0,05

0,10

0,15

0,20

0,25

0,30

0 10 20 30 40


manufact.B


manufact.A

service years

mean value for 3 years, manufact. A

mean value for 3 years, manufact. B

0,00

0,05

0,10

0,15

0,20

0,25

0,30

0 5 10 15 20 25 30

failurer

ate/

100b

ayy

ears

service years

mean value of 3 years, manuf. A

mean value of 3 years, manuf. B

123 kV 420 kV


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Fig. 8 : Test setup for diagnostic measurements on two GIS of different

manufacture

encapsulated

test transformer

mobile UHF

window sensor

substation 1

resonance

reactor

coupling

capacitor

substation 2

Fig. 9 : PD pattern recorded during PD measurements of single baysa) substation 1 b) substation 2

U= 63kV

UE= 55kVUA= 32kV

bay131

ab)

Fig 10 : Exemplary PD patterns recorded in substation 1a) particle on the insulator surface

b void in an insulator

a) b)

Fig 11 : Exemplary PD patterns recorded in substation 1a) small fixed particle on the conductor

b) void in an insulator

a) b)

3.1 Actual insulation conditions

In substation 1 the highvoltage tests were per-formed by means of an

encapsulated test trans-former and for PD meas-urement the UHF methodwas applied using mobile

window sensors [9]. Insubstation 2 a resonant test

circuit was used for HVtesting and the PD meas-urements were carried bymeans of the conventional

method using an encapsu-lated coupling capacitor for

coupling out the PD signals.Both test setups are shownin Fig. 8.

Some findings are exemplified in the following:

a) PD measurements of singlebays:

Substation 1: The PD inception

was smaller than the normalservice voltage of 63 kV, i.e. acertain PD activity had to beassumed already duringservice. The PD patternrecorded is given in Fig. 9 a.

Substation 2: The PD inceptionwas smaller than the rated voltage of123 kV, i.e. a certain PD activity had to be

assumed during earth fault conditions. ThePD pattern can be taken from Fig. 9 b.

In both cases the PD source was identifiedin a epoxy cast resin voltage transformer.

b) PD measurements of busbars and feedersup to the busbar disconnectors or linedisconnectors respectively:

Substation 1: The PD inception voltagewas in the range between normal servicevoltage of 72 kV and rated voltage of123 kV. The exemplarily presented PDpatterns in Fig. 10 give evidence to parti-cles on the surface of an insulator

(Fig. 10 a) and to a void in an insulator(Fig. 10 b).

Substation 2: The PD inception voltageoccurred in the range of the rated voltageof 123 kV. The exemplary PD patterns in

Fig. 11 probably indicate a small fixed

particle on the conductor (Fig. 11 a) anda void in an insulator (Fig. 11b). The latter one was exited after several minutes at a voltage of 110 kV.


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Fig. 12 : Flashover on a horizon-tally arranged insulator

horizontally arranged disc insulator

c) Withstand voltage tests:

Substation 1: The rated power frequency withstand voltage was not fulfilled. Various flashovers anddisruptive discharges appeared even at voltages distinctly below the onsite test voltage of 184 kV. A voltage

breakdown could not have been excluded at the next overvoltage event.

Substation 2: The rated power frequency withstand voltage was approved. All parts of the GIS substation

passed the test voltage of 230 kV. The insulation condition of this GIS substation has seemed to beappropriate.

3.2 Visual inspection and main findings

The visual inspection was particularly conducted on those sections and compartments of the GIS where flash-overs during testing or dielectric failures had occurred in the past.

At substation 1 flashovers could be detected at different horizontally

mounted insulators of some vertical arranged bus ducts. An example isshown in Fig. 12. Furthermore, traces of discharges were identified on

some disconnector insulators. Due to low SF6 pressure of 1 bar over-pressure only, the electrical field stress control of the apparatus is mainlymade by means of cast resin material.

At substation 2 no indications of defective components could be discov-ered. Most of the parts were found in mint conditions. Only some few parti-cles were detected in some disconnector and earthing switch compartments.

3.3 Conclusions for lifetime assessment from the findings of visual inspection and HV testing

From the findings in chapter 3.1 and 3.2 the following conclusions can be dived for lifetime assessment of GISstations of similar design:

Substation 1: The residual lifetime seems to be exploited. If nevertheless a further operation of thesubstation in question is intended, a periodic PD measurement and identification of PD sources is

recommended. The main failure causes are:

Epoxy cast resin voltage transformers

Contamination of horizontally arranged disc insulators Disconnector insulation and field stress control by cast resin material

Due to the low SF6pressure and the basic design mainly oriented on the gaseous field strength of the cylindrical

arrangement the voltage strength of the other non-cylindrical arrangements is mainly achieved by application offield stress control by cast resin material. Those combined insulating arrangements are more sensitive to particlesand PD than purely gas-insulated arrangements.

Substation 2: Residual lifetime is available and can be utilized. Some smaller maintenance activities shouldbe carried out. Weak points are:

Epoxy cast resin voltage transformers

Particles in few disconnector compartments

The basic design of this GIS type is mostly based on the field strength of the gaseous insulation and cast resin

material is only used for support functions. Thus this design obviously offers some reserves in voltage strengthand with this a better long-term performance. To ensure the reliability a replacement of the cast epoxy resinvoltage transformers and a PD measurement after a service period of 2530 years would be recommended.

4 Comparison of outcome of diagnostic measurements and analysis of serviceexperience

4.1 Main conclusions

The insulation performance based on dielectric failures is strongly dependent on the GIS manufacture. Thisoutcome from the statics of the GIS Userforum is also proven by the findings from the diagnostic measurements.One GIS manufacture clearly shows ageing phenomena after service time of 3540 years. The increasingfailure rate as well as the insufficient voltage strength and PD activities at normal service voltage indicate theend of service life. The second GIS manufacture indeed reveals an increasing failure rate for a short time, but

after elimination of the deficiencies no indication of a distinct ageing effect can be observed. The appropriate


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Fig. 13 : Design improvements of modern GIS a) disconnectors, b) voltage transformers, c) insulators

insulation performance is also confirmed by the diagnostic measurements which have demonstrated asatisfactory voltage strength and no PD activities at normal service voltage.

Derived from the statistics as well as from the diagnostic investigations the main failures are originated fromdisconnectors, voltage transformers and horizontally arranged insulators in bus ducts affected by particles.

4.2 Consequences for lifetime assessment and lifetime extension and further development

A service life of 50 years for GIS of the first and second generation is readily achievable for GIS with hithertoacceptable reliability, if some few measures for lifetime extension are introduced:

Replacement of cast resin insulated voltage transformer, if any, by SF6film insulated transformer Supervision of disconnectors and earthing switches with regard particles and contamination Surveillance of the insulation properties by PD measurements by periodic checks

It can be expected that the service performance of the newer GIS generations will be better and consequently theservice life should be longer. A lot failures observed at the first GIS generations does not exist with modern GIS,since numerous design improvements were introduced. Some of them shall be quoted in the following:

Disconnector: The static and dynamic field stress is controlled by metal shielding electrodes thus

avoiding accumulation of cast resin material for stress control (Fig. 13 a).

Voltage transformer: SF6film insulated voltage transformers are applied in all voltages ranges insteadof epoxy cast resin transformer, the insulating bodies of which required an technological standard notavailable at the first GIS generations (Fig. 13 b).

Horizontally arranged insulators: Those insulators are avoided as far as possible. If necessary,

horizontally arranged insulators are fitted with ribs or particle traps. These measures prevent theaccumulation of particles on the insulator surface (Fig. 13 c).

5 Comparison with results of the 3rdCIGRE inquiry

The 3rdCIGRE inquiry contains a comprehensive collection of various GIS reliability data [11]. Data related todielectric failures can be deduced from the results of the inquiry. These are compared with the findings based onthe database of the before mentioned GIS Userforum. Since the CIGRE inquiry does not distinguish the dielec-tric failures in the different voltage classes, an average value for the manufacturing period in question is takenfrom for this consideration.

Table 1: Failures rates according to the 3rdCIGRE inquiry and the GIS Userforum data

manufacturing period


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11/12


12/12

12

8 Conclusions

Focussing on the insulation performance a service life of 50 years for GIS of the first and second generation isachievable for GIS with hitherto acceptable reliability. This is the outcome from the statistics of the GISUsergroup and also confirmed by diagnostic measurements. However, some special maintenance measuresshould be carried out to obtain a satisfactory reliability also in future. Among others a replacement of cast resininsulated voltage transformer, if any, by SF

6 film insulated transformers, a supervision of disconnectors and

earthing switches with regard particles and contamination and a surveillance of the insulation properties by PDmeasurements by periodic checks is recommended.For newer GIS generations a better service performance can be derived from the statistics. Although the basis isdifferent, the findings of the 3rdinquiry of CIGRE WG A3.06 show a similar tendency. Consequently it can beexpected that the service life should be longer. A lot failures observed at the first GIS generations does not existwith modern GIS, since numerous design improvements and quality assurance measurements during

manufacturing and onsite were introduced.When assessing the service life of GIS further criteria besides the insulation performance have to be taken intoaccount, e.g. wear and mechanical performance of the switching equipment, which can also limit the lifetime ofGIS.

In conventional substations a probabilistic data analysis of high and extra high voltage equipment can be used for

an optimisation and prioritization of the maintenance work. Based on expert knowledge a model for prediction of

future asset condition has been developed. This enables asset managers to determine the instant whenmaintenance activities are required and allows a better measure prioritization. The new developed average failuredependent unavailability rate (FU-rate) contains more information than a simple view on failure rates. It can

additionally be used in reliability calculations.

BIBLIOGRAPHY

[1] T. Moloni, D. Kopejtkova, S. Kobayashi, I. M. Welch : Twenty Five Year Review of Experience with SF6Gas Insulated Substations (GIS). Paper 23 -101, CIGRE Paris 1992

[2] I.M. Welch, C. J. Jones, D. Kopejtkova, S. Kobayashi, T. Moloni, P. OConnell : GIS in Service Experience and Recommendations. Paper 23 -104, CIGRE Paris 1994

[3] CIGRE WG 23.03: Report on the second international survey on high voltage gas insulated substations(GIS) service experience. CIGRE Brochure 150, Feb. 2000

[4]

G. Balzer, F. Heil, P. Kirchesch, R. Meister, C. Neumann: Evaluation of HV circuit-breakers for conditionbased maintenance. Paper A3-305, CIGRE Session 2004

[5] CIGRE Joint Working Group 33/23.12, Insulation coordination of GIS: Return of experience, on-site testsand diagnostic techniques, Electra 176, 1998

[6] CIGRE Task Force 15.03.07, Long-term performance of SF6 insulated systems, Paper 15-301, CIGRE

Session 2002[7] G. Balzer, D. Drescher, F. Heil, P. Kirchesch, R. Meister, C. Neumann: Selection of maintenance strategy

by analysis of service experience. CIGRE SC A3 and B3 Colloquium, Tokyo, 2005[8] K. Yoshii, K. Shimizu, T. Nakajima, M. Kamei, T. Kato, Y. Matsuyama: Monitoring and diagnostic

techniques for GIS/GCBs, Paper 123, CIGRE SC A3 and B3 Joint Colloquium, Tokyo, 2005[9] E. Gulski, et al. : Condition assessment and AM decision support for transmission network components,

Paper D1-110, CIGRE Session 2006[10]C. Neumann, B. Krampe, R. Feger, K. Feser, M. Knapp, A. Breuer, V. Rees: PD measurements on GIS of

different designs by non-conventional UHF sensors. CIGRE-Report 15-305, 2000[11]D. Kopejtkova, H. Furuta, M. Kudoke: Gas insulated switchgear reliability, gas insulated switchgear

practices. TB part 5 & 6 of CIGRE WG A3-06, Technical Tutorial CIGRE SC A3, September 2011, Vienna[12]S. Federlein, C. Hille, A. Gaul, A. Schnettler : New methods to assess the impact of maintenance and the

condition of network, CIRED 2009, Session 1, No. 870, Prague, 2009[13]C. Neumann, B. Rusek, C. Schorn, S. Federlein, A. Schnettler, G. Balzer, T. Krontiris: Modelling the effect

of maintenance on failure occurrence and lifetime management of high voltage circuit breakers.CIGRE-Report A3-103, 2010

[14]G. Balzer, D. Drescher, F. Heil, P. Kirchesch, R. Meister, C. Neumann : Evaluation of failure data of h.v.circuit breakers for condition based maintenance. 15th Conference on Electric Power Supply Industry

CEPSI, Shanghai, 2004[15]CIGRE Working Group C1.1, Asset Management of Transmission Systems and Associated CIGRE

Activities, Brochure 309, 2006

[16]

G. Balzer, T. Orlowska, C. Neumann, M. Halfmann, A. Strnad: Life cycle management of circuit-breakersby application of reliability centered maintenance, Paper 13-177, CIGRE Session 2002

Life Cycle of GIS

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