CIGRE 2012
21, rue d’Artois, F-75008 PARIS
A3_202
http : //www.cigre.org
End of life estimation and optimisation of maintenance of HV switchgear
and GIS substations
A study based on probabilistic data analysis, diagnostic measurements
and service experience
C. NEUMANN, B. RUSEK
Amprion GmbH, Dortmund
claus.neumann@amprion.net
G. BALZER, I. JEROMIN
TU Darmstadt, Darmstadt
C. HILLE, A. SCHNETTLER
RWTH Aachen University, Aachen
Germany
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 measurements
can 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 outages (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 previous 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
1
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 are
important issues in this respect. This Paper deals with new methods and tools to support system operators in the
decision making process to find an optimal balance between costs reduction and supply quality. Service experience and diagnostic measurements can provide the basis for this assessment. Consequently, gas-insulated substations as well as conventional switchgears are under consideration.
Gas-insulated switchgear (GIS) technology was introduced in the late 1960th. Today GIS technology is available
for 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 substations (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 three
and four decades. Thus improvements in reliability, decrease in maintenance expenditure, reduction in switchgear dimensions and improvements in cost effectiveness could be obtained [1, 2, 3]. To achieve technical expertise 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 optimal application in terms of overall costs, for planned maintenance measures and unplanned outages (repair due
to failures) [4]. Enabling this strategy, a condition assessment has to be performed. The installation of onlinemonitoring 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 equipment ageing model. Historical minor failure records are analysed to predict their development and to derive the
current and future asset condition with a high degree of accuracy. Using maintenance protocols, calculated
failure 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 additional
monitoring.
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-profit
organisation of 17 German and Austrian grid operators. The failure data of up to four decades are stored and
accumulated at the Institute for Electrical Power Supply of the Technical University of Darmstadt. The data base
comprises about 350 substations and more than 2 560 bays of the 123 kV, 245 kV and 420 kV voltage levels. In
this paper the 123 kV and 420 kV data are analysed. Fig. 1 presents the 123 kV and 420 kV populations.
bays
bay years
75000
62 200
60000
1500
45000
1000
30000
500
15000
0
0
year
b)
200
185
bays
bay years
10 100
150
12000
9000
100
6000
50
3000
bay years
bays installed
2000
2 350
bays installed
2500
bay years
a)
0
0
year
Fig. 1: Number of installed bays and accumulated bay service years
a) 123 kV GIS population
b) 420 kV population
The first 123 kV substation was installed in 1967 and about 2 350 bays in total were installed in 2011. The
service 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.
2
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 reason
might 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 of
the components in question might be reasonable. If the complete installation is affected, the end of service live is
reached 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].
bay years, mean value per year
bay years, mean value for 3 years
bays, mean value for 3 years
bays, mean value per year
bays, mean value for 3 years
0,30
0,90
0,25
0,75
0,20
0,60
0,15
0,45
0,10
0,30
0,05
0,15
0,00
0,00
1971 1976 1981 1986 1991 1996 2001 2006 2011
123 kV
0,60
2,40
0,50
2,00
0,40
1,60
0,30
1,20
0,20
0,80
0,10
0,40
0,00
1981
1986
1991
420 kV
year
1996
2001
2006
Failure rate / 100 bays
bay years, mean value for 3 years
bays, mean value per year
Failure rate /100 bay years
bay years, mean value per year
Failure rate / 100 bays
Failure rate /100 bay years
First information of the service performance can be derived from the failure rate per year. In Fig. 2 the failure
rate in the respective service year is given related to the number of bay years and to the number of bays.
0,00
2011
year
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
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 after
installation 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 failure
rate, i. e. the outage rate due insulation failures has to be reflected. However, this diagram does not provide
information on the development of the insulation properties of the individual GIS installations in the course of
time. Therefore, the failure rate will be analysed in dependence of the faultless service time. That means, if a
dielectric failure in a GIS bay occurs in 11th year after putting into service, the faultless service time will be 10
years. This failure is related to the population of bays being in service for 11 years and more.
Failure rate /100 bay years
mean value of 3 years
0,08
0,06
0,04
0,02
0,00
mean value of 3 years
0,20
0,15
0,10
0,05
0,00
0
123 kV
mean value per year
mean value of 5 years
0,25
Failure rate /100 bay years
mean value per year
mean value of 5 years
0,10
5
10
15
20
25
service years
30
35
40
0
420 kV
5
10
15
20
25
30
service years
Fig. 3: Failure rates of 123 kV and 420 kV GIS installations depending on the faultless service time
The corresponding evaluation is presented in Fig. 3. The failure rates comprise the total 123 kV and 420 kV GIS
population 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 to
be 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.
3
2.2.2
Different GIS generations
mean
mean value
value
mean
mean value
value
0,10
0,10
per
per year
year
for 5
5 years
years
for
mean
for 3
3 years
years
mean value
value for
Failure
Failurerate
rate/100
/100bay
bayyears
years
Failure
Failurerate
rate/100
/100bay
bayyears
years
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 are
considered separately. The population in question amounts 700 bays and 3 750 bay years at the 123 kV level and
130 bays and about 800 bays years at the 420 kV level. The failure rate depending on the faultless service time is
presented in Fig. 4.
≤
≤ 1978
1978
0,08
0,08
0,06
0,06
0,04
0,04
0,02
0,02
per
per year
year
of
of 5
5 years
years
meanvalue
meanvalue of
of 3
3 years
years
≤
≤ 1988
1988
0,20
0,20
0,15
0,15
0,10
0,10
0,05
0,05
0,00
0,00
0,00
0,00
123 kV
123 kV
mean
mean value
value
mean
mean value
value
0,25
0,25
0
0
5
5
10
10
15
20
25
15
20
25
service
service years
years
30
30
35
35
40
40
0
0
5
5
10
10
420 kV
15
20
15
20
service years
years
service
25
25
30
30
Fig.
1989
respectively
depending
on the
Fig. 44 :: Failure
Failurerates
ratesofof123
123kV
kVand
and420
420kV
kVGIS
GISinstalled
installedbefore
before1979
1979orand
1989
respectively
depending
on the
faultless
service
time
faultless service time
The figure clearly indicates that teething faults mainly occurred at the first GIS generation. Furthermore, the
increase of failures after 20 or 15 years of service is also correlated to this GIS generation. It is of interest, if the
behaviour can also be observed at the generation installed after 1978 and 1988 respectively. A consideration of
the subsequent generations is given in Fig. 5.
0,30
mean value per year
mean value for 5 years
0,08
mean value for 3 years
Failure rate /100 bay years
Failure rate /100 bay years
0,10
0,06
> 1978
0,04
0,02
0
Fig. 5 :
meanvalue of 3 years
0,20
mean value of 5 years
0,15
> 1988
0,10
0,05
0,00
0,00
123 kV
mean value per year
0,25
5
10
15
20
service years
25
30
35
0
420 kV
5
10
15
20
service years
Failure rates of 123 kV and 420 kV GIS installed after 1978 or 1988 respectively depending on the
faultless service time
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 the
factory 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 the
second 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 was
investigated 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 and
B 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 20…25 service years and is rather pronounced.
At manufacture B an increasing failure rate after about 30…35 service years can also be stated, but less distinct
as at manufacture B.
4
0,030
mean value for 3 years, manufact. B
0,25
0,025
0,20
0,020
0,15
0,015
0,10
0,010
0,05
0,005
0,00
0,000
0
10
20
30
40
service years
Fig. 6 :
2.3
Failure rate/100 bay years
manufact. B
0,30
Failure rate /100 bay years
manufact. A
420 kV
mean value for 3 years, manufact. A
failure rate / 100 bay years
123 kV
mean value of 3 years, manuf. A
mean value of 3 years, manuf. B
0,30
0,25
0,20
0,15
0,10
0,05
0,00
0
5
10
15
20
service years
25
30
Failure rates of 123 kV and 420 kV GIS of different manufacture depending on the faultless service time
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 components 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 the
majority of failures are
busbar,
initiated in disconnectors or
busbar,
bus ducts
bus ducts
earthing switches. It can be
27%
32%
assumed that these failures
disconnecwere caused by particles
tors,
disconnecearth.
which were produced in the
tors,
instrument
switches
earth.
instrument
transform.
course of time by abrasion
33%
switches
transform.
21%
during switching operations.
46%
9%
At 123 kV GIS a definite
amount of failures are
Fig. 7 : Main origins of failures in 123 kV and 420 kV GIS
originated in instrument
transformers. 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 to
manufacture defect free bulky pieces of cast resin material. Thus, being in service for a certain period of time a
breakdown occurred in the cast material. Failures in bus bars or bus ducts are in the range of 30% and mainly
occurred in the vicinity of spacers.
123 kV
others, e. g.
circuit
breakers
14%
420 kV
others, e. g.
circuit
breakers
18%
These findings and the increase of failure rate after about 20 to 25 years should be taken into account at the
maintenance process [7]. Compartments containing disconnectors and/or earthing switches should be inspected
and cleaned after about 20 to 25 years, in particular those pieces of equipment with higher number of switching
operations. Beyond that epoxy resin insulated instrument transformers should be replaced by SF6 insulated
current 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 ducts
comprising 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 service
for nearly 40 years, to draw conclusions for operation of stations of same or similar type and to provide feedback
for the further development of GIS [8].
The investigations were carried out on two 123 kV GIS installed in the early 1970th which correspond to manufacture A and B respectively mentioned in chapter 2.2.3. These stations had to be dismounted, since the short
circuit current level had increased due to further grid extension and the existing short circuit strength and
switching 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, a
voltage withstand test and a visual inspection of selected parts and components.
5
3.1
Actual insulation conditions
In substation 1 the high
voltage tests were performed by means of an
encapsulated test transformer and for PD measurement the UHF method
was applied using mobile
window sensors [9]. In
substation 2 a resonant test
circuit was used for HV
testing and the PD measurements were carried by
means of the conventional
method using an encapsulated coupling capacitor for
coupling out the PD signals.
Both test setups are shown
in Fig. 8.
substation 1
substation 2
coupling
capacitor
encapsulated
test transformer
mobile UHF
window sensor
Fig. 8 :
resonance
reactor
Test setup for diagnostic measurements on two GIS of different
manufacture
Some findings are exemplified in the following:
a)
PD measurements of single
bays:
•
Substation 1: The PD inception
was smaller than the normal
service voltage of 63 kV, i.e. a
certain PD activity had to be
assumed
already
during
service. The PD pattern
recorded is given in Fig. 9 a.
•
bay 131
U= 63kV
UE= 55kV
UA= 32kV
Fig. 9 :
Substation 2: The PD inception
was smaller than the rated voltage of
123 kV, i.e. a certain PD activity had to be
assumed during earth fault conditions. The
PD pattern can be taken from Fig. 9 b.
In both cases the PD source was identified
in a epoxy cast resin voltage transformer.
b) PD measurements of busbars and feeders
up to the busbar disconnectors or line
disconnectors respectively:
a)
b)
PD pattern recorded during PD measurements of single bays
a) substation 1
b) substation 2
a)
Fig 10 :
b)
Exemplary PD patterns recorded in substation 1
a) particle on the insulator surface
b) void in an insulator
•
Substation 1: The PD inception voltage
was in the range between normal service
voltage of 72 kV and rated voltage of
123 kV. The exemplarily presented PD
patterns in Fig. 10 give evidence to particles on the surface of an insulator
(Fig. 10 a) and to a void in an insulator
(Fig. 10 b).
•
a)
b)
Substation 2: The PD inception voltage
occurred in the range of the rated voltage
Fig 11 : Exemplary PD patterns recorded in substation 1
of 123 kV. The exemplary PD patterns in
a) small fixed particle on the conductor
Fig. 11 probably indicate a small fixed
b) void in an insulator
particle on the conductor (Fig. 11 a) and
a void in an insulator (Fig. 11b). The latter one was exited after several minutes at a voltage of 110 kV.
•
6
c)
Withstand voltage tests:
•
Substation 1: The rated power frequency withstand voltage was not fulfilled. Various flashovers and
disruptive 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 be
appropriate.
3.2 Visual inspection and main findings
The visual inspection was particularly conducted on those sections and compartments of the GIS where flashovers 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 is
shown in Fig. 12. Furthermore, traces of discharges were identified on
some disconnector insulators. Due to low SF6 pressure of 1 bar overpressure only, the electrical field stress control of the apparatus is mainly
made by means of cast resin material.
At substation 2 no indications of defective components could be discovered. Most of the parts were found in mint conditions. Only some few particles were detected in some disconnector and earthing switch compartments.
horizontally arranged disc insulator
Fig. 12 : Flashover on a horizontally arranged insulator
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 GIS
stations of similar design:
•
Substation 1: The residual lifetime seems to be exploited. If nevertheless a further operation of the
substation 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 SF6 pressure 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 of
field stress control by cast resin material. Those combined insulating arrangements are more sensitive to particles
and PD than purely gas-insulated arrangements.
•
Substation 2: Residual lifetime is available and can be utilized. Some smaller maintenance activities should
be 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 strength
and with this a better long-term performance. To ensure the reliability a replacement of the cast epoxy resin
voltage transformers and a PD measurement after a service period of 25…30 years would be recommended.
4
Comparison of outcome of diagnostic measurements and analysis of service
experience
4.1 Main conclusions
The insulation performance based on dielectric failures is strongly dependent on the GIS manufacture. This
outcome 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 35…40 years. The increasing
failure rate as well as the insufficient voltage strength and PD activities at normal service voltage indicate the
end 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
7
insulation performance is also confirmed by the diagnostic measurements which have demonstrated a
satisfactory 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 from
disconnectors, 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 hitherto
acceptable reliability, if some few measures for lifetime extension are introduced:
ƒ
ƒ
ƒ
Replacement of cast resin insulated voltage transformer, if any, by SF6 film 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 the
service 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:
ƒ
ƒ
ƒ
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: SF6 film insulated voltage transformers are applied in all voltages ranges instead
of epoxy cast resin transformer, the insulating bodies of which required an technological standard not
available 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 the
accumulation of particles on the insulator surface (Fig. 13 c).
b)
c)
no horizontal insulators
a)
particle trap
ribs
Fig. 13 : Design improvements of modern GIS
5
a) disconnectors, b) voltage transformers, c) insulators
Comparison with results of the 3rd CIGRE inquiry
The 3rd CIGRE inquiry contains a comprehensive collection of various GIS reliability data [11]. Data related to
dielectric failures can be deduced from the results of the inquiry. These are compared with the findings based on
the database of the before mentioned GIS Userforum. Since the CIGRE inquiry does not distinguish the dielectric failures in the different voltage classes, an average value for the manufacturing period in question is taken
from for this consideration.
Table 1: Failures rates according to the 3rd CIGRE inquiry and the GIS Userforum data
manufacturing period
100 200 kV
CIGRE ,
3rd inquiry
300 500 kV
GIS
Userforum
123 kV
420 kV
MaF, per per 100 bay years
thereof dielectric failures
dielectric failures,
per 100 bay years
MaF, per 100 bay years
thereof dielectric failures
dielectric failures,
per 100 bay years
dielectric failures,
per 100 bay years
dielectric failures,
per 100 bay years
2.0
16%
19791983
1.25
18%
19841988
0.65
14%
19891993
0.125
8%
19941998
0.15
38%
19992003
0.1
46%
0.32
0.22
0.09
0.01
0.06
0.05
0.23
4.0
16%
2.0
18%
1.3
14%
0.6
8%
0.4
38%
0.3
46%
0.55
75%
0.64
0.35
0.18
0.05
0.15
0.14
0.41
<1979
0.2
0.04
0.0
0.11
0.05
20042007
0.3
75%
0.0
0.09
8
Table 1 reveals
r
that thhe failures ratees in both stattistics exhibitt a decreasing tendency forr the different manufacturing perriods. Only thhe last manufaacturing periodd in the CIGR
RE statistics faaces a slightlyy increasing faailure rate.
These finndings as welll as the outcom
me of Fig. 4 and
a Fig. 5 dem
monstrate thatt the manufaccturers have utilised
u
the
return off experience to
t improve thhe design, maanufacturing processes
p
and quality assurrances measu
ures in the
factory annd onsite.
Table 2 : Failure frequency of GIS
S componentss
CIGRE ,
y
3rd inquiry
100 - 200 kV
V
300 - 500 kV
V
GIS
m
Userforum
123 kV
420 kV
Bus bars,
b
bus ducts
d
27
7%
17
7%
32
2%
27
7%
com
mponents
disconnec
ctors,
earthing sw
witches
42%
27%
c
circuit
breakers
27%
50%
14%
18%
33%
46%
in
nstrument
tra
ansformers
4%
6%
21%
9%
Table 2 presents the failure frequuency related to the comp
ponents invollved, i. e. buus bars and bus ducts
respectively, disconnecctors and earthhing switchess, circuit break
kers and instruument transforrmers. This taable points
out that disconnectors
d
and earthing switches disttinctly affect the
t performannce of GIS. It also illustratees that the
high failuure rate of insstrument transformers is not a general prroblem, but more
m
or less typpical for the instrument
i
transform
mer technologyy considered at the GIS Usserforum. Theerefore the reccommendations given in ch
hapter 4.2
are partlyy valid for GIS
S in general, but
b partly applly only for GIS of particularr design.
6
Proobabilistic data analyssis of high and extra high
h
voltagge equipment
A databaase, containingg informationn about 45,0000 high- and extra
e
high-volltage switchgeears, was sub
bject to an
probabilistic data analyysis. Using 8,000 digitaliseed maintenancce protocols annd the experieence and failu
ure records
of approxx. 830,000 assset service yeaars, type specific failure ratees were calcullated.
Fig. 14 exxemplarily sh
hows the
results of a major failuree rate calculation forr some circuitt breakers.
The resultiing mathemaatical correlation is - as expected
d - a bathtub shapedd exponentiall function
[12].
Many decissions are justt based on
failure ratte calculatio
ons even
though theey only tak
ke failure
frequency and service year into
account. Duue to liberalissation and
Fig. 14 : Failure rate of circuit breaakers
increased cost pressurre, many
utilities are
a in the proccess to reduce maintenance costs. This might
m
lead to inncreased failuure rates and thus
t
lower
grid reliabbility. A new parameter is needed
n
to asseess the impactt on maintenannce measures on the grid reeliability.
Since thee (n-1)-criteriaa ensures a higgh level of reddundancy in trransmission syystems, failurees do not alwaays lead to
interruptiion of supply but to a certtain reliabilityy. The reliabillity of these systems
s
is not only based on failure
frequencyy. The combinnation of failuure frequencyy and duration
n is important in this case. A higher timee-to-repair
(TTR) as well as an inccreased failuree rate lead to reduced
r
grid reliability.
r
TTR havee been recorded to get repaair times for sppecific failures. Depending on the failuree cause these times
t
vary
between 0,5h
0
and 48h. If now each major
m
failure is
i weighted with
w its TTR, thhe failure ratees develop to an
a average
failure dependent
d
unaavailability raate (FU-rate)). The results of this calculation are type-specificc average
unavailabillities per serv
vice year.
This param
meter can be expressed
in “percentt” or “minutess per year”
to give a better feelin
ng for the
average duuration. Fig. 15 shows
the resultinng curves.
In compariison to the faiilure rates,
these FU
U-rates deveelop into
purely expponential functions, as
failures havve a shorter repair time
due to teethhing problemss.
Fig. 15 : FU-rate of circuit
c
breakerrs
9
The stronng increase inn unavailabilitty after about 30 years of service
s
for thee 245 kV pufffer-type circu
uit breaker
indicates,, that occurredd failures in thhis case are more
m
severe an
nd have a longger time-to-reppair. With reg
gard to the
failure raates, this circuuit-breaker waas on an average level. Looking at its FU-rate,
F
this nnew parameteer contains
more infoormation abouut the system
m reliability – frequency an
nd duration off failures – annd thus proviides better
informatiion for a replaacement decission. In total, the
t FU-rate of circuit-breakkers is about five to ten tim
mes higher
than the one
o of disconnnectors, instruument transforrmers or surgee arresters.
Using a minimal-cut-s
m
set method andd secondary conditions
c
likee safety aspeccts, calculationns of unavailaability can
be extendded to entire bays in subsstations. The usual proced
dure in AIS-suubstations is mixing switcchgears of
different manufacturerrs and varied manufacturing years to ensure low risk of series-faullts. Fig. 16 prresents the
FU-rate of
o two 220 kV
V bays (201, 202)
2
and two 380 kV bays (401, 404) in a station conssisting of a 22
20 kV and
380 kV suubstation.
Due to diversse installation years, the
course of the function
n is not
t graphs
exponential. The steps in the
appear in those yearss, where
replacementss have taken place. In
this case ann old switch
hgear was
replaced by a new one witth a lower
FU-rate.
The calculatiion results dissplayed in
Fig. 16 demoonstrate that the
t choice
of switchgearr and manufaacturer can
Fig. 16 : Average failure dependennt unavailabiliity rate of bay
ys in
be importantt in terms off unavailsubstations
ability. Evenn though bay
y 401 and
402 havee the same settup – except from
f
one surgge arrester – their
t
FU-ratess differ by appprox. 100 perrcent. This
draws atttention to a deependency on the manufactuurer. Addition
nal investigatioons for the 2220 kV substatiion lead to
the concllusion, that a triple
t
busbar is
i not the bestt choice regarrding the reliaability. A doubble busbar witth transfer
busbar is more reliablee in this case.
7
Moodel for asssessment an
nd predictioon of maintenance neecessity
Many utilities are curreently searchinng for new posssibilities to reeduce maintennance costs [113]. The new Cigré
C
WG
B3.32 is also dealing with
w this topic. In theory, condition
c
based maintenannce should be the most costt-effective
strategy. Still many uttilities don’t apply
a
it yet. The
T biggest ch
hallenge is thee trade-off bettween the effo
ort of data
acquisitioon for conditioon assessmennt and the effoort of a mainteenance measuure itself. Onliine-monitorin
ng systems
can proviide easy data access and constant
c
superrvision enabliing a continuoous conditionn assessment. But these
systems are expensivee and might be source off failures theemselves. Forr most assets – except fro
om power
transform
mers – an onlinne monitoringg system is nott an economiccal alternative..
A usable but of coursee not perfect alternative
a
couuld be the preediction of maaintenance necessity based on expert
knowledgge and all available data of switchgears. Starting pointt is a general condition
c
asseessment modeel which is
applicable for all typess of assets. Inn this case the asset conditio
on is the degrree of ability oof each grid component
c
f
for which
w
it was created.
c
to run thee function or functions
Each asseet is regarded as a multi-staage unit [14], whereas
w
the highest stage iss represented bby the equipm
ment itself,
the seconnd stage is described by itss primary funcctions - accorrding to Cigréé WG C1.1 [115]- and the third
t
stage
conssists of the single componeents of an
equiipment. In caase of a circu
uit breaker
for example thee drive or the
t
highvoltaage insulationn.
Eachh component has several parameters
p
that ensure its functionalitty. These
paraameters can e.g. be the hydraulic
presssure or thee SF6-pressurre. These
paraameters are uusually checked during
mainntenance activities. Fig. 17 shows
the principle.
p
Usinng the model shown in Fiig. 17, the
conddition assessm
ment can now
w be perform
med in differeent ways. Fuzzzy logic,
Fig. 17 : Condition assessment
a
moodel for high voltage
v
equipm
ment
10
artificial neural
n
networrks or weighteed summationn are possible methods.
m
In all
a cases, the w
weighting of all
a relevant
parameters, componennts and functioons is a criticall aspect. At th
his point, expeert knowledge is needed.
To ensuure that the knowledge (in this casee:
Weightinng) is integratted as intendeed, simulationns
with diff
fferent failuree scenarios (in this casee:
Parameteer variations) can be donne to analysse
whether the
t equipmentt condition results in what it
is desiredd to be. If it iss incorrect, thhis procedure is
i
done recursively whhile adopting the singlle
weights. This process should be continued durinng
the lifetim
me of the eqquipment as knowledge
k
annd
experiencce change oveer time.
Step 1
Step 2
• Setup of cond
dition assessme
ent model (fig. 17)
• Weighting of parameters
p
by using expert knowledge
• Simulation of known failure scenarios and comparison with desired outtcome
Step 3
• Check and ado
option of weigh
hting factors
Step 4
• Derivation of maintenance necessity
n
includ
ding
condition and importance
Fig. 19 : Derivation of
o maintenancce necessity
condition
In case off the investigaations for this paper, the coondition assesssment was donne with weighhted summatio
on and the
weights were
w
found byy a pairwise comparison.
c
S
Starting
with the parameterrs, the servicee personnel were
w
asked
component-wise if onne parameter is more impportant for th
hat componennt than anothher. Doing th
his for all
parameters of a compoonent deliverss the ranking of the parameeters for a cerrtain componeent. If this is performed
p
for all coomponents, the weighting of
o parameters is complete and
a the weighhts can be norrmalized. Afteer that the
proceduree has to be reppeated for thee functions annd
the equippment type itseelf.
importa
ance
Fig. 18 : Derivationn of maintenannce necessity using
u
a
condition-iimportance diiagram [16]
For the deriivation of the maintenance necessity,
the known methods
m
are aapplicable. In this case,
a conditionn-importance diagram was used, as
shown in Fiig. 18. The im
mportance of each
e
asset
derives from
m the importannce of the sub
bstation in
which it is innstalled.
Doing this, the maintennance necessitty can be
derived in a four step method as shown in
Fig. 19. Baased on diigitalised maaintenance
protocols off the past ten years, the maaintenance
necessity was
w calculatedd for 123 kV
k circuit
breakers acccording to Figg. 19.
r
leads too the conclusion, that mainttenance measuures in the passt have not alw
ways been
An assesssment of the results
performed with regard to the newly derived mainttenance necesssity.
Fig. 20 : Maintenance necessity, perrformed and desired
d
order of
o maintenancce
Fig. 20 leeft shows thee maintenancee necessity off circuit break
kers and the order
o
in whicch measures have
h
been
performed in the pastt. It is obvioous, that this order has no
ot been optim
mal with regaard to the maaintenance
necessityy.
This is mainly
m
a result of two factorss:
•
T importancce of installedd equipment has
The
h not alwayss been taken innto account inn the past.
•
Mainly a cycllic maintenancce strategy waas performed. Thus the equiipment condittion has not always
M
b
been
taken intto account.
The diagrram on the rigght side displaays the order inn which the measures
m
shoulld have been pperformed.
11
8
Conclusions
Focussing on the insulation performance a service life of 50 years for GIS of the first and second generation is
achievable for GIS with hitherto acceptable reliability. This is the outcome from the statistics of the GIS
Usergroup and also confirmed by diagnostic measurements. However, some special maintenance measures
should be carried out to obtain a satisfactory reliability also in future. Among others a replacement of cast resin
insulated voltage transformer, if any, by SF6 film insulated transformers, a supervision of disconnectors and
earthing switches with regard particles and contamination and a surveillance of the insulation properties by PD
measurements by periodic checks is recommended.
For newer GIS generations a better service performance can be derived from the statistics. Although the basis is
different, the findings of the 3rd inquiry of CIGRE WG A3.06 show a similar tendency. Consequently it can be
expected that the service life should be longer. A lot failures observed at the first GIS generations does not exist
with 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 into
account, e.g. wear and mechanical performance of the switching equipment, which can also limit the lifetime of
GIS.
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 when
maintenance activities are required and allows a better measure prioritization. The new developed average failure
dependent 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 SF6
Gas Insulated Substations (GIS). Paper 23 -101, CIGRE Paris 1992
[2] I.M. Welch, C. J. Jones, D. Kopejtkova, S. Kobayashi, T. Moloni, P. O’Connell : 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 condition
based maintenance. Paper A3-305, CIGRE Session 2004
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[6] CIGRE Task Force 15.03.07, Long-term performance of SF6 insulated systems’, Paper 15-301, CIGRE
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[10] C. Neumann, B. Krampe, R. Feger, K. Feser, M. Knapp, A. Breuer, V. Rees: PD measurements on GIS of
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CIGRE-Report A3-103, 2010
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12