21, rue d’Artois, F-75008 PARIS
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B3-206
CIGRE 2012
ENHANCEMENT OF SUBSTATION RELIABILITY BY RETROFITTING
EXISTING BUS CONFIGURATION APPLYING HYBRID SWITCHGEAR
S. CHAREONSRIKASEM*
K. ANANTAVANICH
S. PRUNGKHWUNMUANG
Electricity Generating Authority of
Thailand (EGAT)
T. SUWANASRI
King Mongkut’s University of
Technology North Bangkok (KMUTNB)
Thailand
SUMMARY
The electric power demand in Thailand has continuously increased. Hence it is essential for the
electric power utility to improve its transmission system reliability to support this load growth. One of
the most effective ways to improve the transmission system reliability is the enhancement of bus
scheme e.g. from the main and transfer bus scheme to the double bus double breaker scheme or the
breaker and a half scheme, which usually needs more space. Therefore, the area extension for the
substation is normally required. On the other hand, the cost of real property increases steadily and
sometimes the physical constraints or environmental impacts may also play a significant role. These
factors lead to strict constraints in terms of space extension especially in case of urban conventional
substations. For this reason, the so-called hybrid switchgear, a mixed technology switchgear making
use of Gas-Insulated Switchgear (GIS) modules with an Air-Insulated Switchgear (AIS) or a GIS
busbar i.e. outdoor GIS, has drawn more and more attention in this application due to its advantages
particularly with respect to space requirement and interface to the existing conventional switchgear.
In this contribution, a pilot project using hybrid switchgear to reconfigure the bus scheme of a 115 kV
conventional substation is introduced. For EGAT’s 115 kV conventional substations, the typical bus
scheme is the main and transfer bus scheme which has a relatively low reliability. In order to find out
the suitable bus scheme for this project from the reliability and economical points of view, the
substation reliability and life cycle cost calculations with different common bus schemes are carried
out. It has been shown that in this case the double bus double breaker scheme is the best one in terms
of reliability and economy. However, the enhancement of the bus scheme using AIS means an area
extension which is impossible in this case. On the other hand, the application of GIS would lead to an
exceedingly high investment costs. As a result, the hybrid switch is applied to overcome the area
constraint while the investment costs are not unacceptably high.
In order to build up the double bus double breaker scheme from the existing main and transfer bus
one, the conventional disconnecting switch close to the transfer bus needs to be replaced by a hybrid
*somchai.char@egat.co.th
switchgear module consisting of a circuit breaker, two disconnecting switches in combination with
earthing switches each with an integrated disconnector, and a current transformer. The integrated
disconnector enables the routine insulation tests of the circuit breaker without de-energizing the
nearby line or busbar. The replacement work utilises the N-1 criterion of the substation for power
transmission so that the substation bay can be de-energized one by one without affecting the
availability of power supply. The modular and compact designs of hybrid switchgear reduce the
installation process and thus the installation time.
KEYWORDS
Hybrid Switchgear, Substation reliability, Bus Scheme, Enhancement, Retrofit.
1. INTRODUCTION
The fast increases in population, living standards and industrial consumption lead to the rapid growth
of the electricity demand in Thailand. In addition to the sufficient and firm generation of electricity,
the security of electricity supply must also be improved to meet this increasing need. Hence, it is an
essential duty of the electric power utility to accordingly enhance its transmission system reliability.
One of the most effective means is the improvement of substation bus arrangement resulting in an
increase in the substation and thus overall reliability. However, this upgrade usually needs more space
and therefore the area extension for the substation is required. On the other hand, the cost of real
property increases steadily and sometimes the physical constraints as well as environmental impacts
play a significant role. All of these factors lead to difficulty in terms of space extension particularly in
case of conventional substations which require a lot of area. For this reason, the so-called hybrid
switchgear (Fig. 1), a mixed technology switchgear making use of Gas-Insulated Switchgear (GIS)
modules with an Air-Insulated Switchgear (AIS) or a GIS busbar i.e. outdoor GIS, has increasingly
found its applications especially in substation extension due to its advantages with respect to space
requirement and interface to the existing conventional substation.
Fig. 1: Hybrid switchgear combining both AIS and GIS technologies and taking the advantage of the
two different technologies [1]
In this contribution, a pilot project of EGAT applying hybrid switchgear to retrofit bus arrangement of
an existing 115 kV conventional substation in order to improve its reliability is introduced. For
EGAT’s 115 kV conventional substations, the typical bus arrangement is the main and transfer bus
which has relatively low reliability but sufficient for the area where the power consumption is not
high. In order to increase the substation reliability resulting from the growing power demand, the bus
scheme must be reconfigured. For this purpose, substation reliability and Life Cycle Cost (LCC)
calculations with different common bus schemes are performed to find out the most suitable bus
scheme for the substation under consideration. Three different substation technologies, AIS, GIS and
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hybrid switchgear, are compared to each other to see their suitability for this project. Afterwards, the
reconfiguration of the bus arrangement applying hybrid switchgear is treated. A special requirement is
introduced here to increase the substation reliability during some scheduled routine tests of the circuit
breaker. Finally, the replacement work for this project is presented. Since it is more or less an
extension work, the existing parts or components have to be considered in the construction. Certain
approaches e.g. for de-installing the existing components, transporting the hybrid switchgear to the
desired positions, connecting them to the rest of substation within a short time and affecting the
availability of power supply as low as possible are necessary.
2. EXISTING SUBSTATION
Nakhon Chaisri (NCS) substation is one of the most important substations in Thailand. It is located in
Nakhon Pathom province, central part of Thailand, and has to supply the electric power to industrial
customers. The NCS substation is composed of a 230 kV and a 115 kV substation located in the same
fence. The 230 and 115 kV substations are connected together via three 300 MVA auto transformers.
The 230 kV substation is the indoor GIS type installed in a clean building. The bus configuration of
the GIS is the double bus single breaker scheme. The 230 kV substation consists of three 300 MVA
transformer bays connected to the 115 kV substation, a bus coupling bay and two transmission line
bays where the power supply to the 115 kV substation is received from here. From experience, the
230 kV substation has shown only a few minor problems, which may be attributed to the advantage of
GIS technology.
In contrast to the 230 kV substation, the 115 kV substation is the outdoor AIS (conventional) type
exposed to fluctuating weather and environmental conditions. The failure of the equipment is often
caused not only by the weather and moisture in air, but also by other uncontrollable factors such as
bird droppings, bee colonies, herd of birds, and etc. The scheme of the 115 kV substation is the main
and transfer bus scheme which has comparatively low reliability. The 115 kV substation comprises
three 300 MVA transformer bays connected to the 230 kV substation, three bays for step down
transformers to supply 22 kV customers, a tie bay, two bays for other 115 kV transmission lines and
two bays to supply 115 kV customers. In order to increase the reliability of the 115 kV substation to
support the rapid load growth in the future, the enhancement of the bus configuration is required.
3. SUBSTATION RELIABILITY CALCULATIONS
With the aid of substation reliability calculations with different bus schemes, it is possible to find the
best bus scheme suitable for the considered substation from the reliability point of view. In this work,
the failure rate λ and unavailability U of the substation are chosen as the criteria for the substation
reliability consideration. They result from the failure rate and unavailability of the major substation
components in series and parallel while only active and overlapping failure events of those
components are considered here. Since the probability that the overlapping failure event of three or
more components occurs is negligibly small, the overlapping failure events higher than the second
order are not taken into consideration. In general, the approximate equations for components in series
and two components in parallel can be expressed as follows [2]:
Components in series
Two components in parallel
n
λs = ∑ λi
[failures/year]
(1)
[hours/year]
(2)
[hours]
(3)
λ p ≈ λ1λ2 (r1 + r2 )
[failures/year]
(4)
i =1
n
U s ≈ ∑ λi ri
U p ≈ λ p rp = λ1λ2 r1r2 [hours/year]
(5)
i =1
rs ≈
Us
λs
rp =
r1r2
r1 + r2
[hours]
(6)
2
where r the repair time in hours and subscripts s and p denote the values for components in series and
two components in parallel, respectively. The repair times resulting from equations (3) and (6) are the
mean values for each case. In order to simplify the calculation, the repair and down times are assumed
to be the same.
The failure rates and down times for a single outage of the major equipment of EGAT’s 115 kV
conventional substations are shown in Table 1. As an important active component which has to
energize and de-energize the circuit quite often, the circuit breaker has the highest failure rate among
all the components. The passive components especially current and voltage transformers have much
lower failure rates compared to that of the circuit breaker. Although the disconnecting switch is an
active component, it has a negligibly low failure rate. This may be described by the fact that the
disconnecting switch is normally closed and opened without load (only with small capacitive
currents). Moreover for EGAT’s 115 kV conventional substations, manual operation (by hand) of the
disconnecting switch is usually specified which may result in a reduction of the failure rate caused by
the operating mechanism unit.
Table 1: Failure rates and down times of the major equipment of EGAT’s 115 kV conventional
substations
Failure rate λ
[failures/year⋅⋅unit]
Items
Busbar
Circuit breaker
Current transformer
Disconnecting switch
Voltage transformer
Power transformer
(230 kV/115 kV)
0.0094
0.0153
0.0002
negligibly low
0.0003
Repair
Down time [h]
0.5
12
8
4
8
0.0067
48
Maintenance
Scheduled maintenance
Down time [h] Interval [yr]
72
10
72
12
72
12
360
6
When calculating the failure rate and unavailability of the substation, the failure rate and unavailability
of each outage event caused by a single component (obtained from Table 1) or two components at the
same time (obtained from Table 1 together with equations (4) to (6)) is summed up corresponding to
equations (1) to (3) [3]. If the failure of the component(s) does not lead to a power outage on the
customer (line) side, it is not included in the calculation. The outage caused by the scheduled
maintenance is not taken into consideration here because the scheduled maintenance is normally well
planned and thus the unintentional outage is unlikely. Furthermore, if the failed component can be
isolated by the corresponding disconnecting switches nearby it without a complete outage on the
customer side, the repair or down time of 0.5 hour is used instead of the value in Table 1. This is the
time that the substation operator requires to open the disconnecting switches manually. The calculated
overall values of the failure rate and unavailability of EGAT’s 115 kV conventional substations with
different common bus configurations are shown in Table 2.
Table 2: Calculated values of the failure rate and unavailability of EGAT’s 115 kV conventional
substations with different common bus schemes
Bus schemes
Main and transfer bus
Breaker and a half
Double bus double breaker
Total failure rate λt
[failures/year]
0.115
0.077
0.031
Total unavailability Ut
[hours/year]
0.197
0.385
0.157
It can be seen that the existing main and transfer bus scheme of the 115 kV NCS substation has the
highest failure rate among the three common bus schemes. If it is changed to the breaker and a half
scheme, the failure rate is reduced about 33% but the unavailability increases 95%. The double bus
3
double breaker scheme yields both the lowest failure rate and unavailability and thus is the best one in
terms of reliability.
4. LIFE CYCLE COST CALCULATIONS AND SUBSTATION TECHNOLOGIES
Life Cycle Cost or LCC is an economical calculation method to determine the total cost of a technical
system during its lifetime so that the system with different schemes or technologies can be
economically compared to achieve a worth investment. For electrical substations, in addition to the
investment costs, the outage costs usually contribute a large portion to the total cost. Therefore, it is
possible for the grid owner to gain the low cost of electrical energy with high reliability. By employing
the LCC calculation together with the failure rate and unavailability of the substation, the best bus
scheme for the specified area in the network from the economical and reliability points of view can be
found. On the other hand when choosing between AIS, GIS and hybrid switchgear technologies, their
investment costs and the physical and environmental constraints on the substation location generally
play a crucial role. Nevertheless, other factors like construction and installation times may
occasionally be the decisive factors.
In order to find out the most suitable bus scheme from the economical point of view for upgrading the
115 kV NCS substation, the LCC calculations for the 115 kV conventional substations with different
common bus schemes are carried out. The LCC of the substation is composed of the Investment Costs
(IC), Operating Costs (OC1), Maintenance Costs (MC), Outage Costs (OC2) and Rest value (R) as
shown in the following equation [3]:
LCC = IC + OC 1 + MC + OC 2 + R
(7)
In this case, the Investment Costs (IC) are divided into the equipment costs, construction and
installation costs and real estate prices. Since the amounts of some basic common equipment like
power transformer, control and communication units, etc. are usually independent on the bus scheme,
their costs are not included in the equipment costs. For comparison purpose, it is sufficient to include
only the costs of the equipment of which the quantities are varied depending on the bus scheme. Those
equipment are the power circuit breaker, the disconnecting switch, the voltage and current
transformers and the protection system. In order to obtain the equipment costs for each common bus
scheme, the costs of mentioned equipment are summed up according to their different quantities in the
minimal cut sets applied in the calculations of failure rate and unavailability of the substation. The
construction and installation costs are related to the equipment costs. On the other hand, different bus
schemes require different amounts of area for the switchyard leading to differences in real estate
prices. The conventional substations with the breaker and a half and double bus double breaker
schemes basically need larger areas than those with the main and transfer bus scheme.
The OC1 are the expenses related to the operation of equipment e.g. salaries of personnel, cost of
electricity, etc. The MC are the expenses required for fixing out of order or broken equipment and
performing routine actions to keep the equipment in working order or prevent trouble from arising. In
general, both of them are expressed in terms of annual costs. In order to calculate the OC1 and MC of
the equipment over their lifetime, the net present value is applied, the sum of the present values of the
individual future cash flows of the same entity taking inflation and returns (e.g. from interest rates)
into account. For a constant annual payment A over N years, the net present value Bn,const can be
determined by [4]:
Bn, const =
qN − 1
⋅ A = β (N , inom ) ⋅ A
q N ⋅ (q − 1)
(8)
with q = 1 + (inom / 100 ) and inom = (1 + (ireal 100 )) ⋅ (1 + z1 ) − 1 . inom, ireal and z1 are the nominal interest
rate, the real interest rate and the inflation rate, respectively.
4
The OC2 are the damage costs resulting from the power outage. With the aid of the interruption cost
per kW and the interrupted energy cost per kWh, the outage costs OC2 per year taking into account
the failure rate λt and unavailability Ut of the substation are:
OC 2 per year = Psub (x ⋅ λt + y ⋅ U t )
(9)
where Psub is the power of the substation in kW, x the interruption cost per kW and y the interrupted
energy cost per kWh. The OC2 over their lifetime can then be determined by applying the net present
value. However, in this case, the yearly increase of the power demand and thus the power of the
substation must be considered as well. Hence, the net present value with a constant increasing rate
Bn,inc is applied [4]:
(q *) − 1 ⋅ A = β (N , i , z ) ⋅ A
q*
⋅
1
1
nom 2
1
q (q *)N ⋅ (q * −1)
N
Bn , inc =
(10)
with q* = q (1 + (z2 / 100 )) . A1 is the initial annual payment and z2 the increasing rate. The annual
payment increases yearly with the increase of power demand.
The rest value R means the remaining value of an investment after a period of usage. For the
upgrading project like this case, the existing equipment can further be used independently on the bus
schemes of the substation. Consequently, the rest value R is the same for all bus schemes and thus
neglected in the consideration.
The parameters for the LCC calculations are listed as follows: OC1 per year = 0.5% of the equipment
costs, MC per year = 1% of the equipment costs, N = lifetime of the equipment = 30 years, z1 =
inflation rate = 3%, ireal = real interest rate = 7%, inom = nominal interest rate = 10.21%, outage costs =
10.38 THB/kW and 75.37 THB/kWh [5], Psub = power of the substation = 400 MW, z2 = increasing
rate of the substation power = 5 to 10%, R = rest value = 0. The LCC components of the 115 kV NCS
substation (AIS type) with different bus schemes are presented in Table 3.
Table 3: LCC components of the 115 kV NCS substation (AIS type) with different bus schemes
Bus schemes
IC [THB]
Main and transfer bus
23.36 M
Breaker and a half
28.07 M
Double bus double breaker
29.93 M
(1 EUR = 41.06 THB on 5 January 2012)
OC1 + MC [THB]
0.24×β (30,10.21) M
0.30×β (30,10.21) M
0.33×β (30,10.21) M
OC2 [THB]
6.41×β 1 (30,10.21,z2) M
11.9×β 1 (30,10.21,z2) M
4.86×β 1 (30,10.21,z2) M
The calculated LCC of the 115 kV NCS conventional substation with different bus schemes depending
on the increasing rate of the substation power z2 are shown in Fig. 2. The double bus double breaker
scheme yields the lowest LCC and thus is the best bus scheme for the 115 kV NCS substation from the
economical as well as reliability points of view. This is due to the predominant contribution of the
outage costs to the LCC. Although the double bus double breaker scheme has comparatively high
investment as well as operating and maintenance costs, its failure rate and unavailability are much
lower than those of the other bus schemes resulting in the lowest value of the outage costs. With the
increasing rate of 5%, which is roughly the average power demand growth of Thailand in the
meantime, the LCC of about 15.5 million THB can be saved when using the double bus double
breaker scheme instead of the main and transfer bus one. The change of the bus scheme will even be
more economical if the increasing rate of the power demand becomes higher. The breaker and a half
bus scheme gives the highest LCC because of its relatively high investment costs and particularly
unavailability and therefore not appropriate in this case.
5
400M
Main and transfer bus
Breaker and a half
Double bus double breaker
350M
LCC [THB]
300M
250M
200M
150M
100M
50M
0M
0
2
4
6
8
10
Increasing rate z2 [%]
Fig. 2: Calculated LCC of the 115 kV NCS conventional substation with different bus schemes
depending on the increasing rate of the substation power z2
When choosing between the substation technologies, the conditions on the substation location as well
as the advantages and disadvantages among the technologies have to be considered. The AIS or
conventional type is advantageous with respect to the equipment cost while a lot of space (clearance)
is usually required for the substation. Hence, this kind of switchgear is basically not suitable for the
metropolitan area where real estate prices are particularly high. In contrast, the GIS technology offers
a possibility to build up the substation within a small or limited area. Therefore, it is proper for the
urban area where the land is expensive. However, the equipment investment costs of GIS are quite
high due to the state-of-the-art technologies and a lot of material applied. For this reason, it must
usually be traded off between the real estate prices and equipment investment costs before using the
GIS.
In the case of 115 kV NCS substation, however, the physical and time constraints play a key role in
choosing the switchgear type for the upgrading project in addition to the investment costs. The use of
AIS for upgrading the bus scheme from the main and transfer bus to the double bus double breaker
scheme is impractical here because the area extension is limited and the upgrading project should be
finished within a short period of time in order to affect the system reliability in the region as low as
possible. With respect to the area limitation, the GIS technology would be of advantage. However, the
investment costs would be exceedingly high for the upgrading because all the existing conventional
equipment could not be used anymore in the substation i.e. an investment for an almost completely
new GIS substation is required. Additionally, EGAT usually requires a building for housing the GIS
substation and preventing it from the exposure to the fluctuating weather conditions. This increases the
total investment cost for the GIS.
In order to overcome the aforementioned constraints, the hybrid switchgear is applied in this project.
The hybrid switchgear technology gains the advantages from both AIS and GIS technologies, which
make it capable of being applied within a compact area while its equipment costs are between those of
GIS and AIS. Furthermore, the hybrid switchgear can be connected with the existing major equipment
in the substation regardless of whether they are AIS or GIS. The module concept inherited from the
GIS provides the reduction of construction and installation times as well as maintenance effort.
5. RECONFIGURATION OF BUS SCHEME APPLYING HYBRID SWITCHGEAR
In order to upgrade the main and transfer bus to the double bus double breaker scheme, the lower
disconnecting switch close to the transfer bus basically need to be replaced by a circuit breaker and
6
two disconnecting switches (Fig. 3). The disconnecting switches are usually used to isolate the circuit
breaker and thus enable its maintenance without de-energizing the line and busbar. The earthing
switches may be integrated to the disconnecting switches in order to discharge dangerous induced
voltages and currents during maintenance. For the 115 kV conventional substation, the bay length will
increase from 35 m to 42 m when changing from the main and transfer bus to the double bus double
breaker scheme (the breaker and a half scheme requires even much more bay length which is 65 m).
However, with the application of the hybrid switchgear, the replacement of the lower disconnecting
switch with a circuit breaker and two disconnecting switches can be done without any further space
requirement (Fig. 4).
Main Bus No. 1
Main Bus
DS
DS
DS
CB
CB
DS
DS
DS
DS
DS
DS
CB
CB
CB
CB
DS
DS
DS
DS
DS
DS
DS
CB
CB
CB
DS
DS
DS
DS
Upper Part
DS
Lower Part
Transfer Bus
CB: Circuit Breaker
DS: Disconnecting Switch
Main Bus No. 2
Fig. 3: Upgrading from the main and transfer bus to the double bus double breaker scheme
35 m
(a)
42 m
(b)
35 m
(c)
Fig. 4: Substation layouts with different bus schemes and switchgear types: (a) Main and transfer bus
scheme with AIS, (b) Double bus double breaker scheme with AIS, (c) Double bus double breaker
scheme with AIS for the upper bus and hybrid switchgear for the lower bus
For this application, the gas-insulated hybrid switchgear module consisting of a circuit breaker, two
disconnecting switches each in combination with an insulated earthing switch (two three-position
disconnecting switches) and a current transformer is specified for each bay (Fig. 5). Unlike the
conventional equipment, each earthing switch here is required to have a disconnector to enable the
maintenance people to measure the contact resistance or perform insulation tests of the circuit breaker
without de-energizing the line or main bus next to the tested circuit breaker (Fig. 5). This is required in
favour of better substation reliability during those scheduled tests.
7
CB: Circuit Breaker
CT: Current Transformer
TPS: Three-Position Switch
CT
TPS
CB
Disconnector
Hybrid Switchgear
TPS
(a)
(b)
Fig. 5: Single line diagram of the specified hybrid switchgear: (a) single hybrid switchgear, (b)
installations in the substation establishing the double bus double breaker scheme
6. REPLACEMENT WORK
Since this project is an upgrading work, proper switching and construction plans as well as interfacing
to the existing components of the substation are necessary. The upgrading work should be completed
within a short period of time affecting the supply of power to the customers as low as possible.
The existing bus scheme of the 115 kV NCS substation is the main and transfer bus of which the
transfer bus is normally not energized. The substation has the N-1 criterion for power transmission
which secures the supply of energy to the customers to a certain extent. Hence, the reconstruction of
the transfer bus from the low to high profile bus to establish another main bus should first of all be
carried out. Then, the replacement and relocation of the equipment can be done. The N-1 criterion for
the lines coming to and going from the substation offers the possibility to de-energize the substation
bays one by one without interrupting the power supply. Due to the fact that the existing lower
disconnecting switches are located close to the access road in the substation, the hybrid switchgear can
easily be transported to their locations through the access road. The relatively light weight of hybrid
switchgear enables a further carriage by a forklift to the installation location. The transportation of
hybrid switchgear through the energized parts is unproblematic because of the compact size of hybrid
switchgear as well as high clearances in the AIS substation. It should be noted that during the
installation of the hybrid switchgear a power supply through the remaining circuit breaker and
protection system is possible (radial bus scheme) if necessary. The combination of required equipment
in a compact switchgear module reduces the number of wiring and connections and thus the
installation time.
7. CONCLUSION
In this contribution, the enhancement of substation reliability by reconfiguring the existing bus scheme
applying the hybrid switchgear is presented. For this purpose, a pilot project for upgrading an
important 115 kV conventional substation with the main and transfer bus scheme is introduced. In
order to find out the best bus scheme for the substation under consideration in terms of reliability and
economy, the substation reliability and Life Cycle Cost (LCC) calculations with three different
common bus schemes are performed. As the criterion for the substation reliability, the failure rate and
unavailability of the substation are applied, resulting from failure events of major substation
equipment (power circuit breakers, busbars, etc.) in series and parallel together with the available data
of their failure rates and repair times. It has been found out that the double bus double breaker scheme
yields the lowest failure rate and unavailability compared to the main and transfer bus as well as
breaker and a half schemes. The LCC calculations show that the double bus double breaker scheme is
the best one for this case not only from the reliability but also from the economical points of view.
However, the reconfiguration of the bus scheme using Air-Insulated Switchgear (AIS) technology
requires an area extension for the substation which is limited in this case. On the other hand, Gas-
8
Insulated Switchgear (GIS) technology would lead to an exceedingly high investment costs. Therefore,
the hybrid switchgear taking the advantages from both AIS and GIS technologies is chosen in this
project to cope with the space constraint while the investment costs are acceptable. In order to buildup the double bus double breaker scheme, the existing lower disconnecting switches of the main and
transfer bus scheme are replaced with the hybrid switchgear modules each consisting of a power
circuit breaker, two disconnecting switches in combination with earthing switches and a current
transformer. A disconnector integrated with the earthing switch is required in order to enable the
routine insulation tests of the circuit breaker without de-energizing the nearby line or busbar. The N-1
criterion of the substation for power transmission makes the replacement work possible without
affecting the availability of power supply.
ACKNOWLEDGEMENT
The authors would like to thank the Transmission System Maintenance Division, EGAT, especially
Mr. Suthep Singharerg for providing the data of failure rate and repair time of substation equipment.
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[2]
[3]
[4]
[5]
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