Jean-Marc Biasse

Philippe Alibert

Philippe Deschamps

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 C I R E D 21st International Conference on Electricity Distribution Frankfurt, 6-9 June 2011 
 
Paper 0768 
 
 
Paper No  0768   1/4 
REDUCE THE NUMBER OF OUTAGE BY INTRODUCING CIRCUIT BREAKER IN THE 
DISTRIBUTION NETWORK, DREAM OR REALITY? 
 
 
 Philippe DESCHAMPS  Philippe ALIBERT  Jean-Marc BIASSE 
Schneider Electric Industries – France Schneider Elctric France – France Schneider Electric Industries - France 
 philippe.deschamps@ philippe.alibert@ jean-marc.biasse@ 
 schneider-electric.com fr.schneider-electric.com schneider-electric.com 
 
ABSTRACT 
The use of CBs in the loop allows to decrease SAIDI and 
SAIFI 
The use of CBs in the loop, yesterday economically not 
possible can be now considered because:  
- current available offers are more adapted to the strict 
requirements of secondary distribution needs 
- modern protection relays allow now an adaptation of the 
existing protection scheme by adding selectivity levels 
between HV/MV substation and MV/LV substations. 
INTRODUCTION 
The distribution network is generally operated in open loop 
allowing a backup solution in case of fault. It is h torically 
equipped with manual switches, with only one protection 
device per feeder, located in the HV/MV substation. The 
increasing demand for quality of supply leaded to the
deployment of remote controlled substation bringing lower 
shortage duration. Nevertheless, in case of fault, ll the 
customers supplied by the faulty feeder are disconnected. 
But in fact the customers upstream the fault could have been 
unaffected. 
The use of circuit breaker instead of switches in the loop 
allows disconnecting only the customers connected to the 
faulty part, a significant benefit regarding the number of 
affected customers compared to the traditional solutions. 
WHY ARE CIRCUIT-BREAKERS IN THE 
NETWORK NOT WIDELY USED? 
There are two types of brakes to implement CBs in the 
network: 
- MV CBs and their associated equipment were expensiv  
and more adapted to HV/MV substations than to MV/LV 
substations, 
- usual time discrimination protection system lead to a 
limitation of the number of discrimination levels. 
Brakes coming from CBs and sensors  
MV/LV substations do not need all functionalities that are 
required in HV/MV substations and cannot support their 
corresponding cost. For instance, withdrawability of CBs 
was justified by maintenance reasons [1]. MV circuit-
breakers made in the 1950’s or 1960’s were using air or oil 
for breaking medium. Often, only a few short-circuit 
clearances were possible on a circuit-breaker before 
maintenance.  Interchangeability of a circuit-breaker during 
maintenance operations was an important facility.  
 
Figure1 – Example of 1970’s withdrawable bulk oil. 
From these years, MV circuit-breakers have been improved 
a lot together with the evolution of the standards requiring a 
higher electrical endurance. Mainly in HV/MV substations, 
circuit-breakers are still withdrawable type, even if the need 
for maintenance is much lower today. 
The disadvantage of using this approach was an increase in 
the front to back dimensions of the switchgear to allow for 
the horizontal movement of the circuit-breaker. So, primary 
switchgear were designed for an environment where space is 
not an issue. As a contrary, compactness is strongly required 
in MV/LV substations.  
 
 
 
 
 
 
 
 
 
 
 
Figure2 – Example of MV/LV compact substation. 
Beside the CBs in primary substations, old generations of 
big sized sensors with heavy burden are still used. For 
example 5A – 10 to 15VA current transformers or 30 to 
50VA voltage transformers were justified in conjunction 
with old electromechanical relays but are no longer 
 C I R E D 21st International Conference on Electricity Distribution Frankfurt, 6-9 June 2011 
 
Paper 0768 
 
 
Paper No  0768   2/4 
necessary with modern digital relays. The real need of 
consumption of digital relays is in the range of 1VA. Then, 
big sized coupling transformers are necessary to cope with 
5A or 1A inputs.  
Brakes coming from time discrimination protection 
systems  
With a distribution network operated in open loop, the 
protection system is generally based on overcurrent elays 
with time discrimination to ensure the coordination. 
According to the neutral earthing system, directional earth 
fault protection can also be used in the primary substation. 
If a large generator is connected into the MV network, 
directional phase overcurrent protection can be necssary in 
the primary substation for the concerned outgoing feeder. 
But, for all these cases, the coordination is always based on 
time discrimination. Of course, in particular cases, other 
protection systems can be used (differential line protection, 
distance protection …), but today these systems are not well 
adapted to the MV power systems requirements. 
 
With a protection system based on time discrimination, the 
time interval between the protection stages is generally 
300ms. This value has fixed a limitation in the number of 
protection stages, to avoid too long clearing time at the 
upper level. The figure 3 gives an example with a simplified 
single line diagram. The timer settings are defined with 
independent time (DT curves) to simplify the example, but 
the same approach could be done with dependant time curv  
(IDMT curves). 
1.3s
HV/MV Primary Substation
0.7s
1.0s
MV/MV Secondary
 Substation
0.1s0.4s
MV customer
 Substation
 
Figure3 – Example of DT timer settings with time 
discrimination 
In this example, the timers at the upper levels are more than 
1s. These settings are often not acceptable because the 
voltage sags are too long in case phase faults on the MV 
outgoing feeders, and the clearing time is too longin case of 
busbar short-circuits in the primary switchboard. Generally, 
protection relays are only used in primary substations and 
customer substations. The secondary substations are based 
on switch-disconnectors without protection relays. Only 
MV/LV transformer feeders are equipped with protection 
relays 
FEED BACK ON SOME EXPERIMENTATIONS 
AND STUDIES  
Despite these breaks, several experimentations have been 
done, aiming to add circuit breakers in the loop. 
In general, major criterions were: 
 A simple and economic upgrade, 
 No or low impact on operation modes 
a. Dong Energy - Copenhagen:  
The solution consists of adding one or two circuit-breakers 
in a radial feeder. Practically, one switch of the RMU is 
replaced by a circuit breaker, driven by a local automatism: 
if the voltage is off, and no fault has been locally seen, then 
the incoming switch is open and a second switch is clo ed 
on a back-up line. If the voltage is off and a fault c rrent has 
been seen, then the circuit breaker trips, isolating he 
downstream section. 
 
Figure4 – Illustration of Dong’s concept 
In case of fault, the faulty section is automatically isolated 
while the healthy sections are still alive thanks to a backup 
[2], [3]. Based on local decentralised automatism located in 
the MV/LV substations, the system does not require any 
communication infrastructure. On the other hand, circuit-
breakers require a higher electrical endurance. They have to 
withstand 40 to 50 breakings at the full fault current, 
assuming that we do not know the real amplitude of br ken 
current at each fault. 
Therefore, a new feature exists now in modern protection 
relays, allowing knowing the prompting level of the 
breakers. 
In addition, Dong’s system requires particular network 
architecture with an available back-up ingoing in each 
upgraded MV/LV substation. 
b. ENEL 
ENEL has deeply investigated the topic [4], [5] and fi ally 
achieved the specification of a new switchgear. Three key 
characteristics were clearly identified to achieve an
innovative solution: 
- the switching time 
- the making and breaking capacity 
- the electrical and mechanical endurance 
These key point being addressed, a particular care w s taken 
to have a compatibility with installed base in order to 
facilitate the implementation. This point is quite easy in 
case 1 case 2 
open 
+ 
backup 
open 
+ 
backup 
trip 
trip 
 C I R E D 21st International Conference on Electricity Distribution Frankfurt, 6-9 June 2011 
 
Paper 0768 
 
 
Paper No  0768   3/4 
Italy since most of substations are equipped with ar 
insulated switchgear, usually bigger and more accessible 
than gas insulated switchgear, and then more convenient to 
upgrade. But ENEL has planned to expand this specification 
to a future SF6 insulated RMU. 
c. New Berlin [6] 
In this case, the network is operated in closed loop with 
several breakers in the circuit. A peer to peer 
communication links each breaker to its neighbour and the 
protections are directional type. Protections are set to open 
the breaker if its neighbour has seen the fault in an opposite 
way (directional logic locking, commonly used in industry). 
This solution requires a specific communication system, 
which is an important drawback. 
The operation in closed loop is not applicable in most of 
feeders where each end is supplied by a different primary 
substation, but it can be operated also in open loop. 
 
As a conclusion, the implementation of circuit break rs 
along the feeder, while bringing interesting benefits in terms 
of quality of supply, generates some technical and/or 
economical constraints which are not always acceptable. 
MODERN SOLUTIONS 
On an ideal point of view, solutions including low cost CBs, 
low cost sensors, no communication, without specific 
network architecture and easy possible upgrade would allow 
to reduce the outage at a cost effective level. 
Today, adequate and economically viable answers to the 
needs of MV/LV substations do exist, in both following 
areas: 
- optimized integrated CB for network applications, 
including LPCTs, 
- adaptation of existing protection systems by the reduction 
of time discrimination interval or the use of logic 
discrimination in substations between incoming and 
outgoing feeders. 
Optimized integrated CB for network applications 
For compactness and for the best integration, fixed 
technology is used as it is now proven that fixed CBs are 
of very high reliability and maintenance free [1]. Modern 
fixed designs offer reliable service provided the switching 
devices meet the service application during their whole 
life and the manufacturer has considered the important 
operational requirements which are: 
- safe working procedures for cable jointing, 
- cable fault location and testing procedures, 
- system phasing out procedures, 
- protection testing procedures, 
- working procedures for switchboard extension. 
These CBs are integrated in a switchgear module that is 
insensitive to harsh environments. These modules include 
optimized sensors that are able to operate with self powered 
relays.  
On another hand, digital relays can now easily accept 
voltage signals from Low Power Current Transformers 
(LPCT). Figure 5 shows there is a huge difference i size 
between two types of CTs at equivalent characteristics. 
 
 
Figure5 –24kV CTs 
comparison, LPCT on left side, 
traditional CT on right side. 
 
 
Adaptation of existing 
protection system 
With digital relays and modern CBs, several improvements 
of the existing protection system allow insertion of one or 
two protection stages without too long clearing time. 
• The time discrimination interval can be reduced to 
200ms. The following chapter explains how this 
reduction is possible. 
• The logic discrimination can be used in substations 
between incoming and outgoing feeders. This 
principle allows same timer settings for both stages. If 
physical wires are necessary, connections are delimited 
to the same switchboard. If digital links are used with 
the GOOSE service of the IEC61850 communication, 
the logic discrimination is easily implemented. 
• The setting groups can be used for an adaptative 
protection system. 
 
With these two improvements, the example of the figure 3 
leads to the following timer settings (figure 6) 
0.5s
HV/MV Primary Substation
0.3s
0.5s
MV/MV Secondary
 Substation
0.1s0.1s
MV customer
 Substation
Blocking
order
Blocking order  
Figure 6 – timer settings after improvement 
Reduction of time discrimination interval 
In the figure 7, the upstream relay A is set with a timer TA 
and the downstream relay B is set with a timer TB. 
 
Figure 7 – time discrimination between two relays 
 C I R E D 21st International Conference on Electricity Distribution Frankfurt, 6-9 June 2011 
 
Paper 0768 
 
 
Paper No  0768   4/4 
To ensure a proper discrimination between A and B relays, 
the time interval ∆T must be above or equal to the sum of 
the following items: 
• The maximum negative error (δA-) of the timer TA 
(without the B relay, the A relay would trip with te 
timer TA-δA-).  
• The maximum positive error (δB+) of the timer TB ( the 
B relay could trip with the timer TB+δB+). 
• The maximum clearing time of the B circuit breaker 
• The overshoot time of the relay B 
• A security margin. 
 
For DT curves of modern relays, the timer accuracy is 
generally around ±2% or ±20ms. The maximum error 
between the timers of A and B relays would be less than 
40ms. 
For IDMT curves, the timer accuracy also depends on the 
current measurement accuracy.  This timer accuracy is 
generally around ±5%, mutiplied by a factor according to 
the current magnitude (as described in the IEC 60255-151 
standard). Due to IDMT curve principle, the time interval 
between the A and B curves must be met for the maxium 
short circuit current.  So, for typical settings, the maximum 
error for the timers of A and B relays is less than 50ms.    
 
The maximum clearing time of circuit breakers depends on 
the technology.  
• With a shunt trip coil system, the clearing time depends 
on the auxiliary voltage level. With the rated voltage 
level, the clearing time is generally less than 80/90ms, 
but with a reduced level of 0.7 times the rated auxiliary 
voltage, 50ms must be added.  
• With modern CBs associated with self-powered relays, 
the trip command is based on low power tripping coil
without any auxiliary power supply. As the result, the 
clearing time is more repetitive, and for modern cicuit-
breaker, the maximum clearing time is generally less 
than 60 to 80ms. 
The overshoot time for modern digital relays (as defined in 
the IEC 60255-151 standard) is generally less than 40ms. 
This time is only due to the depth of Fourier filters (1 
cycle), which are commonly used in the overcurrent 
protection algorithm, and the execution cycle duration o 
compute protection functions. 
In conclusion, without safety margin, the time interval ∆T 
must be above 170ms (50ms + 80ms + 40ms). To ensure 
proper discrimination, a safety margin is needed, an  a time 
interval of 200ms is recommended. 
Used of setting groups for adaptative settings 
With this reduction of the time interval, one or two 
protection stages could be introduced between the primary 
substation and the customer substations. With two sage , 
according to the operating modes of the MV feeders (the 
position of the opening point of the MV loop), the timer 
settings of the secondary substation protection relays could 
be different. This “active” setting modification can be done 
with a low speed communication channel which activates 
the right setting group of the protection relays. Each 
secondary substation relays could be set with two setting 
groups, with two different timers, and the choice of the 
active setting group will be defined by the distribut on 
management system according to the operating mode. 
CONCLUSION 
Today, with modern circuit breakers for secondary 
substations and digital protection relays, adaptation of 
existing protection systems allows to introduce oner two 
protection stages in the distribution networks. 
The insertion of CBs in the feeder allows to reduce 
dramatically the number of affected customer in case of 
fault. Another benefit is the reduction of SAIDI index by 
reducing the time of reconfiguration. Consequently long 
duration outages become short duration outages. 
In the future, new protection systems, possibly based on 
latest developments in communication technologies, will be 
designed to better fit the MV grid evolutions (distributed 
generation, closed loop operation,…) . 
 
REFERENCES 
 
[1] L.Mackay, M.Adams, “Advantages of fixed circuit-
breaker switchgear”, Switchgear & Drives Conference 
& Exhibition 2009, Gallagher Estate, Midrand, South 
Africa, 24 - 25 March 2009 
[2] Ph.Deschamps , J.L.Orsini, K.S.Rasmussen, 2009, 
"On the field autonomous automatism: a 
complementary way for network automation”, 
CIRED 2009. 
[3] K.S.Rasmussen, 2009, "A real case of self healing 
distribution network", CIRED2009. 
[4] G.Valtorta, R.Calone, L.D’Orazio, V.G.Salusest, 2009, 
“Continuity of supply improvement by means of circut 
breakers along MV lines”, CIRED 2009. 
[5] L.Giansante, M.Dota, 2009, “A low cost high 
performance MV switchgear for use in remote 
controlled MV/LV substations: first results of ENEL 
distribizione experimentation”, CIRED 2009. 
[6] Bob Huber, 2005, "Distribution grid of the future - 
Reclaiming the distribution business unit", IEEE Power 
meeting . 
 


REDUCE THE NUMBER OF OUTAGE BY INTRODUCING CIRCUIT BREAKER IN THE DISTRIBUTION NETWORK, DREAM OR REALITY?

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REDUCE THE NUMBER OF OUTAGE BY INTRODUCING CIRCUIT BREAKER IN THE DISTRIBUTION NETWORK, DREAM OR REALITY?

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