1. Eskom Technology Conference
Durban, South Africa, October 2012
Distribution Automation utilizing Nulec Breakers on MV Networks
S. Nayager
Performance Engineer, Plant Department, Eskom Distribution
Phone: +27 31 710 5310, Fax: +27 31 710 5763, Email: Nayages@eskom.co.za
Abstract – Eskom Eastern Region has taken the initiative to
implement the use of Distribution Automation (DA) on MV
Pareto networks in the bid to improve the SAIDI Key
Performance Indicator (KPI). The Distribution Automation
philosophy utilizes Section Breakers (Nulec breakers:
Telecontrollable for remote engineering and contains bi
directional functionality) that are installed on Normal Open
and strategic points. The systems core functionality is to
provide automatic fault isolation on a Pareto feeder and
restore supply to customers unaffected by the fault.
In the Newcastle Area, Emondlo NB 125 (inter linked with
St James NB 108 and Dagbreek NB4) was selected as a
pilot site as it satisfied the Pareto List and backfeeding
capability criteria's needed for the project. This paper
illustrates the design philosophy for Distribution
Automation on Emondlo Network Breaker 125 and also
demonstrates a methodology to guide engineers on
implementing Distribution Automation on other MV
networks.
I. INTRODUCTION
Reliability of supply to end users is a Key Performance
Indicator for most power utilities across the globe. Supply of
electricity is vital for private, public and economic sectors of
life. Power utilities are required, whether directly through the
National Regulator or indirectly through customer
requirements, to improve network reliability.
In order to reach the required level of reliability and quality
of service, it is first necessary to accurately quantify it. To do
so, utilities are measured on performance indexes. One of the
main standardized KPI measured on networks are:
• SAIDI (System Average Interruption Duration Index)
measures the average cumulated power outage time during
one year and is defined as:
SAIDI=
customersofNumberTotal
affected]customersofNumber*[Duration
The use of remote-controlled or intelligent circuit breakers
allows significant reductions in SAIDI values if utilized
correctly. Due to economic constraints, organizations are
required to find cost effective/efficient solutions to achieve
outputs of system reliability. One key technology in this
respect is Distribution Automation which uses time, voltage
and power flow, to detect abnormal conditions, isolate faults
and reconfigure the network, without any communications or
operator assistance. The Distribution Automation system is
based on the following simple rules:
A recloser can be configured in three ways such as:
 F: Feeder recloser
 M: Midpoint recloser
 T: Tie recloser
A Feeder Recloser trips when it loses supply.
A Midpoint Recloser changes Protection Group settings when
it detects a loss of supply and disables its reclose
functionality after a set number of operations.
A Tie Recloser closes when it detects a loss of supply on one
side whilst it still has supply on the other side
Figure [1]: Configuration of breakers for DA system
There are other Distribution Automation systems on the
market which integrates different technologies such as DA
GPRS controllers communicating to a Human Machine
Interface (HMI) station and online power monitoring
controllers that utilize algometric methods; however due to
costs and online/real time power monitoring constraints this
pilot project only utilizes the basic switching functionality of

2. a Nulec breaker. Each breaker is configured based on settings
and contains a GPRS modem for telecontrol functionality
allowing for remote engineering as well as Control Access.
This paper will be structured as follows: In Section 2 we will
expose the issues which motivate a methodological approach
for selecting a network to implement DA; In Section 3 we
will explain the operation of the DA system, explaining each
step with meaningful examples; In section 4 we will show the
calculated performance of the system; and finally in section 5
will define what human interaction is required for the system.
II.PROBLEM DEFINITION
This paper documents a pilot project proposed for the Pareto
Network Emondlo 125 (22kV) situated in the Vryheid area. A
Pareto Feeder is defined as a feeder that falls in a category
of about 20% of lines in the Eastern Region which contribute
to about 80 % of losses. After various discussions with
Network Optimization, Primary Plant and Control Plant the
following criteria’s were derived in selecting a suitable
network for Distribution Automation:
 Pilot site be chosen from the Eastern Region Pareto list
 Sites with 2 sections on the line must meet a 50% pick
up and with 3 sections a 66% pick up. 100%
backfeedability not required.
 Line length - ideally the Section breakers should be
positioned mid way (between 40% to 60%) of the
network
 Section breakers must be telecontrol enabled and bi
directional
 DA system must be implemented with N-1 philosophy
 Nulec breakers are to be installed on all N/O points for
all networks
 Proposed Pareto sites must be where the TSC is willing
to co-operate with manual operations if the need arises.
Emondlo NB 125 was chosen as the pilot network as it is
linked to both Dagbreek NB 4 and St James NB 108 via
normal open points providing backfeeding routes. Table [1]
highlights the installed capacity, utilized capacity and
customer base for all three networks
Network
Breaker
Installed
Capacity
(MVA)
Max
MVA
Used
Customer
Base
Emondlo 125 11860 5250 5707
Backfeeding Source
Dagbreek 4 9180 600 140
St James 108 6400 4800 3048
Table [1]: Network Information
A contingency study of all three networks was compiled in
order to determine if the current infrastructure could
withstand the backfeeding load requirements. These included
conductor current carrying capabilities and line voltage drops
when load was transferred from different networks. This was
done on Retic Master software. Emondlo NB 125 contains
two main section breakers namely SB 122 and SB 123 which
both interlink with Dagbreek NB 4 and St James NB 108 at
Normal Open points providing a backfeeding source in either
direction. The diagram below shows a breakdown of all three
networks and the customer base associated with each zone:
Figure [2]: Emondlo NB 125, Dagbreek NB 4 and St James
NB 108 break down
The table below shows the contingency study for all possible
scenarios the DA system may experience. The table
highlights for each scenario: Section Breaker and link
operations, peak loads before and after backfeeding
commences and voltage line drops.
Table [2]: Contingency study for DA scenarios
From the contingency study of all three networks, it can be
seen that for the first 3 scenarios switching from one network
to another is possible as the infrastructure and equipment is
firm. The voltage line drop from 102.72 to 91.39 seen in the
first scenario is below the standard acceptable value of 93.5
however a Voltage Regulator can be installed to bring this
value above the threshold value. The study indicates that
Emondlo NB 125 cannot pick up the entire St James network
or both Dagbreek NB 4 and St James NB108 at the same time

3. (if both substations are off at the same time) as the Max %
load exceeds 100% which will result in an overload trip. In
the DA philosophy Section Breakers are regarded as the
“brains” of the system as it is responsible for detecting and
channeling power flow to acquired locations. In order to
restore power instantaneously to unaffected customers
without operator assistance on the power grid using DA,
Section breakers are installed at Normal Open points. The
Section Breakers are left in an open position configured to
detect power flow and operate in either direction on the
network depending on where the abnormal condition is. Since
St James cannot be fully backfed from Emondlo NB 125 a
strategic point had to be chosen to induce maximum
backfeeding. S1150 which is located before St James SB 190
was chosen as the point where backfeeding would stop. The
diagram below shows existing reclosers (green), proposed
reclosers (purple) and proposed tie breakers at Normal Open
points (red).
Figure [3]: Current and Proposed Reclosers
Once all the final locations for the reclosers have been
determined, the DA system requires that breakers be tele-
controlled for operational purposes, monitoring as well as
remote engineering. Both VHF and GPRS were tested for all
recloser sites. The radio communication repeater sites and
GPRS signal strengths were strong and stable for all site
locations.
Figure [4]: Repeater communication sites for reclosers
III. OPERATION OF THE DA SYSTEM
Currently the Emondlo NB 125 Network is configured as
follows:
Dagbreek Substation
Power flows from Dagbreek NB 4 via SB 12 to the Normal
Open point S57.
Emondlo Substation
Power flows from Emondlo NB 125 via SB 122 and SB 123
to Normal Open points S57 and S1151 respectively.
St James Substation
Power flows from St James NB 108 to Normal Open point
S1151 and SB 190 (not included in design).
Figure [5]: Current network power flow
Reclosers in a DA system can have many configurations as
seen on page 1. Midpoint breakers are configured to change
protection settings meaning that it contain a ‘setting A’ for
one direction of power flow and a ‘setting B’ for another
direction. Most DA systems are configured using Midpoint
breakers however there are complications and risks involved
when using this configuration. This will be looked at on page
4. A typical DA system is shown below:
Fault Scenario 1
Figure [6]: Fault Scenario 1: Zone 1 or Substation trip
Looking at Figure [6] if there is a permanent fault in Zone 1
or a substation trip the following steps are automated:

4. 1). Substation 1 Network Breaker trips when there is a pickup
in Zone 1
2). Feeder recloser (F1) trips when it loses supply
3). Midpoint recloser (M1) changes setting group from A to
B when it loses supply and is now ready to feed upstream
towards Substation 1
4). Tie recloser closes in when supply is lost on one side
5). Power flow is created from Substation 2 through to F1
Fault Scenario 2
Figure [7]: Fault Scenario 2: Between F1 and M1
Looking at Figure [7] if there is a permanent fault in between
F1 and M1 the following steps are automated:
1). Feeder recloser (F1) trips, ARC, trips & lockout
when there is a fault
2). Midpoint recloser (M1) changes setting group when it
loses supply
3). Tie recloser closes in when supply is lost on one side
4). Power flow is created from Substation 2 through M1 to
the fault
5). Midpoint recloser trips, ARC, trips & lockout onto the
fault
Fault Scenario 3
Figure [8]: Fault Scenario 3: Between M1 and T
Looking at Figure [8] if there is a permanent fault in between
M1 and T the following steps are automated:
1). Recloser (M1) trips, ARC, trips & lockout when there is a
fault
2). Recloser (T) closes in trips & lockout on the fault
3). No backfeeding takes place in this scenario
Figure [9]: Emondlo NB 125 Zoning
Emondlo NB 125 already contains 5 Zones therefore
implementing Midpoint Breakers would introduce a further 2
additional Zones to the network. Splitting the network further
is not practical as the the line lengths between Section
Breakers and Normal Open Points is short and would not be
beneficial as the customer base is minimal. Therefore existing
and proposed Section Breakers have been configured to act as
Feeder Breakers. The final Section Breaker configuration
implementing the DA system is shown below:
Figure [9]: Final DA System with recloser configuration
For scenarios 2 and 3, if the fault is classified as a Sensitive
Earth fault, the philosophy of closing the Mid-Point and Tie
breakers onto a fault contravenes the OHS Act as well as
Eskom regulations. Paragraph 6(1) of Section 14 of the
Occupational Health and Safety Act states simply that:

5. “The user shall provide every electrical installation and
power line with controlling apparatus and protective devices
which shall, as far as is reasonably practicable, be capable of
automatically isolating the power supply in the event of a
fault developing on such installation or power line.”
In addition to this, Section 26 of Electricity Regulation Act,
Act 6 of 2006 states: “Liability of licensee for damage or
injury. In any civil proceedings against a licensee arising out
of damage or injury caused by induction or electrolysis or in
any other manner by means of electricity generated,
transmitted or distributed by a licensee, such damage or
injury is deemed to have been caused by the negligence of the
licensee, unless there is credible evidence to the contrary.”
According to these regulations SEF protection is applied to
lock out at a single shot and does not initiate an auto-reclose
cycle. Therefore for all fault scenarios between the Feeder
and Tie Breaker there needs to be some sort of intelligence
applied hence the introduction of Dead Time. Dead time is
the duration of voltage lost on upstream devices and is
measured from when voltages on all three phases fall below
the Live Terminal Voltage Level until one or more phases
rise above the Live Terminal Voltage Level. Standard Loop
Automation uses the loss of voltage at the recloser to trigger
specific actions. This trigger is a feature in Loop Automation
that is capable of recognising an “Allow DT” condition in the
network by measuring the final dead time of upstream
switchgear.
The dead time is configured by the user and when equal will
“Allow DT” Loop Automation to place. Conversely if the
final dead time does not equal the “Allow” dead time, no
automation will take place. It is therefore necessary to set the
normal “Loop Auto Time” and “Allow” dead time for the Tie
Recloser. Loop Auto Time is defined as the delay after Loop
Automation is triggered but before Loop Automation actions
actually take place. This delay (e.g. 40 secs) ensures that all
the protection sequences are completed before Loop
automation reconfigures the network. In the Tie Recloser this
time is used to determine a prolonged outage and will turn off
Loop Automation if power is lost for longer than the “Loop
Auto Time” which will be configured for all fault scenarios.
Figure [10]: Dead Time configuration between Feeder and
Tie Breaker [5]
IV. PERFORMANCE OF THE DA SYSTEM
Since the DA system on Emondlo NB 125 is configured to
backfeed customers that are affected by Zone 1 faults
(including Dagbreek NB 4 Zone 1 and St James NB 108
Zone 1) an analysis is required to show what KPI benefits the
system provides to the business. The performance evaluation
of all three networks is shown in Figure [11]. The three
graphs highlights Maintenance and Overhead Power Line
fault CID losses seen from January 2010 to December 2011
on the Emondlo, Dagbreek and St James networks.
(11a)
(11b)
(11c)
Figure [11]: Zone 1 CID Losses for the 3 networks (2010-11)
The DA system is only applicable for line faults and excludes
maintenance related outages. In order to realize the benefit of
implementing the DA system one needs to work out the
amount of customers restored immediately by a fault in Zone
1. One must keep in mind that under normal conditions (no
DA system) a fault in Zone 1 on any of the three networks
would mean an operator driving out and closing in N/O
points (in order to restore supply to unaffected customers).
This drive from Vryheid TSC to either N/O point (S57 and
S1151) is approximately 1 hour which is an unnecessary loss
of time, resource and customer revenue.

6. Table [3]: Customers restored by Zone 1 fault
Table [3] shows the amount of customers restored on all three
networks when there is a Zone 1 fault. For example when
there is a fault on Emondlo 125 on Zone 1, the DA system
automatically restores 3443 customers via the tie breakers
leaving only 2264 customers without supply. Figure [12]
below shows the CID losses incurred with and without the
DA system. A cost study is shown in the figures [13, and 14]
which shows the loss in remuneration due to Zone 1 faults in
the last 2 years. Note that all fault events above 2 minutes
was used in the calculation.
Figure [12]: CID losses with and without DA System
Figure [13]: Loss of Revenue for unplanned Zone 1 faults
Figure [14]: Cost of DA System vs Revenue Saved
Utilizing the last two years of performance data the following
SAIDI (System Average Interruption Duration Index)
reductions were calculated with the DA system:
• 61% SAIDI reduction on Emondlo NB 125
• 32% SAIDI reduction on St James NB 108
• 29% SAIDI reduction on Dagbreek NB 4
The revenue lost for Zone 1 trips in the past two years was R
122 614.00. Approximating a lost revenue of R61000 a year
we see that the cost of implementing the DA system is made
up within 14-15 years which is the within the life cycle of 25
years.
V. CONTROLLER INTERACTION
The DA system does require some human intervention once
in operation. The intervention is needed when the faulted
section of line is repaired and normalising is required.
Controllers located in Network Management will have to
perform the following duties as seen in the flowchart below:
Permanent Fault
Operator:
Sectionalises
Affected Section of
Line
Fault
Repaired
Controller:
Disables DA on
Tie Breaker/s
Controller: Open
Tie Breaker/s
Controller: Closes
Network Breaker
(where applicable)
Controller:
Restores DA on
Tie Breaker/s
Controller: Closes
Feeder Breaker/s
End
Y
N

7. VI. CONCLUSION
Implementing the Distribution Automation system on
Emondlo NB 125 will have a great impact on SAIDI
reductions and improvement on customer restoration times.
From the historical performance data the following SAIDI
(System Average Interruption Duration Index) reductions
were calculated with the DA system online:
• 61% SAIDI reduction on Emondlo NB 125
• 32% SAIDI reduction on St James NB 108
• 29% SAIDI reduction on Dagbreek NB 4
The methodology discussed in this paper for selecting a
suitable feeder can be adapted for various MV networks and
should be engineered for broad implementation across the
Eastern Region. The detailed design of the Distribution
Automation System for Emondlo NB 125 was completed and
approved by Project Engineering. The project is currently at
execution stage and will go online at the end of October
2012. There are other DA technologies used such as FLISR
(Fault location, isolation, and service restoration) applications
which utilize decentralized, substation, or control center
intelligence to locate, isolate, reconfigure, and restore power
to healthy sections of a circuit. Implementation of the FLISR
technology utilizing DMS is currently being researched in the
Eastern Region.
VII. ACKNOWLEDGMENT
The author wishes to thank the IEEE for providing this
template and all colleagues who previously provided
technical support. These colleagues include:
Kevin Pillay (Plant Manager)
Mohammed Essop (EDNO_NWC)
Madoda Xulu (EDNS_Settings)
Kacey Maharaj (EDNO_PMB)
Dayahalan Chetty (EDNO Manager)
Rakeen Bhoola (TSG Test and Cables Manager)
Claude Packree (Plant HOPE_Margate)
Kevin Bouwer (Plant QA Manager)
Mohamed Khan (T&Q_Sub Tx)
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