Federal Democratic Republic of Ethiopia
Ministry of Defense
Defense University, College of Engineering
Office of Postgraduate Programs and Research
M-Tech Thesis
Thesis Title: Designing of an Improved Distribution Substation to Mitigate the
Power Reliability at Bishoftu City
By
Behailu Abebe
Supervisor: Dr.-Ing. Getachew Biru Worku
Department: Electrical power Engineering
Specialization: Electrical Power and Automation
Sep.2014
Bishoftu, Ethiopia
CERTIFICATION
I the undersigned, certify that I read and hereby recommend for the acceptance by Defense Engineering
College a thesis entitled “Designing of an Improved Distribution Substation to Mitigate the Power
Reliability at Bishoftu City” submitted by Behailu Abebe in partial fulfillment of the requirements
for the Degree of Masters of Technology in Electrical Power System and Automation Engineering.
Major Advisor: _____________________________
M-Tech Thesis, Defense Engineering College, 2014
Date________________________
I
DECLARATION
I, Behailu Abebe, declare that this thesis is my own original work and it has not been presented and
will not be presented by me to any other university for similar or any other degree award.
Signature ___________________________________ date _____________________
M-Tech Thesis, Defense Engineering College, 2014
II
Dedicated to my family
M-Tech Thesis, Defense Engineering College, 2014
III
ACKNOWLEDGEMENTS
First, my appreciation and gratitude to my major supervisor, Dr.Ing.Getachew Biru, for his enthusiastic
effort, invaluable and stimulating guidance and constructive comments. His work rate and commitment
has been a source of inspiration.
I would like to thank those workers of EEPCO at Bishoftu Substation II and Distribution District and
also at the central region, who helped me to collect the necessary data from the organizations.
Finally, my family and friends have been a persistent source of encouragement not only during the
thesis work but also throughout my academic career. I want them to know that I respect and always
keep in my memory their boundless and invaluable support, beyond a simple thank you.
Above and foremost, thanks to the Almighty God for granting me his limitless care, love and blessings
all along my way.
M-Tech Thesis, Defense Engineering College, 2014
IV
TABLE OF CONTENTS
Contents
Page No.
CERTIFICATION .................................................................................................................................. i
DECLARATION ................................................................................................................................... ii
ACKNOWLEDGEMENTS .................................................................................................................. iv
TABLE OF CONTENTS ........................................................................................................................v
LIST OF TABLES .............................................................................................................................. viii
LIST OF FIGURES .............................................................................................................................. ix
LIST OF ABBREVIATIONS .................................................................................................................x
ABSTRACT ......................................................................................................................................... xii
CHAPTER ONE .....................................................................................................................................1
INTRODUCTION ..................................................................................................................................1
1.1 Background ..............................................................................................................................1
1.2 Statement of the Problem .........................................................................................................1
1.3 Objectives of the Study ............................................................................................................2
1.3.1 General Objective ................................................................................................. 2
1.3.2 Specific Objectives ............................................................................................... 2
1.4 Materials and Methods .............................................................................................................3
1.4.1 Data Sources ......................................................................................................... 3
1.4.2 Methodology ......................................................................................................... 3
1.4.3 Simulation Software Dig Silent Power Factory 14.1 ............................................ 3
1.5 Significance of the Study .........................................................................................................4
1.6 Description of the Study Area ..................................................................................................4
1.7 Outline of the Thesis ................................................................................................................6
CHAPTER TWO ....................................................................................................................................7
LITERATURE REVIEW AND THEORETICAL BACKGROUND ....................................................7
2.1 Theoretical Background ...........................................................................................................7
2.1.1 Electrical Substation ............................................................................................. 7
2.1.2 Distribution Substation ......................................................................................... 7
2.1.3 Substation Design ................................................................................................. 8
2.1.4 Substation Layout ................................................................................................. 8
2.1.5 Switching Function ............................................................................................... 9
2.1.6 Load .................................................................................................................... 10
2.2 Distribution Substation Protection Needs ..............................................................................10
2.3 Distribution Substation Construction Methods ......................................................................11
2.4 Distribution Substation Reliability Configurations ................................................................11
2.5 Implementation of Distribution Automation System .............................................................14
2.5.1 Benefits of Distribution Automation System Implementation ........................... 14
2.6 Reliability Analysis of Electrical Power System ...................................................................15
2.6.1 Definition of Reliability ...................................................................................... 15
2.7 Electricity Service Interruptions.............................................................................................17
2.7.1 Terminology Related to Interruptions ................................................................. 18
2.7.2 Interruption Characteristics ................................................................................. 19
2.7.3 Momentary and Sustained Interruptions ............................................................. 19
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2.7.4 Planned and Unplanned Interruptions ................................................................. 20
2.8 Power System Reliability Indices ..........................................................................................20
2.9 Economics of Reliability Assessment ....................................................................................23
2.10
Review of Related Current Research Works ......................................................................26
CHAPTER THREE ..............................................................................................................................28
EVALUATION AND ANALYSIS OF THE EXISTING SUBSTATION ..........................................28
3.1 Description of Bishoftu Substation II.....................................................................................28
3.2 Reliability Related Data’s of Bishoftu Substation II ..............................................................34
3.3 Calculated Values of Selected Reliability Indices .................................................................38
3.4 Comparison of the calculated values of reliability indices with different standards .............41
CAHPTER FOUR .................................................................................................................................45
UPGRADING OF THE DISTRIBUTION SUBSTATION .................................................................45
4.1 The Need for Upgrading the Bishoftu Substation ..................................................................45
4.2 Estimation of Future Load......................................................................................................45
4.3 Substation Arrangement Selection .........................................................................................47
4.4 Specification of the Major Substation Equipment .................................................................48
4.4.1 Selection of Power Transformer ......................................................................... 49
4.4.2 Voltage Drop at Transformers ............................................................................ 49
4.4.3 Selection of Transformer Feeders ....................................................................... 50
4.4.4 Current Rating Calculations ................................................................................ 50
4.4.5 Voltage Drop Calculations .................................................................................. 51
4.4.6 Fault Current Calculations .................................................................................. 52
4.4.7 Selection of Bus Bars .......................................................................................... 56
4.4.8 Selection of Circuit Breakers .............................................................................. 57
4.4.9 Selection of Surge Arresters ............................................................................... 58
4.4.10 Selection of Isolators........................................................................................... 59
4.4.11 Selection of Current Transformers (CTS)........................................................... 60
4.4.12 Selection of Potential Transformer (PT) ............................................................. 61
4.4.13 Selection of RTU and computers ........................................................................ 62
4.5 Earth Mat Design ...................................................................................................................62
4.5.1 Resistivity of a Soil ............................................................................................. 63
4.5.2 Resistance of the Human Body ........................................................................... 64
4.5.3 Grid current calculation ...................................................................................... 64
4.5.4 Earth Conductor Sizing ....................................................................................... 65
4.5.5 Grid Resistance Calculation ................................................................................ 67
4.5.6 Calculation of Attainable Touch and Step Potential ........................................... 68
4.5.7 Calculation of Tolerable Touch and Step Voltage .............................................. 71
4.6 Distribution Substation Layout ..............................................................................................72
CHAPTER FIVE ..................................................................................................................................74
SIMULATION RESULTS AND DISCUSSION .................................................................................74
5.1 Introduction ............................................................................................................................74
5.2 Stochastic Failure Models ......................................................................................................75
5.3 Simulation Result of the Existing Substation .........................................................................78
5.4 Simulation Result of the Designed Substation .......................................................................82
5.5 Discussion ..............................................................................................................................85
5.6 Economic Aspects of the Designed System ...........................................................................86
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5.6.1 Interruption Costs to Customers ......................................................................... 87
CHAPTER SIX .....................................................................................................................................88
CONCLUSIONS, RECOMMENDATIONS AND FUTURE WORKS ..............................................88
6.1 Conclusions ............................................................................................................................88
6.2 Recommendations ..................................................................................................................89
6.3 Future Work ...........................................................................................................................89
REFERENCE ........................................................................................................................................90
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VII
LIST OF TABLES
Table
Page No
Table 1 power transformer at the substation ................................................................................. 5
Table 2. The compiled data of the substation feeders ................................................................... 29
Table 3. Annual average energy and power consumption of each feeder bus bar ....................... 30
Table 4. Type and number of connected customers ...................................................................... 30
Table 5. Average Hourly Load (MW) of Each Feeder of BishoftuSubstation II........................... 31
Table 6. Frequency of interruptions ............................................................................................ 34
Table 7. Duration of interruption ................................................................................................. 35
Table 8.The average frequency and duration of interruptions per year....................................... 35
Table 9. The percentage of the causes of the average unplanned and planned interruptions ..... 36
Table 10. Calculated SAIFI value for each feeder and the system .............................................. 39
Table 11. Calculated CAIFI value for each feeder and the system .............................................. 40
Table 12 Calculated SAIDI value for each feeder and the system ............................................... 41
Table 13. Summary of comparisons of reliability indices............................................................. 44
Table 14: Power demand forecast for of Bishoftu city from 2014-2038 ...................................... 46
Table 15. Technical specification of selected power transformer ................................................ 49
Table 16. Ratings of Bus-bars within the guidelines of ANSI/IEEE Std.C37.20.2 ....................... 57
Table 17. Ratings of Circuit Breaker ............................................................................................ 58
Table 18. Ratings of Surge Arresters ............................................................................................ 59
Table 19. Ratings of Isolators ....................................................................................................... 60
Table 20. Ratings of Current Transformers .................................................................................. 61
Table 21. Ratings of Voltage Transformers .................................................................................. 61
Table 22: Ratings for RTU ............................................................................................................ 62
Table 23: Basic Range of Soil Resistivity Ref. IEEE Std. 80 ........................................................ 63
Table 24. Typical Values of DfRef. IEEE Std. 80-2000 ................................................................ 65
Table 25. Material constants Ref. IEEE Std. 80-2000 .................................................................. 66
Table 26: Bus Bar/Terminal Stochastic Model ............................................................................. 76
Table 27: Line/Cable Stochastic Model ........................................................................................ 76
Table 28: Transformer Stochastic Model ..................................................................................... 77
Table 29.Output of system reliability indices for the existing system ........................................... 80
Table 30.The Bus bar/ terminal indices of existing system ........................................................... 81
Table 31.The load point indices of the existing substation ........................................................... 81
Table 32 output of reliability indices for the designed system...................................................... 83
Table 33.The Bus bar/ terminal indices of designed system ......................................................... 84
Table 34.The load point indices of the designed substation ......................................................... 84
Table 35 Selected simulation results for comparison ................................................................... 85
Table 36 EEPCOS tariff for different applications....................................................................... 86
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VIII
LIST OF FIGURES
Figure
Page No
Figure 1.The general view of Bishoftu substation II....................................................................... 5
Figure 2.Oil circuit breakers and control room of Bishoftu substation II...................................... 6
Figure 3 single line diagram of substation ..................................................................................... 9
Figure 4. Single bus bar Configuration [52] ................................................................................ 12
Figure 5. Double bus configuration [52] ..................................................................................... 12
Figure 6. Double bus bar configuration with U form [52]........................................................... 13
Figure 7. Double bus bar with bypass configuration [52] ........................................................... 14
Figure 8. Ring configuration [52] ................................................................................................ 14
Figure 9.Bishoftusubstation drawn using Dig-Silent power factory software ............................. 28
Figure 10.Average residential Load (MW) of Each Feeder of Bishoftu Substation II ................. 32
Figure 11.Average total residential Load (MW) of Bishoftu Substation II .................................. 32
Figure 12. Average Industrial Load (MW) of Each Feeder of Bishoftu Substation II ................. 33
Figure 13 Average total Industrial Load (MW) of Bishoftu Substation II.................................... 33
Figure 14. Percentage (%) of Frequency of Interruptions of the Overall System ........................ 37
Figure 15. Percentage (%) of Duration of Interruption s of the Overall System ......................... 37
Figure 16. Comparison of the SAIFI value with different standards ........................................... 42
Figure 17. Comparison of the CAIFI value with different standards ........................................... 42
Figure 18 Comparison of the SAIDI value with different standards ............................................ 43
Figure 19: Double bus bar arrangement of substations............................................................... 48
Figure 20.Rectangular Ground Grid system with 44 ground rods ............................................... 67
Figure 21 complete single line diagram of the designed system .................................................. 73
Figure 22: flow chart for Reliability assessment using Dig silent software ................................. 75
Figure 23 switching configuration in the existing system ............................................................ 77
Figure 24. Switching configuration in the designed system ......................................................... 78
Figure 25 the existing substation .................................................................................................. 79
Figure 26 the layout of the new designed substation .................................................................... 82
Figure 27 comparing results of simulation................................................................................... 85
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IX
LIST OF ABBREVIATIONS
A
Ampere
AAC
All Aluminum Conductors
AC
Alternating Current
ACCI
Average Customer Curtailment Index
AENS
Average Energy Not Supplied Index
ALIDI
Average Load Interruption Duration Index
ALIFI
Average Load Interruption Frequency Index
AMI
Advanced Metering Infrastructure
AMR
Automatic Meter Reading
ASAI
Average Service Availability Index
ASUI
Average Service Unavailability Index
CAIDI
Customer Average Interruption Duration Index
CAIFI
Customer Average Interruption Frequency Index
DNP3
Distributed Network Protocol
DPEF
Distribution Permanent Earth Faults
DPSC
Distribution Permanent Short Circuit
DTEF
Distribution Temporary Earth Faults
DTSC
Distribution Temporary Short Circuit
DTSC
Distribution Temporary Short Circuit
DUR
Duration of Interruptions
E.C
Ethiopian Calendar
EEA
Ethiopia Eclectic Agency
EEPCO
Ethiopian Electric Power Corporation
ENS
Energy Not Supplied Index
FRE
Frequency of Interruptions
G.C
Gregorian Calendar
M-Tech Thesis, Defense Engineering College, 2014
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H
hour
Hz
Hertz
ICS
Interconnected System
IEC
International Electro technical Commission
IEEE
Institute of Electrical and Electronics Engineers
Int
interruption
kV
Kilo Volt
L
Load
LDF
Load factor
MVA
Mega Volt Ampere
MVAr
Mega Volt Ampere Reactive
MW
Mega Watt
OPR
Operational
P
Active Power
Pf
power factor
Q
Reactive Power
RC
Recloser Control
RTU
Remote Terminal Unit
SAIDI
System Average Interruption Duration Index
SAIFI
System Average Interruption Frequency Index
SCADA
Supervisory Control and Data Acquisition
T
Time of Interruption
U
Duration of Interruption
W
Watt
Yr
Year
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XI
ABSTRACT
This thesis work is a study about Designing of an Improved Distribution Substation to Mitigate the
Power Reliability at Beshoftu City. The first task of the study is evaluating the reliability of the existing
distribution system by collecting and analyzes data from Bishoftu substation II and calculating the most
powerful reliability indices. This calculated reliability indices are then compared with the EEPCO’s
standard and the standard of other countries. As this study indicates, the existing power distribution
system of the city has many problems. The main problems are high level of unreliability, low energy
management, poor scheduled maintenance and operation. To address the challenges of the existing
distribution system, designing of an improved substation has been proposed as a solution to tackle the
problem.
The new design can be considered as a modern distribution substation which includes automatic
reclosing systems to minimize the durations of interruptions, remote telemetry units to communicate
with the control room and load dispatch center and the grounding grid system for safety of personals
and equipment in the substation. The design process starts from forecasting the future load of the
substation and includes detail procedure of fault current and voltage drop calculations, selection of the
major substation equipment, selection of protection devices and the earth mat design.
The study utilized different meteorological and statistical data and software like MS-Excel, Dig Silent
AutoCAD and ETAP Simulation, design and Optimization Software. The simulation is used to evaluate
the designed power distribution substation to ascertain that, it produces the desired reliability
improvements. The result of the simulation shows that the designed system can advance the reliability
of the overall system by improving the reliability indices values. These improvements are 75% in SAIFI
value, 70% in SAIDI value, 77% in ENS value and 97% in MAIFI value. And also, the EEPCO’s
revenue can be increased by 78% for that area by reducing the energy not supplied (ENS) due to
interruptions.
Key words: Reliability, Distribution substation, Existing system, designed system, Dig SILENT, ETAP.
M-Tech Thesis, Defense Engineering College, 2014
XII
CHAPTER ONE
INTRODUCTION
1.1 Background
The power distribution system is made up of transformers, poles and wire seen in neighborhoods
circuits. Distribution substations monitor and adjust circuits within the system. The distribution
substations in Ethiopia lower the transmission line voltages to 33 kV and 15 kV or less. The voltage is
then further reduced by distribution transformers to the utilization voltages of 380 volts three-phase or
220 volts single-phase supply required by most users.
Substations are fenced yards with switches, transformers and other electrical equipment. Once the
voltage has been lowered at the substation, the electricity flows to industrial, commercial, and
residential centers through the distribution system. Conductors called feeders reach out from the
substation to carry electricity to customers. At key locations along the distribution system, voltage is
lowered by distribution transformers to the voltage needed by customers or end-users.
Electric distribution system power quality is a growing concern. Customers require higher quality
service due to more sensitive electrical and electronic equipment. The effectiveness of power
distribution system is measured in terms of efficiency, service continuity or reliability, service quality
in terms of voltage profile and stability and power distribution system performance.
In the context of Ethiopia, electric power interruption is becoming a day to day phenomenon. Even
there are times that electric power interruption occurs several times a day, not only at the low voltage
but also at the medium voltage distribution systems.
The drop of the voltage, especially at the residential loads, is causing early failure of equipment,
blackening of light bulbs, and decreased efficiency and performance of high-power appliances.
Damage of electronic devices and burning of light bulbs have also occurred due to over voltages.
1.2 Statement of the Problem
Ethiopian Government is currently making all rounded effort to change the country’s economic status
from the current least developed level to a medium income level. Of the many aspects of this effort,
expanding and strengthening of the electric power supply sector is one among the most emphasized
economic dimensions.
Since Bishoftu city is one of selected areas as the industry zone by the government and is near to the
capital city (Addis Ababa) this makes the city a preferred location for most of the industries in the
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country, and hence considerable share of the electric power supply is supplied to the city. But, electric
power interruption is becoming a day to day phenomenon. Even there are times that electric power
interruption occurs several times a day, not only at the low voltage but also at the medium voltage
distribution systems.
Considering this fact, in this thesis work, a comprehensive investigation of Bishoftu’s power
distribution problem will be conducted. Based on the result of the investigation, design and
performance improvement measures will be identified and considered which can be used as proto-type
to be implemented for other areas as well.
Electrical power distribution is one among the major parts in Power System. Thus, the thesis work will
investigate all the problems to the power distribution and also will cover all the technical design aspects
of the power distribution. At the same time, the design tries to make a balanced optimization between
up-to-date technology use and cost of constructing the power distribution system. In doing so, it is
assumed that the thesis will have a positive contribution to the improvement on the reliability of power
distribution system of the city.
1.3 Objectives of the Study
1.3.1 General Objective
The main objective of this thesis work is to investigate and address the problems that consumers face
due to the present state of the power distribution problem in the city, and recommend ways to better
the situation through a design of the power distribution system.
1.3.2 Specific Objectives
The specific objectives of this work are:
 To investigate the power distribution problems that arise from both the customer side and
the electric utility side, at selected substations,
 To forecast future loads of the city.
 To design an improved power distribution system which is capable of solving the identified
problems
 To estimate the economic impact of the designed system.
 Evaluate the designed power distribution system to ascertain that it produces the desired
reliability improvements.
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1.4 Materials and Methods
1.4.1 Data Sources
Collecting the required data of different type was also one of the initial tasks in the study. Various data,
software and methodologies have been employed throughout the performance of this thesis. A range
of books, manuals, standards and researches, some of which are listed in the literature review, have
been referred.
The major data source for this work is EEPCO, since it is the only supplier in the country, then the
interruption data, the power supply and other related data are collected from the Bisoftu city substation
and EEPCO central office at Addis Ababa city.
1.4.2 Methodology
Due to the nature of the study, it is started by reviewing literatures related to power distribution and
reliability issues. The data collected from the field work is then analyzed. For the evaluation of the
system, power simulation software (like dig silent, auto cad, Visio etc.) are utilized. Generally the
following methodology is followed in conducting the thesis work;
 Site visit
 Technical data collection at selected substation Investigation of power distribution
problems and reliability problems for power distribution systems in the city
 Estimate the load of the system
 Design of power distribution substation
 Analyzing the economic feasibility of the designed system
 Simulation of the reliability improvements
1.4.3 Simulation Software Dig Silent Power Factory 14.1
The calculation program Power Factory, as written by Dig SILENT, is a computer aided engineering
tool for the analysis of transmission, distribution, and industrial electrical power systems. It has been
designed as an advanced integrated and interactive software package dedicated to electrical power
system and control analysis in order to achieve the main objectives of planning and operation
optimization.
The name Dig SILENT stands for "Digital Simulation and Electrical Network calculation program''.
Dig SILENT Version 7 was the world's first power system analysis software with an integrated
graphical single-line diagram interface. In order to meet today's power system analysis requirements,
the Dig SILENT Power Factory power system calculation package was designed as an integrated
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engineering tool which provides a complete 'walk-around' technique through all available functions,
rather than a collection of different software modules. The following key-features are provided by the
program:
1. Integrated interactive single line graphic and data case handling
2. Power system element and base case database
3. Integrated calculation functions (e.g. line and machine parameter calculation based
4. on geometrical or nameplate information)
5. Power system network configuration with interactive or on-line access to the SCADA
system
6. Generic interface for computer-based mapping systems
1.5 Significance of the Study
This study will be a detailed investigation of the general features of the power distribution problems of
Bishoftu and a complete recommendation with a complete design of power distribution system by
including detailed assessment of the power distribution and making an economic analysis of the
designed system. And this result can be recommended to EEPCO for implementation at Bishoftu
substation or other substations throughout the country as required.
1.6 Description of the Study Area
Bishoftu city is situated in West Shewa, Oromiya, Ethiopia; its geographical coordinates are 9° 6' 0"
North, 37° 15' 0" East. Since the location of bishoftu city is near to the capital city the Ethiopian
government selects the city to be one of the industry zones in country. The city has also different natural
resources which attract tourists come to the country, so it is also a place where different hotels and
resorts are under construction. Bishotu substation II is located at Bishoftu town which is the main
substation to supply Bishaftu town and small towns near to Bishoftu including Dire town, Amerti,
Minjar and partial load of Dukem town. And there are many industries supplied from the substation.
The incoming line from Kality substation which is called Koka tap carrying 132 KV is the input of the
substation. Inside this substation there are three power transformers to convert the 132KV to 33KV
and 15KV distribution voltage levels.
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Table 1 power transformer at the substation
Transformer 1
Transformer 2
Transformer 3
Type
2 winding
3 winding
2 winding
MVA
16/20
16/8/8
16/20
HV/MV/LV
132KV/15KV
132KV/33KV/15KV
132KV/15KV
This distribution substation is currently arranged in radial arrangement. The control and protection
systems are also included, in the control room there are old type oil circuit breakers which are shown
in Figure 2 and the control room is not well equipped, as there is no even one PC and all data collections
and communications are done manually.
Figure 1 and 2 are taken during site visit and data collection at Bishoftu Substation II and shows the
transformers bus bars and control room.
Figure 1.The general view of Bishoftu substation II
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Figure 2.Oil circuit breakers and control room of Bishoftu substation II
1.7 Outline of the Thesis
In this section, the outline of the thesis is presented. The thesis consists of 6chapters, which are briefly
summarized below.
Chapter 1 provides the background, the statement of the problem, objectives and methodologies of the
study.
Chapter 2 provides the literature review and the theoretical hints about power system reliability.
Furthermore; it describes different mathematical descriptions of reliability indices.
Chapter 3 presents data collected from the existing substation and the calculated results of reliability
indices.
Chapter 4 presents the designing of an upgraded substation, with major substation equipment
specifications and some design calculations are included as well in this chapter.
Chapter 5 describes the simulation and simulation result performed using the Dig silent power factory
software.
Chapter 6 gives the conclusion and recommendations drawn from the research to impact the reliability
of the system
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CHAPTER TWO
LITERATURE REVIEW AND THEORETICAL BACKGROUND
2.1 Theoretical Background
2.1.1 Electrical Substation
An electrical substation is a subsidiary station of an electricity generation, transmission and
distribution system where voltage is transformed from high to low or the reverse using transformers.
Electric power may flow through several substations between generating plant and consumer, and may
be changed in voltage in several steps. A substation that has a step-up transformer increases the voltage
while decreasing the current, while a step-down transformer decreases the voltage while increasing the
current for domestic and commercial distribution [52]
Substations generally have:
 Switching equipment
 Protection equipment
 Control equipment
 One or more transformers
In a large substation circuit breakers are used to interrupt any short-circuits or over load currents that
may occur on the network. In smaller distribution stations Recloser circuit breakers or fuses may be
used for protection of distribution circuits. Other devices such as capacitors and voltage regulators may
also be located at a substation. Substations may be on the surface in fenced enclosures, underground,
or located in special-purpose buildings [52].
2.1.2 Distribution Substation
A distribution substation transfers power from the transmission system to the distribution system of an
area. The input for a distribution substation is typically at least two transmission or sub transmission
lines. Distribution voltages are typically medium voltage, between 2.4 kV and 33kV depending on the
size of the area served and the practices of the local utility. Besides changing the voltage, the job of the
distribution substation is to isolate faults in either the transmission or distribution systems. Distribution
substations may also be the points of voltage regulation, although on long distribution circuits (several
km/miles), voltage regulation equipment may also be installed along the line. Complicated distribution
substations can be found in the downtown areas of large cities with high-voltage switching and backup
systems on the low-voltage side [52].
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2.1.3 Substation Design
The main considerations taking into account during the design process are [52]:
1. Reliability
2. Cost (sufficient reliability without excessive cost)
3. Expansion of the station.
Selection of the location of a substation must consider many factors: [52]
 Sufficient land area
 Necessary clearances for electrical safety
 Access to maintain large apparatus such as transformers.
 The site must have room for expansion due to load growth or planned transmission
additions.
 Environmental effects (drainage, noise and road traffic effects).
 Grounding must be taking into account to protect passersby during a short circuit in
the transmission system.
 The substation site must be reasonably central to the distribution area to be served.
2.1.4 Substation Layout
The first step in planning a substation layout is the preparation of a one-line diagram which shows in
simplified form the switching and protection arrangement required, as well as the incoming supply
lines and outgoing feeders or transmission lines [51].
One-line diagram should include principal elements:
 Lines
 Switches
 Circuit breakers
Transformers Incoming lines should have a disconnect switch and a circuit breaker. A disconnect
switch is used to provide isolation, since it cannot interrupt load current. A circuit breaker is used as a
protection device to interrupt fault currents automatically. Both switches and circuit breakers may be
operated locally or remotely from a supervisory control center [45, 51 and 52].
Following the switching components, the lines are connected to one or more buses. An electrical bus,
derived from bus bar, is a common electrical connection between multiple electrical devices.
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Figure 3 single line diagram of substation
The thick line is the bus, which represents three wires. The slash through the bus arrow and the "3"
means that the bus represents 3 wires The arrangement of switches, circuit breakers and buses used
affects the cost and reliability of the substation. For important substations a ring bus or double bus.
Substations feeding only a single industrial load may have minimal switching provisions. Once having
established buses for the various voltage levels, transformers may be connected between the voltage
levels. These will again have a circuit breaker in case a transformer has a fault. A substation always
has control circuitry to operate the various breakers to open in case of the failure of some component.
[51]
2.1.5 Switching Function
Switching is the operation of connecting and disconnecting of transmission lines or other components
to and from the system. Switching events may be "planned" or "unplanned". A transmission line or
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other component may need to be de energized for maintenance or for new construction. To maintain
reliability of supply, it is not cost efficient to shut down the entire power system for maintenance. All
work to be performed, from routine testing to adding entirely new substations, must be done while
keeping the whole system running. Also, a fault may develop in a transmission line or any other
component. The function of the substation is to isolate the faulted portion of the system in the shortest
possible time.
2.1.6 Load
The size of the load to be served determines the capacity of the substation. The load must be distributed
such that it can be served with reasonable feeder loss or more. Critical loads (industrial districts) are
served by more complex substations, designed for maximum reliability and speed of power restoration
compare to the ones used in residential areas where a short time power loss is usually not a disaster.
Other substations in the area influence the design of a new substation. The presence of other substations
will increase the overall power capacity and as a result can satisfy the demand for heavy loads.
Substations for critical loads usually use more than one transformer so that the load is served even if
one transformer is out. Otherwise a single large three-phase transformer is used because it costs less
per kVA of capacity, and requires less room, bussing, and simpler protective relaying.
2.2 Distribution Substation Protection Needs
Distribution Substation needs a minimum protection to avoid injury to people and damage to
equipment. The level of protection of a substation is determined by how critical the loss of power is to
the load. The loss of electrical power to a hospital is very serious while the loss of power to a residence
is inconvenient. In the event of a fault the hospital electricity must be restored in the shortest amount
of time possible while the residence can be without electricity several hours without serious
consequences. Equipping a substation with automatic switching to restore power when it is lost and to
assure the least possible damage and repair time after a fault is expensive [51].For example, a small
substation at the end of a radial sub transmission line that might be used to serve a small group of
residences consists of two dead end poles to terminate the lines, two manual non-load break switches,
and primary fusing. This substation can be used to serve a small commercial area. It has a circuit
breaker as well as a primary fuse for back up, and more disconnect switches for isolation during
maintenance. The circuit breaker will operate from relays that require a metal clad enclosure,
instrument transformers, and a DC power supply for the trip circuit. The increased speed of fault
removal supplied by the circuit breaker for this substation has substantially increased its cost. Both
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substations are simple single-source, single-transformer, and single-feeder types. The cost differences
increase with the size of the substation, and the size and number of transformers used [51].
2.3 Distribution Substation Construction Methods
Four basic methods exist for substation construction:
 Wood
 Steel lattice
 Steel low profile
 Unit.
Wood pole substations are inexpensive, and can easily use wire bus structures. Wood is suitable only
for relatively small, simple substations because of the difficulty of building complex bus and switch
gear support structures from wood. Lattice steel provides structures of low weight and high strength.
Complex, lattice steel is reasonably economical and is the preferred material for substation construction
whenever possible. Solid steel low profile substations are superior to lattice or wood constructed
substations. However, low profile construction is more expensive than either wood or lattice steel, and
requires more land because multilevel bus structures cannot be used. The unit substation is a relatively
recent development. A unit substation is factory built and tested, then shipped in modules that are
bolted together at the site. Unit substations usually contain high and low voltage disconnect switches,
one or two three-phase transformers, low voltage breakers, high voltage fusing, bus work, and
relays[49,51,52].
2.4 Distribution Substation Reliability Configurations
 Single bus bar configurations
The single bus bar scheme has only one three-phase but to which the various incoming and outgoing
circuits are connected as shown in Figure 4. It is not preferred for major substation. It lack operational
flexibility and in case of bus fault or CB failure the entire bus has to be de-energized.
Merits of single bus bar system are:
 low cost
 simple to operate
 simple protection
Demerits of single bus bar system are:
 fault of bus or any CB results entire shut down of substation
 difficult to do maintenance and extend the circuit without completely de-energize
substation
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 can be used only load can be interrupted or have other supply arrangements
Its application is for LV, MV bus bar
Figure 4. Single bus bar Configuration [52]
 Double bus configuration
This scheme has two main buses connected to each line CB and a bus tie (coupler) breaker. This allows
the transfer of line circuits from bus to bus by means of isolator. Figure 5 shows this scheme. This
arrangement allows the operation of the circuit from either bus. The failure in one bus will not affect
the other bus; however a bus tie CB failure will cause the outage of the entire system.
Figure 5. Double bus configuration [52]
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
Double bus bar configuration with U form
This scheme provides a very high level of reliability by having two separate breakers available to each
circuit. In addition, with two separate buses, failure of a single bus will not impact either line.
Maintenance of a bus or a circuit breaker in this arrangement can be accomplished without interrupting
either of the circuits. This scheme is high cost arrangement Figure 6 shows double bus bar configuration
with U form
Figure 6. Double bus bar configuration with U form [52]
 Double bus bar with bypass configuration
This scheme is a combination of the double bus system and transfer bus scheme. It has two main buses
and one transfer bus. This scheme is costlier and requires larger space. Therefore it is used in very
important substitution of 220kV and above voltage and when more number of circuit connections is
required. Figure 7.shows this scheme
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Figure 7. Double bus bar with bypass configuration [52]
 Ring (Mesh) bus system
In this scheme, as indicated by the name, all breakers are arranged in a ring with circuits tapped between
breakers. Figure 8 shows this bus system. Reliability of this scheme is higher, however the relaying is
more complex and expansion is limited
Figure 8. Ring configuration [52]
2.5 Implementation of Distribution Automation System
2.5.1 Benefits of Distribution Automation System Implementation
The benefits of distribution automation system implementation can be classified in three major areas
as follows:
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 Operational & Maintenance benefits[47,49]
1. Improved reliability by reducing outage duration using auto restoration scheme
2. Improved voltage control by means of automatic VAR control
3. Reduced man hour and man power
4. Accurate and useful planning and operational data information
5. Better fault detection and diagnostic analysis
6. Better management of system and component loading
 Financial benefits [47,49]
1. Increased revenue due to quick restoration
2. Improved utilization of system capacity
3. Customer retention for improved quality of supply
 Customer related benefits [47,49]
1. Better service reliability
2. Reduced interruption cost for Industrial/Commercial customers
3. Better quality of supply
 Areas of Distribution Automation System Implementation [47,49]
The area distribution automation system can be divided in to two areas:
1. Distribution Substation & Feeder Automation
2. Consumer Location Automation
2.6 Reliability Analysis of Electrical Power System
2.6.1 Definition of Reliability
Power reliability can be defined as the degree to which the performance of the elements in a bulk
system results in electricity being delivered to customers within accepted standards and in the amount
desired. The reliability of the interconnected bulk power system is defined in two ways.
1. Adequacy: The ability of the electric systems to supply the aggregate electrical demand and
energy requirements of their customers at all times, taking into account scheduled and
reasonably expected unscheduled outages of system elements; and
2. Security: The ability of the electric systems to withstand sudden disturbances such as electric
short circuits or unanticipated loss of system elements.
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In brief, reliability has to do with total electric interruptions and complete loss of voltage, not just
deformations of the electric sine wave. Reliability does not cover sags, swells, impulses or harmonics.
Reliability indices typically consider such aspects as [3, 12, 27 and 30]:
 The number of customers;
 The connected load;
 The duration of the interruption measured in seconds, minutes, hours, or days;
 The amount of power (kVA) interrupted; and
 The frequency of interruptions.
Power reliability can be defined as the degree to which the performance of the elements in a bulk
System results in electricity being delivered to customers within accepted standards and in the amount
desired. The degree of reliability may be measured by the frequency, duration, and magnitude of
adverse effects on the electric supply. [3, 12, 27 and 30]:
There are many terms and definitions used in reliability engineering. Some of the frequently used terms
and definitions are presented below [3, 12, and 30]:
 Reliability (𝐑(𝐭)): This is the probability that an item will carry out its assigned mission
satisfactorily for the stated time period when used under the specified conditions. Or Reliability
refers to the probability that a component experiences no failure during a time period.
 Failure: This is the inability of an item to function within the initially defined guidelines.
 Downtime: This is the time period during which the item is not in a condition to carry out its
stated mission. And definitions used in reliability engineering. Some of the frequently used
terms and definitions are presented below [3, 12, and 30].
 Maintainability: This is the probability that a failed item will be repaired to its satisfactory
working state.
 Availability: This is the probability that an item is available for application or use when needed.
Mean time to failure (exponential distribution): This is the sum of the operating time of given
items divided by the total number of failures.
 Useful life: This is the length of time an item operates within an acceptable level of failure rate.
 Failure Frequency(𝐟): The Failure frequency refers to the number of failures that may happen
during a time period. In this study, the dimension of the failure frequency is failures per year.
f=
Number of failures
studied period (x circuit length (for transmisson lines/cables ))
M-Tech Thesis, Defense Engineering College, 2014
( 2.1)
16
 Mean Time to Failure(𝐌𝐓𝐓𝐅): The average time it takes to the occurrence of a component
or system failure measured from t=0.
 Mean Time to Repair(𝐌𝐓𝐓𝐑) : The average time it takes to identify the location of a failure
and to repair that failure.
 Then the relationship between the failure frequency and the Mean Time to Failure is:
f=
1
Mean Time To Failure + Mean Time To Repair
(2.2)
In above equation, the unit for Mean Time to Failure is years.
 Failure Probability (Q(t)): The failure probability is the probability that, under stated
conditions, the system or component fails within a stated period. It is identical to unreliability,
which is denoted as (F(t))
Q(t) = 1 − R(t)
(2.3)
 Availability (𝐀): Availability is the probability that the component is normal at an arbitrary
time t, given that it was good at time zero [4].
A=
MTTF
MTTF + MTTR
(2.4)
 Unavailability (𝐔): Unavailability is the probability that the component is down at an arbitrary
time t and unable to operate [4].
A=
MTTR
f x MTTR
=
MTTF + MTTR
8760
(2.5)
In the formula above, 8760 in the right part is the total hours of one year, because MTTR is measured
in hours. According to the definition of availability and unavailability: [3, 12, and 30]:
U=1−A
(2.6)
The concept pairs of reliability/failure probability and availability/unavailability are more or less the
same. The difference between them is whether the maintenance of the component is considered. If a
healthy component is under maintenance to be checked for its quality, then it is reliable, but
unavailable.
2.7 Electricity Service Interruptions
Interruption of electricity service to a customer involves a reduction in voltage magnitude to zero at
the customer delivery point. [3, 18, 19]:
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2.7.1 Terminology Related to Interruptions
 Transient Fault: A transient fault is a fault that disappears either by itself or by de-energization of
the faulted circuit and it does not require any immediate repair work. The majority of the faults
occurring on overhead feeders are transient faults. Common causes of transient faults are
momentary tree contacts with conductor and flashovers initiated either by lightning or by
conductors temporarily swinging together. In this thesis, it is assumed that in the event of a transient
fault, reclosing of the associated circuit breaker or recloser is always successful, though it might
not be successful on the first or second attempt. [3, 18, 19]:
 Underground Cable Internal Fault: Underground cable internal faults are shunt faults on
underground cables, which occur due to insulation failures. Insulation failures develop over time.
Moisture, temperature and electrical stresses are all factors that contribute to degrade the dielectric
strength of insulation. Common causes of electrical stresses are lightning and switching surges.
Thus, these faults occur in the absence of mechanical damage. In this thesis, all underground cable
faults, except for faults caused by excavation damage, are underground cable internal faults.[3, 18,
29]:
 Underground Cable Fault Caused by Excavation Damage: One of the main fault causes in urban
areas is excavation work in the streets causing damage to underground cables.
 Permanent Forced Outage Duration: The permanent forced outage duration is defined as the
average time it takes to restore the affected component to service without deliberate delays when
the component outage occurrence has been automatically initiated due to a permanent fault on the
component [3, 18, and 19].
 Transient Forced Outage Duration: The transient forced outage duration is defined as the
average time it takes to restore the affected component to service without deliberate delays when
the component outage occurrence has been automatically initiated due to a transient fault on the
component [3, 18, and 19].
 Travel Time: By travel time is meant the average time period from the moment of the outage
occurrence until the repair crew arrives at the trouble area with appropriate equipment. Thus, this
time does not only include the actual travel time of the repair crew. However, no deliberate delays
are included.
 Causes of Interruptions: Interruptions are caused by either planned or unplanned opening
operations of switching devices, disconnecting primary equipment from the network. Opening
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operations of switching devices are initiated either by the protection system or by humans. The
protection system may operate incorrectly and opening operations initiated by humans may be
inadvertent. When the protection system functions as intended, it detects faults and initiates opening
operations of circuit breakers to isolate faulted parts from the healthy parts of the power system in
a selective manner. Faults are caused by external factors, such as road traffic accidents, digging
into buried cable, vegetation, animals and severe weather, and by equipment failure.[3, 18, 29]:
 Incorrect Protection Operations: Incorrect protection operations initiate disturbances and may
extend the consequences of faults. Unwanted protection operations initiate disturbances, while
unwanted protection operations and failure to operate of protection systems may extend the
consequences of faults.
 Non-Selective Fault Clearance Non-selective fault clearance means that a larger portion of the
power system than necessary is disconnected in order to clear a fault. In case of a missing main
protection operation, the corresponding backup protection will clear the fault. If the backup
protection is remote, it operates non-selectively, which may result in an increased number of
customers experiencing interruption. In addition, unwanted protection operations could result in
non-selective fault clearance. Consequently, failure to operate of a protection system and unwanted
protection operations may result in interruptions to customers who would not have been affected if
the fault had been cleared selectively [3, 18, and 19].
 Spontaneous Unwanted Protection Operation: An unwanted protection operation that occurs in
the absence of a power system fault is referred to as a spontaneous unwanted protection operation.
Such unwanted protection operations initiate disturbances, which in turn may cause interruptions
to customers.
2.7.2 Interruption Characteristics
2.7.3 Momentary and Sustained Interruptions
Sustained interruptions are long-duration interruptions lasting longer than a certain period, usually
defined in the interval of 1-5 minutes. Interruptions with a shorter duration are termed momentary
interruptions. Usually, only data on sustained interruptions is reported to the regulatory authority.
Permanent faults on distribution circuits usually cause sustained interruptions to at least some
customers. However, automatic fault isolation and automatic upstream and downstream service
restoration reduces the number of customers that experience a sustained interruption. In the event of a
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transient fault on a distribution circuit, the customers on that circuit will only experience a momentary
interruption if the circuit is reclosed after it has been interrupted to clear the fault. [15]
2.7.4 Planned and Unplanned Interruptions
A planned interruption occurs at a selected time less inconvenient for the customers and the customers
have been notified beforehand of the interruption. On the other hand, if the occurrence time of the
interruption has not been selected, then the interruption is unplanned. Unplanned interruption occurs,
for example, due to fault clearing, unwanted operation of the protection system or due to inadvertent
initiation of opening operation of a switching device by a human. Planned interruptions occur mainly
for the purpose of construction, preventative maintenance or repair. [15]
2.8 Power System Reliability Indices
The degree of reliability may be measured by the frequency, duration, and magnitude of adverse effects
on the electric supply. There are many indices for measuring reliability. The three most referred indices
are SAIFI, SAIDI, and CAIDI, as defined in IEEE Standard 1366.
 System Average Interruption Frequency Index (SAIFI): It is the average frequency of sustained
interruptions per customer over a predefined area. It is the total number of customer interruptions
divided by the total number of customers served. [3, 13, 14]:
SAIFI =
Total number of customer interruptions ∑i λi Ni
=
∑i Ni
Total number ofcustomers served
(2.7)
Where: λi is the failure rate at load point i and Ni is the number of customers at load point i.
 Customer Average Interruption Frequency Index (CAIFI):
This index gives the average
frequency of sustained interruptions for those customers experiencing sustained interruptions. The
customer is counted once regardless of the number of times interrupted for this calculation.
CAIFI =
Total number of customer interruptions ∑(No )
=
Total number ofcustomers affected
∑(Ni )
(2.8)
Where: No =number of interruptions Ni =Total number of customers interrupted
 System Average Interruption Duration Index (SAIDI): It is commonly referred to as customer
minutes of interruption or customer hours, and is designed to provide information as to the average
time the customers are interrupted. It is the sum of the restoration time for each interruption event
times the number of interrupted customers for each interruption event divided by the total number
of customers
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SAIDI =
Sum of customer interruptions durations ∑i Ui Ni
=
∑i Ni
Total number ofcustomers served
(2.9)
Where: Ui is the annual outage time at load point i and Ni is the number of customer at load point
i.
 Customer Average Interruption Duration Index (CAIDI): It is the average time needed to restore
service to the average customer per sustained interruption. It is the sum of customer interruption
durations divided by the total number of customer interruptions.
CAIDI =
Total number of customer interruptions ∑i Ui Ni SAIDI
=
=
∑i λi Ni
Total number ofcustomers served
SAIFI
(2.10)
Where:λi is the failure rate at load point i Ui is the annual outage time at load point i and Ni is the
number of customer at load point i.
 Average Service Availability Index (ASAI): This index represents the fraction of time (often in
percentage) that a customer has power provided during one year or the defined reporting period
ASAI =
∑i Ni X 8760 − ∑i Ui Ni
Customer hours ofavaliuavle service
=
∑i Ni X8760
Customers hours demanded
(2.11)
Where:Ui is the annual outage time at load point i and Ni is the number of customer at load point i.
 Average Service Unavailability Index (ASUI): This index is the complementary value to the
average service availability index (ASAI).
ASUI = 1 − ASAI =
∑i Ui Ni
Customer hours of unavaliuavle service
=
(2.12)
∑i Ni X8760
Customers hours demanded
Where:Ui is the annual outage time at load point i and Ni is the number of customer at load
point i.
II. Load or Energy-Oriented Indices [3, 13, 14]
 Energy Not Supplied Index (ENS): This index represents the total energy not supplied by the
system.
ENS = ∑ La(i) Ui
(2.13)
i
Where:La(i) is the average load given by :
La(i) = Lp(i) LF(i) =
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Ed(i)
t
(2.14)
21
Lp Is the peak load demand LF is the load factor Ed is the total energy demanded in the period of
interest t.
 Average Energy Not Supplied Index (AENS): This index represents the average energy not
supplied by the system.[3, 13, 14]
AENS =
∑i La(i) Ui
Total energy not supplied
=
∑i Ni
Total number ofcustomers served
(2.15)
 Average Customer Curtailment Index (ACCI): This index represents the total energy not supplied
per affected customer by the system.
ACCI =
∑i La(i) Ui
Total energy not supplied
=
∑i No
Total number ofcustomers affected
(2.16)
Where: La(i) is the average load,No is the number of affected
 Average Load Interruption Frequency Index (ALIFI):
This factor is analogous to the System
Average Interruption Frequency Index (SAIFI) and describe s the interruptions on the basis of
connected load (kVA) served during the year by the distribution system
m
Total load interuptions
Li
ALIFI =
=∑
Total connected load
L
(2.17)
i=1
Where: m is number of interruptions in a subdivision of the network (feeder, substation, operating
district, etc.) for a given time period, L is total connected load (kVA) in subdivision, Li is
total connected load (kVA) interrupted byith interruption
 Average Load Interruption Duration Index (ALIDI):
This factor is analogous to the System
Average Interruption Duration Index (SAIDI) and describes the number of hours on average that
each kVA of connected load was without service:
m
ki
lij Tij
Total KVA − hours interupted
ALIDI =
= ∑∑
Total connected KVA
L
(2.18)
i=1 j=1
Where: m is number of interruptions in a subdivision of the network (feeder, substation, operating
district, etc.) for a given time period,k i is number of restoration steps associated with the ith
interruption, L is total connected load (kVA) in subdivision,lij is connected load restored during
jth restoration step, Tij is cumulative interruption duration (hours) for customers/load affected
by jth restoration step associated with ith the interruption.[3, 13, 14]
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 A reliability index that considers momentary interruptions is Momentary Average Interruption
Frequency Index (MAIFI) is the total number of customer momentary interruptions divided by the
total number of customers served. Momentary interruptions are defined in IEEE Std. 1366 as those
that result from each single operation of an interrupting device. The momentary interruptions are
the interruptions that occur in a specified time not to exceed five minutes.
MAIFI =
∑ IDi XNi
Total number ofcusutomer momentary interuptions
=
Total number ofcusutomer served
NT
(2.19)
Where: IDi is the number of interrupting device operations, Ni is the number of customers experiencing
momentary interruptions, andNT is the total number of customers served. [3, 13, 14].
2.9 Economics of Reliability Assessment
Typically, as investment in system reliability increases, the reliability improves, but it is not a linear
relationship [5]. By calculating the cost of each proposed improvement and finding a ratio of the
increased benefit to the increase cost, the cost effectiveness can be quantified. Once the cost
effectiveness of the improvement options has been quantified, they can be prioritized for
implementation. This incremental analysis of how reliability improves and affects the various indices
versus the additional cost is necessary in order to help ensure that scarce resources are used most
effectively. Quantifying the additional cost of improved reliability is important, but additional
considerations are needed for a more complete analysis. The costs associated with an outage are placed
side by side against the investment costs for comparison in helping to find the true optimal reliability
solution. Outage costs are generally divided between utility outage costs and customer outage costs.
[3].
Utility outage costs include the loss of revenue for energy not supplied and the increased maintenance
and repair costs to restore power to the customers affected. The maintenance and repair costs can be
quantified as [5]:
n
Cm&𝑟 = ∑ Ci + Ccomp
(2.20)
i
Where: Ci is the labor cost for each repair and maintenance action, and Ccomp is the component
replacement or repair cost.
The total utility cost for an outage is:
Cout = (ENS) × (cost/KWh) + Cc&𝑟
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(2.21)
23
Where: ENS is the Energy Not Supplied Cc&𝑟 is cost for customer sector type and geographical
location
While the outage costs to the utility can be significant, often the costs to the customer are far greater.
These costs vary greatly by customer sector type and geographical location. Industrial customers have
costs associated with loss of manufacture, damage equipment, extra maintenance, loss of products
and/or supplies to spoilage, restarting costs, and greatly reduced worker productivity effectiveness.
Commercial customers may lose business during the outage, and experience many of the same losses
as industrial customers, but on a possibly smaller scale. Residential customers typically have costs
during a given outage that are far less than the previous two, but food spoilage, loss of heat during
winter or air conditioning during a heat wave can be disproportionately large for some individual
customers. In general, customer outage costs are more difficult to quantify. Through collection of data
from industry and customer surveys, a formulation of sector damage functions is derived which lead to
composite damage functions. The sector customer damage function (SCDF) is a cost function of each
customer sector (industrial, commercial and residential customers). SCDF depict the sector interruption
cost as a function of interruption duration. The composite customer damage function (CCDF), is an
aggregation of the SCDF at specified load points and is weighted proportionally to the load at the load
points [3, 5, 27].
For n number of customers,
n
CCDF = ∑ Ci × SCDFi ×
i=1
cost
KW
(2.22)
Where: Ci is the energy demand of customer type i,
Therefore, the customer outage cost by sector is:
n
COSTi = ∑ SCDFi × Li
(2.23)
i=1
Where:Li is the average load at load point i.SCDFi Is sector customer damage function at load point i
Since the CCDF is a function of outage attributes, customer characteristics, and geographical
characteristics, it is important to have accurate information about these variables. Although outage
attributes include duration, season, time of day, advance notice, and day of the week, the most heavily
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weighted factor is outage duration. The total customer cost for all applicable sectors can be found for
a particular load point [3, 5, and 27].
n
COSTi = ∑ SCDFi × Li
i=1
or
n
COSTi = ∑ Ci × SCDFi × Li
(2.24)
i=1
However, using the CCDF marks the outage cost that is borne disproportionately by different sectors.
For a reliability planning, in addition to the load point indices ofλ, r, and U, one has to determine the
following reliability cost/worth indices [3, 5, and 27]:
1. Expected Energy Not Supplied (EENS) index. Energy per customer unit time is defined as:
Ne
EENSi = ∑ Li × rij × λij
(2.25)
i=1
Where: Ne isthe total number of elements in the distribution system, Li is the average load at load point
i,rij is the failure duration at point i due to component j, and λij is the failure rate at load point i due
to component j.
2.
Expected customer outage cost (ECOST) index. It is defined as
n
ECOSTi = ∑ SCDFij × rij × λij
(2.26)
i=1
Where: SCDFij is sector customer damage function at load point i due to component j.
3.
Interrupted energy assessment rate (IEAR) index. It is defined as
IEAR i =
ECOSTi
EENSi
(2.27)
Where ECOSTi is Expected customer outage cost at load point i, And EENSi is Expected Energy Not
Supplied at load point i,
This index provides a quantitative worth of the reliability for a particular load point in terms of cost for
unit of energy not supplied [3, 5, and 27].
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2.10
Review of Related Current Research Works
Robert E. Goodin. al. 2010, [19]: This paper presents a comparative analysis of distribution reliability
improvements that can be achieved by using various outdoor distribution devices. First, it discusses the
application of the most common types of devices, including line reclosers, automatic sectionalisers and
manual switches. And analyzes to quantify the reliability improvements that can be achieved by using
each (or a combination) of these devices. The paper concludes, all devices offer an improvement in
reliability. Switches will improve SAIDI. Midpoint switches also possess significant value for tie-point
applications where feeder ties are possible. Sectionalisers and reclosers perform relatively closely for
the various configurations except that reclosers offer more improvement for MAIFI. The highest
possible across the board improvement is achieved by using single-phase reclosers and single-phase
reclosing loop schemes.
Y.V. Makarov and N.S. Moharari, Member, 2009, [1]: This paper develops a new reliability and
security index that reflects both on direct and indirect characteristics. Direct characteristics deal with
the risk to not fully supply load in various contingencies. Indirect characteristics address such
undesirable conditions as circuit overloads, voltage problems, low stability margins, area interchange
violations, in-sufficient generation reserves, unfeasible power flows, etc. Although indirect
characteristics do not necessarily cause load losses, they nevertheless signal about a reduced
security/reliability margin. This reduced margin may lead to sometimes hardly predictable and
quantifiable load losses (via remedial actions, islanding, and instability), unforeseen events (cascading
outages), severe system failures (voltage collapse), etc. The new index gives a more comprehensive
answer regarding the general degree of both reliability and security in the system by combining diverse
contributing factors using a fuzzy logic like approach. It is designed to flexibly accommodate various
priorities and admittance of power utilities regarding particular characteristics integrated in the index.
The existing indices such as expected unserved energy, system minutes, stability margins, and others
can be linked to or derived from the general index. The index meets the need in a practical, flexible,
and effective security and reliability index
Fredrik Roos, 2005, [15]: In this thesis, implementations of reliability improvement solutions on a
test system have been evaluated from a socio-economical point of view. For each of the alternative
solutions implemented on the test system, the average annual supply interruption cost to the customers
supplied from the test system has been estimated. Furthermore, the maximum annual capital cost
associated with the implementation of each solution has been estimated. Then, a reliability
M-Tech Thesis, Defense Engineering College, 2014
26
improvement solution is considered justified socio-economically if the capital cost associated with its
implementation is less than the resulting reduction in the interruption cost to the customers.
Hag-Kwen Kim, 2009, [14]: This paper focuses on aging power systems. Aging of components is an
important fact in power system reliability assessment. It results from a number of different reasons:
deterioration, erosion, or damage of equipment. Regardless of reasons, most equipment may develop
aging trend over time. As a result, aging may become the cause of load curtailments because of higher
system failure probability. So it is necessary to examine aging characteristics in system reliability or in
economic evaluation. Power systems with high reliability at low costs offer many benefits in
competitive environment. This thesis illustrates effect of aging on composite power system reliability
evaluation.
Ying Zhang, al, 2010, [21]: This paper outlined a technique for assessing the reliability of alternative
conceptual design architectures. The method is based on identification of criticality and sensitivity of
system components, and a simulation model that incorporates probability and failure rates of individual
components such that system level reliability measures can be computed. This analysis at the system
level supports decision making early in the design process and assists the designers evaluate and
identify critical elements of different conceptual architectures, and to select among or integrate
different architectural solutions to ensure improved reliability.
Solomon Derbie, 2014, [3]: This thesis-work mainly focuses on the reliability problem of the existing
power grid of Adama city and the smart grid has been proposed as a solution. Therefore, the appropriate
components of smart grid are selected to design the overall system. Smart Reclosers are the key
components of Smart Grid which are used for fault detection, isolation and restoration programs in the
distribution systems and the result of this fact has been an unprecedented increase of global demand
for this product. A smart recloser offers a complete design solution with integrated smart grid
capabilities offering not only remote control but automation and the analogue data measurement and
logging capabilities to achieve the utilities business drivers. The designed system is simulated using
the softwares DigSILENT and WindMil that are used to analyze the reliability of the overall system.
The simulation of the designed model shows that the application of smart reclosers can improve the
reliability of the overall system from 50% to 75%.
M-Tech Thesis, Defense Engineering College, 2014
27
CHAPTER THREE
EVALUATION AND ANALYSIS OF THE EXISTING SUBSTATION
3.1 Description of Bishoftu Substation II
Bishoftu city is now supplied from national grid that is, interconnected system (ICS). Ethiopian Electric
Power Corporation (EEPCO) is a provider of electric power in the country. A 132 kV transmission line
is stretched into the substation. Then, the distribution system in the city has a primary voltage of 33 kV
and 15 kV. And also, this voltage value is stepped down to 380 and 220 volts to customer’s level. The
network topology for Bishoftu substation II is radial. The bus bar schemes or bus bar layout is parallel
Single bus bar system. The single bus bar scheme has only one three-phase but to which the various
incoming and outgoing circuits are connected. It is not preferred for major substation and it lack
operational flexibility and in case of bus fault or CB failure the entire bus has to be de-energized, but
it is low cost, simple to operate and requires simple protection. Figure 9 illustrates the current
arrangement of the distribution substation of Bishoftu town.
Figure 9.Bishoftu substation drawn using Dig-Silent power factory software
M-Tech Thesis, Defense Engineering College, 2014
28
Table 2 contains the data about the 33 kV feeder (bus bar 2) and 15kV feeder’s data (bus bar1,3, and
4). In this table L (n) represents the outgoing feeder lines from 33 kV bus bars K (n) represents the
outgoing feeder lines from 15 kV bus bars.
Table 2. The compiled data of the substation feeders
Feeder
Customer
33kV feeder
L1
Abisinia
L2
Eastern industry zone
L3
ArertiMinjar&Chefedo
nsa
15 kV feeders
K1
Steely
K2
Steely
K6
Steely
and
partial
Bisoftu town
K7
Bisoftu town
K8
Industry zone partial
Dukem town
K9
Air force and partial
Bishoftu
K 12
Abyssinia
K13
Abyssinia
K14
Abyssinia & dire town
K15
East Africa Ziquala and
partial Bishoftu town
Total number
of
distribution
Transformer
Total capacity
of distribution
transformer
(kVA)
Total length of
feeder (km)
Conductor
Size (mm)
2
3
9
2500
3300
930
3.5
5.8
45
AAC95
AAC 95
AAC 95
2
2
16
2500
2500
5650
2.3
2.3
34
AAC95
AAC 95
AAC 95
58
6
10435
6390
19
14.5
AAC50
AAC 95
65
21925
4.9
AAC 95
2
2
5
12
3750
3750
4350
4020
3.5
3.5
54
24
AAC95
AAC 50
AAC 95
AAC50
Table 3contains annual average energy and power consumption of each feeder bus bar. The annual
average energy is calculated using the recorded data from 2010/11 G.C (2003 E.C) to 2012/13 G.C
(2005 E.C).
M-Tech Thesis, Defense Engineering College, 2014
29
Table 3. Annual average energy and power consumption of each feeder bus bar
33 KV line BB1
Average Energy consumption
Active KWh Reactive KVRh
7444666.67
947770.00
Average power consumption
Active (MW) Reactive (MVAr)
10.34
1.32
15 KV line BB2
15 KV line BB3
15 KV line BB4
Total
13837260.00
975000.00
6606779.17
28863705.83
8.65
1.35
9.18
29.52
line /Bay
7352760.00
392250.00
4486230.00
13179010.00
4.55
0.54
6.23
12.64
Based on Table 3, the power factor (pf) for the system can be calculated as:
Q
Pf = cos (tan−1 ( ))
P
(3.1)
Where
Pf = power factor
P= active power in (MW)
Q= reactive power in (MVAr)
Hence, the power factor of the overall system is 0.91 and it is a good value. If power factor is lower
than 0.9, it reduces electrical system’s distribution capacity by increasing current flow and causing
voltage drops.
Table 4. Type and number of connected customers
Feeders
L2
L3
K1
K2
K6
K7
K8
K9
K12
K13
K14
K15
System
Residential
789
3200
9600
69
5128
1452
3250
23488
Type of customers
Commercial Industrial Total
8
8
64
6
859
1
1
1
1
142
3342
240
15
9855
4
7
80
1
12
5141
1
1
1
1
27
6
1485
165
16
3431
643
74
24205
M-Tech Thesis, Defense Engineering College, 2014
Remark
dedicated
dedicated
dedicated
dedicated
dedicated
30
Table 5. Average Hourly Load (MW) of Each Feeder of BishoftuSubstation II
Feeder
Hours
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
L2
0.58
0.58
0.58
0.58
0.58
0.58
0.58
1.55
3.11
3.30
3.30
3.89
3.50
2.72
2.33
2.53
6.80
3.89
3.89
6.80
5.83
8.75
2.33
0.58
L3
1.07
1.17
1.17
1.12
1.17
1.94
2.48
2.43
0.49
3.26
3.26
3.45
3.45
3.94
2.87
2.43
3.11
3.11
0.73
6.28
0.87
3.94
1.75
1.36
K1
3.53
3.53
3.53
3.53
3.53
2.98
2.98
1.94
2.39
4.15
3.93
3.93
3.58
1.28
3.07
2.10
4.97
6.44
3.78
3.62
2.98
2.98
2.12
2.47
K2
3.47
3.47
3.31
3.31
3.31
2.98
2.98
1.94
2.39
4.04
4.02
3.31
4.11
1.15
2.34
2.23
5.12
4.33
4.00
3.25
3.07
2.98
2.23
2.56
K6
4.86
4.86
4.86
3.78
3.53
1.57
3.36
3.84
4.06
4.06
3.98
2.01
4.22
4.26
2.50
3.78
2.58
4.00
4.64
2.16
1.90
2.87
3.53
3.80
K7
1.1
1.08
1.15
1.06
1.24
1.55
1.9
1.81
3.14
3.53
3.67
4.26
3.56
0.97
4.22
3.78
3.86
3.89
3.86
3.89
4.2
0.93
3.78
3.78
K8
0.71
0.75
0.75
0.84
0.84
1.08
1.21
1.55
1.72
1.66
1.66
2.67
2.69
3.07
2.63
2.30
3.09
3.18
2.98
2.98
3.31
3.03
2.30
2.30
K9
1.15
1.19
1.24
1.24
1.79
2.80
2.74
2.69
3.20
3.14
3.14
2.89
2.69
2.89
2.52
2.05
2.34
2.27
2.34
6.10
2.41
3.03
2.05
1.81
K12
1.06
1.08
1.15
1.10
1.24
2.10
1.90
1.81
3.14
3.53
3.67
4.26
3.56
0.97
4.22
3.78
3.86
3.89
3.86
3.89
4.00
0.93
3.78
3.78
K13
6.85
6.40
6.85
6.40
6.18
5.76
6.07
6.23
2.74
5.98
4.64
3.60
6.76
2.08
3.80
6.80
1.90
7.07
7.20
5.37
6.80
3.40
6.32
5.98
K14
4.86
4.86
4.86
3.78
3.53
1.57
3.36
3.84
4.06
4.06
3.98
2.01
4.22
4.26
2.50
3.78
2.58
4.00
4.64
2.16
1.90
2.87
3.53
3.80
K15
3.58
3.58
3.60
3.62
3.64
1.72
1.59
4.95
3.67
4.26
4.33
2.41
3.25
4.06
4.48
1.72
3.62
3.53
3.91
3.86
3.75
4.00
3.80
3.67
Total
32.72
32.55
33.05
30.36
30.58
26.63
31.15
34.58
34.11
44.97
43.58
38.69
45.59
31.65
37.48
37.28
43.83
49.6
45.83
50.36
40.82
39.71
37.52
35.89
By referring Table 2 we can categorize the feeders in two groups the first category is feeders which
supply residential loads includes L3, K6, K7, K8, K9and K15. The second category is feeders which
supply industrial loads includes L2, K1, K2, K12, K13 and K14. Figures 10 and 11 shows average
residential load of each feeder and average residential total load, Figures 12 and 13 average industrial
load of each feeder and average industrial total load.
M-Tech Thesis, Defense Engineering College, 2014
31
Average Residential Load at Each Feeder
7
L3
6
K6
5
4
K7
3
K8
2
K9
1
K15
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Figure 10.Average residential Load (MW) of Each Feeder of Bishoftu Substation II
Average Residential Total Load
30
L3
25
K6
20
K7
15
K8
10
K9
K15
5
total
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Figure 11.Average total residential Load (MW) of Bishoftu Substation II
From figure 10 and 11 the following conclusions can be made:
(1) The maximum load of the residential load of the system occurs from 19:00 to 22:00; that is,
from 12:00 to 4:00 o’clock local time.
(2) From all the residential feeders, the minimum load is 0.49MW while the maximum load is
6.28MW.
(3) For the residential load of the system the minimum load is 10.66MW while the maximum load
is 25.27MW.
M-Tech Thesis, Defense Engineering College, 2014
32
Average Industrial Load at Each Feeder
10
L2
9
8
K1
7
6
K2
5
4
K12
3
K13
2
1
K14
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Figure 12. Average Industrial Load (MW) of Each Feeder of Bishoftu Substation II
Average Industrial Total Load
35
L2
30
K1
25
K2
20
K12
15
K13
10
K14
5
total
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Figure 13 Average total Industrial Load (MW) of Bishoftu Substation II
From figure 12 and 13 the following conclusions can be made:
(1) The maximum load of the industrial loads of the system occurs from 18:00 to 22:00; that is,
from 12:00 to 4:00 o’clock local time.
(2) From all the feeders, the minimum load is 0.58MW while the maximum load is 8.75MW.
(3) For the industrial load of the system the minimum load is 12.46MW while the maximum load
is 29.62MW.
M-Tech Thesis, Defense Engineering College, 2014
33
3.2 Reliability Related Data’s of Bishoftu Substation II
This section contains the compiled reliability related data that are collected from Bishoftu
Substation II and Table 6 contains the frequency of interruptions due to non-momentary and
planned interruptions from 2010/11 G.C (2003 E.C)to 2012/13 G.C (2005 E.C)
Table 6. Frequency of interruptions
2010/11 G.C (2003 E.C)
Feeders
NonPlaned Total
momentary
33KV Feeder
L2
28
42
70
L3
290
149
439
15KV Feeder
K1
32
45
77
K2
10
42
52
K6
21
37
58
K7
167
93
260
K8
97
84
181
K9
190
89
279
K12
9
22
31
K13
2
37
60
K14
53
65
118
K15
58
71
129
System
978
776
1,754
2011/12G.C (2004 E.C)
NonPlaned Total
momentary
2012/13 G.C (2005 E.C)
NonPlaned Total
momentary
30
389
25.00
200.00
55
589
37
278
46
185
83
463
17
21
12
187
114
253
6
13
45
40
1,127
45
41
32
109
96
115
25
29
64
96
877
62
62
44
296
210
368
31
42
109
136
2,004
8
15
13
162
89
155
2
21
54
38
872
44
44
34
86
86
80
20
40
70
73
808
52
59
47
248
175
235
22
61
124
111
1,680
The duration of interruptions due to non-momentary and planned interruptions in the existing
distribution system of city from 2010/11 G.C (2003 E.C) to 2012/13 G.C (2005 E.C) are shown in
Table 7. And Table 8 contains the average frequency and duration of interruptions per year of each
feeder and the whole system from September 2010 G.C to august 2013 G.C (from Meskerem
2003 E.C to Nehase 2005 E.C).
M-Tech Thesis, Defense Engineering College, 2014
34
Table 7. Duration of interruption
2010/11 G.C (2003 E.C)
NonFeeder
momentar Planed
Total
y
33 KV feeder
L2
55.45
9.25
46.20
L3
185.46
94.80
90.66
15 KV feeder
K1
127.42
36.05
91.37
K2
114.98
6.11
108.87
K6
94.81
18.95
75.86
K7
213.85
124.34
89.51
K8
177.62
84.73
92.89
K9
227.89
136.63
91.26
K12
58.88
19.97
38.91
K13
175.82
16.50
159.32
K14
124.76
61.00
63.76
K15
184.57
108.30
76.27
System
716.63
1,024.88 1,741.5
2011/12 G.C (2004 E.C)
NonPlaned
momentary
Total
2012/13 G.C (2005 E.C)
Nonmomentar Planed
Total
y
4.49
119.89
19.38
81.11
23.87
201.00
30.11
106.44
17.89
13.15
51.93
213.64
109.57
302.56
4.19
13.78
40.73
65.57
957.39
76.07
61.52
60.84
75.83
73.42
82.67
24.80
95.58
50.45
79.08
780.75
93.96
74.67
112.77
289.47
182.99
385.23
28.99
109.36
91.18
144.65
1,738.1
12.47
7.34
9.34
122.54
97.29
178.31
0.40
15.26
50.34
105.32
735.16
50.05
112.02
80.16
218.46
119.45
106.98
134.52
127.18
91.86
82.52
235.24
112.70
190.69
93.40
261.57
83.26
37.54
37.14
181.79
166.53
108.16
57.82
171.43
66.11
1,095.71 1,830.8
Table 8.The average frequency and duration of interruptions per year
Frequency of Interruption (int/year) Duration of Interruption (hours/year)
Feeders
NonNonplaned
Total
planed
Total
momentary
momentary
33 KV feeder
L2
69.33
38.54
53.16
31.67
37.67
14.62
L3
497.00
94.59
201.64
319.00
178.00
107.04
15 KV feeder
K1
63.67
91.47
113.61
19.00
44.67
22.14
K2
57.67
99.19
108.06
15.33
42.33
8.87
K6
49.67
73.07
99.81
15.33
34.33
26.74
K7
268.00
92.68
246.19
172.00
96.00
153.51
K8
188.67
86.57
183.77
100.00
88.67
97.20
K9
294.00
85.73
291.56
199.33
94.67
205.83
K12
28.00
33.62
41.80
5.67
22.33
8.19
K13
54.33
140.48
155.66
19.00
35.33
15.18
K14
117.00
57.34
108.03
50.67
66.33
50.69
K15
125.33
73.82
166.88
45.33
80.00
93.06
System
1,812.67
967.11
1,770.17
992.33
820.33
803.06
M-Tech Thesis, Defense Engineering College, 2014
35
According to the data collected from the substation, the causes of non-momentary (unplanned)
interruptions are:
 Distribution Permanent Earth Faults (DPEF)
 Distribution Permanent Short Circuit (DPSC)
 Distribution Temporary Earth Faults (DTEF)
 Distribution Temporary Short Circuit (DTSC)
The percentage of the causes of the average unplanned (non -momentary) interruptions and planned
interruptions are given in Table 9
Table 9. The percentage of the causes of the average unplanned and planned interruptions
DPEFT
FRE DUR
DPSC
FRE
DTEF
FRE
DUR
DTSC
FRE
OPR
FRE
Feeder
DUR
DUR
DUR
33KV
feeder
L2
0.073 0.111
0.055 0.565 0.201 0.033
1.409 0.106 2.068 2.148
L3
2.288 3.294
2.251 1.473 6.698 0.891
6.277 0.309 9.773 5.273
15KV feeder
K1
0.201 0.691
0.348 0.428 0.403 0.052
0.092 0.063 2.452 5.099
K2
0.073 0.049
0.275 0.353 0.092 0.043
0.403 0.049 2.324 5.529
K6
0.037 0.007
0.146 0.986 0.329 0.486
0.329 0.011 1.885 4.073
K7
0.659 1.668
1.336 4.469 3.258 2.074
4.191 0.344 5.271 5.166
K8
1.025 2.103
1.336 2.634 1.299 0.342
1.830 0.339 4.868 4.825
K9
1.794 4.122
2.672 4.646 3.294 2.369
3.184 0.336 5.198 4.779
K12
0.037 0.061
0.110 0.085 0.092 0.258
0.073 0.052 1.226 1.874
K13
0.110 0.141
0.055 0.022 0.348 0.048
0.531 0.634 1.940 7.830
K14
0.238 0.709
0.659 1.795 0.384 0.098
1.501 0.223 3.642 3.196
K15
0.256 0.802
1.080 4.170 0.146 0.090
1.007 0.125 4.392 4.115
System
6.790 13.759 10.322 21.627 16.545 6.785 20.827 2.592 45.040 53.907
On Table 9 DPEFT is distribution permanent earth faults, DPSC is distribution permanent short circuit,
DTEF is distribution temporary earth faults, DTSC is distribution temporary short circuit, OPR is
operational interruptions, FRE frequency of interruption and DUR is duration of interruption . Based
on Table 9, it is possible to analyze the percentage contributions of each cause of Interruptions for the
total frequency and duration of interruptions of each feeder and the overall system. Figure 14 and Figure
15 represent the percentage of the causes of interruptions for the total duration of interruptions of
the overall system
M-Tech Thesis, Defense Engineering College, 2014
36
Percentage (%) of frequancy of Interruption s of the
Overall System
DTSC
21%
DPEFT
OPR
45%
DTEF
17%
DPSC
DTEF
DPSC
10%
DTSC
DPEFT
7%
OPR
Figure 14. Percentage (%) of Frequency of Interruptions of the Overall System
Percentage (%) of Duration of Interruptions of the Overall
System
DTSC
DTEF
2%
7%
DPSC
22%
DPEFT
OPR
55%
DPSC
DTEF
DPEFT
14%
DTSC
OPR
Figure 15. Percentage (%) of Duration of Interruption s of the Overall System
M-Tech Thesis, Defense Engineering College, 2014
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In general, based on the analysis results illustrated in Figure 14 and 15, from the total frequency
of interruption, 45% is occurred due to operational and maintenance tasks. Similarly, 55% of the total
duration of interruptions is caused by planned (operational) interruptions. This shows that the
distribution technicians take more time to locate a fault occurred during maintenance since, as there is
no automatic fault locating mechanisms.
3.3 Calculated Values of Selected Reliability Indices
The reliability indices can be calculated using equations from (2.1) to (2.26) which are studied in the
literature review part (chapter two). Based on the data given in Table6 and 7, we calculate some of
the reliability indices for each year. Similarly, it is possible to calculate the average reliability indices
using the data given in Table 8 Therefore, Table 10, 11 and 12 show the SAIFI, CAIFI and SAIDI
values from 2010/11 (2003 E.C) to 2012/13 (2005 E.C), respectively.
System Average Interruption Frequency Index (SAIFI): It is the average frequency of sustained
interruptions per customer over a predefined area. It is the total number of customer interruptions
divided by the total number of customers served.
𝑆𝐴𝐼𝐹𝐼 =
𝑇𝑜𝑡𝑎𝑙𝑛𝑢𝑚𝑏e𝑟𝑜𝑓𝑐𝑢𝑠𝑡𝑜𝑚𝑒𝑟𝑖𝑛𝑡𝑒𝑟𝑟𝑢𝑝𝑡𝑖𝑜𝑛𝑠 ∑𝑖 𝜆𝑖 𝑁𝑖
=
∑𝑖 𝑁𝑖
𝑇𝑜𝑡𝑎𝑙𝑛𝑢𝑚𝑏𝑒𝑟𝑜𝑓𝑐𝑢𝑠𝑡𝑜𝑚𝑒𝑟𝑠𝑠𝑒𝑟𝑣𝑒𝑑
Where: 𝜆𝑖 is the failure rate at load point i and 𝑁𝑖 is the number of customers at load point i.
The SAIFI value of each feeder and the system is calculated using equation 2.7 and given in the table
10
M-Tech Thesis, Defense Engineering College, 2014
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Table 10. Calculated SAIFI value for each feeder and the system
Feeders
L2
L3
K1
K2
K6
K7
K8
K9
K12
K13
K14
K15
System
SAIFI value 2010-2013 (2003-2005 E.C)
2010/11(2003 E.C) 2011/12(2004E.C) 2012/13(2005E.C)
33KV Feeders
70
55
64
439
589
491
15KV feeders
77
62
56
52
62
54
58
44
45
260
296
273
181
210
177
279
368
280
31
31
23
60
42
57
118
109
111
129
136
127
124.41
252.34
219.69
Customer Average Interruption Frequency Index (CAIFI): This index gives the average
frequency of sustained interruptions for those customers experiencing sustained interruptions. The
customer is counted once regardless of the number of times interrupted for this calculation.
𝐶𝐴𝐼𝐹𝐼 =
𝑇𝑜𝑡𝑎𝑙𝑛𝑢𝑚𝑏𝑒𝑟𝑜𝑓𝑐𝑢𝑠𝑡𝑜𝑚𝑒𝑟𝑖𝑛𝑡𝑒𝑟𝑟𝑢p𝑡𝑖𝑜𝑛𝑠 ∑(𝑁𝑜 )
=
𝑇𝑜𝑡𝑎𝑙𝑛𝑢𝑚𝑏𝑒𝑟𝑜𝑓𝑐𝑢𝑠𝑡𝑜𝑚𝑒𝑟𝑠𝑎𝑓𝑓𝑒𝑐𝑡𝑒𝑑
∑(𝑁𝑖 )
Where: 𝑁𝑜 is number of interruptions 𝑁𝑖 is Total number of customers interrupted
The CAIFI value of each feeder and the system is calculated using equation 2.8 and given in the table
11
M-Tech Thesis, Defense Engineering College, 2014
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Table 11. Calculated CAIFI value for each feeder and the system
CAIFI value 2010-2013 (2003-2005 E.C)
FEEDER 2010/11(2003 E.C)
2011/12(2004E.C) 2012/13(2005E.C)
33KV Feeders
L2
8.75
6.88
0.09
L3
0.51
0.69
2.04
15KV feeders
K1
77
62
0.02
K2
52
62
0.02
K6
0.02
0.01
0.13
K7
0.03
0.03
35.16
K8
2.26
2.63
0.03
K9
0.05
0.07
1.07
K12
31
31
0.04
K13
60
42
0.02
K14
0.08
0.07
8.72
K15
0.04
0.04
5.08
System
13.80
12.08
6.76
System Average Interruption Duration Index (SAIDI): It is commonly referred to as customer
minutes of interruption or customer hours, and is designed to provide information as to the average
time the customers are interrupted. It is the sum of the restoration time for each interruption event
times the number of interrupted customers for each interruption event divided by the total number of
customers
𝑆𝐴𝐼𝐷𝐼 =
𝑆𝑢𝑚𝑜𝑓𝑐𝑢𝑠𝑡𝑜𝑚𝑒𝑟𝑖𝑛𝑡𝑒𝑟𝑟𝑢𝑝𝑡𝑖𝑜𝑛𝑠𝑑𝑢𝑟𝑎𝑡𝑖𝑜𝑛𝑠 ∑𝑖 𝑈𝑖 𝑁𝑖
=
∑𝑖 𝑁𝑖
𝑇𝑜𝑡𝑎𝑙𝑛𝑢𝑚𝑏𝑒𝑟𝑜𝑓𝑐𝑢𝑠𝑡𝑜m𝑒𝑟𝑠𝑠𝑒𝑟𝑣𝑒𝑑
Where: 𝑈𝑖 is the annual outage time at load point i and 𝑁𝑖 is the number of customer at load point i.
The SAIDI value of each feeder and the system is calculated using equation 2.9 and given in the table
12
M-Tech Thesis, Defense Engineering College, 2014
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Table 12 Calculated SAIDI value for each feeder and the system
SAIDI value 2010-2013 (2003-2005 E.C)
FEEDER 2010/11(2003 E.C)
2011/12(2004E.C)
2012/13(2005E.C)
33KV Feeder
L2
55.45
23.87
50.19
L3
185.46
201
176.56
15KV feeder
K1
127.42
93.96
103.64
K2
114.98
74.67
115.63
K6
94.81
112.77
102.93
K7
213.85
289.47
243.88
K8
177.62
182.99
171.62
K9
227.89
385.23
218.79
K12
58.88
28.99
39.81
K13
175.82
109.36
172.66
K14
124.76
91.18
138.26
K15
184.57
144.65
185.33
System
189.5847127
249.1040781
226.5016921
3.4 Comparison of the calculated values of reliability indices with different standards
The assessment of reliability indices for a power system network or of parts thereof, is the assessment
of the ability of that network to provide the connected customers with electric energy of sufficient
availability, as one aspect of power quality. Once we calculate the reliability indices then we have to
compare it with the benchmark values of that network, in this case the calculation results is compared
with benchmark value set by EEPCO to say the part of network (the distribution substation of Bishoftu
city) is reliable or not. And also the result is compared with standards of different countries by selecting
three most widely used reliability indices which are SAIFI CAIFI and SAIDI values.
Figures.16,17 and 18.Sows the comparison of the most commonly used reliability indices (SAIF,
CAIFI and SAIDI). Their calculated value for each year is given in Table 10, 11 and 12.
M-Tech Thesis, Defense Engineering College, 2014
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1000
198.81
SAIFI VALU
100
10
1.2
2.5
1.2
1
2.3
5
20
3.4
0.1
0.8
countries with diferent standards
CAIFI Value
Figure 16. Comparison of the SAIFI value with different standards
Countries with diferent standards
Figure 17. Comparison of the CAIFI value with different standards
M-Tech Thesis, Defense Engineering College, 2014
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SAIDI value
1000
221.73
100
10
2.3
5.4
2.5
3.3
6.9
25
6.9
1
1.1
Countries with diferent standards
Figure 18 Comparison of the SAIDI value with different standards
As it is clearly shown in the figures 16,17 and 18 the calculated values of the SAIFI ,CAIFI and SAIDI
values for Bishoftu city is far from the standard value set by EEPCO and standard values of some other
reference countries. This indicates the distribution system of Bishoftu city has a serious reliability
problem. And another problem which is observed during this system evaluation process is, there is an
overloading problem so, we have to find mechanisms to mitigate the reliability problems, one of such
mechanisms is designing of an improved distribution substation to mitigate the power reliability and
to solve the overloading problems which will be discussed in the next chapter. The Table 13
summarizes the comparisons of reliability indices by indicating all the feeders and the whole system at
Bishoftu substation II.
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Table 13. Summary of comparisons of reliability indices
Standard SAIFI value
(int./year/customer )
Standard CAIFI value
(int./year/customer )
Standard SAIDI value
(int./year/customer )
USA
1.2
1.4
2.3
Europe
2.5
0
5.4
Sweden
1.2
0
2.5
Australia
2.3
1.5
3.3
Finland
5
1.3
6.9
Canada
3.4
0
6.9
Unite Kingdome
0.8
2.3
1.1
Ethiopia
20
5
25
L2
63
5.24
43.17
L3
506.33
1.08
187.67
K1
65
46.34
108.34
K2
56
38.01
101.76
K6
49
0.05
103.50
K7
276.33
11.74
249.07
K8
189.33
1.64
177.41
K9
309
0.40
277.30
K12
28.33
20.68
42.56
K13
53
34.01
152.61
K14
112.67
2.96
118.07
K15
130.67
1.72
171.52
system
198.81
10.88
221.73
Country
Bisoftu
distribution
substation
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CAHPTER FOUR
UPGRADING OF THE DISTRIBUTION SUBSTATION
4.1 The Need for Upgrading the Bishoftu Substation
As it was discussed in Chapter three of this thesis, evaluation of the existing distribution substation of
Bishoftu city has two serious problems:
1. Overloading problem because of the rapidly increasing power demand in the city
2. Poor reliability because of the substation is single bus bar system and not equipped with
remotely controlled automatic reclosers and circuit breakers (lack of automation system).
In order to solve the above problems of the distribution system and meet consumers demand with great
capacity and reliability, it is necessary to upgrade the substation by designing the distribution substation
with proper rating of distribution substation equipment and by making the system capable of
performing some distribution automaton functions.
This chapter gives the important mathematical design calculations and decisions for selecting the
necessary equipment for upgrading the substation to improve the performance of the distribution
system in terms of monitoring and automatic fault locating functions.
4.2 Estimation of Future Load
Load forecasting addresses the annual changes in demand that reflect changes in population and GDP.
Although weather is a major driver for short-term forecasting with an explicit role, it plays a
background role in long-term forecasting [50]. For a base case scenario weather is not assumed to
change dramatically from year to year. Currently there are two official forecasts used by EEPCo,
namely the moderate, which presumes an annual average growth of 14% and the ambitious target of
17% [50]. In order to be more realistic, the World Bank’s annual average growth rate of 6% of a power
demand forecast have been used to estimate the capacity of the distribution substation. This estimated
power demand forecast is tabulated in Table 14.
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Table 14: Power demand forecast for of Bishoftu city from 2014-2038
Year
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
Forecasted Demand in
(MW)
53.38
56.58
59.98
63.58
67.39
71.44
75.72
80.27
85.08
90.19
95.60
101.33
107.41
113.86
120.69
127.93
135.61
143.74
152.37
161.51
171.20
181.47
192.36
203.90
216.14
Forecasted Demand in
(MVA)
58.66
62.18
65.91
69.87
74.06
78.50
83.21
88.20
93.50
99.11
105.05
111.36
118.04
125.12
132.63
140.58
149.02
157.96
167.44
177.48
188.13
199.42
211.39
224.07
237.51
From table 14 the power demand at Bishoftu city after 25 years will be approximately 216.14MW of
active power and 237.51MVA by considering a power factor of 0.91. Therefore the power demand
after 25 years will be approximately 230 MW. This indicates that the new design substation should
have a capacity of supplying 230 MW. In the following sections, the calculations for selecting different
substation equipment are done with the consideration of the maximum load of the substation is
250MVA.
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4.3 Substation Arrangement Selection
In planning an electrical substation or switchyard facility, one should consider major parameters as
discussed in the literature review part which are:
 Reliability,
 Cost
 Available area [52].
In order to provide a complete evaluation of the configurations described, other circuit-related factors
should also be considered. The arrangement of circuits entering the facility should be incorporated in
the total scheme. This is especially true with the ring bus and breaker-and-a-half schemes, since
reliability in these schemes can be improved by not locating source circuits or load circuits adjacent to
each other. Arrangement of the incoming circuits can add greatly to the cost and area required. Also,
the profile of the facility can add significant cost and area to the overall project [52]. A high-profile
facility can incorporate multiple components on fewer structures. Each component in a low-profile
layout requires a single area, thus necessitating more area for an arrangement similar to a high-profile
facility. Based on the following reliability based comparison from different literatures the new design
arrangement of the substation is decided to be a double bus bar type. Because it is highly reliable and
arrangement of circuits entering the facility is easier as compared to others. [52]
Configuration
Reliability
Single Bus
List Reliable: Single failure can cause complete outage
Double Bus
Highly reliable: Duplicated components; single failure normally isolates
single component
Main bus and transfer
Least reliable: same as Single bus, but flexibility in operating and
maintenance with transfer bus
Double bus-Single breaker Moderately reliable: depends on arrangement of components and bus
Ring bus
High reliability: single failure isolates single component
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Figure 19: Double bus bar arrangement of substations
4.4 Specification of the Major Substation Equipment
In every electrical substation, there are various indoor and outdoor equipments. The choice of the
equipment depends on technical consideration, rated voltages, rated MVA and the type of substation
[52]. Also the design of the high-voltage substation must include consideration for the safe operation
and maintenance of the equipment. Switching equipment is used to provide isolation, no load
switching, load switching, and/or interruption of fault currents. The magnitude and duration of the load
and fault currents will be significant in the selection of the equipment used. System operations and
maintenance must also be considered when equipment is selected. One significant choice is the decision
of single-phase or three-phase operation [52]. High-voltage power systems are generally operated as a
three-phase system, and the imbalance that will occur when operating equipment in a single-phase
mode must be considered [52]. Air-insulated high-voltage electrical equipment is generally covered by
standards based on assumed ambient temperatures and altitudes. Ambient temperatures are generally
rated over a range from –40°C to +40°C for equipment that is air insulated and dependent on ambient
cooling. Altitudes above 1000 meters (3300 feet) may require de-rating. At higher altitudes, air density
decreases, hence the dielectric strength is also reduced and de-rating of the equipment is recommended
[51, 52]. Operating (strike distances) clearances must be increased to compensate for the reduction in
dielectric strength of the ambient air. Also, current ratings generally decrease at higher elevations due
to the decreased density of the ambient air, which is the cooling medium used for dissipation of the
M-Tech Thesis, Defense Engineering College, 2014
48
heat generated by the load losses associated with load current levels[52]. Galvanized steel towers for
incoming and outgoing lines are located near the fencing of the substation. In some cases the incoming
and out gong Lines may in the form of underground power cables or SF6 gas insulated cables. The
main HV, MV and LV equipment in the substation are generally located outdoor. All the live parts at
HV, MV and LV are supported on insulators. Sufficient phase to phase, phase to ground, section
clearances are provided. For live parts a substation is composed of the following distinct circuits [52]:
A power circuits through which the power flows from incoming lines to the outgoing lines
1. A power circuits through which the power flows from incoming lines to the outgoing lines
2. AC control and protection circuits connected to the secondary of CT’s and VT’s. These
circuits are at low AC or DC voltages.
3. Auxiliary AC and DC power circuits, carrying high power at high voltage.
4.4.1 Selection of Power Transformer
By using the IEC standards for power transformer ratings the power transformer is selected. As the
future power demand is approximately 230MVA.Selection of five 50 MVA each power transformers
with 132/33kV ONAN/ONAF is suitable.
Table 15. Technical specification of selected power transformer
1
2
3
4
5
6
7
8
9
10
11
MVA
KV Ratio
Cooling
Impedance
Winding resistance
Tapping Mode
Tapping Range
Temp Rise (Oil/Winding)
Vector Group
Phases
Frequency
50
132/33KV
ONAN/ONAF
8% at 25.2 MVA
10% at25.2MVA
OLTC
+/- 10% @ 1.25% (16 steps)
50/55 Deg C
YNd11
3
50Hz
4.4.2 Voltage Drop at Transformers
The voltage drop in power transformer is due to the leakage reactance and the winding resistance.
Rather than expressing the impedance in ohms per phase the normal convention with the transformer
is to express the impedance as a percentage value referred to the KVA or MVA rating of transformer.
The change in the transformer terminal voltage from no load to full load is the regulation of the
transformer. The voltage drop is calculated as [51]
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49
1
Δ𝑈 = [(𝑅 ∗ 𝑃)2 + (𝑥 ∗ Q)2 ]2 ÷ 100%
(4.1)
Where:
𝑥
Is Leakage reactance (%) =8
𝑅
Is Winding resistance (%) =10
𝑃
Is Power factor 𝐶𝑜𝑠𝛷 (%) =0.91
𝑄
Is 𝑠𝑖𝑛𝛷 (%) =0.41
Δ𝑈
Is % voltage drop at full load
1
Δ𝑈 = [(𝑅 ∗ 𝑃)2 + (𝑥 ∗ 𝑞)2 ]2 ÷ 100%
Then according to equation (4.1) the voltage drop at each transformer is 0.096%.
4.4.3 Selection of Transformer Feeders
In order to select an appropriate cable for the primary and secondary transformers, it is necessary to
know the following:
1. Size and type of load to be supplied
2. Permissible voltage drop
3. Protective fault current
4. Circuit protection
5. Environmental conditions of installation
4.4.4 Current Rating Calculations
In order to select the appropriate cable size, it is necessary to know the voltage and load current in
Amperes or as MW or MVA. The rated current of the primary cable is calculated by equation (4.2) as
follows [59].
𝐼𝑟𝑎𝑡𝑒𝑑 =
=
𝑀𝑉𝐴
(4.2)
√3 ∗ 𝑉
50 ∗ 106 𝑉𝐴
√3 ∗ 132 ∗ 103 𝑉
= 218.69𝐴
De-rating is a technique used in electrical power where devices are operated at a condition greater than
their rated maximum power dissipation. De-rating increase the margin of safety between part design
limits and applied stress there by providing extra protection for the part. By applying de-rating in an
electrical design its degradation rate is reduced, the reliability and life expectancy are improved [51].
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By considering a De-rating factor of 0.85, the standard current that flows through the primary cable is
given by
𝐼𝑠𝑡𝑎𝑛𝑑𝑎𝑟𝑑 =
=
𝐼𝑟𝑎𝑡𝑒𝑑
𝐷𝑒𝑟𝑎𝑡𝑖𝑛𝑔𝑓𝑎𝑐𝑡𝑜𝑟
(4.3)
218.69
= 257.28𝐴
0.85
The stranded copper conductors table shows that a 3x95 mm2 single core unarmoured XLPE insulated
PVC sheathed 600/1000V stranded copper conductors cable would be capable of carrying a load of
300 A.
The rated current of the secondary cable is also calculated by equation (4.4) as follows
𝐼𝑟𝑎𝑡𝑒𝑑 =
=
𝑀𝑉𝐴
(4.4)
√3 ∗ 𝑉
50 ∗ 106 𝑉𝐴
√3 ∗ 33 ∗ 103 𝑉
= 874.77𝐴
De-rating is a technique usually in electrical power where in the devices are operated at less than their
rated maximum power dissipation, De-rating increase the margin of safety between part design limits
and applied stress there by providing extra protection for the part. By applying de-rating in an electrical
design its degradation rate is reduced, the reliability and life expectancy are improved [51]. By
considering a De-rating factor of 0.85, the standard current that flows through the secondary cable is
given by equation (4.3)
𝐼𝑠𝑡𝑎𝑛𝑑𝑎𝑟𝑑 =
=
𝐼𝑟𝑎𝑡𝑒𝑑
𝐷𝑒𝑟𝑎𝑡𝑖𝑛𝑔𝑓𝑎𝑐𝑡𝑜𝑟
874.77
= 1.29𝐾𝐴
0.85
From the stranded copper conductors table we can get a 3x800 mm2 single core unarmoured XLPE
insulated PVC sheathed 600/1000V stranded copper conductors cable would be capable of carrying a
load of 1086 A.
4.4.5 Voltage Drop Calculations
Permissible voltage drop is computed by calculating the highest current drawn by the load multiplied
by an appropriate factor. The maximum voltage drop according to IEEE standard for distribution
system is 5%.The voltage drop can be calculated multiplying the current by the impedance of the length
of the cable. Calculate the percentage voltage drop by reference to the phase to earth voltage [51].
M-Tech Thesis, Defense Engineering College, 2014
51
The voltage drop is calculated by equation (4.5)
𝑧
) ∗ 𝐼𝑟𝑎𝑡𝑒𝑑 ∗ 𝐷
𝑘𝑚
𝑉𝑑𝑟𝑜𝑝 = √3 ∗ (
(4.5)
Where:
D
Is distance in Km
z
Is impedance in Ω/km
From data table of conductor specifications impedance per kilometer for 3x95 mm2cable is
0.2631Ω/km and considering a distance from Kaliti substation to Bishoftu substation is 30km
distribution substation, the voltage drop in the primary feeder is calculated as follows
𝑧
) ∗ 𝐼𝑟𝑎𝑡𝑒𝑑 ∗ 𝐷
𝑘𝑚
𝑉𝑑𝑟𝑜𝑝 = √3 ∗ (
0.2631𝛺
= √3 ∗ (
𝑘𝑚
) ∗ 218.69𝐴 ∗ 30𝑘𝑚 = 2989.72V
Percentage voltage drop = (2989.72/132000)* 100 =2.26% which is acceptable value.
From data table of conductor specifications impedance per kilometer for 3x800 mm2cable is
0.0963Ω/km and considering an average distance from to the load is 12 km, the voltage drop in the
primary feeder is calculated as follows
𝑧
) ∗ 𝐼𝑟𝑎𝑡𝑒𝑑 ∗ 𝐷
𝑘𝑚
𝑉𝑑𝑟𝑜𝑝 = √3 ∗ (
0.0963𝛺
= √3 ∗ (
𝑘𝑚
) ∗ 874.77𝐴 ∗ 12𝑘𝑚 = 145.9 V
Percentage voltage drop = (1550.9/33000)*100 = 5.03% which is acceptable value.
4.4.6 Fault Current Calculations
Electric cables are designed to operate below a certain maximum temperature, this being dependent on
the conductor material and the type and the thickness of the insulation. Cable selection for a particular
installation must therefore be made on the basis of not exceeding these temperature limits.
For a power transformer with 132/33 kV with 50 MVA rating, the short-circuit capacity is 1000 MVA
[IEC 60076-5]. The earth fault level is 100 MVA, and it may be assumed that a fault will be cleared in
half a second.
The supply impedance seen from the primary side is given by equation (4.6)
𝑍𝑠𝑦𝑠
M-Tech Thesis, Defense Engineering College, 2014
(𝑉𝑃 )2
=
𝑆𝑠𝑐
(4.6)
52
=
(132)2 𝑘𝑣
= 17.42 𝜴
1000𝑘𝑣/𝛺
The short circuit current that can exist on the primary feeder is calculated by equation (4.7)
𝐼𝑆𝐶 =
𝑉𝑃
√3 ∗ 𝑍𝑠𝑦𝑠
132
=
√3 ∗ 17.4
(4.7)
= 4.36
Or the short circuit current that can exist on the primary feeder can be calculated by equation (4.8)
𝐼𝑆𝐶 =
𝑆ℎ𝑜𝑟𝑡𝐶𝑖𝑟𝑢𝑖𝑡𝑀𝑉𝐴
1000 ∗ 106
=
(4.8)
√3 ∗ 𝑉𝑜𝑙𝑡𝑎𝑔𝑒𝑅𝑎𝑡𝑖𝑛𝑔
√3 ∗ 132 ∗ 103
= 4.37𝐾𝐴
The short circuit current withstand capacity of the cable is calculated by equation 4.9
𝐼𝑆𝐶 =
𝐾∗𝐴
(4.9)
√𝑡
Where:
A
Is Cross-section of conductor (mm2)
𝐼𝑆𝐶
Is Short circuit rating of cable (kA)
A
Is Cross-section of conductor (mm2)
t
Is time to trip (in seconds)
K
Is A constant that depends on conductor material and temperature
= 143 A/mm2 for XLPE, Copper conductor
= 92 A/mm2 for XLPE, Aluminum conductor
𝐼𝑆𝐶 =
143 ∗ 95
√0.5
= 19.21
Therefore the cable can withstand the prospective short circuit current.
The cable earth fault current that can exist in the secondary feeder is calculated by equation 4.10
𝐼𝐸𝐹 =
=
M-Tech Thesis, Defense Engineering College, 2014
𝐸𝑎𝑟𝑡ℎ𝐹𝑎𝑢𝑙𝑡𝑀V𝐴
√3 ∗ 𝑉𝑜𝑙𝑡𝑎𝑔𝑒𝑅𝑎𝑡𝑖𝑛𝑔
100 ∗ 106
√3 ∗ 132 ∗ 103
(4.10)
= 437.39𝐴
53
The cable earth fault current withstand capacity is calculated by equation (4.11)
𝐼𝐸𝐹 =
𝐾∗𝐴
(4.11)
√𝑡
Where:
IEF
Earth fault current (kA)
A
Cross-sectional area of earth path (mm2)
t
Fault duration in seconds (0.50sec)
K
A constant that depends on earth path material
= 143 A/mm2 for Copper tape
= 76 A/mm2 for Aluminum wire amour
𝐼𝐸𝐹 =
143 ∗ 95
√0.5
= 19.21
Therefore the cable can withstand the prospective earth fault current.
In many cases, the cable conductor size is larger than dictated by the full load current, and is chosen in
order to withstand the prospective short-circuit current. The use of large conductors can be avoided by
improving the speed of protection and in the case of earth fault current, by the use of sensitive earth
fault protection.
The supply impedance transferred to the secondary side is given by equation (4.12)
2
𝑉s
𝑍𝐿 = 𝑍𝑠𝑦𝑠 ∗ ( )
𝑉𝑝
𝑍𝐿 = 17.424 ∗ (
(4.12)
33 2
) = 1.089𝛺
132
The short circuit current that can exist on the primary feeder is calculated by equation (4.13)
𝐼𝑆𝐶 =
𝑉𝑠
(4.13)
√3 ∗ 𝑍𝑠𝑦𝑠
𝐼𝑆𝐶 =
33
√3 ∗ 1.089
= 17.5𝐾𝐴
Or the short circuit current that can exist in the secondary feeder is calculated by equation (4.14)
𝐼𝑆𝐶 =
M-Tech Thesis, Defense Engineering College, 2014
𝑆ℎ𝑜𝑟𝑡𝐶𝑖𝑟𝑐𝑢𝑖𝑡𝑀𝑉𝐴
√3 ∗ 𝑉𝑜𝑙𝑡𝑎𝑔𝑒𝑅𝑎𝑡𝑖𝑛𝑔
(4.14)
54
=
1000 ∗ 106
√3 ∗ 33 ∗ 103
= 17.5𝐾𝐴
The short circuit current withstand capacity of the cable is calculated by equation (4.15)
𝐼𝑆𝐶 =
𝐾∗𝐴
(4.15)
√𝑡
Where:
𝐼𝑠𝑐
Is Short circuit rating of cable (kA)
A
Is Cross-section of conductor (mm2)
t
Is time to trip (in seconds)
K
Is a constant that depends on conductor material and temperature
= 143 A/mm2 for XLPE, Copper conduct
= 92 A/mm2 for XLPE, Aluminum conductor
𝐼𝑠𝑐 =
143 ∗ 500
= 101.12
√0.5
Therefore the cable can withstand the prospective short circuit current.
The cable earth fault current that can exist in the secondary feeder is calculated by equation (4.16)
𝐼𝑆𝐶 =
𝑆ℎ𝑜𝑟𝑡𝐶𝑖𝑟𝑐𝑢𝑖𝑡𝑀𝑉𝐴
√3 ∗ 𝑉𝑜𝑙𝑡𝑎𝑔𝑒𝑅𝑎𝑡𝑖𝑛𝑔
=
100 ∗ 106
√3 ∗ 33 ∗ 103
(4.16)
= 1.75𝐾𝐴
The cable earth fault current withstand capacity is calculated by equation (4.17)
𝐼𝐸𝐹 =
𝐾∗𝐴
√𝑡
(4.17)
Where:
IEF
𝐼𝐸𝐹 =
Earth fault current (kA)
143 ∗ 500
√0.5
= 101.12𝐾𝐴
Therefore the cable can withstand the prospective earth fault current.
In many cases, the cable conductor size is larger than dictated by the full load current, and is chosen in
order to withstand the prospective short-circuit current. The use of large conductors can be avoided by
M-Tech Thesis, Defense Engineering College, 2014
55
improving the speed of protection and in the case of earth fault current, by the use of sensitive earth
fault protection.
4.4.7 Selection of Bus Bars
The main functional requirement of bus bar system is:
 To carry 𝐼𝑟𝑎𝑡𝑒𝑑 continuously and limited over loading
 To withstand the rated voltage of system ( 𝑉𝑟𝑎𝑡𝑒𝑑 ) and the specified transient over voltage
of the system without flashover
 To provide low resistance path for current flow
 Outdoor bus bars should have minimum corona losses
The bus bar for the new substation is selected by using the IEEE standards for bus bar ratings. The bus
bar is designed with the consideration of not only the present load but also the future loads.
Rating calculations for the bus bar:
 Rated Load Capacity = 230MW
 Voltage = 132 KV
The rated current (𝐼𝑟𝑎𝑡𝑒𝑑 ) of the bus-bar is calculated by equation (4.18)
𝐼𝑟𝑎𝑡𝑒𝑑 =
𝑃
√3 𝑉 cos 𝛷
=
230
√3 ∗ 132 ∗ 0.91
= 1.12 𝐾𝐴
(4.18)
So a bus-bar with a current rating of 1.25 kA is selected for the 132 kV side.
 Rated Load Capacity = 250 MW
 Voltage = 33 KV
The rated current (Irated) of the bus-bar is calculated by equation (4.18)
𝐼𝑟𝑎𝑡𝑒𝑑 =
𝑃
√3 𝑉 cos 𝛷
=
230
√3 ∗ 33 ∗ 0.91
= 4.47𝐾𝐴
So a bus-bar with a current rating of 5 kA is selected for the 33 kV side.
 Short Time Withstand Current
This is the maximum rms total current that can be carried momentarily without electrical, thermal, or
mechanical damage. Standard ratings for a bus and its extensions should be matched to the breaker
rated value [51].
The ratings of 132 and 33 kV bus-bars are indicated in Table 16
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Table 16. Ratings of Bus-bars within the guidelines of ANSI/IEEE Std.C37.20.2
Description
Type of Bus-bar
Rated Current
Rated Insulation Voltage
Rated Short Time Withstand Current
Conductors
a) Bar Dimensions
For 132KV
Copper
1.25 kA
3000kV
65 kA
For 33KV
Copper
5 kA
1000 kV
100 kA
90 mm * 6 mm2
2 * 200 mm * 6 mm2
b) Cross Sectional Area
Resistance
Reactance
Impedance
Voltage Drop ( line to line at Power factor of 0.9)
540 mm2
( 0.036 mΩ/m)
(0.01 mΩ/m)
(0.038 mΩ/m)
(0.08 V/m)
2400 mm2
( 0.0091 mΩ/m)
(0.0025 mΩ/m)
(0.0094 mΩ/m)
(0.08 V/m)
4.4.8 Selection of Circuit Breakers
Circuit breakers are a piece of electrical device that:
 Make or break a circuit either manually or by remote control under normal conditions.
 Break a circuit automatically under fault conditions.
 Make a circuit either manually or by remote control under fault conditions
Rated voltage, rated current and rated short-circuits breaking (interrupting) capacity of circuit breaker
must be determined. Short circuit capacity of the circuit breaker must be above the maximum short
circuit current exists in the location.
The ratings of 132 and 33 kV circuit breakers are indicated in Table17.Standard Rating Structure for
AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis. ANSI/IEEE Std. C37.04
 Rated Short-Circuit Current
The rated short-circuit current of a circuit breaker is the highest value of the symmetrical component
of the poly phase or line-to-line short-circuit current in rms amperes measured from the envelope of
the current wave at the instant of primary arcing contact separation that the circuit breaker is required
to interrupt at rated maximum voltage and on the standard operating duty. It also establishes, by fixed
ratios as defined in ANSI/IEEE Std. C37.04-5.10.2, the highest currents that the breaker is required to
close and latch against, to carry, and to interrupt. [51]
M-Tech Thesis, Defense Engineering College, 2014
57
 Rated Insulation Levels
Rated insulation levels consist of two items:
1. 60 Hz, one-minute withstand voltage, and
2. Impulses withstand voltage or BIL [51].
The standard values are defined in IEEE Std. C37.20.2.
Table 17. Ratings of Circuit Breaker
Description
Type of Circuit Breaker
Rated Service Voltage
Rated Maximum Voltage
For 132 kV
Outdoor Type
132 kV
145 kV
For 33 kV
Outdoor Type
33 kV
36 kV
Type of Quenching Medium
Rated Current
Rated Short Circuit Current
Number of Poles
Rated Frequency
Rated Short Circuit Making Current
Short Circuit withstand current duration
Insulation level
a) Power Frequency Withstand ( kV RMS for 1 min)
b) Impulse Withstand (1.2/50 μsec) kV Peak
SF6
400A
31.5 kA
3
50 Hz
63 kA
0.5 Sec
SF6
1250A
25 kA
3
50 Hz
100 kA
0.5 Sec
170 kV
650 kV
70 kV
170 kV
4.4.9 Selection of Surge Arresters
The lightning arrester mainly differs in their constructional features. However they work with the same
operating principle, i.e. providing low resistance path for the surges. They are mainly classified as:
1) Rod gap arrester
2) Metal Oxide without gap arrester
3) Horn gap arrester
4) Multi-gap arrester
5) Expulsion type lightning arrester
Selection of the proper ratings of a metal oxide arrester without gap is considered in this design; this is
because currently EEPCo is using metal oxide without gap arresters.
The ratings of 132 and 33 kV circuit breakers according to ANSI/IEEE Std. C37.04 indicated in Table
18.
M-Tech Thesis, Defense Engineering College, 2014
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Table 18. Ratings of Surge Arresters
For 33 KV
Outdoor
30 kV
Description
Type of Surge Arresters
For 132 KV
Outdoor
Rated Operating Voltage (Ur)
108 kV
Rated Continuous Operating Voltage (Uc)
Nominal Discharge Current
Rated Short-time- Current
Rated Frequency
Insulation level
a) Power Frequency Withstand Voltage ( kV RMS for 1min)
b) Impulse Withstand Voltage (1.2/50 μsec) kV Peak
Residual voltage for
a) Lightning current 8/20 impulse
b) Step current 1/20 impulse of 10 Ka
c) Switching Current 30/60 Impulse of 500 A/1000 A
High current 4/10 impulse withstand value
Low current, long duration current impulse withstand (upper
value)
84 kV
10 kA
31.5 kA
50 Hz
21 kV
170KV
650KV
70 kV
170 kV
100 kA
100 kA
1000 kA
1000 kA
10 kA
25 kA
50 Hz
4.4.10 Selection of Isolators
Isolator shall be designed such that in fully open position, it shall provide adequate electrical isolation
between the contacts on all the three switches. Isolator shall be horizontal side opening, double side
break rotating post type for use on a 132kV, 50 Hz, 3 - phase system. The isolator shall be motorized
and also fitted with manual operation facility. All the three switches shall be arranged to ensure
simultaneous operation of all switches by drive rods and operating handle for both manual and motor
operation. Auxiliary dry contacts, five normally open and five normally closed shall be provided for
electrical interlocks such that the isolator and associated 132 kV circuit breakers can be interlocked
with each other. The contacts shall be rated to continuously carry at least 10Amps at voltages up to
500V dc/ac.
The ratings of 132 and 33 kV isolators according to ANSI/IEEE C62.2, including their operating
devices and auxiliary equipments are indicated in Table 19.
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Table 19. Ratings of Isolators
Description
Rated Service Voltage
Rated Maximum Voltage
Rated Current
Rated Short-time- Current
Number of Poles
Rated Frequency
Rated Maximum Withstand current
Closing or Opening Time
Insulation level
a) Power Frequency Withstand Voltage ( kV RMS for 1 min)
b) Impulse Withstand Voltage (1.2/50 μsec) kV Peak
For 132 KV
132 kV
145 kV
400A
25 kA
3
50 Hz
100 kA
≤ 30 Sec
For 33 KV
33 kV
36 kV
1250A
31.5 kA
3
50 Hz
100 kA
≤ 30 Sec
170KV
650KV
70KV
170KV
4.4.11 Selection of Current Transformers (CTS)
A CT is essentially a step up transformer which steps down a current to known ratio. The primary of
this transformer consists of one or more turns of thick wire connected in series with the line. The
secondary consists of a large no. of turns of a fine wire and provides for the measuring instruments and
relays a current which is a constant fraction of current in the line. For example, protection devices and
revenue metering may use separate CTs to provide isolation between metering and protection circuits,
and allows current transformers with different characteristics (accuracy, overload performance) to be
used for the devices. Current transformers are used for measurement of current and to provide
secondary current for protection purposes.
The ratings of 132 and 33 kV current transformers according to ANSI/IEEE Std. C57.13 indicated in
Table 20.
M-Tech Thesis, Defense Engineering College, 2014
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Table 20. Ratings of Current Transformers
Description
Rated Service Voltage
Rated Maximum Voltage
Rated Primary Current
a) for line feeder
b) for transformer feeder
Rated secondary currents
Short-time- Current Ratings
Rated Short Circuit Maximum Current
Rated Frequency
Insulation level
a) Power Frequency Withstand Voltage ( kV RMS for 1 min)
b) Impulse Withstand Voltage (1.2/50 μsec) kV Peak
For 132 KV
132 kV
145 kV
For 33 KV
33 kV
36 kV
800 - 400 - 200
800 - 400 - 200
5-5–5
25 kA
100 kA
50 Hz
400 - 200 - 100
800 - 400 - 200
5-5-5
31.5 kA
60 kA
50 Hz
170 kV
650KV
70 kV
170 kV
4.4.12 Selection of Potential Transformer (PT)
PT is essentially a step down transformer and steps down the voltage to a known ratio. The primary of
PT consists of a large number of turns of fine wire connected across the line. The secondary winding
consists of a few turns and provides for measuring instruments and relays a voltage which is known
fraction of the line voltage. It is connected right on the point where line is terminated. Voltage
transformers are used for measurement of voltage and to provide secondary voltage for protection
purposes and measurements.
The ratings of 132 and 33 kV voltage transformers according to ANSI/IEEE Std. C57.13 indicated in
Table 21.
Table 21. Ratings of Voltage Transformers
Description
Rated Maximum Voltage
Rated Primary Voltage
Rated Secondary Voltage (second winding)
Rated Frequency
Insulation level
a) Power Frequency Withstand Voltage ( kV RMS for 1 min)
b) Impulse Withstand Voltage (1.2/50 μsec) kV Peak
Power frequency withstand voltage secondary winding ( kV
RMS for 1 min)
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For 132 KV
145 kV
132/√3 kV
0.1/√3 kV
50 Hz
For 33 KV
36 kV
33/√3 kV
0.1/√3 kV
50 Hz
170 kV
650KV
70 kV
170KV
2 kV
2 kV
61
4.4.13 Selection of RTU and computers
Remote Telemetry Units (RTUs) are multiplexed addressable I/O device with communications. They
have input and out-put points and they are connected to a more intelligent controller. The controller is
responsible for the control algorithm. This kind of RTU has very little computing power and is specified
for use in installations like substation automation. The Remote Telemetry Unit is strictly a slave device.
It is not programmable and cannot be used as a stand-alone controller, but it is usually addressable. We
can use it to relay status and values both from the remote site to a controller and from the controller
down [47].
Table 22: Ratings for RTU
Discretion
Temperature range
CPU size
Total memory
Ethernet ports
Input isolation
mechanical vibrations
Size
+10 to +50𝑜𝐶
32 bit 50MHz
16MB
2/2
2.5 kV AC
0.035 mm @ 50 Hz
4.5 Earth Mat Design
Safety and reliability are the two major concerns in the operation and design of an electrical substation.
These concerns also pertain to the design of substations. To ensure that substations are safe and reliable,
the substation must have a properly designed earthling (grounding) system. Earthing or grounding
means connecting all parts of the apparatus (other than live part) to the general mass of earth by wire
of negligible resistance. This ensures that all parts of the equipment other than live part shall be at earth
potential (i.e., zero potential) so that the operator shall be at earth potential at all the time, thus will
avoid shock to the operator. The neutral of the supply system is also solidly earthed to ensure its
potential equal to zero.
The substation ground grid design is based on the substation layout plan. The following points serve
as guidelines to start a grounding grid design [51]:
1. The substation should surround the perimeter and take up as much area as possible to avoid
high current concentrations. Using more area also reduces the resistance of the grounding grid.
2. Typically conductors are laid in parallel lines. Where it is practical, the conductors are laid
along the structures or rows of equipment to provide short ground connections.
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3. Typical substation grid systems may include 4/0 bare copper conductor buried 0.3-0.5 m below
grade and spaced 3-7 m apart in a grid pattern. The conductors should be securely bonded at
cross-connections
4. Ground rods may be installed at grid corners and junction points along the perimeter. They may
also be installed at major equipment, especially near surge arresters.
5. The grid should extend over the entire substation and beyond the fence line
6. The ratio of the sides of the grid meshes is usually 1:1 to 1:3
Conductors can be of various materials including copper, copper-clad steel, aluminum, or steel. Each
type of conductor has advantages and disadvantages. Copper is the most commonly used material for
grounding. Copper has high conductivity. Also, it is resistant to most underground corrosion because
it is cathode with respect to most other metals. It also has good temperature characteristics and thermal
capacity [51].
4.5.1 Resistivity of a Soil
The earth’s soil can be considered to be a pure resistance and thus is the final location that a fault
current is dispersed. Soil resistance can contain a current up to a critical amount which varies depending
on the soil and at this point, electrical arcs can develop on the surface of the soil that can electrify
objects on the surface such as a person [51]. Table 22 shows a basic collection of soil resistivity
depending on the moisture and type.
Table 23: Basic Range of Soil Resistivity Ref. IEEE Std. 80
Type of Earth
Wet Organic Soil
Moist Soil
Dry Soil
Bedrock
Average Resistivity (Ω-m)
10
100
1000
10000
Table 23 shows that wet or even moist soil have very small resistances so it is beneficial to keep the
grounding soil as damp as possible. In order to greatly reduce the shock current and increase the contact
resistance between the soil and the feet of people in a substation, a thin layer of a highly resistive
protective surface material just as crushed rock (gravel) is spread above the earth grade at a substation.
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4.5.2 Resistance of the Human Body
The internal resistance of a human body is approximately 300 Ω [51]. The body resistance including
skin ranges from 500-3000 Ω [51]. For simplicity, IEEE Std. 80-2000 represents the resistance of a
human body from hand-to-feet and also from hand-to-hand, or from one foot to the other as
RB = 1000 Ω
The Earth-Mat Design is done according to design procedure on referred ANSI/IEEE standard:
 Basic design data
Design rectangle (total area)
250m x 200m = 50000 m2
Area occupied (A)
10000 m2
Fault current (IEF =Ig)
101.12 kA
Fault duration
0.5 sec
Soil resistivity
100 ohm-m
Depth of burial
0.5 m
Earth electrode
40 mm dia. hard-drawn copper wire, 3 m long
Earth mat conductor
Copper Round
X/R ratio
10
4.5.3 Grid current calculation
A portion of the fault current will flow through the grounding grid to the earth. This is called the grid
current and must be calculated. The maximum grid current, IG is calculated by equation (4.17)
𝐼𝐺 = 𝐷𝑓 ∗ 𝐼𝑔
(4.17)
Where:
𝐼𝐺
Is maximum grid current/ asymmetrical fault current (A)
𝐷𝑓
Is decrement factor for the duration of the fault (From Table 23)
𝐼𝑔 =IEF
RMS symmetrical grid/fault current (A)
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Table 24. Typical Values of DfRef. IEEE Std. 80-2000
Decrement factor, Df
Fault Duration, tf
Cycles at 50 Hz
Seconds
X/R =10 X/R = 20
X/R = 30
X/R = 40
0.00833
0.4165
1.576
1.648
1.675
1.688
0.05
2.5
1.232
1.378
1.462
1.515
0.1
5
1.125
1.232
1.316
1.378
0.2
10
1.064
1.125
1.181
1.232
0.3
15
1.043
1.085
1.125
1.163
0.4
20
1.033
1.064
1.095
1.125
0.5
25
1.026
1.052
1.077
1.101
0.75
37.5
1.018
1.035
1.052
1.068
1
50
1.013
1.026
1.039
1.052
Using Table 23 for a fault duration of 0.5 seconds and the X/R ratio of 10, the decrement factor 𝐷𝑓 =
1.026.
The asymmetrical fault current is calculated as follows:
𝐼𝐺 = 1.026 ∗ 101.12 = 103.75𝐾𝐴
4.5.4 Earth Conductor Sizing
The cross-section area of main earth conductor should be decided by considering mechanical thermal
and electrical considerations. The equation 4.18 is based on referred ANSI/IEEE standard.
𝐴=
𝐼𝐺
𝑇𝐶𝐴𝑃∗10−4
√(
𝑡𝑐 𝛼𝛾 𝜌𝛾
𝐾𝑜 +𝑇𝑚
) 𝑙𝑛 ( 𝐾
𝑜 +𝑇𝑎
(4.18)
)
Where:
IG
Asymmetrical fault current (kA) = 104.78 kA
A
Conductor cross section (mm2)
Tm
Maximum allowable temperature (°C) = 1084 °C
Ta
Ambient temperature (°C) = 40 °C
αr
Thermal coefficient of resistivity at reference temperature
Tr (1/°C) =0.00381(1/°C)
ρr
resistivity of the ground conductor at reference temperature Tr (µΩ-cm) = 1.78
tc
Duration of fault current (sec) = 0.5
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65
K0
Equals 1/ α0 or (1/ αr) - Tr (°C) = 242
TCAP
Thermal capacity per unit volume (J/𝑐𝑚2∙℃) = 3.42
Common values of αr, K0, Tm, ρr, and TCAP values can be found in Table 18.
The cross-section area of the earth conductor is then calculated by equation (4.18) as follows
103.75
𝐴=
√(
3.42∗10−4
242+1084
= 265.18𝑚𝑚2
) 𝑙𝑛 ( 242 + 40 )
0.5∗0.00381∗1.78
The diameter of a conductor (dc) can be calculated by equation (4.19)
𝑑𝑐 = 2 √
𝐴
𝛱
(4.19)
265
𝑑𝑐 = 2 √
= 18.38𝑚𝑚
𝛱
From the results of cross-section area of the earth conductor determination we get 265.18𝑚𝑚2 the
standard copper value near to the calculated value is then 300𝑚𝑚2 . However, 300𝑚𝑚2 Hard-drawn
copper conductor is used.
Table 25. Material constants Ref. IEEE Std. 80-2000
Description
Copper, annealed soft-drawn
Copper, commercial hard-drawn
Copper-clad steel wire
Copper-clad steel wire
Copper-clad steel rod
Aluminum, EC grade
Aluminum, 5005 alloy
Aluminum, 6201 alloy
Aluminum-clad steel wire
Steel-1020
Stainless-clad steel rod
Zinc-coated steel rod
Stainless steel, 304
Material
αr factor at Ko at
Conductivity 20°C
0°C
(%)
(1/°C)
(0°C)
100
0.00393
234
97
0.00381
242
40
0.00378
245
30
0.00378
245
20
0.00378
245
64
0.00403
228
53.5
0.00353
263
52.5
0.00347
2268
20.3
0.0036
258
10.8
0.0016
605
9.8
0.0016
605
8.6
0.0032
293
2.4
0.0013
749
M-Tech Thesis, Defense Engineering College, 2014
Fusing
ρr at
temperature 20°C
Tm(°C)
(μΩ-cm)
1083
1.72
1084
1.78
1084
4.4
1084
5.86
1084
8.62
657
2.86
652
3.22
654
3.28
657
8.48
1510
15.9
1400
17.5
419
20.1
1400
72
TCAP
thermal
capacity
(J/cm3°C)
3.42
3.42
3.85
3.85
3.85
2.56
2.6
2.6
3.58
3.28
4.44
3.93
4.03
66
4.5.5 Grid Resistance Calculation
The ground resistance for a substation needs to be very low to minimize the ground potential rise and
increase the safety of the substation. The ground resistance is usually 1 Ω or less for transmission and
other large substations [51]. In distribution substations, the usual acceptable range is 1-5Ω. Resistance
primarily depends on the area to be occupied. Also resistance can be decreased for a given area by
using ground rods and adding more grid conductors. If it is impossible to reach a desired ground
resistance by adding more grid conductors and/or ground rods, the soil surrounding the electrode can
be modified [51].
Considering the area occupied by the grounding grid a layout of 100m x 100m with equally spaced
conductors in ETAP software we can see the results of ground grid design as shown in figure 17with
spacing distance D = 20m and a grid burial depth h = 0.5m.
Figure 20.Rectangular Ground Grid system with 44 ground rods
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The grid wire pattern is 11 x 11 and the grid conductor combined length (LC) is
𝐿𝐶 = (11 ∗ 250) + (11 ∗ 200) = 4950𝑚
Assume that the 44 ground rods, 3m long are used as shown in Figure 18
𝐿𝑅 = 44𝑥3 = 132𝑚
The total length of buried conductor (LT) is
𝐿𝑇 = 𝐿𝐶 + 𝐿𝑅
(4.20)
= 4950 + 132
= 5082𝑚
Using the total length of buried conductor calculated in the previous step LT = 5082m and having the
grid area A = 50000 m2, the substation grounding resistance (Rg) is calculated by equation (4.21) by
considering dry soil.
𝑅𝑔 = 𝜌 [
1
1
1
+
(1 +
)]
𝐿𝑇 √20𝐴
1 + ℎ√20/𝐴
(4.21)
Where:
𝑅𝑔
Is substation ground resistance (Ω)
Ρ
Is soil resistivity (Ω-m) = 1000 Ω-m
LT
Is total length of buried conductor = 5082 m
A
Is area occupied by the ground grid (𝑚2) = 50000 m2
H
Is ground rod height = 3 m
𝑅𝑔 = 1000 [
1
1
1
+
(1 +
)] = 1.94𝛺
5082 √20𝑥50000
1 + 3√20/50000
4.5.6 Calculation of Attainable Touch and Step Potential
Attainable touch voltage is a form of touch voltage. Attainable touch voltages represent the highest
possible touch voltages that may be encountered within a substation’s grounding system. Attainable
touch voltage is the basis for designing a safe grounding system, both inside the substation and
immediately outside. In order for the grounding system to be safe, the attainable touch voltage has to
be less than the tolerable touch voltage. Otherwise the substation ground grid design needs modification
[51].
The attainable touch voltage can be calculated by equation (4.22)
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𝐸𝐴𝑡𝑡𝑎𝑖𝑛𝑎𝑏𝑙𝑒𝑡𝑜𝑢𝑐ℎ =
𝜌 × 𝐼𝐺 × 𝐾𝑚 × 𝐾𝑖
𝐿𝑀
(4.22)
Where
IG
Is Asymmetrical fault current (kA) = 104.78 kA
ρ
Is resistivity of the earth (Ω/m) = 1000(Ω/m)
LM
Is effective burial length (m)
Km
Is geometrical spacing factor
Ki
Is irregularity factor
The geometrical spacing factor, Km, for attainable touch voltage is calculated by equation (4.23) [28]
(𝐷 + 2 ∗ ℎ)
1
𝐷2
ℎ
𝐾𝑖𝑖
ℎ
𝐾𝑚 =
[𝑙𝑛 [
+
−
]] +
𝑙𝑛 [
]
2×𝛱
16 ∗ ℎ ∗ 𝑑
8∗ℎ∗𝑑
4∗𝑑
𝐾ℎ
𝛱(2 ∗ 𝑛 − 1)
(4.23)
Where
D
Is spacing between parallel conductors (m) = 25 m
d
Is diameter of grid conductors (m) = 18.38 mm
h
Is depth of ground grid conductors (m) = 0.5 m
Kii
Is corrective weighting factor adjusting for the effects of
inner conductors on the corner mesh =1
Kh
Is corrective weighting factor adjusting for the effects of
grid depth =1.225
n
Is geometric factor
The corrective weighted factor Kh is calculated by equation (3.22) [51]
𝐾ℎ = √1 +
ℎ
ℎ𝑜
(4.24)
Where:
h0
𝐾ℎ = √1 +
Is grid reference depth (h0 =1)
0.5
= 1.225
1
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For ground grids with ground rods along the perimeter and throughout the grid, as well as in the corners,
the corrective weighting factor, Kii =1 [51].
The geometric factor n is calculated by equation (3.23) [51].
𝑛 = 𝑛𝑎 ∗ 𝑛𝑏 ∗ 𝑛𝑐 ∗ 𝑛𝑑
(4.25)
Where:
𝑛𝑎 =
𝑛𝑎 =
2 ∗ 𝐿𝐶
𝐿𝑃
2 ∗ 6650
= 12.09
1100
nb=1
for square grids
nc=1
for square and rectangular grids
nd=1
for square, rectangular, and L-shaped grids
𝑛 = 12.09 × 1 × 1 × 1 = 12.09
The irregularity factor Ki, is used in conjunction with n and it is calculated (4.23) [46]
𝐾𝑖 = 0.644 × 0.148 ∗ 𝑛
𝐾𝑖 = 0.644 × 0.148 × 12.09 = 2.434
𝐾𝑚 =
(25 + 2 ∗ 0.5)
1
252
0.5
1
8
[𝑙𝑛 [
+
−
]] +
𝑙𝑛 [
] = 1.33
2×𝛱
16 ∗ 0.5 ∗ 0.01838 8 ∗ 25 ∗ 0.1838 4 ∗ 0.01838
1.255
𝛱(2 ∗ 12.09 − 1)
For ground grids with ground rods along the perimeter and throughout the grid, as well as in the corners,
the effective buried length LM, is calculated by equation (4.26) [51].
𝐿𝑀 = 𝐿𝐶 [1.55 + 1.22 (
𝐿𝑟
√𝐿2𝑥 +𝐿2𝑦
)] 𝐿𝑅
(4.26)
Where:
LC
Is total length of conductor in the horizontal grid(m)=(11 × 250) + (11 × 200) = 5082
LP
Is peripheral length of grid (m) =2*250+2*200=900m
Lx
Is maximum length of grid in the x-direction (m) = 11*250 =2750 m
Ly
Is maximum length of grid in the y-direction (m) = 11*200 = 2200 m
Lr
Is total length of each ground rods (m) = 3 m
LR
Is total length of all ground rods (m) = 44*3= 132 m
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3
𝐿𝑀 = 4950 + [1.55 + 1.22 (
)] 132 = 5154.74𝑚
√27502 + 22002
𝐸𝐴𝑡𝑡𝑎𝑖𝑛𝑎𝑏𝑙𝑒𝑡𝑜𝑢𝑐ℎ =
1000 × 104.78 × 1.33 × 2.434
= 65.18V
5154.74
If a grid system is designed for safe attainable touch voltages, the step voltages will be within tolerable
limits. Step voltages are usually smaller than touch voltages because both feet are in series rather than
parallel. Also, the body can tolerate higher currents through a foot-to-foot path because it doesn’t pass
through vital organs such as the heart. For the ground system to be safe, the attainable step voltage has
to be less than the tolerable step voltage [51].
The attainable step voltage is calculated by equation (4.27) [51]
EAttainabl step =
ρ × K s × K i × IG
LS
(4.27)
The effective buried conductor length LS is calculated by equation (3.27) [51]
LS = 0.75 × LC + 0.85 × LR
(4.28)
LS = 0.75 × 4950 + 0.85 × 132 = 4987.5m
The step factor KS for the step voltage is calculated by equation (4.29) [51]
KS =
1 1
1
1
[
+
+ (1 − 0.5n−2 )]
Π 2×h D+h D
(4.29)
Where:
D
spacing between parallel conductors (m)
h
depth of ground grid conductors (m)
n
geometric factor composed of factors na, nb, nc, and nd
KS =
1
1
1
1
[
+
+ (1 − 0.512.09−2 )] = 0.3308
Π 2 × 0.5 25 + 0.5 25
Therefore the attainable step voltage is
EAttainabl step =
1000 × 0.3308 × 2.434 × 103.75
= 16.74 V
4987.5
4.5.7 Calculation of Tolerable Touch and Step Voltage
For a crushed rock surfacing layer (hS) of 0.1m with surface layer resistivity of 3000 Ω-m, and with
the soil resistivity of 1000 Ω-m, the reduction factor (CS) can be calculated by equation (4.30) [51].
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ρ
Cs = 1 −
0.09 (1 − ρ )
s
(4.30)
2hs + 0.09
1000
Cs = 1 −
0.09 (1 − 3000)
2 × 0.1 + 0.09
= 0.79
The tolerable step and touch potentials are calculated by using equations (4.31) and (4.32) respectively
[51]
ETolerable step = (1000 + 6 × Cs × ρs )
0.116
(4.31)
√t s
ETolerable step = (1000 + 6 × 0.79 × 3000)
ETolerable touch = (1000 + 1.5 × Cs × ρs )
0.116
√0.5
= 2496.82V
0.116
(4.32)
√t s
ETolerable touch = (1000 + 1.5 × 0.79 × 3000)
0.116
√0.5
= 747.24V
Once the attainable touch and step voltages are calculated, the results are compared with the tolerable
touch and step voltages in order to see if the attainable touch and step voltage are below the tolerable
touch and step voltages.
EAttunable touch<<ETolerable touch
EAttunable step <<ETolerable step
Since attainable touch voltage is less than the tolerable touch voltage and the attainable step voltage is
less than the tolerable step voltage therefore, the grounding system is safe.
4.6 Distribution Substation Layout
The drawing included in this section is drawn by using AutoCAD software and includes:
 Primary circuit which includes bus bars ,transformers and feeder lines
 Switching
 Functional Relaying
 Advanced Monitoring (Automation)
 Automatic meter reading (AMR)
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Figure 21 complete single line diagram of the designed system
This drawing will be visible during print directly from AutoCAD, it is now invisible because I bring it to word file.
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CHAPTER FIVE
SIMULATION RESULTS AND DISCUSSION
5.1 Introduction
Reliability assessment involves determining, generally using statistical methods, the total electric
interruptions for loads within a power system. The interruptions are described by several indices that
consider aspects such as [63]:
 The number of customers
 The connected load
 The duration of the interruptions
 The amount of power interrupted and
 The frequency of interruptions.
In Power Factory, Reliability assessment uses a system state enumeration to analyze all possible system
states, one by one. A fast 'topological' method is used which ensures that each possible system state is
only analyzed once. State frequencies (average occurrences per year) are calculated by considering
only the transitions from a healthy situation to an unhealthy one and back again. The software needs
the one line diagram, the voltage and power levels for each component, and the stochastic failure
models for each components as an input and gives the system reliability indices, the load point
reliability indices as an output.
These are some of the units used in the reliability assessment [63]:
1. Frequencies are normally expressed in [1/a] = 'per annum' = per year
2. Lifetimes are normally expressed in [a] = 'annum'
3. Repair times are normally expressed in [h] = 'hours'
4. Probabilities or expectancies are expressed as a fraction or as time per year ([h/a],
[min/a]).
The simulation is done using Dig silent power factory software. Using this software the existing and
the new substations are compared based on the stochastic failure models. Stochastic Failure models
define the probability that a component will fail and when it does fail, the mean time to repair the
component. The following Stochastic failure models are used for this simulation:
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 Bus bar/Terminal Stochastic Model
 Line/Cable Stochastic Model
 Transformer Stochastic Model
 Double Earth Fault Failure Model
The following flow chart shows how to perform reliability assessment using Dig silent power factory
software [63].
Create stochastic models
Define radial feeders
Configure switchs
Define loads
Run Reliability assessment
Figure 22: flow chart for Reliability assessment using Dig silent software
5.2 Stochastic Failure Models
This section describes the stochastic failure models of different substation components using this
stochastic failure model the two substations are evaluated in the Dig silent software. Stochastic Failure
models define the probability that a component will fail and when it does fail, the mean time to repair
the component.
A stochastic reliability model is a statistical representation of the failure rate and repair duration time
for a power system component. For example, a line might suffer an outage due to a short circuit. After
the outage, repair will begin and the line will be put into service again after a successful repair.
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 Bus Bar/Terminal Stochastic Model
The probability of the bus bar failure is the sum of the failure data for the bus bar and the failure data
per connection. For example a bus bar with 3 connections, a failure frequency for the bus bar of 0.002
and a failure frequency of 0.005 per connection will have a total probability of failure of 0.002 + 3 *
0.005 = 0.017.
Table 26: Bus Bar/Terminal Stochastic Model
Bus bar
Failure frequency (1/a)
1
2
3
4
5
5
3
4
3
9
Additional failure per
connection (1/a)
4
2
8
8
12
Repair duration (h)
30
25
12
15
25
 Line/Cable Stochastic Model
The probability of the line failure is determined using the Sustained failure frequency and the length of
the line. For example, a 12 km line with a Sustained failure frequency of 0.032
(1/ (a*km)) will have a failure probability of 12 * 0.032 = 0.384 (1/ (a*km)).
Table 27: Line/Cable Stochastic Model
Line No
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Failure frequency
(1/a(km)
8
6
4
3
9
7
12
10
19
22
20
13
11
14
8
M-Tech Thesis, Defense Engineering College, 2014
Repair duration (h)
Fault frequency 1/(a*km)
15
18
21
20
28
24
19
22
28
17
20
16
18
32
21
3
2
4
6
8
10
12
14
7
6
7
14
12
9
16
76
 Transformer Stochastic failure Model
The probability of the transformers is also includes the failure frequency (1/a) and the repair
durations (h). The failure data for the transformer is given in table 28.
Table 28: Transformer Stochastic Model
Transformer No Failure frequency (1/a)
1
0.005
2
0.004
3
0.006
4
0.007
5
0.006
 Double earth fault failure model
Repair duration (h)
1
2
1.5
2.3
3.2
A double earth fault might occur after voltage rises on healthy phases on a feeder following a single
phase to earth fault on the feeder, causing a second phase to earth fault on the same feeder. For all the
substation equipments it is assumed that the double earth fault occurs with probability of single earth
fault and the frequency of single earth fault is assumed to be 12 /a and the conditional probability of
second earth fault is 20% will take a repair duration of 3 hours.
The reliability configurations of CBs for the existing and the new systems are shown in figures 23 and
24.
Figure 23 switching configuration in the existing system
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Figure 24. Switching configuration in the designed system
5.3 Simulation Result of the Existing Substation
The result of reliability analysis is obtained by performing the following procedures in the Dig Silent
power factory software
 Draw the one line diagram on the working plane of the software
 Specify the voltage and power levels for each component
 Enter the created stochastic models in each component
 Specify the type and operation characteristics of switching and protection devices
 Run the reliability assessment
The following figure illustrates the existing substation of Bishoftu city. In this figure, it is shown that
the existing system is a single bus bar arrangement and there is no any radial feeder. The circuit breakers
and isolators are aged and all of the switching equipments are manually operated. So, that the fault
clearing operations takes longer time.
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Figure 25 the existing substation
The system reliability indices and load point reliability indices are given in the output window of the
software from this output it is observed that the existing substation have reliability problems since the
indices given here are higher for the failure models used as input. The following figure shows the
reliability indices for the system.
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Table 29.Output of system reliability indices for the existing system
The Additional Calculated Indices for Bus bars/Terminals and load point indices on the simulation of
the existing system are given in the output window of the software which is shown in Table 30 and 31.
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Table 30.The Bus bar/ terminal indices of existing system
Table 31.The load point indices of the existing substation
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5.4 Simulation Result of the Designed Substation
The result of reliability analysis is obtained by performing similar procedures as it is done for the
existing system in the Dig Silent power factory software this procedures are:
 Draw the one line diagram on the working plane of the software
 Specify the voltage and power levels for each component
 Inter the created stochastic models in each component
 Specify the type and operation characteristics of switching and protection devices
 Run the reliability assessment
The following figure illustrates the new designed substation for Bishoftu city. In the figure it is shown
that the new designed system is double bus bar arrangement and there feeders are arranged to be radial
feeder. This means by connecting the outgoing feeders with circuit breakers to the nearby feeder, we
can achieve high reliability. And all switching devices are changed by automatically operated circuit
breakers, isolators and load switches.
Figure 26 the layout of the new designed substation
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From the following outputs we can observe that the designed system gives an improved output of
system reliability indices, load point reliability indices and energy reliability based indices. And these
achievements are only by considering the primary system design.
Table 32 output of reliability indices for the designed system
The Additional Calculated Indices for Bus bar/Terminals and load point indices on the simulation of
the designed system are given in the output window of the software which is shown in Table 33 and
34.
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Table 33.The Bus bar/ terminal indices of designed system
Table 34.The load point indices of the designed substation
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5.5 Discussion
As it is explained above the simulation is done to check if the new designed substation can improve
the reliability of the power supply system. This can be done by comparing the outputs of the simulation.
This section takes some of the reliability indices such as System Average Interruption Frequency Index
(SAIFI), System Average Interruption Duration Index (SAIDI), Energy Not Supplied (ENS) and
Momentary Average Interruption Frequency Index (MAIFI) to compare the new and existing
substation and to check the benefit to both supplier and customer from the new system.
Table 35 Selected simulation results for comparison
SAIFI
[1/C/a]
SAIDI
ENS
MAIFI
[h/C/a]
[MWh/a]
[1/Ca]
The existing sub station
129.326130
2885.851
154773.142246
22005.142246
The new substation
32.483425
877.667
35409.669
704.797565
comparing results of simulation
1000000
154773.1422
SAIFI
100000
22005.14225
10000
[1/C/a]
35409.669
2885.851
877.667
SAIDI
[h/C/a]
ENS
[MWh/a]
704.797565
1000
129.32613
100
32.483425
MAIFI
10
[1/Ca]
1
The existing sub station
The new substation
Figure 27 comparing results of simulation
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5.6 Economic Aspects of the Designed System
Using the energy not supplied index (ENS) we can see how much Birr will be lost in the existing and
the new substations. And we can compare the savings from these systems. Since the minimum value
of the tariff is 0.273 Birr/kWh and the maximum value is 0.6943 Birr/kWh then we can take the mean
value of this to perform this analysis which is equal to 0.4835 Birr/kWh.
Table 36 EEPCOS tariff for different applications
Customers
Active energy range (Kwh)
Rate price birr/kWh
0-50
0.273
51-100
0.3564
101-200
0.4993
Residential
201-300
0.55
301-400
0.566
401-500
0.588
Above 500
0.6943
Commercial
0-50
0.6088
Above 50
0.6943
Industrial
>15KV
0.4086
The ENS of both systems is given in Table 35and based on that, we can calculate the amount of money
lost in both systems
 For the existing system
= ENS ∗ tariff
= [(154773.142246[MWh/a])*(0.4835birr/kWh.)]
= [(154773.142246 *103kWh/a)*(0.4835birr/kWh.)
=74,832,814.275941 Birr/a
 For the new system
= ENS ∗ tariff
= [(35409.669MWh/a)*(0.4835birr/kWh.)]
= [(35409.669*103KWh/a)*(0.4835birr/kWh.)
= 17,120,574.9615 Birr/a
From this analysis we can see that the existing substation lost 74,832,814.275941 birr/a. only because
of the interruptions, and the designed substation can reduce this loss by77.12% and the loss will be
come17, 120,574.9615birr/a.
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5.6.1 Interruption Costs to Customers
Access to electricity supplies at reasonable cost and quality levels has become a basic condition for
development, economical growth and welfare. The more developed societies are, the more vulnerable
they are to electricity supply interruptions. This dependence on reliable electricity supplies implies that
costs are associated with electricity supply interruptions.
The size of the economical losses due to interruptions depends largely on the composition of the
customers that experience interruptions. Customers at Bishoftu city are roughly divided into three
categories: residential, commercial, and industrial customers.
For industries, electricity supply interruption costs are strongly related to production losses and to costs
involved in restoring production. In addition, interruptions also cause property damages and revenue
loses for industries, commercial customers and for private individuals.
Wide-spread long-lasting blackouts put the vulnerable society to the test and involve extra expenses
required to maintain tolerable living conditions. It is difficult to estimate the exact value interruption
costs and economical loses, since the properties of each customer are different.
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CHAPTER SIX
CONCLUSIONS, RECOMMENDATIONS AND FUTURE WORKS
Based on the results obtained from this research work which studies the reliability problems of
Bishoftu distribution substation and designing of an improved distribution substation for mitigating the
reliability and overloading problem, this section discusses the major conclusions, the most important
recommendations and the suggested areas of future research work.
6.1 Conclusions
This research work shows that the reliability of the Bishoftu substation II (distribution system of
Bishoftu city) does not meet the requirements set by the regulatory body that is, Ethiopian Electric
Agency (EEA). The average frequency of interruptions at the existing substation is 1812.67
interruptions per customer per year and the average duration of interruptions is 1770.17 hours per
customer per year. There is extremely high unavailability of electric power in the distribution network.
The power supply of the overall system is unavailable for 1770.17 hours per year. There is also much
loss of unsupplied energy due to both planned and non-momentary outages in the existing system. And
also, the reliability of Bishoftu city power supply is very poor as compared to the international
reliability indices and the reliability indices set by EEPCO. There are many reasons for these reliability
problems according to this work, the low capacity, arrangement, aging of the substation equipment,
poor trained of scheduled maintenance and operation and lack of new technologies such as remotely
controlled smart reclosers and circuit breakers are recognized as the main causes for the identified
problems.
Therefore, redesigning the existing substations changing the equipment arrangements as they can
perform their operations in more reliable way, replacing the aged manual switchgear devices,
implementing substation automation and developing awareness of scheduled substation maintenance
and operation are given as the key solutions to solve the problems of the distribution system in this
research work. By implementing these we can improve the reliability of the power supply system from
the current status.
In general, based on simulation results of reliability indices values, the new designed substation
achieved 75% improvement in SAIFI value, 70% improvement in SAIDI value, 77% improvement in
ENS value and 97% improvement in MAIFI value since, the new substations arranged in double bus
bar manner and equipped with remotely controlled circuit breakers and switches which are parts of
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substation automation system. And also, EEPCO can increase its revenue by 78% for that area by
reducing the energy not supplied (ENS) due to interruptions.
6.2 Recommendations
Based on the findings of the research work these important recommendations are given:
 The Ethiopian Electric Power Corporation (EEPCO) should work to improve the reliability of
the power grid at Bishoftu city and in the country as a whole to meet the customer need and the
country’s development need.
 The existing substation should be upgraded to meet the reliability standards. Based on the thesis
results, we recommend that changing the substation arrangement from single Bus Bar to double
Bus Bar system with the automatic switching devices can improve the reliability of the existing
distribution system.
 EEPCO should implement substation automation technologies to improve the quality and
reliability of the power supply.
 The trainings of the maintenance personnel should be high priority so that maintenance works
of the distribution system is conducted with good skill at required quality on regular basis.
 As maintaining power reliability is very essential for economic development of the country and
improving livelihood of the whole population, the problem needs a continuous research and
improvement. Hence, it is recommended to make detailed studies to solve the serious
distribution reliability problems.
6.3 Future Work
The following tasks are suggested as most important areas of study in the future.
1. In-depth study of substation automaton systems for power system reliability.
2. Designing of the whole distribution system for Bishoftu city by implementing network
reduction and distribution automation to achieve better power quality and reliability.
3. Designing of distribution substations with options to accommodate distributed generations.
4. Smart grid technology for power system reliability.
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