FACULTY OF ENGINEERING DEPARTMENT OF ELECTRICAL AND ...eie.uonbi.ac.ke/sites/default/files/cae/engineering/eie/POWER... · DEPARTMENT OF ELECTRICAL AND INFORMATION ENGINEERING POWER

UNIVERSITY OF NAIROBI

FACULTY OF ENGINEERING

DEPARTMENT OF ELECTRICAL AND INFORMATION

ENGINEERING

POWER SUBSTATION, DISTRIBUTION AND PROTECTION SYSTEM

DESIGN FOR FAHARI CITY

PROJECT INDEX: PRJ 097

BY

CYRUS KARIUKI KAMAU

F17/1767/2006 SUPERVISOR: DR. N. O. ABUNGU

EXAMINER: MR. WALKADE

PROJECT REPORT SUBMITTED IN PARTIAL FULFILMENT OF THE

REQUIREMENT FOR THE AWARD OF THE DEGREE

OF

BACHELOR OF SCIENCE IN ELECTRICAL AND ELECTRONICS ENGINEERING

OF THE UNIVERSITY OF NAIROBI 2011

Submitted on: 18TH MAY, 2011

i

DEDICATION

I dedicate this project work to my father Peter and mother Catherine for continually

inspiring me to work hard in my academics, my brothers David, Gerald and Kennedy and

my sisters Charity and Joyce for their support and encouragement throughout my

academic life. God bless you.

ii

ACKNOWLEDGEMENTS

First of all, I thank the Almighty God, who gave me the opportunity and strength to carry

out this work.

I would like to thank Dr. Nicodemus Abungu my supervisor for the opportunity to work

with him, for his helpful suggestions, encouragement, trust and untiring monitoring of my

progress during the project work. Dr. Abungu has been an advisor in the true sense both

academically and morally throughout this project work.

Much appreciation goes to Eng. Limo, Eng. Adai and Eng. Ireri for the helpful technical

information they provided me with regarding this project.

Gratitude is accorded to Nairobi University, for providing all the necessary facilities to

complete my work.

I would like also like to thank all my friends especially Fahari City group members, for

their encouragement, advice and support during my project work.

Special thanks to Mr. Edwin Mokaya and Evelyne Amondi, my proof readers.

God bless you all.

iii

DECLARATION AND CERTIFICATION ND CERTI

This BSc. work is my original work and has not been presented for a degree award in this

or any other university.

………………………………………..

CYRUS KARIUKI KAMAU

F17/1767/2006

This report has been submitted to the Dept. of Elect and Info Engineering, University of

Nairobi with my approval as supervisor:

……………………………………..

Dr. NICODEMUS ABUNGU ODERO

Date: ……………………

FICATION

iv

TABLE OF CONTENTS

CONTENTS DEDICATION ........................................................................................................................... i ACKNOWLEDGEMENTS ..................................................................................................... ii DECLARATION AND CERTIFICATION ........................................................................... iii TABLE OF CONTENTS ........................................................................................................ iv LIST OF FIGURES................................................................................................................ vii LIST OF TABLES ................................................................................................................ viii LIST OF ACRONYMS AND ABBREVIATIONS ................................................................ ix ABSTRACT .............................................................................................................................. x CHAPTER 1 .............................................................................................................................. 1 1.1 INTRODUCTION ......................................................................................................... 1 1.2 STATEMENT OF THE PROBLEM ............................................................................ 1 1.3 OBJECTIVES ................................................................................................................ 3 CHAPTER 2 ............................................................................................................................. 4 2 LITERATURE REVIEW ................................................................................................. 4

2.1.1 ELECTRIC POWER SYSTEM ............................................................................ 4

2.1.2 POWER DISTRIBUTION SYSTEM ................................................................... 4

2.2 DISTRIBUTION SYSTEM PLANNING ..................................................................... 7 2.2.1 FACTORS AFFECTING SYSTEM PLANNING ................................................. 7

CHAPTER 3 .............................................................................................................................. 8 3 FAHARI CITY POWER SYSTEM DESIGN .................................................................. 8

3.1.1 GENERAL........................................................................................................... 8

3.1.2 STANDARDS ..................................................................................................... 8

3.2 LOAD ASSESMENT. .................................................................................................... 8 3.3 SECONDARY SUBSTATION SIZING...................................................................... 10 3.4 GENERAL SUBSTATION LAYOUT ........................................................................ 11 3.5 SUBSTATION SITE LOCATION .............................................................................. 11 CHAPTER 4 ............................................................................................................................ 13 4 GENERAL NETWORK PLAN ...................................................................................... 13 4.1 LOOP FEEDER SYSTEM .......................................................................................... 13

4.1.1 RING MAIN UNIT ............................................................................................ 14

4.2 PRIMARY AND SECONDARY VOLTAGE LEVELS............................................. 15 4.3 SECONDARY DISTRIBUTION SUBSTATIONS SIZING ...................................... 16 CHAPTER 5 ............................................................................................................................ 20 5 SUBSTATION SPECIFIC DESIGN .............................................................................. 20 5.1 SUBSTATION EQUIPMENT ..................................................................................... 20 5.2 SWITCHGEAR AND CONTROLGEAR .................................................................. 22

v

5.2.1 RATINGS .......................................................................................................... 23

5.3 11KV INDOOR SWITCHGEAR AND EQUIPMENT .............................................. 26 5.4 RING MAIN SWITCHGEAR (RMUS) RATINGS ................................................... 28 5.5 33KV OUTDOOR SWITCHGEAR AND EQUIPMENT RATINGS ....................... 28 5.6 SURGE ARRESTORS ................................................................................................ 29 5.7 INSTRUMENT TRANSFORMERS ........................................................................... 30 5.8 POWER TRANSFORMERS ...................................................................................... 30

5.8.1 TRANSFORMER GROUNDING ...................................................................... 30

5.8.2 FINAL POWER TRANSFORMER SPECIFICATIONS .................................... 33

5.9 SUBSTATION FEEDERS ........................................................................................... 33 5.9.1 NUMBER OF FEEDERS ................................................................................... 35

5.9.2 DISTRIBUTION FEEDER EXIT AND DESIGNATION................................... 35

5.10 SUBSTATION SPECIFIC DESIGN LAYOUT ......................................................... 38 CHAPTER 6 ............................................................................................................................ 39 6 CONDUCTOR SIZING .................................................................................................. 39 6.1 SUBSTATION ............................................................................................................. 39

6.1.1 33 KV OVERHEAD BUS CONDUCTORS ....................................................... 39

6.1.2 33KV POWER TRANSFORMER FEEDERS .................................................... 39

6.1.3 11 KV BUS INCOMERS FROM 5MVA POWER TRANSFORMER ................ 39

6.2 DISTRIBUTION .......................................................................................................... 40 6.2.1 11KV RING MAIN FEEDERS .......................................................................... 40

6.2.2 DISTRIBUTION TRANSFORMERS FEEDERS FROM RMU ......................... 40

6.2.3 LOW VOLTAGE SECONDARIES ................................................................... 41

6.2.4 POWER FACTOR ............................................................................................. 41

CHAPTER 7 ............................................................................................................................ 43 7 FAHARI POWER SYSTEM FAULT ANALYSIS AND PROTECTION .................... 43 7.1 FAULT CALCULATION ........................................................................................... 44

7.1.1 BUS FAULT LEVELS....................................................................................... 44

7.1.2 SUMMARY OF RESULTS ............................................................................... 48

7.1.3 CIRCUIT BREAKER RATINGS ....................................................................... 49

CHAPTER 8 ............................................................................................................................... 50 8 PROTECTION ................................................................................................................ 50

8.1.1 OVERCURRENT PROTECTION ..................................................................... 50

8.1.2 EARTH-FAULT PROTECTION ....................................................................... 51

8.1.3 MAGNETISING INRUSH ................................................................................. 51

8.1.4 CONSUMER SERVICE MAINS ....................................................................... 52

vi

8.1.5 DISTRIBUTION TRANSFORMER FEEDER ................................................... 53

8.1.6 RING MAINS .................................................................................................... 56

8.1.7 11 KV SWITCHGEAR (BUSBAR) PROTECTION ........................................... 62

8.1.8 SUBSTATION TRANSFORMERS AND FEEDERS......................................... 64

8.1.9 LIGHTNING PROTECTION ............................................................................. 66

CHAPTER 9 ............................................................................................................................ 68 9 CONCLUSION AND FUTURE WORK ........................................................................ 68 9.1 CONCLUSION ............................................................................................................ 68 9.2 RECOMMENDATIONS FOR FUTURE WORK ..................................................... 69 REFERENCES ....................................................................................................................... 85 APPENDIX A: SUBSTATION DESIGN FLOW CHART ................................................... 70 APPENDIX B: OVERHEAD VERSUS UNDERGROUND SYSTEM ................................ 71 APPENDIX C: VOLTAGE SELECTION ............................................................................ 72 APPENDIX D: INDOOR VERSUS OUTDOOR SWITCHGEAR ...................................... 73 APPENDIX E: POWER TRANSFORMER RATINGS ....................................................... 73 APPENDIX F: POWER CABLES ........................................................................................ 77 APPENDIX G: LIGHTNING STROKE PROTECTION .................................................... 83

vii

LIST OF FIGURES

FIGURE 3.1: FAHARI MAIN SUBSTATION GENERAL LAYOUT .............................................. 11 FIGURE 3.2: FAHARI SUBSTATION SITE LOCATION ............................................................ 12 FIGURE 4.1: GENERAL PLAN OF THE NETWORK ................................................................ 13 FIGURE 4.2: RING MAIN UNIT ONE LINE DIAGRAM ............................................................ 14 FIGURE 4.3: GENERAL FAHARI CITY POWER SYSTEM LAYOUT .......................................... 15 FIGURE 4.4: PLOT OF COST PER KVA OF LOAD SUPPLIED [15] .......................................... 17 FIGURE 4.5: DISTRIBUTION TRANSFORMER LOCATIONS .................................................... 18 FIGURE 5.1: ROTATING CENTRE POST DISCONNECTOR WITH GROUNDING SWITCH ............. 20 FIGURE 5.2: OUTDOOR AND INDOOR SWITCHGEAR INSTALLATION .................................... 22 FIGURE 5.3: SIEMENS 8DH10 MV METAL-CLAD SWITCHGEAR [4].................................... 27 FIGURE 5.4: TYPICAL MV SWITCHGEAR INSTALLATION ................................................... 27 FIGURE 5.5: SIEMENS 8DJ20 RING MAIN UNIT ................................................................. 28 FIGURE 5.6: A POWER TRANSFORMER ............................................................................. 30 FIGURE 5.7: 5MVA TRANSFORMER GROUNDING ............................................................. 31 FIGURE 5.8 RING SYSTEM IMPLEMENTATION ................................................................... 34 FIGURE 5.9: RADIAL-TYPE FEEDER DEVELOPMENT .......................................................... 36 FIGURE 5.10: RECTANGULAR-TYPE FEEDER DEVELOPMENT ............................................. 36 FIGURE 5.11: FAHARI SUBSTATION FEEDER LAYOUT ........................................................ 37 FIGURE 5.12: PRIMARY FEEDER SERVICE AREA DESIGNATION .......................................... 37 FIGURE 5.13: SUBSTATION SPECIFIC DESIGN PLAN. .......................................................... 38 FIGURE 7.1: TYPES OF FAULTS ........................................................................................ 43 FIGURE 7.2: FAHARI POWER SYSTEM ONELINE DIAGRAM. ................................................. 45 FIGURE 8.1: OVERCURRENT CURRENT TRANSFORMER CONNECTIONS ............................... 50 FIGURE 8.2: EARTH FAULT CURRENT TRANSFORMER CONNECTIONS. ................................ 51 FIGURE 8.3: SERVICE MAIN CONNECTIONS. ...................................................................... 52 FIGURE 8.4: RING MAIN CIRCUIT 1 WITH ASSOCIATED OVERCURRENT PROTECTION ........... 56 FIGURE 8.5 ANTICLOCKWISE FEEDING OF RING MAIN 1 VIA BUS-SECTION ONE ................... 57 FIGURE 8.6: RING 1 OVERCURRENT RELAYS CHARACTERISTICS, ETAP PROGRAM REPORT .. 58 FIGURE 8.7: CLOCKWISE GRADING .................................................................................. 59 FIGURE 8.8: CLOCKWISE OVERCURRENT RELAYS ETAP SIMULATION REPORT .................... 60 FIGURE 8.9: ZONED BUSBAR (SWITCHGEAR) PROTECTION ................................................ 63 FIGURE 8.10: IMPLEMENTATION OF THE BUS DIFFERENTIAL PROTECTION SCHEME. ........... 63 FIGURE 8.11: SUBSTATION SWITCHYARD PROTECTION LAYOUT........................................ 64 FIGURE 8.12: PRINCIPLE OF THE ROLLING SPHERE (IEEE STD. 998-1996) ....................... 66 FIGURE 8.13: SUBSTATION LIGHTNING MASTS GENERAL LAYOUT ..................................... 67 FIGURE E.1: SOLID GROUNDED POWER TRANSFORMER .................................................... 74 FIGURE E.2: RESISTANCE GROUNDING ............................................................................ 75 FIGURE E.3: PETERSON COIL ........................................................................................... 75 FIGURE F. 1: OLEX CATALOGUE SINGLE CORE ALUMINIUM 11KV CABLES ........................ 79

viii

LIST OF TABLES

TABLE 3.1: LOADS CLASSIFICATIONS ................................................................................ 9 TABLE 3.2: TYPICAL DIVERSITY FACTORS ......................................................................... 9 TABLE 4.1: TYPICAL POWER SUPPLIED BY EACH DISTRIBUTION VOLTAGE [2] .................... 16 TABLE 4.2: DISTRIBUTION TRANSFORMER SIZES .............................................................. 18 TABLE 4.3: DEMAND ON INDIVIDUAL RING CIRCUITS ....................................................... 19 TABLE 5.1: POWER FREQUENCY WITHSTAND VOLTAGE AS SET BY IEC STD 60694 ............ 23 TABLE 5.2: STANDARD RATINGS OF LIGHTNING IMPULSE WITHSTAND VOLTAGE ............... 24 TABLE 5.3: 11KV INDOOR SWITCHGEAR RATINGS ............................................................ 26 TABLE 5.4: 33KV OUTDOOR SWITCHGEAR AND CONTROLGEAR SPECIFICATIONS............... 28 TABLE 5.5: MINIMUM CHARACTERISTICS FOR 33KV AND 11KV SURGE ARRESTORS .......... 29 TABLE 5.6: FAHARI SUBSTATION TRANSFORMER SPECIFICATIONS .................................... 33 TABLE 6.1: 33KV AND 11KV CONDUCTOR SIZING ............................................................ 40 TABLE 6.2: LOW VOLTAGE CONDUCTOR SIZING .............................................................. 41 TABLE 6.3: FAHARI SYSTEM POWER FACTOR ANALYSIS ................................................... 42 TABLE 7.1: BASE VALUES .............................................................................................. 46 TABLE 7.2: TRANSFORMER IMPEDANCES ......................................................................... 46 TABLE 7.3: RING SECTIONS IMPEDANCES ........................................................................ 46 TABLE 7.4: IMPEDANCES TO THE VARIOUS BUSES ............................................................ 47 TABLE 7.5: FAULTS ON VARIOUS BUSES. ......................................................................... 48 TABLE 7.6: CIRCUIT BREAKER RATINGS .......................................................................... 49 TABLE 8.1: TYPICAL RELAY TIMING ERRORS FOR STANDARD IDMT ................................. 51 TABLE 8.2: SECONDARY LINES FUSE RATINGS ................................................................. 53 TABLE 8.3: SERVICE MAINS LINES FUSE RATINGS ............................................................. 53 TABLE 8.4: OVERCURRENT RELAY SETTINGS ................................................................... 55 TABLE 8.5: EARTH FAULT RELAY SETTINGS ..................................................................... 55 TABLE 8.6: RING 1 ANTICLOCKWISE OVERCURRENT RELAY SETTINGS ............................. 57 TABLE 8.7: RING 1 ANTI CLOCKWISE EARTH FAULT RELAY SETTINGS ............................... 59 TABLE 8.8: RING 1 CLOCKWISE OVERCURRENT RELAY SETTINGS...................................... 59 TABLE 8.9: RING 1 CLOCKWISE EARTH FAULT RELAY SETTINGS ....................................... 61 TABLE 8.10: ANTI-CLOCKWISE OVERCURRENT RELAYS SETTINGS .................................... 61 TABLE 8.11: ANTI-CLOCKWISE EARTH FAULT RELAYS SETTINGS ...................................... 61 TABLE 8.12: RING 2 CLOCKWISE OVERCURRENT RELAY SETTINGS .................................... 62 TABLE 8.13: RING 2 CLOCKWISE EARTH FAULT RELAY SETTINGS ..................................... 62

ix

LIST OF ACRONYMS AND ABBREVIATIONS

AC Alternating Current

DC Direct Current

IEC The International Electrotechnical Commission

IEEE Institute of Electrical & Electronics Engineers

ANSI American National Standards Institute

RMU Ring Main Unit

SF6 Sulphur-Hexa-Flouride

CB Circuit Breaker

ACSR Aluminium Coated Steel Reinforced

CT Current Transformer

VT Voltage Transformer

SA Surge Arrestor

LV Low Voltage

MV Medium Voltage

HV High Voltage

FDR Feeder

SWGR Switchgear

XLPE Cross-Linked-Polyethylene

TX Transformer

IDMT Inverse Definite Minimum Time

HRC High Rupturing Fuses

TMS Time Multiplier Setting

LM Lightning Mast

ONAN Oil Natural Air Natural

ONAF Oil Natural Air Forced

x

ABSTRACT

The distribution system of a power supply system is the closest one to the customer.

Therefore, its failures affect customer service more directly than, for example, failures on

the transmission and generating systems, which usually do not cause customer service

interruptions.

As a result, Fahari distribution system planning started at the customer level. The

demand, type, location and other customer load characteristics were assessed so as to

ascertain the most feasible type of distribution system. The total load modified by a

suitable diversity factor was used to determine the substation capacity. In addition to the

connected loads a long-range time scale with a horizon of 25years was incorporated into

the plan.

The customer loads were then grouped for service from 415V secondary lines connected

to distribution transformers that step down from 11kV primary voltage. The distribution

system loads were then assigned to one main substation that would step down from 33kV

sub-transmission voltage. Specifications and ratings of the controlgear, switchgear and

other equipment were determined according to IEC, IEEE and KPLC standards and

several models that met the specifications proposed.

Conductor types and sizes were then determined with the load current and fault level

being the main considerations.

A one line diagram was prepared and fault calculation done as a preliminary requirement

for protection system design, which was done and simulated with ETAP power system

simulation software to test the design soundness.

1

CHAPTER 1 1.1 INTRODUCTION

1.2 STATEMENT OF THE PROBLEM

Fahari is a new city located in Nyanza. Figure 1.1 shows the geographical locations of

the major power consumers.

Figure 1.1: Fahari city map

It has several modern commercial, residential and public buildings and amenities

which require reliable electric power connections. Table 1.1 shows the estimated peak

load demands for each of these establishments.

2

Table 1.1: Peak loads for the various consumers

CUSTOMER PEAK LOAD(KVA)1 ESTATE 6002 HOSPITAL 5003 HOTEL(BIG) 4004 SECONDARY SCHOOL 3005 SHOPPING MALL 3006 BANK 3007 HOTEL(SMALL) 3008 OFFICE BLOCK ONE 3509 OFFICE BLOCK TWO 300

10 LIBRARY 20011 MONASTERY 15012 PETROL STATION 20013 MARKET 100

TOTAL 4000 This project endeavors to design a reliable and flexible electric power distribution system

for Fahari city, power being drawn from a 33kV sub-transmission line with the following

being put into consideration:

a) Adequacy: To provide service connections to the various consumers in the area.

b) Reliability: This being an urban area, residential and commercial consumers will

suffer great inconvenience through only a relatively short loss in supply of only a

few hours, with business likely to suffer considerable financial loss.

c) Safety: Protection of consumers and utility personnel.

d) Quality: The electricity should be of accepted quality and standard in terms of:

• Standard voltage levels.

• Balanced three phase supply.

• Good power factor.

• Less voltage dips.

• Minimum interruption in power supply.

• The voltage drop at any consumer terminal should remain within ± 5% of

the declared voltage.

e) Efficiency: The efficiency of the system should not be less than 90%.

f) Economy: The system should be cost effective.

3

1.3 OBJECTIVES

To accomplish the above requirements the following objectives were to be met:

A. A power substation was to be designed, placed and sized in such a way as to serve

the load reliably and efficiently with a good voltage regulation.

B. Primary and secondary distribution lines were to be designed to deliver power to

consumers from the substations while at the same time minimizing conductor

losses. The distribution system was to be designed to give the maximum possible

flexibility and reliability of supply to consumers.

C. An adequate Protection System was to be designed to detect and disconnect

elements of the power system in event of a fault to minimize the number of

consumers affected by a fault and protect equipment and utility personnel.

1.4 ORGANISATION OF THE REPORT

This report has been organized into nine chapters defining the process followed to meet

the objectives specified in the previous section.

Chapter two gives a brief general review of literature on electric power system design.

Since load assessment is a preliminary to any power system design, chapter three

attempts to capture the power requirements of Fahari city and seeks to ascertain the most

feasible size, layout and location of the main Substation.

Chapter four covers the general distribution network plan that would serve Fahari city

with the best reliability and efficiency as per the requirements.

Chapter five tackles the specific substation design that would support the general

network plan defined in chapter four. It vividly captures the type, ratings and nature of

the installations and equipment necessary for its construction as per the industry

standards.

Chapter six concentrates on determining sizes and type of various conductors used in the

various sections.

Chapter seven focuses on fault analysis a preliminary to protection system design

covered in chapter eight. With the objectives met chapter nine gives a brief conclusion.

4

CHAPTER 2 2 LITERATURE REVIEW

2.1.1 ELECTRIC POWER SYSTEM

Electrical energy is produced through an energy conversion process. The electric power

system is a network of interconnected components which generate electricity by

converting different forms of energy to electrical energy and conveying it to places where

it can be utilized. The electric power system consists of three main subsystems:

• generation subsystem

• transmission subsystem

• distribution subsystem

Electricity is generated at the generating station by converting a primary source of energy

to electrical energy (potential energy, kinetic energy, or chemical energy are the most

common forms of energy converted). The voltage output of the generators is then

stepped-up to appropriate transmission levels using a step-up transformer (say 220kV or

400kV).

Electrical power is transmitted by high voltage transmission lines from sending end or

primary transmission substation to receiving end or secondary transmission substation. At

the receiving end substation, the voltage is stepped down to a lower value (say 66kV or

33kV or 11kV). The secondary transmission system transfers power from this receiving

end substation to secondary substation.

At the secondary substation voltage is stepped down to 11kV. The final consumer then

receives power from the distribution system.

2.1.2 POWER DISTRIBUTION SYSTEM

Distribution system is the final stage in the delivery of electricity to end users. Typically,

the network would include medium-voltage (less than 50 kV) power lines, electrical

substations and pole- mounted or pad-mounted transformers, low-voltage (less than 1000

V) distribution wiring.

The main part of distribution system includes:

a) Receiving substation

5

b) Sub-transmission lines

c) Distribution substation located nearer the load centre

d) Secondary circuits on the LV side of the distribution transformer

e) Service mains

2.1.2.1 MAIN COMPONENTS OF A DISTRIBUTION SYSTEM

A distribution system consists of all the facilities and equipment connecting a

transmission system to the customer’s equipment. A typical distribution system can

consist of:

a. Substation: A substation is a high-voltage electric system facility. It is used to

switch generators, equipment, and circuits or lines in and out of a system. It also

is used to change AC voltages from one level to another, and/or change

alternating current to direct current or direct current to alternating current

b. Distribution feeder circuit: Distribution feeder circuits are the connections

between the output terminals of a distribution substation and the input terminals

of primary circuits.

c. Switches: Distribution systems have switches installed at strategic locations to

redirect or cut-off power flows for load balancing or sectionalizing. Also, this

permits repairing of damaged lines or equipment or upgrading work on the

system. The main types of switches include:

• Circuit breaker switches.

• Single-pole disconnect switches (isolators).

• Three pole ground operated switches.

d. Protective Equipment: Protective equipment in a distribution system consists of

protective relays, cut out switches; disconnect switches, lightning arresters, and

fuses. These work individually or may work together to open circuits whenever a

short circuit, lightning strikes or any other disruptive event occurs. The

distribution system is often designed with many layers of redundancy. The

redundancy consists of the many fuses and circuit breakers throughout the system

that can disable parts of the system but not the entire system. Lightning arresters

6

and surge arrestors also act locally to drain off electrical energy from a lightning

strike so that the larger circuit breakers are not actuated.

e. Primary Distribution Circuits: Primary circuits are the distribution circuits that

carry power from substations to local load areas. They are also called express

feeders or distribution main feeders. The distribution feeder bay routes power

from substation to the primary distribution feeder circuit.

f. Distribution Transformers: Distribution transformers reduce the voltage of the

primary circuit to the voltage required by customers. This voltage varies and is

usually:

• 240 volts single phase for residential customers,

• 415 volts for commercial or light industry customers.

Three phase pad mounted transformer are used with an underground primary

circuit and three single-phase pole type transformers for overhead services.

g. Secondaries: Secondaries are the conductors originating at the low voltage

secondary winding of a distribution transformer.

h. Services: The wires extending from the secondaries or distribution transformer to

a customer's location are called service. A service can be above or below ground.

Underground services have a riser connection at the distribution pole.

Commercial and residential services are much the same and can be either 240 or

415 or both.

2.1.2.2 CLASSIFICATION OF DISTRIBUTION SYSTEMS

Distribution systems can be classified according to:

a) The type of construction: the distribution systems may be classified as:

• Overhead distribution systems.

• Underground distribution system.

b) The type of current: the distribution systems may be classified as:

• AC distribution

• DC distribution

AC distribution system may be further sub-divided into two systems known as:

• High voltage or primary distribution systems.

7

• Low voltage or secondary distribution systems.

2.2 DISTRIBUTION SYSTEM PLANNING

System planning is essential to assure that the growing demand for electricity can be

satisfied by distribution system additions which are both technically adequate and

reasonably economical.

The distribution system is particularly important to an electrical utility for two reasons:

a) Its close proximity to the ultimate customer

b) Its high investment cost.

Since the distribution system of a power supply system is the closest one to the customer,

its failures affect customer service more directly than, for example, failures on the

transmission and generating systems, which usually do not cause customer service

interruptions.

Therefore, distribution system planning starts at customer level. The demand, type, load

factor, and other customer load characteristics dictate the type of distribution system

required. Once the customer loads are determined, they are grouped for service from

secondary lines connected to distribution transformers that step down from primary

voltage. The distribution transformers are combined to determine the demands on the

primary distribution system. The primary distribution system loads are then assigned to

substations that step down from transmission voltage. The distribution system loads, in

turn, determine the size and location of the substation as well as the routing and capacity

of the associated transmission lines.

2.2.1 FACTORS AFFECTING SYSTEM PLANNING

Some of the major factors affecting system planning include:

a) Load Forecasting.

b) Substation Expansion.

c) Substation Site Selection.

8

CHAPTER 3 3 FAHARI CITY POWER SYSTEM DESIGN

3.1.1 GENERAL

Fahari city power system was to be composed of:

• One secondary substation being served by two existing 33kV lines.

• Primary distribution lines.

• Distribution transformers.

• The necessary protection.

The most feasible method of supplying and distributing electrical power was determined

by first quantifying the electrical power requirements (or maximum demand) for the

installation.

In the early design stages (system sizing), the power demand was based on the

summation of all the loads which were to be served modified by suitable diversity

factors.

3.1.2 STANDARDS

The power utility industry is strictly governed by international laid down codes and

standards. Kenya and many other 50 Hz countries are governed by the IEC and the IEEE,

therefore all applicable national and local laws, codes, and standards were adhered to.

3.2 LOAD ASSESSMENT.

Load estimation required analysis of load characteristics and took into account the

diversity factor relationship between connected loads and the actual demand imposed on

the system.

Preliminary loads

The load data given in table 3.1 was used to compute preliminary estimates of the

expected maximum demands and electrical energy usage. The various loads were

classified as:

• Commercial

• Residential

• General power

9

Table 3.1: Loads classifications

CUSTOMER PEAK LOAD(KVA) COMMERCIAL RESIDENTIAL GENERAL POWER1 HOTEL (BIG) 400 4002 HOTEL (SMALL) 300 3003 OFFICE BLOCK ONE 350 3504 OFFICE BLOCK TWO 300 3005 SHOPPING MALL 300 3006 BANK 300 3007 LIBRARY 200 2008 PETROL STATION 200 2009 MARKET 100 100

10 ESTATE 600 60011 MONASTERY 150 15012 HOSPITAL 500 50013 SCHOOL 300 300

TOTAL 4000 2450 750 800

Diversity factor

This is ratio of the sum of the individual peak demands in a system to the maximum

demand on power system, since all the power consumers cannot be at their peak at the

same time.

The diversity factors used are given in table 3.2 [1].

Table 3.2: Typical diversity factors

Therefore Fahari substation demand:

(3.1)

10

= .

(3.2)

= 1785

3.3 SECONDARY SUBSTATION SIZING

The load growth of the geographical area served by a utility company is the most

important factor influencing the installation or expansion of a distribution system.

Therefore, forecasting of load growths and system reaction to these growths was found to

be essential in the planning process. There are two time scales of importance to load

forecasting:

• Long-range, with time horizons on the order of 15 or 20 years away.

• Short-range, with time horizons on the order of 5 years distant [1].

Defining the growth equation as:

= (1 + ) (3.3)

Where

= load at the end of nth year

= initial load

= annual growth rate

n = number of years

Fahari substation design was on a long range time scale and expected to continuously

meet the growing demand for a period of 25 years with an assumed annual growth rate of

9% for the first 10 years and a rate of 6% thereafter.

The first 10 years we get:

= 1785(1 + 0.09) (3.4)

= 4225.7 KVA

The last 10 years:

= 4225(1 + 0.06) (3.5)

= 10, 125 KVA

From the above analysis substation capacity was chosen to be 10 MVA, achieved by

having two 5MVA transformers in parallel for improved reliability.

Justification:

11

1. Paralleling the two transformers will cater for the additional demand in future in

case of increase in capacity.

2. It will save on down time during changeover in case one transformer becomes

faulty.

3. It will allow for remote selection of one transformer in case there is no need of

loading both transformers at the same time.

3.4 GENERAL SUBSTATION LAYOUT

To tap the full benefits of this transformer arrangement and also increase reliability a

sectionalized 11kV bus was proposed with a bus tie connecting the two as shown in

figure 3.1.

Figure 3.1: Fahari main substation general layout

3.5 SUBSTATION SITE LOCATION

The following factors were considered in the selection of an appropriate location for the

main power substation in Fahari city.

1. Existing sub-transmission lines location; there were two lines, one to the north

and the other on north eastern side.

2. Load densities; the area with the highest load density was ascertained by using the

quarter area circle method as shown in figure 3.2.

3. Closeness to load centers.

12

4. Feeder limitations; distance to the furthest load center was limited to 3km so as to

ensure there was good voltage regulation, reduced line losses and feeder costs.

5. Load forecasts; there was a higher probability of future loads being located along

the Jomo Kenyatta Highway.

The chosen site location is as shown in figure 3.2.

Figure 3.2: Fahari substation site location

13

CHAPTER 4 4 GENERAL NETWORK PLAN

The radial feeder system is the simplest and lowest in first cost but has poorest service

reliability. The parallel system provides improved reliability of supply, particularly if the

circuits follow different routes. The ring system provides alternative supplies to a number

of scattered sub stations and has been proven to offer a very high degree of reliability

[13]. However voltages drop, sizing, and protection engineering are more complicated

than for radial systems. The interconnected networks are a common development of the

simple ring system.

Figure 4.1: General plan of the network

4.1 LOOP FEEDER SYSTEM

In a loop feeder system, two or more radial feeders originating from the same or different

secondary substations are laid on different routes of load areas. The ends of the feeders

are then tied together through normally open switching devices or normally closed

switching devices. This combination is usually referred to as the ring main or the ring

loop.

This system is by far the most reliable for continuity of supply and gives better voltage

regulation and less power losses.

14

It was adopted because continuity of supply was a priority factor and to ensure a high

degree of availability of supply to the consumers.

4.1.1 RING MAIN UNIT

Low voltage distribution substations took the form of feeders from Ring Main Units

(RMUs). These units would house the protective equipment and switchgear example the

relays and the circuit breakers they control. Several RMUs were connected in a loop fed

from the main substations but from different transformers.

The cables forming the ring and all associated switchgear were sized for single-end

feeding of the whole ring [6], to allow for an outage affecting the ring between a

substation and the first RMU, or at the substation itself.

The arrangement of an individual RMU is shown in Figure 4.2.

Figure 4.2: Ring main unit one line diagram

Thus with the feeder system included the overall system layout is as shown in figure 4.3.

Spur feeding a distribution transformer.

15

Figure 4.3: General Fahari city power system layout

From figure 4.3, the feeders serving a particular ring main emanate from different bus

sections which are in turn fed by different power transformers.

4.2 PRIMARY AND SECONDARY VOLTAGE LEVELS

The standard utility service voltage in Kenya is 415/240 V. Primary distribution voltage

levels are usually 33kV or 11kV.

Fahari city area was about 12sq.km with a total connected load of 4MVA.The

advantages of a higher voltage system were apparent in that it would carry more power

for a given current.

16

Less current means lower voltage drop, smaller conductors, fewer losses, more power-

carrying capability and much longer distribution circuits. Higher voltage systems will

also need fewer voltage regulators and capacitors for voltage support.

Table 4.1 shows maximum power levels typically supplied by various distribution

voltages.

Table 4.1: Typical power supplied by each distribution voltage [2]

System voltage (kV) Total power (MVA)

0.415 0.288

11 7.6

33 22.8

11kV distribution voltage was found to provide a good balance between cost, reliability

and safety for primary distribution.

This voltage was then stepped down to utility service voltage of 415V by the secondary

distribution transformers.

4.3 SECONDARY DISTRIBUTION SUBSTATIONS SIZING

Secondary distribution is that part of ac distribution system that includes the range of

voltages at which the ultimate consumer utilizes the electrical energy delivered. The

secondary distribution normally employs 415/240, 3-phase 4-wire system. The primary

distribution circuit delivers power to various sub-stations, called distribution sub-stations.

The sub-stations were situated near the consumer’s localities and equipped with step-

down transformers. The voltage was stepped down to 415 V and power delivered by 3-

phase, 4-wire A.C system.

Criteria used for the secondary distribution substations sizing and locations:

• Loads located next to each other were lumped together so that they shared one

transformer, therefore minimizing costs.

• Load categories (commercial, residential or general power); where possible loads

in different categories were grouped together so as to have as much load diversity

as possible. This would reduce the probability of all loads connected to a

particular transformer peaking at the same time.

17

• They were located as close as possible to the consumers to minimize losses due to

the high currents resulting from the stepped down voltage.

• Each transformer had to be able to serve the connected consumers at their peak

loads.

• A 20% load growth was allowed and the next higher rating selected from the

standard sizes available.

• The transformers sizes were harmonized to a few standard sizes (630 kVA, 800

kVA). This would reduce the number of transformers needed as spares. In this

case only two were required rather than seven, hence improving reliability and

reducing system downtime incase a transformer was lost.

It is also important to note that for underground systems, as the transformer size

increases, the cost per kVA load decreases to an optimum point at about the 500-700

kVA transformer rating [15].

Figure 4.4: Plot of cost per KVA of load supplied [15]

Considering the above the distribution transformers were placed as illustrated in the

figure 4.5.

Optimum

18

Figure 4.5: Distribution transformer locations

They were also sized as illustrated in table 4.2 for the respective ring mains.

Table 4.2: Distribution transformer sizes RING MAIN 1

RMU TRANSFORMER RATING (KVA) CONNECTED LOAD (KVA)

1 TX 1 630 HOSPITAL 500

500

2 TX 2 630 SCHOOL 300

LIBRARY 200

500

3 TX 3 630 BIG HOTEL 400

MONASTERY 150

550

4 TX 4 630 PETROL STN 200

BANK 300

500

19

RING MAIN 2

RMU TRANSFORMER RATING (KVA) CONNECTED LOAD (KVA)

5 TX 5 800 SMALL HOTEL 300

SHOPPING MALL 300

600

6 TX 6 150 MARKET 100

ESTATE TX 600

700

7 TX 7 800 OFFICE ONE 300

OFFICE TWO 350

650

Loads were balanced between the two ring circuits as shown in the table 4.3.

Table 4.3: Demand on individual ring circuits

RING CIRCUIT MAXIMUM DEMAND

(KVA)

DIVERSITY FACTOR

(user to feeder)

MAXIMUM DEMAND

ON FEEDER

1 2050 1.95 1051

2 1950 1.95 1000

TOTAL 4000 2051

From table 4.3 diversity factor between feeders is 1.15, therefore maximum demand on substation is:

= .

= 1784 KVA (4.1) This confirms the previous calculation.

20

CHAPTER 5 5 SUBSTATION SPECIFIC DESIGN

The substation would be a combination of switching, controlling, and voltage step-down

equipment arranged to reduce sub-transmission voltage to primary distribution voltage

for residential, commercial, and industrial loads.

It consists of:

a. Switchgear- isolators, circuit breakers, earthing switches etc

b. Controlgear- current transformers, voltage transformers, contactors etc

c. Protection equipment- relays, fuses, surge arrestors etc.

d. Power Transformers.

5.1 SUBSTATION EQUIPMENT

The main equipments in fahari substation consist of:

a. Transformers: To step down the 33kV primary voltage to 11kV suitable for

distribution purpose.

NB: One 33kV/0.415 auxiliary transformer was also needed to supply the

substation with reliable ac power.

b. Circuit breakers: Circuit breakers were needed so as to disconnect and isolate

the faulted section. Sulphur-hexa-fluoride (SF6) circuit breakers were chosen.

c. Isolating switches (isolators): It is a requirement that whenever maintenance or

repair work is to be carried out on equipment in a substation or feeders, it be

disconnected from the supply by an isolator, normally operated on no load.

Isolators are normally interlocked with circuit breakers and earthing switches.

Figure 5.1: Rotating centre post disconnector with grounding switch

21

d. Current and potential transformers: Current and voltage transformers were

needed so as to step down the line current for the purpose of metering and

relaying.

e. Bus bars: The incoming and outgoing circuits were connected to bus bars.

Flexible ACSR stranded conductor bus bars supported from two ends by strain

insulators was chosen for the 33kV bus bar.

f. Protective relays: Whenever a fault occurs the protective relay would operate

and send a trip signal to circuit breakers. The relays were housed in panels in the

control room and Ring Main Units.

g. Surge arrestors (lightning arrestors): Surge arrestors would protect the

substation equipment from lightning and switching surges.

h. Earthing switch: The earthing switch is usually connected between the line

conductor and earth and is mounted on the frame of isolator. Normally it is in

open position. When the line is disconnected the earthing switch is closed to

discharge the trapped charges to earth.

i. Station earthing system: The function of station earthing system is to provide a

low resistance path for flow of earth fault currents (for proper operation of

protection devices) and safety of equipment and personnel.

j. Station battery and charging equipment: A substation needs dc supply for

protection and control purposes. This supply is obtained from batteries. 110V dc

supply is used for medium size substations while 240V supply is used for large

substations.

The batteries were to be equipped with charging equipment fed by the auxiliary

transformer.

NB: 110V dc supply was chosen for Fahari substation.

22

5.2 SWITCHGEAR AND CONTROLGEAR

This refers to switching devices and their combination with associated control,

measuring, protective, regulating equipment accessories, enclosures and supporting

structures.

They can either be outdoor or indoor with the voltage level being the main determining

factor.

From the comparison of the above (in appendix D) the 33kV switchgear was selected to

be of outdoor open air type and the 11kV chosen to be of indoor type as shown in figure

5.2.

Figure 5.2: Outdoor and indoor switchgear installation

Indoor switchgear and controlgear are usually metal enclosed and are subdivided into

three main types as in IEC 60298;

a. Metal-clad switchgear: in which components are arranged in separate

compartments with earthed metal partitions, with each of the compartments

having at least for the following components;

• Each main switching device, for example circuit breaker.

• Components connected to one side of a main switching device, for

example feeder circuit.

• Components connected to the other side switching of main switching

device, for example busbars.

b. Compartmented switchgear: have non metallic partitions.

c. Cubicle switchgear: Have no partitions.

23

The common ratings of switchgear and controlgear, including their operating devices and

auxiliary equipment, are selected from the following according to IEC 60694.

• Rated voltage ().

• Rated insulation level.

• Rated normal current ().

• Rated short-time withstand current ().

• Rated peak withstand current ().

• Rated supply voltage of closing and opening devices and of auxiliary circuits ().

5.2.1 RATINGS

The 33KV and 11kV medium-voltage switchgear and controlgear equipment were rated

according to the following main specifications:

A. Nominal voltage

This is the designed average voltage of a system, e.g. 11 kV. The actual voltage

will typically fluctuate between 10.5 and 11.5 kV (95–105%).

B. Rated voltage

The normal practice is to rate switchgear panels 10% higher than the required nominal

voltage, therefore for Fahari substation switchgear the rated voltage for 11kV panels will

be 12kV and 36kV for 33kV switchgear IEC 60038.

C. Voltage class

A voltage class is a term applied to a set of distribution voltages and the equipment

common to them; it is not the actual system voltage.

Fahari power system equipment voltage classes were therefore selected to be:

• 35kV for the 33kV primary side of substation transformer.

• 15kV for the equipment on the 11kV secondary side of the substation transformer.

D. Power frequency withstand voltage ()

This is the 50Hz voltage that the switchgear insulation can withstand for 1 min.

Table 5.1: Power frequency withstand voltage as set by IEC Std 60694 12kV equipment 36kv equipment

Power frequency withstand voltage. 28kVrms 70kVrms

24

Commissioning engineers also use this test to prove the integrity of the equipment

insulation before switching on the power. This test is also known as a pressure test.

E. Impulse voltage

This is the highest peak voltage the equipment will be able to withstand for a very short

period of time, as in the case of a voltage peak associated with lightning impulse voltage

(), switching impulse () or other transients. The rated insulation level is specified by

the rated lightning impulse withstand voltage phase to earth.

BIL standards are also set by IEC 60694.

Table 5.2: Standard ratings of lightning impulse withstand voltage 12kV equipment 36kV equipment

Rated lightning impulse withstand

voltage. 75kVpk 170kVpk

F. Rated frequency ()

The standard values of the rated frequency are 16HZ, 25 Hz, 50 Hz and 60 Hz.

50Hz is the standard in Kenya.

G. Rated normal current ()

The rated normal current of switchgear and controlgear is the rms value of the current

which it can be able to carry continuously under specified conditions of use.

The values of rated normal currents are selected from the R 10 series, specified in IEC

60059.

NOTE; the R10 series comprises the numbers 1 - 1.25 - 1.6 - 2- 2.5 - 3.15 - 4.5 - 6.3 – 8

and their products by10.

For the 11kV switchgear this was calculated to be equal to the full load capacity of the

substation. This was;

= ÷ √3 × 11000 (5.1)

= 12,500,000 ÷ √3 × 11000 (5.2)

= 656.08 Amps

Choosing from the R10 series a normal current of 1000 amps was found to be sufficient.

25

H. Rated short-time withstand current ()

This is the rms value of the current which the switchgear and control gear can carry in the

closed position during a specified short time under prescribed conditions of use.

The rated short-time withstand current is selected from the R10 series as specified in IEC

60059 and is chosen to be equal to the short-circuit rating assigned to switchgear and

control gear.

Therefore, since two transformers are feeding the 11kV bus in parallel, the total fault

current is: = 6.634 kA A short time withstand current rating of 10 kA would be sufficient.

The fault current rating is usually specified as a current and a time rating.ie. 10kA for 3

seconds. This means that the panel will be able to withstand a three-phase through fault

current of 10 kA for a continuous period of 3 s.

The amount of electrical energy the panel can absorb, according to the formula,

= (5.3)

Exceeding this energy limit will cause thermal damage to the panel. Therefore to get the

1sec withstand current rating:

=

(5.4)

10 × 3 = × 1 (5.5)

Therefore

= 17.32 (5.6)

A standard rating of 20 kA for 1 second was chosen.

I. Rated peak withstand current ()

This is the peak current associated with the first major loop of the rated short-time

withstand current which switchgear and controlgear can carry in closed position under

prescribed conditions of use.

The rated peak withstand current corresponds to the rated frequency. For a rated

frequency of 50Hz and below it is equal to 2.5 times the rated short-time withstand

current. IEC Std 60694-4.7.

26

Hence the rated peak withstand current for the 11kV switchgear:

= 2.5 × 20 (5.7)

= 50

From the standard R10 series ratings a value of 63 kA was chosen.

J. Rated duration of short circuit ()

This is the interval of time for which switchgear and controlgear can carry, in closed

position, a current equal to its rated short-time withstand current.

The standard values of rated duration of short circuit are 1s, 2s and 3s.

K. Full load current

This is the maximum load current that may pass continuously through the switchgear

panel.

Due to economy of scale, MV circuit-breakers/disconnectors are manufactured in a few

standard sizes, for example 630 A, 1250 A, 1600 A, 2000 A and 2500 A according to IEC

60059 standard.

5.3 11KV INDOOR SWITCHGEAR AND EQUIPMENT

All 11 kV primary equipment and accessories were to be installed indoors.

Because of its many advantages (appendix E), the metal-clad type of switch gear was

chosen. Its specifications are summarized in table 5.3.

Table 5.3: 11kV indoor switchgear ratings 11kV INDOOR SWITCHGEAR

Item Particulars Unit

1 Cubicles

Metal Clad type

- Rated Voltage 11 kV

- Maximum service voltage 12 kV

- Rated frequency 50 Hz

- Rated continuous busbar current 1250 A

One minute power frequency withstand voltage

- to earth 28 kV rms

- Impulse withstand voltage 1.2/50 ms

- to earth 75 kV peak

27

- Permissible 1 second short-time current 20 kA rms

- Permissible 3 second short-time current 10 kA rms

- peak withstand current 63 kA peak

A suitable selection from Siemens switchgear catalogue was made with the ratings shown

in figure 5.3.

Figure 5.3: Siemens 8DH10 MV metal-clad switchgear [4]

Figure 5.4: Typical MV switchgear installation

28

5.4 RING MAIN SWITCHGEAR (RMUS) RATINGS

The Ring Main Units being at the same voltage with the 11KV indoor switchgear had

similar ratings and a suitable Siemens model was chosen with the ratings as shown in

figure 5.5.

Figure 5.5: Siemens 8DJ20 ring main unit

5.5 33KV OUTDOOR SWITCHGEAR AND EQUIPMENT RATINGS

Table 5.4 shows the 33kV outdoor switchgear specifications.

Table 5.4: 33KV outdoor switchgear and controlgear specifications 33kV OUTDOOR SWITCHGEAR

Item Particulars Unit

- Rated Voltage 33 kV

- Maximum service voltage 36 kV

- Rated frequency 50 Hz

- Rated continuous busbar current >250 Amps

One minute power frequency withstand voltage

- to earth 70 kV rms

- Impulse withstand voltage 1.2/50 ms

- to earth 170 kV peak

- Permissible 1 second short-time current 31.5 kA rms

- Permissible 3 second short-time current 20 kA rms

- peak withstand current 100 kA peak

29

5.6 SURGE ARRESTORS

Surge arrestors are installed at the transition point between e.g. an overhead line and a

transformer, and as close to the transformer terminals as possible.

Surge arrestors are also installed on the ends of overhead lines. They are usually

connected between phases and earth.

Three types of surge arrestors normally used are:

1. Rod spark gapped

2. Multiple gapped arrestors

3. Zinc (metal) oxide surge arrestors (modern).

In applying surge arrestors the voltage rating, lighting density and the surge rating is

usually considered in determining the insulation coordination of the power system.

KPLC1-3cb-TSP-11-031/32 standards define the minimum characteristics for 33kV and

11kV distribution and sub-station class surge arrestors;

Table 5.5: Minimum characteristics for 33kV and 11kV surge arrestors

TYPE Nominal discharge

current Description (33kV and 11kV)

1 10kA A distribution class metal oxide surge arrestor for use

along 33kV power lines and substations.

2 20kA

Surge arrestor for use along 33kV power lines and

substations in high lightning intensity areas as per

annex C of IEC 600994-4.

.

Geographically fahari city is located in a high intensity lightning region of west Kenya.

Hence Type 2 was chosen.

It has the following specifications:

33kV 11kV

Rated voltage and frequency 27kV ; 50 Hz 9kV ; 50 Hz

Insulation withstand 95 95

Continuous operating voltage

(minimum) 22kV 11kV

30

5.7 INSTRUMENT TRANSFORMERS

The main tasks of instrument transformers are:

• To transform currents or voltages from usually a high value to a value easy to

handle for relays and instruments.

• To insulate the relays, metering and instruments from the primary high-voltage

system.

• To provide possibilities of standardizing the relays and instruments, etc. to a few

rated currents and voltages.

5.8 POWER TRANSFORMERS

The term power transformer is used to refer to those transformers used between the

generator and the distribution circuits and are usually rated at 500kVA and above [10].

Figure 5.6: A power transformer

5.8.1 TRANSFORMER GROUNDING

It is important that the neutral of a power system be earthed otherwise this could ‘float’

all over with respect to true ground, thereby stressing the insulation above its design

capability. This is normally done at the power transformer as it provides a convenient

access to the neutral point.

Neutral grounding methods can be classified into:

• Effective neutral grounding (or solidly neutral grounding) method.

31

• Non-effective neutral grounding method.

The difference between the two practices is the difference of the zero-sequence circuit

from the viewpoint of power network theory. Therefore all power system behavior

characterized by the neutral grounding method can be explained as phenomena caused by

the characteristics of the zero-sequence circuit (appendix E).

Resistance grounding was chosen for the substation transformers in Fahari city as

shown in figure 5.7.

Figure 5.7: 5MVA Transformer grounding

5.8.1.1 GROUNDING RESISTOR SIZING

The earth grounding current during line to ground is usually limited 100-400A [11].

The transformer full load current:

=

√ = 262 A (5.8)

Ground fault current was then limited to 200 A. The value of the grounding resistor

which would reduce ground fault current to this value was found as explained below:

Taking; a, b and c to represent lines in a three phase system.

Conditions resulting from a line to ground fault on phase a can be expressed by the

following equations:

0; 0 (5.9)

With 0 and 0the symmetrical components of current are given by:

1 1 11

1

00

(5.10)

So that, and each equal

and:

= = (5.11)

32

Since for line to ground faults:

=

=

(5.12)

But

= + 3 ; < < 3 (5.13)

And

= < < (5.14)

Therefore

=

(5.15)

Therefore value of the grounding resistor is given by;

= √×

(5.15)

= √×

= 31.75 Ω (5.16)

5.8.1.2 TRANSFORMER TAPS

On-load Tap changers

On-load tap changers are very necessary to maintain a constant voltage on the LV

terminals of the transformer for varying load conditions.

This is achieved by providing taps, generally on the HV winding because of the lower

current levels. The tap changer changes the turns ratio between primary and secondary,

thereby maintaining a nominal LV voltage within a specific tolerance. A typical range of

taps would be +15 to –5% giving an overall range of 20%. The tap changer is usually

mounted in a separate compartment to the main tank with a barrier board in between.

This sometimes has a vent between the two to equalize the pressures.

Fahari substation power transformers were furnished with voltage taps in the high-

voltage winding. Six taps above and two taps below rated voltage each with a tap range

of 2.5%, yielding a 20% total tap voltage range (ANSI/IEEE, 1981 (R1989); ANSI/IEEE

C57.12.52-1981 (R1989)).

33

5.8.2 FINAL POWER TRANSFORMER SPECIFICATIONS

Table 5.6: Fahari substation transformer specifications Transformers

Item Particulars 33/11kV 11/0.415kV Unit

1 Continuous capacity a) ONAN 5000 - KVA

b) ONAF 6250 - KVA

Rated voltage (HV)(Winding) 33 11 kV

Rated voltage (LV) (Winding) 11 0.415 kV

Rated frequency 50 50 Hz

BIL rating 170 95 kV

Number of phases 03 03 -

Reactance % 7.15 - %

Connection (HV) DELTA DELTA -

Connection (LV) GND STAR GND STAR -

Vector group Dyn11

Type of cooling ONAN ONAN -

OLTC high voltage taps required

a) Above 15% -

b) Below 5% -

Highest System Voltage

a) HV 36 12 kV

b) LV 12 - kV

Grounding Type RESISTOR SOLID -

-Grounding resistor value 32 - OHMS

5.9 SUBSTATION FEEDERS

Since the feeder system chosen was the loop type. Feeders were paired so as to form a

closed ring and with each fitted with a circuit breaker.

The 11 kV bus was sectionalized into two sections each being fed from the different

power transformers. A bus sectionalizer in form of a circuit breaker and disconnector was

to be installed between the two bus sections which would make it possible to join or

separate the two sections while in service.

Each one of the feeders constituting a pair was to emanate from one of these sections and

the other from the other section because of the following reasons.

34

• In case protection system is isolates one section of the bus (i.e. if it is faulted)

supply is still maintained to the entire loop.

• If one transformer is out, the ring can still be fed from both sides which normally

reduces line losses and improves on the voltage regulation.

• It allows for maintenance on any of the switchgear, control gear, transformer etc

without interrupting service to the power consumers.

Tapings from the ring main were designed to be via ring main units which would then

feed their respective secondary distribution transformers.

The ring main units are also usually fitted with the necessary switchgear and controgear

as shown in figure 5.8.

Figure 5.8 Ring system implementation

This system is by far the most reliable for continuity of supply and gives better voltage

regulation and less power losses. It is used where continuity of supply is the priority

factor and thus large investment may be warranted.

35

5.9.1 NUMBER OF FEEDERS

Normally a primary distribution line or feeder is designed to carry a load of 1-4 MVA

depending on the feeder length, so the number of Feeders emanating from a secondary

substation at 11 kV is 3 or more [18].

The substation feeders should be able to ferry all electrical power from a source to the

designated load areas. Therefore the number of feeders for fahari city substation was

determined by the substation full capacity and the estimated full load on each.

Each feeder was first assigned an average capacity of 2.5 MVA and the substation

capacity being the sum of the ONAF ratings of the two power transformers.

Therefore assuming a typical ONAF value for a 5MVA transformer which is usually

6.25 MVA we have:

SUBSTATION CAPACITY = 6.25 x 2 (5.17)

= 12.5 MVA

NUMBER OF FEEDERS =

(5.18)

= ..

= 5 (5.19)

NB: Since each ring is fed by a pair of feeders, 6 feeders were chosen, three from

each 11kV bus section with the respective pairing feeder connected to the opposite

bus section.

With 6 feeders only three ring mains could be realized. One ring main was reserved as

spare which translates to two spare feeders.

5.9.2 DISTRIBUTION FEEDER EXIT AND DESIGNATION

The objective of distribution feeder exit plan is to provide for uniform area development

plan to minimize circuitry changes associated with the systematic expansion of the

distribution system.

The main types of feeder development are:

a. Rectangular-type development: commonly used for loop and grid feeder

systems [1].

b. Radial-type development: suitable for radial and parallel feeder systems.

36

Figure 5.9: Radial-type feeder development

Fahari being a ring-type feeder distribution system the rectangular type of feeder

development was adopted as illustrated in figure 5.10.

Figure 5.10: Rectangular-type feeder development

The substation feeders were designed in such an arrangement as to have the feeders

supplied from the same transformer extend in opposite directions so that all the ring main

circuits can be made from feeders supplied from different transformers.

This would make it easier to restore service to an area that is affected by a transformer

failure.

This was implemented on the fahari map as shown in figure..

Figure 5.11 shows substation feeders and their names.

37

Figure 5.11: Fahari substation feeder layout

NB: Feeder 3 and 6 were reserved spare feeders.

Feeders 1, 2, 4 and 5 were allocated service areas as shown in the map in figure 5.12.

Whereby feeders 1 and 4 formed the first ring main and feeder 2 and 5 were joined to

form ring main circuit 2.

Figure 5.12: Primary feeder service area designation

38

5.10 SUBSTATION SPECIFIC DESIGN LAYOUT

Figure 5.13: Shows the plan of the substation.

Figure 5.13: Substation specific design plan

39

CHAPTER 6 6 CONDUCTOR SIZING

The fault current level and full load current were used to size conductors in Fahari City.

6.1 SUBSTATION

6.1.1 33 KV OVERHEAD BUS CONDUCTORS

Full load current:

=

√× =

√×

=218.69 Amps (6.1)

The full load current was adjusted by 20% and a cable selected from the cable catalogue.

Fault level (chapter 7) = 10.496 kA

The conductor should be able to withstand the maximum fault current for a short period

before the protection system operates.

Therefore to get the 1sec withstand current rating;

=

(6.2)

10.5 × 3 = × 1 (6.2)

= √330.75 = 18.186 kA (6.3)

20 kA 1sec or 10 kA 3sec withstand level was chosen.

The full load current was adjusted by 20% and a cable selected from the cable catalogue

(appendix F).

NB: This was done for all the cables in Microsoft excel.

6.1.2 33KV POWER TRANSFORMER FEEDERS

These are the overhead conductors feeding the transformers from the 33KV bus.

Full load current

=

√× =

√×

= 109 Amps (6.4)

Fault level (chapter 7) = 10.496 kA

6.1.3 11 KV BUS INCOMERS FROM 5MVA POWER TRANSFORMER

There are two XLPE underground cables feeding the 11kV indoor switchgear from the

switchyard where the power transformers are located.

40

Transformer 11KV full load current:

=√×

= √×

= 328 Amps (6.5)

Fault level (from chapter 7) = 3.318 kA

6.2 DISTRIBUTION

6.2.1 11KV RING MAIN FEEDERS

The capacity of one ring main:

RING MAIN CAPACITY=

= .

(6.6)

= 4.166MVA

Feeders serving a loop must have sufficient reserve to handle the load that may be

transferred to them under abnormal conditions hence in this case should be able to carry

the full load of the Ring Main they serve.

Hence full load current = √×

= 218.65A (6.7)

6.2.2 DISTRIBUTION TRANSFORMERS FEEDERS FROM RMU

These are the conductors connecting the 11/0.415 kV distribution transformers to the

Ring Main Units.

They carry relatively low currents hence the cable selection was based on the fault level.

Table 6.1: 33kV and 11kV conductor sizing

DESCRIPTION

F.L

current

(A)

Fault

level

(KA)

CABLE DESCRIPTION

Type Size

(sq.mm)

Current

rating

(A)

Withstand

level Ohms/Km

Length

(m)

33KV BUS 219 10.496 - - >500 20 kA 1sec - 30

33KV TX FDR 109 10.496 - - >500 20 kA 1sec - 10

11KV INCOMER 328 3.318 1-C 150 263 10 kA 1sec 0.265+ j0.109 10

11KV FDRS

Ring Main 1 219 6.636 3-C 120 255 10 kA 3sec 0.325+j0.102 4424

Ring Main 2 219 6.636 3-C 120 255 10 kA 3sec 0.325+j0.102 4970

Ring Main3 219 6.636 3-C 120 255 10 kA 3sec 0.325+j0.102 SPARE

11/0.415 TX FDRS

41

6.2.3 LOW VOLTAGE SECONDARIES

The full load currents for the various cables was found to be relatively high, hence copper

conductors were used so as to reduce on the voltage drop.

N.B: Voltage drop at the consumer terminal should remain within ± 5% of the specified

voltage.

Table 6.2: Low Voltage conductor sizing

6.2.4 POWER FACTOR

The worst case power factor was analyzed for fahari power system to any of the

consumers. It was done by picking the consumer located furthest from the substation.

TX-1 (630kVA) 33 6.636 3-C 25 143 10 kA 1sec 0.927+0.132i 10

TX-2 (630kVA) 33 6.636 3-C 25 143 10 kA 1sec 0.927+0.132i 10

TX-3 (630 kVA) 33 6.636 3-C 25 143 10 kA 1sec 0.927+0.132i 10

TX-4 (630 kVA) 33 6.636 3-C 25 143 10 kA 1sec 0.927+0.132i 10

TX-5 (800 kVA) 42 6.636 3-C 25 143 10 kA 1sec 0.927+0.132i 10

TX-6 (150 kVA) 7 6.636 3-C 25 143 10 kA 1sec 0.927+0.132i 10

TX-7 (800 kVA) 42 6.636 3-C 25 143 10 kA 1sec 0.927+0.132i 10

SECONDARY

LINE

DESCRIPTION

F.L

current No:

120%

F.L

current

CABLE DESCRIPTION ANALYSIS

Size

(sq.mm)

Current

rating (A) mV/ A.m

Length

(m)

Voltage

drop (V) % V.D (V)

Hospital 696 2 417 185 465 0.259 20 2 0.43%

Small hotel 417 1 501 240 539 0.216 60 5 1.30%

School 417 1 501 240 539 0.216 60 5 1.30%

Library 278 1 334 120 368 0.366 20 2 0.49%

Mall 417 1 501 240 539 0.216 20 2 0.43%

Bank 417 1 501 240 539 0.216 20 2 0.43%

Big hotel 556 1 668 400 685 0.171 60 6 1.38%

Office 1 487 1 584 300 607 0.190 20 2 0.45%

Office 2 417 1 501 240 539 0.216 60 5 1.30%

Market 139 1 167 50 218 0.868 60 7 1.75%

Petrol station 278 1 334 120 368 0.366 60 6 1.47%

Monastery 209 1 250 70 269 0.609 20 3 0.61%

42

This analysis assumed that the worst system power factor would be at the consumer

located at the remotest point of the distribution system with the system being at its lowest

capacity (one 33kV line and power transformer out).

This was Office one (350 kVA) with ring two open at bus section two, being fed by one

33kV line and one power transformer.

Several assumed values of the connected load power factor were used and the overall

power factor looking into the system calculated in Microsoft excel.

Results were recorded in table 6.3.

Table 6.3: Fahari system power factor analysis Load power factor Overall system power factor

1 0.999

0.95 0.942

0.90 0.891

0.85 0.840

From the analysis a power factor value of 0.9 was recommended for the connected loads

failure to which tariff penalties ensue.

With all the loads corrected to a power factor of 0.9, a system power factor above 0.891

could be guaranteed.

43

CHAPTER 7

7 FAHARI POWER SYSTEM FAULT ANALYSIS

These different types of faults are illustrated in Figure 7.1.

Figure 7.1: Types of faults

NB: Switchgear needs to be rated to withstand and break the worst possible fault current,

which is a solid three-phase short-circuit close to the switchgear. ‘Solid’ meaning that

there is no arc resistance. Normally arc resistance will be present, but this value is

unpredictable, as it will depend on where exactly the fault occurs, the actual arcing

distance, the properties of the insulating medium at that exact instance.

Arc resistance will decrease the fault current flowing.

These approximate values are conservative, giving the worst case, and were therefore

confidently used for the ratings of switchgear panels.

44

7.1 FAULT CALCULATION

Importance of fault calculations:

• Highest fault current is used to rate the switchgear installed in the system.

• It helps to determine the quantities which can be used by the protection equipment

(e.g. relays) to distinguish between healthy (i.e. loaded) and fault conditions.

• Ensure that load and short circuit ratings of plant are not exceeded.

• It helps select the best relay characteristics for fault detection.

The highest fault current in this system would occur when there is a 3 phase short circuit

on the respective buses.

For the 11kV section of the fahari system the lowest fault level would occur during a line

to ground fault since the transformers are resistor grounded with the upper limit being

200A.

Since the switchgear equipment and the cables are connected to buses, faults calculations

were done on the various buses.

7.1.1 BUS FAULT LEVELS

Figure 7.2 illustrates fahari power system one line diagram.

45

Figure 7.2: Fahari power system one-line diagram.

46

Per unit method was used in the fault calculations.

Defining the base values:

=

√× ; =

(7.1)

Table 7.1: Base values LOCATION BASE MVA BASE KV I base (KA) Z base

33KV SIDE OF TX 5 33 0.087 217.8

11KV SIDE OF TX 5 11 0.262 24.2

0.415 SIDE OF DISTR.TX 5 0.415 6.956 0.034445

Transformer impedances:

• All referred to the same base of 5MVA.

Table 7.2: Transformer impedances Description MVA . X:R New .(5 )

TX A 5 7.15% 12.14 0.0058+0.071i

TX B 5 7.15% 12.14 0.0058+0.071i

TX 1 0.63 4.00% 3.96 0.0777+0.307i

TX 2 0.63 4.00% 3.96 0.0777+0.307i

TX 3 0.63 4.00% 3.96 0.0777+0.307i

TX 4 0.63 4.00% 3.96 0.0777+0.307i

TX 5 0.80 5.00% 5.79 0.0531+0.307i

TX 6 0.15 4.00% 2.74 0.5485+1.503i

TX 7 0.80 5.00% 5.79 0.0531+0.307i

7.1.1.1 CABLE IMPEDANCES TO THE VARIOUS BUSES Table 7.3: Ring sections impedances RING CCT FROM TO Length Z/ km TOTAL Z .

FDR 1- 4 FDR1 RMU1 0.318 0.325+0.102i 0.10335+0.032436i 0.00427+0.00134i

RMU1 RMU2 0.718 0.325+0.102i 0.23335+0.073236i 0.00964+0.00302i

RMU2 RMU3 1.315 0.325+0.102i 0.42737+0.13413i 0.01766+0.00554i

RMU3 RMU4 1.215 0.325+0.102i 0.39487+0.12393i 0.01631+0.00512i

RMU4 FDR4 0.858 0.325+0.102i 0.27885+0.087516i 0.01152+0.00361i

FDR 2-5 FDR2 RMU5 1.9 0.325+0.102i 0.6175+0.19381i 0.0255+0.008i

RMU5 RMU6 1.27 0.325+0.102i 0.41275+0.12954i 0.0170+0.005i

RMU6 RMU7 1.17 0.325+0.102i 0.38025+0.11934i 0.0157+0.005i

RMU7 FDR5 0.63 0.325+0.102i 0.20475+0.06426i 0.0084+0.003i

47

Table 7.4: Impedances to the various buses DESCRIPTION MINIMUM Z TO BUS MAXIMUM Z TO BUS

33 KV BUS 0.0079+0.0023i 0.0159+0.0047i

11 KV BUS 0.0109+0.0380i 0.0218+0.0760i

RMU 1 0.0151+0.0393i 0.0769+0.0933i

RMU 2 0.0248+0.0423i 0.0673+0.0903i

RMU 3 0.0387+0.0467i 0.0534+0.0859i

RMU 4 0.0224+0.0416i 0.0697+0.0910i

RMU 5 0.0364+0.0460i 0.0473+0.0841i

RMU 6 0.0350+0.0456i 0.0644+0.0894i

RMU 7 0.0193+0.0406i 0.0801+0.0943i

7.1.1.2 33 KV BUS MAXIMUM FAULT LEVEL

Starting from the source:

1. Each 33kV line has a fault MVA of 300MVA (they are two) and reactance to

resistance ratio of 0.3. Hence fault level at the 33KV bus is 600MVA when both

lines are on.

Therefore source impedance:

=

= 3.63 Ω for one line. (7.2)

With X: R being 0.3 Z= 3.477 + j1.043

. =

= ..

. = 0.0159+0.00478i (7.3)

3Ø fault current =

√× .= 5.248 kA for one line. (7.4)

The highest fault level would occur when all lines are connected.

= 5.248 × 2 = 10.496 kA (7.5)

48

7.1.1.3 11KV BUS MAXIMUM FAULT LEVEL

=

× kA (7.6)

Minimum impedance to bus

= (33kv lines in parallel) + (transformer impedance in parallel)

= 0.0079+0.0023i + 0.0029 + 0.035i (7.7)

Therefore 3Ø fault current

= ..

× 0.262 (7.7)

= 6.634 < − 73.99 kA

NB: THIS WAS DONE FOR ALL THE BUSES. WITH THE HIGHEST FAULT

OCCURING WHEN THE IMPEDANCE FROM THE SOURCE TO A PARTICULAR

BUS WAS MINIMUM. THIS WAS DONE IN THE EXCEL AND RESULTS RECORDED

IN TABLE 7.5.

7.1.2 FAULT CALCULATIONS RESULTS Table 7.5: Faults on various buses. BUS MAX 3Ø MIN L-L fault MIN L-G

33KV 10.497 4.545 -

11KV 6.634 2.873 198

RMU 1 6.220 1.878 191

RMU 2 5.342 2.017 192

RMU 3 4.321 2.246 193

RMU 4 5.548 1.981 192

RMU 5 4.470 2.356 193

RMU 6 4.560 2.063 193

RMU 7 5.824 1.836 191

TX 1 LV side 19.356 14.011 -

TX 2 LV side 19.063 14.217 -

TX 3 LV side 18.639 14.515 -

TX 4 LV side 19.136 14.166 -

TX 5 LV side 19.050 14.866 -

TX 6 LV side 4.203 3.530 -

TX 7 LV side 19.354 14.215 -

49

7.1.3 CIRCUIT BREAKER RATINGS

Circuit breakers installed in the system should have enough breaking capacity to

disconnect the circuit at maximum fault level and hence their capacity should be greater

than the fault MVA.

Fault MVA = √3 × × (7.8)

33 KV BUS fault MVA = √3 × 10.497 × 33 (7.8)

= 600 MVA

The ratings were selected from the R 10 series, as specified in IEC 60059.

NOTE; the R10 series comprises the numbers 1 - 1.25 - 1.6 - 2- 2.5 - 3.15 - 4.5 - 6.3 – 8

and their products by10.

Therefore 800 MVA, SF6 circuit breakers were chosen for the 33KV bus.

The same was done for all the buses and the values recorded in table 7.5.

Table 7.6: Circuit breaker ratings

BUS MAX 3Ø VOLTAGE (kV) MVA

CIRCUIT

BREAKER

CAPACITY (MVA)

33KV 10.497 33 600 800

11KV 6.634 11 127 200

RMU 1 6.220 11 119 200

RMU 2 5.342 11 102 200

RMU 3 4.321 11 83 200

RMU 4 5.548 11 106 200

RMU 5 4.470 11 86 200

RMU 6 4.560 11 87 200

RMU 7 5.824 11 111 200

50

CHAPTER 8 8 PROTECTION

8.1.1 OVERCURRENT PROTECTION

8.1.1.1 CURRENT TRANSFORMERS CONNECTIONS

Figure 8.1: Overcurrent Current transformer connections

The following were put into consideration for proper co-ordination and discrimination of

protection devices:

a. The current setting was set just above full load current allowing a 10% tolerance.

b. Operating time difference was allowed for between two adjacent devices to

ensure that downstream device will clear fault before upstream device trips also

known as grading margin. A suitable grading margin was chosen taking into

account:

• Breaker opening time (0.15s)

• Allowance for errors (0.1s)

• relay overshoot time (0.05s)

• safety margin (0.1)

A grading margin of 0.4sec was used for relay to relay coordination.

51

Table 8.1: Typical relay timing errors for standard IDMT Relay Technology

Electro-mechanical Static Digital Numerical

Typical basic timing error (%) 7.5 5 5 5

Relay overshoot time 0.05 0.03 0.02 0.02

Safety margin 0.10 0.05 0.03 0.03

Typical overall grading margin

-Relay to relay 0.40 0.35 0.30 0.30

c. When grading inverse time relays with fuses the grading margin for proper co-

ordination was given by the formula: [6]

0.14 0.15 (8.1)

8.1.2 EARTH-FAULT PROTECTION

8.1.2.1 CURRENT TRANSFORMER CONNECTIONS

Figure 8.2: Earth fault current transformer connections.

The typical settings for earth-fault relays are 30%-40% of the full-load current or

minimum earth-fault current on the part of the system being protected [6].

40% of minimum earth-fault current was used on the relays.

8.1.3 MAGNETISING INRUSH

The phenomenon of magnetizing inrush is a transient condition that occurs primarily

when a transformer is energized. It is not a fault condition, and therefore transformer

protection must remain stable during the inrush transient.

52

The waveform of transformer magnetising current contains a proportion of harmonics

that increases as the peak flux density is raised to the saturating condition.

An analysis of the resulting current waveform will show that it contains a high proportion

of second harmonic and will last for several cycles. Residual flux can increase the current

still further; the peak value attained being of the order of 2.8 times the normal value if

there is 80% permanence present at switch-on.

In practice, only the second harmonic is used to provide bias for overcurrent and

differential relays.

Therefore relays with harmonic restraint feature were proposed for transformer and

transformer feeder protection.

8.1.4 CONSUMER SERVICE MAINS PROTECTION

The consumer connection to the distribution 11/0.415 KV transformer was protected by

fuses on each phase as shown in figure 8.3.

Figure 8.3: Service main connections.

It has been established by tests that satisfactory grading between the two types of fuses

will generally be achieved if the current rating ratio between them is greater than two. [6]

For instance fuse 1 in figure 8.3 was rated 900amps with an operating time of 0.09

seconds and fuses 2 and 3 rated 450amps and 306amps respectively with operating time

of 0.03 seconds.

53

This was done for all secondary and service mains and as illustrated in table 8.2 and 8.3.

Table 8.2: Secondary lines fuse ratings Transformer

secondary

11/0.415KV

CAPACITY

KVA

Max

3Øsc

(KA)

Min

L-L

(KA)

Full Load

current

(A)

FUSE

RATING

(A)

Operating time

(Sec)

TX 1 630 19.356 14.011 876 900 0.03

TX 2 630 19.063 14.217 876 900 0.09

TX 3 630 18.639 14.515 876 900 0.09

TX 4 630 19.136 14.166 876 900 0.09

TX 5 800 19.050 14.886 1113 1250 0.09

TX 6 125 4.203 3.530 174 200 0.03

TX 7 800 19.534 14.215 1113 1200 0.09

Table 8.3: Service mains lines fuse ratings

Service line Max Min

L-L

Full Load

current

FUSE

RATING Operating time

Hospital 19.356 14.011 696 800 0.03

Small hotel 19.050 14.866 417 450 0.03

School 18.639 14.515 417 450 0.03

Library 18.639 14.515 278 306 0.03

Mall 19.050 14.866 417 459 0.03

Bank 19.136 14.166 417 459 0.03

Big hotel 19.063 14.217 556 612 0.03

Office 1 19.354 14.215 487 536 0.03

Office 2 19.354 14.215 417 459 0.03

Market 4.203 3.530 139 200 0.03

Petrol station 19.136 14.166 278 306 0.03

Monastery 19.063 14.217 209 230 0.03

8.1.5 DISTRIBUTION TRANSFORMER FEEDER PROTECTION

Fuses must withstand the magnetising inrush currents drawn when power transformers

are energised. High Rupturing Capacity (HRC) fuses, although very fast in operation with

large fault currents, are extremely slow with currents of less than three times their rated

54

value. It follows that such fuses would do little to protect the transformer, serving only to

protect the system by disconnecting a faulty transformer after the fault has reached an

advanced stage.

Relays were therefore used to provide overcurrent and earth-fault protection downstream

of the RMUs.

For proper coordination with the fuses on transformer secondary the grading margin was

calculated as below:

= 0.14 × 0.1 + 0.15 = 0.19 (8.2)

A time delay of 220 ms was chosen to discriminate with circuit protection on the

secondary side.

Standard inverse relay characteristic (IEC std 60255) was used to set the operating time

of the IDMT relays.

Standard inverse relay characteristic can be defined by the equation below.

Operating time, t = .

(). × (seconds) (8.3)

Where:

=

(8.4)

Transformer 1 feeder

=

= 155.5 (8.5)

Operating time, t = ...

× 1 = 1.318 sec (8.6)

The operating time required, is 0.22 sec.

TMS =

=

..

= 0.1669 (8.7)

The nearest TMS is 0.175

This was done for all the relays and the calculated settings recorded in tables 8.4

and 8.5 for overcurrent and earth fault respectively.

Current transformers with a turn ratio of 100:1 were used.

55

Table 8.4: Overcurrent relay settings

FDR

Fault current (11KV SIDE)

Maximum load current

CT RATIO

Relay current setting Time

multiplier setting

Op-time max min Per

cent Primary current

TX 1 6.220 1.878 33 100:1 0.4 40 0.175 0.22

TX 2 5.342 2.017 33 100:1 0.4 40 0.175 0.22

TX 3 4.321 2.246 33 100:1 0.4 40 0.175 0.22

TX 4 5.548 1.981 33 100:1 0.4 40 0.175 0.22

TX 5 4.470 2.356 42 100:1 0.5 50 0.150 0.22

TX 6 4.560 2.063 7 100:1 0.15 15 0.200 0.22

TX 7 6.320 1.750 42 100:1 0.5 50 0.150 0.22

Table 8.5: Earth fault relay settings

Feeder

Minimum Earth-Fault current (11KV SIDE)

Max load current (A)

Relay current setting Time

multiplier setting

Op-time CT RATIO

Per cent

Primary current

TX 1 191 33 100:1 0.77 77 0.05 0.22

TX 2 192 33 100:1 0.77 77 0.05 0.22

TX 3 192 33 100:1 0.77 77 0.05 0.22

TX 4 192 33 100:1 0.77 77 0.05 0.22

TX 5 194 42 100:1 0.77 77 0.05 0.22

TX 6 193 7 100:1 0.77 77 0.05 0.22

TX 7 191 42 100:1 0.77 77 0.05 0.22

A high-set instantaneous relay element was also used, the current setting being chosen to

avoid operation for a secondary short circuit. This would enable for a high-speed

clearance of primary terminal or winding short circuits.

The highest fault on any of the transformers secondary side is 19.5 kA.

Referred to the 11kV primary side;

=

× 19.5 = 0.730 (8.8)

56

This value compared with the maximum fault level on the primary of 6.22kA provided

for current discrimination with the downstream devices.

Therefore the relays high-set instantaneous element current setting was chosen to operate

for a current of 900 Amps.

8.1.6 RING MAINS PROTECTION

The distribution type within Fahari city is the Ring Main type. The primary reason for its

use is to maintain supplies to consumers in case of fault conditions occurring on the

interconnecting feeders. One of the ring main circuits with associated overcurrent

protection is shown in Figure 8.4. Current may flow in either direction through the

various relay locations, and therefore directional overcurrent relays were applied.

Grading of Ring Mains

The usual grading procedure for relays in a ring main circuit is to open the ring at the

supply point and to grade the relays first clockwise and then anti-clockwise [18].

Figure 8.4: Ring main circuit 1 with associated overcurrent protection

That is, the relays looking in an anti-clockwise direction around the ring are arranged to

operate in the sequence 1-2-3-4-5 and the relays looking in the clockwise direction are

arranged to operate in the sequence A-B-C-D-E, as shown in figure 8.5 and 8.6

respectively.

57

The arrows associated with the relaying points indicate the direction of current flow that

will cause the relay to operate. A double-headed arrow is used to indicate a non-

directional relay, such as those at the supply point where the power can flow only in one

direction. A single-headed arrow is usually used to indicate a directional relay, such as

those at intermediate substations around the ring where the power can flow in either

direction. The directional relays were set in accordance with the invariable rule,

applicable to all forms of directional protection that the current in the system must flow

from the substation busbars into the protected line in order that the relays may operate

[6].

8.1.6.1 RING MAIN CIRCUIT 1

8.1.6.1.1 ANTI-CLOCKWISE (BS-1 towards BS-2) FOR RING 1

The ring was opened at bus section 2 therefore the supply was via bus-section one as

shown in figure 8.5.

Figure 8.5: Anticlockwise feeding of ring main 1 via bus-section one

Table 8.6: Ring 1 anticlockwise overcurrent relay settings

Location

3∅Fault current Max (KA)

Maximum load current (A)

CT RATIO

Relay current setting Time multiplier setting

Op-Time Per cent

Primary current (A)

BS-1-5 6.64 219 300:1 1.18 351 0.775 2.22

RMU1-4 6.43 219 300:1 1.07 319 0.65 1.82

RMU2-3 5.60 219 300:1 0.97 291 0.525 1.42

RMU3-2 4.41 219 300:1 0.88 264 0.4 1.02

RMU4-1 3.63 219 300:1 0.8 240 0.25 0.62

58

The relay settings calculated as in table 8.6 were simulated in a ETAP power system

simulator and the relay characteristic report generated to confirm that coordination was

satisfactory.

Figure 8.6: Ring 1 overcurrent relays characteristics, Etap program report

59

THE SAME WAS DONE FOR ALL THE RELAYS TO ENSURE THAT COORDINATION

WAS GUARANTEED.

Table 8.7: Ring 1 anti clockwise earth fault relay settings

Location

Minimum earth Fault current (A)

Maximum load current

Relay current setting Time multiplier setting

Op-Time CT RATIO

Per cent Primary current (A)

BS-1-5 198 219 300:1 0.27 81 0.275 2.22

RMU1-4 198 219 300:1 0.25 75 0.25 1.82

RMU2-3 196 219 300:1 0.23 69 0.20 1.42

RMU3-2 194 219 300:1 0.21 63 0.175 1.02

RMU4-1 192 219 300:1 0.19 57 0.1 0.62

8.1.6.1.2 CLOCKWISE (BS-2 towards BS-1) FOR RING 1

The ring was opened at bus section 1 therefore the supply was via bus-section two as

shown in figure 8.7.

Figure 8.7: Clockwise grading

Table 8.8: Ring 1 clockwise overcurrent relay settings

Location

Fault current Max (KA)

Maximum load current

CT RATIO

Relay current setting Time

multiplier setting

OP -Time Per cent

Primary current (A)

BS-2-E 6.64 219 300:1 1.18 351.40 0.725 2.22

RMU4-D 5.66 219 300:1 1.07 319.44 0.625 1.82

RMU3-C 4.55 219 300:1 0.97 290.40 0.500 1.42

RMU2-B 3.69 219 300:1 0.88 264.00 0.400 1.02

RMU1-A 3.33 219 300:1 0.80 240.00 0.250 0.62

60

Figure 8.8: Clockwise overcurrent relays Etap simulation report

61

Table 8.9: Ring 1 clockwise earth fault relay settings

Location

Minimum Earth Fault current (A)

Maximum load current (A)

CT RATIO

Relay current setting Time

multiplier setting

OP -Time Per cent

Primary current (A)

BS-2-E 198 219 300:1 0.27 81 0.275 2.22

RMU4-D 197 219 300:1 0.25 75 0.250 1.82

RMU3-C 195 219 300:1 0.23 69 0.200 1.42

RMU2-B 193 219 300:1 0.21 63 0.175 1.02

RMU1-A 191 219 300:1 0.19 57 0.100 0.62

.

The same was done for ring main circuit 2.

8.1.6.2 RING MAIN CIRCUIT 2

8.1.6.2.1 ANTI-CLOCKWISE (BS-1 towards BS-2) FOR RING 2

Table 8.10: Anti-clockwise overcurrent relays settings

Location

Maximum Fault current (KA)

Maximum load current (A)

CT RATIO

Relay current setting Time multiplier setting

Op-Time Per cent

Primary current (A)

BS-1-4 6.64 219 300:1 1.07 321 0.625 1.82

RMU5-3 4.69 219 300:1 0.97 291 0.5 1.42

RMU6-2 3.81 219 300:1 0.88 264 0.375 1.02

RMU7-1 3.22 219 300:1 0.80 240 0.25 0.62

Table 8.11: Anti-clockwise earth fault relays settings

Location

minimum Earth Fault current

Maximum load current

CT -RATIO

Relay current setting Time multiplier setting

Op-Time Per cent

Primary current (A)

BS-1-4 198 219 300:1 0.25 75 0.25 1.82

RMU5-3 195 219 300:1 0.23 69 0.20 1.42

RMU6-2 193 219 300:1 0.21 63 0.175 1.02

RMU7-1 191 219 300:1 0.19 57 0.1 0.62

62

8.1.6.2.2 CLOCKWISE (BS-2 towards BS-1) FOR RING 2

Overcurrent relay settings Table 8.12: Ring 2 clockwise overcurrent relay settings

Location

Maximum Fault current (KA)

Maximum load current

CT RATIO

Relay current setting Time multiplier setting

Op-Time Per cent

Primary current (A)

BS-2-D 6.64 219 300:1 1.07 75 0.675 1.82

RMU7-C 5.86 219 300:1 0.97 69 0.55 1.42

RMU6-B 4.75 219 300:1 0.88 63 0.4 1.02

RMU5-A 3.85 219 300:1 0.8 57 0.25 0.62

Table 8.13: Ring 2 clockwise earth fault relay settings

Location

Fault current

Maximum load current

Relay current setting Time multiplier setting

Op-Time Min L-

G CT RATIO Per cent

Primary current (A)

BS-2-D 198 219 300:1 0.25 75 0.25 1.82

RMU7-C 198 219 300:1 0.23 69 0.225 1.42

RMU6-B 196 219 300:1 0.21 63 0.175 1.02

RMU5-A 194 219 300:1 0.19 57 0.1 0.62

8.1.7 11 KV SWITCHGEAR (BUSBAR) PROTECTION

Busbars are the most important components in a distribution network. They form an

electrical ‘node’ where many circuits come together, feeding in and sending out power.

If for any reason the busbars fails, it could lead to shutdown of all distribution loads

connected through them, even if the power generation is normal and the feeders are

normal. Unit protection type of protection was preferred due to fast operation required.

63

8.1.7.1 BUSBAR DIFFERENTIAL PROTECTION

Protection zones were first identified as:

1. Main zone 1, covering bus-section one.

2. Main zone 2, covering bus-section two.

3. Check zone, covering both sections of the bus.

The current transformers define the zone boundary.

Figure 8.9: Zoned busbar (switchgear) protection

Implementation

Figure 8.10: Implementation of the bus differential protection scheme.

64

The primary effective setting should not exceed 30% of the prospective minimum fault

current [6].

The minimum fault current on the 11kV bus is 198Amps (line to ground fault), therefore;

Differential relays current setting = 0.3 198 60

Operating time delay of 20ms was chosen to trip all breakers connected to the respective

bus zones.

8.1.8 SUBSTATION TRANSFORMERS AND FEEDERS PROTECTION

Figure 8.11: Substation switchyard protection layout.

For a fault at the location shown in figure 8.11 fault current can flow in either direction

and this could make all the relays send tripping signals to all the circuit breakers.

With this type of system configuration, it was necessary to apply directional relays at the

receiving end and to grade them with the non-directional relays at the sending end, to

ensure correct discriminative operation of the relays during line faults.

This is done by setting the directional relays ′ and ′ in Figure 8.11 with their

directional elements looking into the protected circuit, and giving them lower time and

current settings than relays and .

The usual practice is to set relays ′ and ′ to 50% of the normal full load (328) of

the protected circuit and 0.1TMS [6]. This gave a current setting of 165 Amps.

A high-set instantaneous overcurrent relay element was also used for relays and,

the current setting being chosen to avoid operation for a secondary short circuit. This

would enable for a high-speed clearance of primary terminal short circuits.

The highest fault on the 33/11kV transformers secondary side is 3.317 kA.

65

Referred to the 33kV primary side:

=

× 3.317 = 1.105 (8.10)

This value compared with the maximum fault level on the 33KV primary of 10.496 kA

provided for current discrimination with the downstream devices.

Therefore the relays high-set instantaneous element current setting was chosen to operate

for a current of 1.3 kA and send tripping signals to their respective circuit breakers

connected to the 33kV busbar.

OTHER PROTECTIVE DEVICES FOR THE TRANSFORMERS

The transformers had to have the following devices pre-installed in them [19]:

a. Thermal relays to respond to unacceptable temperature rises in the transformer,

and signal overloads.

b. Buchholz relays to detect internal damage by checking on gassing or sudden oil

flow; they should signal minor disturbances and trip the breaker if the trouble is

serious.

c. Temperature monitors to signal when a set temperature is reached, and trip feeder

circuit breakers.

d. Tele-thermometers to indicate the temperature in the transformer’s topmost oil

layer with maximum and minimum signal contacts.

e. Oil level alarms to respond to low oil level.

f. Oil flow indicators to detect any disruption in the circulation in closed-circuit

cooling and trigger an alarm.

g. Airflow indicators to detect any break in the flow of forced-circulation air, and

trigger an alarm.

66

8.1.9 LIGHTNING PROTECTION

The rolling sphere method was used for the substation Lightning protection for fahari city

substation.

8.1.9.1 ROLLING SPHERE METHOD

The rolling sphere method employs the simplifying assumption that the striking distances

to the ground, a mast, or a wire are the same. Use of the rolling sphere method involves

rolling an imaginary sphere of radius S over the surface of a substation. The sphere rolls

up and over (and is supported by) lightning masts, shield wires, substation fences, and

other grounded metallic objects that can provide lightning shielding. A piece of

equipment is said to be protected from a direct stroke if it remains below the curved

surface of the sphere by virtue of the sphere being elevated by shield wires or other

devices. Equipment that touches the sphere or penetrates its surface is not protected

(appendix G). The basic concept is illustrated in Figure 8.12.

Figure 8.12: Principle of the rolling sphere (IEEE STD. 998-1996)

Minimum Stroke Current

The allowable stroke current was chosen to be 2 kA for shielding Fahari substation.

Normally 99.8% of all strokes will exceed 2 kA [7]. Therefore, this limit will result in

very little exposure, but will make the shielding system more economical.

This is justifiable by the fact that the substation equipment had a fault current withstand

level over 6kA.

With a stroke current of 2kA:

67

Strike distance, S = 8 2. (8.11)

=15.064m

K=1.2 for lightning masts shielding.

Procedure

a. The substation plan, end elevation and side elevation were first drawn to scale.

b. Grounded metallic objects that could provide lightning shielding were first

identified, these include; substation fence, busbar towers 1 and 2 and the lightning

pole on the 11kV switchgear room.

c. A dashed line was drawn parallel to the ground at a distance S (the striking

distance) as obtained from Equation 3 above the ground plane.

d. For the end elevation an arc of radius S that touched the fence and the ground

plane was drawn with the centre located on the dashed line.

e. From tower 1 to tower 2 it was found that to make the protected zone cover the

33kV bus a lightning mast was required between the two towers.

f. Its height was determined to be 12m.

g. The same was done for the side elevation and the lightning mast height (12m)

found from the previous plot found to be satisfactory. Two more masts were

located as shown in figure 8.8 with each 8m high.

The general plan layout of the lightning masts is as shown in figure 8.13.

Figure 8.13: Substation lightning masts general layout

68

CHAPTER 9 9 CONCLUSION AND RECOMMENDATIONS FOR FUTURE WORK

9.1 CONCLUSION

Fahari distribution system was designed with reliable quality power as the main priority.

This was achieved by having several layers of redundancy; two 33kV overhead lines

serving the main substation, two transformers operating in parallel, sectionalizing of the

11 kV busbar and the adoption of the ring main type of primary distribution.

The ring system adopted was found to be most reliable for continuity of supply with

better voltage regulation and less power losses guaranteed. It was a requirement to have

the voltage drop at any consumer terminal remain within ± 5% of the required voltage,

from the analysis the worst voltage drop was found to be 1.47% at the petrol station. In

addition to that, with all the loads corrected to a power factor of 0.9, a system power

factor above 0.891 could be guaranteed. Otherwise with connected loads operating at

unity power factor (ideal) an overall power factor of 0.99 could be realized.

The protection system was developed to mitigate the effects of faults and improve overall

system reliability by ensuring the protection devices operated selectively and fast.

To test the integrity of the protection system, the coordination of the devices was

simulated using ETAP 6.0 power system simulation software. The results confirmed that

the protection system operated as required. The protection system operating time was set

to be within the withstand level of the equipment.

With this design, fahari power consumers were assured of reliable and quality service

connections.

69

9.2 RECOMMENDATIONS FOR FUTURE WORK

Due to time limitation some aspects of the project were not covered which are usually

important in system design. The author therefore proposed further work on these areas:

a. Wiring and circuit diagrams of the substation control circuit, civil design for the

substation etc. as defined in the flow chart in appendix A.

b. Cost analysis of the whole system.

c. Development of the distribution system into an interconnected system to further

improve on reliability.

d. Automation of the whole system by having remote centralized control and

monitoring using modern technology e.g. SCADA.

70

APPENDIX A: SUBSTATION DESIGN FLOW CHART

Figure A.1: Steps involved in establishing a new substation

71

APPENDIX B: OVERHEAD VERSUS UNDERGROUND SYSTEM

The distribution system can be overhead or underground.

The choice between overhead and underground system depends upon a number of widely

differing factors.

Advantages of underground system:

a) Public Safety: Underground system is safer than overload system.

b) Initial Cost and maintenance cost: Initial cost for underground system is more

expensive but the maintenance cost of underground system is very low in

comparison with that of overhead system.

c) Frequency of Faults or Failures: As the cables are laid underground, so these

are not easily accessible. The insulation is also better, so there are very few

chances of power failures or faults as compared to overhead system

d) Frequency of Accidents: The chances of accidents in underground system are

very low as compared to overhead system.

e) Voltage Drop: In underground system because of less spacing between the

conductors inductance is very low as compared to overhead lines, therefore,

voltage drop is low in underground system.

f) Appearance: Underground system of distribution or transmission is good looking

because no wiring is visible.

Advantages of overhead system:

a) Flexibility: Overhead system is more flexible than underground system. In

overhead system new conductors can be laid along the existing ones for load

expansion. In case of underground system new conductors are to be laid in new

channels.

b) Fault Location and Repairs: Though there are very rare chances of fault

occurring in underground system, but if one occurs it is very difficult to locate

that fault and its repair is difficult and expensive.

Considering the factors stated above underground system of distribution was

chosen.

72

APPENDIX C: VOLTAGE SELECTION

The following factors were considered in selecting an appropriate distribution voltage:

By defining power as:

= 3∅ (C.1)

The following can be deduced from that relationship:

a. Power — for the same current, power changes linearly with voltage hence a

higher voltage can carry more power for a given ampacity.

=

(C.2)

When =

b. Current — for the same power, increasing the voltage decreases current linearly

hence reducing the size of conductor required.

=

(C.3)

When =

c. Voltage drop — for the same power delivered the percentage voltage drop

changes as the ratio of voltages squared. A 415V circuit has 700 times the

percentage voltage drop as a 11kV circuit carrying the same load.

% =

% (C.4)

When =

d. Area coverage — for the same load density, the area covered increases linearly

with voltage: A 24.94-kV system can cover twice the area of a 12.47-kV system;

an 11kV system can cover 26.5 times the area of a 415V system.

=

(C.6)

Where:

, = voltage on circuits 1 and 2

, = power on circuits 1 and 2

, = current on circuits 1 and 2

%, % = voltage drop per unit length in percent on circuits 1 and 2

, = area covered by circuits 1 and 2

73

APPENDIX D: INDOOR VERSUS OUTDOOR SWITCHGEAR

• Indoor equipment is protected from adverse environmental conditions hence

improving on the reliability compared to outdoor installations which is exposed.

• Indoor installation is more compact hence suitable when space is limited

especially in big cities.

• Insulation difficulties for high voltages are a common problem in indoor

installations due to reduced spacing between conductors hence inflating costs

compared to same voltage rating for outdoor switchgear.

• A severe uncontained fault can cause severe damage to equipment in indoor

installations because of their close proximity to each other, hence outdoor

preferred for sections with high voltages and high fault levels.

• Indoor installations are good-looking than outdoor type.

APPENDIX E: POWER TRANSFORMER RATINGS

COOLING CLASS

Methods of cooling for liquid-immersed transformers have been arranged into cooling

classes identified by a four-letter designation as follows:

Table E.1: Cooling Class letter description.

74

TRANSFORMER GROUNDING

It is important that the neutral of a power system be earthed otherwise this could ‘float’

all over with respect to true ground, thereby stressing the insulation above its design

capability. This is normally done at the power transformer as it provides a convenient

access to the neutral point.

Neutral grounding methods can be classified into;

• Effective neutral grounding (or solidly neutral grounding) method.

• Non-effective neutral grounding method.

The difference between the two practices is the difference of the zero-sequence circuit

from the viewpoint of power network theory. Therefore all power system behavior

characterized by the neutral grounding method can be explained as phenomena caused by

the characteristics of the zero-sequence circuit.

Effective neutral grounded system:

The neutral of a power transformer is grounded solidly with a copper conductor

Figure E.0.1: Solid grounded power transformer

Advantages:

• Neutral held effectively at ground potential.

• Cost of current-limiting device is eliminated.

• Size and cost of transformers are reduced by grading insulation toward neutral

point N.

Disadvantages:

• As most system faults are phase-to-ground, severe shocks are more considerable

than with resistance grounding.

• High earth fault currents which can damage equipment extensively.

• Third harmonics tend to circulate between neutrals.

• Communication interference.

75

Non-effective neutral grounded system:

Resistive or reactive impedance is connected between the transformers neutral and earth

Figure E.0.2: Resistance grounding

Non-effective grounding is achieved using several methods:

a. Resistive neutral grounded system.

A resistor is connected between the transformer neutral and earth. The value is such as to

limit an earth fault current to between 1 and 2 times full load rating of the transformer.

Advantages

• Low earth fault current. (Can be engineered to any chosen value). The earth

grounding currents during 1line to ground and 2 lines to ground faults are limited

within 100–400 A.

• Fault damage is minimal.

• Communication interference minimal.

Disadvantages

• Full line-to-line insulation required between phase and earth.

b. Arc-suppression coil (Peterson coil) neutral grounded system.

A tap changeable reactor is connected in the transformer neutral to earth. Value of

reactance is chosen such that reactance current neutralizes line capacitance current. The

current at the fault point is therefore theoretically nil and unable to maintain the arc,

hence its name.

Figure E.0.3: Peterson coil

From the above considerations it is evident that the effective grounding method has lower

initial cost but higher long term equipment repair cost, compared to resistive earthing

76

which has higher initial cost but lower long term equipment repair cost making resistive

earthing the more cost effective method.[14]

Considering the Petersons coil, tuning of the coil in the zero-sequence circuit may be

easy for smaller power systems with radial feeder connections. However, it is not so easy

for large power systems which include several substations that must be neutral grounded,

and/or for loop-connected power systems, which is the case with fahari system which has

a loop feeder system.

77

APPENDIX F: POWER CABLES

The following types of power cable are mainly used for underground distribution

purposes in the medium-voltage (MV) range:

• Paper-insulated lead covered (PILC) cables.

• Cross-linked polyethylene (XLPE) cables.

PAPER-INSULATED LEAD-COVERED (PILC) CABLES

The PILC cables are manufactured by using layers of paper impregnated with a

compound mineral oil as insulating medium, both as individual core and overall

insulation. A lead sheath is constructed as an outer core layer to mainly provide a seal for

the compound in the paper layers, and also for excellent corrosion protective properties as

well as to provide additional mechanical protection.

A steel tape layer (often a double layer) or steel wires are used for the main mechanical

protection and it may also be used as a return path for earth currents. The outer sheath

may be a PVC layer or other type of insulating and waterproof material.

CROSS-LINKED POLYETHYLENE (XLPE) CABLES

XLPE, PEX and PVC are used as conductor insulating materials in these cables. XLPE is

a semiconductor, and provide partial insulation as well as electrical stress relieving. The

conductors, with their XLPE layers, are embedded in PVC to provide total insulation.

Steel wires are used for mechanical strength, and may also be used to provide the return

path for earth fault currents. The outer sheath is normally a PVC sheath to provide

insulation and waterproofing.

XLPE cables are used from low voltage (600/1000 V) up to 800 kV applications.

CABLE SELECTION

When selecting a cable for the 11kV underground distribution application the following

factors were put into consideration;

• The XLPE cables have higher current ratings than PVC cables for the same

conductor size.

• PILC cables tend to be more expensive than XLPE cables for the same conductor

size.

• XLPE cables are better suited to be moved frequently after installation, making

them better suited for use in a continuously changing environment.

78

• The choice between aluminum or copper conductors was an economic one.

Aluminum was chosen for primary distribution because it was cheaper than copper for

the long distances involved.

Copper cables were chosen for the low voltage distribution because copper has better

conductivity than aluminum. Using copper would reduce on the voltage drop since

currents are usually high in LV circuits.

Therefore XLPE aluminum cable type was selected for 11KV underground distribution

for Fahari city.

79

CABLE SIZING

1. 11 KV INCOMER

Figure F. 0.1: Olex catalogue single core aluminium 11kV cables

80

2. 11kV RING FEEDERS

Figure F.2: Olex catalogue three core aluminium 11kV cables

81

3. 11/0.415 KV TRANSFORMER FEEDERS

Figure F.3: Olex catalogue three core copper 11kV cables

82

4. TRANSFORMER SECONDARY CABLES

Figure F.4: Olex catalogue four core mains cable

83

APPENDIX G: LIGHTNING STROKE PROTECTION

THE ELECTROGEOMETRIC MODEL (EGM) [7]

As voltage levels (and therefore structure and conductor heights) have increased over the

years, the classical methods (fixed-angle and empirical curves) of shielding design have

proven less adequate. This led to the development of the electro-geometric model which

is used to design a zone of protection for substation equipment.

The revised EGM model takes the following aspects into consideration:

1. The stroke is assumed to arrive in a vertical direction. (It has been found that a

previous assumption of the stroke arriving at random angles is an unnecessary

complication.)

2. The differing striking distances to masts, wires, and the ground plane are taken

into consideration.

3. A value of 24 kA is used as the median stroke current. This selection is based on

the frequency distribution of the first negative stroke to flat ground.

4. The model is not tied to a specific form of the striking distance.

One method of applying the EGM model is the rolling sphere method.

The EGM theory shows that the protective area of a shield wire or mast depends on the

amplitude of the stroke current [7]. If a shield wire protects a conductor for a stroke

current, it may not shield the conductor for a stroke current less than that has a

shorter striking distance (length of the last stepped leader).

Conversely, the same shielding arrangement will provide greater protection against stroke

currents greater than that have greater striking distances.

Application of the EGM by the Rolling Sphere Method

It is only necessary to provide shielding for the equipment from all lightning strokes

greater than stroke current that would result in a flashover of the buswork. Strokes less

than are permitted to enter the protected zone since the equipment can withstand

voltages below its BIL design level.

Bus insulators are usually selected to withstand a basic lightning impulse level (BIL).

Insulators may also be chosen according to other electrical characteristics, including

negative polarity impulse critical flashover (C.F.O.) voltage. Flashover occurs if the

84

voltage produced by the lightning stroke current flowing through the surge impedance of

the station bus exceeds the withstand value.

The stroke current is calculated as follows:

= .

(G.1)

Or

= .

(G.2)

Where

is the allowable stroke current in kilo-amperes.

BIL is the basic lightning impulse level in kilovolts.

C.F.O. is the negative polarity critical flashover voltage of the insulation

being considered in kilovolts.

Zs is the surge impedance of the conductor through which the surge is

passing in ohms.

The final striking distance is related to the magnitude of the stroke current as illustrated

in equation (3)

= 8. IEEE Std. 998-1996 (G.3)

Where

is the strike distance in meters

is a coefficient to account for different striking distances to a mast, a

shield wire, or the ground plane.

Normally k = 1 is given for strokes to wires or the ground plane and a value of k =1.2 is

given for strokes to a lightning mast.

Protection against Stroke Current is calculated from Eq. (1) as the current producing a

voltage the insulation will just withstand. Substituting this result in Eq. (3) gives the

striking distance S for this stroke current.

85

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86

[16] Olex New Zealand Limited Bell factory, Cable catalogue.

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