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`ECONOMIC ANALYSIS OF ADDING CAPACITOR
BANKS TO THE SRI LANKAN TRANSMISSION
NETWORK
S.A.D. Tharanga
(08/8314)
Degree of Master of Science
Department of Electrical Engineering
University of Moratuwa
Sri Lanka
September 2012
ECONOMIC ANALYSIS OF ADDING CAPACITOR
BANKS TO THE SRI LANKAN TRANSMISSION
NETWORK
Suraweera Arachchige Damith Tharanga
(08/8314)
Dissertation submitted in partial fulfillment of the requirement for the degree Master
of Science in Electrical Installation
Department of Electrical Engineering
University of Moratuwa
Sri Lanka
September 2012
i
Declaration
“I declare that this is my own work and this dissertation does not incorporate without
acknowledgement any material previously submitted for a Degree or Diploma in any
other University or institute of higher learning and to the best of my knowledge and
belief it does not contain any material previously published or written by another
person except where the acknowledgement is made in the text.
Also, I hereby grant to University of Moratuwa the non-exclusive right to reproduce
and distribute my dissertation, in whole or in part in print, electronic or other
medium. I retain the right to use this content in whole or part in future works (such as
articles or books)”.
……………………….
Signature of the candidate Date:
(S.A.D.Tharanga)
The above candidate has carried out research for the Masters Dissertation under my
supervision.
…………………………….
Signature of the supervisor Date:
(Dr. K.T.M. Udayanga Hemapala)
ii
Abstract
At present, there are significant reactive power flows in the Sri Lankan power system, giving
rise to excessive network losses, creating under voltage conditions and limiting the
utilization of transmission line and transformer capacities. This undesirable flow of reactive
power through the network can be reduced by generating reactive power as close as possible
to the loads; at least at grid substation level. Capacitor banks can be used for reactive power
compensation and voltage support in grid substations as it is a comparatively inexpensive
source of reactive power.
Ceylon Electricity Board (CEB) has some amount of breaker switched capacitor banks
installed at several grid substations. In most of the cases the capacitors have been selected
only with the aim of mitigating under voltage situation and very little attention is given for
loss reduction in the power system by installing capacitor banks. But still there are grid
substations which experience under voltages during some periods of the day. Therefore, the
objective of this research is to propose new additions of capacitors to the CEB network for
network loss reduction and mitigating under voltage levels.
Whole CEB power system is modeled in Power System Simulator for Engineering (PSS®E)
software. Load flow network simulations were run for different scenarios and identified the
grid substations showing the under voltages and key locations for reactive power demand.
First the required sizes of capacitor banks were selected for grid substations considering only
under voltage mitigation. Then the capacitor banks were selected for grid substations
considering both voltage support and loss reduction. The new selection of capacitors was
justified by examining its economic feasibility.
Proposed new additions of capacitors to the CEB network can contribute for reducing the
network losses, delaying the investment on generators and improving the voltage level in the
power system.
Key words: Reactive Power, Breaker Switched Capacitor, Network Loss Reduction
iii
Acknowledgement
First, I would like to express my sincere gratitude to Dr. K.T.M. Udayanga
Hemapala for his guidance and supervision during conducting this research and
preparation of final dissertation.
I extend my sincere gratitude to Prof. J.P. Karunadasa, Head of the Department of
Electrical Engineering and to the staff of the Department of Electrical Engineering
for the support extended during the study period.
I am also most grateful to Mr. Jayasiri Karunanayake for his advice in making this
study practical and meaningful. I also specially thank Mr. Eranga Kudahewa for his
instructions during the simulations and the study.
I would like to take this opportunity to extend my sincere thanks to Mr. Janaka
Manohara, Electrical Engineer (Transmission O&Ms Branch – Galle Region), Mr.
Rohana Ekanayake, Chief Engineer (Transmission O&Ms Branch – Kandy Region),
Mr. Sajith Paulas, Electrical Engineer (Transmission O&Ms Branch – Kandy
Region), Mr. Anuradha Mudannayake, Electrical Engineer (Generation Planning
Branch), Mr. Anjana Subasinghe, Electrical Engineer (New Galle Transmission
Project) and all the Office Staff of Transmission Project(AGSAREP) of Ceylon
Electricity Board who gave their co-operation to make my investigation work a
success.
It is with great pleasure that I remember the encouragement and support extended by
the colleagues in the post graduate programme, friends and specially my parents and
my wife. May be I could not have completed this research without their valuable
support.
iv
Table of Contents
Page
Declaration .................................................................................................................... i
Abstract ........................................................................................................................ ii Acknowledgement ...................................................................................................... iii List of Figures ............................................................................................................. vi List of Tables ............................................................................................................. vii List of Abbreviations ................................................................................................ viii
List of Appendices ...................................................................................................... ix
INTRODUCTION ....................................................................................................... 1
1.1 Background ........................................................................................................ 1 1.2 Objectives .......................................................................................................... 3 1.3 Scope of Work ................................................................................................... 3
REACTIVE POWER FLOW AND CAPACITOR BANKS ....................................... 5 2.1 Reactive Power .................................................................................................. 5
2.2 Shunt Capacitors ................................................................................................ 7 2.3 Different Types of Capacitor Banks .................................................................. 8 2.4 Var Control ........................................................................................................ 9 2.5 Voltage Control ................................................................................................ 10
FAMILIARIZATION WITH CEB POWER SYSTEM ............................................ 11
3.1 Capacitor Banks in the CEB System................................................................ 11 3.2 Dispatch Scenarios in the CEB System ........................................................... 12
SYSTEM MODELLING, SIMULATION AND DATA ANALYSIS ...................... 15
4.1 Selecting Capacitor Banks ............................................................................... 16 4.1.1 Under voltage mitigation only ...................................................................... 16
4.1.2 Both under voltage mitigation and loss reduction ........................................ 17 4.2 Reduction of Mvar Generation at Power Stations ........................................... 21 4.2.1 Under voltage mitigation only ...................................................................... 21
4.2.2 Both under voltage mitigation and loss reduction ........................................ 21 4.3 Reduction of I
2R Loss in the Network ............................................................. 22
4.3.1 Under voltage mitigation only ...................................................................... 22
4.3.2 Both under voltage mitigation and loss reduction ........................................ 22 4.4 Economic Analysis: ......................................................................................... 23
4.4.1 Under voltage mitigation only ...................................................................... 24 4.4.2 Both under voltage mitigation and loss reduction ........................................ 24
CONCLUSION AND RECOMMENDATIONS ...................................................... 27 5.1 Conclusion ....................................................................................................... 27 5.2 Recommendations for Future Developments ................................................... 27
Reference List ............................................................................................................ 28 Appendix 1: Hydro maximum Day Peak…………………………………………... 28
Appendix 2: Hydro maximum Night Peak…………………………………………29
Appendix 3: Hydro maximum Off Peak……………………………………............30
Appendix 4: Thermal maximum Day Peak…………………………………………31
Appendix 5: Thermal maximum Night Peak……………………………………......32
Appendix 6: Thermal maximum Off Peak……………………………………….....33
v
Appendix 7: Typical Dispatch Day Peak………………………………………….34
Appendix 8: Typical Dispatch Night Peak………………………………………...35
Appendix 9: Typical Dispatch Off Peak…………………………………….……..36
vi
List of Figures
Page
Figure 2.1: Typical metal enclosed capacitor bank...................................................... 8
Figure2.2: Typical pad mounted capacitor bank .......................................................... 8
Figure 2.3: Typical stacked rack capacitor bank.......................................................... 9
Figure 2.4: Typical pole mounted capacitor bank ....................................................... 9
Figure 3.1: Typical load profile of Sri Lanka ............................................................ 12
Figure 3.2: Capability curve of a hydrogen cooled generator ................................... 14
Figure 4.1: Under voltage condition at Galle grid substation .................................... 15
Figure 4.2 Under voltage condition at Ampara grid substation ................................. 16
vii
List of Tables
Page Table 3.1: Existing capacitor banks in CEB system ................................................. 11 Table 3.2: Permissible voltage deviations as per CEB voltage criteria ..................... 13 Table 4.1: Grid substations having under voltage condition ..................................... 16
Table 4.2: Capacitor requirement for under voltage condition .................................. 17
viii
List of Abbreviations
Abbreviation Description
AVR Automatic Voltage Regulator
BSC Breaker Switched Capacitor
CEB Ceylon Electricity Board
GT Gas Turbine
NPV Net Present Value
PCB Poly Chlorinated Biphenyl
PSS/E Power System Simulator for Engineering
ix
List of Appendices
Appendix Description Page
Appendix 1 Hydro maximum Day Peak 27
Appendix 2 Hydro maximum Night Peak 28
Appendix 3 Hydro maximum Off Peak 29
Appendix 4 Thermal maximum Day Peak 30
Appendix 5 Thermal maximum Night Peak 31
Appendix 6 Thermal maximum Off Peak 32
Appendix 7 Typical Dispatch Day Peak 33
Appendix 8 Typical Dispatch Night Peak 34
Appendix 9 Typical Dispatch Off Peak 35
1
Chapter 1
INTRODUCTION
1.1 Background
Many power system components in a network and particularly the loads are
inherently inductive and hence consume large amounts of reactive power. Reactive
current supports the magnetic fields in motors and transformers [1]. Supporting both
real and reactive power with the system generation requires increased generation and
transmission capacity, because it increases losses in the network. That is why most of
the power utilities around the world are trying to generate its reactive power
requirements as close as possible to the load centers. In general, many utilities
describe this as the concept of reactive power compensation in the technical
vocabulary.
Shunt-connected capacitors or synchronous condensers near the load centers are a
common method to generate reactive power. Shunt capacitors have the advantage of
providing reactive power close to the load centers, minimizing the distance between
power generation and consumption, and do not have the maintenance problems
associated with synchronous condensers. Breaker switched or fixed capacitor banks,
are comparatively economical and installation is also easy. Later additions according
to match load characteristics are comparatively flexible. Controlling capacitance in a
transmission or distribution network could be the simplest and most economical way
of maintaining system voltage, minimizing system losses and maximizing system
capability.
The application of capacitor banks and its controlling philosophy is different from
location to location. For an end consumer it is used as a power factor corrector that
helps to reduce his demand and avoid penalties from the energy supplier. For a
distribution company, the capacitors installed at intermediate locations on
distribution line reduce line losses hence increases line capacities and improve the
bus bar voltage. For a transmission company, the intention is not only to reduce loses
2
or increase line capacities but also to give voltage support which is an inherent
system problem under heavily loaded conditions and to further delay investment
costs on augmenting line and substation capacities. Static shunt capacitors are
installed near the load terminals, in factory substations, in the receiving substations,
in switching substations, etc. to provide leading vars and thus to reduce the line
current and total kVA loading of the substation transformer[2]. At generation buses,
capacitor banks also can be used for voltage support though it is rare. Depending on
the location and requirement, the controlling philosophy of the capacitor banks will
differ. Generally, as mentioned earlier, the distribution capacitor banks are controlled
for local requirements. In many cases the control consists of switches that are opened
and closed in a seasonal basis or some other local requirement.
Ceylon Electricity Board (CEB), like many other utilities, has about 130Mvar of
Breaker Switched Capacitor (BSC) banks in operation, installed at various
substations in the system. In most of the cases the capacitors have been selected only
with the aim of mitigating under voltage situation and very little attention is given for
loss reduction in the power system by installing capacitor banks. But still there are
grid substations which experience under voltages during some periods of the day.
Further, some of the installed capacitor banks are currently out of service due to
technical problems. The main intentions of the use of capacitor banks is to give
voltage support at the substation level, reduction of losses in power transformers and
transmission lines, and to release the capacity constraints in transformers and lines.
Increased economic benefits can be achieved by installing more capacitor banks.
Underutilizing an economical reactive power source is a factor to consider.
All the capacitor banks in CEB network are connected to the 33kV load bus in the
relevant grid substation. This philosophy of installing the capacitor banks in grid
substations does not either release the distribution feeder capacity or reduce the
feeder losses. If those were expected then the capacitors could have been closer to
the loads. However, lagging var injection or in other words leading var consumption
at 33kV bus level improves the voltage stability and releases the power transformers
at the substation. If the utility expects latter two cases, the switching of the capacitor
3
banks shall be based on reactive power or voltage. In case of voltage, the banks
should be switched considering the voltage measurements at the point of
interconnection. If releasing the capacity constraint or minimizing losses are
concerned, then more capacitors shall be utilized to minimize drawing reactive
power from remote generation.
1.2 Objectives
Taking all these into Consideration, the main objective of the research study is to
look in to the possibilities of adding BSC banks to the CEB system with a view of
both under voltage mitigation and reducing network losses.
1.3 Scope of Work
Running load flow simulations of the CEB network in PSS/E software for
different scenarios and identifying the grid substations having under voltage
problem.
Studying the system and identifying key locations with reactive power
demand.
Calculating the network loss without adding new capacitor banks.
Calculating the reactive power generation by generators in the system without
adding new capacitor banks.
Selecting capacitor bank sizes for the selected locations considering under
voltage mitigation only (Method 1).
Calculating the network loss after adding new capacitor banks (Method 1).
Calculating the reactive power generation by generators in the system after
adding new capacitor banks (Method 1).
Selecting capacitor bank sizes for the selected locations considering both
under voltage mitigation and loss reduction (Method 2).
Calculating the network loss after adding new capacitor banks (Method 2).
4
Calculating the reactive power generation by generators in the system after
adding new capacitor banks (Method 2).
Calculating economic benefits of adding new capacitor banks according to
Method 1 and Method 2.
Reduction of heat(I2R) losses in the network and reduction of reactive power
generation at power station level due to capacitors can be obtained using simulations.
Using those data and investment costs of breaker switched capacitors, economic
feasibility of adding those capacitor banks to the system can be investigated.
5
Chapter 2
REACTIVE POWER FLOW AND CAPACITOR BANKS
2.1 Reactive Power
Every electric load that works with magnetic fields (motors, chokes, transformers,
inductive heating, arc-welding generators) produces a varying degree of electrical
lag, what is called inductance. This lag of inductive loads maintains the current sense
(eg: positive) for a time even though the negative going voltage tries to reverse it.
This phase shift between current and voltage is maintained, current and voltage
having opposite signs. During this time, negative power or energy is produced and
fed back into the network. When current and voltage have the same sign again, the
same amount of energy is again needed to build up the magnetic fields in inductive
loads[3]. This magnetic reversal energy is called reactive power. In alternating
voltage networks (50/60 Hz) such a process repeats 50 or 60 times a second. So an
obvious solution is to briefly store the magnetic reversal energy in capacitors and
relieve the network (supply line) of this reactive energy. For this reason, automatic
reactive power compensation systems (detuned/conventional) are installed for larger
loads like factory plants. Such systems consist of a group of capacitor units that can
be cut in and cut out and which are driven and switched by a power factor controller
as determined by a current transformer.
As a good approximation many power systems are mainly inductive i.e. have a high
reactance to resistance (X/R) ratio. For such systems difference in voltages causes
reactive power flows and conversely reactive power flows influence terminal
voltage[4].
But conductors of transmission lines act like plates of a capacitor also. The
conductors are charged, and there is a potential difference between the conductors
and between the conductors and the ground. Therefore there is capacitance between
the conductors and between the conductors and the ground. This also adds capacitive
reactive power to the system. The basic equation for calculation of the capacitance is
6
the definition of the capacitance as the ratio of the charge and the potential difference
between the charged plates:
CQ
VF
where Q is the total charge on the conductors (plates)
V is the potential difference between the conductors or a conductor and
ground (i.e. plates)
For transmission lines, we usually want the capacitance per unit length
Cq
VF m /
where q is the charge per unit length in C/m
V is the potential difference between the conductors or a conductor and
ground (i.e. plates)
Capacitance of Balanced Three Phase Line between a phase conductor and neutral is
given by
CD
D
F mn
o
eq
b
2
ln
/
where D D D Deq ab bc ca 3
and Dab, Dbc, and Dca are the distances between the
centers of the phase conductors, and Db is the geometric mean radius for the bundled
conductors. (in the expression for Db the outside radius of the conductor is used,
rather than the GMR from the tables.)
The capacitive reactance to neutral than becomes
Xf
D
Dmilecn
eq
b
1779 106.
ln .
7
2.2 Shunt Capacitors
Capacitor Banks consist of individual capacitor units where such a unit is a
combination of shunt or series set of capacitor elements. Depending on the bank size,
those units are again connected in series or parallel to give the required size. In
medium and high voltage levels, sizing of the capacitors in parallel combinations in
banks generally has to consider the discharge energy through a shorted parallel
capacitor in the same group.
Earlier generation capacitor units were manufactured using very refined kraft paper
with a PCB (Poly Chlorinated Biphenyl) impregnant. The kraft paper had many non-
uniformities or flaws. Several layers of paper were used between the foil layers to
avoid weak spots in the design. With this design, the stress levels were low but the
dielectric losses were higher than that of today’s capacitor can designs. High
dielectric losses resulted in high hot spot temperatures. High temperatures accelerate
deterioration of the capacitor dielectric strength. Failure of the dielectric material
resulted in continued arcing, charring, and gas generation that swelled the capacitor
cans and eventually ruptured the cases.
Today’s capacitor units are built with polypropylene film (instead of kraft paper) and
dielectric fluids with electrical characteristics superior to those of PCB. The
polypropylene film is very thin, pure, and uniform, with exceptionally few design
flaws. This latest design only requires two to three layers of film. While this
increases the stress levels, it reduces the dielectric losses which results in low hot
spot temperatures. As a result of these changes, today’s capacitor units do not age
quickly. Swelling or case rupture is now very rare. Because film layers are thin and
of high quality, element failures do not cause arcing and charring. Instead, the foil
welds together. Capacitor units for power system applications are built with
dielectric polypropylene film, aluminum foil and impregnant. Thin layers of
dielectric film are wound between the aluminum foils, which act as the electrode.
8
2.3 Different Types of Capacitor Banks
Different types of capacitor banks are available in the present market. Metal enclosed
type, pad mounted type, stack-rack banks and pole top mounted types are the most
common type in utility applications. Metal enclosed type banks specifically made tor
indoor installations. Pad mounted capacitor banks are also enclosed in a metal
enclosure and commonly used for areas where accessible to public.
Figure 2.1: Typical metal enclosed capacitor bank
Normally, metal enclosed and pad mounted units come with factory assembled and
tested hence the installation is very easy. Those banks significantly reduce
unnecessary human interference such as trespassing and tampering. They do not need
a fence around it. However their initial cost is high compared to other types and only
available up to a certain voltage level.
Figure2.2: Typical pad mounted capacitor bank
Stack rack capacitor banks are commonly used in the utility sub stations. The initial
cost of these is comparatively low and all components are visible. The components
are easily replaceable and also easily expandable.
9
The pole top mounted banks are commonly used in distribution networks for
improving the voltage profile in distribution lines. Those are available as smaller
banks and eliminate the need for space. The maintenance and component
replacement is little difficult.
Figure 2.3: Typical stacked rack capacitor bank
Figure 2.4: Typical pole mounted capacitor bank
2.4 Var Control
Var control is the natural means to control capacitors because the latter adds a fixed
amount of leading var to the system regardless of other conditions, and loss reduction
depends only on reactive current. Since reactive current at any point along a feeder is
affected by downstream capacitor banks, this kind of control is susceptible to
10
interaction with downstream banks. In a system like CEB, there are no switchable
capacitor banks along the distribution feeder so that this problem will not arise.
However, in multiple capacitor feeders, the furthest downstream banks should go on-
line first and off-line last. Var controls require current sensors and typically costly.
2.5 Voltage Control
Voltage control is used to regulate voltage profiles on the bus on which the
capacitors are connected to. However, while doing this it may not consider the
reduction of system losses since lagging or leading low power factors always
increase the currents through its components. Voltage control requires no current
sensors.
Considering above parameters for switching the capacitor banks, we can define two
concepts of control philosophies. First is single variable switching that considers
only one measuring parameter. Second concept is multi variable and Boolean
switching. In the latter case multiple parameters are measured and the decision for
switching is done depending on the optimal situation considering both parameters.
The fact we have to consider is the cost of the controllers.
11
Chapter 3
FAMILIARIZATION WITH CEB POWER SYSTEM
3.1 Capacitor Banks in the CEB System
Capacitor banks are installed in several grid substations in the existing CEB system.
But some of them are out of service due to technical problems. The existing capacitor
banks in operational condition are detailed in Table 3.1.
Table 3.1: Existing capacitor banks in CEB system
Grid Substation
Capacitor Size
(Mvar)
Kotugoda 30
Galle 20
Kurunegala 10
Habarana 10
Kiribathkumbura 20
Matugama 20
Puttalam 20
Panadura 20
All those capacitor banks are breaker switched shunt capacitors connected in
ungrounded double star connection. In the present system, the typical step size of
each bank is 5Mvar. This may slightly changes with the presence of the reactor.
CEB's general concept in fixing the capacitor banks is such that it uses symmetrical
banks for each bus section in the 33kV bus bar. All the capacitor banks in CEB
network are connected to the 33kV load bus in the relevant grid substation and there
are no capacitor banks at the transmission level. The reason for this is due to lower
costs at low voltage levels than at higher voltage levels.
12
Generally, the banks are equipped with the inrush limiting reactors as well as
detuning reactors in most cases. However there are banks without those reactors as
well. The banks with detuning reactor are called as the filter banks because they are
meant for eliminating the switching inrush, reduce resonance effects and to filter 5th
harmonics in the system loads. The other banks are sometimes having inrush limiting
reactors and sometimes there are no such reactors.
3.2 Dispatch Scenarios in the CEB System
The daily electricity demand pattern of a country depends on its per capita income,
level of industrialization, climate condition, etc. A typical load profile of Sri Lanka
(load curve of 01.03.2012) is shown in Figure 3.1.
Figure 3.1: Typical load profile of Sri Lanka
The load profile of Sri Lankan power system has distinctly identifiable demand
levels during different periods of the day. Those are;
1. Day peak
2. Night peak
3. Off peak
13
Both hydro power and thermal power carry considerable portions of Sri Lanka’s
electricity generation. Therefore when the water level in the reservoirs is low,
System Control Center dispatches more thermal generators and minimizes hydro
generation. This is called Thermal Maximum dispatch. When the water level in the
reservoirs is high due to rain, System Control Center dispatches more hydro
generators and minimizes thermal generation. This is called Hydro Maximum
dispatch. The pattern of dispatching generators in the remaining periods of the year is
called Typical Dispatch.
Voltage levels and power flows of the network depend on the demand level of the
loads and the locations and the power injections of the generators connected to the
system. Therefore nine scenarios have to be considered regarding load demand and
generator dispatch. They are:
1. Hydro Maximum- Day peak
2. Hydro Maximum- Night peak
3. Hydro Maximum- Off peak
4. Thermal Maximum- Day peak
5. Thermal Maximum- Night peak
6. Thermal Maximum- Off peak
7. Typical Dispatch- Day peak
8. Typical Dispatch - Night peak
9. Typical Dispatch - Off peak
Table 3.2 shows the allowable voltage deviations as per CEB voltage criteria.
Table 3.2: Permissible voltage deviations as per CEB voltage criteria
Nominal Voltage Allowable Variation
33kV +/-5%
132kV +/-10%
220kV +/-5%
14
There is some contribution from the leading reactive power of transmission line
capacitances for lagging var compensation of the inductive loads. Further when we
look at the typical capability curve of a generator, it is clear that some amount of
reactive power also is generated during the most economical operation of a
synchronous generator (around 0.85 power factor) [5].
Figure 3.2: Capability curve of a hydrogen cooled generator
15
Chapter 4
SYSTEM MODELLING, SIMULATION AND DATA ANALYSIS
Whole CEB power system is modeled in Power System Simulator for Engineering
(PSS®E) software. Automatic Voltage Regulators (AVR) of generators and
transformers are set to auto mode during the simulations.
For identifying the under voltage conditions, branches with excessive reactive power
flows, calculating the present network losses and amount of reactive power
generation, load flow simulations of the present transmission network were run for
the all nine scenarios (Refer Appendix 1 to Appendix 9). Under voltage conditions at
Galle and Ampara grid substations are shown in Figure 4.1 and Figure 4.2
For selecting capacitors for only under voltage mitigation as per the current CEB
practice, grid substations with under voltage levels were identified. Capacitors were
added for those locations until voltage improves up to the permissible range. Then
the network losses and amount of reactive power generation were calculated after
adding those capacitors to the system.
Figure 4.1: Under voltage condition at Galle grid substation
16
Figure 4.2 Under voltage condition at Ampara grid substation
For selecting capacitors for both under voltage mitigation and network loss reduction
as the new proposal, it was investigated whether 100% reactive load compensation
can be done at the grid substations without creating overvoltage conditions.
Capacitors were added to grid substations to the nearest 5Mvar step of the reactive
load of each day peak, night peak and off peak load. Simulations were run to see
whether there are any under voltage or over voltage conditions. No under voltage
conditions were observed and over voltages were observed in some grid substations
during off peak. The amount of capacitors were reduced from those grid substations
until those voltages were reduced to permissible limit.
After adding the selected capacitors to the relevant grid substations, network losses
and amount of reactive power generation were calculated by running load flow
simulations for the nine scenarios.
4.1 Selecting Capacitor Banks
4.1.1 Under voltage mitigation only
Table 4.1: Grid substations having under voltage condition
Grid
Substation
Busbar Volage (kV)
Hydro Maximum Thermal Maximum Typical Dispatch
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Galle OK 117.7 OK OK 117.6 OK OK 117.6 OK
Ampara OK 115.3 OK 117.2 114.9 OK 118.7 115 OK
17
To prevent this under voltage condition, capacitors were selected as shown in Table
4.3.
Table 4.2: Capacitor requirement for under voltage condition
Grid
Substation
Capacitor Requirement (Mvar)
Hydro Maximum Thermal Maximum Typical Dispatch
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Ampara 0 20 0 10 20 0 10 20 0
Galle 0 20 0 0 30 0 0 20 0
Table 4.4: Voltage improvement after adding capacitor banks
Grid
Substation
Busbar Volage (kV)
Hydro Maximum Thermal Maximum Typical Dispatch
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Galle 126.7 122.3 127.2 125.6 121.5 125.7 126.3 121.5 121.9
Ampara 126.9 124.5 128.8 122.2 124 128.4 123.7 124.3 127.3
4.1.2 Both under voltage mitigation and loss reduction
Capacitors were added to grid substations to the nearest 5Mvar step of the reactive
load of each day peak, night peak and off peak load. Over voltages were observed in
some grid substations during off peak. Simulation diagram of capacitor addition
during off peak are shown in Appendix 10. Capacitor bank values for reactive load
compensation during day peak is shown in Table 4.5. Capacitor bank values for
reactive load compensation during night peak are shown in Table 4.6. Capacitor bank
values for reactive load compensation during off peak are shown in Table 4.7.
18
Table 4.5: Capacitor bank values for reactive load compensation during day peak
Grid Substation
Reactive
Demand
(Mvar)
Capacitor
Bank
(Mvar) Grid Substation
Reactive
Demand
(Mvar)
Capacitor
Bank
(Mvar)
Wimalasurendra 4 5 Kurunegala 18 20
Ampara 12 10 Habarana 19.8 20
Inginiyagala 0 0 Anuradhapura 4.87 5
Ukuwela 11 10 New Anuradhapura 2.4 0
Vavuniya 4.1 5 Trincomalee 7.71 10
Rantambe 1.8 0 Ratnapura 8 10
Kelanithissa 18 20 Kiribathkumbura 26 25
Beliatta 1.8 0 Valachchenai 11.2 10
Hambanthota 5.2 5 Ratmalana 36 35
Horana 18 20 Matugama 19.8 20
Katunayake 22.8 25 Puttalam 2 0
Kosgama 24 25 Athurugiriya 20.62 20
Seethawaka 12 10 Veyangoda 22.13 20
Nuwaraeliya 14.5 15 Jayawardenapura 15.4 15
Thulhiriya 18.3 20 Panadura 30 30
Oruwala 0 0 Madampa 16.8 15
Kolonnawa 41.03 40 Kelaniya 10.2 10
Pannipitiya 22 20 Ambalangoda 10.4 10
Biyagama 38 40 Dehiwala 20.4 20
Kotugoda 35.8 35 Pannala 16.4 15
Sapugaskanda 23.8 25 Aniyakanda 18 20
Bolawatta 29.73 30 Maradana 16.1 15
Badulla 10 10 Havelock Town 19.2 20
Balangoda 5.4 5 Colombo E 29.1 30
Deniyaya 5.22 5 Colombo F 25.2 25
Galle 20.94 20 Puttalam Coal 20 20
Embilipitiya 8 10 Substation C 7.2 5
Matara 16 15
19
Table 4.6: Capacitor bank values for reactive load compensation during night peak
Grid Substation
Reactive
Demand
(Mvar)
Capacitor
Bank
(Mvar) Grid Substation
Reactive
Demand
(Mvar)
Capacitor
Bank
(Mvar)
Wimalasurendra 2 0 Kurunegala 11 10
Ampara 9 10 Habarana 15.4 15
Inginiyagala 0 0 Anuradhapura 7.97 10
Ukuwela 11.78 10
New
Anuradhapura 3.6 5
Vavuniya 2.5 5 Trincomalee 9.1 10
Rantambe 1.16 0 Ratnapura 6 5
Kelanithissa 7.51 10 Kiribathkumbura 15 15
Beliatta 1.8 0 Valachchenai 0 0
Hambanthota 4.4 5 Ratmalana 18.6 20
Horana 7.31 5 Matugama 15 15
Katunayake 13.2 15 Puttalam 15 15
Kosgama 20 20 Athurugiriya 11.72 10
Seethawaka 8 10 Veyangoda 23.34 25
Nuwaraeliya 17.31 15 Jayawardenapura 9.3 10
Thulhiriya 16.27 15 Panadura 22 20
Oruwala 0 0 Madampa 17 15
Kolonnawa 17.61 20 Kelaniya 8.05 10
Pannipitiya 20 20 Ambalangoda 10.8 10
Biyagama 30 30 Dehiwala 17.2 15
Kotugoda 27.2 30 Pannala 10 10
Sapugaskanda 23.86 25 Aniyakanda 16 15
Bolawatta 29.15 30 Maradana 9.4 10
Badulla 2 0 Havelock Town 10.9 10
Balangoda 7.8 10 Colombo E 12.5 15
Deniyaya 5.18 5 Colombo F 12.1 10
Galle 20.65 20 Puttalam Coal 20 20
Embilipitiya 4 5 Substation C 11.2 10
Matara 13 15
20
Table 4.7: Capacitor bank values for reactive load compensation during off peak
Grid
Substation
Reactive
Demand
(Mvar)
Capacitor Banks
(Mvar)
Grid Substation
Reactive
Demand
(Mvar)
Capacitor Banks
(Mvar)
Initial
To
prevent
over
voltages Initial
To
prevent
over
voltages
Wimalasurendra 0.76 0 0 Kurunegala 3.04 5 0
Ampara 4.56 5 5 Habarana 5.02 5 5
Inginiyagala 0.00 0 0 Anuradhapura 1.68 0 0
Ukuwela 3.86 5 0
New
Anuradhapura 1.52 0 0
Vavuniya 0.00 0 0 Trincomalee 3.79 5 0
Rantambe 0.37 0 0 Ratnapura 3.04 5 0
Kelanithissa 4.51 5 5 Kiribathkumbura 4.56 5 5
Beliatta 1.37 0 0 Valachchenai 0.00 0 0
Hambanthota 1.14 0 0 Ratmalana 7.38 5 5
Horana 3.49 5 0 Matugama 6.99 5 5
Katunayake 6.38 5 5 Puttalam 6.08 5 5
Kosgama 7.40 5 5 Athurugiriya 3.24 5 0
Seethawaka 4.56 5 5 Veyangoda 4.88 5 0
Nuwaraeliya 2.31 0 0 Jayawardenapura 4.64 5 0
Thulhiriya 4.27 5 5 Panadura 9.12 10 0
Oruwala 0.00 0 0 Madampa 7.45 5 0
Kolonnawa 7.52 10 5 Kelaniya 3.32 5 0
Pannipitiya 9.12 10 0 Ambalangoda 4.71 5 0
Biyagama 22.80 20 10 Dehiwala 7.40 5 0
Kotugoda 16.42 15 0 Pannala 4.56 5 0
Sapugaskanda 16.29 15 15 Aniyakanda 4.56 5 0
Bolawatta 13.04 15 10 Maradana 3.88 5 0
Badulla 3.80 5 0 Havelock Town 3.34 5 0
Balangoda 2.28 0 0 Colombo E 4.56 5 0
Deniyaya 1.47 0 0 Colombo F 4.48 5 0
Galle 21.89 20 5 Puttalam Coal 4.48 5 0
Embilipitiya 0.00 0 0 Substation C 2.40 0 0
Matara 6.08 5 5
21
4.2 Reduction of Mvar Generation at Power Stations
4.2.1 Under voltage mitigation only
Table 4.8: Reduction of Mvar generation by adding capacitors for under voltage mitigation
Scenario
Hydro Maximum Thermal Maximum Typical Dispatch
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Q generated w/o
capacitors
(Mvar)
788.6 631.4 41.7 827.7 644.2 79.7 804.6 625.5 31.3
Q generated
with capacitors
(Mvar)
749.2 599.0 41.7 823.3 603.5 79.7 789.7 595.6 31.3
Reduction in
Mvar Generation 39.4 32.4 0.0 4.4 40.7 0.0 14.8 29.9 0.0
Maximum
Reduction in
Mvar Generation 40.7
4.2.2 Both under voltage mitigation and loss reduction
Table 4.9: Reduction of Mvar generation by adding capacitors according to new method
Scenario
Hydro Maximum Thermal Maximum Typical Dispatch
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Q generated
w/o capacitors
(Mvar) 788.6 631.4 41.7 827.7 644.2 79.7 804.6 644.2 31.3
Q generated
with capacitors
(Mvar) 21.8 75.1 2.3 31.6 83.7 5.8 26.4 79.2 4.1
Reduction in
Mvar
Generation 766.8 556.3 44.0 796.1 560.5 73.9 778.2 565.0 27.2
Maximum
Reduction in
Mvar
Generation 796.1
22
4.3 Reduction of I2R Loss in the Network
4.3.1 Under voltage mitigation only
Table 4.10: Loss reduction by adding capacitors for under voltage mitigation
Scenario
Hydro Maximum Thermal Maximum Typical Dispatch
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
I2R Loss
without
Capacitors
(MW)
29.2 46.0 9.2 29.4 46.9 11.9 29.4 43.7 10.0
I2R Loss with
Capacitors
(MW)
28.7 45.1 9.2 28.8 46.0 11.9 28.8 42.9 10.0
Reduction in
I2R Loss (MW)
0.5 0.9 0.0 0.6 0.9 0.0 0.6 0.8 0.0
Period
(hours/day) 12 3 9 12 3 9 12 3 9
Energy Saved
per Day (kWh) 8,341.50 10,119.60 9,246.00
Period
(months/year) 1 6 5
Energy Saved
per Year (kWh) 3,458,673.00
4.3.2 Both under voltage mitigation and loss reduction
Table 4.11: Loss reduction by adding capacitors according to new method
Scenario
Hydro Maximum Thermal Maximum Typical Dispatch
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
Day
Peak
Night
Peak
Off
Peak
I2R Loss without
Capacitors (MW) 29.2 46.0 9.2 29.4 46.9 11.9 29.4 46.9 10.0
I2R Loss with
Capacitors (MW) 24.9 43.7 8.7 26.9 45.3 10.6 26.3 44.8 9.8
Reduction in
I2R Loss (MW) 4.3 2.3 0.5 2.5 1.6 1.3 3.1 2.1 0.2
Period
(hours/day) 12 3 9 12 3 9 12 3 9
Energy Saved
per Day (kWh) 62,608.20 46,967.70 45,267.60
Period
(months/year) 1 6 5
Energy Saved
per Year (kWh) 17,122,572.00
23
4.4 Economic Analysis:
It is necessary to investigate the economic benefits of the investment on capacitors
selected above. Reduction in I2R Loss in transmission lines and transformers can be
calculated. At present the average unit cost of generation is approximately Rs.18.50.
Due to the reduction of Mvar generation in the generators of the system, generation
capacity is relieved for active power (MW) generation. According to the Capability
Curve of a typical generator in Figure 3.2, power (MW) generation can be increased
by approximately 0.5 times the reduction of Mvar generation in the generators.
Typical life time of a capacitor bank can be taken as 20 years. Therefore addition of
respectively 20MW Gas Turbine (GT) power plant and 400MW coal plant can be
postponed by 20 years for each case as summarized below.
Typical cost is USD700/kW for a 20MW GT power plant and USD150/kW for a
400MW coal power plant. Typical cost of capacitor bank addition is 4Mn Rs/Mvar
including capacitor, switchgear and control equipment. Exchange rate is taken as
Rs.130/USD.
Table 4.12: Cash flow data for economic analysis
Capacitor Bank
Selection Method
UV Mitigation
Only
UV Mitigation and
Loss Reduction
Size of New Cap Banks Installed
(Mvar) 30 225
Cost of New Cap Banks ( Mn Rs.) 120 3260
Reduction in Mvar Generation in
Power Plants 40.75 796.10
Size of Postponed Power Plant
(MW) 20 400
Postponed Investment on Power
Plant (Mn Rs.) 1820 7800
Energy Saved per Year by Loss
Reduction (kWh) 3,458,673 17,122,572
Cost of Energy Saved per Year
(Mn Rs.) 63.9 316.7
24
4.4.1 Under voltage mitigation only
Net Present Value (NPV) of capacitor banks installed according to the above criteria
is calculated in Table 4.13 .
4.4.2 Both under voltage mitigation and loss reduction
Net Present Value (NPV) of capacitor banks installed according to the above criteria
is calculated in Table 4.14.
25
Table 4.13: NPV of capacitor banks installed under voltage mitigation only
Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Cost of New Cap Banks (Mn Rs.)
(-) 120
Postponed Investment on
Generators (Mn
Rs.)
1820
(-)
1820
Cost of Energy
Saved per Year (Mn Rs.)
63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9
Net Cash Flow of
Project (Mn Rs.) 1700 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9 63.9
(-)
1756.1
NPV (Mn Rs.) 1,535.0
26
Table 4.14: NPV of capacitor banks installed according to new method
Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Cost of New Cap
Banks (Mn Rs.) -3260
Postponed
Investment on Generators (Mn
Rs.)
7800 -7800
Cost of Energy Saved per Year
(Mn Rs.)
316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7
Net Flow of
Project (Mn Rs.) 4540 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7 316.7
-
7483.3
NPV (Mn Rs.) 4,524.2
27
Chapter 5
CONCLUSION AND RECOMMENDATIONS
5.1 Conclusion
1. Despite capacitor banks are installed at several grid substations, still there are
grid substations in the CEB system having under voltage situation during
different periods of the day.
2. 100% reactive load compensation at rgrid substations can be done during day
peak and night peak without creating over voltage conditions.
3. 100% reactive load compensation during off peak creates over voltages in
several grid substations.
4. Adding capacitor banks considering both under voltage situation and amount
of reactive power flow can reduce network losses significantly compared to
adding capacitor banks considering only the under voltage situation, and
hence gives more economic benefits compared to the latter.
5. Addition of a power plant can be delayed by the life time of proposed
capacitors.
6. If release the capacity constraint or minimize losses are concerned, then the
capacitors shall be fully utilized to minimize drawing reactive power from
remote generation. Therefore it is required to consider capacitor bank
controllers with multi- parameter or Boolean switching. Reactive power and
voltage shall be the parameters to consider in the switching decisions.
5.2 Recommendations for Future Developments
Adding capacitors at grid substations helps to release capacity and reduce losses of
the transmission network but does not release capacity or reduce losses of the
distribution feeders. If capacitors are added with optimal sizes at optimal locations
for individual feeders of each grid substation, network losses can be further reduced.
28
Reference List
[ 1] Dhillon M.S. , Tziouvaras D. A. , Protection of fuseless capacitor banks using
digital relays
[2] Gupta J.B. (2004), Switchgear and Protection (2nd
edition), S.K. Kataria & Sons
Publishers and Distributors, Chapter 16 pp 510
[ 3] Web site: http://www.aet.com.sg/technical_notes/technical_notes.html
[4] Arulampalam A. , Barnes M. , Englers A. , Goodwin A. , Jenkins N. , Control of
power electronic interfaces in distributed generation Microgrids
[5] Prabha Kundur : “Power System Stability and control” , The EPRI
Power System Engineering Series, McGraw-Hill, Inc., 1994.
[7] Maxwell M., “Distribution System”, Electric Utility Engineering Reference
Book, Westinghouse Electric Corporation. (for general reading reference)