Computer Applications in Power Systems

By :
DB&DG

Year 5
Power stream
Section 1 and 2
Acc.year 2021 G.C

July 21 1
 Computer Applications in Power Systems

Course Contents

 SCADA Systems

 On-line and real-time applications of computers for automatic

generation control and voltage control

 Economic dispatch control, Computer aided protection

 Automation: Monitoring, protection and control, Intelligent

Electronic Devices.

July 21 2
 Introduction to SCADA Fundamentals and
Implementation

Supervisory control and data acquisition

July 21 3
Electric power generation, Buildings, facilities and
transmission and distribution: environments: Facility
Electric utilities detect current flow and managers use SCADA to
line voltage, to monitor the operation of control HVAC, refrigeration
circuit breakers, and to take sections of units, lighting and entry
the power grid online or offline. systems.

Manufacturing: manage parts

inventories for just-in-time
manufacturing, regulate industrial
automation and robots, and monitor
process and quality control.

Mass transit: regulate electricity to

subways, trams and trolley buses; to
automate traffic signals for rail
systems; to track and locate trains
and buses; and to control railroad
crossing gates.

Water and sewage: State and

municipal water utilities use
SCADA to monitor and regulate
water flow, reservoir levels, pipe
pressure and other factors.

Traffic signals: regulates

July 21 traffic lights, controls traffic
flow and detects out-of-
SCADA control 4
order signals.
 POWER
DISTRIBUTION
SYSTEM

Remote Telemetry Unit (RTU)

WATER
DISTRIBUTION
SYSTEM

SCADA MASTER UNITS

HUMAN COMPUTER INTERFACE

Remote Telemetry Unit (RTU)

PROCESS
PLANT
July 21 5
TRANSPORT SYSTEM PETROCHEMICAL PLANT
 16 Digital i/o SITE monitoring Pager
Time Sync Notification
2 Analogue inputs
2 control outputs
1 RS232 port 10 RouteT LAN

Remote
Telemetry Sites
Units 1-8
(RTU)

Rs232

SNMP
monitoring
Dial-up remote
Access
Alarms from remote DPS TELECOM SCADA
July 21 equipment SYSTEMS 6
 Supervisory control and data acquisition

• SCADA concept was developed to be universal means of remote

monitoring of control system
• Primary function of SCADA is monitoring
• Supervisory is the process of happening in the field
There are two parts to the term SCADA
1.Supervisory control indicates that the operator, residing in the
energy control center (ECC), has the ability to control remote
equipment.
2. Data acquisition indicates that information is gathered
characterizing the state of the remote equipment and sent to the ECC
for monitoring purposes.

July 21 7
 A SCADA system performs four functions:
1. Data acquisition
2. Networked data communication
3. Data presentation
4. Control

July 21 8
These functions are performed by four kinds of SCADA
components:
 Sensors (either digital or analogue) and control relays that
directly interface with the managed system.
 Remote telemetry units (RTUs). These are small computerized
units deployed in the field at specific sites and locations.
RTUs serve as local collection points for gathering reports from
sensors and delivering commands to control relays.

July 21 9
 Monitoring equipment is normally located in the substations and
is consolidated in what is known as (RTU).
 Generally, the RTUs are equipped with microprocessors having
memory and logic capability.
 Older RTUs are equipped with modems to provide the
communication link back to the ECC, whereas newer RTUs
generally have intranet or internet capability.
 Relays located within the RTU, on command from the ECC, open
or close selected control circuits to perform a supervisory
action.

July 21 10
  SCADA master units. These are larger computer consoles that
serve as the central processor for the SCADA system. Master
units provide a human interface to the system and
automatically regulate the managed system in response to
sensor inputs.
 The communications network that connects the SCADA
master unit to the RTUs in the field.

July 21 11
 Data Acquisition

 To gather data in real time

 To record system event into log file
 Information storage and reports

SCADA system needs to monitor hundreds or thousands of

sensors.

July 21 12
 Data Acquisition

Sensors measure:
1. Inputs and outputs e.g. water flowing into a reservoir (input),
valve pressure as water is released from the reservoir (output).
2. Discrete inputs (or digital input) e.g. whether equipment is on
or off, or tripwire alarms, like a power failure at a critical facility.
3. Analogue inputs: where exact measurement is important e.g. to
detect continuous changes in a voltage or current input, to
track fluid levels in tanks, voltage levels in batteries, temperature
and other factors that can be measured in a continuous range
of input.

July 21 13
 For most analogue factors, there is a normal range defined
by a bottom and top level e.g. temperature in a server room
between 15 and 25 degrees Centigrade. If the temperature
goes outside this range, it will trigger a threshold alarm.
 In more advanced systems, there are four threshold alarms
for analogue sensors, defining Major Under, Minor Under,
Minor Over and Major Over alarms.

July 21 14
Data Communication

A communications network is required to monitor multiple

systems from a central location.
 TREND: put SCADA data on Ethernet and IP over SONET.
 SECURITY: Keep data on closed LAN/WANs without
exposing sensitive data to the open Internet.
 Encode data in protocol format (use open, standard protocols
and protocol mediation)

July 21 15
 Sensors and control relays can’t generate or interpret protocol
communication - a remote telemetry unit (RTU) is needed to
provide an interface between the sensors and the SCADA
network.
 RTU encodes sensor inputs into protocol format and forwards
them to the SCADA master;
 RTU receives control commands in protocol format from the
master and transmits electrical signals to the appropriate
control relays.

July 21 16
Data Presentation

SCADA systems report to human operators over a master

station, HMI (Human-Machine Interface) or HCI (Human-
Computer Interface).
SCADA master station has several different functions:
 continuously monitors all sensors and alerts the operator
when there is an “alarm”
 presents a comprehensive view of the entire managed system,
 presents more detail in response to user requests
 performs data processing on information gathered from
sensors
 maintains report logs and summarizes historical trends.

July 21 17
Selection of RTU’s

RTUs need to:

 communicate with all on-site equipment
 survive an industrial environment. Rugged construction and
ability to withstand extremes of temperature and
humidity (it needs to be the most reliable element in your
facility).
 have sufficient capacity to support the equipment at a site
(though should support expected growth over a reasonable
period of time).
 have a secure, redundant power supply for 24/7 working,
support battery power and, ideally, two power inputs.

July 21 18
 have redundant communication ports e.g. secondary
serial port or internal modem to keep the RTU online even if
the LAN fails (multiple communication ports easily support a
LAN migration strategy)
 have non-volatile memory (NVRAM) for storing
software and/or firmware. New firmware downloadable over
LAN to keep RTU capabilities up to date without excessive
site visits
 control local systems by themselves (Intelligent control)
according to programmed responses to sensor inputs
 have a real-time clock to accurately date/time stamp
reports
 have a watchdog timer to ensure that the RTU restarts
after a power failure.
July 21 19
Selection of SCADA Master

 A SCADA master should display information in the most useful

ways to human operators and intelligently regulate managed
systems. It should :
 have flexible, programmable soft controls to respond to
sensor inputs
 allow programming for soft alarms (reports of complex events
that track combinations of sensor inputs and date/time
statements).
 automatically page or email directly to repair technicians and
provide detailed information display in plain English, with a
complete description of what activity is happening and how to
manage it.

July 21 20
 have tools to filter out nuisance alarms (to prevents
operators from loosing confidence and stop responding even
to critical alarms)
 support multiple backup masters, in separate locations
(primary SCADA master fails, a second master on the
network automatically takes over, with no interruption of
monitoring and control functions)
 support multiple open protocols to safeguard the SCADA
system against unplanned obsolescence.
July 21 21
 CHAPTER 2:
On-line and real-time applications of computers for
(AGC) and voltage control

 AGC major objectives

 Tie-Line Control
 Two areas systems
 area control error (ACE)
 Tie-line bias supplementary control for two areas
 Automatic Generation Control (AGC) Implementation
 AGC Features

July 21 22
 AUTOMATIC GENERATION CONTROL

Automatic generation control (ÁGC) is the name given to a

control system having three major objectives:
1. To hold system frequency at or very close to a
specified nominal value (e.g.,50 Hz).
2. To maintain the correct value of interchange
power between control areas.
3. To maintain each generation at the most economic value.

July 21 23
 AUTOMATIC GENERATION CONTROL system

• The Generation Control system contains real-time processes

that regulate the generation of power in accordance with
operational and economic constraints
• The Automatic Generation Control (AGC) regulates the output
of electric generating units in order to maintain the power
system frequency and/or control area net interchange to their
scheduled values.
• AGC can also regulate the power output of electric generating
units to ensure compliance with the current system production
schedule.

July 21 24
 Cont’d

Maintains system frequency and control area net interchange at

their scheduled values.
Divided into the following sections:
• Automatic Generation Control (AGC)
• Economic Dispatch (ED)

July 21 25
 Economic Dispatch (ED)

Economic Operation of Power Systems

 One of the earliest applications of on-line centralized control was
to provide a central facility, to operate economically, several
generating plants supplying the loads of the system
 Modern integrated systems have different types of generating
plants, such as coal fired thermal plants, hydel plants, nuclear
plants, oil and natural gas units etc.
 The capital investment, operation and maintenance costs are
different for different types of plants.

July 21 26
 The operation economics can again be subdivided into two parts

1. Problem of economic dispatch, which deals with determining

the power output of each plant to meet the specified load,
such that the overall fuel cost is minimized.
2. Problem of optimal power flow, which deals with minimum –
loss delivery, where in the power flow, is optimized to
minimize losses in the system. In this chapter we consider
the problem of economic dispatch.

July 21 27
 Economic Dispatch (ED)

Economic Operation of Power Systems

One of the earliest applications of on-line centralized control was to provide a
central facility, to operate economically, several generating plants supplying the
loads of the system
• The Economic Dispatch (ED) function calculates the optimum
basepoints for in-service economically dispatch able generating
units
• The economically dispatch able generating units are controlled
generating units that can be modeled as thermal units or hydro
units.

July 21 28
 Supplementary control

July 21 29
 Cont’d

 we may start out assuming that we are studying a single

generating unit supplying load to an isolated power system.
 A load change will produce a frequency change with a
magnitude that depends on the droop characteristics of the
governor and the frequency characteristics of the system
load.

July 21 30
 Cont’d

 Once a load change has occurred, a supplementary control must

act to restore the frequency to nominal value.
 This can be accomplished by adding a reset (integral) control to
the governor, as shown in the above Figure.
 The reset control action of the supplementary controller will
force the frequency error to zero by adjustment of the speed
reference set point.
 For example, the error shown in the bottom diagram would be
forced to zero.

July 21 31
 Cont’d

July 21 32
 Complete block diagram representation of LFC of
an isolated power system:

• A Complete block diagram representation of an isolated

power system can be obtained by combining individual blocks
of speed governor, turbine, generator & load

July 21 33
 Tie-Line Control
When two utilities interconnect their systems, they do so for
several reasons.
 One is to be able to buy and sell power with neighboring
systems whose operating costs make such transactions
profitable.
 even if no power is being transmitted over ties to
neighboring systems, if one system has a sudden loss of a
generating unit, the units throughout all the interconnection
will experience a frequency change and can help in restoring
frequency.
 Interconnections present a very interesting control problem
with respect to allocation of generation to meet load.
July 21 34
 Two areas systems

July 21 35
 Cont’d

The hypothetical situation in Figure above will be used to illustrate

this problem.
Assume both systems in Figure have equal generation and load
characteristics (R1 = R2, D1 = D2) and, further, assume system 1
was sending 100 MW to system 2 under an interchange agreement
made between the operators of each system.
Now, let system 2 experience a sudden load increase of 30 MW.
Since both units have equal generation characteristics, they will both
experience a 15 MW increase, and the tie line will experience an
increase in flow from 100 MW to 115 MW

July 21 36
 Cont’d

 The 30 MW load increase in system 2 will have been satisfied by a

15 MW increase in generation in system 2, plus a 15 MW increase
in tie flow into system 2.
 This would be fine, except that system 1 contracted to sell only
100 MW, not 115 MW, and its generating costs have just gone up
without anyone to bill the
extra cost to, What is needed at this point is a control scheme
that recognizes the fact that the 30 MW load increase occurred in
system 2 and, therefore, would increase generation in system 2 by
30 MW while restoring frequency to nominal value. It would also
restore generation in system I to its output before the load
increase occurred.
July 21 37
 Cont’d

 Such a control system must use two pieces of information: the

system frequency and the net power flowing in or out over the
tie lines.
 Such a control scheme would, of necessity, have to recognize
the following.
1. If frequency decreased and net interchange power leaving
the system increased, a load increase has occurred outside the
system.
2. If frequency decreased and net interchange power leaving
the system decreased, a load increase has occurred inside the
system.

July 21 38
 Cont’d

This can be extended to cases where frequency increases

We will make the following definition
P net, int =total actual net interchange (+power leaving the
system - power entering )
P net, int schedule=scheduled or desired value

Pnet int = Pnet int- Pnet int scheduled

July 21 39
 Cont’d

July 21 40
 Cont’d

July 21 41
 Cont’d

 The required change in generation, historically called the

area control error or ACE, represents the shift in the
area & generation required to restore frequency and net
interchange to their desired values. The equations for ACE
for each area are

July 21 42
 Cont’d

July 21 43
 Cont’d

 Tie-line bias supplementary control for two areas, This

control can be carried out using the scheme outlined.
 Note: that the values of B1 and B2 would have to change each
time a unit was committed or decommitted, in order to have
the exact values as given above equation.
 Actually, the integral action of the supplementary controller
will guarantee a reset of ACE to zero even when B1 and B2
are in error.

July 21 44
Example
• Two‐area system, below Find change in frequency, ACE, and
appropriate control action.

July 21 45
 Solution
Frequency Calculation

July 21 46
ACE Calculation

July 21 47
Control Action

 ACE indicates each area action to the change of load.

 ACE of area B is zero, this means that nothing should be done

in area B.

 ACE of area A < 0, this means that area A should increase the
setting control power by – (‐10) = 10 MW to cover its own
load.

July 21 48
 Tie-line bias supplementary control for two areas

July 21 49
 Automatic Generation Control (AGC) Implementation

Modern implementation of automatic generation control

(AGC) schemes usually consists of a central location where

information pertaining to the system is telemetered.

Control actions are determined in a digital computer and then

transmitted to the generation units via the same telemetry

channels.

July 21 50
 Cont’d

To implement an AGC system, one would require the following

information at the control center.

1. Unit megawatt output for each committed unit,

2. Megawatt flow over each tie line to neighboring systems.

3. System frequency.

July 21 51
 Good AGC system

1. The ACE signal should ideally be kept from becoming too

large. Since ACE is directly influenced by random load
variations, this criterion can be treated statistically by saying
that the standard deviation of ACE should be small.
2. ACE should not be allowed to “drift.” This means that the
integral of ACE over an appropriate time should be small.
“Drift” in ACE has the effect of creating system time errors or
what are termed inadvertent interchange errors.
3. The amount of control action called for by the AGC should
be kept to a minimum. Many of the errors in ACE, for example,
are simply random load changes that need not cause control
action. Trying to “chase” these random load variations will only
wear out the unit speed-changing hardware.

July 21 52
 AGC Features

This section will serve as a simple catalog of some of the features

that can be found in most AGC systems.
 Assist action: Often the incremental heat rate curves for
generating units will give trouble to an AGC when an excessive
ACE occurs.
 If one unit’s participation factor is dominant, it will take most of
the control action and the other units will remain relatively fixed.

July 21 53
 Cont’d
 Although it is the proper thing to do as far as economics are
concerned, the one unit that is taking all the action will not be
able to change its output fast enough when a large ACE calls for
a large change in generation.
 The assist logic then comes into action by moving more of the
units to correct ACE.
 When the ACE is corrected, the AGC then restores the units
back to economic output.

July 21 54
 Cont’d

 Filtering of ACE: As indicated earlier, much of the change in

ACE may be random noise that need not be “chased” by the
generating units.
 Most AGC programs use elaborate, adaptive nonlinear
filtering schemes to try to filter out random noise from true
ACE deviations that need control action.
 Telemetry failure logic: Logic must be provided to insure
that the AGC will not take wrong action when a telemetered
value it is using fails.
 The usual design is to suspend all AGC action when this
condition happens.
July 21 55
 Cont’d

 Unit control detection: Sometimes a generating unit will not

respond to raised lower pulses. For the sake of overall control,
the AGC ought to take this into account.
 Such logic will detect a unit that is not following raised/lower
pulses and suspend control to it, thereby causing the AGC to
reallocate control action among the other units on control.
 Ramp control: Special logic allows the AGC to ramp a unit
form one output to another at a specified rate of change in
output.
 This is most useful in bringing units on-line and up to full
output.

July 21 56
 Cont’d

 Rate limiting: All AGC designs must account for the fact that
units cannot change their output too rapidly.
 This is especially true of thermal units where mechanical and
thermal stresses are limiting.
 The AGC must limit the rate of change such units will be called
on to undergo during fast load changes.
 Unit control modes: Many units in power systems are not
under full AGC control. Various special control modes must be
provided such as manual. base load, and base load and regulating.
 For example. base load and regulating units are held at their base
load value but are allowed to move as assist action dictates, and
are then restored to base-load value

July 21 57
 CHAPTER 3:
Economic dispatch control, Computer aided
protection

 What is System Protection

 Purpose of System Protection
 Computer aided protection
 Expected benefits of computer relaying
 What Components (Equipment) Do We Protect
 Comparison of Electro-Mechanical to Microprocessor-Based
Protective Relays

July 21 58
 What is System Protection?

System protection is the art and science of detecting problems with

power system components and isolating these components.
 Problems on the power system include:
1.Short circuits
2.Abnormal conditions
3.Equipment failures
The protection system defines as:
Protective relays, associated communication systems, voltage and
current sensing devices, station batteries and DC control
circuitry.

July 21 59
 PROTECTIVE RELAYS

Relay is a device that detects the fault and initiates the operation of the

CB to isolate the defective element from the rest of the system.

July 21 60
 Purpose of System Protection

 Protect the public

 Improve system stability
 Minimize damage to equipment
 Protect against overloads
 Employ relay techs and engineers

July 21 61
 Computer aided protection

 The field of computer relaying started with attempts to

investigate whether power system relaying functions could be
performed with a digital computer.
 The short circuit, load flow, and stability problems – whose
solution was the primary preoccupation of power system
planners – had already been converted to computer programs,
replacing the DC boards and the Network Analyzers.

July 21 62
 Cont’d

 Relaying was thought to be the next promising and exciting field

for computerization.
 It was clear from the outset that digital computers of that period
could not handle the technical needs of high speed relaying
functions.

July 21 63
 Expected benefits of computer relaying

 It would be well to summarize the advantages offered by

computer relays, and some of the features of this technology
which have required new operational considerations.
Among the benefits flowing from computer relays are:
 Cost
 Self-checking and reliability
 System integration and digital environment
 Functional flexibility and adaptive relaying

July 21 64
 What Components (Equipment) Do we Protect?

 Generators
 Transformers
 Reactors(components of electric ckt used to create
reactance)
 Lines
 Buses
 Capacitors

July 21 65
 Differential protection of power equipment
(generator)

• Obviously, the short circuit currents caused by these faults

can cause damage to the generator winding & core.
• Hence, these faults should be cleared by high speed
instantaneous relays.
• Faults between conductors can sometimes be repaired by re-
tapping or replacing the conductor,
• Figure below shows the simplified scheme of differential
protection.

July 21 66
 Cont’d

July 21 67
 Cont’d

 For the generator differential protection, identical CTs & relay

connection should fulfill the basic requirement.
 But ideally identical CTs & equal lead lengths (from CT1 to
relay & CT2 to relay) can not be obtained in practice.
 If the lead lengths are not equal, adjustable extra resistances
can be connected in series with pilot wires so that the relay coil
is connected to the equipotential points (or for non identical
CTs, a biased differential relay can be used).

July 21 68
 Cont’d

 Another way to solve the problem of non-identical CTs &

unequal lead lengths is by the use of stabilizing resistance in
series with the relay coil.
 The value of the stabilizing resistance can be find out by
considering the worst case i.e. absolute saturation of one of CT
while other is working in its linear range.
 This is the simple way of assessing the criteria of stability
against through faults, since if the relay setting is greater than
the spill current calculated by this method, stability is assured.

July 21 69
 Cont’d
Referring figure below & for the worst condition…..
Lm1, Lm2 – Magnetizing Inductances of CT1 & CT2
RCT – CT secondary resistance
RL – lead resistance
RR – relay resistance
LR – relay inductance
RSTAB – stabilizing resistance.

July 21 70
 Cont’d

 Figure below shows the equivalent circuit of figure above.

 From figure, voltage across the relay VR,
VR = IR (RR + XR) = if (RCT + RL)
Normally LR is small & hence XR << RR

July 21 71
 Cont’d

• The current through relay IR as given in above equation

can be limited by connecting extra stabilizing resistance
Rstab in series with the relay coil. IR will then reduced to
….

• The desired value of stabilizing resistance can be

calculated from the expression….
• where IS = pick up setting of the relay

July 21 72
Example 1

A generator having rated current equal to 1000 A is to be

protected by circulating current differential relay using stabilizing
resistor.
The through fault stability is required up to 10 times full load
current.
Assuming one set of CTs at one end completely saturated. CT
ratio is 1000/1 amp. CT secondary resistance = 0.05 ohm and
total lead burden = 1 ohm (from CT to relay), determine the
required stabilizing resistance.
Relay picks up at 0.1 A and relay has resistive burden of 50 ohm.

July 21 73
 Solution:
Using equation… VR = if (RCT + RL)
= 10x1 (0.05 + 1)
= 10 (1.05) = 10.5 volts

Using equation Rstab = VR/ Is – RR

= ((10.5 / 0.1 )- 50)ohm

(105-50 )ohm
= 55 ohm
Thus…
stabilizing resistance should have a value less than 55 ohm.

July 21 74
Cont’d

July 21 75
 Cont’d

July 21 76
Example 2

July 21 77
 Cont’d

July 21 78
Example 3
• A generator is provided with restricted e/f protection. The ratings are 11
kV, 5000 KVA. The percentage of winding protected against phase to
ground fault is 80%. The relay setting such that it trips for 25% out of
balance. Calculate the resistance to be added in neutral to ground
connection.
Solution:
V = 11 x 103 / √3 = 6340 V

I = KVA / √3 kV = 5000 / √3 x 11 = 262 A

Io = 262 x 25% = 262 x 25 / 100 = 65.5 A

% of winding unprotected = (R x Io / V) x 100
20 = (R x 65.5 / 6340) x 100

July 21 79
 Continued…

hence, resistance to be added in neutral to ground

connection is…….

R = ( 20 x 6340 / 65.5 x 100 ) = 1.94 ohm

Therefore,
R = 1.94 ohm

July 21 80
Example 4

A star-connected, 3-phase, 10 MVA, 6·6 kV alternator is protected by circulating

current protection, the star point being earthed via a resistance r. Estimate the value
of earthing resistor if 85% of the stator winding is protected against earth faults.
Assume an earth fault setting of 20%. Neglect the impedance of the alternator
winding.
Solution. Since 85% winding is to be protected, 15% would be unprotected. Let R
ohms be the earthing resistance required to leave 15% of the winding unprotected.

July 21 81
July 21 82
Transformer Protection

Why transformer protection ???

 To Protect the Transformer from severe damages.
 Time required to rectify the Transformer in case of damages is
more and it is very difficult.
 Operation of a power network when the power transformer is
out of service is always difficult.

July 21 83
 What cause transformer failure?

Winding Bushing
 Insulation deterioration come Bushings deterioration come
from: from:
 Moisture  General aging
 Contamination
 Vibration
 Cracking
 Overheating  Internal moisture
 Voltage surge

July 21 84
Transformer Protection Scheme

Mechanical Electrical
1. Bias Differential Protection
1.Buchholz relay 2. Over Fluxing
2.Sudden pressure 3. Over Voltage
4. Under Voltage
3.Pressure relief 5. Neutral Unbalance
4.Temperature 6. Restricted Earth Fault
protection 7. Back up O/C & E/F

July 21 85
Comparison of Electro-Mechanical to Microprocessor-Based
Protective Relays

Advantages of Electromechanical
 Lower Cost
 Easier to Test
Disadvantages of Electromechanical
 Need three individual relays
 Maintain more often
 Moving Parts
 Usually performs only one protective function
 Slower operating than Micro-Processor Based

July 21 86
 Advantages of Micro-Processor Based

Performs hundreds of protective functions

 Only one relay needed for all phases
 Faster operating than Electromechanical
 Self-Monitoring
 Takes up less space
 Longer maintenance cycle(?adv or disad)
Disadvantages Micro-Processor Based
 Higher Cost
 Complex training for testing

July 21 87
 Cont’d

End of chapter 3
July 21 88
 CHAPTER 4:
Automation: Monitoring, protection and control, Intelligent
Electronic Devices (IEDs)

 FACTS devices
 Power Flow Control on AC Systems
2

 FACTS Applications and Implementations

 FACTS Devices connection
0

 FACTS Technology - Possible Benefits 2

10 5 0 5 10

 FACTS + Energy Storage

 Enhanced Power Transfer and Stability
 Power Quality Issues
 Intelligent electronic device

July 21 89
 FACTS devices

FACTS devices (FACTS=flexible AC transmission system)

 FACTS are designed to remove constraints and to meet planners´,
investors´ and operators´ goals without their having to undertake
major system additions.
 This offers ways of attaining an increase of power transmission
capacity at optimum conditions, i.e. at maximum availability,
minimum transmission losses, and minimum environmental impact.
Plus, of course, at minimum investment cost and time expenditure.

July 21 90
 Cont’d

 The term ”FACTS” covers several power electronics based

systems used for AC power transmission.
 Given the nature of power electronics equipment, FACTS
solutions will be particularly justifiable in applications requiring one
or more of the following qualities:
 Rapid dynamic response
 Ability for frequent variations in output
 Smoothly adjustable output.

July 21 91
 Cont’d

 Important applications in power transmission involving FACTS

and Power Quality devices:
 SVC (Static Var Compensators)
 Thyristor-Controlled Series Capacitors (TCSC) and Statcom.
 PST (Phase-shifting Transformers)
 IPC (Interphase Power Controllers)
 UPFC (Universal Power Flow Controllers), and
 DVR (Dynamic Voltage Restorers).

July 21 92
 Power Flow Control on AC Systems

Radial
Parallel

Meshed

July 21 93
 Cont’d

July 21 94
 FACTS Applications and Implementations

Transmission Transfer Capacity Enhancement

Steady State Dynamic
Issues Traditional Solutions Issues
Voltage Limits Breaking Advanced Solutions Transient Stability
Thermal Limits Resistors Load Damping Power Swings
Angular Stability Limits FACTS
Loop Flows
Shedding Post-Contingency
Voltage Control
Fixed Energy Voltage Stability
Compensation Storage Subsynchronous Res.

Line Enhanced
Transmission Power Transfer
Reconfiguration
Link and Stability
Better
Protection SVC
FACTS STATCOM
Increased TCSC, SSSC
Devices UPFC
Inertia

July 21 95
 FACTS Devices Connection

Shunt Connected
Static VAR Compensator (SVC)
Static Synchronous Compensator (STATCOM)
Static Synchronous Generator - SSG
Battery Energy Storage System (BESS)
Superconducting Magnetic Energy Storage (SMES)

Combined Series and Series-Shunt Connected

Static Synchronous Series Controllers (SSSC)
Thyristor Controlled Phase-Shifting Transformer or
Phase Angle Regulator (PAR)
Interline Power Flow Controller (IPFC)
Thyristor Controlled Series Capacitor (TCSC)
Unified Power Flow Controller (UPFC)

July 21 96
 FACTS Technology - Possible Benefits

 Control of power flow as ordered.

 Increase the loading capability of lines to their thermal capabilities,
Increase the system security through raising the transient stability
limit, limiting short-circuit currents and overloads,
 Provide secure tie lines connections to neighboring utilities and
regions thereby decreasing overall generation reserve
requirements on both sides.
 Provide greater flexibility in siting new generation.
 Reduce reactive power flows, thus allowing the lines to carry
more active power.
 Reduce loop flows.
 Increase utilization of lowest cost generation.
July 21 97
Enhanced Power Transfer and Stability: Technologies’ Perspective

Compensation FACTS Devices

Devices Energy Storage

Fast
SMES Real Power Injection
and Absorption
P
TSSC
P TSSC
P
SSSC Additional
UPFC SSSC
UPFC
Stability
Margin
Electric Grid Electric Grid
2

Q STATCOM Q STATCOM
1.5
Acceleration
Area
Deceleration
Area

Power Transfer
1 Stability
Margin
Fast Fast 0.5

Reactive Power Injection Reactive Power Injection and

and Absorption Absorption 0
0 0.5 1 1.5
Phase Angle
2 2.5 3

July 21 98
 Q
FACTS + Energy Storage
The Role of Energy Storage: real
power compensation can
increase operating control and STATCOM
reduce capital costs Reactive Power Only
Operates in the
vertical axis only
MVA Reduction P P - Active Power
Q - Reactive Power

The Combination or Real

and Reactive Power will
typically reduce the Rating
of the Power Electronics
front end interface.
Real Power takes care of STATCOM + SMES
power oscillation, whereas Real and Reactive Power
reactive power controls Operates anywhere within the
voltage. PQ Plane / Circle (4-Quadrant)

July 21 99
 Enhanced Power Transfer and Stability:
Location and Configuration Type Sensitivity

No Compensation
60
.8

59
.2

time (sec)

2 STATCOMs 1 STATCOM + SMES

60 60
.8 .8

59 59
.2 .2

time (sec)
time (sec)
Voltage and Stability Control Enhanced Voltage and Stability Control
(2 x 80 MVA Inverters) ( 80 MVA Inverter + 100Mjs SMES)

July 21 100
 Power Quality Issues

The Need For An Integrated Perspective of PQ

 Harmonics
 Imbalance
 Voltage Fluctuations
 Voltage Sags
 Standards, Limits, Diagnostics, and Recommendations
Flexibility, Compatibility, Probabilistic Nature, Alternative
Indices
 Combined effects

July 21 101
 Intelligent electronic device

An Intelligent Electronic Device (IED) is a term used in the

electric power industry to describe microprocessor-based
controllers of power system equipment, such as circuit
breakers, transformers and capacitor banks
IEDs receive data from sensors and power equipment and can
issue control commands, such as tripping circuit breakers if they
sense voltage, current, or frequency anomalies, or raise/lower
voltage levels in order to maintain the desired level.
Common types of IEDs include protective relaying devices, On
Load Tap Changer controllers, circuit breaker controllers,
capacitor bank switches, recloser controllers, voltage regulators
etc
July 21 102
 Cont’d

 Digital protective relays are primarily IEDs, using a

microprocessor to perform several protective, control and
similar functions.
 A typical IED can contain around 5-12 protection functions, 5-8
control functions controlling separate devices, an auto reclose
function, self monitoring function, communication functions etc.
Hence, they are aptly named as Intelligent Electronic Devices.
 Some recent IEDs are designed to support
the IEC61850 standard for substation automation, which
provides interoperability and advanced communications
capabilities.

July 21 103
 Cont’d

Protective relay is an example of an Intelligent Electronic

Device

July 21 104
 Exercise 1

A generator having rated current equal to 100A is to be protected by

circulating current differential relay using stabilizing resistor.
The through fault stability is required up to 5 times full load current.
Assuming one set of CTs at one end completely saturated. CT ratio is 100/1
amp. CT secondary resistance = 0.025 ohm and total lead burden = 1 ohm
(from CT to relay), determine the required stabilizing resistance.
Relay picks up at 0.2 A and relay has resistive burden of 25 ohm.

Exercise 2 A generator is protected by restricted earth fault protection. The

generator ratings are 3.2 KV, 2 MVA. The percentage of winding protected
against phase to ground fault is 85%. The relay setting is such that it trips for 20%
out of balance. Calculate the resistance to be added in the neutral to ground
connection. Show each step in detail

July 21 105
Exercise 3

A generator is provided with restricted e/f protection. The ratings are 11 kV,
5000 KVA. The percentage of winding protected against phase to ground fault is
80%. The relay setting such that it trips for 25% out of balance. Calculate the
resistance to be added in neutral to ground connection.

July 21 106