Smart grid technologies after midsem slides

SMART GRID
TECHNOLOGIES
DR. SIVKUMAR MISHRA
DEPARTMENT OF ELECTRICAL ENGINEERING

Course Objective:
• Develop a conceptual basis for Smart Grid
• Equip the Students with a thorough understanding of various
communication technologies and management issues with
smart grid.
Learning outcome:
• A clear understanding of smart grid technologies to enable
students to pursue research in that area.
Syllabus -Smart Grid Technologies

Module -1
• Introduction to Smart Grid: Evolution of Electric Grid, Concept of Smart Grid, Definitions, Need of
Smart Grid, Functions of Smart Grid, Opportunities & Barriers of Smart Grid, Difference between
conventional & smart grid, Concept of Resilient & Self-Healing Grid, Present development &
International policies in Smart Grid. Case study of Smart Grid .(7)
Module -2
• Information and Communication Technology for Smart Grid: Data communication, Communication
Technologies for the Smart Grid, Information Security for the Smart Grid (12)
Module -3
• Sensing, measurement, control and automation: Smart Metering and Demand-Side Integration,
Distribution Automation Equipment, Distribution Management Systems, Transmission System
Operation (12)
Module -4
• Power electronics and energy storage: Power Electronic Converters, Power Electronics in the Smart
Grid, Power Electronics for Bulk Power Flows, Energy storage (9)
Text Book:
JanakaEkanayake, Nick Jenkins, Kithsiri Liyanage, Jianzhong Wu, Akihiko Yokoyama,“ Smart Grid: Technology
and Applications”, Wiley
Reference Book:
Communication and Networking in Smart Grids, Editor: Yang Xiao, CRC Press
Syllabus -Smart Grid Technologies

SMART METERING AND
DEMAND-SIDE
INTEGRATION

In many countries, the power infrastructure is ageing and is being
increasingly heavily used as demand for electricity rises.
This overloading will worsen as large numbers of electric vehicles, heat
pumps and other new loads use low-carbon energy from the electric
power system.
Obtaining planning permission for the installation of new power
system equipment, particularly overhead lines, is becoming
increasingly difficult.
Demand-side programmes have been introduced widely to make
better use of the existing power supply infrastructure and to control
the growth of demand.

The dual aims of reducing CO2 emissions and improving energy
security (energy policy goals in many countries) coincide in the
increasing use of renewable energy for electricity generation.
However, connection of a large amount of intermittent renewable
generation alters the pattern of the output of central generation and
the power flows in both transmission and distribution circuits.
One solution to this increase in variability is to add large-scale energy
storage devices to the power system. This is often not practical at
present due to technical limitations and cost. Therefore, flexibility in
the demand side is seen as another way to enable the integration of a
large amount of renewable energy.

Load control or load management has been widespread in power
system operation for a long time with a variety of terminology used
to describe it.
The name Demand-Side Management (DSM) has been used since the
1970s for a systematic way of managing loads .
Later on, Demand Response (DR), Demand-Side Response (DSR),
Demand-Side Bidding (DSB) and Demand Bidding (DB) were used to
describe a range of different demand side initiatives
To avoid the confusion caused by such overlapping concepts and
terminologies, as recommended by CIGRE, Demand-Side Integration
(DSI) is used to refer to all aspects of the relationships between the
electric power system, the energy supply and the end-user load.

Effective implementation of DSI needs an advanced ICT (Information
and Communication Technology) infrastructure and good knowledge
of system loads. However, the electro-mechanical meters that are
presently installed in domestic premises have little or no
communication ability and do not transmit information of the load in
real time.
Smart metering refers to systems that measure, collect, analyze, and
manage energy use using advanced ICT.
The concept includes two-way communication networks between
smart meters and various actors in the energy supply system. The
smart meter is seen to facilitate DSI through providing real-time or
near-real-time information exchange and advanced control
capabilities.

Smart metering
• Electricity meters are used to measure the quantity of electricity supplied
to customers as well as to calculate energy and transportation charges for
electricity retailers and network operators.
• The most common type of meter is an accumulation meter, which records
energy consumption over time.
• Accumulation meters in consumer premises are read manually to assess
how much energy has been used within a billing period.
• In recent years, industrial and commercial consumers with large loads
have increasingly been using more advanced meters, for example, interval
meters which record energy use over short intervals, typically every half
hour. This allows the energy suppliers to design tariffs and charging
structures that reflect wholesale prices and helps the customers
understand and manage their pattern of electricity demand. Smart meters
are even more sophisticated as they have two-way communications and
provide a real-time display of energy use and pricing information,
dynamic tariffs and facilitate the automatic control of electrical
appliances.

Figure shows the evolution of electrical metering, from simple
electro-mechanical accumulation metering to advanced smart
metering.
Smart metering

• It can be seen from Figure that manual reading was widespread
prior to the year 2000.
• A number of Automatic Meter Reading (AMR) programs were
developed around this time where energy consumption information
was transmitted monthly from the meters to the energy supplier
and/or network operator using low-speed one-way communications
networks.

• Since 2000, there has been a dramatic increase in the performance
of the metering infrastructure being installed. One-way
communication of meter energy use data, AMR, has given way to
more advanced two-way communications supporting applications
such as varying tariffs, demand-side bidding and remote
connect/disconnect.
• The Smart Grid vision represents a logical extension of these
capabilities to encompass two-way broadband communications
supporting a wide range of Smart Grid applications including
distribution automation and control as well as power quality
monitoring.

Conventional and smart metering compared

Smart meters have two-way communications to a Gateway and/or a
Home Area Network (HAN) controller. The Gateway allows the transfer
of smart meter data to energy suppliers, Distribution Network
Operators (DNOs) and other emerging energy service companies. They
may receive meter data through a data management company or from
smart meters directly.

The benefits of advanced metering
Energy suppliers
and
network operator
benefits
All benefit Customer benefits
Short-term
Lower metering
costs and more
frequent and
accurate readings
Better
customer
service
Variable pricing
schemes
Energy savings as a
result of improved
information
Limiting
commercial
losses
due to easier
detection of
Facilitating
integration
of DG and
flexible
loads
More frequent and
accurate billing

The benefits of advanced metering
Energy suppliers and
network operator
benefits
All benefit Customer benefits
Longer
term
Reducing peak demand via
DSI programs and so reducing
cost of purchasing wholesale
electricity at peak time
More reliable energy
supply and reduced
customer complaints
Simplification of
payments for DG output
Better planning of generation,
network and maintenance
Using ICT
infrastructure to
remotely control DG,
reward consumers and
lower costs for utility
Additional payments for
wider system benefits
Supporting real-time system
operation down to
distribution levels Capability
to sell other services (e.g.
broadband and video
communications)
Facilitating adoption
of electric vehicles and
heat pumps, while
minimising increase in
peak demand
Facilitating adoption of
home area automation
for more comfortable life
while minimising energy
cost

Smart meters: An overview of the hardware used
• A traditional electro-mechanical meter has a spinning
aluminium disc and a mechanical counter display that
counts the revolutions of the disc.
• The disc is situated in between two coils, one fed with
the voltage and the other fed with the current of the
load. The current coil produces a magnetic field, φI
and the voltage coil produces a magnetic field, φV.
• The forces acting on the disc due to the interaction
between the eddy currents induced by φI and the
magnetic field φV and the eddy currents induced by
φV and the magnetic field φI produce a torque.
• The torque is proportional to the product of
instantaneous current and voltage, thus to the power.
The number of rotations of the disc is recorded on the
mechanical counting device that gives the energy
consumption.

Electronic Energy Meters
• The replacement of electro-mechanical meters
with electronic meters offers several benefits.
• Electronic meters not only can measure
instantaneous power and the amount of energy
consumed over time but also other parameters
such as power factor, reactive power, voltage and
frequency, with high accuracy.
• Data can be measured and stored at specific
intervals.
• Moreover, electronic meters are not sensitive to
external magnets or orientation of the meter itself,
so they are more tamperproof and more reliable.

• Early electronic meters had a display to show energy consumption
but were read manually for billing purposes.
• More recently electronic meters with two-way communications
have been introduced.
• Figure provides a general functional block diagram of a smart meter.
In Figure, the smart meter architecture has been split into five
sections: signal acquisition, signal conditioning, Analogue to Digital
Conversion (ADC), computation and communication.
Functional block diagram of a smart meter

Signal acquisition
• A core function of the smart meter is to acquire system
parameters accurately and continuously for subsequent
computation and communication.
• The fundamental electrical parameters required are the
magnitude and frequency of the voltage and the
magnitude and phase displacement (relative to the
voltage) of current.
• Other parameters such as the power factor, the
active/reactive power, and Total Harmonic Distortion
(THD) are computed using these fundamental quantities.

Signal acquisition
• Current and voltage sensors measure the current into the premises
(load) and the voltage at the point of supply
• In low-cost meters the measuring circuits are connected directly to
the power lines, typically using a current-sensing shunt resistor on
the current input channel and a resistive voltage divider on the
voltage input channel (Figure)

Signal acquisition
• The current sensing shunt is a simple high stability resistor (typically
with resistance between 100μΩ and 500 mΩ) with the voltage drop
across it proportional to the current flowing through it. The current
rating of this shunt resistor is limited by its self-heating so it is
usually used only in residential meters (maximum current less than
100 A).

Signal acquisition
• In order to match the voltage across the current sensing resistor
(which is very small) with the Analogue to Digital Converter (ADC), a
Programmable Gain Amplifier (PGA) is used in the signal
conditioning stage before the ADC (normally integrated within a
single chip with the ADC).
• The voltage resistive divider gives the voltage between the phase
conductor and neutral. The alloy Manganin is suitable for the
resistive divider due to its near constant impedance over typical
operating temperature ranges.

A specification sheet of a smart meter states that its rated current is
100 A and power dissipation is 3 W. It employs a current-sensing
resistor of 200 μΩ. When the load current is at the rated value of
the meter, calculate:
1. the power dissipation in all the other components of the meter;
2. the voltage across the current-sensing resistor;
3. the gain of the PGA to match with an ADC having a full scale of 5V
Answer
1. The power dissipated in the current-sensing resistor is given by:
PR = I2R = (100)2 × 200 × 10−6 = 2 W
Therefore, the power consumed by other components (the
microcontroller, display, and so on) is:
Premain = (3 − 2)W = 1 W
2. Voltage across the current-sensing resistor at full-load current is:
I × R = 100 × 200 × 10−6 = 0.02 V
3. Gain of the PGA = 5/0.02 = 250.

Signal acquisition
• A Current Transformer (CT) can also be used for sensing current and
providing isolation from the primary circuit.
• A CT can handle higher currents than a shunt and also consumes
less power.
• The disadvantages are that the nonlinear phase response of the CT
can cause power or energy measurement errors at low currents and
large power factors, and also the higher meter cost.
• Some applications may require smart meters with high precision
over a wide operating range.
• For such applications more sophisticated voltage and current
measuring techniques such as Rogowski coils, optical methods and
Hall Effect sensors may be used.

• The Hall Effect is a phenomenon in which a magnetic field across a
thin conductive material, with a known current flowing (I), causes
a voltage (V) across the material, proportional to the flux density
(B), as shown in Figure.
• This voltage is measured perpendicular to the direction of current
flow.
• Hall Effect sensors can be used to measure the magnetic field
around a conductor and therefore the current flowing within it.
Simplified diagram of a Hall Effect sensor

Signal conditioning
• The signal conditioning stage involves the preparation of the input
signals for the next step in the process, ADC.
• The signal conditioning stage may include addition/subtraction,
attenuation/ amplification and filtering.
• When it comes to physical implementation, the signal conditioning
stages can be realised as discrete elements or combined with the
ADC as part of an Integrated Circuit. Alternatively the stages can be
built into a ‘System on a Chip’ architecture with a number of other
functions.
• In many circumstances the input signal will require attenuation,
amplification or the addition/subtraction of an offset such that its
maximum magnitude lies within the limits of the inputs for the ADC
stage.

Signal conditioning
• To avoid inaccuracy due to aliasing, it is necessary to remove
components of the input signal above the Nyquist frequency (that
is, half the sampling rate of the ADC).
• Therefore, prior to input to the ADC stage, a low pass filter is
applied to the signal. The sampling frequency is determined by the
functions of the meter.
• If the meter provides fundamental frequency measurements
(currents, voltage and power) and in addition harmonic
measurements, then the sampling frequency should be selected
sufficiently high so as to obtain harmonic components accurately.

A smart meter displays current harmonic measurements up to
the 5th harmonic component. What should be the minimum
sampling frequency used in the signal conditioning stage?
Assume that the frequency of the supply is 50 Hz.
The frequency of the 5th harmonic
component = 5 × 50 Hz = 250 Hz.
In order to capture up to 5th
harmonic component, the signal
should be filtered by an anti-aliasing
filter with a cut-off frequency of 250
Hz.
According to the Nyquist criteria, the
minimum sampling frequency should
then be at least = 2 × 250 Hz = 500 Hz.
This is shown in Figure , where fs is
the sampling frequency.

Analogue to digital conversion
• Current and voltage signals obtained from the sensors are first
sampled and then digitised to be processed by the metering
software.
• Since there are two signals (current and voltage) in a single phase
meter, if a single ADC is used, a multiplexer is required to send the
signals in turn to the ADC.
• The ADC converts analogue signals coming from the sensors into a
digital form. As the number of levels available for analogue to
digital conversion is limited, the ADC conversion always appears in
discrete form.

• Figure shows an example of how samples of a signal are digitised by
a 3-bit ADC.
• Even though 3-bit ADCs are not available, here a 3-bit ADC is used
to illustrate the operation of an ADC simply. The 3-bit ADC uses 23 (=
8) levels thus any voltage between −0.8 and −0.6 V is represented
by 000 (the most negative range is assigned 000).
• In other word, −0.8, −0.75, −0.7, and −0.65 are all represented by
000. Similarly, voltage between −0.6 and −0.4 V is represented by
001, and so on.

• The resolution of an ADC is defined as: Resolution = Voltage
range/2n; where n is the number of bits in the ADC.
• For the 3-bit ADC shown in Figure , the voltage range is 1.6 V (−0.8
to 0.8) and therefore the resolution is 1.6/23 = 0.2 V. The higher the
number of bits used in the ADC, the lower the resolution. For
example, if an 8-bit ADC (typically 8-, 16- and 32-bit ADCs are
available) is used, the resolution is 1.6/28 = 6.25 m
• There are many established methods for conversion of an analogue
input signal to a digital output .
• The majority of the methods involve an arrangement of
comparators and registers with a synchronizing clock impulse.
• The most common ADCs for metering use the successive
approximation and the sigma-delta method.

A smart meter uses the same 16-bit analogue to digital converter for both current
and voltage measurements. It uses a 100 : 5 A CT for current measurements and
415: 10 V potential divider for voltage measurements. When the meter shows a
current measurement of 50 A and a voltage measurement of 400 V, what is the
maximum possible error in the apparent power reading due to the quantisation
of the voltage and current signals?
Answer:
Current range to the ADC: 0–5 A, Resolution of the ADC: 5/216 = 76 μA
So the maximum quantization error of the current is 76 μA.
50 A passes through the primary of the CT and so the ADC reads: 50 × 5/100 = 2.5 A
Voltage range to the ADC: 0–10 V, Resolution of the ADC:10/216 = 152 μV
So the maximum quantisation error of the voltage is 152 μV.,
400 V is read by voltage divider and so the ADC reads; 400 × 10/415 = 9.64 V
The apparent power reading is: ((V + ΔV ) (I + Δ I) = VI +V ΔI + I ΔV + ΔV ΔI) ≈ VI +V ΔI
+ IΔV
Therefore, the maximum possible error in the apparent power reading due to the
quantisation is: VI + IV = 9.64 × 76 × 10−6 + 2.5 × 152 × 10−6 = 1.11 mVA.

The successive approximation method
In a successive approximation ADC, shown in Figure , the up-down counter initially
sets the Most Significant Bit (MSB) of its output to 1 while keeping all other outputs
at zero.
The counter output is converted into an analogue signal using a Digital to Analogue
Converter (DAC) and compared with the analogue input by a comparator. If the
analogue input signal is larger than the DAC output, then the up-down counter sets
the MSB and the next bit to 1 and the comparison is repeated.
If the analogue signal is smaller than the DAC output, then the MSB is reset to zero
and the next bit is set to 1. This process is repeated until the analogue input signal is
the same as the DAC output. At that point the DAC input will be same as the digitised
value of the analogue signal.

The sigma-delta converter consists of an
integrator, a latched comparator, and a
single-bit DAC, as shown in Figure.
The output of the DAC (signal at E) is
subtracted from the input signal, A. The
resulting signal, B, is then integrated, and
the integrator output voltage (signal at C)
is converted to a single-bit digital output
(1 or 0) by the comparator (signal at D).
The high frequency bit stream at D (at
frequency kfs where k > 1) is finally
divided by the digital filter thus giving a
series of bits corresponding to the
digitised value of the analogue signal at
every sampling frequency(f s).

The sigma-delta method
In order to explain the operation of this circuit, assume that the signal at A is Vref/2,
that the output at E is −Vref with signal at C below the threshold (corresponding to
logic ‘0’). Initially the output of the summation (B) is 3Vref/2 (Vref/2+Vref), and the
output of the integrator increases linearly. At the first clock pulse, as the integrator
output is greater than its threshold, it gives logic ‘1’ (see Figure-b). Since the
corresponding DAC output is +Vref, the signal at B now becomes negative (Vref/2−Vref).
Therefore, the integrator output reduces linearly (rate determined by the difference
of signals at A (actual signal) and E (analogue value of the digitised signal)). At the
next clock the output of the integrator is greater than the threshold, the output
remains at ‘1’. This negative feedback loop works such that the signal at D becomes
the digitised signal of input signal at A.

Computation
The computation requirements are split into arithmetic operations on
input signals, time stamping of data, preparation of data for
communication or output peripherals, handling of routines associated
with irregular input (such as payment, tamper detection), storage of
data, system updates and co-ordinating different functions.
The block diagram shown in Figure shows different functional blocks
associated with the computation functions of a smart meter.

Computation
Due to the relatively large number of arithmetic operations (Table 5.2)
required for the derivation of the parameters, a Digital Signal
Processor (DSP) is used.
Required parameter Operation type
Instantaneous voltage Multiplication
Instantaneous current Multiplication
Peak voltage/current Comparison
System frequency Zero detection, Fourier analysis
RMS voltage/current Multiplication
Phase displacement Zero detection, comparison
Power factor Trigonometric function
Instantaneous apparent power Multiplication
Instantaneous real power Multiplication
Instantaneous reactive power Multiplication
Energy use/production Integration
Harmonic voltage distortion Fourier analysis

Computation
In addition to routine arithmetic operations, a meter deals with a large
number of other procedures (that is, payment, tamper detection,
system updates, user interactions) as well as other routine tasks (for
example, the communication of billing information).
Therefore, a high degree of parallelism (the ability to perform multiple
tasks, involving the same data sets, simultaneously) and/or buffering
(the ability to temporarily pause arithmetical operations so that other
needs can be attended to) is required.
For computation, volatile memory (where information is lost on loss of
power supply) and non-volatile memory is needed. Volatile memory is
used for temporary storage of data to support the processor(s) as
operations are undertaken.
The amount of volatile memory used depends on the quantity, rate
and complexity of computation and the rate of communication
to/from ports.

Computation
A certain amount of non-volatile memory is typically required to store
specific information, such as the unit serial number and maintenance
access key codes.
Additionally data related to energy consumption should be retained
until successful communication to the billing company has been
achieved.
In order that the acquired data can be meaningfully interrogated, a
time reference must be appended to each sample and/or calculated
parameter.
For this purpose a real-time clock is used. The accuracy of the real-
time clock can vary with temperature. In order to maintain this
function during system power losses or maintenance, a dedicated
clock battery is typically used.

Input/Output
A smart meter has a display that presents information in the form of
text and graphs for the human user. Liquid Crystal Displays (LCD) and the
Light Emitting Diodes (LED) are preferred for their low cost and low
power consumption requirements. Both display types are available in
seven-segment, alphanumeric and matrix format. LEDs are relatively
efficient light sources, as they produce a significant amount of light
when directly polarised (at relatively low voltages: 1.2–1.6 V), and a
current of a few milliamps is applied.
Smart meters provide a small key pad or touch screen for human–
machine interaction, for instance, to change the settings of a smart
meter so as to select the smart appliance to be controlled or to select
payment options.
As smart meters require calibration due to variations in voltage
references, sensor tolerances or other system gain errors, a calibration
input is also provided. Some meters also provide remote calibration and
control capability through communication links.

Input/Output
Energy consumption and tariffs may be displayed on a separate
customer display unit located in an easily visible location within the
residence (for example, the kitchen).
This is to encourage customers to reduce their energy use, either
throughout the year or at times of peak demand when generation is
short.
Research is ongoing to determine the most effective way to display
information to encourage customers to take notice of their energy
consumption, and/or the signals from the suppliers to restrict demand
at times of generation shortage.
Approaches that have been used include displays using
- three coloured lights (resembling traffic lights) or a globe that changes
colour to signal changes in tariffs. This is used with a Time of Use Tariff
to control peak demand.
- a digital read-out or analogue display resembling a car speedometer
showing energy use;
- a continuously updated chart showing energy use and comparison

Input/Output
It is hoped that customers will manage and reduce their energy
consumption when they are provided with more accurate, up-to-date
information, also that any reduction made soon after the display is
installed will be maintained.
Trials indicate that initial reductions in electrical energy use of up to 10
per cent may be possible but maintaining this level of reduction
requires careful design of the displays and tariffs but also other
interventions such as outreach programmes to customers that provide
advice on how to reduce energy consumption.

Communication
Smart meters employ a wide range of network adapters for
communication purposes.
The wired options include the Public Switched Telephone Network
(PSTN), power line carrier, cable modems and Ethernet.
The wireless options include ZigBee, infrared, and GSM/GPRS/CDMA
Cellular.

Communications infrastructure and protocols for
smart metering
• A typical communications architecture for smart metering is shown
in Figure. It has three communications interfaces:Wide Area
Network (WAN), Neighbourhood Area Network (NAN) and Home
Area Network (HAN).

Home Area Network
A Home-Area Network (HAN) is an integrated system of smart meter,
in-home display, microgeneration, smart appliances, smart
sockets, HVAC (Heating, Ventilation, Air Conditioning) facilities and
plug-in hybrid/electric vehicles.
A HAN uses wired or wireless communications and networking
protocols to ensure the interoperability of networked appliances
and the interface to a smart meter. It also includes security
mechanisms to protect consumer data and the metering system.

Home Area Network
A HAN enables centralized energy management and services as well as providing
different facilities for the convenience and comfort of the household.
Energy management functions provided by HAN include energy monitoring and
display, controlling the HVAC system and controlling smart appliances and smart
plugs.
The services provided by HAN for the convenience of the household can include
scheduling and remote operation of household appliances as well as household
security systems.

Home Area Network
Home-based multimedia applications such as media centres for listening to music,
viewing television and movies require broadband Internet access across the
HAN.
A separate HAN used for energy services can coexist with the broadband Internet
system but there is some expectation that the systems will be merged in the
future.

Home Area Network
It is expected that HAN will provide benefits to the utilities through
demand response and management and the management of micro-
generation and the charging of electric vehicles.
In order to provide demand management functions and demand
response, two options are being actively considered in different
countries (Figure a and b).
One option is to use the smart meter as the interface to the suppliers,
network operators and other actors. The other option is to use a
separate control box which is directly interfaced to the outside
world through the NAN and WAN.

Neighborhood Area Network (NAN)
The primary function of the Neighbourhood Area Network (NAN) is to
transfer consumption readings from smart meters. The NAN should
also facilitate diagnostic messages, firmware upgrades and real-
time or near real-time messages for the power system support.
It is anticipated that the data volume transferred from a household for
simple metering is less than 100 kB3 per day and firmware upgrades
may require 400 kB of data to be transferred .
However, these numbers will escalate rapidly if different real-time or
near real-time smart grid functions are added to the smart metering
infrastructure.
The communication technology used for the NAN is based on the
volume of data transfer. For example, if ZigBee technology which
has a data transfer rate of 250 kb/s is used, then each household
would use the communication link only a fraction of a second per
day to transfer energy consumption data to the data concentrator.

DISTRIBUTION
AUTOMATION
EQUIPMENT

Substation automation equipment
The components of a typical legacy substation automation system are
shown in Figure
Traditionally, the secondary
circuits of the circuit breakers,
isolators, current and voltage
transformers and power
transformers were hard-wired to
relays.
Relays were connected with
multi-drop serial links to the
station computer for monitoring
and to allow remote
interrogation.
However, the real-time operation
of the protection and voltage
control systems was through
hard-wired connections.

The configuration of a modern substation automation system is
illustrated in Figure

Two possible connections (marked by boxes) of the substation
equipment are shown in Figure

Although it may vary from design to
design, generally it comprises three
levels:
The station level includes the
substation computer, the substation
human machine interface (which
displays the station layout and the
status of station equipment) and the
gateway to the control centre.
The bay level includes all the
controllers and intelligent electronic
devices (which provide protection of
various network components and a
real-time assessment of the
distribution network).
The process level consists of
switchgear control and monitoring,
current transformers (CTs), voltage
transformers (VTs) and other
sensors.

In connection 1, analogue
signals are received from CTs
and VTs (1 A or 5 A and 110 V)
as well as status information
and are digitised at the bay
controller and IEDs.
In connection 2, analogue and
digital signals received from CTs
and VTs are digitised by the
interfacing unit.
The process bus and station bus
take these digital signals to
multiple receiving units, such as
IEDs, displays, and the station
computer that are connected to
the Ethernet network.
To increase reliability, normally
two parallel process buses are
used (only one process bus is
shown in Figure.

The station bus operates in a
peer-to-peer mode.
This bus is a LAN formed by
connecting various Ethernet
switches through a fibre-optic
circuit.
The data collected from the IEDs
is processed for control and
maintenance by SCADA software
that resides in the station
computer.

The hard-wiring of traditional
substations required several
kilometres of secondary wiring in
ducts and on cable trays. This not
only increased the cost but also
made the design inflexible.
In modern substations as inter-
device communications are
through Ethernet and use the
same communication protocol,
IEC 61850, both the cost and
physical footprint of the
substation have been reduced.

Current transformers
The normal load current of transmission and distribution circuits varies
up to hundreds or even thousands of amperes.
When a short circuit fault occurs, the current may increase to more
than 20 times the normal load current.
Current transformers (CTs) are used to transform the primary current
to a lower value (typically 1 or 5 A maximum) suitable for use by the
IEDs or interfacing units.
The majority of CTs, which are now in service, are iron cored with a
secondary winding on the core. The primary is often the main circuit
conductor forming a single turn.
The iron core of these transformers introduces inaccuracies in the
measurements due to the presence of magnetising current (which only
appears on the primary), flux leakage, magnetic saturation and eddy
current heating.
In order to minimise their measurement errors, the design is
optimised for the specific application.

Measurement CTs are used to drive ammeters, power and energy
meters. They provide accurate measurements up to 120 per cent of
their rated current.
In contrast, protection CTs provide measurement of the much greater
fault current and their accuracy for load current is generally less
important.
Measurement CTs are specified by IEC 60044-1 according to their
accuracy classes, of 0.1, 0.2, 0.5 and 1 per cent at up to 120 per cent of
rated current.
Protection CTs are normally described for example, as ‘10 VA Class 10P
20’. The first term (10 VA) is the rated burden of the CT that can have a
value of 2.5, 5, 10, 15 or 30 VA.
The accuracy class (10P) defines the specified percentage accuracy. The
last term (20) is the accuracy limit (the multiple of primary current up
to which the CT is required to maintain its specified accuracy with
rated burden connected). The accuracy limit can be 5, 10, 20 or 30.

As shown in connection 2 of Figure (normally used in modern
substations), the current measurements from a CT are digitised and
made available to the process bus and used by a number of devices.
Multiple use of the same digitised measurement requires high
accuracy CTs that measure both load and fault currents.
While iron cored CTs and hybrid CTs (an iron cored CT with an optical
transmitter) remain the most widely used CTs in the power system,
high accuracy designs such as the Rogowski coil formed on a printed
circuit board and optical CTs are becoming available.

Rogowski coil CTs are used in a Gas Insulated Substations (GIS).
The secondary winding of the coil is a multi-layer printed circuit board
as shown in Figure with the upper and lower tracks of each layer
connected by metal vias (thus forming a rectangular coil).
The voltage induced on the secondary windings due to primary current
is integrated (as a Rogowski coil gives di/dt) by the sensor electronics
to obtain the value of the primary current.

Rogowski Coil CT
A Rogowski coil, named after Walter Rogowski, is an electrical device
for measuring alternating current (AC) or high-speed current pulses.
It consists of a helical coil of wire with the lead from one end returning
through the centre of the coil to the other end, so that both terminals
are at the same end of the coil.

Rogowski Coil CT
The whole assembly is then wrapped around the
straight conductor whose current is to be measured. There is no metal
(iron) core. The winding density, the diameter of the coil and the
rigidity of the winding are critical for preserving immunity to external
fields and low sensitivity to the positioning of the measured
conductor.

Rogowski Coil CT
Since the voltage that is induced in the coil is proportional to the rate
of change (derivative) of current in the straight conductor, the output
of the Rogowski coil is usually connected to an electrical (or
electronic) integrator circuit to provide an output signal that is
proportional to the current.
Single-chip signal processors with built-in analog to digital converters
are often used for this purpose.

Optical CT
Optical CTs use the Faraday effect , whereby the plane of polarisation
of a light beam when subjected to a magnetic field, is rotated through
an angle.
The Faraday effect describes an interaction between light and a
magnetic field in a medium.
A polarised light beam rotates when subjected to a magnetic field
(Figure).
The rotation of the plane of polarisation is proportional to the
intensity of the magnetic field in the direction of the beam of light.

Optical CT
The angle of rotation β in radians is given by β = νBd where B is the
magnetic flux density (in T), d is the length of the path (inm) and ν the
Verdet constant for the material.
Some other designs are being developed based on the Faraday effect
that use a disc of an optically active material around the conductor.
The light enters the disc from one side and travels around it (thus
around the conductor) and is collected at the other end.

Optical CT
Figure shows optical CT in its simplest form.
The opto-electronics compares the polarisation of the light beam
entered into the optical fibre and that collected after being subjected
to the circular magnetic field.
The angle of deflection is used to generate digital signals proportional
to the line current.

Voltage transformers
It is necessary to transform the power system primary voltage down to
a lower voltage to be transferred through process bus to IEDs, bay
controller and station computer.
The secondary voltage used is usually 110 V. At primary voltages up to
66 kV, electromagnetic voltage transformers (similar to a power
transformer with much lower output rating) are used but at 132 kV
and above, it is common to use a capacitor voltage transformers (CVT).
As the accuracy of voltage measurements may be important during a
fault, protection and measuring equipment are often fed from the
same voltage transformer (VT). IEC 60044-2 and ANSI/IEEE C57.13
define the accuracy classes of VTs. Accuracy classes such as 0.1,
0.2,0.5, 1.0 and 3.0 are commonly available.
For example, Class 0.1 means the percentage voltage ratio error should
not exceed 0.1 per cent at any voltage between 80 and 120 per cent of
rated voltage and with a burden of between 25 and 100 per cent of
rated burden.

CVT
The basic arrangement of a high voltage CVT is a capacitor divider, a
series reactor (to compensate for the phase shift introduced by the
capacitor divider) and a step-down transformer (for reducing the
voltage to 110 V).
The voltage is first stepped down to a high value by a capacitor divider
and further reduced by the transformer, as shown in Figure .

Optical CVT
For applications up to 11 kV, optical CVTs are now available. Due to the
lower voltage involved the inductor and transformer (in previous
figure) are replaced by an opto-electronic circuit mounted on the base
tank (Figure below. In this arrangement there is no L-C circuit to
resonate, and hence no oscillations, over-voltages or any possibility of
ferro-resonance.
Basic circuit of an optical CVT.

Optical CVT
Some VTs use a similar technique to optical CTs based on the Faraday
effect.
In this case, an optical fibre is situated inside the insulator running
from top to bottom and is fed by a circular polarised light signal.
Due to the magnetic field between the HV terminal and the base tank,
the polarisation of the light signal changes and that deflection is used
to obtain the HV terminal voltage.

Intelligent electronic devices (IED)
The name Intelligent Electronic Device (IED) describes a range of
devices that perform one or more of functions of protection,
measurement, fault recording and control.
An IED consists of a signal processing unit, a microprocessor with input
and output devices, and a communication interface.
Communication interfaces such as EIA 232/EIA 483, Ethernet, Modbus
and DNP3 are available in many IEDs.

Relay IED
Modern relay IEDs combine a number of different protection functions
with measurement, recording and monitoring.
For example, the relay IED shown in Figure has the following
protection functions:

Relay IED
three-phase instantaneous over-current: Type 50 (IEEE/ANSI
designation);
three-phase time-delayed over-current (IDMT): Type 51;
three-phase voltage controlled or voltage restrained instantaneous or
time-delayed overcurrent: Types 50V and 51V;
earth fault instantaneous or time-delayed over-current: Types 50N and
51N.

Relay IED
The local measurements are first processed and made available to all
the processors within the protection IED.
A user may be able to read these digitised measurements through a
small LED display as shown in Figure .

Relay IED
Furthermore, a keypad is available to input settings or override
commands.
Various algorithms for different protection functions are stored in a
ROM.

Relay IED
For example, the algorithm corresponding to Type 50 continuously
checks the local current measurements against a set value (which can
be set by the user or can be set remotely) to determine whether there
is an over-current on the feeder to which the circuit breaker is
connected.
If the current is greater than the setting, a trip command is generated
and communicated to the Circuit Breaker (CB).
IEDs have a relay contact that is hard-wired (in series) with the CB
tripping coil and the tripping command completes the circuit, thus
opening the CB.

Meter IED
A meter IED provides a comprehensive range of functions and features
for measuring three phase and single-phase parameters.
A typical meter IED measures voltage, current, power, power factor,
energy over a period, maximum demand, maximum and minimum
values, total harmonic distortion and harmonic components.

Recording IED
Even though meter and protection IEDs provide different parameters
(some also have a data storage capability), separate recording IEDs are
used to monitor and record status changes in the substation and
outgoing feeders.
Continuous event recording up to a resolution of 1 ms is available in
some IEDs. These records are sometimes interrogated by an expert to
analyse a past event.
This fault recorder records the pre-fault and fault values for currents
and voltages. The disturbance records are used to understand the
system behaviour and performance of related primary and secondary
equipment during and after a disturbance.

Bay controller
Bay controllers (Figure ) are employed for control and monitoring of
switchgear, transformers and other bay equipment.
The bay controller facilitates the remote control actions (from the
control centre or from an on-site substation control point) and local
control actions (at a point closer to the plant).

Bay controller
The functionalities available in a bay controller can vary, but typically
include: CB control, switchgear interlock check, transformer tap
change control and programmable automatic sequence control.

Remote terminal units (RTU)
The distribution SCADA system acquires data (measurements and
states) of the distribution network from Remote Terminal Units (RTU).
This data is received by an RTU situated in the substation (referred to
here as the station RTU), from the remote terminal units situated in
other parts of the distribution network (referred to here as the field
RTU).
The field RTUs act as the interface between the sensors in the field
and the station RTU.
The main functions of the field RTU are to: monitor both the analogue
and digital sensor signals (measurements) and actuator signals
(status), and convert the analogue signals coming from the sensors
and actuators into digital form.
The station RTU acquires the data from the field RTUs at a predefined
interval by polling. However, any status changes are reported by the
field RTUs whenever they occur.

Remote terminal units (RTU)
Modern RTUs, which are microprocessor-based, are capable of
performing control functions in addition to data processing and
communication.
The software stored in the microprocessor sets the monitoring
parameters and sample time; executes control laws; sends the control
actions to final circuits; sets off calling alarms and assists
communications functions.
Some modern RTUs have the capability to time-stamp events down to
a millisecond resolution.

Faults in the distribution system
When a fault occurs in the transmission or distribution system, the
power system voltage is depressed over a wide area of the network
and only recovers when the fault is cleared.
Transmission systems use fast-acting protection and circuit breakers to
clear faults within around 100 ms. In contrast, the time-graded over-
current protection of distribution circuits and their slower CBs only
clear faults more slowly, typically taking up to 500 ms.
Fast clearance of faults is important for industrial, commercial and
increasingly for domestic premises. Many industrial processes rely on
motor drives and other power electronic equipment which is
controlled by microprocessors.
Commercial and domestic premises use ever more Information
Technology Equipment (ITE). This equipment is becoming increasingly
sensitive to voltage dips.

Figure shows the well-known ITI (CBEMA) curve which specifies the AC
voltage envelope that can be tolerated by Information Technology
Equipment (note the log scales on the axes).

During a fault on the AC network, depending on the location of the
fault, the voltage will drop. The subsequent operation of the ITE
depends on the fault clearance time and the voltage dip.

For example, for a fault that creates a 40 per cent voltage dip (60 per
cent retained voltage) for 400 ms, there is no damage to the ITE but its
normal operation is not expected.
However, for a fault that creates a 20 per cent voltage dip (80 per cent
retained voltage) for 400 ms, the ITE should work normally.

Fault location, isolation and restoration
Figure shows a typical 11 kV distribution network.
When there is a fault on the network at the location shown, the over-
current protection element in IED1 detects the fault and opens CB1.
This will result in an outage at loads L1 to L5.
Since there are no automated components in the network, supply
restoration for a part of the network requires the intervention of a
restoration crew and in some areas may take up to 80 minutes .

Supply restoration is normally initiated by phone calls from one or
more customers (in the area where outage occurred) reporting a loss
of supply to the electricity supplier.
Upon receiving these calls a restoration crew is dispatched to the area.
It will take some time for the team to locate the fault and manually
isolate it by opening SD3 and SD4. Then CB1 is closed to restore the
supply to L1, L2 and L3. The normally open point (NOP) is closed to
restore the supply to L5. Load L4 will be without supply until the fault
is repaired.

A simple method to reduce the restoration time of loads L1, L2, L3 and
L4 is using a pole-mounted recloser and sectionaliser as shown in
Figure.
When a fault occurs, the recloser trips. Upon detecting the
interruption, the sectionaliser, S, increments its counter by 1.
After a short time delay, the recloser closes and if the fault persists, it
will trip again. The counter of S increments again and it is then
opened.

The recloser then closes successfully.
The operation of the sectionaliser facilitates restoration of supply to
L1, L2, L3 and L4 within a couple of minutes.
However, the restoration of supply to L5 requires the intervention of
the crew.
As this method does not need any communication infrastructure, it is
reliable and relatively inexpensive.

A greater degree of automation may be introduced by using reclosers
with RTUs, with communication infrastructure between them (see
Figure ).
In this scheme, an Agent is employed that gathers data from all the
intelligent devices in the system.
During normal operation, the Agent polls all the RTUs and IEDs to
establish the system status.

When there is a fault at the location shown, IED1 detects the fault
current, opens the CB and informs the Agent.
The Agent sends commands to RTU1 to RTU4 (remote terminal units
up to the normally open point) to open them and requests current and
voltage data from them in real time.

A possible automatic restoration method is:
1. Send a command to IED1 to close CB1.
2. Send a command to RTU1 to reclose R1.
3. If the fault current prevails, initiate a trip but as there is no fault
current, R1 remains closed.
4. Similarly send commands to RTU2, 3 and 4 to reclose R2, R3 and
R4. When R3 is closed, fault current flows, thus causing R3 to trip
and lock-out.

3. Then send a command to RTU9 to close the normally open point.
4. Finally, send a command to RTU4 to close R4. As the fault current
flows, a trip command is initiated for R4.
R3 and R4 thus isolate the fault and supply is restored to loads L1, L2,
L3 and L5.

Voltage regulation
Distribution circuits are subject to voltage variations due to the
continuous changes of the network load.
At times of heavy load the voltage of the downstream networks is
reduced and may go below the lower limit (in the UK the voltage on
the 230/400 V circuits should be maintained within +6 per cent and
−10 per cent).
Under light load conditions the voltage may go above the upper limit.
The voltage variations may become severe when distributed
generators are connected under light load conditions, the power flow
may be reversed .
Sustained voltages above 10 per cent or below −10 per cent of the
nominal voltage may damage or may prevent normal operation of IT
equipment.
As many consumers (domestic, industrial and commercial) are now
heavily dependent on this equipment, regulating the voltage within
the national limits is very important.

Voltage regulation
Traditionally, an automatic tap changer and Automatic Voltage Control
(AVC) relay, sometimes with line drop compensation, is used on the
HV/MV transformers to maintain the voltages on distribution circuits
within limits. These transformers whose output voltage can be tapped
while passing load current are referred to as having On-Load Tap
Changers (OLTCs). The operation of the OLTC is achieved by operating a
tap selector in coordination with a diverter switch as shown in a, b, c.

Voltage regulation
In automatic arrangements (with a motorised tap changer), an AVC
relay is introduced to maintain the MV busbar voltage within an upper
and lower bounds (a set value ± a tolerance).
The main purpose of introducing a tolerance is to prevent the
continuous tapping up and down (hunting effect). A time-delay relay is
also usually employed to prevent tap changing due to short-term
voltage variations. In modern automatic on-load tap changers, the AVC
software and time-delay relay are in a bay controller as shown in
Figure

Voltage regulation
In the USA, pole-mounted capacitor banks are used in distribution
circuits for voltage regulation. They provide power factor correction
closer to load, improve voltage stability, increase the line power, flows
are lower and reduce network losses. These capacitors may be fixed or
variable.
Modern pole-mounted variable capacitors come with current- and
voltage sensing devices, data logging facility and local intelligence.
Variable capacitors are essentially a number of switched capacitors
where the number of capacitors that are switched in is determined by
an intelligent controller fixed to the pole.
The location of the capacitor bank that provides reactive power and its
value of reactive power support are critical to achieve the optimum
voltage profile while minimising network losses and maximising line
flows. In some cases coordinated control of the OLTC transformer,
pole-mounted capacitors and any distributed generators in the
network may provide enhanced optimisation of different parameters.

Voltage regulation
A section of a distribution network is shown in Figure
1. Calculate the voltage the OLTC should maintain at busbar A to
achieve a line voltage of 11 kV at busbar B, when (i) L1 = 1 MW and
(ii) L1 = 3 MW.
2. If the 33/11 kV transformer has taps of ±12.5 per cent in steps of
2.5 per cent, discuss the tap setting for cases (i) and (ii). Assume
that the primary voltage of the transformer is 33 kV.
3. With the calculated voltage under (a)(i) on busbar A, calculate the
value of the capacitor in Mvar required to set the magnitude of the
line voltage at busbar B to 11 kV, when L1 = 3 MW.

Voltage regulation
A section of a distribution network is shown in Figure
Select Sbase = 100 MVA and Vbase = 11 kV
Zbase =(Vbase)2 /Sbase = (11 × 103)2 /100 × 106= 1.21Ω
Line impedance in pu = [2 + j1]/1.21 = 1.65 + j0.83 pu
Transformer reactance = 15% on 20 MVA = 0.15 × 100/20 = 0.75 pu

Voltage regulation
1. (i) When L1 = 1 MW
As voltage at busbar B is 1∠0◦ pu, IL = S in pu = 1/100 = 0.01 pu
Voltage at busbar A = 1.0 + (1.65 + j0.83)∗0.01
= 1.0165 + j0.0083 pu
= 1.0165∠0.47◦ pu
(ii) When L1 = 3 MW
IL = 0.03 pu
Voltage at busbar A = 1.0 + (1.65 + j0.83)∗0.03
= 1.0495 + j0.0249 pu
= 1.05∠1.36◦ pu

Voltage regulation
2. On a 33/11 kV transformer a tap changer is normally on the 33 kV
side. When the tap setting is at 0 per cent, the voltage at busbar is 1
pu. Lowering the tap position by one step, the voltage becomes 1.025
pu. So under case (a)(i), the tap setting will remain at 0 per cent. When
the load is increased to 3 MW, in order to maintain the required
voltage, the tap position should be lowered by two steps, that is, to −5
per cent. This gives a voltage of 1.05 pu.

Voltage regulation
3. With a capacitor connected to busbar B, see Figure
When L1 = 3 MW, IL = 0.03 pu
Assume capacitor current is IC and as it leads the voltage (Vd + jVq), the
current in the line section AB = IL + jIC
Voltage at busbar B = 1.0165∠0.47◦ + (1.65 + j0.83) ∗ (0.03 + jIC)
Equating the voltage at busbar B to Vd + jVq:
1.0165∠0.47◦ + (1.65 + j0.83) ∗ (0.03+jIC) = Vd + jVq
[1.0165 + 0.0495 − 0.83IC] + j [0.0083 + 0.0249 + 1.65IC] = Vd + jVq
Equating real and reactive parts of the above equation:
Vd = 1.066 − 0.83IC Vq = 0.0332+1.65IC

Voltage regulation
As the magnitude of the voltage at busbar B should be 1 pu:
[1.066 − 0.83IC]2 + [0.0332+1.65IC]2 = 1
Solving this quadratic equation, one can obtain:
IC = 0.106 pu and 0.381 pu
The first solution gives the voltage at busbar B as 1∠12◦; whereas the
second solution gives it as 1∠41.5◦.
As the phase angle of the second solution is not reasonable, the first
solution was selected.
The value of capacitance required = 1.06 ∗ 10 Mvar = 10.6 Mvar.
It is worth noting that this capacitor is much larger than the load
connected at busbar B.

DISTRIBUTION
MANAGEMENT SYSTEMS

Electricity distribution networks connect the high-voltage transmission
system to users. Conventional distribution networks have been
developed over the past 70 years to accept bulk power from the
transmission system and distribute it to customers; generally they
have unidirectional power flows.
The Smart Grid is a radical reappraisal of the function of distribution
networks to include:
• integration of Distributed Energy Resources;
• active control of load demand;
• more effective use of distribution network assets.
Distribution systems are extensive and complex and so they are
difficult to monitor, control, analyse and manage. Table shows
some of the factors that contribute to the complexity of
distribution systems.

Complexity
Network Distribution networks are often built as meshed circuits but operated
radially. Their topology changes frequently during operation, due to
faults and maintenance.
The structure of the network changes as the network expands
The three-phases are often unbalanced
The time scales that have to be considered range from milliseconds
(protection operation) to years (network expansion)
The networks have strict performance objectives
There is limited communication between elements of the network
and most control is local
Comprehensive monitoring of distribution networks would generate
a very large amount of data

Loads The composition of loads is complex and not well known
The pattern of distribution load consumption varies dynamically with
time. The trend of the load variation is more difficult to predict than
that of a large transmission network
It is not possible to obtain simultaneous measurements of all loads.
Load measurements normally are insufficient and may contain large
errors and bad data
The correlation between loads is not well understood

Distribution Management System
Real-time monitoring and remote control are very limited in today’s
electricity distribution systems and so there is a need for intervention
by the system operators particularly during widespread faults and
system emergencies.
However, it is difficult to deal with such a complex system through
manual procedures.
A Distribution Management System (DMS) is a collection of
Applications used by the Distribution Network Operators (DNO) to
monitor, control and optimise the performance of the distribution
system and is an attempt to manage its complexity.
The ultimate goal of a DMS is to enable a smart, self-healing
distribution system and to provide improvements in: supply reliability
and quality, efficiency and effectiveness of system operation.

A DMS should lead to better asset management, the provision of new
services and greater customer satisfaction.
The first generation of Distribution Management Systems integrated a
number of simple Applications into a computer system.
An interactive graphical user interface was then added to visualise the
network being managed.
The subsequent use of large relational databases allowed the
management of more complicated distribution networks and a large
volume of data.
However, as more and more Applications were added, managing the
information exchange and maintaining the DMS became a challenge.

Standardised models such as the Common Information Model (CIM)
were developed to aid information management.
For the Smart Grid future, the DMS will use higher-performance ICT
hardware, be equipped with greater intelligence, and be deployed in a
decentralised manner.
A DMS includes a number of Applications that use modelling and
analysis tools together with data sources and interfaces to external
systems, as shown in Figure .
The modelling and analysis tools are pieces of software which support
one or more Applications.

As shown in Figure , a DMS includes Applications:
1. for system monitoring, operation and outage management. These
are the Applications responsible for the daily running of the network
with the primary object of maintaining continuity of supply.
2. to help manage the assets of the utility, such as inventory control,
construction, plant records, drawings, and mapping. These include the
automated mapping system, the facilities management system, and
the geographical information system.
3. associated with design and planning for network extensions. These
Applications are used for audits of system operation to determine
short-term solutions and optimal expansion planning to achieve
system reinforcement at minimum cost.
All these Applications require modelling and analysis tools for which
network parameters, customer information, and network status data
are used as inputs.

SCADA
As shown in Figure , a DMS includes Applications:
1. for system monitoring, operation and outage management. These
are the Applications responsible for the daily running of the network
with the primary object of maintaining continuity of supply.
2. to help manage the assets of the utility, such as inventory control,
construction, plant records, drawings, and mapping. These include the
automated mapping system, the facilities management system, and
the geographical information system.
3. associated with design and planning for network extensions. These
Applications are used for audits of system operation to determine
short-term solutions and optimal expansion planning to achieve
system reinforcement at minimum cost.
All these Applications require modelling and analysis tools for which
network parameters, customer information, and network status data
are used as inputs.

Introduction
• Transmission systems in many countries are facing ever more
demanding operating conditions with increasing penetrations of
renewable energy generation, larger flows and greater cross border
trading of electricity.
• The variability of the power output of renewable energy sources
and unplanned flows through transmission grids are causing
difficulties for the system operators, who are responsible for
maintaining the stability of the system.
• Excessive power flows in transmission circuits and large variations
in busbar voltages may arise during steady-state operation so that
when faults and network outages occur, they can lead to system
collapse.
• In order to aid the transmission system operators to monitor,
control, and optimize the performance of generation and
transmission systems, a suite of Applications collected into an
Energy Management System (EMS) is used.

Introduction
• As the monitoring and control functions for EMS are often provided
by SCADA, these systems are also referred to as EMS/SCADA.
• EMS is normally located in the System Control Centre and effective
real-time monitoring and remote control exist between the Control
Centre and the generating stations and transmission substations.
• With the growing availability of measurements from Phasor
Measurement Units (PMUs), it is expected that, in future, PMU
measurements will be integrated with EMS.
• However, at present, PMUs are mainly incorporated into separate
Wide Area Applications. It is expected that EMS and Wide Area
Applications will coexist separately for some time.

Introduction
A structure of an EMS/SCADA and Wide Area Applications
Figure shows how different data sources feed into Applications. Good
visualisation tools are also important to represent information in an
effective manner.

Data sources
• IEDs receive measurements and status information from substation
equipment and pass it into the process bus of the local SCADA.
• The substation SCADA systems are connected to the Control Centre
where the SCADA master is located and the information is passed to
the EMS Applications.
IEDs and SCADA

Phasor Measurement Units
In a modern day power system, to gain more reliability Wide Area
Measurement Systems (WAMS) are being built around the world to
have continuous monitoring of the system where Synchrophasors are
the vital part.
Phasor Measurement Units (PMU) are widely used in the day to day
operation of contemporary power systems.
PMU gives phasor values of voltage and current which are GPS time
stamped.
Grid monitoring in real-time is essential for ensuring stable operation
of the grid. PMU help in making the grid completely observable, i.e.,
the voltages, currents and power flow at each and every bus are
available for complete analysis of the power system.
PMU provides monitoring of a large area grid network and thereby
blackout conditions can be avoided. Hence, it is considered as key
element in the Smart Grid(SG) system. Power system monitoring,
analysis, protection and control is done using PMU.

The data gathered by PMU are time stamped i.e. all data gathered
from different PMU's are time synchronized which helps them to be
used in checking the status of a large interconnected power system.
Therefore, PMU can measure voltage and current at any instant at any
location in a power transmission system.
Time stamping of the PMU data is done by Global positioning System
(GPS)

Figure shows a PMU.
It measures 50/60 Hz sinusoidal waveforms of voltages and currents
at a high sampling rate, up to 1200 samples per second and with high
accuracy.
From the voltage and current samples, the magnitudes and phase
angles of the voltage and current signals are calculated in the phasor
microprocessor of the PMU.

As the PMUs use the clock signal of the Global Positioning System
(GPS) to provide synchronised phase angle measurements at all their
measurement points, the measured phasors are often referred to as
synchrophasors

Figure shows voltage synchrophasors at the two ends of an inductive
transmission line.
The sinusoidal waveform of the voltage is expressed as:
vi (t ) = Vm-i sin (ωt + φi)
‘i' is the bus number at each end of the line (1 or 2)
Vm- i is the peak value.
The voltage synchrophasor is given by:
Vi = Vm_iejφi = √2Vrms_i ejφi
where Vrms_i is the rms value of the voltage magnitude.

PMU
Synchrophasors measured at different parts of the network are
transmitted to a Phasor Data Concentrator (PDC) at a rate of 30–60
samples per second.
Each PDC sends the data that is collected to a super PDC where there
is Application software for data visualisation, storing the data in a
central database and for integration with EMS, SCADA and Wide Area
Application systems (Figure ).

The power flow on the transmission line in Figure is 5 pu and the
voltage at both busbars is 1.0 pu. The system frequency is 50 Hz. The
power flow is estimated using the phase difference between busbars 1
and 2, that is using φ1 − φ2. The measurement of the phase angle φ1
has a time stamp error of 0.1 ms and that of the phase angle φ2 is
zero. Find the error in the estimated power flow.
The phase angle error Δφ is derived from the time stamp error of 0.1
ms and is given by: Δφ = 0.1/20 × 2π ∼= 0.0314 rad
The phase angle difference φ1 − φ2 is calculated in the following way:
P = V1V2/X sin (φ1 − φ2)
= 10 sin (φ1 − φ2) = 5pu
∴ φ1 − φ2 = π/6

The power flow on the transmission line in Figure is 5 pu and the
voltage at both busbars is 1.0 pu. The system frequency is 50 Hz. The
power flow is estimated using the phase difference between busbars 1
and 2, that is using φ1 − φ2. The measurement of the phase angle φ1
has a time stamp error of 0.1 ms and that of the phase angle φ2 is
zero. Find the error in the estimated power flow.
The estimated power flow error ΔP is shown in Figure and is given by:
ΔP =(V1V2 /X) sin (φ1 − φ2 + Δφ) − V1V2 /X sin (φ1 − φ2 )
= 2 ×( V1V2 /X) cos(φ1 − φ2 + Δφ/2 ). sin(Δφ/2)
≈ 2 ×( V1V2 /X ) cos (φ1 − φ2 +Δφ/2 ) (Δφ/2)
= 2 × 10.1× cos(π/6)× (0.0314/2)
= 0.272 pu

Energy management systems
Energy Management Systems (EMS) were designed originally at a time
when the electrical power industry was vertically integrated and had
centralised communications and computing systems.
With deregulation of the power industry and the development of the
Smart Grid, decision-making is becoming decentralised, and
coordination between different actors in various markets becomes
important.
A number of international standards are emerging (or are in place) for
the abstract description of systems and services. The abstract
description of interfaces is facilitated through the use of the Unified
Modelling Language (UML) which provides an object-orientated
representation of the power system. Use of standardised data models
allows Applications from different vendors to be integrated, thus
reducing the necessity for data wrappers. Today, IEC 61970 is the
commonly used standard for EMS systems.

A typical EMS system configuration
A typical EMS system configuration is shown in Figure.
System status and measurement information are collected by the
Remote Terminal Units (RTUs) and sent to the Control Centre through
the communication infrastructure.

The front-end server in the EMS is responsible for communicating with
the RTUs and IEDs. Different EMS Applications reside in different
servers and are linked together by the Local Area Network (LAN).

EMS Applications include Unit Commitment, Automatic Generation
Control (AGC), and security assessment and control. However, an EMS
also includes Applications similar to those of a DMS and most of the
tools used in a DMS such as: topological analysis, load forecasting,
power flow analysis, and state estimation.

Smart grid technologies after midsem slides

Smart grid technologies after midsem slides

More Related Content

What's hot (20)

Similar to Smart grid technologies after midsem slides (20)

Recently uploaded (20)

Smart grid technologies after midsem slides