2.  Current power scenario
 Essence of IT in power sec.
 Need of IT
 Current scenario of IT in power sec.
 EMS,Scada
 GIS,DA
 DMS,OMS
 Case analysis...
 Future of IT
 Reference

3.  Installed generation capacity has grown from 1,362
MW in 1947 to 1,80,358.12 MW as on 30th July 2011.
 PLF = 77.5 as on 2009-2010.
 Peak electricity supply fell short despite the growth.
Per capita consumption of electricity equals to
704 kWh in 2008-09.
 MoP has launched various initiatives and has come up
with UMPP.
 Plans to add about 78700 MW of generation capacity
in 11th year plan(2007-2012).
3

4.  AT&C losses in various states(10-20 %:
Goa, Tamilnadu, Puducherry, Punjab, Himanchal P.; 30-40
%: Orissa, Haryana; 60-80 %: Jammu &
Kashmir, Arunanchal Pradesh; > 80 %: Meghalaya)
 The various losses occurs because of poor billing, lack of
consumer education , political interference and inefficient
use of electricity.
 Annual losses incurred by SEB’s account to Rs. 67000 crore
per annum.
4

5.  IT offers a framework for an efficient power system.
 It can monitor, control electricity realtime with fine
granularity, construct a robust self healing grid, detect
outages, load congestion and shortfall, establish 2 way
power exchange with a large number of renewable
generators, storage devices.
 It can identify theft and losses, provide choices to
customer, allows new pricing mechanisms such as
TOD(Time Of Day), real time, enables improved
transparency, structure for sophisticated billing, collection
and information management.
5

7.  Business process automation
 Generation automation
 Distribution system automation
 Revenue and commercial management
 Consumer relationship management (CRM)
 AT&C(Aggregate Technical and Commercial) loss
reduction
7

9.  Maximizing availability, efficiency, and safety are crucial
role, monitoring, reporting, and controlling emissions

10.  Different IT techniques used in transmission are
DA,SCADA,ERP,GPS etc.
 ERP helps in detection and resolving of fault by remote
switch.
 SCADA is being implemented in LDC.
 Energy meters(SANDS, APEX, etc) are
installed, which are power measuring units.
 GPS are used in transmission to bring about a time
synchronization of different relays in different grids.
10

11.  Deals with tariff structure for bulk power
 Performance based tariff for supply based tariff
 System of rewards and penalties seeking to enforce day
ahead pre-committed schedules (One & One-half hours in
advance)
 Promote responsibility & accountability in power generation
 Paradigm shift from max power to max reliability
 A path to deregulated power market

12.  Objective from maximum production to optimal
production
 Multiple unit power plant to identify optimum loading
for each unit to save on operational costs
 Identify units to bring online / offline to meet plant
demand at minimum operating cost
 Dispatching least cost power in preference to more
costly power

13.  Monitor various online real-time plant parameters
from different generating stations
 Establish a full-fledged Generation Control Room for
performance diagnosis & optimization
 Provide suitable connectivity between each power
station & Control Room

14. Load Dispatch
Center
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Plant
Plant
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15.  ABT Optimization for Revenue Maximization
 Economic Load Dispatch
 Online Plant Performance Monitoring

16.  Power Plant Monitoring for each Unit
 Online Performance Monitoring & Calculation for each Unit
 Merit Order Despatch (MOD) at plant level
 Dispatch monitoring for switchyard energy meters

17.  Open communication architecture
 Easy to use configuration utility
 Flexible tariff calculation & UI charges module
 Invoices in user-defined format
 Reports and trends
 Exporting reports & other data
 Monitoring actual generation Vs scheduled generation

18.  Capability to handle multiple units
 Use of historical data to generate a best-fit cost curve for
the unit
 Configuring individual units with historical data and
operating constraints
 Allows users to perform simulation

20.  Defective meters.
 No meter for many consumers.
 Meter tampering, usually with the connivance of the
SEB staff.
 Non reading or incorrect reading of meters.
 Theft and unauthorised or unrecorded connections.
 Incomplete & inadequate consumer data base.
 No system which can provide dependable data on the
leakages.
 Lack of management attention.

21. Over drawls
and Thefts
Overloading of
Equipment
Frequent
interruptions
Poor Voltage
Profile
High Losses
Failure of
transformers

22.  HT meter reading, new meters should be installed
with remote reading facility and a communication
link to the host computer at the substation.
 For LT meter reading
 A remote meter reading arrangement with a
telecommunication link as proposed for HT
meters will not be cost effective.
 Hand held computerized data- logger(CDL).
 Trend analysis comparison with early consumption
pattern etc. would be built into the host computer
program to spot any variations indicating meter
tampering, illegal use of power.
 Help in checking the performance of
meter reading squad.

23.  AMR(AUTOMATIC
METER READING)
 MRI (Meter reading
instrument).
 RMR (Remote meter
reading).
 Spot Billing.
 Prepaid meters.

26.  The term SCADA usually refers to centralized systems which
monitor and control entire sites, or complexes of systems
spread out over large areas (anything from an industrial plant
to a nation).
A SCADA system usually consists of the following subsystems:
 A Human Machine Interface or HMI is the apparatus which
presents process data to a human operator, and through
this, the human operator monitors and controls the process.
 A supervisory (computer) system, gathering (acquiring) data
on the process and sending commands (control) to the
process.
 Remote terminal unit (RTUs) connecting to sensors in the
process, converting sensor signal into digital signal and
sending digital data to the supervisory system.

27.  Programmable Logic Controller (PLCs) used as
field devices because they are more
economical, versatile, flexible, and configurable than
special-purpose RTUs.
 Communication infrastructure connecting the
supervisory system to the remote terminal units.

28. RADIO
MASTER STANDBY
INTERFACE
DAH
PRINTER
Computer operator
Transformer with
microcontroller
chip
HT SIDE
LT SIDE
Scada
Tower

29.  Visibility for the network
operation
 Real-time,accurate and
consistent information of the
system
 Flexibility of operational
controls
 Faster fault identification
, Isolation & system
restoration
 Extensive reporting &
statistical data archiving
 Central database and history
of all system parameters
 Improve availability of
system, Optimized Load
Shedding

30. 1. Lower level of load
shedding
2. Improved Power
Quality, Voltage Profile.
3. Speedy Fault Restoration

31.  Generation Monitoring
 Load Dispatch
 Distribution Automation
 Railway Traction
 Oil and Gas
 Water Utilities
 Facility Management Systems - Building,
 Laboratory
 Industrial Control

32.  SCADA/EMS (Supervisory Control and Data
Acquisition/Energy Management System)
supervises, controls, optimizes and manages generation and
transmission systems.
 SCADA/DMS (Distribution Management System)
performs the same functions for power distribution
networks.
 Both systems enable utilities to collect, store and analyze
data from hundreds of thousands of data points in national
or regional networks, perform network modeling, simulate
power operation, pinpoint faults, preempt outages, and
participate in energy trading market.

33.  SCADA/EMS systems are a complete solution which
realize the functions of electric power system supervisory &
control and data acquisition, electric power network safety
& economical operation and analysis, real-time dispatch
management, dispatcher training, data communication
between different centers, etc.
 Integrated Hardware/Software Platform
 SCADA System
 Power Analysis Software: Network Topology, State
Estimation, Dispatch Power Flow, Network Equivalence,
 Short-circuit Current Calculation, Voltage Control/Reactive
Power Optimization, Static Security Assessment,
 Load Forecasting and so on
 Dispatch Information Management System (DMIS)
 Dispatcher Training Simulation System (DTS)
 Tele-Meter Reading System(TMR)

35.  A Geographic Information System (GIS) is a
computer-based system including
software, hardware, people, and geographic
information.
 A GIS can :
 create, edit, query, analyze, and display map
information on the computer.
 Geographic– 80% of government data collected is
associated with some location in space.
 Information- attributes, or the characteristics
(data), can be used to symbolize and provide further
insight into a given location.
System – a seamless operation linking the information to
the geography – which requires
hardware, networks, software, data, and operational
procedures .

36.  Hardware
 Software
 People
 Method
 Data

39.  The term distribution automation can be applied to many
aspects of the electric power delivery system, from the control
center to the substation, to the feeders and indeed to the
customer revenue meters.
 As the Institute of Electrical and Electronics Engineers
defines, distribution automation (DA) is “a system that
enables an electric utility to remotely monitor , coordinate
and operate distribution components in a real-time mode from
remote locations.”
 Today, the DA field encompasses all aspects of a distribution
network automation scheme, from the control center-based
SCADA and distribution management system on out to the
substation, where RTUs, PLCs, power meters, digital
relays, bay controllers and a myriad of communicating
devices now help operate, monitor and control power flow
and measurement in the medium-voltage ranges.

40. Fundamentally, there are three components of a system-wide
distribution automation system.
 These include control center-based control and monitoring
systems, including distribution SCADA or distribution
management systems.
 The data communications infrastructure and methodology
required to acquire and transmit operating data to and from
various network points in addition to substations.&
 The various distribution automation field
equipment, ranging from remote terminal units to
intelligent electronic devices required to
measure, monitor, control and meter power flow.
 Taken together, expenditures for this wide range of electric
power grid distribution automation activity exceed $1
billion dollars each year.

41.  System operators can more efficiently monitor and control
power delivery functions in real time if they have field
automation assistance.
 Field devices such as circuit
breakers, reclosers, switches, capacitors , transformers and
even substation batteries can all be monitored if not
controlled or operated remotely.
 Operators can also remotely measure
voltage, current, power factor, as well as overall demand
and load flows.
 Taken together, this information provides systems
operations the current conditions of the power delivery
system ,when system failures occur, automation of the
distribution network implies a much enhanced ability to
pinpoint outage locations and causes and to restore power

42. RTU
SCADA System
M2M Gateway
Data Concentrator
FPI Monitoring Unit

43.  Automating the process of metering/measurement
through digital communication techniques.

44. ELECTRO-MECHANICAL
Low Accuracy
Control – NIL
PAST Communications - Expensive
Theft Detection – Poor
DIGITAL SOLID STATE
High Accuracy
Control – LIMITED
CURRENT Communications – External through Retrofit
Theft Detection – Node only
NEXT GEN SMART METER & IT SYSTEM
Very High Accuracy
Control – FULL
NEXTGEN Communications – Built in (on chip / PCB)
Theft Detection – High (Network level)

45.  Remotely reads customer meters and then transfers the
data into the billing system
 Reduce the need for meter readers to manually gather
utility meter readings each month.

46. INPUT
1. Area wise verified Network provided
by GIS group .
2. Data for Load Modeling in DMS
provided by Network
Group, Metering Group, Energy &
Automation Group & GIS Group.

47.  A Distribution Management System (DMS)
comprises a base SCADA system that is equipped
with additional planning and operations
functions for the utility's sub-transmission and
distribution feeder systems.
 DMS applications are highly data intensive. This
is due to the greater numbers of power system
elements and spatial information to be included
in displays, analysis functions and databases.

48.  PST can view entire 11 kV network
 Decision can be taken for restoration of
supply based on DMS application.
 Once Distribution Automation starts, selected
RMU controlling will be done by PST from
DMS.

49. Many of these functions rely heavily on data obtained or
shared with other IT systems. Typical functions of a
DMS include:
 Display Enhancements
 Asset Management
 Work Management
 On-line Monitoring and Operator Advice
 Analysis Tools
 Accounting & Reporting

50. Customer
Substation
Customer complaints Automation
Pro-Active information
Recovery information Real-time information
Disturbance records
Customer Type of disturbance
Service Time to recover Control Center
No. of customers affected
Customers affected Work order Disturbance information
Work report Disturbance report
Compensation
Fault statistics
Spares
Sales Asset
Management Repair and Maintenance Engineering
Asset records
Disturbance report
Accounting

52.  An Outage Management System (OMS) is a computer
system used by operators of electric distribution
systems to assist in restoration of power.

53.  Prediction of location of fuse or breaker that
opened upon failure.
 Prioritizing restoration efforts and managing
resources based upon criteria such as locations of
emergency facilities, size of outages, and duration
of outages.
 Providing information on extent of outages and
number of customers impacted to
management, media and regulators.
 Calculation of estimation of restoration times.
 Management of crews assisting in restoration.
 Calculation of crews required for restoration.

54.  Consumer trouble call management through SAP-ISU.
 Outage management using prediction logic.
 Crew management.
 Prioritization of outages through predefined logics.
 Planned outage management through SAP-PM.
9/03/2010 54

55.  Reduced outage durations due to faster restoration
based upon outage location predictions.
 Reduced outage duration averages due to prioritizing
 Improved customer satisfaction due to increase
awareness of outage restoration progress and providing
estimated restoration times.
 Improved media relations by providing accurate outage
and restoration information.
 Fewer complaints to regulators due to ability to
prioritize restoration of emergency facilities and other
critical customers.
 Reduced outage frequency due to use of outage
statistics for making targeted reliability improvements.

56. SYSTEM CONCEPT
Customer calls
with service request
Call center generate call Enroute
tickets in
SAP-ISU
Onsite
Outage Management System
Worked

57. •Call assignment
•Trouble prediction AMI
•Switching •Meter
•Takes trouble calls •Dispatching status
•Informs customers of information
restoration status
Control Centre
CIS •Provides location
SAP-ISU •Provides circuit data
•Provides routing
Outage Management
•Keeps OMS apprised System – for 1.8 million
of status on Customers
monitored devices GIS
•Initiates work
•Tracks work status
SCADA/DMS •Closes jobs
WMS(SAP)

58. IT implementation is nothing but coordination between
all the software's and interfaces on real time basis.

60.  KEPCO has opening T&D losses of 30% in the
year 1961.
 Key measures taken by KEPCO:
 DA
 SCADA,DMS
 GIS,AMR
 Inspection teams for disconnection and
reconnection only after payment on time and
monitoring through online systems.
 Computerised Customer relationship centres.
 KEPCO reduced the T&D losses from 30% in
1961 to 3.9% in 2003.

61.  NDPL distributes electricity in North & North West
parts of Delhi and serves a population of 50 lakh . The
company started operations on July 1, 2002 post the
unbundling of erstwhile Delhi Vidyut Board. With a
registered consumer base of around 12 lakh and a peak
load of around 1350 MW
 Since privatisation, the Aggregate Technical &
Commercial (AT&C) losses in NDPL areas have been
reduced a lot by constant efforts of automation and
technology i.e. Use of SCADA,GIS,DA,DMS,& OMS
 Today they stand at 14% losses( as on March
31, 2011) which is an unprecedented reduction of over
74% from an opening loss level of 53%.
 They are going to be the 1st utility in India to
implement Smart Grid procedures as a pilot project.

67. What is Smart Grid?
“SMART GIRD” is a set of technology
implementation that uses advanced
sensing, metering, communication, control, computati
on and reporting technologies to facilitate generation
and distribution of electricity more
effectively, economically and securely to achieve
desired balancing of supply and demand.
Smart Grid : An evolving set of concepts and not a set
of formulae
67

68. It is Advanced Metering Infrastructure (AMI)
68

69. What is Smart Grid?
It is Substation & Distribution Automation
69

70. What is Smart Grid?
It is Distribution & Outage Management
70

71. What is Smart Grid?
To a Design & Planning Engineer
It is Asset and Load Management
71

72. What is Smart Grid?
To an IT Engineer
It is the challenge of bringing it all together
72

73. What is Smart Grid?
They are all correct!
If they work together smartly.
73

74. Url and Links Websites
http://energycentral.fileburst.com/S www.energybizmag.com
ourcebooks/gsbk0106.pdf
http://en.wikipedia.org/wiki/SCAD www.wikepedia.com
A
http://www.pfc.gov.in www.pfc.gov.in
http://cercind.gov.in/ www.cercind.gov.in
http:// powermin.nic.in/ Indian www.powermin.nic.in
electricity scenario/ Final Report

75. Any Queries ..????