automation in scada, substation & metering
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Detailed information on scadaTRANSCRIPT
Automation in SCADA, Substation & Metering
18-Feb-12 1
ARUNACHALAM ADDITIONAL DIRECTOR
National Workshop on
Emerging Technologies in Electrical Power Engineering
17-18 February 2012
Silicon Institute of Technologies Bhubaneswar, Orissa
CPRI, BANGALORE
18-Feb-12 CPRI, BANGALORE 2
Outline
• Power System Automation – SCADA
– DA
• SUBSTATION AUTOMATION
• Metering System
• Smart Grid
Central Power Research Institute
MINISTRY OF POWER
GOVERNMENT OF INDIA
ESTABLISHED IN 1960
AUTONOMOUS SOCIETY IN 1978
RESEARCH
TESTING
CONSULTANCY
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1) Central Power Research Institute, Bangalore. 2) Switchgear Testing & Development Station, Bhopal. 3) Ultra High Voltage Research Laboratory, Hyderabad. 4) Regional Testing laboratory, Noida. 5) Thermal Research Centre, Nagpur. 6) Regional testing Laboratory, Kolkata 7) Regional testing Laboratory, Guwahati
Central Power Research Institute - Units
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Testing of power apparatus for 1. Electrical test 2. Insulation test 3. Thermal test 4. Stress test 5. Environmental test 6. Mechanical test 7. Seismic qualification test 8. Short time current test up to 300 kA rms 9. Direct testing upto 2500 MVA capacity 10.Synthetic testing 11.HV test upto 800 kV 12.Impulse test 13.Ingress protection test 14.Dielectric property test 15.EMI-EMC test 16.Heat run test 17.Flame proof test 18.Test for energy efficiency and many
more.
ISO 17025 ISO 9000
CCAR - CENTER FOR
COLLABORATIVE RESRACH
CPRI FACILITIES
PROTOCOL LABORATORY a) IEC 62056 b) IEC - 60870- 5- 101 c) IEC - 60870- 5- 103 d) IEC - 60870- 5- 104 . e) IEC - IEC 60870-6 . f) DNP 3.0 g) IEC 61850
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5
OVERVIEW ON POWER SYSTEM AUTOMATION…
Acquisition of Information
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POWER SYSTEM AUTOMATION
Availability of Information
Decision making
Analysis of the Information
From end points – meters, DTR, Feeders, RMUs
Communication and networking, DAS, AMR
Applications – EMS, DMS
O&M, Control, Planning, MIS, ERP, MBC
MCC Master Control Center
Communication Connectivity
SUBSTATION SUBSTATION
Generic - Automation Architecture
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IT systems
VSAT, MPLS, FOC, GPRS
System strengthening
• Feeder re-configuration
• Conductor size
• LT: HT ratio
• DTR
• Load balancing
• Improving tail end voltage
Automation
• RMUs.
• Sectonalisers
• Auto re-closers
• Fault Pass Indicators (FPI)
• Communication systems.
• DMS functions.
Typical Automation Functions
System Centric Function Customer Centric
Function
MIS Related Function
Substation monitoring &
control (Local & Remote)
Reduced outage Technical loss reduction
DTR monitoring Reduced interruption Commercial loss reduction
Remote control of RMU &
sectionalizes
Better voltage System information for
planning
Planned system operation Planned load shedding Load forecast
Power transformer
monitoring
Improved reliability Optimal network planning
Load monitoring & control Quick service restoration Energy audit
Condition monitoring &
maintenance
Billing & Payment GIS mapping
TCMS / IVRS Asset management
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AMBIENCE
• Indian electricity act
• Open access
• De-regulation
• Reforms
• Energy conservation act
TECHNOLOGY
• Computing platforms
• Measuring technology
• Interfacing
• Networking
• It enabling
• Communication
THE STANDARDS
• Open systems
• Communication protocols
• Information access
THE NEED
• Data / information
– Customer
– Management
– Operation
• Historical
• Efficiency improvement
Automation - Drivers
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10
Network application overview
The SCADA
systems
caters to the
whole of
Karnataka
state which
has five
Distribution
companies
and 23
major
generating
stations and
major IPP’s
and Central
Generation
Share
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Courtesy - KPTCL
11 18-Feb-12 CPRI, BANGALORE
Courtesy - KPTCL
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Objectives
• Common integrated solution to cater to the network extending to the entire state of Karnataka – covering 854 Stations of Transmission, Generation and Distribution companies in the I phase.
• Integrated Solution for Energy Auditing, Energy Billing and Availability Based Tariff to meet regulator’s requirement.
• Integration of all Sub-station and Generating Station Automation systems
• Data to all ESCOMs for scheduling and monitoring
• Facilitate Integration to other “down the line” Distribution Systems of ESCOM.
BLR
144
TUM
111
MYS
152
HAS
28
BGL
237
GUL
150
RTU RTU
ALDC ALDC
DR - HUB
MCC-1 MCC-2
BLR
6 - ALDC
822 ( 400/220/110/66/33) SS
OUTLINE ARCHITECTURE - SCADA/EMS/DMS Project
Transmission SCADA
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14
Features
• SCADA from all receiving stations ranging from 33kV to 400kV
• SCADA from all Major Generating stations and IPPs.
• Data from all feeders from 11 kV to 400 kV.
• Area Load Dispatch Centre for Six Transmission Zones
• Distribution Control Centre for five ESCOMs
• Up-gradation of State Load Despatch Centre
• Exclusive Control Centre for Bangalore City
• EB/EA/ABT system to perform Energy Billing, Energy Audit and
• Availability Based Tariff functions
• Sub-system to perform Open Access operations.
• Real time Energy Data Acquisition from all Interface points.
• Energy Management System and Distribution Management System
• VSAT Hub and network with leased bandwidth from INSAT 3A
• Disaster Recovery Hub
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15
Functional Structure of EM Centers
Energy Management System
Data Acquisition Load Forecasting Topology Processing
State Estimator
Dispatcher Power Flow
Network Sensitivity Funct
Network Parameter
Adaptation
Security Analysis Funct
Unit Commitment
Security Dispatch
Function
Interchange Transaction
Scheduling
Voltage Control Funct
Economic Dispatch and AGC
Optimal Power flow
Supervisory Control
Logical Alarm
Sequence of Events Funct
Alarm Processor
Historical Data base
Load shedding Funct
Automatic Data collection
Safety Management
Base Functions Generation Functions Network Analysis Functions
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DISTRIBUTION AUTOMATION SYSTEM (DAS)
Stages involved in Power Distribution
MV
LV
Distribution Automation
The “distribution automation” includes - automation
that is used in the planning, engineering,
construction, operation, and maintenance of the
distribution power system, including interactions with
the transmission system.
• Manuel to Automatic
• MV network is the focus
DMS Functions The typical DMS functions are i. Loss Minimization via Feeder Reconfiguration (LMFR) ii. Load Balancing via Feeder Reconfiguration (LBFR) iii. Fault Management and System Restoration (FMSR) iv. Outage Management v. Peak Management vi. Workforce Management vii. Voltage VAR control (VVC) viii. Network Connectivity Analysis (NCA) ix. State Estimation (SE) x. Load Flow Application (LFA) xi. Operation Monitor (OM) xii. Distribution Load forecasting (DLF) xiii. Distributed Planning • Operational planning • Assessing planned outages • load forecasting
System strengthening • Feeder re-configuration • Adding additional feeders • Increasing conductor size in selected segments • Reducing LT: HT ratio • Adding more distribution transformers • Load balancing on existing feeders and DTRs • Improving tail end voltage wherever required. • Revamping of sub-stations • Re-conditioning required DTRs.
Automation • RMUs on the MV network. • Sectonalisers • Auto re-closers • Fault Pass Indicators (FPI) • Communication connectivity. • DMS functions.
R
T
U
R
T
U
Primary Plant
Interface
KEY ELEMENTS of DAS
Data & Control
Pathway
Communications
Master
Station Substation
1 2
3
4 Optical Fibre,
Cable
Radio
Microwave
R
T
U
1
2 RTU
3
4
Communications
Master Station
Line
Reporting
Analysis
5
5 Control Room,
Corporate Usage
Control Room
Operators
Outage Analysis
Operational analysis,
decisions, issue controls
5
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RTU
COMMUNI-
CATIONS
SCADA
DMS
User
Interface
Data
Acquisition
DMS Applications
SCADA
Functions
SCADA Platform Environment
Maintenance Management
Decision Support Systems
OMS Crew Management
GIS
Other Applications
DAS Functional/Architectural Overview
Corporate Data Accessibility and Availability
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Substation No. of
interruptions
Duration of
Interruptions
S1 48 47:42:00
S2 50 23:16:15
S3 48 16:14:15
Indian utilities statistics
Example Failure Rates
Overhead Failure Rates
Voltage Circuit
km
Failures
Over
5 Years
Failures
Per km
Per Year
12kV
Main 309 190 0.123
Lateral 217 201 0.185
4kV
Main 241 111 0.092
Lateral 161 70 0.087
Underground Failure Rates
Voltage Circuit
km
Failures
Over
5 Years
Failures
Per km
Per Year
12kV
XLPE 360 33 0.018
EPR 116 9 0.016
PILC 231 64 0.055
PE 242 13 0.011
4kV
XLPE 28 1 0.007
EPR 12 2 0.033
PILC 160 30 0.038
PE 10 0 0.000
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Example Causes of Failure Equipment Failures
(Resulting In Sustained Outages)Average (1996-2001)
0
20
40
60
80
100
120
140
160
Equ
ipm
ent F
ailu
re
Unk
nown
Act
ivity
/Fore
ign
Obj
ect
Veg
etat
ion
Wea
ther
Dis
trib
utio
n Supp
ly F
ailu
re
Ele
ctrica
l Ove
rloa
d
Oper
atin
g Error
Oth
er C
ircu
it
Impr
oper
Cons
truct
ion
Nu
mb
er
of
Su
sta
ine
d O
uta
ge
s
6 Year Average
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Outage Management System
• Automatically infers fault location based on customer trouble calls or other indications
• Shows fault location on geographical display of power system so crews can be dispatched immediately to this location
• Displays can be used to show crew positions and reflect repair status as switches are opened and closed
• Tracks number of interrupted customers and corresponding outage durations
Reduces repair times, keeps customers better informed,
and provides more accurate reliability data!
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Automation Philosophy
Circuit Breaker
R/S feeder R/S feeder
Remote operation to close switch
Additional network restored, total time 11-18 mins
Circuit Breaker
R/S feeder R/S feeder
Normally open point
Automated RMU / DT with FPI
Circuit Breaker
R/S feeder R/S feeder
Normally open point
FPI indicates passage of fault current
CB Trips
Circuit Breaker
R/S feeder R/S feeder
Normally open point
Remote Operation of RMU Switch & Partial Restoration of supply – typically 1-2 mins
After Automation ( Average time to restore Power Supply to healthy section 1-2 Minutes)
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Impact of Automation System
Power Restored
to Customers on
Healthy Sections
of FeederFault
Occurs
Customer
Reports
Outage
Travel Time
Fault
Located
Investigation
& Patrol TimeTime to Perform
Manual Switching Repair Time
Feeder
Back to
Normal
5 – 10
minutes
15 – 20
minutes
10 - 15
minutes
45 – 75
minutes
15 – 30
minutes
1 - 4
Hours
Power Restored
to Customers on
Healthy Sections
of FeederFault
Occurs
Customer
Reports
Outage
Travel Time
Fault
Located
Investigation
& Patrol TimeTime to Perform
Manual Switching Repair Time
Feeder
Back to
Normal
5 – 10
minutes
15 – 20
minutes
10 - 15
minutes
45 – 75
minutes
15 – 30
minutes
1 - 4
Hours
Fault
Occurs
Customer
Reports
Outage
Travel Time
Fault
Located
Investigation
& Patrol TimeTime to Perform
Manual Switching Repair Time
Feeder
Back to
Normal
5 – 10
minutes
15 – 20
minutes
10 - 15
minutes
45 – 75
minutes
15 – 30
minutes
1 - 4
Hours
Without Automation
With Automation
minutes Hoursminutesminutes Hoursminutesminutes Hoursminutes1 – 2
minutes
1 – 2
minutes
1 – 2
minutes
Field
Crews
On- Scene
15 – 30
Feeder
Back to
Normal
Power Restored
to Customers on
Healthy Sections
of Feeder
Travel Time Repair Time
1 - 4 5 - 10
Patrol
Time
Customer
Reports
Outage
Fault
Occurs
Field
Crews
On- Scene
15 – 30
Feeder
Back to
Normal
Power Restored
to Customers on
Healthy Sections
of Feeder
Travel Time Repair Time
1 - 4 5 - 10
Patrol
Time
Customer
Reports
Outage
Fault
Occurs
Field
Crews
On- Scene
15 – 30
Feeder
Back to
Normal
Power Restored
to Customers on
Healthy Sections
of Feeder
Travel Time Repair Time
1 - 4 5 - 10
Patrol
Time
Customer
Reports
Outage
Fault
Occurs
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Future
State
Analysis
Crew Management
Outage
Management
Outage Analysis
Outage Reporting
IVR
Reports and
History
Operational
Diagrams
Switching
Management Switching
Planning
Asset
Maintenance CIS
SCADA
Network
Operational
Model
NOM
Updates to
Network Model
and Diagrams
Calls
Planning ERP, GIS
Corporate
Asset Data
and
Model
Design
r/t state r/t state
Current State
Analysis
(Incorporates Load
Modelling and
Network Analysis
Typical Distribution Control Room
Environment
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Future
State
Analysis
Crew Management
Outage
Management
Outage Analysis
Outage Reporting
IVR
Reports and
History
Operational
Diagrams
Switching
Management Switching
Planning
Asset
Maintenance CIS
SCADA
Network
Operational
Model
NOM
Updates to
Network Model
and Diagrams
Calls
Planning ERP, GIS
Corporate
Asset Data
and
Model
Design
r/t state r/t state
Current State
Analysis
(Incorporates Load
Modelling and
Network Analysis
Typical Distribution Control Room
Environment
DAS
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Reliability Performance Indices
• With moves toward deregulation and open competition, access to accurate and timely outage information is critical in order to maximize operational efficiency, minimize customer complaints, and maintain electric system reliability.
• In this respect, it is common practice to track and benchmark reliability using standard performance indices such as CAIDI, SAIFI, and SAIDI.
• These indices serve as valuable tools to compare utility reliability performance, but care must be taken to ensure they are being calculated in the same manner.
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Index Definitions • System Average Interruption Frequency Index
• System Average Interruption Duration Index
• Customer Average Interruption Duration Index
Served Customers ofNumber Total
onsInterruptiCustomer ofNumber TotalSAIFI
Served Customers ofNumber Total
Durationson InterruptiCustomer SAIDI
onsInterruptiCustomer ofNumber Total
Durationson InterruptiCustomer CAIDI
Interruptions/Customer/Yr
Minutes/Customer/Yr
Minutes/Interruption/Yr
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AIL
Crew
Savings
Man
Power
Savings
Fmas
Savings
Scada
Scada
Cost
Savings in
Power @ 40
% LF
Pay Back
Period(
Yrs)
Before After Before After Before After Before After
0 3.2 3.2 12.4 12.4 192000 192000 105 105 0 0 0 0 0 0
1 3.2 0.8 12.4 2.95 192000 48000 105 26 3365.4 561 97.6 759.5 6.1236 0.2
2 3.2 3.2 12.4 7.6 192000 192000 105 105 0 561 97.6 872 3.1104 1.87
3 3.2 1.8 12.4 8.25 192000 108000 105 59 1959.6 561 97.6 872 2.6892 0.36
4 3.2 0.6 12.4 2.7 192000 36000 105 19 3663.6 561 97.6 1172 6.2856 0.29
5 3.2 0.6 12.4 1.5 192000 36000 105 19 3663.6 561.00 97.6 1584.5 7.0632 0.39
SAIFI SAIDI
No. of Permanent
Faults No. of VehiclesConclusions
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Example of Automated GOS
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Example of Automated Load Break Switches/Line Reclosers
SF6 LBS
Vacuum LBS
Air-Break LBS
Line Recloser
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Example of RMU (Pad-Mounted Switches)
Generally, if not automation ready, can be retro-fit with motor
or solenoid operating mechanism
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Substation Automation
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SS Architecture - wired
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STATION LEVEL
BAY LEVEL
PROCESS LEVEL
SS Architecture – Networked – IEC 61850
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PROCESS LEVEL
BAY LEVEL
STATION LEVEL
ETHERNET
IEC 61850 - ARCHITECTURE
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Substation Bus – Ethernet – OFC – 100/1000 Mbps
Process Bus – Ethernet – OFC – 100/1000 Mbps
IED
(Relay) IED
(BCU)
IED
(METER)
HMI Gateway
MU MU MU LEGACY IED
GOOSE
TO RCC
INTEROPERABLE
IEC 61850 – SALIENT FEATURES
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1. Freedom to allocate function to devices
2. Interoperability – IEDs of different mfrs can co-exist and exchange
info.
3. One or more logical node in a physical device
4. Sampled values of Voltage and Current exchange
5. High speed IED to IED communication – [GOOSE]
6. Interface to legacy system
MACRO - MICRO
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LOGICAL DEVICE
LOGICAL NODE
DATA&OBJECTS
M/CT/ST
ATTRIBUTE
U/MF/SIGN
PHYSICAL DEVICE
Smart Grid
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THE ENERGY SECURITY
• Demand for energy – all forms - unsustainable
• KYOTO PROTOCOL • Climate change • Global warming – restrict GREEN house gas • CO2 - emissions
• Need at least 50% more energy in 2030.
CPRI
47 CPRI, BANGALORE
Fossil Fuel
Coal
Oil
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THE KEY DRIVERS CPRI
48 CPRI, BANGALORE
Need for more energy
Increased usage of renewable energy resources
Sustainability
Competitive energy prices
Security of supply
Ageing infrastructure and workforce
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Energy consumption 3.4% of global level
Demand for energy 3.6% per annum
Power statistics - India
Installed capacity as of September 2010.
Sector MW %age State Sector 80,844.12 52.5 Central Sector 51,867.63 34.0 Private Sector 32,124.05 13.5 Total 1,64,835.80 Per capita usage 612 kwh Energy = -12.1% Peak Demand = - 10.6%
CPRI
Peak periods
DEM
AN
D
• Balance Demand with Supply • Reduce Losses • Customer participation in Supply – DSM / DR • Time of USE - TOU • Green initiatives - RE
peak shaving
Distribution – smart grid
0 24 Time
peak shifting
50 CPRI, BANGALORE
DG
DSM/DR
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SMART GRID
51
DG – Distributed Generation DR – Demand Response
Integrated Intelligence
Network I2N
Courtesy - IEEE
A reform process which aims at optimally utilising the available energy with demand
CPRI
51 CPRI, BANGALORE 18-Feb-12
1. Self-Healing and Adaptive – Rapidly detects, re-configures and restores power supply.
2. Interactive with consumers and markets - Motivates and includes the consumer and stakeholders.
3. Optimized to make best use of resources and equipment - Optimizes assets and operates efficiently.
4. Predictive rather than reactive – the system operation can be planned to avoid emergencies.
5. Distributed Generation - Accommodates all generation and storage options
CPRI Characteristics of SG
52 CPRI, BANGALORE 18-Feb-12
“an automated, widely distributed energy delivery network characterized by a two-way flow of electricity and information, capable of monitoring and responding to changes in everything from power plants to customer preferences to individual appliances.”
Smart Grid Vision Definition
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Smart Grid Challenges
• Financial Resources The regulators will require extensive proof before authorizing major investments based heavily on societal benefits.
• Government Support The industry may not have the financial capacity to fund new technologies without the aid of government programs to provide incentives to invest.
• Compatible Equipment Some older equipment must be replaced as it cannot be retrofitted to be compatible with smart grid technologies. This may present a problem for utilities and regulators since keeping equipment beyond its depreciated life minimizes the capital cost to consumers. Early retirement of equipment may become an issue.
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Smart Grid Challenges
• Speed of Technology Development The solar , the basement fuel cell, and the chimney wind generator were predicted 50 years ago as an integral part of the home of the future.
• Policy and Regulation The state financing the project may not always be the one benefiting most from it. Unless an attractive return on smart grid investments is encouraged, utilities will remain reluctant to invest in new technologies.
• Cooperation The challenge for diverse utilities will be the cooperation needed to install critical circuit ties and freely exchange information to implement smart grid concepts.
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The Functionalities
1. AMI 2. Smart Distribution 4. Smart Pricing
5. Demand Control
6. Building / Home automation
7. Renewable Integration
8. Plug in Electric Vehicle - Bay
9. Condition Based Maintenance
56 CPRI, BANGALORE 18-Feb-12
consumers [smart meters]
Power network & apparatus
SG Control Center
DG
Two way communication
Smart Grid Control Scheme CPRI
Two way communication
MDM CP ANALYTICS OMS PM
DA SA CBM
AMI SMART METERS HAN
SOLAR PV WIND BIO MASS 57 CPRI, BANGALORE 18-Feb-12
IT LAYER
COMMUNICATION LAYER
NETWORK LAYER
Typical System Architecture CPRI
58 CPRI, BANGALORE 18-Feb-12
Metering
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Advanced Metering Infrastructure (AMI) AMI and its role: The AMI is the nerve center of any smart grid implementation. AMI constitute Smart meters at consumer premises. Two way communication network between CC and end points. MDAS that will act as Front end to field devices and MDMS IT system comprising of HW and SW running MDMS located at the SGMC. The role of AMI is vital and would facilitate Periodic flow of customer meter data and network data in to the data base. Disseminate DSM / DR programs Facilitate MDM Customer empowerment through consumer portal
Why Immediate Attention?
• Meter data is becoming vital part in deciding many of the performance and planning parameters of utilities.
• Many of utilities are looking for automation to manage huge amount useful data generated from meters and other sources of grid/network.
• AMR is becoming part of DA/DSM/SCADA leading to AMI / Smart metering solution.
• AMR / AMI is becoming best tool to check AT & C losses and control / detect pilferages.
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Smart Meter – The Notion
• An intelligent device which enables a customer to participate in the utilities initiatives for energy management.
• The initiatives are put forth by utility through its policies and functions.
• Lead to Smart metering - Not only collecting information but also sending information.
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Smart Metering
Typical functions are:
• Interval meter data (load profile.
• Meter reading
• Meter management (reduction, disconnection, demand management, etc).
• Measurement of consumption and generation by distributed units.
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Smart Metering
• Meter parameterisation such as tariff structures, contractual power, meter interval, etc.
• Message transfer from market players to the customer - price signals.
• Information display on the meter and / or communication port for external display
• Power quality measurement (incl. Continuity of supply and voltage quality)..
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METERS THAT MATTER HOST
A BJ / KJ
HT
M4
M3 M1
M2
LT
HT
D C&I
OTHERS
SS Meters – 11/33/66/110/220/400 kV
BOUNDARY / BANK METERS - ABT
DTR
DATA
ROUTING NETWORK
FEP
FEP
FEP
Metering management
• It is crucial that the party responsible for collecting and administrating meter data makes data accessible to all other authorised market players in a non-discriminatory way.
• If the customer is expected to react to price signals, actual demand etc...then easy access to meter data, for instance on a display, is needed.
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• Automated meter reading (AMR)
• Meter Date Management (MDM)
Need for protocol
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APPLICATION
LINK LAYERS
PHYSICAL LAYER
APPLICATION
LINK LAYERS
PHYSICAL LAYER
PSTN PLC RF TCP/IP CELLULAR
1. No common meter reading protocol
2. Many manufacturers – many communication protocols.
3. Non availability of protocol information
4. Integration issues - different make meters at the field level.
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AMR impediments
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THE APPROACH • Homogeneity at meter end
• Accessibility at all times
• Interoperability
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HOST
METER WITH STANDARD PROTOCOL
Choose OPEN PROTOCOL - A General practice
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The IEC 62056 is an open protocol exclusively evolved for Metering purpose. It operates at meter level. A wide range of data types can be read either selectively or in groups. The parameters are identified through unique codes. The protocol can work with many common communication medium. The protocol implementation can be verified for conformance with the dedicated test tool. India has been aligning with IEC for standardization. In the present effort to bring in uniform protocol and based on the relative merits and demerits, IEC 62056 protocol would become the natural choice for metering purposes in India.
Open Protocols
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IEC 62056 (dlms) FEATURES
OBJECT MODELLING - COmpanion Specification for Energy Metering
[COSEM]
DATA IDENTIFICATION – Object Identification System [OBIS] & IC
MEASUREMENT COMPUTATION COMMUNICATION
METER
MANDATORY OBJECTS
ADDITIONAL OBJECTS
INSTANTANEOUS VALUES
PROFILES
TARIFF READINGS
POWER QUALITY PARAMETERS
AND OTHERS
ADOPTED BY IEC
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The smart meters shall have the following minimum features:
1. Measure and Compute electrical parameters.
2. Store and communicate requested data as per programmed interval.
3. Detect, resolve abnormal & tamper events and store the same
4. Inbuilt memory to store all relevant meter data, events for a required period.
5. Meter communication protocol shall be as per open standard.
6. Options for both Prepaid and postpaid metering.
7. Shall be configurable remotely.
8. Interface to a Home Display Unit
9. Support remote firmware upgrade
10. Support remote load management
11. Load Reconnect / Disconnect switch
• Steady state values - Instantaneous
• Dynamic values - Profiles
• Harmonics - Power Quality
• Import / Export - Four Quadrant
• Event recording / reporting
• Time Stamping
• Unit & Scaler representation
• Unique identification codes - OBIS
• Country / Manufacturer specific codes
• In built support for common communication profiles
• Access and Data Security
• Interoperable
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IEC 62056 – DLMS / COSEM –A Overview
1. Power line communication – Broadband
– Narrowband
2. Low power RF – Mesh networks - Zigbee
75 CPRI, BANGALORE
Smart meters - communication
18-Feb-12
HAN Architecture
DCU
GSM ZGW
ZC
ZC
ZC
ZC
Geyser
AC
Room Heater
Fridge
HDU Contact
or
Contactor
Contactor
Contactor
1Ø / 3Ø AC 77 CPRI, BANGALORE 18-Feb-12
Zigbee Zigbee is a new wireless technology built on the IEEE 802.15.4 networking standard for wireless personal area networks (WPANs). ZigBee is targeted at RF applications that require low data rate low power low cost Worldwide ZigBee operates in 2.4 GHz, the ISM radio bands which do not require license. The composite IEEE standard (Physical and Mac layers) and Zigbee (network and application layers) standard has enabled enormous applications for home automation, wireless sensors, automatic meter reading etc.
78 CPRI, BANGALORE 18-Feb-12
Device types
The Zigbee system is a network of three different types of generic devices namely ZigBee coordinator(ZC), ZigBee Router (ZR) ZigBee End Device (ZED). ZC - Root of the network tree , generally one per network. Store information about the network Monitor performance Configure parameters. ZR - Function as a router / intermediate router Passing data from other devices Stretching the reach. ZED - Only discharge designated function Example - controlling a light. ZED can talk to ZC or ZR Cannot relay data from other devices.
CPRI
79 CPRI, BANGALORE 18-Feb-12
Topology
Wireless Control That Simply Works
ZigBee Coordinator
ZigBee Router
ZigBee End Device
Star
Mesh
Cluster Tree
The “Topology” is the configuration of the hardware components and how the data is transmitted through that configuration. The Zigbee networking supports three topologies - Star, Mesh and Cluster Tree.
CPRI
80 CPRI, BANGALORE 18-Feb-12
81 CPRI, BANGALORE 18-Feb-12
BPLC URBAN / RURAL NETWORK
LV / MV DATA RATE > 10 Mbps
Sub station
DTR
DTR
ISP NODE
DSL INTERNET
CLOUD
MCC
11 kV
18-Feb-12 CPRI, BANGALORE 82
FOC + PLC - COMBI FOR POWER SECTOR AND INTERNET
FIBRE BACK BONE
CPE
SS
CPE
DTR
CPEs BB-ROUTER
AMR LV
10
HOST
HT
MV
DSL
DSL
50
DSL
18-Feb-12 CPRI, BANGALORE 83
Thank you
varun @ cpri.in
18-Feb-12 CPRI, BANGALORE 84