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Transcript of SCADA and Metering - Asea Apua 2009... · 17/11/2010 3 Key to reliable SCADA functionality A...
17/11/2010
1
SCADA and Metering SCADA and Metering
UPDEA UPDEA -- Workshop Workshop
Topics
• What we measure• Substation configurations – and our evolution• Four level control vision• SCADA Data Types• Graphical data display• Telecontrol Standard• Metering• Common Information Model
What does SCADA stand for?
SCADA – Supervisory Control and Data Acquisition
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4 = Current Transformers
3 = Line Traps
1 = Voltage Transformers
2 = Breaker
1
2
3
2
4
What do we Measure?Primary and secondary plant status and indications
Primary and Secondary data
Power Station• Unit Status • Unit Output• AGC state• Gen Breaker
HV Yard• Trfr Status • Trfr Output• Bkr State• Line Flows• Isolator state• Health data• Protection data• Local Information states
LV Yard• Trfr Status • Trfr Output• Customer load• Bkr State• Isolator state• Health data• Protection data• Local Information states
What is the key to efficient SCADA systems?
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Key to reliable SCADA functionality
A resilient telecoms backbone underpins the SCADA and Metering process.
To be effective, substation data must be
collected real time and on time!
Overloaded comms links cause trouble in a
disturbance.
Independent consumption metering is ideal.
What are the four types of SCADA data?
SCADA provides: • Status Data
– Two-State Device Control such as circuit breakers, isolators, etc.– Single-State such as alarms – Six state devices, such as auto reclose relays– BCD Tap position
• Analogue Data– Megawatts, Mvars, kV, water level, flow rate
• Accumulator Data– Power station sent out Megawatts and Mvars
• Supervisory control – Device Control such as, breaker control, Auto manual.– Setpoint Device Control, Auto Reclose Relay setting– Pulse control such as AGC up or down, tap change control– Static Var Compensator voltage or Mvar set point
260160
250140
VENUS
Feeder Bay
Generator Bay4
1 & 3 Pole
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Substation Configuration and Evolution
HMI
IRIG-B
GPS Receiver
Estel Remote Terminal Unit
Sub-Station 02 Munic 1 Munic 2
Sub-Station 04
1 2
0
0
0
0
012
500
500
400
500
1600
12
200
120100
200
Gen 1
100
220
100
220
Substation ID
Todays Configuration
Station RTU
CPU
Memory
Sub-Station 02 Munic 1 Munic 2
Sub-Station 04
1 2
0
0
0
0
012
500
500
400
500
1600
12
200
120100
200
Gen 1
100
220
100
220
Substation IDSTABNAC Distribution
SMARTTEMSE Port
IEC 60870-5-101
TransformerProtection
Panel
CPU
Memory
Class 1 data collected within 5 milliseconds of state change.
Alarm any unauthorized change in the network within 4 seconds.
Time stamped data accurate to 1/1000 second
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Bay Processor
ERTU
Remote Terminal Units
Tomorrow’s Configuration
Estel Remote Terminal Unit
GPS Receiver
IRIG-B
HMI
Station RTU
CPU
Memory
]]]
]]]]]]
]]]]
]]]]]]]
]]
]]]]
D20 Station RTU
IEC 61850 LAN
D25 Bay Controller
Sub-Station 02 Munic 1 Munic 2
Sub-Station 04
1 2
0
0
0
0
012
500
500
400
500
1600
12
200
120100
200
Gen 1
100
220
100
220
Substation ID
TransformerProtection
Panel
CPU
MemoryD25 Bay Controller
National Control TEMSE
IEC 60870-5-101
Distribution ABB
DMP3
STABNACIEC 60870-5-101
D400
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PPPLocal Engineeringvia Substation LAN
Remote Engineeringvia GPRS link to Substation LAN
Local HMI (via Browser)Technical Services
Substation Control System in 10 Years
IEC 61850 Station LAN
GPS Receiver
Station Level
(S)NTP Time Synchronization
]]]
]]]]]]
]]]]
]]]]]]]
]]
]]]]
Bay Level
Process Level
Bay Level
CommsAC/DC Supply
+ -
Distribution ABB
DMP3
National Control TEMSE IEC 60870-5-101
Feeder 6Mercury 1
Feeder 3Gamma 1
Reactor 6
Reactor 3
765KV Mercury 1Interconnectorbusbar
765KV Gamma 1Interconnectorbusbar
Feeder 2Hydra 1
Transformer 21
Feeder 1Beta 1
Transformer 21765KV Interconnectorbusbar
765KV Beta 1Interconnectorbusbar
765KV Reactor Transfer busbar
765KV busbar 1
765KV busbar 2
Perseus765 kV
BusbarReactor 1
234132
234132
300200
300200
150
150150
Breaker and a half
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Four Level Vision
NationalControl Centre
Four Level VisionTEMSE
DistributionControl Centre #1
SMART
DistributionControl Centre #n
SMART
SubstationControl #1
ERTU
SubstationControl #n
ERTU
ReticulationControl #1
PMRTU
ReticulationControl #n
PMRTU
Level 1
Level 2
Level 3
Level 4
Estel Variant Protocol
Future Inter Control Centre Protocol
StandbyControl Centre
DMP3 Protocol
TEMSE
IEC 60870-5-101
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Levels 1- 4
• Level 1 : National and Standby control centres (220kV to 765kV).
• Level 2 : Distribution control centres (33kV to 132kV). – SMART (Standard Master for Regional Telecontrol).
• Level 3 : Substation control systems– Based on the Enhanced Remote Terminal Unit (ERTU) being replaced GE
Harris D400 Gateway.
• Level 4 : Reticulation control. (33kV and below). – Final link in the chain of supply to the end customer.
– Includes pole mounted SCADA (PMU) systems protection purposes and permit sectionalising of lines when attempting to isolate faults.
Pole Mounted Units• A pole mounted RTU (PMRTU) is based on
conventional SCADA principles and has 3 main elements:– stand alone central controller or master station– a number of remote terminal units in the field– a UHF radio based communications network.
• The RTU acts as the interface to the pole mounted devices with a mechanical actuator where no built-in telecontrol interface exists.
• Uses a common protocol, known as the Estel Variant protocol.
• The current central controller can act as a stand alone device.
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SCADA Data Types
SCADA Data Types
Status Data– Two-State or double bit Device such as
circuit breakers, isolators, etc.
– Single-State such as alarms and indications
– Six state devices, such as auto reclose relays.
– BCD Tap position indication
1/400
2/400
1/275
2/275
Bay 1
Atlas 2
Trfr 1
CPLR 1
CPLR 2
Sect 1A B
1
2
3
4
5
500280
128012
1 & 3 Pole500280
Aut
M
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Double Bit Points – RTU sideDouble Bit points have a different meaning at the RTU and at the front ends
You need two bits for each state for two state devices at the ERTU, e.g. a breaker
S X Open = 0 1Close = 1 0In transit = 0 0Don’t Believe = 1 1
(S = Status, X = extended)
At the ERTU two bits are used to indicate the combined state of the device.
RTUs x nCPU
12 v
Memory
X.21 1200/9600 b/s
Back Ends
TCP/IP
Rapid re-routing communications cloud
HMI HMI HMI HMI HMI
Front Ends
Front Ends
X.21
Double bit indication
Double bit State
How many bits are used to model a 2 state device in the SCADA back end?
Double Bit Points – DB sideFront end the bit states:
S XOpen = 0 0Close = 1 0In transit = 0 1Don’t Believe = 1 1
Extended bit X = Health Status bit S = Device
Why is it necessary to do a conversion at the Front End from 2 bits to 1 bit for the state of the device?
We only want one structure in the data base for single bit and double bit values.
You need two bits for each state for two state devices at the ERTU
S X Open = 0 1Close = 1 0In transit = 0 0Don’t Believe = 1 1
Extended bit X = Health Status bit S = Device
Point ID Type State Bad Old Date Suppress
Alpha_ Beta 1 Breaker Open No Yes 18 March No
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We have Six State ARC relays that have 6 states.
Four of the states are controllable
The states are
1. Manual
2. Closing off
3. 1 Pole
4. 3 Pole
5. 1 + 3 Pole
6. Unknown
Six Bit status devices
1. In what form is the data sent back to the control room?2. How should it be represented at the RTU?3. How should it be represented in the data base?
Controllable
Six Bit status devices
1 In what form is the data sent back to the control room? Digital
2 How should it be represented at the RTU? Digital
3 How should it be represented in the data base Table Index
0 0 0 = Closing Off0 0 1 = 1 Pole0 1 0 = 3 Pole0 1 1 = 1 + 3 Pole1 0 0 = Manual1 0 1 = DBI1 1 0 = DBI 1 1 1 = DBI
01234567
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Hexadecimal
Where does the word Hexadecimal come from?
What is an 8 bit number is called?
Octal = 8 bits
• Hex = 6• Decimal = 10• Hexadecimal = Number 16
• Byte = 8 bits• Nibble = 4 bits• Bit = 1 binary digit
Hexadecimal
0 0 0 0001 1 0 0012 2 0 0103 3 0 0114 4 0 1005 5 0 1016 6 0 1107 7 0 111
8 8 1 0009 9 1 00110 A 1 01011 B 1 01112 C 1 10013 D 1 10114 E 1 11015 F 1 111
N10 N16 23 22 21 20
8 Bits = 1111 1111 = FF = 27 = 255 Or 1 0000 0000 - 1 = (28 -1) = 256 - 1
What is the value of an 8 bit number when all the bits are 1?
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Binary Coded Decimal
The BCD Number System is used to measure tap positions where the decimal numbers 1 – 10 have specific bit values in the Hex format.
What number format is used to measure are tap positions?
Binary Coded Decimal
• Each decimal digit is assigned to 4 bits.• It is NOT a number base in the sense that binary, octal
and hexadecimal are• Leading 0s must be included as they are vital to the
conversion.
0 0 0 0 0 01 1 0 0 0 12 2 0 0 1 03 3 0 0 1 14 4 0 1 0 05 5 0 1 0 16 6 0 1 1 07 7 0 1 1 18 8 1 0 0 09 9 1 0 0 1
N10 N16 23 222120
What would the BCD encoding for the number 127 be:
H T U 0001 0010 0111
1 0 0 = 1002 0 = 20
7 = 7
How are numbers represented in BCD format?
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Binary Coded Decimal
1. The binary patterns 1010 through 1111 do not represent valid BCD numbers, and cannot be used.
2. A, B,C,D,E
1. Examining Hex values which Hex numbers are not used in BCD coding?
2. What are the equivalent Hex values of these numbers.
Binary Coded Decimal
• Where do use BCD formats and why?• What would be the range of the numbers needed• What is the numerical value of the bits in position 5 and 4 (25 24 23 22 21 20)• What is the BCD value of 31
1. Transformer Tap Positions2. Normally between 1 and 323. 10 and 204. 11 0001
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SCADA Data Types - Analog
Substation Analog values• Megawatt • Mvar• Amps • Voltage• Frequency• Transformer oil temperature (actual values)• Transformer Tap position• Conductor Temperature (New)• Dam Water Level
Derived analog value alarms• Area Loads• Tap changer rate of change
260160
250140
VENUS
Feeder Bay
Generator Bay
4
Digital to Analog Conversion
- 4000 Counts+ 4000 Counts
+ 2000 MW
- 2000 MW
+ 1000 Counts
If the counts from the ERTU is 1000 what is the engineering value?
y = mx + c where m = 2000 : c = 04000
Y = 2000 x 1000 + 0 4000
= 500 MWs
CTVT
MW Mvar
Analog
Analog
RTU
Host I/O
Digital Counts
Transducer
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Graphical data display
Alarm Data Categories
1. Health ( Only real Alarms)2. Unit Protection 3. Non – Unit Protection 4. Information 5. Device state6. Communications7. Analog8. Tap position9. Station 10. Secondary AC/DC
Following an examination of substation data the following data categories were identified
Health
UnitProtection
Non UnitProtection
Information
All data points are assigned to one four alarm category types i.e.
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Abnormal State Propagation
Device
Four IconCategories
Element data by category
Device State
n Healthn Main Prot.n Backup Prot.n Information
Element counts
BaysBay State
Device counts
n Devices
n Healthn Main Prot.n Backup Prot.n Information
etc.etc.
Substation
Station State
n Healthn Main Prot.n Backup Prot.n Information
n Bays
Bay counts
etc.etc.etc.
Region
Region State
n Healthn Main Prot.n Backup Prot.n Information
n Substations
Substation counts
etc.etc.etc.
Notify the control staff of existence abnormal conditions on the station one line diagramsAllow them to examine the abnormal data when they want to.Upwardly summate the category counts and display the counts as icons at each level.
One line display showing device, bay and station ic ons
Isolators has health and information icons
Note the device information icon next to the Transformer as well as the parent Transformer Bay and at next to the station name.
The station bay has active health alarms
Transformer had a fault and tripped.
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Bay
Bay State – What is it?
Bay States1. Disconnected : All links open (Don’t care about BKR )
2. Isolated : Bus links closed – Line Link Open
3. Connected : Links closed – BKR Open
4. Dead : Link & BKR Closed kV <= 0
5. Energised : Link & BKR Closed kV > 0
6. On load : Link & BKR Closed MW > 0
7. Bypass : Bypass Link closed , Line link open
8. Mvar only : Links & BKR Closed MW = 0 and Mvar > 0
9. Unknown : Analogs <> Status
10. Increasing (s) : Value is approaching limit (20 min)
11. Increasing (f) : Value is approaching limit (10 min)
12. Will Trip in 5 : Bay will trip bay in 5 minutes
Atlas
MajubaMunic 1
Jupiter
1 2
00
00
012
400320
400320160012
120
200
Gen 1
100120
Venus
Munic 2
Bay State
MOLL
BKR
MOL1
MOL2.OR.
.AND.
.AND.
(MOLL & BKR) & (MOL1 | MOL2) & (kV | MW | Mvar)
IED
IED
IED
IED
Do we tell the control staff about the breaker state when the bay is disconnected?
12 3
65
7 4
Bay State Benefits
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Tele-control Standard
Transformer Standard (1)Isolator_1 01_State 10_State Category Type Bin Aud CtlIsolator State Closed Open Info Double Log_only TruePole Disagree Normal Health Single Protect
Isolator_2 01_State 10_State Category Type Bin Aud CtlIsolator State Closed Open Info Double Log_only TruePole Disagree Normal Health Single Protect
HV_BKR 01_State 10_State Category Type Bin Aud CtlAC Supply Failed Alarm Normal Info Single DC_SupBreaker Failed to Trip Alarm Normal Main Single Breaker YesBreaker State (ERTU) Closed Tripped Info Double Breaker Yes TrueBreaker Unhealthy Alarm Normal Health Single BreakerBus Zone Trip Alarm Normal Info Single Bus_Zone YesDC Supply Failed Alarm Normal Health Single PanelEarth Applied Alarm Normal Health Single PanelExternal to Unit Protection Operated Normal Main Single ProtectPole Disagree Normal Health Single ProtectProtection Abnormal Alarm Normal Health Single ProtectProtection Operated Alarm Normal Main Single ProtectProtection Unhealthy Alarm Normal Health Single PanelSF6 Gas Critical Alarm Normal Health Single Breaker YesSF6 Non-urgent Alarm Normal Info Single BreakerSupervisory Isolated Off Info Single Panel
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Transformer Standard (2)
Current Trfr 01_State 10_State Category Type Bin Aud CtlSF6 Gas Critical (CT) Alarm Normal Health Single CT YesSF6 Non-Critical (CT) Alarm Normal Health Single CT
Transformer 01_State 10_State Category Type Bin Aud CtlAmps Info Analog Panel No FalseMegavars Info Analog Panel No FalseMegawatts Info Analog Panel No FalseTap position Info BCD Trfr No True
Bucholz Alarm Normal Health Double TrfrCooling Failed Normal Health Single PanelDifferential Protection Alarm Normal Backup Single PanelOil Level Low Normal Health Single PanelOver Current/Earth Fault Alarm Normal Main Double PanelRestricted Earth Fault Alarm Normal Main Single PanelTap (a/m) State Auto Manual Info Single Log_only TrueTap out of Step Alarm Normal Health Single TrfrTemperature High Normal Health Single Panel
Metering
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Metering Scheme Components
Meter equipment
Miscellaneous meter equipment
Ancillary meter equipment
DataValidation
LOAD
Meter pulses
VTCT
SUPPLY
Junction box
Junction box
VT supply cablingCT supply cabling
Meter datacapturing
Billingsystem
Accuracy Class
Load Accuracy Class
Active Energy Meter
Reactive Energy Meter
CT VT
> 100MVA 0.2 1 0.2 0.2
10 MVA to < 100 MVA
0.5 2 0.2 0.2
1 MVA to < 10 MVA
1 2 0.5 0.5
100 kVA to < 1 MVA
1 3 0.5 0.5
< 100 kVA & Whole current
2 3 1 (where applicable)
-
Transmission Loads
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Metering Data Management SystemGeneratorsDistributors International REDs
IPPs
Data Management
Data Acquisition
Data Dissemination
Customer Application
• Second Line Verification & Validation of Data
• Data Warehousing • Data Management
(Profiling,Totalisation & Mapping) • Reporting • Access Control • Audit Trails
• Remote Acquisition of Metering Data
• First Line Validation of Data • Limited Storage of Data
• Transfer of Data to Customer • Stakeholder Systems • Web viewing of metering
information
Common Information Model
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Common Information Model
1. Why does it cost so much to buy an EMS?2. Can you take different software packages from one EMS vendor and load
them on to a different EMS platform?3. How can the problem be overcome – two reasons?
1. You can’t buy shrink wrapped software for SCADA systems2. No because every vendor’s data is unique3. By agreeing to a standard way of modelling the data interface4. Defining a common software interface definition
Overall structure of an EMS
S1S 2S 3S 4
A 2
A 4
S 5S 6S 7S 8A 1
A 5
A 3
A 6
Status RecordStatus RecordStatus RecordStatus RecordAnalog RecordAnalog RecordAnalog RecordAnalog RecordStatus RecordStatus RecordStatus RecordStatus RecordAnalog RecordAnalog Record
Host SCADAData Base
Raw dataEngineering data
One Line Display
Data base
BrowserProcess
23123434
Commslink
Scanner Process
Alarm Process
Control Process
S1S 2S 3S 4
A 2
A 4
S 5S 6S 7S 8A 1
A 5
A 3
A 6
RTU
Host I/O
Raw data in the RTU DB
New Process
?
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Common Information ModelS1S 2S 3S 4
A 2
A 4
S 5S 6S 7S 8A 1
A 5
A 3
A 6
Status RecordStatus RecordStatus RecordStatus RecordAnalog RecordAnalog RecordAnalog RecordAnalog RecordStatus RecordStatus RecordStatus RecordStatus RecordAnalog RecordAnalog Record
Host SCADAData Base
New Process
• A standard developed by the electric power industry that aims to allow application software to exchange information about the configuration and status of an electrical network.
• The CIM is currently maintained as a UML model and defines a common vocabulary and basic ontology for aspects of the electric power industry.
• The central package within the CIM is the 'wires model', which describes the basic components used to transport electricity.
Integration Bus
Purpose
Need a common way to represent the Data to be exchanged –It is called the CIM or Common Information Model
The CIM is:– a data model defining all relationships– background map for information exchange
CIM is not :– a database (object or relational)– the end of the road
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Common Information Model
The central package within the CIM is the 'wires model', which describes the basic components used to transport electricity.
Generation
Domain<<Global>> Wires LoadModel
Core
Meas
Topology
Outage
Protection Financial EnergyScheduling
Reservation
SCADA
CimVersion
Version : String = cim10_010806LastUpdate : String = August 6, 2001
(from CIM)
Common Information Model• Individual application components are interconnected via a component execution system
and component adapters.
• They provide the infrastructure services needed by the components to discover and communicate with each other and with the public data stores in the various EMS contexts.
Programs
PublicData
ICCPNetwork
ICCP
UserPCs
Programs
PublicData
DistributionManagement
SystemsComponentInterface
SCADANetwork
AlarmProcessor
LoadManagement
GenerationControl
Accounting/Settlement
NetworkApplications
TopologyProcessor
Legacy System
Public Data
Programs
Public Data
Programs
Public Data
Programs
Public Data
ProgramsCIM Server
Public Data
Public Data
Programs
Legacy Wrapper
Programs
Component Execution System and Component Adapters (e.g., Integration Bus)
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3 Aspects to consider for a reliable SCADA service
Reliable SCADA service
Technical Aspects
1. Substation monitoring with battery backup
2. Reliable tele-communications infrastructure
3. SCADA master with ability to survive disturbances
4. Trained control staff that know how to deal with disturbances
5. Battery backup for control room and computer room
6. Hardware and software maintenance plan
7. Available and appropriate spares budget
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Reliable SCADA service
Human Resources
• Trained and motivated
– Substation Remote Terminal Unit (gateway) support staff
– SCADA computer support staff (hardware, software and web)
– Telecommunications support staff
– Engineering support staff
• Management support
• User Group participation – documentation
• Procurement system that works for the control room
• Educate the buyers about your business
Educate the Business (in house)
Education
• Your business is NOT Information Technology (IT) – that is some one else's business.
• Your business is Process Control in a big way.
• Most of the time your business division don’t even known you exist.