SCADA and Metering - Asea Apua 2009... · 17/11/2010 3 Key to reliable SCADA functionality A...

17/11/2010

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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 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 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?


• 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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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.


• 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


etc.etc.

Substation

Station State


n Bays

Bay counts

etc.etc.etc.

Region

Region State


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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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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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.

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Questions

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