Scada Ab & CD Slides

SCADA / DMS

DISCOM’S SUB STATIONS & DISTRIBUTION NETWORK

MASTER CONTROL CENTRE DISASTER CENTRE

Load Shed Application (LSA)

Fault Management and System Restoration (FMSR)

Loss Minim.via feeder reconfiguration (LMFR)

Load Balancing via feeder reconfiguration (LBFR)

Network Connectivity Analysis (NSA)

Load Flow Applications (LFA)

State Estimation (SE)

Voltage VAR Control (VVA)

Operation Monitor (OM) Distribution Load Forecasting (DLF) Dispatcher Training Simulator(DTS)

Contents

Introduction

Historical Developments

Over view of Power Networks

Protection Systems

SCADA Systems - RTU

Communication Systems & Security issues

Contents (Contd.)

Distribution Automation

Quality Assurance

Utility IT Requirements

Case Study

Q & A – Discussions

Introduction

Stages involved in Power Distribution

AU

TOM

ATION

Sub Transmission System

132-66kV

66-33 kV 11kV 11kV

440-220 V 11kV-440 V

Distribution Operations

Monitoring the power system

Making adjustments and maintaining the system so that it can be used reliably, efficiently, and safely

Repairing the system as quickly as possible in response to incidents such as equipment faults

Tracking and maintaining system reliability data

System planning and expansion to serve new customers

So, within this context, objectives may be summarized as follows.....

Objectives

Consistent with National Electricity Policy, to improve reliability and quality of service of distribution system by

Reducing frequency and duration of power interruptions to targets consistent with best international practice

Maintaining power quality with respect to voltage and frequency excursions

To operate efficiently and safely by

Minimizing power losses

Applying manpower resources effectively

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

SCADA/DMS Functional/Architectural Overview

Corporate Data Accessibility and

Availability

CPRI-UARC

R

T

U

R

T

U

Primary Plant

Interface

KEY ELEMENTS of DMS

Data & Control

Pathway

Communications

Town Master Station

Substation

1 2

3

4 MPLS/MLLN

GPRS/

CDMA

MPLS

F

R

T

U

1

2 RTU

3

4

Communications

Master Station

Line

5

5 Control Room,

Corporate Usage,Backup, LD

Control Room

Operators

Outage Analysis

Operational analysis,

decisions, issue controls

5

MPLS / MLLN

DR Centre SLDC

Reporting

Analysis



• SCADA system is in use since a long time (with conventional telephone technology)

• Deployment of SCADA system accelerated with the development of microprocessors

• Present day SCADA system are based on compact RTUs and latest communication technology including mobile communication system.

Historical Developments (contd.)

• SCADA Communication protocol development started with proprietary from industries and users.

• To make interoperable, DNP protocol emerged as open protocol standard during early 1993 in USA and Canada

• During same period, IEC 60870 -5 has also emerged as international standard for SCADA applications

• IEC 61850 series of standard is now available for IEDs.

PROTECTION OF POWER SYSTEM

The basic function of a relay or protection

equipment is to detect and isolate the fault section at

the earliest so that continuity of supply is restored in

the rest of the system.

Faults in Power System

Faults can be either symmetrical or asymmetrical or

unbalanced.

• Symmetrical faults involve all three phases

• Asymmetrical faults include phase to phase, phase to

phase to ground or single line to ground.

Protective Relays

that protect power systems from

faults:

Short circuits

other abnormal conditions

underfrequency, overvoltage, etc.

To sense the abnormal conditions

Initiate the isolation of faulty section

PROTECTION REQUIREMENTS:

Protective relays should be :

• RELIABILITY

DEPENDABILITY

SECURITY

• SELECTIVITY

• SENSITIVITY

• STABILITY

• SPEED

• COST

• Design should achieve balance

Over Current Protection

There are two types of over current relays

• Instantaneous (50)

• Time over current

Protection of Radial system by Over current relay

51 51 51

Fault

B1 B2 B3

Differential Protection • Differential protection is a unit type of protection.

• It is a very reliable type of protection used for protection of Transformers,

Bus bar and Transmission lines.

Protected

Equipment

Relay

Distance Protection

• A distance relay operates based on the measurement of the impedance.

Impedance measuring relays are used when over current relays do not

provide adequate protection or short circuit current is low, the operating time

is independent of the current magnitude.

R

X

Plain impedance characteristic

Modified characteristics are given in Figure

Quadrilateral characteristic

Zones of Distance protection

Zone1

Zone 2

Zone3

t2 t3

Zones of Distance protection

• Zone1 – Upto 80 to 90% of protected line with no intentional time delay

• Zone 2 – Up to 50 % of the adjacent line from remote end delay 0.3 sec to

0.5 sec

• Zon3 – up to 100 % of the adjacent line + 25 % of second line delay 0.6

sec to 1 sec

PROTECTIVE RELAY

TECHNOLOGY

ELECTRO

MECHANICAL

STATIC DIGITAL

NUMERICAL

Self-supervision

Setting groups

Programmable logic

Adaptive schemes

Multiple protection characteristics

Communication capability

Instrumentation features

FEATURES OF NUMERICAL RELAYS

Classification of relays by construction type

Based on type of construction relays can be classified into

• Electro magnetic

• Solid state

• Microprocessor

• Numerical

Modern Numerical relays are built with integrated functions. Advantages of

Numerical relays are: • Reliability

• Multi-functionality

• Self diagnosis

• Events and disturbance recording facility

• Communication capabilities

• Adaptive protection

Electromechanical / static versus Numerical Relays

Electromechanical & Static Relays

Numerical Relays

Single Function – Single Characteristic

Multiple Functions – Multiple Characteristics

Dynamic change of protection characteristics not possible

Dynamic change of protection characteristics - programmable

Only fault detection, isolation & location

Additional features of Control, Metering, Monitoring and communication

Numerical relays in Substation automation environment

• In an substation automation environment, Numerical relays help in

visualizing and understanding the fault and operation. Logics can be

configured in the relay for having effective control and protection of the

system with out hard wiring. Multiple relay settings groups in Numerical

relay can be utilized for faster power restoration in emergencies.

• Adopted relay settings for standard power flow will not be suitable for

emergency load management. During such situations second relay

setting group with suitable relay setting can be adopted. Through

station automation group changing can be done from remote HMI and

power restoration through different network is faster with suitable relay

settings.

• On-line relay settings and fault data record down loading is possible.

Faster tripping diagnosis makes faster restoration of system and

immediate corrective actions possible.

Supervisory Control and Data Acquisition

(SCADA)

SCADA Functions:

• Time synchronization of RTUs,, FRTUs & FPIs(if time synch is

supported in FPI)

• Data Exchange among the various SCADA/DMS sub-

system(legacy), IT systems, State load dispatch centres.

• Data Processing

• Continuous real-time data storage and playback

• Sequence of event processing

• Supervisory Control

• Fail-soft capability

• Remote database downloading ,diagnostics & configuration

• GIS adaptor

• Information Storage & Retrieval (ISR)

• Historical Data information & Retrieval and

• Data recovery (DR)

REMOTE TERMINAL UNIT(RTU)

• Microprocessor based equipment or intelligent device

• Acquiring field data & monitoring

• Transmitting telemetry data to the Control Centre

and/or altering the state of connected objects based on

control messages received from the Control Centre.

The functions of RTU’s integrated into the design include:

• Circuit Breaker Control

• Feeder monitoring

• Feeder protection sequences

The salient features include

• Programmability

• Sequence of Events (SOE) Recording

• Programmable Logic Functions

Data Acquisition

RemoteTerminal Unit

HARDWARE CONNECTIVITY DIAGRAM FOR SCADA

AT SUBSTATION RTU

MAIN CPU

BOARD PSU

COMMN BOARD

A N A L O G I / P

D I G T A L I / P

C O N T R O L O/P

TERMINAL BLOCK

TERMINAL BLOCK

TERMINAL BLOCK

REMOTE TERMINAL UNIT

TRANSDUCER O/P TERMINAL

MVAR VOLT MW

TRANSDUCER I/P TERMINAL P T SEC

110VAC

CT SEC 1 AMPS

F R O M

S W I T C H Y A R D - F I E L D

EVENT LOGGER PANEL

D R I V E R

R E L A Y

TRANSDUCER PANEL

COM PORT

R

T

U

Pictorial view

SCADA Human–Machine Interface

(HMI)

• A HMI is the apparatus (Monitor / Display system)

which presents process data to a human operator,

and through which the operator controls

• Usually HMI will be situated in the Master Control

Centre or it can be even at substations where the

system can be monitored & controlled.

Communication Systems

• Communication system is vital for any SCADA / DMS

system

• Communication between Master Controller Centre

and RTUs (substations) and FRTUs (at feeder –

RMU/Sectionlizer/Autoreclosure locations)

• Control signal flow, status (digital) and analogue

signals (measurends like bus voltage, feeder current,

power, reactive power, energy consumption etc.)

Communication Systems

• Data Acquisition - RTU/FRTU/RMU/FPI’s

• Time Synchronization – RTU/FRTU/FPIs

• Data Exchange – IT System under RAPDRP

• Continous real time storage & playback

• SOE

• Supervisory Control

• Remote database downloading, diag.& config

• CIM Compliance IEC 61968

• GIS Adaptor – to support native adaptors, CIM/XML using Model & Data Exchange over IEC 61968

Enterprise SOA based bus

• ISR

• LDC & DR

• DAS

• LAN

SYSTEMS REQUIRING COMMUNICATIONS

SYSTEMS REQUIRING COMMUNICATIONS

COMMUNICATIONS OPTIONS

SCADA FUNCTIONAL REQUIREMENTS


ENVIRONMENTAL REQUIREMENTS

COMMUNICATION REQUIREMENT ELEMENTS



SCADA TOPOLOGY


REQUIREMENT OF STANDARDS


UCA AND IEC 61850 PROTOCOLS


DESIGN FACTORS FOR COMMUNICATIONS


TRANSMISSION MEDIA CLASSIFICATIONS


Electromagnetic Spectrum for Wireless Transmission


Electromagnetic Spectrum for Wireless Transmission


Conducted or Guided Media Transmission

Communication Technologies

Public communications

• Dedicated Leased Telephone Line from service providers like BSNL.

• GSM/EDGE/GPRS / CDMA / 3G communication from Service

Provider like BSNL, Airtel etc.

Utility owned communications

• Distribution Line carrier Communications (DLC).

• Dedicated Utility Multiple Address Radio Communications (MARS).

• Optical fiber cable (OFC) communication run on overhead lines /

underground power lines

• Satellite Communications ( VSAT)

Public Telephone Communications:

• Two way communication system with data rate of 64

kbps to 8 Mbps with leased lines

• Good reliability in urban areas.

• Suitable for substation SCADA.

GSM/ GPRS/ CDMA

• Availability of Multiple mobile telephone operators in

urban locations

• Best suited communication for widely scattered devices in

distribution network like DTR’s, FRTUs,Switches etc.

• Low capital cost and only (low) recurring charges based

on usage.

Optical Fiber cable • Arial self supporting outdoor Optical Fiber cable are freely

suspended on utility 33 kV poles connecting substations and

control centre in in ring / mesh topology

• Protective outer jacket with one messenger and one fiber cable

which contains 4 /6/8 strands of multimode fibers.

• Ease of installation and reduces time and cost.

• Gigabits of band width and highly reliable and secured

communication medium with free from all interference

• High capital costs

RTU to Central Monitoring Station

IBM Compatible

Modem

Modem

COMMUNICATION LINK

SCADA Schematic Diagram with fiber links

FO Substation to Control Centre

FO

wit

hin

S

ubst

atio

n

Multi Access Radio Systems (MARS):

• MARS is usually owned by the utility,

• Require license from the authority of (in India Wireless Planning & Coordination)

• Consist of a master radio which communicates with several remote radios.

• Master is located at central place on mast of adequate height such that line of sight is

available for a radius of about 30 km all around.

• Master will be able to poll about 1000 remotes in the area and perform SCADA

function.

• It is a two way communication system

• It is primarily intended for data communication.

• Voice communication with master is provided by means of hand sets that can be

plugged into remote unit.

• During the period of voice communication, the polling will be interrupted. Therefore

voice usage is restricted to system emergencies only.

• Each system uses a pair of frequencies, one for master to remote communications

and the other for remote to master, so that one outbound and one inbound

transmission can occur concurrently.

• Frequency bands of 400 MHz, 900 MHz, 2.4 GHz and 5 GHz

Satellite Communication (VSAT)

• A satellite communication system using Very Small Aperture Terminal (VSAT)

• VSAT is a point to multipoint star network like TDMA.

• Consists of one single Hub and number of remote Personal Earth Stations

(PES).

• Communication system between Hub and remote PES is through two

separate radio links.

• The link from remote PES to Hub is called as ‘in bound’ and from Hub to the

remote PES is called as ‘out bound’.

• The in route bandwidth is 64-128 KBPS and out route band width is 128 – 512

KBPS, which is shared by a number of PES using TDM.

• Data from central Hub is broadcast to all remote PES, which are in listen

mode. Each remote VSAT listening to the Master will decode only the data

addressed to one of its ports.

• Satellite transponder acts like a repeater between hub and remote

• No end user transmission either originates or terminates at the satellite.

• In India extended ‘C’ band with up link in the 6.315/6.815 GHz and down link

in the 4.09 / 4.59 GHz range is used.

• The Multi Frequency Time Division Multiple Access (MFTDMA) is the latest

technology which uses optimum bandwidth for communication.

The structure of SCADA Communication

Protocol

• ISO/IEC 7498 - 1994 Open Systems Interconnection(OSI) basic reference

model for communicational

• seven layers

7- Application Layer : SCADA application, DMS

6- Presentation Layer: Common data representation

5-Session Layer: Connection between end users

4 -Transport Layer: end-to-end reliable delivery

3- Network Layer: routing & relaying data

2- Data Link Layer: error free transmission

1- Physical Layer: physical data path

Standard Protocols

• IEC 60870-5 -101 (Serial Communication)

• IEC 60870 – 5-104 (Ethernet compatible Network communication)

• IEC 61850 Network compatible communication for IEDs

• DNP 3

SCADA Security issues

• Vulnerable due to

• Adoption of open standards for protocols & open

solutions and moving out from the proprietary

technologies

• Increased number of connections between SCADA

systems and office IT networks

• Web interface to SCADA Systems

• the lack of concern about security and authentication

in the design, deployment and operation of some

existing SCADA networks

• Myths

• SCADA systems have the benefit of security through

obscurity through the use of specialized protocols and

proprietary interfaces

• SCADA networks are secure because they are physically

secured

• SCADA networks are secure because they are

disconnected from the Internet.

Security concerns in SCADA systems

• SCADA security policies

• Firewall architecture, DMZ, and rule based

• Secure remote access to a control center

• SCADA protocol security issues

• Securing field communications

• User authentication technologies and integration with SCADA applications

• Access control principles and implementation

• Active Directory integration with SCADA applications

• Detecting cyber attacks on SCADA systems

• Vulnerability scanning

• Security patch management

• Anti-virus protection and management

• Exceptions – what to do when you can’t implement best practice

• SCADA security standards

21 Steps to Improve Cyber Security of SCADA

Networks 1. Identify all connections to SCADA networks.

2. Disconnect unnecessary connections to the SCADA network.

3. Evaluate and strengthen the security of any remaining connections to the SCADA

network .

4. Harden SCADA networks by removing or disabling unnecessary services.

5. Do not rely on proprietary protocols to protect your system.

6. Implement the security features provided by device and system vendors .

7. Establish strong controls over any medium that is used as a backdoor into the

SCADA network .

8. Implement internal and external intrusion detection systems and establish 24-hour-a-

day incident monitoring .

9. Perform technical audits of SCADA devices and networks, and any other connected

networks, to identify security concerns .

10. Conduct physical security surveys and assess all remote sites connected to the

SCADA network to evaluate their security.

11. Establish SCADA “Red Teams” to identify and evaluate possible attack scenarios .

Contd….

12. Clearly define cyber security roles, responsibilities, and authorities for

managers, system administrators, and users.

13. Document network architecture and identify systems that serve critical

functions or contain sensitive information that require additional levels of

protection.

14. Establish a rigorous, ongoing risk management process.

15. Establish a network protection strategy based on the principle of

defense-in-depth.

16. Clearly identify cyber security requirements.

17. Establish effective configuration management processes.

18. Conduct routine self-assessments.

19. Establish system backups and disaster recovery plans.

20. Senior organizational leadership should establish expectations for cyber

security performance and hold individuals accountable for their

performance.

21. Establish policies and conduct training to minimize the likelihood that

organizational personnel will inadvertently disclose sensitive information

regarding SCADA system design, operations, or security controls.

Interrelationship of IEC 62351 Security

Standards and the TC57 Protocols

Distribution Operations

– Monitoring the power system

– Making adjustments and maintaining the system so that it can be used reliably, efficiently, and safely

– Repairing the system as quickly as possible in response to incidents such as equipment faults

– Tracking and maintaining system reliability data

– System planning and expansion to serve new customers

Objectives

• Consistent with India’s National Electricity Policy, to improve reliability and quality of service of distribution system by – Reducing frequency and duration of power

interruptions to targets consistent with best international practice

– Maintaining power quality with respect to voltage and frequency excursions

• To operate efficiently and safely by – Minimizing power losses

– Applying manpower resources effectively

Reliability Factors

• Reliability depends on many factors which include

– What causes faults such as • Equipment malfunction, animals and vegetation overgrowth

causing short-circuits, human error (e.g., cable strikes, cars

hitting poles), storms/earthquakes, etc.

– Distribution system characteristics such as • Underground and/or overhead feeders, open-loop structure,

availability of alternative sources of power, equipment

ratings, component failure rates, number of cable joints,

effects of ageing, etc.

Outage Time Around the World (minute/year)

462

90 7758

11

0

50

100

150

200

250

300

350

400

450

500

Example (without

DAS)

USA UK FRANCE JAPAN

Average Outage Time per consumer per annum

Example Causes of Failure (From a US Electric Utility)

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

Example Failure Rates (From a US Electric Utility)

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

Example Failure Rates (The Netherlands Year 2007)

MV Failure Rates in 2007 – The Netherlands

Cable Type Circuit km No. of Failures Failures Per km

Per Year

XLPE 18,316 127 0.0069

PILC 105,970 1,125 0.0106

Reliability Factors (Cont.) – Repair response times such as

• Time to detect fault and notify field crew

• Time for crew to travel, then find and isolate fault

• Time for crew to restore service to some and finally all

customers affected by the fault

– Reliability strategies such as those based on • Use of circuit breakers, automatic reclosers, fuses,

sectionalizing switches, fault indicators, animal guards, etc.

• Maintenance programs, e.g., inspections, tree trimming, real-

time condition monitoring

• Trouble call, outage management, automation systems

Basic Scenario

• Consider the following scenario where distribution operations as at rely on manual operations – Fault indication and/or trouble call received

– Crew dispatched by radio and/or telephone to • Locate fault by inspection and/or other check-out procedures

• Repair damage and return system to pre-fault state

– Crew may also close upstream and downstream switches to restore power to as many customers as possible prior to repairing damage

Reliability Strategies

• Given the basic scenario just discussed, strategies for improving reliability fall into two basic categories

– Reducing frequency of fault occurrence • Use properly selected and maintained distribution equipment

• Reconfigure, replace, or upgrade equipment as necessary

• Use appropriate devices to prevent faults from occurring or at least reduce the number of customers affected

– Minimizing fault repair times • Call centers to allow customers to report outages

• Computer-based Outage Management Systems

• Computer-based Feeder Automation Systems

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

Present Operations ( Average time to restore Power Supply 40 Minutes )

Circuit Breaker

R/S feeder R/S feeder

Normally open point

RMU / DT

R/S feeder

Circuit Breaker

R/S feeder

Normally open point

Supply restored manually for part

network typical time 15 – 20 mins

Circuit Breaker


Normally open point

RMU / DT

CB Trips on fault

Circuit Breaker


Normally open point now closed manually

Additional network restored

manually, total time 40 mins

Faulty Section

Automation Philosophy

Circuit Breaker


Remote operation to close switch

Additional network restored, total time

11-18 mins

Circuit Breaker


Normally open point

Automated RMU / DT with FPI

Circuit Breaker


Normally open point

FPI indicates passage of fault

current

CB Trips

Circuit Breaker


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)

OMS Concept – Scenario #1

Sub A

Feeder B010

from Sub BFeeder A007

from Sub A

Open

Tie-Switch

Closed

Switches

Distribution

Transformers

Inferred Fault

Location

Customer

trouble calls

Sub A

Feeder B010

from Sub BFeeder A007

from Sub A

Open

Tie-Switch

Closed

Switches

Distribution

Transformers

OMS Concept – Scenario #2

Inferred Fault

Location

Customer

trouble calls

Customer

trouble calls

11 kV Overhead Distribution 33/11kV S/S

As is now


Fault here

As is now


Improvement Way

AR

AR

AR

AR

SE SE

SE

SE

11 kV Overhead Distribution

33/11kV S/S

Improvement Way

AR

AR

AR

AR

SE SE

SE

SE


33/11kV S/S

Improvement Way

AR


Improvement Way

AR

AR

AR

AR

SE SE

SE

SE


33/11kV S/S

Improvement Way

AR

AR

AR

AR

SE SE

SE

SE


Improvement Way

AR

AR

AR

AR

SE SE

SE

SE

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



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



Feeder

Back to

Normal

5 – 10

minutes

15 – 20

minutes

10 - 15

minutes

45 – 75

minutes

15 – 30

minutes

1 - 4

Hours

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


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


1 - 4 5 - 10

Patrol

Time

Customer

Reports

Outage

Fault

Occurs

Without Automation

With Automation

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.

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

Reliability Benchmarking Example

Another Benchmark Example

CEM HKE CLP

ConEd

EnergyAustralia

ETSA UtilitiesWestern Australia

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

SA

IDI

in

Min

ute

s/C

ust

om

re/Y

ear

SAIDI Comparison

CEM

ConEd

EnergyAustralia

ETSA Utilities Western Australia

0.00

0.20

0.40

0.60

0.80

1.00

1.20

SA

IFI

in #

Tim

es/C

ust

om

er/Y

ear

SAIFI Comparison

Some European Comparisons Survey Per Year 2004

Possible SAIDI Variations by Zone

Feeder Automation • Rather than rely on manual switching by field crews,

automated feeder devices can be used to – Detect and isolate a faulted feeder section

– Restore power to customers upstream of the fault

– Restore power to customers downstream of the fault

• Such feeder automation can be implemented using different strategies, e.g., those that depend on – Automated devices operating locally without

supervision

– Devices controlled remotely by an automation system

Possible SAIFI Variations by Zone

Example Strategy Study Using SAIDI

0.0

1.0

2.0

3.0

4.0

0 1 2 3 4

Cost (MUSD)

SA

IDI

(hr/

yr)

Base

Fuse Saving

Ag

gre

ss

ive

Sw

itc

hin

g

New

Lin

e D

evic

es

New

Fee

de

r

Au

tom

ati

on

Rec

on

fig

ura

tio

n

FC

Is

Tre

e W

ire

0.0

1.0

2.0

3.0

4.0

0 1 2 3 4

Cost (MUSD)

SA

IDI

(hr/

yr)

Base

Fuse Saving

Ag

gre

ss

ive

Sw

itc

hin

g

New

Lin

e D

evic

es

New

Fee

de

r

Au

tom

ati

on

Rec

on

fig

ura

tio

n

FC

Is

Tre

e W

ire

Law of Diminishing Return

Reliability Improvement vs. Cost

0

500

1000

1500

2000

2500

3000

0 20000 40000 60000 80000 100000

Cost

Cu

st

Ou

tag

e M

inu

tes

Imp

rov

em

en

t

• Stage 2: – Develop strategy implementation scheme

– Select vendors

• Stage 3: – Supply and install distribution system upgrades

including automation equipment

– Supply and install control center facilities

– Supply, install, and commission DAS including remote terminal units and communications equipment

• Stage 4: Determine and implement capacity building program to support systems and business processes resulting from the upgradation project.

Reliability Improvement implementation

VH

MUSS

Axis HT SJM RMUKrubara Sangha RMU

Sagar RMUJanatha RMUW5 SD

Arya Vysya

Mourya

GLM

KPC

Churchill

A.R Circle

brigade Plaza

Jwala

Complex

Keshava

Nivasa

Brigade

Majestic

SJM HT

Palmodi

UBI

Vectra

Pancha

Rathna

Heritage

Adarsh Inn

Lakshmi

Rajamma

Simha

Era

Tallam

Sagar

Adigas

Central

CollegeCTO

Green House

Arya Vysya

Janatha Bazaar

KamatFP

Bajaj

Sapna

Sukh Sagar

Park RMU Syndicate RMU

Vijaya

Samraj

KamatHT

S.N Bazaar

Sukh Sagar

HT (New)

Sukh Sagar

HT(Old)

Janatha Bazaar

From Syndiate RMU OD (F20 of 'A' station)

Single Linde Diagram of F1 Feeder of 'A' Station (W4 SD)

F01F08

F06

F11

M

M

M

A

M

Sn

V

A

M

V

A

M

U

S

S

Single Line Diagram showing automation component

SS#1 SS#

2

AUTOMATION OF MANUAL SYSTEMS

Automate existing Equipment

Introduce scada ready components

• Switches

• RMU

• Auto Reclosures

• Sectionalisers

• Fault Passage

Indicators

lV. Remote-controlled switch network

Normally-open point

Telecontrolled Switches

Substation CBs

33/11kV Substation

10km

10km

12.5km

10km

10km 10km

10km

10km

10km 10km

10km

10km

10km

10km

17.5km

10km 10km

20km

Feeder 1

Feeder 2 Optical Fiber

Fault

Control

room

Communications

Normally-open point

Sectionalisers

Substation CBs

33/11kV Substation

10km

10km

12.5km

10km

10km 10km

10km

10km

10km 10km

10km

10km

10km

10km

17.5km

10km 10km

20km

Feeder 1

Feeder 2

Radio Communications

Control

room

Fault

lV. Sectionalizer network

Normally-open point

Feeder Automation Sectionalisers

Reclosers

33/11kV Substation

10km

10km

12.5km

10km

10km 10km

10km

10km

10km 10km

10km

10km

5km

5km

5km

5km

10km

7.5km

5km

5km

5km

5km

7.5km

12.5km

Feeder 1

Feeder 2

Fault

Control

room

FA

tim

e Protection Direction

Changes

Recloser

Trips

Tie closes

FA Sectionalises

lV. Feeder automation network

Reliability Analysis

• DRAKE (Distribution Reliability Analysis – KEMA) is a software tool that allows a reliability assessment model to be defined and then used to – Design new systems to meet explicit reliability targets

– Identify reliability problems on existing systems

– Test the effectiveness of reliability improvement projects

– Determine the reliability impact of system expansion

– Design systems that can offer different levels of reliability

– Design systems that are best suited for performance based rates

Results of a Reliability Analysis

• On a feeder, system, and customer basis generate results such as the expected number of – Momentary interruptions per year

– Sustained interruptions per year

– Hours of interruption per year

– Protection device operations per year

– Switching operations per year

Modeling Capabilities in Reliability Analysis

• Different types of faults (3-phase, line-to-ground, etc.) • Feeder automation (e.g., Fault Location, Isolation, and

System Recovery) • Fuse saving and fuse clearing • Single-phase reclosing and lockout • Imperfect protection coordination • Post-fault feeder reconfiguration • Capacity limitations during feeder reconfiguration • Equipment bypass during system reconfiguration • Impact of weather • Changes in operational practices during storms • Reliability optimization algorithms

Sample Screen Captures

Visualization of Results

Custom Histograms

Reliability IndicesRisk Assessment

Custom Graphs

Query Searches on Data and Results

DAS functions Network Connectivity Analysis (NCA)

State Estimation (SE)

Load Flow Application (LFA)

Voltage VAR control (VVC)

Load Shed Application (LSA)

Fault Management and System Restoration

(FMSR)

Loss Minimization via Feeder Reconfiguration

(LMFR)

Load Balancing via Feeder Reconfiguration

(LBFR)

Operation Monitor (OM)

• Distribution Load forecasting (DLF)

Distribution Network (DA) Model The Distribution Automation should represent the various components of the Utilities distribution

system and include all the primary substation feeders, distribution network and devices with

possible islands, which may be formed dynamically. The following devices are represented in the

network model.

Power Injection points

Transformers

Feeders

Load (balanced as well as unbalanced)

Circuit Breakers

Sectionalizers

Isolators

Fuses

Capacitor banks

Reactors

Generators

Bus bars

Temporary Jumper, Cut and Ground

Meshed & radial network configuration

Line segments, which can be single-phase, two-phase, or three phase and make up a distribution circuit.

Conductors

Grounding devices

Fault detectors

IEDs

Operational limits for components such as lines, transformers, and switching devices

The database of the network model of the utility system can have interface with the GIS system of

the area for better visual decisions for crew management and asset information. The Customer

Interface Management can also integrate with the distribution automation system for effective

utilisation.

Network Connectivity Analysis (NCA) The network connectivity analysis function provides the connectivity between various network

elements. The prevailing network topology will be determined from the status of all the switching

devices such as circuit breaker, isolators etc that affect the topology of the network modelled.

NCA runs in real time as well as in study mode. Real-time mode of operation uses data acquired by

SCADA. Study mode of operation will use either a snapshot of the real-time data or save cases. NCA

can run in real time on event-driven basis.

The network topology of the distribution system will be based on

Tele-metered switching device statuses

Manually entered switching device statuses.

Modelled element statuses from DA applications. The NCA will be useful in determining the network topology for the following status of the

network.

Bus connectivity (Live/ dead status)

Feeder connectivity

Network connectivity representing S/S bus as node

Energized /de-energized state of network equipments

Representation of Loops (Possible alternate routes)

Representation of parallels

Abnormal/off-normal state of CB/Isolators

The NCA also assists the power system operator to know the operating state of the distribution

network indicating radial mode, loops and parallels in the network. Distribution networks which are

normally operated in radial mode; loops and/or parallel may be intentionally or inadvertently formed.

State Estimation (SE) The State Estimation (SE) is used for assessing (Estimating) the distribution network state. It shall assess loads of all network nodes, and, consequently, assessment of all other state variables (voltage and current phasors of all buses, sections and transformers, active and reactive power losses in all sections and transformers, etc.) in the Distribution network.

Load Flow Application (LFA) The Load Flow function shall provide real/active and reactive losses on:

Station power transformers

Feeders

sections

Distribution circuits including feeder regulators and distribution transformers, as well as the total circuit loss

Phase voltage magnitudes and angles at each node.

Phase and neutral currents for each feeder , transformers, section

Total three phases and per phase KW and KVAR losses in each feeder, section , transformer ,DT substation & for project area

Active & reactive power flows in all sections, transformers List of overloaded feeder, lines, busbars, transformers loads etc including the actual current magnitudes, the overload limits and the feeder name, substation name

List of limit violations of voltage magnitudes, overloading.

Voltage drops

Volt –VAR control (VVC) In electrical power system the reactive power can be generated at source generators or can be

injected at the substations through Volt-var systems. It is more appropriate to inject at substations

rather then producing then at generator points and transporting them over long distances. Any

power system always tries to optimise on the reactive power flow over their networks.

The coordination of voltages and reactive power flows control requires coordination of VOLT and

the VAR function. This function shall provide high-quality voltage profiles, minimal losses,

controlling reactive power flows, minimal reactive power demands from the supply network.

The following resources should be taken into account in any voltage and reactive power flow

control:

TAP Changer for voltage control

VAR control devices: switchable and fixed type capacitor banks.

Load Shed Application (LSA) The power delivery to the consumers is also bogged down with the Demand-Supply problems, with

demand being always higher than supply. The reasons for less Supply are several including the

faults, tripping of lines. In these situations the power system operator tries to distribute available

power through Shedding of loads to consumers over small definite periods till he tides over the

situation of loss of power.

The load-shed application helps to automate and optimise the process of selecting the best

combination of switches to be opened and controlling in order to shed the desired amount of load.

Given a total amount of load to be shed, the load shed application shall recommend different

possible combinations of switches to be opened, in order to meet the requirement. The despatcher

is presented with various combinations of switching operations, which shall result in a total

amount of load shed, which closely resembles the specified total. The despatcher can then choose

any of the recommended actions and execute them.

In case of failure of supervisory control for few breakers, the total desired load shed/restore will not

be met. Under such conditions, the application will inform the dispatcher the balance amount of load

to be shed /restore. The load-shed application runs again to complete the desired load shed /restore

process.

Fault Management & System Restoration (FMSR) Application

The availability of data related to the breakers/ switches and the level of The Fault current flowing

in the networks helps one to Manage & Restore the System in an event of fault. This application

helps to provide the assistance to the power system despatcher for detection, localisation,

isolation and restoration of distribution system after a fault in the system has occurred with the

help of operating through the supervisory control available on SCADA. The devices which help in

localisation & isolation of the fault includes Auto Reclosures(AR), Sectionalisers, Fault Passage

Indicators etc. The operation & characteristics of these devices are separately addressed in the

SCADA section.

Loss Minimization via Feeder Reconfiguration (LMFR)

The switching operation during fault and requirement to supply power through alternate feeders in

the distribution network modifies the feeder configuration topology. The information of network

topology and availability of adjacent feeder networks can be useful in right selection of feeders

with overall aim of reducing the line losses and maximum power delivery to consumers.

This function identifies the opportunities to minimize technical losses in the distribution system by

reconfiguration of feeders in the network for a given load scenario. The technical losses are the

losses created by characteristic of equipment & cable such as efficiency, impedance etc.

The function helps in calculation of the current losses based on the loading of all elements of the

network. The Telemetered values, which are not updated due to telemetry failure, can also be

considered by LMFR application based on arriving at the recommendations of LF Application. The

LMFR application can be utilised to have the various scenarios for a given planned & unplanned

outages, equipment operating limits, tags placed in the SCADA system while recommending the

switching operations.

Load Balancing via Feeder Reconfiguration (LBFR)

The discussions had on previous topic can be used for the Load Balancing via Feeder

Reconfiguration for the optimal balance of the segments of the network that are over & under

loaded. This helps in better utilization of the capacities of distribution facilities such as transformer

and feeder ratings.

The Feeder Reconfiguration Function can be used also to have a scenario on an overload condition,

unequal loadings of the parallel feeders and transformers, periodically or on demand in the

network by the despatcher. The system will help generate the switching sequence to reconfigure

the distribution network for transferring load from some sections to other sections. The LBFR

application can even consider the planned & unplanned outages, equipment operating limits, tags

placed in the SCADA system while recommending the switching operations.

The function helps in distributing the total load of the system among the available transformers and

the feeders in proportion to their operating capacities, considering the discreteness of the loads,

available switching options between the feeder and permissible intermediate overloads during

switching. The despatcher can have the options to simulate switching operations and visualise the

effect on the distribution network by comparisons based on line loadings, voltage profiles, load

restored, system losses, number of affected customers.

Load Forecast (LF) The Distribution Automation system keeps logging data periodically of the network. This historical

database and weather conditions data collected over a period can be used for prediction and to

have forecasting of the requirement of consumer loads. Generally there are two types of

forecasting that are resorted too.

Short-Term Load Forecasting (STLF) will be used for assessment of the sequence of average

electrical loads in equal time intervals, from 1 to 7 days ahead. The Long term forecasting is used

for forecasting load growths over longer durations. The fore casting techniques are based on

different forecasting methods such as:

Autoregressive.

Least Squares Method

Time Series Method.

Neural Networks.

Kalman filter

Weighted Combination of these method

Feeder Automation Philosophy

• Feeder automation makes use of various devices to reconfigure/switch feeders under normal and abnormal operating conditions, devices such as – Circuit breakers – Line reclosers/regulators – Group operating switches/load break

switches

• As to be discussed these devices are used within the context of different automation philosophies

Example of Automated GOS

Example of Automated Load Break Switches/Line Reclosers

SF6 LBS

Vacuum LBS

Air-Break LBS

Line Recloser

Example of RMU (Pad-Mounted Switches)

Generally, if not automation ready, can be retro-fit with motor

or solenoid operating mechanism

Automated Feeder Switching

• Automated feeder switching can involve the fore-mentioned devices in such a way that – They operate in a coordinated, but

unsupervised manner

– Alternatively in a supervised (integrated) manner, i.e., monitored and possibly controlled by a computer system located for example at a substation or control center

• Remote operation can be manual, semi-automatic, and/or fully automatic (no manual intervention)

Feeder Automation Architectures

• Standalone Automatic Switches – Reclosers, sectionalizers

• Centralized System – Switches controlled by central DAS/DMS

• Substation Centered Approach – Substation unit controls switches on associated

feeders

• Peer-to-Peer Arrangement – Groups of switches communicate to determine

appropriate switching actions

Centralized Feeder Automation

• System controlled by central DAS – Acquire data from field

devices

– Process data in DAS

– Issue supervisory control commands

• Can be manually, semi-automatic, or fully-automatic

Comm. TowerWorkstation

Centralized Feeder Automation (Conceptual Block Diagram

SCADA Server

DAS/DMS ServerFeeder Models

Power Flow

Load Estimator

Topology Processor

Feeder Automation

Switch Order

Management

Substation

and Feeder

Devices

Fault indicator

status, currents,

voltages

Device Control

Commands

Geogaphic

Information

System

(GIS)

Real-Time

Data

Dispatcher ConsoleEquipment

Status and

Loading

Switching

Actions

Central

DAS/DMS

Feeder

Equipment

Data, Topology

Information

Central Scheme Pro’s & Con’s

• Pro’s – Dispatchers retain control – Dispatchers are always informed – Considerably more operating flexibility

• Fewer restrictions (e.g., number of switches controlled) • Better ability to handle abnormal situations

– No “unnecessary” switching – Additional functionality possible

• Non-outage switching • Feeder load balancing

• Con’s – Requires DAS – Requires extensive communications infrastructure – Requires distribution system (network) models to be created

and maintained

Substation Centered Approach

• System controlled by substation PLC or RTU – Acquire data from field

devices – Process data in

substation master – Issue supervisory control

commands as needed to field devices

• Can be manual, semi-automatic, or fully-automatic

Comm. Tower

Local HMI

RTU/PLC

SCADA EMS

Substation

OPTIO

NAL

Substation Centered Pro’s and Con’s

• Pro’s - Fairly easy to set up and maintain - May or may not require electrical feeder models - May be interconnected to a central DAS, but can

operate independently - Lower cost alternative

- Con’s - Difficulty in handling complex situations as in case

of heavily loaded feeders where load must be split up

- Limited number of switches controlled - Requires substation/feeder communications

Peer-to-Peer Approach

• Network of Distributed Controllers

– Work as a team – Acquire “local” data via

local sensors – Acquire “remote” data

via “peer-to-peer” communications with other controllers

– Process data locally – Open/close associated

switch as needed • Primarily intended for

fully-automatic operation

Peer-to-Peer Pro’s

• Pro’s – Does not require

• Central SCADA system

• Feeder models supported by GIS interface

• Extensive communications infrastructure

– Costs less than central approach – Primary application is FLISR, but not limited to this

• Can be fully functional feeder SCADA system

Peer-to-Peer Con’s

• Con’s

– Lack of operator visibility and control • Can add SCADA interface (most utilities do!)

– Communication difficulties • Peer-to-peer communications among pole top units can be a

challenge!

– Costs more than substation centered approach

– Some “unnecessary” switching involved • Switches in a team open regardless of fault location

• Then close back in as necessary

• May fail to close? Extra “mechanical” operations?

Feeder Automation Applications

• Fault Location, Isolation, and Service Restoration – Can detect and locate fault, isolate the faulty section,

restore power to “healthy” feeder segments

• Load Shedding – Can shed one feeder section if necessary

• Cold Load Pickup – Can pick up feeder load one section at a time

• Feeder Reconfiguration – Can balance load between feeders and reduce losses

• “Intelligent” Substation Bus Transfer – Can transfer load to another substation following

transformer failure

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

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

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

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

DAS Vision • Conceptual Architecture

– The DAS system will have a distributed architecture with an ability to support Control Centres and remote data acquisition

– It will incorporate rapid disaster recovery capability including a backup control centre. • Scope of Control

– There will be a designed level of System-Wide DAS Control capability e.g., Load switching, Fault Location Isolation and System Restoration (FLISR)

• Performance and Expandability – The system will provide operationally acceptable performance as its domain of influence

grows or changes. It will support expansion as operational or corporate needs grow or change

• Interfaces and Integration – The DAS will provide for relevant interfaces necessary to support the suite of

applications and in accord with the principle of elimination of duplication in particular data entry

• Corporate Data Visibility – The DAS will provide for corporate visibility and accessibility to SCADA/DMS data

• Operational Flexibility – The DAS will provide flexible support of roles and responsibilities of personnel

(Operators, System Engineers, Maintainers, Crews, Crew Managers, etc.) • DMS Applications

– The DAS will include a DMS suite of capabilities within its bounds of influence – Capability building is core to its success,

DAS Functional Requirements

• Core DAS+

– Protocols (IEC 60870-5-101, IEC 60870-5-104, TASE.2)

– Distributed Data Acquisition Nodes

– Distributed Control Desks (Main Control Room, Backup CR, Remote Consoles)

– Various Communications Interfaces

– Data Acquisition (Status, Analogues)

– Historical Data (what retention, what storage rates, accessibility?)

– Alarming (what is intended to be the response of the BESCOM Operator?)

– Provides Primary UI to SCADA & DMS applications

• Data Volumes, Navigation, Browser Access need to be considered

– Disaster Recovery Management

• Regular exercise of backup capability

– Possible Import of Data from Corporate Asset Data – GIS, other??

– Possible integration/interface with Corporate Distribution applications

• Customer Information System (CIS) / Billing System

• Interim Outage Management System (OMS) (Phase 1)

DAS Functional Requirements (cont’d)

• DAS Core – Network Operational Model & tools to build + incrementally update the

NOM from corporate data sources • Connectivity • Electrical Attributes • ‘Intelligent’ Views (Operational Diagrams)

– Maintain current network state in NOM • Outage Management

– Analysis, grouping, ungrouping outage reports – Inferring the source/cause of outages – Providing data to call centre & IVR with respect to unplanned and

planned outages – Dispatching outage jobs to work management – Tracking outages to completion – Deriving outage statistics (CAIDI, CAIFI, SAIDI, SAIFI)

DAS Functional Requirements (cont’d)

• Switching

– Planning/scheduling all network switching – linked to work management

– Planning detailed switching steps - obeying processes + rules

– Support the plan/check/approval process + access permit process for work in progress

– Record the execution of switching actions and record network state in NOM

– Support processes to update NOM as network asset added/removed/changed

• Distribution Network State Analysis

– Current State

• Live/Dead Analysis (including effect of jumpers, cuts, and grounds)

• Check proposed switching

• Routinely check impact of selected contingencies

– Future Possible State

• Develop/check proposed switching

• Check worst case scenarios

• Check potential contingencies

• Crew Management

– Assign and close out trouble tickets (e.g., allows statistics to be maintained)

– Track field resources and facilities return to service.

Example of a Recent DAS architecture

- Ergon Energy, Queensland Australia

Ergon Energy Overview

• 68 connection points to the TNSP

• 33 Ergon Energy owned generating stations (diesel/wind/solar) which supply isolated distribution

• Total distribution asset value is approximately $3 billion

• Includes 140,000km of distribution lines and more than 400 Zone Substations.

ABB Support

ABB Houston

DMZ LAN

IS&R LAN

SCADA LAN

FCFC FCFC

SAN Switches

RAID Array

AlphaServer DS 25

2CPU

4GB Memory

288GB Disk

AlphaServer DS 25

1CPU

4GB Memory

432GB Disk

Oracle IS&R Servers

NETWORK MANAGER

Applications Servers

ControllersRockhampton

Control Centre

Corporate Data Network

C&DS Users

Rockhampton Master

Station (RMS)

SCADA Wide Area Network

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

Expansion

SBS PCI

ExpansionSBS PCI

Expansion

SBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

Expansion

SBS PCI

ExpansionSBS PCI

Expansion

SBS PCI

Expansion

DMZ LAN

IS&R LAN

SCADA LAN

FCFC FCFC

SAN Switches

RAID Array

AlphaServer DS 25

2CPU

4GB Memory

288GB Disk

AlphaServer DS 25

1CPU

4GB Memory

432GB Disk

Oracle IS&R Servers

NETWORK MANAGER

Applications Servers

Rockhampton

DAFE

Operational

Communicaitons

Network

ControllersGarbutt

Control Centre

Garbutt Master

Station (GMS)

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

Expansion

SBS PCI

ExpansionSBS PCI

Expansion

SBS PCI

Expansion

Townsville

DAFE

Operational

Communicaitons

Network

Operational

Communicaitons

Network

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

Expansion

SBS PCI

ExpansionSBS PCI

Expansion

SBS PCI

Expansion

Operational

Communicaitons

Network

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

Expansion

SBS PCI

ExpansionSBS PCI

Expansion

SBS PCI

Expansion

Operational

Communicaitons

Network

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

ExpansionSBS PCI

Expansion

ICP B/O Panels

SBS PCI

Expansion

SBS PCI

ExpansionSBS PCI

Expansion

SBS PCI

Expansion

Operational

Communicaitons

Network

Historian Users

Toowoomba

DAFE

Maryborough

DAFE

Mackay

DAFE

Cairns

DAFE

Internet

VPN Access

Powerlink Wide Area

Network

Remote Access

via PSTN

Remote Access

via PSTN

Ergon NOC

NOC Support

Network diagram for the distribution area

Network diagram for the Town of Rockhampton showing streets and transformers

Control Centre Facilities

• Layout of work areas

• Allowance for Engineering/administration

• Allowance for meeting/visitors

• Wallboard

• Equipment Room

• UPS

• Air Conditioning

• Communications equipment, access, distances

• Corporate connectivity

Ergon Energy Australia - Distribution

Comed USA – Distribution Chicago

Typical System Architecture for Local Control Centre at Distribution Substations

Numerical

Relays

IEDs

Feeder 1 Feeder 2 Feeder 12

IEC 60870-5-104

to Control Centre

Serial interfaces of 3rd party relays

on IEC-103 protocol

IEC 61850

FO Link

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ET Switch

Laptop

Field Signals DI/ DO/

AI

System Configuration for Data Concentrators

SICAM

AK1703 Data

Concentrator

HMI (LCC)

Inverter

RTU

Electro

Mechanical

Relays

IEC 61850 Substation Architecture

RTU at Substation- ABB SPIDER-200

IBM Compatible

Modem

Modem

COMMUNICATION LINK

Radio - TDMA

Har

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DEC

Alpha

Servers

FEP

Poll

Data

Repeaters Limited

applications

Substation Switch yard

Quality Assurance

Introduction

• SCADA / DMS systems and components needs to undergo various

tests and inspection methodologies as per well-established national

and international standards.

• The testing ensures the procured systems / components meets the

safety, reliability and other requirements to ensure proper

functioning of the system.

Standards for SCADA / DMS

• Any large utility with an on going SCADA program and which over

time intends to install a number of discrete SCADA systems, must

eventually integrate these systems.

• The SCADA program will involve multiple vendors over time and

they will face problems due to the SCADA industry's use of

proprietary hardware, software and communications protocols.

• A smaller utility may be able to install in one go a SCADA system

that encompasses the majority of their operations.

- The utility will buy a proprietary system and rely on that vendor

for continued upgrades and support.

- But this approach will be cost intensive and highly dependent on

the vendor support.

• The prime difference between these two situations is that the

smaller utility can standardise by installing a single system whereas

the larger utility is necessarily faced with a lengthy program, with

relatively small expansions at any time (compared to the overall

system).

Standards for SCADA / DMS

• To ensure interoperability and to protect long term investment over

technology obsoleteness, it is essential to adopt standardized

products.

• It will ensure availability of quality products at competitive prices

from multiple vendors.

• Communications protocols are the major area requiring standards,

and there are a number of alternatives.

• Another aspect of standards is that they cannot be too rigid, but

must still leave flexibility for systems to add new functionality or

select certain options.

• Many standards come with both mandatory requirements and

optional selections, as well as with “extension rules” for expanding

the standards in a consistent manner for new functions.

• This helps to address a few vendor-specific requirements or utility-

specific requirements, as well as the flexibility to meet unforeseen

requirements in the future.

Standardizing Bodies

There are many national and international standardizing bodies:

– International Electro technical Commission (IEC)

– IS (Indian Standard)

– Institute of Electrical and Electronics Engineers (IEEE)

– American National Standard Institution (ANSI)

– British Standards (BS)

– European Committee for Electro technical Standardization

(CENELEC) etc

Protocols

• Modbus communication protocol is extremely used in process

instrumentation. Even though it is used in power sector, it is not

amenable for wide power sector automation requirements.

• DNP3 (Distributed Network Protocol) is a set of communication

protocols used between components in process automation systems

and is emerged from the electricity industry.

• RTU programming standards is IEC-61131-3 programming

languages. These have been developed for PLC programming, and

are increasingly being mandated for use by large manufacturing

concerns.

Commonly Referred Standards

RTU – The main component used for SCADA applications:

IEC 60870-5 SER Telecontrol Equipment and Systems –

Part 5: Transmission Protocols

IEC 60870-5-1 Transmission Frame Formats

IEC 60870-5-2 Data Link Transmission Services

IEC 60870-5-3 General Structure of Application Data

IEC 60870-5-4 Definition and Coding of Information Elements

IEC 60870-5-5 Basic Application Functions

IEC 60870-5-6 Guidelines for conformance testing for

IEC 60870-5 companion standards

IEC Technical Committee 57 has also published following companion

standards for telecontrol equipment:

IEC 60870-5-101 Transmission Protocols, companion standards

especially for basic telecontrol tasks

IEC 60870-5-102 Companion standard for the transmission of

integrated totals in electric power systems (this standard is not

widely used)

IEC 60870-5-103 Transmission Protocols, Companion standard for

the informative interface of protection equipment)

IEC 60870-5-104 Transmission Protocols, Network access for IEC

60870-5-101 using standard transport profiles

Substation Automation System (SAS)

IEC 61850 SER Communications Networks and Systems in

Substations

- Technical report / standard series are applicable to substation

automation systems.

- This standard defines the communication between intelligent

electronic devices in the substation and the related system

requirements.

Inter-Control Center Communication Protocol (ICCP)

• IEC 61870-6 Series Telecontrol equipment and systems - Part 6:

Telecontrol protocols compatible with ISO standards and ITU-T

recommendations.

• ICCP or IEC 60870-6/TASE.2 (Telecontrol Application Service

Element 2) is being specified by utility organizations throughout the

world to provide data exchange over wide area networks (WANs)

between utility control centers, utilities, power pools, regional control

centers, and Non-Utility Generators.

ICCP Functionality

Basic ICCP functionality is specified as “Conformance Blocks”. The objects that are used

to convey the data are defined in various parts of IEC 60870-6.

• IEC TC 57 WG3 also generated standards for telecontrol protocols compatible with

ISO standards and ITU-T recommendations.

These standards include:

– IEC 60870-6-1 Application context and organization of standards

– IEC 60870-6-2 Use of basic standards (OSI layers 1–4)

– IEC 60870-6-501 TASE.1 Service definitions

– IEC 60870-6-502 TASE.1 Protocol definitions

– IEC 60870-6-503 TASE.2 Services and protocol

– IEC 60870-6-504 TASE.1 User conventions

– IEC 60870-6-601 Functional profile for providing the connection-oriented

transport service in an end system connected via permanent access to a packet

switched data network

– IEC 60870-6-602 TASE transport profiles

– IEC 60870-6-701 Functional profile for providing the TASE.1 application service

in end systems

– IEC 60870-6-702 Functional profile for providing the TASE.2 application service

in end systems

– IEC 60870-6-802 TASE.2 Object models

DMS & CIM Standards

• IEC 61968 Series Application integration at electric utilities - System

interfaces for distribution management

• IEC 61968 is a series of standards under development that will define

standards for information exchanges between electrical distribution

systems. These standards are being developed by Working Group 14 of

Technical Committee 57 of the IEC (IEC TC 57 WG14).

The various standards published / under development are listed below.

• IEC 61968-1 – Interface architecture and general requirements

• IEC 61968-2 – Glossary

• IEC 61968-3 – Interface for Network Operations [NO]

• IEC 61968-4 – Interfaces for Records and Asset management [AM]

• IEC 61968-5 – Interfaces for Operational planning & optimization

[OP] [Under Development]

• IEC 61968-6 – Interfaces for Maintenance & Construction [MC] [Under

Development]

• IEC 61968-7 – Interfaces for Network Extension Planning [NE] [Under

Development]

• IEC 61968-8 – Interfaces for Customer Support [CS] [Under Development]

• IEC 61968-9 – Interface Standard for Meter Reading & Control [MR]

• IEC 61968-10 – Interfaces for Business functions external to distribution

management [Under Development]. This includes Energy management &

trading [EMS], Retail [RET], Supply Chain & Logistics [SC], Customer

Account Management [ACT], Financial [FIN], Premises [PRM] & Human

Resources [HR]

• IEC 61968-11 – Common Information Model (CIM) Extensions for

Distribution [Under Development]

• IEC 61968-12 – Common Information Model (CIM) Use Cases for 61968

[Under Development]

• IEC 61968-13 – Common Information Model (CIM) RDF Model exchange

format for distribution

• IEC 61968-14-1-3 to 14-1-10 – Proposed IEC Standards to Map IEC61968

and Multispeak Standards [Under Development]

• IEC 61968-14-2-3 to 14-2-10 – Proposed IEC Standards to Create a CIM

Profile to Implement MultiSpeak Functionality [Under Development]

DMS & CIM Standards contd…

Security standards

IEC 62351 series:

• IEC 62351 is a standard developed by WG15 of IEC TC57. This is developed for handling the security of TC 57 series of protocols including IEC 60870-5 series, IEC 60870-6 series, IEC 61850 series, IEC 61970 series & IEC 61968 series.

• IEC 62351-1 — Introduction to the standard

• IEC 62351-2 — Glossary of terms

• IEC 62351-3 — Security for any profiles including TCP/IP

• IEC 62351-4 — Security for any profiles including MMS (e.g., ICCP-based IEC 60870-6, IEC 61850, etc.).

• IEC 62351-5 — Security for any profiles including IEC 608705 (e.g., DNP3 derivative)

• IEC 62351-6 — Security for IEC 61850 profiles.

• IEC 62351-7 — Security through network and system management.

• IEC 62351-8 — Role-based access control.

Other Standards

IEEE C37.1-2007 Standard for SCADA and Automation Systems

• This standard applies to, and provides the basis for, the definition,

specification, performance analysis, and application of systems used

for supervisory control data acquisition or automatic control or both,

in attended or unattended electric substations, including those

associated with generating stations; and power utilization and

conversion facilities.

• The standard is generic and comprehensive enough to cover the

most of the aspects of system design, interface & processing

requirements and environmental requirements.

DNP 3.0:

• The main use of this standard is in utilities such as electric and water companies.

• It was developed for communications between various types of data acquisition and control equipment.

• It is primarily used for communications between a master station and RTUs or IEDs.

• The DNP3 protocol is also referenced in IEEE1379-2000, which recommends a set of best practices for implementing modern SCADA Master-RTU/IED communication links.

• The IEEE adopted DNP 3.0 as IEEE 1815-2010 in the year 2010.

• The Indian standard for Supervisory Control and Data Acquisition (SCADA) System for Power System Applications is IS 15953- 2011. This standard covers generic requirements of Power System SCADA.

TESTING AND INSPECTION

TESTING

• Testing on automation components is conducted to evaluate the system's compliance with its specified requirements.

• Testing is done at various levels and purposes/applications.

• Testing is required:

- Throughout the development and use cycle (life cycle) of a system (product, process or service) and it is more rigorous, it is for evaluation.

- During design (simulation), fabrication, assembly,

transfer of technology & field use.

- By independent accredited test laboratories like CPRI, ETDC/ ERTL etc. generally for a third party certification.

- For marking purposes such as BIS, CE, UL and many

others.

Type test: Series of tests carried out on the samples of the same type having identical characteristics, selected by manufacturer to prove conformity with all the requirements of the standard.

• Automation components shall conform to the type tests.

• A complete integrated unit shall be tested to assure full compliance with the functional and technical requirements of the Specification including functional requirement.

• The testing sample shall include one of each type of cards/modules and devices.

• Type testing shall be conducted in NABL accredited Labs or internationally accredited labs.

Test Nos. DESCRIPTION OF THE TEST

A FUNCTIONAL TESTS

Check for BOQ, Technical details, Construction & Wiring.

Check for database & configuration settings

Check the operation of all Analog inputs, Status input & Control output points.

Check operation of all communication ports.

Check for communication with master stations including remote database downloading from master

station

Check for auto restoration of RTU/FRTU on DC power recovery after its failure

Test for self-diagnostic feature

Test for time synchronization from Master

Test for SOE feature

End to end test (between RTU/FRTU & Master station) for all I/O points

Test for MODBUS protocol implemented for acquiring data from MFT/ transducers and updation time

demonstration in daisy chain configuration

Test for IEC 60870-5 -104,101 protocol implemented

Test for supporting other protocol

Table 1


A Test for operation with DC power supply voltage variation

Test for internal Clock stability

Test for Noise level measurement

Test for Control Security and Safety for Control outputs

Test for functionality/parameters verification of CMRs & Heavy duty trip relays

Test for data concentrator

Test for IED pass through

Test for SOE buffer & time data back up

Other functional tests as per technical specification requirements including features in support/ capability (for

future)

Test for DCPS of FRTU

Test for compliance of standards for bought items viz. CMRs, Heavy duty trip relays, MFT, weather sensor

etc.

Test for functionality/parameters for bought items viz. CMRs, Heavy duty trip relays, MFT, weather sensor

etc.

Test for test tools

Contd…..


B EMI/EMC IMMUNITY TESTS FOR RTU/FRTU

Surge Immunity Test as per IEC 60870-2-1

Electrical Fast Transient Burst Test as per IEC-60870-2-1

Damped Oscillatory Wave Test as per IEC 60870-2-1

Electrostatic Discharge test as per IEC 60870-2-1

Radiated Electromagnetic Field Test as per IEC 60870-2-1

Damped Oscillatory magnetic Field Test as per IEC-60870-2-1

Power Frequency magnetic Field Test as per IEC-60870-2-1

C INSULATION TEST FOR RTU/FRTU

Power frequency voltage withstand Test as per IEC 60870-2-1

1.2/50 μs Impulse voltage withstand Test as per IEC 60870-2-1

Insulation resistance test

D ENVIRONMENTAL TEST FOR RTU/FRTU

Dry heat test as per IEC 60068-2-2

Damp heat test as per IEC 60068-2-3

Routine Tests or Factory acceptance test (FAT):

Tests carried out on each sample to check

conformity with the requirements of the standard in

aspects which are likely to vary during production.

Acceptance Test or Site Acceptance Test (SAT):

Tests carried out on samples taken from a lot for

the purpose of acceptance of the lot.

Field Tests :

• After automation components are installed and commissioned in field, the Contractor shall carry out the field-testing.

Availability Tests:

• After field testing, automation components shall exhibit a 98% availability during test period.

• Availability tests shall be performed along with Master station.

• The RTU/FRTU shall be considered available only when all its functionality and hardware is operational.

• The non-available period due to external factors such as failure of DC power supply, communication link etc., shall be treated as hold-time & availability test duration shall be extended by such hold time.

Central Power Research Institute (CPRI) has full fledge

test facilities for type testing, IEC 61850, IEC 62056

protocol validation.

Utility IT Requirements

Conclusion

• SCADA / DMS improves the quality of service by reduction in number of outages & outage durations

• Quick isolation of faulty section & fast restoration of healthy section so that only least customers are affected during outage period.

• All data are available in real time and historical data archive for planning

Conclusion (contd.)

• Sharing of data with all stakeholders and MIS

• Though requires capital investment, but a good SCADA / DMS system implemented in a phased manner brings returns in a shorter period.

• All data are available in real time and historical data in archive for planning and other applications of utility

THANK YOU

Documents

Scada Ab & CD Slides