Implementation of SCADA in Power Plant

SESSION 2006-2010

Project Advisor

Prof. Dr. Aftab Ahmad

AUTHORS

NAUMAN AHMAD 06-EE-61 KHUZAIMA ASLAM KHAN 06-EE-127 HAFIZ MUHAMMAD FAYYAZ 06-EE-133

DEPARTMENT OF ELECTRICAL ENGINEERING UNIVERSITY OF ENGINEERING AND TECHNOLOGY,

TAXILA

(July 2010)

Implementation of SCADA in Power Plant By

NAUMAN AHMAD 06-EE-61 KHUZAIMA ASLAM KHAN 06-EE-127 HAFIZ MUHAMMAD FAYYAZ 06-EE-133

This Thesis is submitted in partial fulfillment of the requirement

for the degree of Bachelor of Science in Electrical Engineering

Supervised by Approved by

Internal Examiner External Examiner

Prof. Dr. Aftab Ahmad

Dean of Faculty Chairman of Faculty

DEPARTMENT OF ELECTRICAL ENGINEERING UNIVERSITY OF ENGINEERING AND TECHNOLOGY, TAXILA

JULY 2010

ABSTRACT

________________________________________________________

Today SCADA is the most important part of industry, water distribution, hydro power

plants, substations, electric distribution and number of other relevant fields all over the world.

SCADA has become the most advanced technology in field of automation and control.

Wherever automation and control is required, SCADA is the first priority.

ABB has commissioned SCADA in AttockGen. For numerical protection ABB has

used IED670. IED670 also provides control and monitoring for busbar, feeder, transformer

etc. IED670 can be configured and monitored with the help of Protective and Control IED

Manager PCM600 toolbox which is also overviewed. PCM600 is also the product of ABB.

From PCM600 IEDs can be easily adapted according to power system requirement. Data

from IEDs travels to the remote terminal unit (RTU). ABB uses RTU560 that is provided

with different telecontrol functions. These telecontrol functions are used when RTU560 is at

remote location. RTU560 system and module concept are also studied. Medias for the

communication of RTU and remote control center are also overviewed.

Finally different communications within plant in the implementation of SCADA are

taken into account. IED station and remote communications, RTU communication with sub-

devices and as a host device are studied. Along with this, different protocols to carry out

these communications are also considered.

DEDICATION

_______________________________________________________

We dedicate this humble effort, the fruit of our thoughts and study, to our

magnificently precious parents whose hands always raised in prayers for us, who taught us

the lesson of patience, perseverance, self confidence and self reliance.

We also dedicate to our respectable teachers, close friends and family members

whose support led us to success.

The Authors

ACKNOWLEDGEMENTS

______________________________________________________

The most important acknowledgement, by far, is to ALLAH, The Almighty, The

Most Gracious, the Most Bountiful, the MASTER OF THE WORLD, Who has bestowed

us the most powerful thing in His world, the brain and enabled us to complete this final year

project successfully. All the respect to our beloved Holy Prophet Muhammad (Peace Be

Upon Him), who after a lot of hardships and difficulties, made us able to recognize our

ALLAH and to distinguish virtue and evil.

We would like to express our profound gratitude, most sincere appreciation and

special thanks to our Project Advisor Prof. Dr. AFTAB AHMAD, without whose moral

support, invaluable suggestions and continual enthusiasm, it would have been extremely

difficult to work on this project. We also thank to Mr. Qadir Bakhsh and Mr. Shehriar

Khan for their humble suggestions and guidance.

We also like to thank our Family Members, friends, class fellows and faculty

members for their invaluable suggestions and critical review of our project. This support is

commendable.

ABBREVIATIONS

______________________________________________________

SCADA Supervisory Control and Data Acquisition

HMI Human Machine Interface

RTU Remote Terminal Unit

MTU Main Terminal Unit

PLC Programmable Logic Controller

LAN Local Area Network

WAN Wide area Network

DCS Distributed Control System

VHF Very High Frequency

UHF Ultra High Frequency

OPC Open Access to Real-Time Information

HIS Historical information system

IPS Invensys Process Systems

ABB Asea Brown Bowery

CPU Central Processing Unit

PRV Pressure Regulating Valve

MAC Main Automation Contractor

MEC Main Electrical Contractor

HDCC Hydro Dispatch Control Cell

MCM Machine Condition Monitoring

I/O Input Output

IED Intelligent Electronic Devices

NPCC National Power Control Center

NCC Network Control Centers

ITI Integrated Totals

AMI Analog Measured Values

CMU Communication Unit

HCI Host Communication Interface

SCI Sub-device Communication Interface

PDP Process Data Processing

DIST Archive Disturbance Data Archive

GPS Global Positioning System

FIFO First In First Out

SPI Single point input

DPI Double point input

ADC Analog Digital Converter

DMV Digital Measured Values

DMI Digital measured value

STI Step Position Value

BCD Binary Coded Decimals

GRAY Gray code

EPR End of Period Reading Counters

IR Intermediate Reading Counters

CVT Current/Voltage-Transformer

SA Substation Automation bus

SM Substation monitoring bus

LON Locally Operated Network

GOOSE Generic Object Oriented Substation Event

PCM Pulse Coded Modulation

CM Multiple command

MT Multiple transmit

SCS Substation Control System

TABLE OF CONTENTS

________________________________________________________

Chapter 1 Introduction  

1.1 SCADA System in General .............................................................................................1

1.2 Basic SCADA Communication Topologies....................................................................2

1.3 Supervisory Control ........................................................................................................3

1.4 Data Acquisition..............................................................................................................3

1.5 Modules of SCADA ........................................................................................................4

1.5.1 Remote Terminal Unit (RTU) ......................................................................4

1.5.2 Master Terminal Unit (MTU) ......................................................................4

1.5.3 The Central SCADA Master System (HMI) ................................................4

1.5.4 Communication Medias ...............................................................................4

1.5.5 SCADA Software ............................................................................................................5

1.6 SCADA Security .............................................................................................................6

1.7 SCADA System Applications .........................................................................................6

1.7.1 Alarm Processing .........................................................................................6

1.7.2 Tagging and Interlock Checking ..................................................................6

1.7.3 Analytical and Forecast Tools......................................................................6

1.7.4 Historical Information System (HIS) ...........................................................6

1.7.5 Operator Training Simulator ........................................................................6

1.8 SCADA Future ................................................................................................................7

1.9 SCADA Vendors .............................................................................................................7

Chapter 2 Literature Review

2.1 Literature Survey.............................................................................................................8

2.1.1 Fundamentals of Power System Protection by Y.G.Paithankar...................8

2.1.2 Power System Engineering ...........................................................................8

2.1.3 Securing SCADA Systems by Ronald L.Krutz............................................8

2.1.4 SCADA: Supervisory Control and Data Acquisition by Stuart A. Boyer ...9

2.1.6 Research Paper on SCADA by A. Daneels & W.Salter ...............................9

2.1.7 Intrusion Detection and Cyber Security of SCADA by Dale Peterson ..........9

2.2 Background of SCADA...................................................................................................9

2.2.1 SCADA implementation by sensor to panel system ....................................9

2.2.2 Architecture for Secure SCADA and DCS Networks................................11

2.3 Remote Access of SCADA ...........................................................................................12

2.4 Implementation of SCADA in Water Distribution........................................................13

2.5 Implementation of SCADA in oil and gas pipelines.....................................................14

2.6 Application of the SCADA System in Waste water Treatment Plants .........................16

2.7 Application of SCADA in Hydro Power Plant .............................................................17

2.8 SCADA for Offshore Wind Farms................................................................................18

2.9 Already Projects on SCADA.........................................................................................19

2.9.1 Supervisory Control and Data Acquisition ................................................19

2.9.2 SCADA Implementation at CJPL Jaranwala .............................................19

2.9.3 General SCADA Educational Laboratory for Undergraduate Students.....19

2.10 Present Project ...............................................................................................................19

CHAPTER 3 Data Collection

3.1 Basic IED Applications: .............................................................................21

3.1.1 Self Supervision with Internal Event List ..................................................21

3.1.2 Voltage Selection .......................................................................................21

3.1.3 Automatic Opening of Transformer Disconnector ....................................22

3.1.4 Automatic Load Transfer from bus A to bus B..........................................23

3.2 IED Requirements .........................................................................................................23

3.2.1 Current Transformer Requirements ...........................................................23

3.2.2 SNTP Server Requirements .......................................................................23

3.3 Monitoring Functions in IED ........................................................................................23

3.3.1 Measurements.............................................................................................24

3.3.2 Event Counter.............................................................................................24

3.3.3 Event Function ...........................................................................................24

3.3.4 Disturbance Report.....................................................................................24

3.3.5 Event List ...................................................................................................25

3.3.6 Indications ..................................................................................................25

3.3.7 Event Recorder...........................................................................................26

3.3.8 Trip Value Recorder...................................................................................26

3.3.9 Disturbance Recorder.................................................................................27

3.4 Logic Functions in IED .................................................................................................27

3.4.1 Configurable Logic Blocks ........................................................................28

3.4.2 Fixed Signal Function Block......................................................................28

3.4.3 Boolean 16 to Integer Conversion..............................................................28

3.4.4 Boolean 16 to Integer Conversion with Logic Node Representation.........28

3.4.5 Integer to Boolean 16 Conversion..............................................................28

3.4.6 Integer to Boolean 16 Conversion with Logic Node Representation.........29

3.5 Indication LEDs ............................................................................................................29

3.6 Human Machine Interface .............................................................................................29

3.7 REB670 .........................................................................................................................30

3.7.1 Differential Protection Using REB670 ......................................................31

3.7.2 Zone Selection Features .............................................................................32

3.7.3 Tripping Circuit Arrangement....................................................................33

3.7.4 Trip Circuit Supervision for Bus bar Protection ........................................33

3.8 Transformer Terminal RET 54_X.................................................................................33

3.8.1 Functions of the Transformer Terminal .....................................................34

3.8.2 Control Functions.......................................................................................35

3.8.3 Communication Functions .........................................................................35

3.8.4 Standard Functions.....................................................................................35

3.8.5 System Structure ........................................................................................35

3.9 Feeder Terminal REF 54_X ..........................................................................................36

3.9.1 Functions of the Feeder Terminal ..............................................................38

3.9.2 Protection Functions...................................................................................39

3.9.3 Control Functions.......................................................................................39

3.9.4 Communication Functions .........................................................................39

3.9.5 Standard Functions.....................................................................................39

3.9.6 System Structure ........................................................................................39

CHAPTER 4 Data Integration and Processing

4.1 Introduction ...................................................................................................................41

4.2 General Features of RTU560 ........................................................................................42

4.3 RTU560 System Concept ..............................................................................................43

4.4 RTU560 Communication and Module Concept............................................................44

4.5 RTU560 Application Functions ....................................................................................46

4.5.1 Telecontrol Functions.................................................................................47

4.5.2 General Functions ......................................................................................47

4.5.3 Programmable Logic Control (PLC)..........................................................48

4.5.4 Archive and Local Print Function ..............................................................48

4.5.5 Disturbance Data Archive ..........................................................................48

4.5.6 Integrated Human Machine Interface.........................................................49

4.5.7 Routing of SPA bus Protocol Telegrams ...................................................49

4.6 Telecontrol Functions....................................................................................................49

4.6.1 Indication Processing ................................................................................50

4.6.2 Analog Measured Value Processing ..........................................................50

4.6.3 Digital Measured Value Processing ...........................................................50

4.6.4 Integrated Total Processing........................................................................51

4.6.5 Direct Interfacing to Current/Voltage Transmitters ...................................51

4.6.6 Object Commands ......................................................................................52

4.6.7 Regulation Step Command Output ............................................................52

4.7 Communication .............................................................................................................52

4.6.1 Internal Communication.............................................................................52

4.6.2 External Communication............................................................................52

CHAPTER 5 SCADA Communication and Protocols

5.1 IED Station Communication .........................................................................................54

5.1.1 IEC 61850-8-1 Communication Protocol ..................................................54

5.1.2 LON Communication Protocol .................................................................54

5.1.3 SPA Communication Protocol ..................................................................55

5.1.4 Single Command, 16 Signals (CD) ............................................................56

5.1.5 Multiple Command (CM) and Multiple Transmit (MT)............................56

5.2 IED Remote Communication ........................................................................................56

5.3 RTU External Communication......................................................................................57

5.3.1 Telecontrol Protocols .................................................................................57

5.3.2 Host Communication Interfaces................................................................57

5.3.3 Sub-Device Communication Interfaces .....................................................58

5.3.4 Redundant Communication........................................................................58

Chapter 6 Protection and control IED Manager PCM600

6.1 Features .........................................................................................................................59

6.2 Engineering ...................................................................................................................59

6.3 Connection of signals ....................................................................................................60

6.4 Parameter setting ...........................................................................................................60

6.5 Disturbance handling.....................................................................................................61

6.6 Communication management Tool ...............................................................................61

6.7 How to Use the IED in Conjunction with PCM 600 Toolbox....................61

Conclusion and Suggestions ..........................................................................................63

References............................................................................................................................64

Chapter 1

Introduction

SCADA is an acronym that stands for supervisory control and data acquisition.

SCADA refers to a system that collects data from various sensors at a factory, plant or in

some remote locations and then sends this data to a central computer which then manages and

controls the data.

SCADA systems are used to control dispersed assets where centralized data

acquisition is important. These systems are used in distribution systems such as water

distribution and wastewater collection systems, oil and gas pipelines, electrical utility

transmission and distribution system, and rail and other public transportation systems.

SCADA systems integrate data acquisition systems with data transmission systems and HMI

software to provide a centralized monitoring and control system for numerous process input

and outputs. SCADA systems are used to collect field information, transfer it to central

computer facility and display the information to the operator graphically or textually, thereby

allowing the operator to monitor or control an entire system from a central location in real

time. Based on sophistication and setup of the individual system, control of any individual

system, operation, or task can be automatic, or it can be performed by operator commands.

1.1 SCADA System in General SCADA systems consist of both hardware and software. Typical hardware includes an

MTU placed at a control center, communication equipment (e.g. Radio, telephone line, cable,

or satellite), and one or more geographically distributed field sites consisting of either an

RTU or PLC, which controls actuators and/or monitor sensors. The MTU stores and

processes the information from RTU inputs and outputs, while the RTU or PLC controls the

local process. The communication hardware allows the transfer of information and data back

and forth between the MTU and RTU’s or PLC’s.

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Figure 1.1 shows the components and general configuration of a SCADA system. The

control center houses a control server (MTU) and communication routers. Other control

center components include the HMI, engineering workstations, and the historian, which are

all connected by a LAN. The control center collects and logs information gathered by the

field sites, displays information to the HMI, and may generate actions based upon detected

events. The control center is also responsible for centralized alarming, trend analyses and

reporting. The field site performs local control of actuators and monitor sensors. Field sites

are often equipped with a remote access capability to allow field operators to perform remote

diagnostics and repairs usually aver a separate dial up or WAN connection. Standard and

proprietary communication protocols running over serial communications are used to

transport information between the control center and field sites using telemetry techniques

such as telephone line, cable, fiber and radiofrequency such as broadcast, microwave and

satellite.

Figure 1.1 Components and general configuration of a SCADA system

1.2 Basic SCADA Communication Topologies MTU-RTU communication architectures vary among implementations. The various

architectures used include point-to-point, series-star and multi-drop. Point-to-point is

functionally the simplest type; however, it is expensive because of individual channels

2

needed for each connection. In a series connection, the number of channels used is reduced;

however, channel sharing has an impact on the efficiency and complexity of SCADA

operations. Similarly, the series-star and multi-drop configurations’ use of one channel per

device results in decreased efficiency and increased system complexity.

Figure 1.2 Basic SCADA communication topologies

1.3 Supervisory Control A control scheme whereby a computer or controller monitors and intermittently

downloads programs sets sub-goals or adjust control parameters of a level automatic

controller.

1.4 Data Acquisition

Process of collecting data from the system through some manual or automatic means

for the purpose of producing printed reports for operating, supervisory, maintenance or data

acquisition. “The process of disciplines”

3

1.5 Modules of SCADA Some of the modules of SCADA are discussed below briefly:

1.5.1 Remote Terminal Unit (RTU)

The main function of RTU is to collect data from plant and to transmit data to

different systems through a bus which run on specific protocols. Data may be send to a MTU,

remote supervisory center or to any site. RTU is a basic component of SCADA that converts

analog signals (either from some level sensor or temperature) to digital signals that can be

accepted at the PLC level.

Modern RTU’s are usually capable of executing simple programs autonomously

without involving the host computers of the DCS or SCADA system to simplify deployment

and to provide redundancy for safety reasons.

1.5.2 Master Terminal Unit (MTU)

Data from different RTU’s or remote sites come to MTU which stores and processes

the data and sends to other computers.

1.5.3 The Central SCADA Master System (HMI)

The HMI of a SCADA system is where data is processed and presented to be viewed

and monitored by a human operator. The interface usually includes control where the

individual can interface with SCADA system. HMI can also be linked to a database, which

can use data gathered from RTU’s or PLC’s to provide graphs on trends, logistic info,

schematics for a specific sensor or machine or even make troubleshooting guides accessible.

1.5.4 Communication Medias

Some of Communication Medias used in SCADA are discussed below briefly:

i. Copper Cable

Twisted pair copper cable is the most popular medium used for SCADA

communications and it has been used in its present form for many years.

ii. Coaxial Cable

It is simply a transmission line consisting of an unbalanced pair made up

of an inner conductor surrounded by a grounded outer conductor, which is

held in a concentric by a dielectric.

4

iii. Power Line Carrier (PLC)

PLC uses power transmission lines to transmit radio frequency signals.

PLC system operates in on-off ode by transmitting radio frequency signals

in the 10 to 500 kHz band over transmission lines. In Pakistan, for hilly

areas, SCADA communication is done over PLC because these sites are

not in-line.

iv. VHF/UHF Radio

It has no physical connection. This communication depends on distance

and the distance decides the use of specific signal. In Pakistan this type of

communication is used in plain areas where sites are in-line.

v. Satellite

It is especially when geographic placement of elements in the controlled

network is diverse through large areas with ‘virtually no terrestrial

communication networks’, removing the requirements to lay hundreds or

thousands of kms of wires. In Pakistan this mode is recently been. In

modern power plants.

vi. Fiber Optic Cable

Inside a plant communication is done with the help of optical fiber. It has

large bandwidth, so it can carry large data from plant which is de-

multiplexed by RTU. As this mode of communication is expensive on

large scale, so, it is not in use in Pakistan over large distances.

1.5.5 SCADA Software

The supervisory computer consists of a PC running either Campbell Scientifics’ HMI

software or another vendor’s software. InTouch, Intellution, Lookout and other software

packages can be used in conjunction with OPC client/server software application. Like other

HMI software packages, OPC client/server software provides a graphical interface that the

operator uses to view the status of remote sites, acknowledge alarms and control the units.

5

1.6 SCADA Security SCADA networks were initially designed to maximize functionality, with little

attention paid to security. As a result, performance, reliability, flexibility and safety of

distributed control/SCADA systems are robust, while the security of these systems of often

weak. This makes some SCADA networks potentially vulnerable to disruption of service,

process redirection or manipulation of operational data that could result in public safety

concerns and/or serious disruptions to the nation’s critical infrastructure. Action is required

by all organizations, government or commercial to secure their SCADA networks as part of

effort to adequately protect the nation’s critical infrastructure.

1.7 SCADA System Applications Some of the SCADA system applications are given below:

1.7.1 Alarm Processing

Alarm processing, processes the data collected and alerts the Control Center

Operators immediately, if an alarm condition is detected.

1.7.2 Tagging and Interlock Checking

Tagging and interlock checking functions help to prevent inadvertent errors and

ensure the safety of all persons working with the electricity network as well as supply

reliability.

1.7.3 Analytical and Forecast Tools

Analytical and forecast tools such as state estimator, contingency analysis, security

enhancement and short term load forecast are provided in the EMS to assist the control centre

operators to evaluate the status of its power network, forecast the system demand in future,

analyze and determine the outages of transmission and generating facilities, etc. in short, to

manage the system in a reliable and effective manner.

1.7.4 Historical Information System (HIS)

Extremely large volume of historical and future data can be stored and retrieved. The

system uses Oracle relation database as the database engine.

1.7.5 Operator Training Simulator

This provides hand-on training for the Control Centre Operators for normal,

emergency and restorative control of power system.

6

1.8 SCADA Future Research and technology development is required to fill the technology gaps between

the problems of today and the industry solutions of tomorrow. The direction of SCADA is

towards fully automated, distributed and self healing infrastructures. More intelligence and

system level security is needed to illuminate the issues associated with optimizing at a local

level and main-in-the-middle limitations. Constant efforts are being made to push the

capability of the infrastructure to a point where humans will not be able to respond quickly

enough to prevent or secure against an outage or attack.

1.9 SCADA Vendors Some of the SCADA vendors are given below:

Mass Group

OPTO 22 (Automation made simple)

red lion

Cal Amp

IPS (INVENSYS PROCESS SYSTEMS)

gridconnect

ABB (Asea Brown Bowery)

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Chapter 2

Literature Review

The primary sources of literature for this project were books, manuals and internet.

The help files provided with SCADA components and implementation are comprehensive

and covers all topics related to this project. Prof. Dr. Aftab Ahmad also helped, to gain

insight into this topic. Specially, Mr. Shehriar Khan helped in the completion of this project.

Tours have also been made in order to collect relevant technical material.

2.1 Literature Survey

2.1.1 Fundamentals of Power System Protection by Y.G.Paithankar & S.R. Bhinde

The book provides a very comprehensive material related to the protection of power

system. As the project is based upon the power system (power plant), the book provides the

basics of power system protection for the implementation of SCADA in power plants.

2.1.2 Power System Engineering by M.L.Soni & P.V. Gupta

The book provides complete basic information of power system but according to requirement of the project power plant portion is concerned mainly along with other helping material.

2.1.3 Securing SCADA Systems by Ronald L.Krutz

The book defines SCADA system components and functions, and provides

illustrations of general SCADA system architectures. The book also provides information

about the security importance of SCADA systems. The book also discusses the security

problems related to SCADA and the techniques to solve these security issues.

As security of SCADA systems is not prime focus of project, so only brief overview

of security risks for SCADA systems is studied from the book.

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2.1.4 SCADA: Supervisory Control and Data Acquisition by Stuart A. Boyer

The book provides basics of SCADA and gives an overview of related topics to

project. The book focuses on technologies that make SCADA easily understandable. The also

identifies basic differences between SCADA Systems of different industries. But again,

according to the project requirement only basics of SCADA is studied from the book.

2.1.5 Guide to Supervisory Control and Data Acquisition (SCADA) and Industrial

Control Systems Security by Keith Stouffer, Joe Falco, Karen Kent

The book provides basic difference between SCADA, DCS and ICS. But basically the

book is referred to study SCADA systems and the difference between SCADA and DCS and

SCADA system implementation and applications. In the book basic to deep concept of

SCADA is given but only relevant information about SCADA is taken from the book.

2.1.6 Research Paper on SCADA by A. Daneels & W.Salter

The research paper describes SCADA Systems in terms of their architecture, their

interface to the process hardware, functionality, scalability, performance and openness. Some

consideration is also given to the industrial standards of SCADA Systems.

2.1.7 Intrusion Detection and Cyber Security Monitoring of SCADA by Dale Peterson

The research paper describes how to protect SCADA from attacks of hackers, cyber

terrorists, and others who want to disrupt the critical infrastructure of SCADA System. The

paper also provides means for early detection of attacks from the most common threat agents.

The deficiencies and future specific solutions of SCADA system are also discussed. Only

brief overview of the paper is taken.

2.2 Background of SCADA SCADA (supervisory control and data acquisition) has been around as long as there

have been control systems. The first ‘SCADA’ system utilized data acquisition by means of

panels of meters, lights and strip chart recorders. The operator manually operating various

control knobs exercised supervisory control. These devices were and still are used to do

supervisory control and data acquisition on plants, factories and power generating facilities.

2.2.1 SCADA implementation by sensor to panel system

The following figure shows a sensor to panel system

9

Figure 2.1 Sensors to panel using 4–20 mA or voltage

The sensor to panel type of SCADA system has the following advantages:

It is simple, no CPUs, RAM, ROM or software programming needed

The sensors are connected directly to the meters, switches and lights on

the panel

It could be (in most circumstances) easy and cheap to add a simple

device like a switch or indicator

The disadvantages of a direct panel to sensor system are:

The amount of wire becomes unmanageable after the installation of

hundreds of sensors

The quantity and type of data are minimal and rudimentary

Installation of additional sensors becomes progressively harder as the

system grows

Re-configuration of the system becomes extremely difficult

Simulation using real data is not possible

Storage of data is minimal and difficult to manage

No off site monitoring of data or alarms

Someone has to watch the dials and meters 24 hours a day

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2.2.2 Architecture for Secure SCADA and Distributed Control System Networks

To address the security needs of control networks, it is essential to begin with a

layered defense-in-depth approach that enables administrators to monitor the network at

every level. Primary concerns for a control system network manager include:

Assuring the integrity of the data

Securing remote access

Validating and authenticating every device and user on the control system

network

A systematic approach to security begins with reducing the vulnerable surface of the

industrial control system network. The first step is the creation of control system-specific

policies that detail; which devices, what protocols and which applications may run on the

network, who has access to these devices and from where, and what are the types of

operations a user (or a role) is allowed to perform. The next step is to identify the appropriate

locations to implement the policy. This could be through the appropriate configuration of

controls on devices already present on the network, and by adding various network elements.

Such network elements are required to create a security perimeter, provide additional

enforcement points and segment the network for fault containment. The third step is to

monitor the implementation of the policy to ensure these controls are effective, locate any

violations and then feedback into the policy any corrections based on observed network

behavior. Security is a continuous process and requires diligent monitoring, reviewing and

adjusting to be effective. Figure below shows one of the existing technologies that can be

used for securing typical control networks.

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Figure 2.2 Typical electric SCADA network diagram

2.3 Remote Access of SCADA Remote access is enabled for several reasons: a plant operator/engineer may remotely

monitor equipment status, an ISO may need to collect current production data, or a vendor

may have to diagnose and fix operational problems. In order to minimize the probability of

unintentional misuse or tampering, users should be limited only to functions for which they

are authorized. For example, a vendor logging in to update a patch must not be able to run

any control system commands. If a contractor’s laptop contains spyware, or his antivirus is

not up to date, that contractor should not be allowed access to the control system network.

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Figure 2.3 Adding remote accesses to SCADA

2.4 Implementation of SCADA in Water Distribution Supervisory Control and Data Acquisition (SCADA) solutions for water systems

combined with, leak detection and use of Pressure Regulating Valve (PRV) stations may

significantly improve the situation. These measures have to be complemented with adapted

water conservation programs aimed at minimizing excessive water usage. These initiatives

shall combine to form a "water strategy" for conserving this valuable resource and making it

available at an affordable price.

Water companies are able to provide estimates of their production, imports, exports

and consumption, but are less able to point on reasons for unaccounted-for water. Water

losses can be determined by conducting periodic water balance in defined sections of a water

network. This calculation is based on the measurement of water flow, produced and imported

quantities compared to exported and consumed quantities. This can be done automatically by

the SCADA system and with RTUs, and the outcome provides a guide to how much water is

lost as a result of leakage from the network and how much of the water loss can be attributed

to other undetectable reasons.

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Figure 2.4 SCADA systems for water distribution

Water utilities are now seeking new ways to introduce improvements in their

maintenance processes, which may also reduce operating and maintenance costs. Introduction

of electronic microprocessor based pump efficiency monitoring, combined with water

SCADA systems will result in faster return on the investment in a SCADA system.

Implementation of this process involves:

Calculating the volume of pumped water as measured and logged by the RTU

Monitoring of the "peak power" drawn by the pump during its activation.

Monitoring the average energy supplied to that pump during the same period

2.5 Implementation of SCADA in oil and gas pipelines SCADA minimizes risk by providing integrated products and solutions as the Main

Automation Contractor (MAC) and the Main Electrical Contractor (MEC). Solutions for oil

and gas pipeline automation include block valve stations, pump stations, tank farms in liquid

applications and compressing, reducing and metering stations in gas applications.

Benefits using the SCADA integrated approach:

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Risk Management - everything working right first time.

Schedule Improvement - engineering, commissioning and start-up time

reduced.

Cost Reduction - lower engineering, start-up and maintenance costs.

Operational Efficiency - a reality that the total plant availability and

throughput will maximize the plant’s profit margin.

Best Use of Technology - truly integrated solution.

Designing It Right - providing best in class and fit for purpose solutions that

“build-in” long term benefits.

SCADA offers total solutions for transportation and distribution to manage the

movement of hydrocarbons through pipelines, tankers and terminals; eliminate losses; and

meet strict government regulations. From the stations to the control room, and on to the

boardroom. Pipeline data and pipeline components are presented as configurable software

objects. Each object carries a range of related information, such as electrical and mechanical

capabilities, intellectual properties and identity information that makes the object instantly

recognizable to enterprise-wide information networks. With Aspect Objects, pipeline

information is deployed rapidly and uniformly. Hence Supervisory Control And Data

Acquisition (SCADA) systems improve the use of pipeline facilities. The result is faster

turnaround with increased functionality.

15

Figure 2.5 SCADA in oil and gas pipeline

2.6 Application of the SCADA System in Waste water Treatment Plants The implementation of the SCADA system has a positive impact on the operations,

maintenance, process improvement and savings for city Wastewater Operations. The

application discusses the system's evolvement, the external/internal architecture, and the

human-machine-interface graphical design. The system also successes in monitoring the city

sewage and sludge collection/distribution systems, wet-weather facilities and wastewater

treatment plants, complying with the USEPA requirements on the discharge, and effectively

reducing the operations and maintenance costs.

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2.7 Application of SCADA in Hydro Power Plant Hydro automation improves efficiency and reduces operating expense. A number of

hydro plants are operated by remote control utilizing standard SCADA concepts. The rest of

the plants are manually controlled locally at the plant site. Intelligent control systems placed

at most of protecting and loading the generating units. The corporate WAN is used to transmit

schedules to the plants from the Hydro Dispatch Control Cell (HDCC) located in the Power

Business Center. If the WAN is unavailable for some reason, the local control system simply

continues to operate the plant according to the last schedule it received. SCADA

communication channels allow for manual control of the plants if the WAN is unavailable.

The basic control components and design concept for the HDCC are shown in Figure below.

Figure 2.6 Hydro dispatch control cell

Inter-plant communications between the various components of the automation

system are accomplished through one of three LANs. Communications between the local

operating work- station and the automation hardware is over an Ethernet fiber optic LAN

configured. All the Ethernet addresses on this LAN and the machine condition monitoring

17

(MCM) LAN are configured such that access to and from internet is not possible. The MCM

LAN, which also utilizes Ethernet connections, is used to allow the transfer of data between

third party machine condition monitoring systems and the automation system. The third LAN

in the automation system is the Profibus LAN that allows communication between the

various PLCs and their remote I/O. This LAN is entirely internal to the plant.

Figure 2.7 Automation philosophy of hydro-plant

2.8 SCADA for Offshore Wind Farms The SCADA system for wind farm monitoring and control will require a

communications network between the wind turbines in the wind farm, and back to the shore.

Candidate media for this are:

Copper twisted pair (RS485)

Fiber Optic - multi mode

Fiber Optic - single mode

Radio telemetry

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The SCADA system is conceptually separate to the machines and their controllers.

Unless there is a regulatory requirement that requires the machines to stop if there was a loss

of communications, the machines should be allowed to run independently of the SCADA

system status. Although the SCADA system needs to be reliable, there is no obvious benefit

in making it any more reliable than the power distribution network, if it utilizes

communications cables within the power cables.

2.9 Already Projects on SCADA Some projects have already been done on SCADA. Two of the projects with little

description are given below:

2.9.1 Supervisory Control and Data Acquisition

This project is related to the general study of SCADA and SCADA was not

implemented in any of the particular system. Various aspects of SCADA system were studied

in this project and some work on Micro-SCADA Simulator in terms of SCADA Simulation

was also a part of this project.

2.9.2 SCADA Implementation at CJPL Jaranwala

This project was implemented in spinning plant at CJPL Jaranwala. In the project

hardware is also implemented. The sensors used are switches and the data is collected at

RTU. In the project PLC is used as RTU.

2.9.3 General SCADA Educational Laboratory for Undergraduate Students

The work is done on Ms Basis. The thesis is generally about general SCADA, modern

trends in SCADA, SCADA applications and most importantly SCADA developed in lab to

have clear understanding of SCADA for the students of undergraduate. And the project

description is given below

Power factor improvement

Hardware needed to calculate power parameters

Control features to improve power factor

2.10 Present Project The objective of the project is the ‘Implementation of SCADA in Power Plant’. In the

project, study and observation is carried out on how data is collected from power plant, which

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technology is used to collect data, which mode of communication is used to transfer data

from plant to RTU, which sensors are used, which protocols are used, whether the technology

implemented is based on relay logic, PLC or IED. Also mode of communication between

power plant and National Power Control Center (NPCC) is taken under consideration.

The project is the general implementation of SCADA in power plants or substations.

This generalized concept can be applied to any power plant or substation. ABB technology is

used in the implementation in the project. If in any other power plant or substation, SCADA

is implemented other than ABB, there can be a slight difference in technology, protocols,

name of components etc but the main method and scheme will remain same. So, the study

can be applied to any power plant or substation with SCADA with a slight difference.

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CHAPTER 3

Data Collection

Data from different components of the power plant or substation is collected with the

help of intelligent electronic devices (IEDs) and terminal units. Different IEDs are used to

collect data from different components of plant. This collected data is then used for

protection, monitoring and control of these components and hence control of power plant or

substation.

In this chapter features of different IEDs and terminal units from ABB are

overviewed. It is also discussed that, what are the requirements of these IEDs and terminal

units, what kind of protection is offered by these IEDs and terminal units and how data is

collected by these IEDs and terminal units.

3.1 Basic IED Applications:

3.1.1 Self Supervision with Internal Event List

The protection and control IEDs have a complex design with many included

functions. The included self-supervision function and the internal signals function block

provide good supervision of the IED. The fault signals make it easier to analyze and locate a

fault. Both hardware and software supervision is included and it is also possible to indicate

possible faults through a hardware contact on the power supply module and/or through the

software communication. Internal events are generated by the built-in supervisory functions.

The supervisory functions supervise the status of the various modules in the IED and, in case

of failure, a corresponding event is generated. Similarly, when the failure is corrected, a

corresponding event is generated.

3.1.2 Voltage Selection

The Bus bar voltage must in many cases be used as reference for line or bay

protection.

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Examples are:

Line distance protection where the bus bar is provided with three phase

voltage transformers and the lines with only single-phase sets for Synchronism

check reference. The Synchronism check function in IED 670 has a built-in

voltage selection.

Bus voltage protection e.g. Over- and under voltage, Over- and under

frequency protection functions in the bay.

Voltage reference for metering functions - where three phase voltage

transformers do not exist on the object.

A voltage selection can be created in IED 670 with user defined logic where

positions of disconnectors (and breakers) are used to create the required

voltage selection.

The voltage transformers for a double bus system are connected to the line

protection function, which may be line distance relays or voltage or frequency

relays.

Supervision of the fuse/MCB failures can be fed through the same logic and

connected to e.g. block operation of under voltage functions.

It is also a possible to block functions when both disconnectors are open.

3.1.3 Automatic Opening of Transformer Disconnector and Closing the Ring Breakers

The available function blocks to create user defined logic can be utilized for many

functions. One example is to open the transformer High voltage disconnector at internal

transformer faults in multi-breaker arrangements and then close the ring or one- and a half

breaker diameter.

The logic can include status supervision before the fault was tripped to ensure that the

sequence is only closing apparatuses already closed before the fault, information about the

fault to ensure it was a transformer fault, check that the disconnector is open before the

breaker/s is/are closed and verification that the new status has been reached before next

sequence is started.

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3.1.4 Automatic Load Transfer from bus A to bus B

With transformer applications it is sometimes required to automatically transfer the

load from one transformer to the other. It includes closing bus tie and closing transformer

breakers. It mostly also involves switching back after the normal supply has been restored to

the original transformer. The load transfer scheme includes a combination of advance logic

checking apparatus positions and the measurement of bus and transformer voltage and the use

of Synchronism check device to control the closing.

An advanced alternative exists for generating stations where the unit transformer

supplies will need to synchronize at switching and this synchronizing is done on a decaying

bus voltage on voltage level as well as frequency level depending on the available

synchronous and asynchronous machines maintaining the bus voltage.

3.2 IED Requirements

3.2.1 Current Transformer Requirements

The performance of a protection function will depend on the quality of the measured

current signal. Saturation of the current transformer (CT) will cause distortion of the current

signal and can result in a failure to operate or cause unwanted operations of some functions.

Consequently CT saturation can have an influence on both the dependability and the security

of the protection. The protection IED has been designed to permit heavy CT saturation with

maintained correct operation.

3.2.2 SNTP Server Requirements

The SNTP server to be used shall be connected to the local network, i.e. not more

than 4-5 switches/routers away from the IED. The SNTP server shall be dedicated for its task,

or at least equipped with at real-time operating system, i.e. not a PC with SNTP server

software. The SNTP server shall be stable, i.e. either synchronized from a stable source like

GPS, or local i.e. without synchronization.

3.3 Monitoring Functions in IED Every IED is provided with the following monitoring functions:

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3.3.1 Measurements

Measurement functions are used for power system measurement, supervision and

reporting to the local HMI. The possibility to continuously monitor measured values of active

power, reactive power, currents, voltages, frequency, power factor etc. is vital for efficient

production, transmission and distribution of electrical energy. It provides to the system

operator fast and easy overview of the present status of the power system.

Additionally it can be used during testing and commissioning of protection and

control IEDs in order to verify proper operation and connection of instrument transformers

(i.e. CTs & VTs). During normal service by periodic comparison of the measured value from

the IED with other independent meters the proper operation of the IED analog measurement

chain can be verified. Finally it can be used to verify proper direction orientation for distance

or directional over current protection function.

Dead-band supervision can be used to report measured signal value to station level

when change in measured value is above set threshold limit or time integral of all changes

since the last time value updating exceeds the threshold limit. Measure value can also be

based on periodic reporting.

3.3.2 Event Counter

This function has six counters which are used for storing the number of times each

counter has been activated. All six counters have a common blocking function used, for

example, when testing. All six counters have a common reset and a common function.

3.3.3 Event Function

When using a Substation Automation system with LON or SPA communication, time

tagged events can be sent at change or cyclically from the IED to the station level. These

events are created from any available signal in the IED that is connected to the Event function

block. The event function block is used for LON and SPA communication.

3.3.4 Disturbance Report

To get fast, complete and reliable information about disturbances in the primary and/

or in the secondary system it is very important to gather information on fault currents,

voltages and events. It is also important having a continuous event-logging to be able to

monitor in an overview perspective. These tasks are accomplished by the Disturbance Report

function and facilitate a better understanding of the power system behavior and related

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primary and secondary equipment during and after a disturbance. An analysis of the recorded

data provides valuable information that can be used to explain a disturbance, basis for change

of relay setting plan, improve existing equipment etc. This information can also be used in a

longer perspective when planning for and designing new installations, i.e. a disturbance

recording could be a part of Functional Analysis (FA).

Every disturbance report recording is saved in the IED. The same applies to all events,

which are continuously saved in a ring-buffer. The Local Human Machine Interface (LHMI)

is used to get information about the recordings, and the disturbance report files may be

uploaded to the PCM 600 (Protection and Control IED Manager) and further analysis using

the Disturbance Handling tool. If the IED is connected to a station bus (IEC 61850-8-1),

according to IEC 61850, disturbance recorder and fault location information will be available

on the bus. The same information will be obtainable if IEC 60870-5-103 is used.

3.3.5 Event List

From an overview perspective, continuous event-logging is a useful system

monitoring instrument and is a complement to specific disturbance recorder function. The

event list (EL), always included in the IED, logs all selected binary input signals connected to

the Disturbance report function. The list may contain of up to 1000 time tagged events stored

in a ring-buffer where, if the buffer is full, the oldest event is overwritten when a new event is

logged.

The difference between the event list (EL) and the event recorder (ER) function is that

the list function continuously updates the log with time tagged events while the recorder

function is an extract of events during the disturbance report time window. The event list

information is available in the IED and the user can use the Local Human Machine Interface

(LHMI) to get the information. The list can also be uploaded from the PCM 600 tool.

3.3.6 Indications

Fast, condensed and reliable information about disturbances in the primary and/or in

the secondary system is important. Binary signals that have changed status during a

disturbance are an example of this. This information is used primarily in the short term (e.g.

immediate disturbance analysis, corrective actions) to get information via the LHMI in a

straightforward way without any knowledge of how to handle the IED. There are three LED’s

on the LHMI (green, yellow and red) which will display status information about the IED (in

service, internal failure etc.) and the Disturbance Report function (trigged).

25

The Indication function (IND), always included in the IED, shows all selected binary

input signals connected to the Disturbance Report function that have been activated during a

disturbance. The status changes are logged during the entire recording time, which depends

on the set of recording times (pre-, post-fault and limit time) and the actual fault time. The

indications are not time-tagged. The indication information is available for each of the

recorded disturbances in the IED and the user may use the Local Human Machine Interface

(LHMI) to view the information.

3.3.7 Event Recorder

Quick, complete and reliable information about disturbances in the primary and/or in

the secondary system is vital e.g. time tagged events logged during disturbances. This

information is used for different purposes in the short term (e.g. disturbance analysis,

corrective actions) and in the long term (e.g. disturbance analysis, statistics and maintenance,

i.e. Functional Analysis).

The event recorder (ER), always included in the IED, logs all selected binary input

signals connected to the Disturbance Report function. Each recording can contain up to 150

time-tagged events. The events are logged during the total recording time, which depends on

the set of recording times (pre-, post-fault and limit time) and the actual fault time. During

this time, the first 150 events for all 96 binary signals are logged and time-tagged.

The event recorder information is available for each of the recorded disturbances in

the IED and the user may use the Local Human Machine Interface (LHMI) to get the

information. The information is included in the disturbance recorder file, which may be

uploaded to the PCM 600 (Protection and Control IED Manager) and further analyzed using

the Disturbance Handling tool. The event recording information is an integrated part of the

disturbance record (Comtrade file).

3.3.8 Trip Value Recorder

Fast, complete and reliable information about disturbances such as fault currents and

voltage faults in the power system is vital. This information is used for different purposes in

the short perspective (e.g. fault location, disturbance analysis, corrective actions) and the long

term (e.g. disturbance analysis, statistics and maintenance, i.e. Functional Analysis).

The trip value recorder (TVR), always included in the IED, calculates the values of all

selected external analog input signals (channel 1-30) connected to the Disturbance Report

26

function. The estimation is performed immediately after finalizing each recording and

available in the Disturbance Report. The result is magnitude and phase angle before and

during the fault for each analog input signal. The information is used as input to the fault

location function (FL), if included in the IED and in operation.

The trip value recorder information is available for each of the recorded disturbances

in the IED and the user may use the Local Human Machine Interface (LHMI) to get the

information. The information is included in the disturbance recorder file, which can be

uploaded to the PCM 600 (Protection and Control IED Manager) and further analyzed using

the Disturbance Handling tool.

3.3.9 Disturbance Recorder

To get fast, complete and reliable information about fault current, voltage, binary

signal and other disturbances in the power system is very important. This is accomplished

by the Disturbance Recorder function and facilitates a better understanding of the behavior of

the power system and related primary and secondary equipment during and after a

disturbance. An analysis of the recorded data provides valuable information that can be used

to explain a disturbance, basis for change of IED setting plan, improvement of existing

equipment etc. This information can also be used in a longer perspective when planning for

and designing new installations, i.e. a disturbance recording could be a part of Functional

Analysis (FA).

The Disturbance Recorder (DR), always included in the IED, acquires sampled data

from all selected analog input and binary signals connected to the function blocks i.e.

maximum 30 external analog, 10 internal (derived) analog and 96 binary signals. The

function is characterized by great flexibility as far as configuration, starting conditions,

recording times, and large storage capacity are concerned. Thus, the disturbance recorder is

not dependent on the operation of protective functions, and it can record disturbances that

were not discovered by protective functions.

3.4 Logic Functions in IED

Every IED is provided with the following logic functions:

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3.4.1 Configurable Logic Blocks

A high number of logic blocks and timers are available for user to adapt the

configuration to the specific application needs. There are no settings for AND gates, OR

gates, inverters or XOR gates. For normal On/Off delay and pulse timers the time delays and

pulse lengths are set from the CAP configuration tool. Both timers in the same logic block

(the one delayed on pick-up and the one delayed on drop-out) always have a common setting

value. Pulse length settings are independent of one another for all pulse circuits. For

controllable gates, settable timers and SR flip-flops with memory, the setting parameters are

accessible via the local HMI or Protection and Control IED Manager (PCM 600).

3.4.2 Fixed Signal Function Block

The fixed signals function block generates a number of pre-set (fixed) signals that can

be used in the configuration of an IED, either for forcing the unused inputs in the other

function blocks to a certain level/value, or for creating certain logic.

3.4.3 Boolean 16 to Integer Conversion

The B16I function block (or the Boolean 16 to integer conversion block) is used to

transform a set of 16 binary (logical) signals into an integer. It can be used – for example, to

connect logical output signals from a function (like distance protection) to integer inputs from

another function (like line differential protection).

3.4.4 Boolean 16 to Integer Conversion with Logic Node Representation

This function block (or the Boolean 16 to integer conversion with logic node

representation block) is used to transform an integer into a set of 16 binary (logical) signals.

This function block can receive an integer from a station computer – for example, over

IEC61850. These functions are very useful when you want to generate logical commands (for

selector switches or voltage controllers) by inputting an integer number.

3.4.5 Integer to Boolean 16 Conversion

This function block (or the integer to Boolean 16 conversion block) is used to

transform a set of 16 binary (logical) signals into an integer. It can be used – for example, to

connect logical output signals from a function (like distance protection) to integer inputs from

another function (like line differential protection).

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3.4.6 Integer to Boolean 16 Conversion with Logic Node Representation

This function block (or the integer to Boolean 16 conversion with logic node

representation block) is used to transform an integer into a set of 16 binary (logical) signals.

This function block can receive an integer from a station computer – for example, over

IEC61850. These functions are very useful when you want to generate logical commands (for

selector switches or voltage controllers) by inputting an integer number.

3.5 Indication LEDs The function block HLED (LED Monitor) controls and supplies information about the

status of the indication LEDs. The input and output signals of HLED are configured with the

PCM 600 tool. The input signal for each LED is selected individually with the PCM 600

Signal Matrix Tool (SMT). LEDs for trip indications are red and LEDs for start indications

are yellow.

3.6 Human Machine Interface The local human machine interface is available in a small, and a medium sized model.

The principle difference between the two is the size of the LCD. The small size LCD can

display seven line of text and the medium size LCD can display the single line diagram with

up to 15 objects on each page.

The local human machine interface is equipped with an LCD that is used among other

things to locally display the following crucial information:

Connection of each bay with respect to the two differential protection zones

and the check zone. The user can freely set in PST the individual bay names in

order to make easy identification of each primary bay for station personnel

Status of each individual primary switchgear device (i.e. open, closed, 00 as

intermediate and 11 as bad state). The user can freely set in PCM 600 the

individual primary switchgear object names in order to make easy

identification of each switchgear device for station personnel

The local human machine interface is equipped with an LCD that can display the

single line diagram with up to 15 objects.

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Figure 3.1 Bay to zone connection example

3.7 REB670 REB670 is a product of ABB. It is designed for the selective, reliable and fast

differential protection of bus bars, T-connections and meshed corners. REB 670 can be used

for protection of single and double bus bar with or without transfer bus, double circuit

breaker or one and- half circuit breaker stations. The IED is applicable for the protection of

medium voltage (MV), high voltage (HV) and extra high voltage (EHV) installations at a

power system frequency of 50Hz or 60Hz. The IED can detect all types of internal phase-to-

phase and phase-to-earth faults in solidly earthed or low impedance earthed power systems,

as well as all internal multi-phase faults in isolated or high impedance earthed power systems.

Differential protection zones in REB 670 include a sensitive operational level. This

sensitive operational level is designed to be able to detect internal bus bar earth-ground faults

30

in low impedance earthed power systems (i.e. power systems where the earth-fault current is

limited to a certain level, typically between 300A and 2000A primary by a neutral point

reactor or resistor). Alternatively this sensitive level can be used when high sensitivity is

required from bus bar differential protection (i.e. energizing of the bus via long line).

Overall operating characteristic of the differential function in REB 670 is shown in

the following figure.

Figure 3.2 REB 670 operating characteristic

3.7.1 Differential Protection Using REB670

In REB670 numerical protection relays, all CT and VT inputs are galvanically

separated from each other. All analog input quantities are sampled with a constant sampling

rate and these discreet values are then transferred to corresponding numerical values (i.e. AD

conversion). After these conversions, only the numbers are used in the protection algorithms.

Therefore, for the modern numerical differential relays the secondary CT circuit resistance

might not be a decisive factor any more.

The important factor for the numerical differential relay is the time available to the

relay to make the measurements before the CT saturation, which will enable the relay to take

the necessary corrective actions. This practically means that the relay has to be able to make

the measurement and the decision during the short period of time, within each power system

cycle, when the CTs are not saturated. From the practical experience, obtained from heavy

current testing, this time, even under extremely heavy CT saturation, is for practical CTs

around two milliseconds. Because of this, it was decided to take this time as the design

criterion in REB 670 IED, for the minimum acceptable time before saturation of a practical

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magnetic core CT. Thus, the CT requirements for REB 670 IED are kept to an absolute

minimum.

Only three values are needed to REB670 for the differential protection.

i. incoming current (i.e. sum of all currents which are entering the protection

zone)

ii. outgoing current (i.e. sum of all currents which are leaving the protection

zone)

iii. differential current (i.e. sum of all currents connected to the protection zone)

3.7.2 Zone Selection Features

The REB670 offers an extremely effective solution for stations where zone selection

(i.e. CT switching) is required. This is possible due to the software facility, which gives full

and easy control over all CT inputs connected to the IED. The philosophy is to allow every

CT input to be individually controlled by a setting parameter. This parameter called ZoneSel

can be individually configured for every CT input, which is available within REB 670 IED.

This parameter, for every bay, can be set to only one of the following five alternatives:

i. FIXEDtoZA

ii. FIXEDtoZB

iii. FIXEDtoZA&-ZB

iv. CtrlIncludes

v. CtrlExcludes

If for a particular CT input setting parameter ZoneSel is set to FIXEDtoZA, then this

CT input will be only included to the differential zone A. This setting is typically used for

simple single zone application such as: single bus bar stations, one-and-a-half breaker

stations or double breaker stations.

If for a particular CT input setting parameter ZoneSel is set to FIXEDtoZB, then this

CT input will be only included to the differential zone B. This setting is typically used for

applications such as: one-and-a-half breaker stations or double breaker stations.

If for a particular CT input setting parameter ZoneSel is set to FIXEDtoZA&-ZB,

then this CT input will be included to the differential zone A, but its inverted current value

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will be as well included to the differential zone B. This setting is typically used for bus

coupler or bus section bays when only one current transformer is available.

3.7.3 Tripping Circuit Arrangement

The contact outputs on REB 670 are of medium duty type. It is possible to use them to

directly trip the individual bay circuit breakers. This solution is suitable for all types of

station arrangements. The internal zone selection logic provides individual bay trip signals in

REB 670 internal software and no external relay for this purpose are required. This

arrangement insures correct trip signal distribution to all circuit breakers in case of bus bar

protection operation or individual bay breaker failure protection operation. Breaker fail

protection can be internal or external to REB 670 IED.

3.7.4 Trip Circuit Supervision for Bus bar Protection

Trip circuit supervision is mostly required to supervise the trip circuit from the

individual bay relay panel to the circuit breaker. It can be arranged also for the tripping

circuits from the bus bar protection.

However, it can be stated that the circuit from a bus bar protection trip relay located in

the bus bar protection panel is not so essential to supervise as bus bar faults are very rare

compared to faults in bays, especially on overhead power lines. Also it is normally a small

risk for faults in the tripping circuit and if there is a fault it affects only one bay and all other

bays are thus correctly tripped meaning that the fault current disappears or is limited to a low

value.

3.8 Transformer Terminal RET 54_X RET 541/543/545 transformer terminals are designed to be used for the protection,

control, measurement and supervision of two-winding power transformers and generator

transformer blocks in distribution networks.

The main protection function is three-phase current differential protection with

stabilized and instantaneous stages for fast and selective winding short-circuit and interturn

protection. Besides 2nd and 5th harmonic restraints, the stabilized stage also includes a

waveform recognition-based blocking-deblocking feature. Reliable operation even with

partially saturated current transformers, that is, short operate times at faults occurring in the

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zone to be protected and high stability at external faults are achieved. Increased sensitivity

can be obtained by automatic adaptation to the position changes of the on load tap changer.

In addition to the differential protection, the Basic version terminals incorporate the

following protections:

Restricted earth fault protection with stabilized numerical or high impedance

principle, unbalance and thermal overload protections, three phase over-current and

directional or non directional earth fault back-up protection with definite and IDMT

characteristics on both sides of the transformer.

With the optional automatic voltage regulation function, RET 54_ transformer

terminal can be applied as a comprehensive integrated transformer management terminal. The

voltage regulator can be applied for a single transformer or for parallel transformers with

Master Follower, Negative Reactance or Minimizing Circulating Current principles.

RET 541/543/545 terminals can measure two sets of three phase currents, phase-to-

phase or phase-to-earth voltages, neutral current, residual voltage, frequency and power

factor. Active and reactive power is calculated from the measured currents and voltages.

Energy can be calculated on the basis of the measured power. The measured values can be

indicated locally and remotely as scaled primary values. With the condition monitoring

functions, RET 54_ transformer terminal monitors e.g. trip circuits, gas pressure of the

breaker and breaker wear, and provides scheduled time intervals for maintenance.

By means of the graphic HMI display, the control functions in the transformer

terminal indicate the position of disconnectors, circuit breakers and tap changer locally. Local

control of these objects is possible via the push buttons on the front panel of the transformer

terminal. Furthermore, the transformer terminal allows position information of the objects to

be transmitted to the remote control system. Controllable objects, such as CBs, can also be

opened and closed over the remote control system.

3.8.1 Functions of the Transformer Terminal

The functions of the RET 54_ transformer terminal are categorized as:

Protection functions

measurement functions

control functions

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condition monitoring functions

communication functions

general functions

standard functions

Some of these are detailed below:

3.8.2 Control Functions

The control functions are used to indicate the position of switching devices, i.e. circuit

breakers and disconnectors, and to execute open and close commands for controllable

switching devices in the switchgear. Furthermore, there are supplementary functions for

control logic purposes, e.g. on/off switches, MIMIC alarm, LED control, numerical data for

the MIMIC and logic controlled position selection.

3.8.3 Communication Functions

The RET 54_ transformer terminal provides the IEC_103, Modbus1, DNP 3.01, SPA

and LON serial communication protocols.

3.8.4 Standard Functions

Standard functions are used for logics, such as interlocking, alarming and control

sequencing. The use of logic functions is not limited and the functions can be interconnected

with each other as well as with protection, measurement, power quality, control, condition

monitoring and general functions.

3.8.5 System Structure

The system very often resembles the system in the figure below. The protection,

control or alarm functions are implemented by using RET 54_ transformer terminals,

SPACOM units or other SPA bus devices (devices connected to the system via the SPA bus).

Generator or motor transformers are protected and controlled with RET 54_ transformer

terminals.

35

Figure 3.3 Example of a LON-based substation automation system

3.9 Feeder Terminal REF 54_X The REF 54_feeder terminals are designed to be used for the protection, control,

measurement and supervision of medium voltage networks. They can be used with different

kinds of switchgear including single bus bar, double bus bar and duplex systems. The

protection functions also support different types of networks, such as isolated neutral

networks, resonant earthed networks and partially earthed networks.

The functionality available for REF 54_ depends on the selected functionality level

and is also tied to the hardware configuration. The desired functions can be activated from a

wide range of protection, control, measurement, power quality, condition monitoring, general

and communication functions within the scope of I/O connections, considering the total CPU

load. Compared to the traditional use of separate products, the combination of desired

functions provides cost-effective solutions and, together with the relay configuration (IEC

61131-3 standard), allows the REF 54_ feeder terminals to be easily adapted to different

kinds of applications.

By means of the graphic HMI display, the control functions in the feeder terminal

indicate the position of disconnectors or circuit breakers locally. Further, the feeder terminal

36

allows position information from the circuit breakers and the disconnectors to be transmitted

to the remote control system. Controllable objects, such as CBs, can be opened and closed

over the remote control system. Position information and control signals are transmitted over

the serial bus. Local control is also possible via the push-buttons on the front panel of the

feeder terminal.

The feeder terminal is designed to be used for the selective short-circuit and earth

fault protection. The feeder protection type REF 54_ includes over current and earth fault

functions and is used for feeder short-circuit, time over current and earth-fault protection in

solidly, resistant or resonant-earthed networks and in isolated neutral networks. When

desired, auto-reclosing is achieved by using the auto-reclose function. Up to five successive

auto-reclose cycles can be carried out.

The REF 54_ terminal measures phase currents, phase-to-phase or phase-to-earth

voltages, neutral current, residual voltage, frequency and power factor. Active and reactive

power is calculated from measured currents and voltages. Energy can be calculated on the

basis of the measured power. The measured values can be indicated locally and remotely as

scaled primary values.

With the condition monitoring functions the REF 54_ feeder terminal monitors for

example gas pressure and breaker wear, registers the operate time and provides scheduled

time intervals for maintenance. In addition to protection, measurement, control and condition

monitoring functions, the feeder terminals are provided with a large amount of PLC functions

allowing several automation and sequence logic functions needed for substation automation

to be integrated into one unit. The data communication properties include SPA bus

communication, LON bus communication, IEC 60870-5-1031 communication, DNP 3.0

communication or Modbus communication with higher-level equipment. Further, LON

communication, together with PLC functions, minimizes the need for hardwiring between the

units.

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Figure 3.4 A distributed protection and control system based on REF 54_ feeder and RET 54_ transformer terminals

3.9.1 Functions of the Feeder Terminal

The functions of the REF 54_ feeder terminal are categorized as:

Protection functions

Measurement functions

Power quality functions

Control functions

Condition monitoring functions

Communication functions

General functions

Standard functions

Some of these are detailed below:

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3.9.2 Protection Functions Protection is one of the most important functions of the REF 54_ feeder terminal. The

protection function blocks (for example NOC3Low) are independent of each other and have

their own setting groups and data recording. Conventional current transformers can be used

for protection functions based on current measurement. Correspondingly, voltage dividers or

voltage transformers are used for protection functions based on voltage measurement.

3.9.3 Control Functions

The control functions are used to indicate the position of switching devices, that is,

circuit breakers and disconnectors, and to execute open and close commands for controllable

switching devices in the switchgear. Furthermore, there are supplementary functions for

control logic purposes, such as on/off switches, MIMIC alarm, LED control, numerical data

for the MIMIC and logic controlled position selection.

3.9.4 Communication Functions

The REF 54_ feeder terminal provides the IEC_103, Modbus, DNP 3.0, SPA and LON

serial communication protocols.

3.9.5 Standard Functions

Standard functions are used for logics, such as interlocking, alarming and control

sequencing. The use of logic functions is not limited and the functions can be interconnected

with each other as well as with protection, measurement, power quality, control, condition

monitoring and general functions.

3.9.6 System Structure

The system very often resembles the system in the following figure. The protection,

control or alarm functions are implemented by using REF 54_ feeder terminals, SPACOM

units or other SPA bus devices (devices connected to the system via the SPA bus). Generator

or motor feeders are protected and controlled with REF 54_ feeder terminals.

39

Figure 3.5 Example of a LON-based substation automation system

40

CHAPTER 4

Data Integration and Processing

All the components in a power plant are connected to a remote terminal unit (RTU).

So, all the data from different components is integrated at RTU. Then, from RTU the data is

send to local control unit and also to remote control unit (MTU).

ABB uses RTU560 as its remote terminal unit. Its basic features and its configuration

to integrate data are discussed in this chapter.

4.1 Introduction The RTU560 is required to be configurable to nearly all demands made on remote

stations in networks for electricity, gas, oil, water or district heating.

Increasing capabilities of decentralized control and closed-loop control solutions

allows running more functions to be done in the station directly. The RTU560 supports this

by own PLC programs which may use for control tasks on one side and by the capability to

communicate with the external control, protection and monitoring units via serial lines on the

other side. The RTU560 will distribute process information from these units on the demands

for station and network control to several network control centers (NCC). Following figure

will clear the idea.

41

Figure 4.1 Typical configuration of a telecontrol system

4.2 General Features of RTU560 The telecontrol system RTU560 should be in the position to transmit nearly all kind of

process information, derived from various units in the station, to the control centers and to

marshal commands received from the control centers to the addressed control unit within the

station.

Beside the acquisition and processing of the directly parallel wired process signals to

the RTU560 IO-process interface, the RTU560 is designed for the link of serial

communication routes within the station as well to the higher control level. This can be

another RTU560 router station or a network control center. Within the station it is the

connection of other existing additional control, protection or monitoring devices (Intelligent

Electronic Devices = IED) via serial interfaces.

Functional system features of the RTU560 to fulfill the requirements for remote

control stations:

High functional scope for telecontrol applications functions

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PLC capabilities to execute control and closed loop control applications for

pump stations, hydro power plants, station interlocking for electrical

substations, etc..

Archiving of process and station events in a sequence of events list in the

Flash memory. Accessible via Intranet or equivalent independent network.

Archiving of Integrated Totals (ITI) and Analog Measured Values (AMI) in

the Flash memory. Accessible via Intranet or equivalent independent network.

Reading and archiving of disturbance files from protection relays on request of

the protection relay. Reading of the disturbance files by file transfer over a

separate communication network (e.g. Intranet) on user's demand. Independent

and direct information of available new disturbance files in the disturbance file

archive to the NCC.

Possibility to build (engineer) group alarms for the typical alarm messages,

beside a PLC program.

Interfacing nearly all types and big numbers of IEDs in a station via serial

telecontrol protocols, like IEC 60870-5-103, MODBUS, SPA-Bus, DNP 3.0,

or via Ethernet like IEC 60870-5-104 or IEC 61850.

Marshalling and filtering process events to the connected NCCs. Decoupling

transaction sequences and delay times to the different NCCs by using a

separate process data base per NCC link.

Remote access for diagnostic purposes via Web-Browser and Internet or

Intranet. With detailed information down to each process signal.

Integrated HMI (Human Machine Interface) for process supervision and

control. Via Web-Browser and Internet or Intranet.

4.3 RTU560 System Concept

The RTU560 is based on a communication node which is highly flexible. The number

of CMU boards depends on the demands in a station or router RTU. The figure blow shows

the basic concept for the RTU560 family.

43

Figure 4.2 RTU560 System concepts

Each CMU type has a number of serial interfaces to connect serial communication

links. Each CMU can run up to two different communication protocols either as Host

Communication Interface (HCI=Slave protocol) or as Sub-device Communication Interface

(SCI = master protocol).

This concept allows cascading the number of CMUs to the demands on different

protocols and interfaces.

The second main point is the internal communication concept. To avoid several

special conversions etc. all process informations, regardless from which interface received,

are converted into an internal presentation and distributed to all CMUs via the RTU560

System bus. Therefore each protocol module needs always only the conversion into / from

the internal presentation. This requests also that each protocol module has its own process

data base for signal processing etc.

4.4 RTU560 Communication and Module Concept The high processing performance of the RTU560 is accomplished by the efficient

distribution of the tasks to the communication and processing units (CMU) and the micro-

44

controllers on the I/O boards. The software concept is designed to communication and

application modules which have clear interfaces between each other. This allows configuring

and arranging the modules in a good flexibility to the project demands.

Already the RTU232 has the basis of this concept by splitting the work between the

CPU board (23ZG21) and the IO boards. Each IO board has its own micro-controller and

does the basic tasks for the connected process signals, like time stamping, threshold

monitoring for analog input signals or command output supervision for switching commands.

Figure 4.3 Example of a RTU560 organization in hardware modules

The above picture about the RTU560 organization shows the modularity by

connecting the IEDs, IO modules and the NCCs to different CMU. The below picture shows

a configuration in modules which are needed for a typical medium RTU560 with one CMU.

The main modules are:

45

i. HCI Host Communication Interface

ii. SCI Sub-device Communication Interface

iii. PDP Process Data Processing (includes communication via

the

560 RTU serial peripheral bus with the i/o boards)

iv. PLC Programmable Logic Control

v. Archive Process event archive Integrated Total Information (ITI)

Archive Analog measured value (AMI) archive

vi. DIST. Archive Disturbance Data Archive

vii. Load Profile Archive for Alpha Counter Load Profiles

viii. Integrated HMI Integrated Human Machine Interface

Figure 4.4 Example of communication and application modules within one CMU

4.5 RTU560 Application Functions The RTU560 supports a number of application functions which are requested for

typical remote substations. The module concept gives the possibility to configure these

functions on request and cost optimized.

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4.5.1 Telecontrol Functions

The main task of an RTU is the telecontrol task. Telecontrol means "remote control".

This involves the use of radio waves for radio control of devices or machinery at a remote

location. This is used principally for remote control of machinery and the industrial

equipment used for engineering work, construction, forestry and the like.

Binary Signals

Binary signal acquisition with a time resolution of 1 ms

Event detection and time stamping

Digital filter for signal bouncing

Chatter suppression of unstable signals

Signal inversion

Calculating group alarms (AND, OR) with a time stamp of the signal

forcing the group alarm (no PLC program)

Monitoring double indications and double commands

Integrated totals with up to 125 Hz

Integrated totals with up to 8 kHz by pre-divider and for continuous

counting

RTU560A / C supports (1-out-of-n)-check for interposing relays of

output commands

Analog Signals

Zero dead-band supervision

Live-zero monitoring (e.g. 4 … 20/40 mA)

Smoothing

Threshold monitoring with integration method

Threshold monitoring with absolute threshold

4.5.2 General Functions

i. Support of different time synchronization methods

by GPS/DCF77/IRIG-B receiver

by telecontrol protocol (e.g. IEC 60870-5-101)

by external minute pulse (e.g. from a master clock within the station)

ii. Distribution

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4.5.3 Programmable Logic Control (PLC)

The PLC module has access to the controlling process via its process interface imaged

in the RTU560 process DB actualized by the internal communication. That allows to use

nearly all process information from direct connected process signals as well as from process

data points received via serial communication line. Control information for actuators to the

process will be handled in the same way from the PLC to the physical output signals etc. The

overall transaction time for a PLC task is therefore given by the PLC cycle time plus the

update time between the process actuators and sensors and the PLC's RTU560 process DB.

4.5.4 Archive and Local Print Function

Besides the queuing of events in the specific protocol queues it is possible to store

important information for a longer period and to access this information at a later time on

demand.

The RTU560 supports this function with a local archive which is organized in the

Flash memory. For special purposes it is also possible to print these events on a local printer,

connected to the RTU560.

The following data types may be stored in the archive.

Process events with time stamp

Process commands

RTU560 system events and system messages

Login / logout to the Integrated HMI

Analog measured values

Integrated totals

4.5.5 Disturbance Data Archive

Protection relays and combined bay control and protection units (e.g. the ABB REF

54x, Rex5xx units) have the capability to store information about a trip in a file. These files

will be kept in the relay until a new file overwrites it or it is transmitted to an external unit.

The RTU560 supports the user with an automatic reading of the disturbance files out

of the relays, when the relay indicates a new disturbance file. The file is stored in the

RTU560 disturbance file archive. The reserved Flash memory can be configured and may be

in the range of up to 128 MB. The RTU560 handles a disturbance file directory to store the

files per protection relay. The total number of files per relay is fixed (typ. 8 files) and is given

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by the total number of relays in the station. A new file overwrites the oldest, when the

number of files exceeds the configured maximum number.

4.5.6 Integrated Human Machine Interface

The RTU560 function ’Integrated HMI’ is an easy possibility to realized specific

monitoring and control applications. For this function no additional SCADA product is

required.

4.5.7 Routing of SPA bus Protocol Telegrams

The RTU560 supports the transmission of SPA bus telegrams which are encapsulated

in transparent mode in the IEC 60870-5-101 or –104 protocol. A certain data type in the

private range of the protocol is defined therefore. In that case the interpretation and handling

of the SPA telegram is done by the subordinated SPA bus unit and the SPA bus master which

is e.g. a Micro SCADA Pro system of ABB. The RTU560 operates as a passive router.

4.6 Telecontrol Functions The communication units and the I/O boards share the processing of the telecontrol

functions. The I/O boards take over the essential tasks of scanning and output of process

signals, and the communication unit the communication with the NCCs as well as the

organization and management of the process image in the data base. All time critical

functions are concentrated on the I/O boards. The I/O boards transmit process value changes

or status changes as events. The I/O bus (IOC) of the communication unit detects and

transmits the events to the communication unit (CMU) of the communication unit. To control

the data flow, each I/O board has a FIFO buffer for the temporary storage of up to 50 events.

All events are time stamped.

The telecontrol functions are divided in:

i. Monitoring direction

Indication processing

Analog measured value processing

Digital measured value processing

Integrated total processing

ii. Command direction

Object command output

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Regulation command output

Setpoint message output

Monitoring Direction

4.6.1 Indication Processing

There are two types of indications:

i. Single point input (SPI)

ii. Double point input (DPI)

Figure 4.5 shows the signal definition for SPI and DPI. Double indications are

represented by two sequential bits. The normal state of a DPI is an antivalent bit combination

(10 or 01). The two intermediate positions 11 or 00 are handled different within the RTU560.

An intermediate state is given during the runtime of a unit from one position to the other (e.g.

an isolator switching from OFF to ON).

Figure 4.5 Indication type definitions

4.6.2 Analog Measured Value Processing

Each analog value is converted by the analog digital converter (ADC) into a signed

integer presentation.

4.6.3 Digital Measured Value Processing

There are two types of digital measured values (DMV):

50

i. Digital measured value (DMI)

ii. Step position value (STI)

The RTU560 can handle different bit patterns to read them and convert them into a

digital measured value:

8 bit digital measured value (DMI8)

16 bit digital measured value (DMI16)

8 bit step position value (STI)

The RTU can handle conversions for:

binary data (BIN)

binary coded decimals (BCD)

Gray code (GRAY)

4.6.4 Integrated Total Processing

There are two types of integrated total values (ITI) defined in the RTU560:

i. End of period reading counters (EPR) ii. Intermediate reading counters (IR)

4.6.5 Direct Interfacing to Current/Voltage Transmitters

The Current/Voltage-Transformer Interface 560CVT01 is used for monitoring input

signals from three independent phases with 3 or 4 wire connections. For each phase voltage,

current and power are measured directly, and a number of other parameters derived from

these in software. The results are transmitted to the RTU560.

Command Processing

The communication unit accepts and checks the received command telegrams from

the central system and releases them for execution if the check has been positive. Depending

on the command type the central control unit processes the commands like data base update

or checks and if the tests are positive, it prepares the command-specific output procedures.

Then the command is transmitted to the output board via the I/O bus.

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4.6.6 Object Commands

This command type is used for the switching commands, e.g. for circuit breakers or

isolators. Object commands are always configured as impulse double commands with two

independent output relays (ON / OFF).

4.6.7 Regulation Step Command Output

These commands ensure the continuous fine tolerance adjustment of plant equipment,

e.g. earth-fault neutralizers. Regulation commands are pulse double commands with two

separated output relays.

4.7 Communication The communication of the RTU560 may be divided into two parts

i. Internal communication with a neutral process data point presentation

ii. External communication to NCCs, IEDs, Sub-RTUs, etc.

4.6.1 Internal Communication

The internal communication has to handle

process data point information

organizational information

RTU560 system information

Information form external connected communication lines with their protocols will be

converted into an internal presentation by the HCI and SCI modules. The internal protocol is

based on the IEC60870-5-101 data presentation.

Once a process data point information from external protocol as well from the

RTU560 IO-boards coming via the RTU560 Peripheral bus is converted into the internal data

presentation, it is used by all other modules. Each HCI or SCI module converts only from

internal presentation to external presentation and vice versa.

4.6.2 External Communication

The external communication of RTU with IED’s, sub RTU’s, local control centre and

network control center (NCC) is discussed in chapter 5. Along with external communication,

protocols are also discussed in the same chapter.

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CHAPTER 5

SCADA Communication and Protocols

In this chapter, communication among different components of SCADA is discussed.

In the first portion, communication of IED is taken into account. Different communication

possibilities in IED and the protocols used to carry out communication are discussed.

In the second portion, external communication of RTU is overviewed.

Communication of RTU with IED’s, sub RTU’s, local control center and network control

center (NCC) is discussed. The basic communication scheme in SCADA can be best

understood with the help of following diagram.

Figure 5.1 Basic communication scheme in SCADA

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5.1 IED Station Communication Each IED is provided with a communication interface, enabling it to connect to one or

many substation level systems or equipment, either on the Substation Automation (SA) bus or

Substation Monitoring (SM) bus.

Following communication protocols are available:

IEC 61850-8-1 communication protocol

LON communication protocol

SPA or IEC 60870-5-103 communication protocol

DNP3.0 communication protocol

These protocols are discussed below:

5.1.1 IEC 61850-8-1 Communication Protocol

IEC 61850–8–1 allows two or more intelligent electronic devices (IEDs) from one or

several vendors to exchange information and to use it in the performance of their functions

and for correct co-operation.

GOOSE (Generic Object Oriented Substation Event), which is a part of IEC 61850–

8–1 standard, allows the IEDs to communicate state and control information amongst

themselves, using a publish-subscribe mechanism. That is, upon detecting an event, the

IED(s) use a multi-cast transmission to notify those devices that have registered to receive the

data. An IED can, by publishing a GOOSE message, report its status. It can also request a

control action to be directed at any device in the network.

5.1.2 LON Communication Protocol

An optical network can be used within the Substation Automation system. This

enables communication with the IED 670s through the LON bus from the operator’s

workplace, from the control center and also from other IEDs via bay-to-bay horizontal

communication.

The hardware needed for applying LON communication depends on the application,

but one very central unit needed is the LON Star Coupler and optical fibers connecting the

star coupler to the IEDs.

54

Figure 5.2 Example of LON communication structure

5.1.3 SPA Communication Protocol

The SPA communication is mainly used for the Station Monitoring System. It can

include different numerical relays/terminals/IEDs with remote communication possibilities.

Connection to a personal computer (PC) can be made directly (if the PC is located in the

substation) or by telephone modem through a telephone network via a LAN/WAN

connection.

Hardware required for a local monitoring system is:

Optical fibers for the SPA bus loop

Optical/electrical converter for the PC

PC

A remote monitoring system for communication over the public telephone network

also requires telephone modems and a remote PC. The software required for a local

monitoring system is PCM 600, and for a remote monitoring system it is PCM 600 in the

remote PC only.

55

Figure 5.3 SPA communication structure for a monitoring system

5.1.4 Single Command, 16 Signals (CD)

The IEDs may be provided with a function to receive commands either from a

substation automation system or from the local human-machine interface, HMI. That

receiving function block has outputs that can be used, for example, to control high voltage

apparatuses in switchyards. For local control functions, the local HMI can also be used.

Together with the configuration logic circuits, the user can govern pulses or steady output

signals for control purposes within the IED or via binary outputs.

5.1.5 Multiple Command (CM) and Multiple Transmit (MT)

The IED may be provided with a function to send and receive signals to and from

other IEDs via inter bay bus. The send and receive function blocks has 16 outputs/ inputs that

can be used, together with the configuration logic circuits, for control purposes within the

IED or via binary outputs. When it is used to communicate with other IEDs, these IEDs have

a corresponding Multiple transmit function block with 16 outputs to send the information

received by the command block.

5.2 IED Remote Communication

IED 670s can be equipped with communication devices for line differential

communication and/or communication of binary signals between IEDs. The same

communication hardware is used for both purposes.

Communication between two IEDs geographically on different locations is a

fundamental part of the line differential function. Sending of binary signals between two

IEDs, one in each end of a power line is used in teleprotection schemes and for direct transfer

56

trips. In addition to this, there are application possibilities like e.g. blocking/enabling

functionality in the remote substation, changing setting group in the remote IED depending

on the switching situation in the local substation etc.

5.3 RTU External Communication

5.3.1 Telecontrol Protocols

The telecontrol protocols can be defined into two groups.

i. Host Communication Interfaces (HCI)

The Protocols between a Network Control Center (NCC), Substation Control System

(SCS) (e.g. MicroSCADA Pro of ABB) and the RTU. In this case the NCC is master and the

RTU560 is Slave.

ii. Sub-device Communication Interfaces (SCI)

The Protocols between the RTU560 and a subordinated unit, like an IED in the

stations itself or another subordinated RTU unit (e.g. a station with an RTU560E). In this

case the RTU560 is master and the sub-device is slave.

5.3.2 Host Communication Interfaces

i. Command Direction

NCCs or SCS as host can send commands to the RTU560. The HCI checks the

command as much as possible and distributes it via the internal communication to all other

modules. The responsible module (e.g. the PDP) checks the command for formal correctness

and can acknowledge the command for the host. The acknowledgement is send to the host by

the HCI module.

A command addressed to a sub-device is routed by the SCI module to the addressed

sub-device, which has to acknowledge the command. This method secures, that the unit

responsible for the execution of the command confirms, that it is possible to do the command

task.

ii. General Interrogation

A general interrogation command from the host is answered by the HCI directly. This

is possible, because the HCI has the complete and valid process signal image in its process

57

DB. All SCI and PDP modules are responsible to force a complete process signal image after

start up or when a sub-device fails becomes online again. The HCI are informed about any

changes by internal communication. This method secures, that the process data bases in all

modules is kept actual.

5.3.3 Sub-Device Communication Interfaces

i. Command Direction

The SCI handles commands distributed via internal communication which are

addressed to a sub-device, connected to one of the communication lines managed by the SCI.

These commands can come from a host or from a PLC module.

ii. General Interrogation

The SCI will generate a General Interrogation Command for all connected devices

after startup, or if an IED becomes normal again. Via internal communication all other

modules can update their process data base. This ensures that all modules have the actual

complete process signal image.

5.3.4 Redundant Communication

The RTU560 has the possibility to handle some versions of redundant

communication.

Redundant line (for Host- and subordinated devices)

Multi host (in the sense of redundant communication)

Both for serial lines or Ethernet connections

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Chapter 6

Protection and control IED Manager PCM600

Protection and Control IED Manager PCM 600 is an easy-to-handle tool for con

figuration and communication engineering, parameter setting, and monitoring. It provides

versatile functionalities required throughout the life cycle of protection and control IEDs in

transmission and distribution applications. It features functionality for creating and editing

single line diagram for the IED HMI, and supports the efficient configuration of I/O signals.

6.1 Features Flexible tool architecture

Easy to adapt IEDs to power system requirements

Support of ANSI units and symbols

Scheduled polling of disturbance files

Automatic disturbance reporting

Graphical on-line monitoring of internal binary signals

Forcing of input and output signals

On-line monitoring of LED indications

Full control of all parameter setting updates

6.2 Engineering PCM 600 is compliant with IEC 61850, which simplifies IED engineering and

enables information exchange with other IEC 61850 compliant tools. PCM 600 enables us to

modify the attached template based on a default plant structure including all IEDs in a power

plant or substation. This structure reflects the substation topology.

PCM 600 can graphically adapt the configuration or create new configurations to

meet the specific needs. Furthermore, this tool secures the downloading of formally correct

59

configuration through extended syntax checking and guided error tracking. Signal status can

also be monitored online, which is extremely useful for troubleshooting.

Additionally, PCM 600 features a powerful IED import-export and copy-paste

functionalities which enables to efficiently reuse existing IEDs, bays or substations. All data

associated to the IEDs, bays or substation, such as settings, graphical configuration or

bay/substation topology, can be exported and used as IED template or copied to the new plant

structure.

6.3 Connection of signals After the IEDs have been configured and parameterized, configure, for instance the

bay-to-bay communication for station-wide interlocking and send the complete IED

description to a system engineering tool. In an IEC 61850 based system GOOSE (Generic

Object Oriented System-Wide Events) messaging is used for time critical messages.

The graphical signal matrix tool (SMT) of PCM 600 can efficiently connect CTs, VTs

and binary input and output signals without changing the configuration. This is especially

helpful during commissioning in case the connection from the process termination to the IED

terminal blocks needs to be changed. The SMT is also used for connecting the LEDs on the

IED as well as for connection of the GOOSE signals between the IEDs.

Furthermore, PCM 600 supports effective commissioning and testing of physical

connections by allowing user to activate both analog and binary signals from the signal

monitoring tool.

6.4 Parameter setting PCM 600 features advanced Filtering for handling parameter settings. A normal mode

allows the relay engineer to quickly view and change the most important parameters, whereas

an advanced mode presents all parameters. Parameter settings can be stored in the PCM 600

as primary quantities, which will simplify the setting calculations.

This tool provides full control over the updated parameters. Upload the current

settings from the IED to PCM 600 while the IED is in service. After changing the desired

parameters the Filtering functionality of PCM 600 compare them easily with the uploaded

settings. This way it can be ensured that the intended settings have been modified and that the

60

values are correct before the new IED settings are downloaded. This also reduces the time

needed for commissioning and maintenance. PCM 600 permits the restoring of verified

default settings to the IED anytime after the IED has been taken into operation.

6.5 Disturbance handling Disturbance handling is vital through the entire life cycle of a substation. PCM 600

takes the first step towards a new era in disturbance handling. It processes data. The signal

monitoring function gives online information about the measured quantities and status of

binary input and output signals for understanding the cause of the disturbance, for fast

corrective actions. The report layout and contents can be easily adapted to meet the needs of

different subscribers. This feature significantly reduces the time required for the handling of

disturbance reports and allows the subscriber to spend more time on complicated disturbances

demanding special attention.

The disturbance files are stored in IEDs in COMTRADE, the de-facto standard

format. Disturbances stored in the IED can be uploaded using a scheduler. After the upload,

PCM 600 automatically creates a disturbance report, which will be immediately sent to

subscribers by e-mail. Such a notification shortens the time from disturbance detection to

corrective actions.

6.6 Communication management Tool A new communication management tool has been implemented in PCM 600 Ver. 1.5

SP1. It can be used to configure 670 IEDs featuring support for the DNP 3.0 Level 2

protocol. By means of the communication management tool the user can configure the IED to

interface with one or several DNP 3.0 Level 2 masters. The communication management tool

allows the user to select the signals to be included in the DNP 3.0 Level 2 communication

and to modify signal related attributes.

6.7 How to Use the IED in Conjunction with PCM 600 Toolbox

Procedure

Select the IED configuration. The IED is available with four alternative

configurations as described above.

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Select and order the IED which best suits the application. There are a number of

templates including options for use. Check which one is the most suitable for required

application.

Adjust the configuration if required by adjusting the input and outputs with the Signal

Matrix Tool (SMT) in PCM 600.

Select the number of setting groups on the Activate setting group function block.

Save the IED, compile and download to the relay.

Set the IED with use of the PCM 600 Parameter Setting Tool PST.

Adjust the setting to the values suitable for application. General setting values have

only one set and are the basic parameters such as CT and VT ratios etc.

Download to the IED.

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Conclusion and Suggestions

In the present project, various aspects of power system protection are considered for

the implementation of SCADA. Main purpose of SCADA is monitoring and control and it is

possible with the help of understanding of power system protection because in modern

SCADA, implemented in power system, data is collected with the help of protective relays.

In the present project, numerical relays called IEDs are used for protection and collection of

data. This collected data from IEDs and the previous data or history becomes the basis for

decision of control and decides weather the specific station would remain in system or not.

Due to vastness of SCADA, only the implementation in power plant is taken into account,

however the communication of power plant with network control center, for example NPCC

in Pakistan, should also be considered and the control and monitoring from the remote

control center (NPCC) should also be taken into account. Due to lack of facilities and security

reasons, limited number of visits are made for the study of SCADA in power plants. Yet, the

project can be a very good starting point for understanding of SCADA and further

consideration of SCADA in power plants.

If further work is carried out on SCADA, a complete training session must be

arranged. So that the basic relay functions, their uses, their configuration and programming

along with their implementation can be better understood. In the same session testing of

relays should also be learned. Related software’s should also be learned for SCADA

implementation like MicroSCADA simulator and most importantly, software for relay

testing. “Freja” is the software for relay testing and is very important from power system

view point. So the future work can be carried on the commissioning of SCADA in power

plants.

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References

• Guide to Supervisory Control and Data Acquisitions (SCADA) and Industrial

Control System Security by Keith Stouffer, Joe Falco and Karen Kent.

• Practical SCADA for Industry by David Bailey, Edwin Wright

• Securing SCADA Systems by Ronald L. Krutz

• SCADA: Supervisory Control and Data Acquisition by Stuart A. Boyer

• SCADA System by Allen Bradley

• Practical Modern SCADA Protocols by Gordon Clarke and Deon Reynders

• A Guide to utility automation: SCADA systems for Electric power by Michael

Wiebe

• UCI’s specification of the SCADA and its Communication System, Utility Consulting

International, Cupertino, California, USA

• Sandia National Laboratories, Sandia Corporation

• AREVA’s Functional Specification Design Documents and user’s manuals. AREVA,

France

• http://www.efarabi.com

• http://www.tech-faq.com/SCADA.html

• http://en.wikipedia.org/wiki/SCADA

• http://www.ABB.com

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