Sensaphone SCADA 3000 -Analog Output Module - DescriptionThe SCADA 3000 Analog Output Module is an optional component for use with the Sensaphone SCADA 3000 system. The module features four analog output signals that can be configured as 4-20mA, 0-20mA, or 0-10V. The outputs can be used to control equipment, drive digital dis-plays, or provide information to other computer devices. The individual outputs are capable of driving up to 1000 Ohms. They may be controlled automatically via a ladder program or C-program. 

The module also features a microprocessor watchdog circuit to maintain system reliability. LED indicators are provided to show system power and module operation via a blinking pulse LED.

HOW THE ANALOG OUTPUT MODULE WORKS:The Analog Output Module has four independent outputs that can be used to control equipment, drive digital displays, or provide information to other computer devices. The only requirement is that the equipment be capable of accepting a 4-20mA, 0-20mA or 0-10V signal. 

The SCADA 3000 CPU sends information to the module telling it how much current or voltage to drive to each of the outputs. The output levels are determined based on the control program you create using the Ladder program, C-program or PID settings. The SCADA 3000 Software allows you to set up a custom table to scale the signal to units that describe your process. By setting low and high table values of 0 and 100 respectively, you can now control the position of the valve from 0 to 100% as opposed to 4-20mA. This can greatly simplify programming as well as viewing the position of the valve from the software.

Common system components

A SCADA system usually consists of the following subsystems:

A human–machine interface or HMI is the apparatus which presents process data to a human operator, and through

this, the human operator monitors and controls the process.

A supervisory (computer) system, gathering (acquiring) data on the process and sending commands (control) to the

process.

Remote terminal units  (RTUs) connecting to sensors in the process, converting sensor signals to digital data and

sending digital data to the supervisory system.

Programmable logic controller  (PLCs) used as field devices because they are more economical, versatile, flexible, and

configurable than special-purpose RTUs.

Communication infrastructure connecting the supervisory system to the remote terminal units.

Various process and analytical instrumentation

[edit]Supervision versus control

There is, in several industries, considerable confusion over the differences between SCADA systems and distributed control

systems (DCS). Generally speaking, a SCADA system always refers to a system that coordinates, but does

not control processes in real time. The discussion on real-time control is muddied somewhat by newer telecommunications

technology, enabling reliable, low latency, high speed communications over wide areas. Most differences between SCADA

and DCS are culturally determined and can usually be ignored. As communication infrastructures with higher capacity

become available, the difference between SCADA and DCS will fade.

Summary

DCS is process oriented, while SCADA is data acquisition oriented.

DCS is process driven, while SCADA is event driven.

DCS is commonly used to handle operations on a single locale, while SCADA is preferred for applications that are

spread over a wide geographic location.

[edit]Systems concepts

The term SCADA usually refers to centralized systems which monitor and control entire sites, or complexes of systems

spread out over large areas (anything from an industrial plant to a nation). Most control actions are performed automatically

by RTUs or by PLCs. Host control functions are usually restricted to basic overriding or supervisory level intervention. For

example, a PLC may control the flow of cooling water through part of an industrial process, but the SCADA system may

allow operators to change the set points for the flow, and enable alarm conditions, such as loss of flow and high

temperature, to be displayed and recorded. The feedback control loop passes through the RTU or PLC, while the SCADA

system monitors the overall performance of the loop.

Data acquisition begins at the RTU or PLC level and includes meter readings and equipment status reports that are

communicated to SCADA as required. Data is then compiled and formatted in such a way that a control room operator using

the HMI can make supervisory decisions to adjust or override normal RTU (PLC) controls. Data may also be fed to

a Historian, often built on a commodityDatabase Management System, to allow trending and other analytical auditing.

SCADA systems typically implement a distributed database, commonly referred to as a tag database, which contains data

elements called tags or points. A point represents a single input or output value monitored or controlled by the system.

Points can be either "hard" or "soft". A hard point represents an actual input or output within the system, while a soft point

results from logic and math operations applied to other points. (Most implementations conceptually remove the distinction by

making every property a "soft" point expression, which may, in the simplest case, equal a single hard point.) Points are

normally stored as value-timestamp pairs: a value, and the timestamp when it was recorded or calculated. A series of value-

timestamp pairs gives the history of that point. It's also common to store additional metadata with tags, such as the path to a

field device or PLC register, design time comments, and alarm information.

[edit]Human–machine interface

Typical basic SCADA animations [1]

A human–machine interface or HMI is the apparatus which presents process data to a human operator, and through which

the human operator controls the process.

An HMI is usually linked to the SCADA system's databases and software programs, to provide trending, diagnostic data, and

management information such as scheduled maintenance procedures, logistic information, detailed schematics for a

particular sensor or machine, and expert-system troubleshooting guides.

The HMI system usually presents the information to the operating personnel graphically, in the form of a mimic diagram.

This means that the operator can see a schematic representation of the plant being controlled. For example, a picture of a

pump connected to a pipe can show the operator that the pump is running and how much fluid it is pumping through the pipe

at the moment. The operator can then switch the pump off. The HMI software will show the flow rate of the fluid in the pipe

decrease in real time. Mimic diagrams may consist of line graphics and schematic symbols to represent process elements,

or may consist of digital photographs of the process equipment overlain with animated symbols.

The HMI package for the SCADA system typically includes a drawing program that the operators or system maintenance

personnel use to change the way these points are represented in the interface. These representations can be as simple as

an on-screen traffic light, which represents the state of an actual traffic light in the field, or as complex as a multi-projector

display representing the position of all of the elevators in a skyscraper or all of the trains on a railway.

An important part of most SCADA implementations is alarm handling. The system monitors whether certain alarm conditions

are satisfied, to determine when an alarm event has occurred. Once an alarm event has been detected, one or more actions

are taken (such as the activation of one or more alarm indicators, and perhaps the generation of email or text messages so

that management or remote SCADA operators are informed). In many cases, a SCADA operator may have to acknowledge

the alarm event; this may deactivate some alarm indicators, whereas other indicators remain active until the alarm

conditions are cleared. Alarm conditions can be explicit—for example, an alarm point is a digital status point that has either

the value NORMAL or ALARM that is calculated by a formula based on the values in other analogue and digital points—or

implicit: the SCADA system might automatically monitor whether the value in an analogue point lies outside high and low

limit values associated with that point. Examples of alarm indicators include a siren, a pop-up box on a screen, or a coloured

or flashing area on a screen (that might act in a similar way to the "fuel tank empty" light in a car); in each case, the role of

the alarm indicator is to draw the operator's attention to the part of the system 'in alarm' so that appropriate action can be

taken. In designing SCADA systems, care is needed in coping with a cascade of alarm events occurring in a short time,

otherwise the underlying cause (which might not be the earliest event detected) may get lost in the noise. Unfortunately,

when used as a noun, the word 'alarm' is used rather loosely in the industry; thus, depending on context it might mean an

alarm point, an alarm indicator, or an alarm event.

[edit]Hardware solutions

SCADA solutions often have distributed control system (DCS) components. Use of "smart" RTUs or PLCs, which are

capable of autonomously executing simple logic processes without involving the master computer, is increasing. A

standardized control programming language, IEC 61131-3 (a suite of 5 programming languages including Function Block,

Ladder, Structured Text, Sequence Function Charts and Instruction List), is frequently used to create programs which run on

these RTUs and PLCs. Unlike a procedural language such as the C programming language or FORTRAN, IEC 61131-3 has

minimal training requirements by virtue of resembling historic physical control arrays. This allows SCADA system engineers

to perform both the design and implementation of a program to be executed on an RTU or PLC. A programmable

automation controller (PAC) is a compact controller that combines the features and capabilities of a PC-based control

system with that of a typical PLC. PACs are deployed in SCADA systems to provide RTU and PLC functions. In many

electrical substation SCADA applications, "distributed RTUs" use information processors or station computers to

communicate with digital protective relays, PACs, and other devices for I/O, and communicate with the SCADA master in

lieu of a traditional RTU.

Since about 1998, virtually all major PLC manufacturers have offered integrated HMI/SCADA systems, many of them using

open and non-proprietary communications protocols. Numerous specialized third-party HMI/SCADA packages, offering built-

in compatibility with most major PLCs, have also entered the market, allowing mechanical engineers, electrical engineers

and technicians to configure HMIs themselves, without the need for a custom-made program written by a software

developer.

[edit]Remote terminal unit

The RTU connects to physical equipment. Typically, an RTU converts the electrical signals from the equipment to digital

values such as the open/closed status from a switch or a valve, or measurements such as pressure, flow, voltage or current.

By converting and sending these electrical signals out to equipment the RTU can control equipment, such as opening or

closing a switch or a valve, or setting the speed of a pump. It can also control the flow of a liquid.

[edit]Supervisory station

The term supervisory station refers to the servers and software responsible for communicating with the field equipment

(RTUs, PLCs, etc.), and then to the HMI software running on workstations in the control room, or elsewhere. In smaller

SCADA systems, the master station may be composed of a single PC. In larger SCADA systems, the master station may

include multiple servers, distributed software applications, and disaster recovery sites. To increase the integrity of the

system the multiple servers will often be configured in a dual-redundant or hot-standby formation providing continuous

control and monitoring in the event of a server failure.

[edit]Operational philosophy

For some installations, the costs that would result from the control system failing are extremely high. Possibly even lives

could be lost. Hardware for some SCADA systems is ruggedized to withstand temperature, vibration, and voltage extremes.

In the most critical installations, reliability is enhanced by having redundant hardware and communications channels, up to

the point of having multiple fully equipped control centres. A failing part can be quickly identified and its functionality

automatically taken over by backup hardware. A failed part can often be replaced without interrupting the process. The

reliability of such systems can be calculated statistically and is stated as the mean time to failure, which is a variant of mean

time between failures. The calculated mean time to failure of such high reliability systems can be on the order of centuries.

[edit]Communication infrastructure and methods

SCADA systems have traditionally used combinations of radio and direct wired connections, although SONET / SDH is also

frequently used for large systems such as railways and power stations. The remote management or monitoring function of a

SCADA system is often referred to as telemetry. Some users want SCADA data to travel over their pre-established

corporate networks or to share the network with other applications. The legacy of the early low-bandwidth protocols remains,

though.

SCADA protocols are designed to be very compact. Many are designed to send information only when the master station

polls the RTU. Typical legacy SCADA protocols include Modbus RTU, RP-570,Profibus and Conitel. These communication

protocols are all SCADA-vendor specific but are widely adopted and used. Standard protocols are IEC 60870-5-101 or

104, IEC 61850 and DNP3. These communication protocols are standardized and recognized by all major SCADA vendors.

Many of these protocols now contain extensions to operate over TCP/IP.

Although some believe it is good security engineering practice to avoid connecting SCADA systems to the Internet so

the attack surface is reduced, many industries, such as wastewater collection and water distribution, have used existing

cellular networks to monitor their infrastructure along with internet portals for end-user data delivery and modification.

Cellular network data is encrypted before transmission over the Internet.

With increasing security demands ( such as North American Electric Reliability Corporation (NERC) and critical

infrastructure protection (CIP) in the US), there is increasing use of satellite-based communication. This has the key

advantages that the infrastructure can be self contained (not using circuits from the public telephone system), can have built-

in encryption, and can be engineered to the availability and reliability required by the SCADA system operator. Earlier

experiences using consumer-grade VSAT were poor. Modern carrier-class systems provide the quality of service required

for SCADA.[2]

RTUs and other automatic controller devices were developed before the advent of industry wide standards for

interoperability. The result is that developers and their management created a multitude of control protocols. Among the

larger vendors, there was also the incentive to create their own protocol to "lock in" their customer base. A list of automation

protocols is being compiled here.

Recently, OLE for process control (OPC) has become a widely accepted solution for intercommunicating different hardware

and software, allowing communication even between devices originally not intended to be part of an industrial network.

[edit]SCADA architectures

The United States Army's Training Manual 5-601 covers "SCADA Systems for C4ISRFacilities".

SCADA systems have evolved through 3 generations as follows:[citation needed]

[edit]First generation: "Monolithic"

In the first generation, computing was done by mainframe computers. Networks did not exist at the time SCADA was

developed. Thus SCADA systems were independent systems with no connectivity to other systems. Wide Area

Networks were later designed by RTU vendors to communicate with the RTU. The communication protocols used were

often proprietary at that time. The first-generation SCADA system was redundant since a back-up mainframe system was

connected at the bus level and was used in the event of failure of the primary mainframe system.

[edit]Second generation: "Distributed"

The processing was distributed across multiple stations which were connected through a LAN and they shared information

in real time. Each station was responsible for a particular task thus making the size and cost of each station less than the

one used in First Generation. The network protocols used were still mostly proprietary, which led to significant security

problems for any SCADA system that received attention from a hacker. Since the protocols were proprietary, very few

people beyond the developers and hackers knew enough to determine how secure a SCADA installation was. Since both

parties had vested interests in keeping security issues quiet, the security of a SCADA installation was often badly

overestimated, if it was considered at all.

[edit]Third generation: "Networked"

Due to the usage of standard protocols and the fact that many networked SCADA systems are accessible from the Internet,

the systems are potentially vulnerable to remote cyber-attacks. On the other hand, the usage of standard protocols and

security techniques means that standard security improvements are applicable to the SCADA systems, assuming they

receive timely maintenance and updates.

[edit]Security issues

The move from proprietary technologies to more standardized and open solutions together with the increased number of

connections between SCADA systems and office networks and the Internet has made them more vulnerable to attacks—see

references. Consequently, the security of some SCADA-based systems has come into question as they are seen as

potentially vulnerable to cyber attacks.[3][4]

In particular, security researchers are concerned about:

the lack of concern about security and authentication in the design, deployment and operation of some existing SCADA

networks

the belief that SCADA systems have the benefit of security through obscurity through the use of specialized protocols

and proprietary interfaces

the belief that SCADA networks are secure because they are physically secured

the belief that SCADA networks are secure because they are disconnected from the Internet.

SCADA systems are used to control and monitor physical processes, examples of which are transmission of electricity,

transportation of gas and oil in pipelines, water distribution, traffic lights, and other systems used as the basis of modern

society. The security of these SCADA systems is important because compromise or destruction of these systems would

impact multiple areas of society far removed from the original compromise. For example, a blackout caused by a

compromised electrical SCADA system would cause financial losses to all the customers that received electricity from that

source. How security will affect legacy SCADA and new deployments remains to be seen.

There are two distinct threats to a modern SCADA system. First is the threat of unauthorized access to the control software,

whether it be human access or changes induced intentionally or accidentally by virus infections and other software threats

residing on the control host machine. Second is the threat of packet access to the network segments hosting SCADA

devices. In many cases, there is rudimentary or no security on the actual packet control protocol, so anyone who can send

packets to the SCADA device can control it. In many cases SCADA users assume that a VPN is sufficient protection and are

unaware that physical access to SCADA-related network jacks and switches provides the ability to totally bypass all security

on the control software and fully control those SCADA networks. These kinds of physical access attacks bypass firewall and

VPN security and are best addressed by endpoint-to-endpoint authentication and authorization such as are commonly

provided in the non-SCADA world by in-device SSL or other cryptographic techniques.

The reliable function of SCADA systems in our modern infrastructure may be crucial to public health and safety. As such,

attacks on these systems may directly or indirectly threaten public health and safety. Such an attack has already occurred,

carried out on Maroochy Shire Council's sewage control system in Queensland, Australia.[5] Shortly after a contractor

installed a SCADA system there in January 2000 system components began to function erratically. Pumps did not run when

needed and alarms were not reported. More critically, sewage flooded a nearby park and contaminated an open surface-

water drainage ditch and flowed 500 meters to a tidal canal. The SCADA system was directing sewage valves to open when

the design protocol should have kept them closed. Initially this was believed to be a system bug. Monitoring of the system

logs revealed the malfunctions were the result of cyber attacks. Investigators reported 46 separate instances of malicious

outside interference before the culprit was identified. The attacks were made by a disgruntled employee of the company that

had installed the SCADA system. The employee was hoping to be hired full time to help solve the problem.

Many vendors of SCADA and control products have begun to address the risks posed by unauthorized access by

developing lines of specialized industrial firewall and VPN solutions for TCP/IP-based SCADA networks as well as external

SCADA monitoring and recording equipment.[6] Additionally, application whitelisting solutions are being implemented

because of their ability to prevent malware and unauthorized application changes without the performance impacts of

traditional antivirus scans.[citation needed] Also, the ISA Security Compliance Institute (ISCI) is emerging to formalize SCADA

security testing starting as soon as 2009. ISCI is conceptually similar to private testing and certification that has been

performed by vendors since 2007. Eventually, standards being defined by ISA99 WG4 will supersede the initial industry

consortia efforts, but probably not before 2011.[citation needed]

The increased interest in SCADA vulnerabilities has resulted in vulnerability researchers discovering vulnerabilities in

commercial SCADA software and more general offensive SCADA techniques presented to the general security community.[7]

[8] In electric and gas utility SCADA systems, the vulnerability of the large installed base of wired and wireless serial

communications links is addressed in some cases by applying bump-in-the-wire devices that employ authentication

and Advanced Encryption Standard encryption rather than replacing all existing nodes.[9]

In June 2010, VirusBlokAda reported the first detection of malware that attacks SCADA systems (Siemens' WinCC/PCS7

systems) running on Windows operating systems. The malware is calledStuxnet and uses four zero-day attacks to install a

rootkit which in turn logs in to the SCADA's database and steals design and control files.[10][11] The malware is also capable of

changing the control system and hiding those changes. The malware was found by an anti-virus security company on 14

systems, the majority of which were located in Iran.[12]

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SCADA

scada system po

IN

POWER DISTRIBUTIONSYSTEMS

 

ABSTRACT:

The efficient and authentic power supply to the consumer is the primary function of anydistribution system. So, in distribution systems certain measures are taken for supervision,control, operation, measurement and protection. These are highly onerous works that take lot of manpower. So, the need of advanced automatic control systems to reach the required destinationi s   b e c o m i n g   m a n d a t o r y ,   t o   s u p e r s e d e   a n t i q u a t e d   w a y s   t h a t   a r e  p e r s i s t i n g   i n   t h e   p r e s e n t distribution system.In th i s paper we emphas ize ma in l y on the SCADA (Superv i so ry Con t ro l And Da ta Acquisition) systems, the most sophisticated automatic control system, being used in distributionau tomat ion   fo r  qua l i t y  power .  Th i s  paper   commences  w i t h  bas i c  i n t roduc t i on  o f   “wha t   i sSCADA?” Then continues by describing about the hardware components and basic architectureo f  SCADA sys tem used   in  d i s t r i bu t i on  au tomat ion .  C lea r l y  e luc ida tes  abou t   t he   so f twa recomponents that are installed in a SCADA system which can be used for distribution power systems and for quality power 

 

This paper then takes upon applications of SCADA, the exalted aspect, in distributions y s t e m s .   T h e   a p p l i c a t i o n s   i n c l u d e   c o n t r o l ,   o p e r a t i o n ,  s u p e r v i s i o n ,   m e a s u r e m e n t   a n d instrumentation, service of SCADA in distribution systems. This is the latest trend in power system protection and control.

1. INTRODUCTION:

The Indian electric power supply system is the most complex power grid system. So,efficient and reliable power supply is the major concern of our supply system. The losses thatoccur in the transmission and distribution are very large in comparison with major developedcountries. This occurs because of inefficient safety, monitoring and control devices that are persisting in present distribution system. The most advanced automatic control system, whichcan perform the operations like monitoring and control is SCADA. SCADA is the application of computer in power systems. Distribution automation is the major up gradation of any distributionsystem. This can be achieved by implementing SCADA in distribution systems.SCADA is an acronym for Supervisory Control and Data Acquisition. SCADA systemsare used to monitor and control a plant or equipment in industries such as telecommunications,wa te r  and  was te   con t ro l ,   ene rgy ,  o i l   and  gas   re f i n ing  and  t ranspor ta t i on .  These  sys temsencompass the t rans fe r o f da ta be tween a SCADA cen t ra l hos t compu te r and a number o f  Remote Terminal Units (RTUs) and/or Programmable

Logic Controllers (PLCs), and the centralhos t  and   the opera to r   t e rm ina ls .  These  sys tems  can  be   re la t i ve l y   s imp le ,   such  as  one  tha tmonitors environmental conditions of a small office building, or very complex, such as a systemthat monitors all the activity in a nuclear power plant or the activity of a municipal water system.Trad i t i ona l l y ,  SCADA sys tems  have  made  use  o f   t he  Pub l i c  Sw i t ched  Ne twork   (PSN) fo r  mon i to r i ng  pu rposes .  Today  many  sys tems  a re  mon i to red  us ing   the  i n f ras t ruc tu re  o f   t hecorporate Local Area Network (LAN)/Wide Area Network (WAN). Wireless technologies arenow being widely deployed for purposes of monitoring.A SCADA system can be implemented with the hardware and software components thatconstitute a whole SCADA system. Using SCADA system the various application programs thatcan be implemented in power supply systems are fault location, load balancing, load shedding2

 

etc. Now a detailed description of hard ware components, software components and application programs is given.

2. HARDWARE COMPONENTS:

T h e   c o m p o n e n t s   o f   a   S C A D A   s y s t e m   a r e   f i e l d   i n s t r u m e n t a t i o n ,   r e m o t e  s t a t i o n s , Communication Network (CN) and Central Monitoring Station (CMS).

2.1 Field instrumentation:

Field instrumentation generally comprises sensors, transmitters and actuators that aredirectly interfaced to the plant or equipment and generate the analog and digital signals that will be monitor by the remote station. Signals are also conditioned to make sure they are compatiblewith the inputs/outputs of the Remote Terminal Unit (RTU) or a Programmable Logic Controller (PLC) at the remote Station. It also refers to the devices that are connected to the equipment or m a c h i n e s   b e i n g   c o n t r o l l e d   a n d   m o n i t o r e d   b y   t h e   S C A D A   s y s t e m .   T h e s e  a r e   s e n s o r s   f o r   monitoring certain parameters and actuators for controlling certain modules of the system.

2.2 Remote stations:

The remote station is installed at the remote plantwith equipment being monitored and controlled by thecentral host computer. This can be a RTU or PLC. Fieldins t rumen ta t i on ,   connec ted   to   the  p lan t  o r  equ ipmen t   b e i n g   m o n i t o r e d   a n d  c o n t r o l l e d ,   i s   i n t e r f a c e d   t o   t h e remote station to allow process manipulation at a remotesite. It is also used to gather data from the equipment andtransfer it to the central SCADA system.

 Fig 1: RTU on the pole top

2.3 Communication Network:

The Communication Network (CN) refers to thecommunication equipment needed to transfer data to andf rom d i f f e ren t   s i t es .  The  med ium used  can  be  cab le , t e l e p h o n e ,   r a d i o ,   a n d   f i b e r   o p t i c   o r  s a t e l l i t e communication system. 

2.4 Central Monitoring Station: The  Cen t ra l  Mon i to r i ng  S ta t i on   (CMS)   i s   t he

  F i g   2 :   R T U   i n   a   s u b   s t a t i o nmaster unit of the SCADA system. Its function is collecting information gathered by the remotestations and generating necessary action for any event that is detected. The CMS can have asingle computer configuration or it can be networked to workstations to facilitate sharing of i n fo rmat ion f rom the SCADA sys tem. I t uses a Man Mach ine In te r face (MMI ) to mon i to r   various types of data needed for the operation. A MMI program runs on the CMS computer. Amimic diagram of the whole plant or process can be displayed onscreen for easier identificationwith the real system. Each I/O point of the remote units can be displayed with correspondinggraphical representation and the present I/O reading. Set-up parameters such as trip values,limits, etc. are entered on this program and downloaded to the corresponding remote units for updating of their operating parameters..Fig 3: A typical SCADA system architecture There are two typical network configurations for the SCADA systems. They are the  point-to-point and the point-to-multipoint configurations. The point-to-point configuration is thesimplest set-up for a telemetry system. Here data is exchanged between two stations. One stationcan be set up as the master and the other as the slave. The point-to-multipoint configuration iswhere one device is designated as the master unit to several slave units. The master is usually themain host and is located in the control room, while the slaves are the remote units. Each slave isassigned a unique address or identification number.3. SOFTWARE COMPONENTS:3.1 Data Acquisition and Processing:4

3There are two typical network configurations for the SCADA systems. They are the  point-to-point and the point-to-multipoint configurations. The point-to-point configuration is thesimplest set-up for a telemetry system. Here data is exchanged between two stations. One stationcan be set up as the master and the other as the slave. The point-to-multipoint configuration iswhere one device is designated as the master unit to several slave units. The master is usually themain host and is located in the control room, while the slaves are the remote units. Each slave isassigned a unique address or identification number.

. SOFTWARE COMPONENTS:3.1 Data Acquisition and Processing:

 This serves as a data collector from the devices to our SCADA system is connected and presents it as a processed data to user. Data acquisition can be done in multiple scan rates anduses different protocols. The data can be fetched as a whole or as a group and also report byexception. Data processing means conversion of fetched data into engineering conversions, zerosuppression, reasonability check, and calculation subsystem. So, user can use this processed datafor future purpose

3.2 Control:Users are allocated to groups, which have defined read/write access privileges to the process parameters in the system and often also to specific product functionality. The allocatedusers can have the access to the devices, which are to be controlled. Control can be either singleor group, open or closed loop control. The execution of control can be executed at selective  places, can be immediately executed, can be executed at required time etc.3.3 Man machine interface:The  p roduc ts   suppor t  mu l t i p le   sc reens ,  wh ich  can  con ta in   comb ina t i ons  o f  synop t i cdiagrams and text. They also support the concept of a "generic" graphical object with links to process variables. These objects can be "dragged and dropped" from a library and included into asynoptic diagram.Most of the SCADA products that were evaluated decompose the process in "atomic" parameters (e.g. a power supply current, its maximum value, its on/off status, etc.) to which aTag-name is associated. The Tag-names used to link graphical objects to devices can be edited asrequired. The products include a library of standard graphical symbols, many of which wouldhowever not be applicable to the type of applications encountered in the experimental physicscommunity.Standard windows editing facilities are provided: zooming, re-sizing, scrolling etc. On-l i ne con f igu ra t i on and cus tomiza t i on o f t he MMI i s poss ib le fo r use rs w i th the approp r ia te  privileges. Links can be created between display pages to navigate from one view to another.

3.4 Alarm handling:Alarm handling is based on limit and status checking and performed in the data servers.More complicated expressions (using arithmetic or logical expressions) can be developed bycreating derived parameters on which status or limit checking is done by the data server. Thealarms are logically handled centrally, i.e., the information only exists in one place and all userssee the same status (e.g., the acknowledgement), and multiple alarm priority levels (in generalmany more than 3 such levels) are supportedMost of the SCADA products that were evaluated decompose the process in "atomic" parameters (e.g. a power supply current, its maximum value, its on/off status, etc.) to which aTag-name is associated. The Tag-names used to link graphical objects to devices can be edited asrequired. The products include a library of standard graphical symbols, many of which wouldhowever not be applicable to the type of applications encountered in the experimental physicscommunity

3.5 Logging and Archiving:The terms logging and archiving are often used to describe the same facility. However,logging can be thought of as medium-term storage of data on disk, whereas archiving is long-term storage of data either on disk or on another permanent storage medium. Logging is typically performed on a cyclic basis, i.e., once a certain file size, time period or number of points isreached the data is overwritten. Logging of data can be performed at a set frequency, or onlyinitiated if the value changes or when a specific predefined event occurs. Logged data can betransferred to an archive once the log is full. The logged data is time-stamped and

can be filteredwhen viewed by a user. The logging of user actions is in general performed together with either auser ID or station ID. There is often also a VCR facility to play back archived data. 3.6 Automated mapping and facilities management (AM/FMoSCADA systems can be made use to have GUI system. GUI system can be used to havemaps, graphical representation of the required area, and graphical representation of required data.Using SCADA these maps can be layered, zoomed, scrolled and planned. The historical data of the machine can als be used

4. APPLICATION PROGRAMS:

The various application programs that can be implemented using SCADA systems arec l e a r l y   e x p l a i n e d   h e r e .   T h e   f o l l o w i n g   a r e   t h e   a p p l i c a t i o n s   t h a t   c a n   b e  u s e d   f o r   r e m o t e monitoring, control, safety, efficient utilization of resources etc.4.1 Fault location, isolation and Service Restoration:This function determines alternate paths for restoring service to the affected load pointsdue to a fault on a section of the feeder considering current loading conditions. Most of the ruralfeeders do not have an alternate supply for service restoration. In urban areas, many alternate  paths are available to a feeder; therefore, this function will be more effective. To implement thisfunc t i on ,   l oad  sw i t ches  o r   sec t i ona l i ze rs  a re  needed  a t   se lec ted   feeder  l oca t i ons .  Ear l i e r , sectionalizers were air-break switches without any remote-control features. All such switchesshould be replaced with remotely controllable switches.4.2 Maintaining good voltage profileTh is func t i on con t ro l s the capac i to r banks and vo l tage regu la to rs to p rov ide a goodvo l tage  p ro f i l e   i n   the  d i s t r i bu t i on   feeders .  An  approp r ia te   schedu le   fo r  sw i t ch ing  on /o f f   o f   capacitor banks and raise/lower voltage regulator taps was based on the feeders' reactive loadcurves in order to get good voltage profiles and reduce energy losses.

4.3 Load Balancing:This function distributes the system total load among the available transformers and thefeeders in proportion to their capacities. As explained above, there was a need to replace theexisting switches with remotely controllable switches in order to reconfigure the network for  load balancing.4.4 Load Control:

Load Management Function is divided into three categories:(a) During summer

there is usually a generation shortage. Therefore, loads need to be shed for  long durations. A restriction and control schedule is worked out based on which of the loads atdifferent substations are shed on a rotation basis. This function will automatically shed the loadsaccording to the schedule. Provisions to change the schedule are also provided.(b) Emergency Based Load Shedding: During emergencies, the utility needs to shed some load tokeep  up   the  ba lance  be tween  genera t i on  and  demand .   Ins t ruc t i ons  a re   sen t  t o   respec t i vesubstations to shed load. Based on the amount of relief requested, the operator would select someloads and shed them. Th is func t i on w i l l he lp to i den t i f y l oads to be shed cons ide r ing the i r    priority, time when they were last shed and the duration of the last interruption to ensure thatonly the required amount of load shedding is done.(c) Agricultural Pump Control -Agricultural loads are categorized into groups. This functioncontrols the agricultural loads automatically, based on predefined schedule. Provision to changeschedules is also provided.(d )  F requency -Based  Au tomat i c  Load  Shedd ing : - In   th i s   imp lemen ta t i on ,  f requency -based automatic load shedding is carried out by software using this function. Appropriate loads areshed by the RTU, based on priorities and actual amount of load whenever the system frequencycrosses the pre-set values. This is done as a closed loop function in the RTU. To sense systemfrequency, high-response-time (about 200 msec) frequency transducers are required. Presently ithas been difficult to find such high-response-time frequency transducers.

4.5 Remote metering:T h e   f u n c t i o n   o f   r e m o t e   m e t e r i n g   i s   t o   r e a d   d a t a   f r o m   t h e   m e t e r s   a n d   t o  p r o v i d e information to the operator of the consumption patterns of the high-value HV customers. Itsmain feature is to provide a multiple tariff to the customers to encourage them to shift their loadsfrom peak times to off-peak times. This function also provides meter-tampering detection4.6Maintaining Maps:T h e   f u n c t i o n   o f   A M / F M   i s   t o h a v e   a n   i n t e g r a t e d   d i s p l a y   o f  t h e g e o g r a p h i c a l   m a p s   a n d   s i n g l e - l i n e schematics of the electrical distributionnetwork to facilitate: - Display dynamic8

 information of various devices - Import scanned maps in standard formats - Provide functionslike map information layering, zooming, scrolling and panning - Extract historical data of thedevices from the database Fig 4. Typical example of a geographical map4.7 Fuse-off-call operations:This consumer-aid application function responds to complaints from consumers. It hasthe following features: Accepts interruption/restoration data from the operator. Accepts DTtrip/close information from SCADA. Identifies the interruption source whenever possible andg ives i n fo rmat ion on   the ou tage  e f fec ts   to the  opera to r .  D isp lays s ta tus o f   energ i zed /de - energized status of the consumer. This function will improve the response time to the consumer complaints.4.8 Energy accounting:This function helps in arriving at the system's load patterns, which helps in planningexpansion. It also helps in detecting abnormal energy consumption patterns of the consumers andidentifying high-loss areas. Processing the data obtained by the remote metering function and thedata obtained from the substation does this.5. CONCLUSION:Because of the explained application programs and advantages SCADA systems can beused for efficient, reliable, safe power supply systems.  SCADA systems are most advancingcomputer application, so even once the SCADA system is installed its up gradation can be easilydone. So SCADA system is to be implemented in all the power industries.References:(1) NDR Sarma, “ Rapid Growth Leads to System Automation Efforts”,Transmission and Distribution World, Sept, 1997.(2) David L. Brown, James W. Skeen, Parkash Daryani, Farrokh A Rahimi,“Prospects For Distribution Automation at Pacific Gas & Electric Company”,IEEE Transactions on Power Delivery, Vol. 6, No. 4, October 1991, pp 1946-1954.9

 

SCADA In POWER DISTRIBUTION SYSTEMS

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SCADA In POWER DISTRIBUTION SYSTEMS SEMINAR 

ABSTRACT:

The efficient and authentic power supply to the consumer is the primary function of any distribution system. So, in distribution systems certain measures are taken for supervision, control, operation, measurement and protection. These are highly onerous works that take lot of manpower. So, the need of advanced automatic control systems to reach the required destination is becoming mandatory, to supersede antiquated ways that are persisting in the present distribution system.In this paper we emphasize mainly on the SCADA (Supervisory Control And Data Acquisition) systems, the most sophisticated automatic control system, being used in distribution automation for quality power. This paper commences with basic introduction of “what is SCADA?” Then continues by describing about the hardware components and basic architecture of SCADA system used in distribution automation. Clearly elucidates about the software components that are installed in a SCADA system which can be used for distribution power systems and for quality power This paper then takes upon applications of SCADA, the exalted aspect, in distribution systems. The applications include control, operation, supervision, measurement and instrumentation, service of SCADA in distribution systems. This is the latest trend in power system protection and control.

1. INTRODUCTION:

The Indian electric power supply system is the most complex power grid system. So, efficient and reliable power supply is the major concern of our supply system. The losses that occur in the transmission and distribution are very large in comparison with major developed countries. This occurs because of inefficient

safety, monitoring and control devices that are persisting in present distribution system. The most advanced automatic control system, which can perform the operations like monitoring and control is SCADA. SCADA is the application of computer in power systems. Distribution automation is the major up gradation of any distribution system. This can be achieved by implementing SCADA in distribution systems.SCADA is an acronym for Supervisory Control and Data Acquisition. SCADA systems are used to monitor and control a plant or equipment in industries such as telecommunications, water and waste control, energy, oil and gas refining and transportation. These systems encompass the transfer of data between a SCADA central host computer and a number of Remote Terminal Units (RTUs) and/or Programmable Logic Controllers (PLCs), and the central host and the operator terminals. These systems can be relatively simple, such as one that monitors environmental conditions of a small office building, or very complex, such as a system that monitors all the activity in a nuclear power plant or the activity of a municipal water system. Traditionally, SCADA systems have made use of the Public Switched Network (PSN) for monitoring purposes. Today many systems are monitored using the infrastructure of the corporate Local Area Network (LAN)/Wide Area Network (WAN). Wireless technologies are now being widely deployed for purposes of monitoring.A SCADA system can be implemented with the hardware and software components that constitute a whole SCADA system. Using SCADA system the various application programs that can be implemented in power supply systems are fault location, load balancing, load shedding etc. Now a detailed description of hard ware components, software components and application programs is given.

2. HARDWARE COMPONENTS:

The components of a SCADA system are field instrumentation, remote stations, Communication Network (CN) and Central Monitoring Station (CMS).2.1 Field instrumentation:Field instrumentation generally comprises sensors, transmitters and actuators that are directly interfaced to the plant or equipment and generate the analog and digital signals that will be monitor by the remote station. Signals are also conditioned to make sure they are compatible with the inputs/outputs of the Remote Terminal Unit (RTU) or a Programmable Logic Controller (PLC) at the remote Station. It also refers to the devices that are connected to the equipment or machines being controlled and monitored by the SCADA system. These are sensors for monitoring certain parameters and actuators for controlling certain modules of the system.2.2 Remote stations:The remote station is installed at the remote plant with equipment being monitored and controlled by the central host computer. This can be a RTU or PLC. Field instrumentation, connected to the plant or equipment being monitored and controlled, is interfaced to the remote station to allow process manipulation at a remote site. It is also used to gather data from the equipment and transfer it to the central SCADA system. Fig 1: RTU on the pole top2.3 Communication Network:The Communication Network (CN) refers to the communication equipment needed to transfer data to and from different sites. The medium used can be cable, telephone, radio, and fiber optic or satellite communication system.2.4 Central Monitoring Station:The Central Monitoring Station (CMS) is the Fig 2: RTU in a sub station master unit of the SCADA system. Its function is collecting information gathered by the remote stations and generating necessary action for any event that is detected. The CMS can have a single computer configuration or it can be networked to workstations to facilitate sharing of information from the SCADA system. It uses a Man Machine Interface (MMI) to monitor various types of data needed for the operation. A MMI program runs on the CMS computer. A mimic diagram of the whole plant or process can be displayed onscreen for easier identification with the real system. Each I/O point of the remote units can be displayed with corresponding graphical representation and the present I/O reading. Set-up parameters such as trip values, limits, etc. are entered on this program and downloaded to the corresponding remote units for updating of their operating parameters.

There are two typical network configurations for the SCADA systems. They are the point-to-point and the point-to-multipoint configurations. The point-to-point configuration is the simplest set-up for a telemetry system. Here data is exchanged between two stations. One station can be set up as the master and the

other as the slave. The point-to-multipoint configuration is where one device is designated as the master unit to several slave units. The master is usually the main host and is located in the control room, while the slaves are the remote units. Each slave is assigned a unique address or identification number.

3. SOFTWARE COMPONENTS:

3.1 Data Acquisition and Processing:This serves as a data collector from the devices to our SCADA system is connected and presents it as a processed data to user. Data acquisition can be done in multiple scan rates and uses different protocols. The data can be fetched as a whole or as a group and also report by exception. Data processing means conversion of fetched data into engineering conversions, zero suppression, reasonability check, and calculation subsystem. So, user can use this processed data for future purposes.