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Session One: SCADA and Substation Control Communication

Session One:SCADA and Substation Control Communication

By Andrew West

SCADA Communications Architect, Foxboro, Australia

Chair, DNP Users Group Technical Committee

Spokesperson, IEC TC57 WG03 (IEC 60870-5)

Introduction

Data telemetry and telecontrol systems cover a wide spectrum of industries and needs.

Some systems are relatively simple with modest needs while some are more complex,

with stringent requirements for data integrity and command validation.

This paper looks at the use of the current standard SCADA communication protocols and

their properties. Particular focus is given to the existing protocol standards prevalent in

electric power SCADA and the related field of substation automation.

The recently published IEC 61850 standard for communication for substation automation

introduces a new paradigm for interconnecting substation devices and for defining and

configuring their information sharing. This paper discusses and compares the capabilities

provided by the existing standards and IEC 61850. It investigates the benefits and pitfalls

of the new standard and will assist the reader to determine where it may be applicable or

appropriate.

What makes SCADA different from other control systems?

A primary differentiator between a SCADA (Supervisory Control And Data Acquisition)

system and other types of control systems such as DCS (Distributed Control System) is

the purpose to which the control system will be put:

In general DCS is focussed on the automatic control of a process, usually within a

confined area. The DCS is directly connected to the equipment that it controls and is

usually designed on the assumption that instantaneous communication with the

equipment is always possible.

A SCADA system is usually supplied to permit the monitoring and control of a

geographically dispersed system or process. It relies on communication systems that

may transfer data periodically and may also be intermittent. Many SCADA systems

for high-integrity applications include capabilities for validating data transmissions,

verifying and authenticating controls and identifying suspect data.

DCS often operates with a state paradigm: the system relies on the ability to obtain an

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immediate view of the current state of the system at any time. SCADA systems in many

industries (especially electric power) rely on an event reporting paradigm where even

transitory or fleeting changes in the state of the plant are reported.

In view of this, different messaging protocols and formats are used in different industries

and applications. In the DCS arena, the Bus protocols (Modbus, FieldBus, ProfiBus,

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Session One: SCADA and Substation Control Communication

etc.) and a slew of proprietary protocols are prevalent. These are suitable for the

requirements of DCS Input/Output (I/O). In the SCADA arena, the most commonly used

protocols are DNP3, IEC 60870-5-101, Modbus variants and proprietary protocols. Some

specific applications such as gas metering also have specific protocols designed to meet

their needs.

Telecontrol and telemetry are areas where installation-specific system design is required:

There is no single solution that is right for every situation.

SCADA: More than meets the eye

Many different industries rely on SCADA system functions. Each different industry and

individual systems within an industry will have different requirements. Meeting these

requirements dictates the functions and technologies that are implemented in successful

control systems. Some industries that use SCADA functionality include:

Electricity Transmission & Distribution

Oil & Gas Pipelines and Gas Distribution

Water & Wastewater

Railways & Road Transportation

Fire Protection & Security

Telecommunication

Factory Automation (PLC-type systems)

High-integrity SCADA system applications include electric power transmission &

distribution and pipeline monitoring & control systems. Electricity SCADA often

requires very short data latency (time delay for reporting new data) and accurate, high-

resolution time tagging of reported data.

When reviewing system implementations that meet the various requirements of different

industries, some patterns of common groupings emerge.

In general, systems that have requirements for large point counts, high data

communication and control integrity and high availability tend to use traditional

mainframe, super-mini or workstation computing platforms with operating systems such

as VMX, UNIX or LINUX. They tend to use synchronous or isochronous communication

systems (that readily allow the identification of message corruption); support the

reporting of transitory events and communicate with Remote Terminal Units (parallel-

executing multitasking field equipment).

Systems that meet less strenuous requirements tend to be based on COTS Windows

platforms, communicate over asynchronous links and use PLCs (typically single-threaded

looping execution) field equipment.

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Session One: SCADA and Substation Control Communication

This general separation of architectures for meeting different system requirements allows

for the differentiation of systems into High-End and Low-End SCADA systems. This

typical grouping is illustrated below in Table 1.

High-End SCADA Systems

Operator Interface

Workstation or Mainframe

Unix, VMS, etc.

Remote Devices

RTU

Synchronous Communications

Sequence of Event Processing

Requirements

Large Point Count (10,000s)

Short Data LatencyExtremely High Availability

Two-Pass Control Strategy

Significant Levels of Redundancy

Extensive Applications Capability

Many tags per point

Low-End SCADA Systems

PC

DOS, Windows

PLC

Asynchronous Communications

State Processing

Moderate Point Count (1,000s)

Longer Data LatencyHigh Availability

Single-Pass Control Strategy

Little or No Redundancy

Few or No Applications

Few tags per point

Table 1 System Capability Grouping

The electric power heritage

The standardization process in SCADA communication protocols has been primarily

driven by the special requirements of electric power SCADA. This process began withthe International Electrotechnical Commission in the 1980s. IEC Technical Committee 57

(Power System Control and Associated Communications) set up a Working Group

(WG03: Telecontrol Protocols) to look at the standardization of communication between

substations and control centres. This committee produced a standard, IEC 60870, in many

parts, to address requirements and definitions for SCADA communications for electric

power control. The first part of the standard was published in 1988 and work on the series

is still continuing. The various parts cover:

Basic concepts

Environmental characteristics

General principles of data integrity

A three-layer stack architecture

Data link services

Application functions

Data formats

Application objects

Testing

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Session One: SCADA and Substation Control Communication

The IEC 60870-5-1 through 60870-5-5 series of standards present a general recipe

book for defining communication protocols. IEC 60870-5-101 is a companion

standard that presents a worked example profile for an Electric Power SCADA

protocol based on the earlier parts of the series. It was first published as in 1995 and

updated to the second edition in February 2003. The new edition is almost twice the size

of the first edition and the extra content is mainly explanatory material that clarifies the

standard. In 2000, IEC 60870-5-104 was published. This standard describes the transport

of IEC 60870-5-101 application data over network transports such as TCP/IP. Specific

application standards for electrical metering (60870-5-102) and substation protection

devices (60870-5-103) have also been produced. The IEC 60870-5-101 and -104

standards are now widely adopted in Europe and some other regions (notably the Middle

East and Latin America) for electric power SCADA.

While the IEC was progressing with the development of the 60870 series, vendors,

particularly those in North America, were well aware of the power industrys requirement

for standardized SCADA communication. Many utilities were aware of the IECs work

and were requesting IEC compliant SCADA protocols. Several vendors responded tothis challenge by taking the early parts of IEC 60870-5 and providing these as an

underpinning to their proprietary protocols. DNP3 (then called DNP V3.00) was one such

offering developed by Westronic Inc., an RTU manufacturer based in Calgary, Canada.

One significant distinction between DNP3 and its IEC-compliant contemporaries was that

Westronic chose to place the protocol specification in the public domain under the control

of a users group in 1993. The DNP Users Group appointed a Technical Committee in

1995 to assume technical responsibility for the extension and enhancement of the

protocol. This strategy gained significant market acceptance in North America. A

specification for using DNP3 over LANs and WANs was published in 1998. Since the

beginning of the current millennium, virtually every substation automation device sold in

North America supports DNP3. DNP3 is also well supported in the electric powerindustry in Australia. DNP3 shares the electric power SCADA market with

IEC 60870-5-101/-104 in Asia, Africa and South America.

While IEC 60870-5-101 is specifically an electric power-oriented protocol (with specific

objects for things such as Transformer Tap Positions), DNP3 is a more generic SCADA

protocol. As such it has found acceptance in a wider set of industries, including oil & gas

pipeline control systems and water & wastewater systems. While IEC 60870-5-101 is

used in the UK for electrical transmission SCADA, in an unusual departure from the

European norm, DNP3 is often used there for distribution SCADA because of its

capability to make efficient use of multi-drop radio communication networks.

All the other SCADA protocols are now relegated to also ran status in the electric

power SCADA protocol race. The September 2002 Newton-Evans report on the electric

power market reported that DNP3 was the most used protocol within substations in North

America (52% of utilities), followed by Modbus Plus (31%). Between the substation and

the control centre, DNP3 serial is in use at 32% of utilities; DNP3 over LAN/WAN

(TCP/IP or UDP/IP) is in use at 19%. The next highest groupings are other TCP/IP at

9% and Modbus Plus at 6%. The majority of existing systems use one of the many legacy

proprietary protocols. DNP3 on serial and LAN/WAN transports remains the most

specified protocol in North American Electric Power for new and upgrade installations.

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Session One: SCADA and Substation Control Communication

DNP3 and IEC 60870-5

Both DNP3 and IEC 60870-5-101/-104 serve similar functions. They both:

Reliably and efficiently transfer field data (including information about transitoryevents) to the master station or the control centre

Allow commands to be issued to the field with a very high degree of control security

(verification and rejection of errors) by using the high-integrity select-before-operate

command strategy

Suit medium-bandwidth communication channels (e.g. 9600-baud serial connections)

Include good data link frame integrity checking

Support application layer data object identification

Include data validity checking flags

Support the transmission of digital (on/off) and analog data (in integer or floating-

point formats), counters and digital and analog control commands or setpoints

Support transfer of files, setting of clocks, etc.

IEC 60870-5-101/-104 also supports some electric-power specific objects related to

transformers and substation protection devices.

The protocols support the transfer of report-by-exception (RBE) where only changes in

field data are reported. RBE improves the efficiency with which data can be transferredunder normal operating conditions. The protocols are also capable of transmitting data

with millisecond-resolution timestamps, allowing accurate identification of the sequence

of actions in the field. These event-reporting capabilities are useful for accurate analysis

of power system events. They are also useful in other industries (such as pipeline or water

monitoring systems) where relatively infrequent scanning can be used to recover an audit

trail of field activity.

DNP3 supports an unsolicited reporting mode where a field device can report events

without being polled by the master. Unsolicited reporting can be very useful for a large

electrical distribution network where (for example) pole-top reclosers can report activity

on a shared radio bearer without being polled. IEC 60870-5-101 also supports an

unsolicited reporting mode, but only with a dedicated point-to-point communication

channel using a balanced data linkunlike the DNP3 model that can support

unsolicited reporting on multi-drop communications channels.

Substation Automation Communication

Recent years have seen a proliferation of Intelligent Electronic Devices in substations that

perform various monitoring, metering and protective functions. Some of these devices

replace earlier electromechanical devices that performed equivalent functions and some

provide entirely new capabilities such as calculation of power system harmonic levels or

distance to a fault.

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Session One: SCADA and Substation Control Communication

Relationship between standards

In the electric power control arena, the working groups of IEC TC57 have produced a set

of protocols that cover the transfer of data through all parts of electric utility control

systems. The various working groups also interact with other standards bodies as

illustrated in Figure 1.

Standards &

Technology

____________

ISO ODP

IEEE

CIRED

Open GIS

Open

Application

Group

WG3

RTUs

TC57

WG9

Distribution

Feeders

SPAG

WG7

Control

Centers

Component Container

Technology

_________________

CORBA (OMG)

Enterprise Java Beans

DCOM (Microsoft)

DistribuT

ECH

GITA

T&D

Utility

Integration

Bus

WG14

DMS

EPRI

CCAPI

Project

WG13

EMS

Object

Mgmt.

Group

WGs 3,10,11,12

Substations

OLE

Process

Control

(OPC)

EPRI

UCA2

Project

Figure 1 Standardization Activities

The standards produced by the TC57 working groups are shown in Figure 2. The

philosophy adopted by the IEC is that each different application area should be addressed

by a single standard, so that no two standards provide alternate ways of achieving the

same purpose. To support this philosophy, the various standards should support each

other and have clear interfaces. The IEC TC57 has created a reference architecture shown

in Figure 3 that shows where the various standards are applied to the interfacing of

information from substation devices through to dispatch centres.

The IEC 60870-5-101 and -104 SCADA protocols connect the substation to the control

centre. These are augmented with IEC 60870-6 (Inter-Control Centre Protocol) for use

when the substation automation system provides the functionality of a control centre. IEC60870-5-102 transmits metering data and 61334 provides transmission across power line

carrier.

IEC 61850 (Communication Networks and Systems in Substations) is intended for

sharing of data between substation devices. IEC 60870-5-103 transfers protection device

data within the substation while 60834 transfers protection coordination information

between substations. IEC 61850 can also be used to transfer data between substation and

control centre, but it is not optimized for that application.

Once SCADA data has been collected by the master station, it can be shared with other

control centres using IEC 60870-6 and can interface with EMS, DMS and MIS

applications using the Common Information Model (IEC 61970) and Component

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Session One: SCADA and Substation Control Communication

Interface Specification for Information Exchange (IEC 61968). Prior to 2004 there was an

impediment to the integration of the reference model due to a fundamental

incompatibility of the object models described in IEC 61850 and those described in IEC

61970. The committees responsible for these standards have since agreed to extend their

respective models in order to provide for compatible interchange of data.

Control Center A

IT-System1

IT-Systemm

Control Center B

EMS

Apps.

61970

DMS

Apps.

61968

Communication Bus

6197061970

SCADA

RTU

Inter-CCDatalink

Substation /

Field Device

1

Substation

AutomationSystem

60870-6

Substation /Field Device

n

60870-5-103

Protectio

n,

Cont

rol,Mete

ring

61850

60834

61850

Switchgear, Transformers,Instrumental Transformers

Figure 2 TC57 Standards

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619 68

60 870-6-T ASE .2608 70-5 -101/1 04

608 70-5 -102

613 34 618 50

619 68

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Session One: SCADA and Substation Control Communication

Inter-Application Messaging Middleware

61970/61968 Common Information Model (CIM)Inboard

Interface61970 Component Interface Speci fications (CIS) 61968 SIDMS

SCADAInter-CC

Data Links

EMS Apps DMS AppsExternal IT

Apps

61850

Outboard

INterface

SCSM: Specific

Communication Service

Mappings

Substation/Field Devices

ACSI

60870-6

OSI Protocol Stacks(ISO/TCP)

ControlCenter

Figure 3 Reference Architecture

In those parts of the world where DNP3 is dominant for electric power SCADA, it is

often also used for interfacing the substation IEDs (switchgear, protection relays,

metering devices, etc.) with the RTUs, station computers and substation automation

devices. There have been a number of demonstration installations in North and South

America using the UCA2 design models. The UCA2 designs and concepts were passed to

the IEC for inclusion in IEC 61850 and the UCA2 program has been wound up.

The functions supported by some types of IED do not conform to the normal SCADA

model of objects having values that should be reported to a master station. For example,

protection devices report data associated with a protection event, such as the tripping of

a circuit breaker due to overload. The nature of these events is that they do not have a

normal state that is continuously reported, but may have information to report when an

event occurs. Such information only comes into existence because of the protection

event. Additionally, when an event occurs, there may be a large number of separate

measurements captured (such as the magnitude of the currents in each phase at the time

of the trip, the total load tripped, etc.). These various measurements constitute a complete

set or record of values associated with a single event. Some devices may also capture

oscillographic information (waveform traces) when an event occurs. Much of this data is

not reported through a SCADA system but is retrieved and analyzed separately by

protection engineers following a protection event. Because of the special requirements

and data types of these systems, some specific protocols such as IEC 60870-5-103 have

been produced to transfer this data.

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RTU61850 Station Bus

61850 Process Bus

Switchgear, Transformers

SC SM -1 SC SM -2

6 08 70-561 334

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The primary difference between the adoption of DNP3 and the IEC series of protocol

standards in different parts of the world seems to be driven largely by political forces. In

areas where technical innovation and market forces dominate, DNP3 is widely used. In

some parts of the world, national treaties, trade agreements and even government

legislation bind utilities to the use of the IEC standards. The other determining factor is

often the relative influence of European or American manufacturers in each particular

marketplace: When given the choice European vendors will tend to offer IEC interfaces

while American vendors will tend to offer DNP3 interfaces.

SCADA protocols continue to evolve

As evidenced by the new edition of IEC 60870-5-101, work is still going on to improve

these protocols. The DNP3 Technical Committee has published a series of Technical

Bulletins and other documents since 1995 that contain clarifications and extensions to the

protocol. The DNP3 protocol specification is presently being updated to incorporate this

material. The new specifications have been progressively released in draft since 2003 and

should be complete in 2006.

Standardized conformance testing has boosted the end-users confidence that devices

from different vendors will work together. The DNP3 Technical Committee first

published a conformance test for outstation devices in 1998. It is presently developing a

test procedure for master stations, scheduled for completion in 2006. The IEC working

group is currently preparing test procedures for IEC 60870-5-101 and -104 that will be

published as IEC 60870-5-6, probably in 2005. An amendment to IEC 60870-5-104 is

currently in production to clarify various matters associated with connection

management.

Other development work continues in SCADA protocol standards today. Current workitems on both committees lists include:

Improved security (especially validation of authorization of control commands)

Configuration definition (machine readable/automatic configuration) to simplify

system integration

IEC 61850

IEC 61850 is a substation automation protocol designed to allow sharing of data betweensubstation devices. It is specifically intended to support the sharing of high-speed

protection information between protection devices. Protection schemes require sharing of

data between devices to occur in a very short time, typically less than 4ms. IEC 61850

was also envisaged as a general way for all substation devices to share all real time data.

The US Electric Power Research Institute set up a research program in 1992 to develop a

Utilities Communication Architecture (UCA) that had similar goals. After

implementing a number of demonstration tests, the outcomes of this work were passed

over to the IEC as inputs to IEC 61850. Some of the UCA concepts have been adopted

directly into IEC 61850. The development of IEC 61850 has been continuing since 1994.

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Session One: SCADA and Substation Control Communication

Figure 4 IEC 61850 Levels

Figure 5 Protocols

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IEC 61850 provides for the interconnection of substation devices on a high speed

Ethernet network. The substation equipment is functionally modeled in the standard

European manner of substation-level (e.g. interlocking), bay level (e.g. protection or auto

reclose) and process level (e.g. measuring devices, switchgear, etc). This is illustrated in

Figure 4. Typical interface between devices in this model is via hard-wired field I/O (e.g.CT and VT measurements) or by data interfaces using various protocols. Some

commonly used protocols (including IEC 61850-compliant protocols) are identified for

various functions in Figure 5.

The design presented in IEC 61850 includes data models called Logical Nodes (LN).

These are divided into two groups that represent primary equipment and substation

functions. For example: the switch logical node has representations for the switch state

(open or closed) and permits commands to request change of state of the switch. Table 2

lists the logical node groups defined in IEC 61850.

Table 2 Logical Node Groups

In a similar manner to advanced SCADA protocols, each quantity in these data models

has associated quality flags, a time of measurement, etc. The standard also presents a

structured naming convention that all devices adopt. The standard provides for devices to

have self-description capabilities, identifying to other devices what data they contain and

can provide. For example: the Group Indicator listed in Table 2 is the first letter of the

Logical Node type for each LN in that group. The protocol supports a high-level object-

oriented data access mechanism to allow interrogation of data in other devices, searching

for data in other devices and subscribing to data in other devices. In the publish-subscribe

model, the publisher provides the requested data to each subscriber whenever the data

changes or on a periodic basis, as requested by the subscriber.

The standard describes a methodology for specifying configuration parameters using

XML to allow the sharing of configuration data between engineering tools and devices

from different vendors. It also provides for an automatic project documentation process.

Southern African SCADA & MES Conference 2005 IDC Technologies

Group Indicator Logical Node Groups LNs define

A Automatic Control 4

C Supervisory control 5

G Generic Function References 3

I Interfacing and Archiving 3

L System Logical Nodes 3

M Metering and Measurement 8

P Protection Functions 28

R Protection Related Functions 10a)

S Sensors, Monitoring 4a)

T Instrument Transformer 2a)

X Switchgear 2a)

Y Power Transformer and Related Functions 4a)

Z Further (power system) Equipment 15a)

LNs of this group exist in dedicated IEDs if a process bus is used. Without a process bus, LNs of this groupare the I/Os in the hardwired IED one level higher (for example in a bay unit) representing the external device

b its in uts and out uts

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The conceptual model of the standard is closely associated to functionality typically

required in some factory automation systems. The Manufacturing Message Specification

(MMS: ISO 9506) was adopted as the basis for the high-level functions. MMS uses

TCP/IP as its transport. IEC 61850 also describes some special services that operate

directly at the Ethernet level: GSSE (Generic Substation Status Event), GOOSE (Generic

Object Oriented Substation Event) and SV (Sampled Values). These messages use a high-

speed repetition broadcast mechanism to ensure prompt data delivery. IEC 61850 species

SNTP over UDP/IP for time synchronization.

SV

G O O SE SN TP

U D P/IP

M M S Protocol Suite

TC P/IP

ISO C O

T-Profile

T-Profile

G SSE

G SSE

T-Profile

ISO /IEC 8802-2 LLC

ISO /IEC 8802-3 Ethertype

ISO / IE C 8802-3

Figure 6 Mapping of Services

A specific application function, such as the implementation of a protection scheme,

typically involves logical nodes in one or more physical device. For example, a

measurement unit might directly monitor the values of the power system voltage, current

and phase angle quantities and provide these to the device that performs the protection

function. The device performing the protection function also communicates with the

circuit breaker controller to which it will issue a command to trip when required. The

protection function may also communicate with a station computer (HMI) to show its

status, etc. Each logical node may be used as part of one or more functions. The IEC

61850 standard describes the logical nodes and their interfaces but does not describe the

application functions that they are used for, nor does it describe which logical nodes

should be provided in any specific piece of equipment. These are matters left to the

equipment vendor.

The first field deployments of IEC 61850 were completed in November 2004 when

Siemens and ABB commissioned one substation each in Switzerland.

The goals of IEC 61850 include the standardization of substation control system designs

to reduce the amount of effort required in engineering each installation. This should lead

to improved economies over the life of a substation control system. It is recognized that

equipment that supports IEC 61850 has a higher capital cost than equivalent equipment

that does not. Early design studies suggest that there are modest reductions in engineering

effort required to configure substation control systems using IEC 61850. As the tools

mature, it is expected that the level of automation of the design process can be increased,

leading to further reduction. It is expected that the ongoing cost of configuration

maintenance should be significantly reduced.

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These benefits are best seen when considering a complete control system replacement or

new installation. There is less benefit to be gained from partial retrofit of IEC 61850-

compliant equipment, and no initial benefit from the installation of individual orphaned

IEC 61850 compliant equipment. There may, however, be justification for such

piecemeal approaches to substation refurbishment, as reengineering workload should be

reduced in the long term when significant amounts of the control equipment can use the

common interfaces.

Whats next?

The IEC 60870-5-101/-104 and DNP3 protocols were purpose-designed for their SCADA

roles. They probably have a service life of another 15 to 20 years. It is not yet clear what

will replace them. The IEC 61850 substation automation protocol might take over their

role. Much could depend on a revolution or evolution in communications bandwidth and

processing power. The existing protocols that were specifically designed for robust and

efficient reporting of SCADA data are optimized for that role.

The trend for expansion of SCADA applications to collect field data for corporate IT

systems will have an impact on system requirements. The future seems to promise greater

integration and data sharing between devices with less manual configuration effort.

Recent trends have shown a continual increase in substation equipment capability and a

concurrent increase in the number of parameters and variables they use or can monitor

and report. Some of this data is useful for the real-time operation and monitoring of the

substation, some can be useful for post-mortem fault analysis. The capability of IEC

61850 to transport complex data objects may make it ideal to transport more of this ad-

hoc data.

It is possible that future systems will see support for interfaces where a combination of

protocols can used. This would permit each interface to be optimized for its particular

function, while allowing for the breadth of features that are provided by the different

protocols. The expansion of TCP/IP into the substation and between substations and

control centres will support multiple parallel information sessions. New mechanisms and

new protocols will undoubtedly be designed to serve specific applications. In the same

way that there is no single solution that fits every problem, it may be foolish to assume

that any single protocol will be the optimum mechanism for supporting every substation

control function.

Are there standards for SCADA and Substation Automation?

Some of the protocol standards that are commonly used in electric power SCADA and

Substation Automation have been discussed here. Electric power data communication

usually imposes more stringent requirements than other industries; thus some of the

issues mentioned above may not be applicable everywhere. Adhering to standards

generally results in more flexibility, vendor-independence, cost savings and a degree of

future-proofing. As always, it is up to the end user to decide how important they are in

any particular application.

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Bibliography

DNP3 Specification Volume 1 DNP3 Introduction, DNP Users Group, 2002

IEC 60870-5-101 (2003-02) Telecontrol equipment and systems - Part 5-101:

Transmission protocols - Companion standard for basic telecontrol tasks, IEC, 2003

The World Market for Substation Automation and Integration Programs in Electric

Utilities: 20022005, Newton Evans Research Company, Inc., 2002

Reference Architecture for TC57, KPMG Consulting, 2002

IEC 61850 Communication networks and systems in substations, IEC, in various parts

since 2002

Websites

DNP Users Group Website: http://www.dnp.org

IEC Webstore: http://www.iec.chIEC 60870-5 Maillist: http://www.TriangleMicroWorks.com/iec60870-5/

SCADA Maillist: http://www.iinet.net.au/~ianw/mailst.html

IEC 61850 & UCA Users Group: http://www.ucausersgroup.org/

About the Author

Andrew West received Bachelors degrees in Engineering, Science and Arts from the

University of Queensland. He spent ten years with the Queensland Electricity

Commission as a control system software engineer working on both master stations and

transmission substation control systems and six years with Leeds & Northrup as firmware

system architect for the Foxboro RTU products. He has worked for Triangle

MicroWorks, Inc., a provider of software source code libraries for SCADA

communication protocols and is now SCADA System Architect for Invensys in Brisbane.

He also spent two years in the Maldives as an Australian Volunteer Abroad. He is a

Graduate member of the Institution of Engineers, Australia and is a Member of the IEEE.

Andrew has been involved in SCADA systems for over 20 years and has participated in

SCADA protocol standardization activities since 1996. He co-authored IEEE standards

1379 (IEEE Recommended Practice for Data Communication Between Remote Terminal

Units and Intelligent Electronic Devices in a Substation) and P1615 (Draft Standard

Environmental and Testing Requirements for Communications Networking Devices in

Electric Power Substations). He is a member of the Standards Australia working groupEL-050: Power System Control and Communication and its predecessor IT/24 (SCADA).

He has been a member of IEC TC57 WG03 since 1998 and spokesperson for that

committee since 2001. He has been a member of the DNP Users Group Technical

Committee since 1996 and Chair of the committee since 1999.

Southern African SCADA & MES Conference 2005 IDC Technologies