ALSTOM T&D. Network Protection And Automation Guide (NPAG)

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Chapter 24  The Digital Substation

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x Integrity (preventing unauthorised modification).

x Availability / Authentication (preventing denial of

service and assuring authorised access to information).

x Non-Repudiation (preventing denial of an action taking

place).

x Traceability/Detection (monitoring and logging of

activity to detect intrusion and analyse incidents).

The threats to cyber-security may be unintentional (e

.g.

natural disasters, human error), or intentional (e.g. cyber-

attacks by hackers).

Cyber-security is attainable with a range of measures such as

closing down vulnerability loopholes, assuring availability,

implementing adequate security processes and procedures,

and providing appropriate technology such as firewalls.

Examples of vulnerabilities are:

x Indiscretions by personnel (e.g. users keep passwords in

locations visible to others).

x Bypassing of controls (e.g. users turn off security

measures).

x Bad practice (users do not change default passwords,

or everyone uses the same password to access all

substation equipment).

x Inadequate technology (e.g. substation is not

firewalled).

Examples of availability issues are:

x Equipment overload, resulting in reduced or no

performance.

x Expiry of a certificate prevents

access to equipment.

Processes and procedures are required to assure secure

exchange of the following categories of information:

x Security Context: This define

s information that allows

users to have access to devices. It includes passwords,

permissions and user credentials.

x Log and Even

t Management: This includes security

logs, which are stored in different IEDs.

x Settings: This includes information about the IED, such

as the number of used and unused ports and

performance statistics.

x Datagrams: Packets of information exchanged between

IEDs.

The OSI 7-layer model enables security measures to be applied

at the Transport layer (layer 4) and the Application layer (layer

7).

At the Transport layer the dialog between two devices is

controlled. The connections between the two devices in

question are established, managed, and terminated at

this

layer. Applying security at this layer is known as Transport

Layer Security, and the most common protocol to achieve this

is the Transport Layer Security protocol (TLS), otherwise

known as Secure Socket Layer (SSL).

Security measures applied at the Transport Layer (layer 4)

guarantee confidentiality, integrity and authenticity, but

because they rely on security provided by the transport layer,

this type of secure data exchange is limited to point-to-point

communication.

A more flexible solution can be implemented by applying

security at the Application Layer (layer 7), whereby messages

themselves are secured independently of the transport on

which they are exchanged. Application of security measures at

layer 7 produces a Service Oriented Architecture (SOA).

SOA is based on web services that are message oriented.

Secure messages can be sent between any of the devices in

the network and are not limited to point-to-point

communication. SOA solutions are not prescribed to any

specific profile, but the Device Profile for Web Services

(DPWS) protocol provides an appropriate level of security for

substation automation. Figure 24.14 depicts layer 4 (TLS) and

layer 7 (DPWS) security application.

Figure 24.14: TLS vs DPWS

DPWS enables secure web services on devices with limited

resources. This means that DPWS is very applicable to IEDs.

DPWS is widely deployed having been embedded in the

Windows 7 operating system and the DotNet framework for

previous Windows versions.

24.3.1 Role Based Access Control

In order to have a complete cyber-security solution, other

criteria must be taken into consideration, such as

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Authentication, Authorisation and Accounting (AAA).

In Role Based Access Control (RBAC), different classes of user

can be granted different rights of access to different

information in devices on the network.

A typical RBAC model is shown in Figure 24.15.

Figure 24.15: RBAC Model

The RBAC model has five basic elements: users, roles,

permissions, objects and operations.

x Objects are entities that contain or receive information

(e.g. files, directories, printers, etc.).

x Operations are executable functions (read, write, insert,

delete, etc.)

x Permission

s can contain objects and operations.

x Users acquire permissions through roles.

Transactions are controlled th

rough RBAC, so that access is

granted only to what, where, and when, and to whom it

should be granted.

A typical transaction is shown in Figure 24.16, in which an

AAA server stores security-related data such as user credentials

and permissions.

Operator Interface,

IED, or EWS

Authentication

Server

Authorisation

Server

IED

Discovery Messages

Discovery Message response

Connection attempt

Authentication required

Authentication request

Authentication response

Authorisation request

Get authorisation

Secure exchanges

Authorized

Computer

Figure 24.16: Message Flow

Note: Authorisation and Authentication functionality is

usually contained in one server. This figure shows two servers

to illustrate the detailed interactions.

Once a device is attached to the network, an automatic device

discovery process may be performed. Following that, the user

selects the device he/she would like to interact with. The

chosen device requests a token from the user to prove that

he/she has been authenticated by the security server. The user

transfers this token to the end device (in this case, the IED).

The IED then requests the user roles and credentials from the

authorisation server. If the roles and credentials are certified, a

secure exchange of data can occur between the devices'

applications. This secure data exchange includes for example

log events, messages stored at the IED level, etc., for which

the user has been granted access.

24.3.2 Cyber Security Standards

There are several standards which apply to substation cyber-

security some of which are outlined in Table 24.5.

Standard Country Outline

NERC CIP (North American Electric

Reliability Corporation)

USA

Framework for the protection of the grid

critical Cyber Assets

BDEW (German Association of

Energy and Water Industries)

Germany

Requirements for Secure Control and

Telecommunication Systems

ANSI ISA 99 USA

Relevant for electric power utility

completing existing standard and

identifying new topics such as patch

management

IEEE 1686 International

International Standard for substation

IED cyber security capabilities

IEC 62351 International

Power system data and communication.

protocol

ISO/IEC 27002 International

Framework for the protection of the grid

critical Cyber Assets

NIST SP800-53 (National Institute of

Standards and Technology)

USA

Complete framework for SCADA SP800-

82 and Industrial control system cyber

security

CPNI Guidelines (Centre for the

Protection of National Infrastructure)

Clear and valuable good practices for

Process Control and SCADA security

Table 24.5: Standards applicable to cyber-security

The NERC CIP standards, in conjunction with IEEE 1686 are

widely applied since they are compulsory in the USA, with

compliance auditing having started in 2007.

24.3.2.1 NERC Compliance

The North American Electric Reliability Corporation (NERC)

created a set of standards for the protection of critical

infrastructure. These are known as the CIP standards (Critical

Infrastructure Protection). These were introduced to ensure the

protection of critical cyber assets, which control or have an

influence on the reliability of North America’s bulk electric

systems.

The group of CIP standards are listed below:

x CIP-002-1 Critical Cyber Assets

x CIP-003-1 Security Management Controls

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x CIP-004-1 Personnel and Training

x CIP-005-1 Electronic Security

x CIP-006-1 Physical Security

x CIP-007-1 Systems Security Management

x CIP-008-1 Incident Reporting and Response Planning

x CIP-009-1 Recovery Plans

CIP-002-1 Critical Cyber Assets

CIP 002 is concerned with the identification of critical assets,

such as overhead lines and transformers, as well as critical

cyber-assets, such as IEDs that use routable protocols to

communicate outside or inside the Electronic Security

Perimeter, or are accessible by dial-up. Utilities are required to

create and maintain a register of these assets.

CIP-003-1 Security Management Controls

CIP 003 requires the implementation of a cyber security policy,

with associated documentation, that demonstrates

Management commitment and ability to secure its critical

cyber-assets. The standard also requires change control

practices whereby all entity or vendor-related changes to

hardware and software components are documented and

maintained.

CIP-004-1 Personnel and Training

CIP 004 requires that personnel having authorised cyber-

access or authorised physical access to critical cyber-assets,

(including contractors and service engineers), have an

appropriate level of training to assure security.

CIP-005-1 Electronic Security

CIP 005 requires the establishment of an Electronic Security

Perimeter (ESP), which provides:

x The disabling of ports and services that are not required

x Permanent monitoring and access to logs

x Vulnerability assessments (yearly at a minimum)

x Documentation of network changes

CIP-006-1 Physical Security

CIP 006 requires that physical security controls, providing

perimeter monitoring and logging along with robust access

controls, are implemented and documented. All cyber-assets

used for physical security are considered critical and should be

treated as such.

CIP-007-1 Systems Security Management

CIP 007 addresses system security management and covers

the following points:

x Test procedures

x Ports and services

x Security patch management

x Antivirus

x Account management

x Monitoring

x Annual vulnerability assessment

These should be defined and documented for all c

ritical cyber

assets.

CIP-008-1 Incident Reporting and Response Planning

CIP 008 requires that an incident response plan be developed,

including the definition of an incident response team, their

responsibilities and associated procedures.

CIP-009-1 Recovery Plans

CIP 009 requires that a disaster recovery plan should be

created and implemented. It should be tested with annual

drills.

24.3.2.2 IEEE 1686

IEEE 1686 is an IEEE Standard for substation IEDs' cyber-

security capabilities. Used in conjunction with the NERC CIP

standards, it proposes practical and achievable mechanisms to

achieve secure operations as outlined below:

x Passwords are 8 characters long and can contain

upper-case, lower-case, numeric and special

characters.

x Passwords are never displayed or transmitted to a user.

x IED functions and features are assigned to different

password levels. The assignment is fixed.

x Record of an audit trail listing events in the order in

which they occur, held in a circular buffer.

x Records contain all defined fields

from the standard and

record all defined function event types where the

function is supported.

x No password defeat mechanism exists. Instead a

secure recovery password scheme is implemented.

x Unused ports (physical and logical) may

be disabled.

Whilst the potential threats from cyber-attack are grave,

methods for assuring security in the real and cyber worlds are

constantly evolving and, correctly applied, should help keep the

lights on.

24.4 CURRENT AND VOLTAGE – DIGITAL

TRANSFORMATION

Developments in communication have done much to realise

the digital substation, but to realise a full digital substation it is

necessary to have everything in digital form. Whilst much

substation protection, control, and automation technology has

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always been digital (trip signals, interlocking signals, etc.), the

principal power system inputs of voltage and current have

traditionally been presented in analogue form.

It has been traditional to present scaled versions of power

system currents and voltages to measuring devices, protective

relays etc. Scaled versions can easily be produced using

conventional electrical transformers, although capacitor

dividers may be additionally employed for transforming very

high voltages.

As is shown in chapter 6, conventional transformers based on

iron cores introduce measurement errors. Due to the wide

dynamic range of current signals on power systems, current

transformers for protection need large cores to avoid saturation

under fault conditions. Due to the nature of the magnetic core

material, however, these large cores produce significant errors

at nominal current, which renders them impractical for

metering purposes. Therefore metering-class transformers

need to be introduced resulting in increasing costs.

The iron core is a source of inaccuracy due to the need to

magentise the core, as well as the effect of flux remanence,

flux leakage, eddy current heating, etc. Conventional wired

1A/5A current transformers (CT) circuits have thermal

overload constraints, and pose increasing burdens on the core

as cross-site wire run lengths increase. This can degrade

protection performance, potentially leading to the need to

duplicate CTs. Conventional voltage transformer (VT) circuits

may experience ferro-resonance phenomena, with thermal

overstress resulting. Capacitor voltage transformers (CVT) can

produce high frequency interference signals.

As introduced in chapter 6, techniques that do not require the

iron core of conventional transducers can overcome the

limitations. The solutions use different sensor technologies

such as optical and Rogowski coils. In practical

implementations, the techniques require sophisticated

solutions employing digital signal processors and micro-

processors in numerical products. Since such solutions are

eminently able to support digital communications, it is a logical

progression to present numerical representations of the

measured quantities to other substation devices via

communication links, rather than reproducing scaled analogue

waveforms. This presentation of analogue power system

quantities in the form of standardised digital communication

signals is the final element in realising the digital substation.

Solutions providing signal transformation based on technology

other than wound transformers are often referred to as non-

conventional instrument transformers (NCIT), and the devices

that provide the standardised digital communication

equivalents of the power system signals are referred to as

merging units.

As described in the earlier chapter on transformers, NCIT

technologies may be based on optical techniques, or Rogowski

coils, and overcome the limitation of iron-cored transformers

by delivering:

x Single devices providing measurement class accuracy

with dynamic ranges also capable of faithfully re-

producing fault currents.

x Reliable, repeatable accuracy.

x High measurement bandwidth for rated frequency,

harmonics, and sub-harmonics.

x Low electrical stress insulation – no premature ageing,

moisture ingress, or risk of ex

plosion.

As well as having a lower risk of explosion, NCIT devices

are

also inherently safer since they cannot be ‘open-circuited’.

An NCIT device based on Rogowski coil technology is shown in

Figure 24.17.

Figure 24.17: Rogowski coil installation in GIS

Merging units present signals such as power system voltages

and currents to IEDs within the substation, in the form of

numerical values adhering to standardised definitions. The use

of NCIT sensors has made it possible for raw measurement

information to be fed into so-called Merging Units for further

distribution. It is these merging units that are one of the main

contributors to the digital substation, and these will be

discussed in the next section.

24.4.1 Merging Unit

The merging unit (MU) is the interface device which takes as

its inputs connections from the instrument transformer

sensors, and performs signal processing to generate and

distribute output sampled value streams. The merging unit is

thus the gateway to the data from the instrument transformer,

as it has the intelligence to interpret the effects of the specialist

physical characteristics of the instrument transformer sensor,

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Chapter 24  The Digital Substation

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and convert the output to a numerical value adhering to

standardised definitions for communication with substation

IEDs.

As well as connecting with NCIT technology such as optical

sensors and Rogowski coils, merging units can also be

provided in conjunction with conventional transformer

technology such that numerical equivalents of system current

and voltage can be provided over communication buses.

Using merging units with conventional current and voltage

transformers allows the different life-cycle expectations of

primary and secondary plant to de de-coupled as per Figure

24.18.

Figure 24.18: De-coupling primary and secondary plant with merging

units

Key features of merging units are:

x They can support signal processing for all transformer

types including conventional and NCIT.

x They provide accurately time-stamped sampled

analogue values.

x They deliver Ethernet multicast transmission of sampled

analogue values via a process bus.

x They can support Ethernet connection to the station

bus.

x They feature watchdog self monitoring of the NCIT

sensors as well as the MU itself.

The connections to the process bus and

station bus are in

accordance with the IEC61850 standard t

hat is introduced

later in this chapter and is shown in Figure 24.19.

Figure 24.19: Location of MU in the substation

Each merging unit module offers signal processing to provide

sampled values of phase currents (Ia, Ib, Ic), phase voltages

(Va, Vb, Vc), plus residual current and residual voltage. The

sampled value frames are multicast via Ethernet, using a fibre

optic, or copper Ethernet connection.

The outputs of the merging units need to be accurately time

stamped. This requires the merging units to be accurately

time-synchronised, and this is discussed in the next section.

24.4.1.1 Merging Unit Time Synchronisation

The accurate time synchronisation needed by the merging

units is realised in the same way as for synchronising phasor

measurement units (PMUs) described in chapter 20.

Synchronisation can be achieved thanks to the global

positioning satellite system. Synchronising signals may either

be delivered over fibre-optic links in the form of one-pulse-per-

second (1pps) signals or over Ethernet according to IEEE1588.

In 1956 the American Inter Range Instrumentation Group

standardised the different time code formats. These were

published in the IRIG Document 104-60. This was revised in

1970 to IRIG Document 104-70, and published later as IRIG

Standard 200-70.

The name of an IRIG code format consists of a single letter

plus 3 subsequent digits. Each letter or digit reflects an

attribute of the corresponding IRIG code. The following tables

contain the meanings of the suffixes and descriptions of the

abbreviations used.

Suffix

position

Suffix description Suffix Specification

First letter Format

1000 PPS

100 PPS

1 PPM

10 PPS

10000 PPS

1 PPS

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Suffix

position

Suffix description Suffix Specification

First digit Modulation Frequency

DC Level Shift, width coded, no carrier

Sine wave carrier, amplitude modulated

Manchester Modulated Code

Second digit Frequency/Resolution

No carrier/index count interval

100 Hz / 10 milliseconds

1 kHz / 1 milliseconds

10 kHz / 100 microseconds

100 kHz / 10 microseconds

1 MHz / 1 microsecond

Third digit Coded expressions

BCD

TOY

, CF, SBS

BCD

TOY

, CF

BCD

TOY

BCD

TOY

, SBS

BCD

TOY

, BCD

YEAR

, CF, SBS

BCD

TOY

, BCD

YEAR

, CF

BCD

TOY

, BCD

YEAR

BCD

TOY

, BCD

YEAR

, SBS

Table 24.6: Serial time code formats

Abbreviation Meaning

PPS Pulses Per Second

PPM Pulses Per Minute

DCLS DC Level Shift

BCD Binary Coded Decimal, coding of time (HH,MM,SS,DDD)

CF Control Functions depending on the user application

SBS Straight Binary Second of day (0....86400)

TOY Time Of Year

Table 24.7: Suffix Descriptions

There are many subsets of the IRIG-B format. IRIG-B is the

standard for time synchronisation using 100 PPS. It was this

flavour that was embraced by the utility industry to provide

real-time information exchange between substations. For IED

time synchronisation, IRIG-B12x is typically used for

modulated signals and IRIG-B00x for demodulated signals.

The IRIG-B time code signal is a sequence of one second time

frames. Each frame is split up into ten 100ms slots as follows:

 Time-slot 1: Seconds

 Time-slot 2: Minutes

 Time-slot 3: Hours

 Time-slot 4: Days

 Time-slot 5 and 6: Control functions

 Time-slots 7 to 10: Straight binary time of day

The first four time-slots define the time in binary-coded

decimal (BCD). Time-slots 5 and 6 are used for control

functions, which control deletion commands and allow

different data groupings within the synchronisation strings.

Time-slots 7-10 define the time in SBS (Straight Binary

Second of day).

Each frame starts with a position reference and a position

identifier. Each time-slot is further separated by an 8mS

position identifier.

A typical 1 second time frame is illustrated in Figure 24.20. If

the control function or SBS time-slots are not used, the bits

defined within those fields are set as a string of zeroes.

Figure 24.20: IRIG-B frame construction

The 74-bit time code contains 30 bits of BCD time-of-year

information in days, hours, minutes and seconds, 17 bits of

SBS, 9 bits for year information and 18 bits for control

functions.

The BCD code (seconds sub-word) begins at index count 1

with binary coded bits occurring between position identifier

bits P0 and P6: 7 for seconds, 7 for minutes, 6 for hours, 10

for days and 9 for year information between position identifiers

P5 and P6 to complete the BCD word. An index marker occurs

between the decimal digits in each sub-word to provide

separation for visual resolution.

The SBS word begins at index count 80 and is between

position identifiers P8 and P0 with a position identifier bit, P9

between the 9th and 10th SBS coded bits. The SBS time code

recycles each 24-hour period.

The eighteen control bits occur between position identifiers P6

and P8 with a position identifier every 10 bits.

The frame rate is 1.0 second with resolutions of 10ms (dc level

shift) and 1ms (modulated 1 kHz carrier).

With IEDs interconnected via Ethernet on the station bus, and

with time synchronised merging units multicasting time

stamped analogue sampled values via the process bus, the

building blocks for the digital substation are all in place. The

need for a common understanding between source and

destination has already been highlighted. The introduction of

standard protocols such as Modbus, DNP3 and IEC60870-5-

103 go some way to opening the doors to common

understanding, but it was the introduction of IEC61850 that

brought true possibilities for interoperability and ‘plug-and-

play’ opportunities for substation automation.

24.5 IEC61850

In the early 1990s the Electric Power Research Institute

(EPRI) in the US started work on a Utility Communications

Architecture (UCA). The goal was to produce industry

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Chapter 24  The Digital Substation

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consensus regarding substation integrated control, protection,

and data acquisition, to allow interoperability of substation

devices from different manufacturers. The work developed to

produce UCA2 which showed that true interoperability was

possible. UCA2 was taken forward by IEC TC57 to produce the

standard IEC61850 that revolutionises substation automation.

24.5.1 Benefits of IEC61850

IEC 61850 is the international standard for Ethernet-based

communication in substations. It enables integration of all

protection, control, measurement and monitoring functions

within a substation, and additionally provides the means for

interlocking and inter-tripping.

IEC 61850 is more than a protocol, or even a collection of

protocols. It is a comprehensive standard, which was designed

from the ground up to operate over modern networking

technologies. It delivers functionality that is not available from

legacy communications protocols. These unique characteristics

of IEC 61850 can significantly reduce costs associated with

designing, installing, commissioning and operating power

systems.

Some of the key features and capabilities of IEC61850 are as

follows:

x Use of a virtualised model: In addition to the protocols

that define how the data is transmitted over the

network, the virtualised model also allows definition of

data, services, and device

behaviour.

x Use of names for data: Every element of IEC 61850

data is named using descriptive strings.

x Object names are standardised: Names are not dictated

by the device vendor nor co

nfigured by the user. They

are defined in the standard and provided in a power

system context, which allows the engineer to

immediately id

entify the meaning of the data.

x Devices are self-describing: Client applications can

download the description of all the data, without any

manual configuration of data

objects or names.

x High-Level Services: IEC61850’s abstract

communications service interface supports a wide

variety of services, such as generic object-oriented

substation events (GOOSE), sampled measured values

(SMV), logs, etc.

x Standardised substation configuration language (SCL):

SCL enables the configuration

of a device and its role in

the power system to be precisely defined using

extensible mark-up

language (XML) files.

The major benefits of the standard are as follows:

x Eliminates procurement ambiguity: As well as for

configuration purposes, SCL can be used to precisely

define user requirements for substations and devices.

x Lower installation cost: IE

C 61850 enables devices to

exchange data using GOOSE over the station LAN

without having to wire separate links for each IED. By

using the station LAN to exchange these signals, this

reduces infrastructure costs associated with wiring,

trenching and

ducting.

x Lower transducer costs: A single merging unit can

deliver measurement signals to many devices using a

single transducer. This reduces transducer, wiring,

calibration, and maintenance costs.

x Lower commissioning costs: IEC 61850-compatible

devices do not require much manual configuration.

Also, client applications do not need to be manually

configured for

each point they need to access, because

they can retrieve this information directly from the

device or import it via an SCL file. Many applications

require nothing more than the setting up of a network

address. Most manual configuration is therefore

eliminated, drastically reducing errors, rework, and

therefore costs.

x Lower equipment migration costs: The cost associated

with equipment migrations is reduced due to the

standardised naming conventions and

device

behaviour.

x Lower extension costs: Adding devices and applications

into an existing IEC 61850-based network can be done

with little impact on existing equipment.

x Lower integration costs. IEC 61850 networks are

capable of delivering data without separate

communication front-ends or

reconfiguring devices.

This means that the cost associated with integrating

substation data is substantially reduced.

x Implement new capabilities: IEC61850 enables new

and innovative applications that would be

too costly to

produce otherwise. This is because all data associated

with a substation is available on its LAN in a standard

format and accessible using standard protoc

ols.

24.5.2 Structure of the IEC 61850 standard

The IEC 61850 standard consists of ten parts, as summarised

in Table 24.8.

Part Title

Part 1 Introduction and overview

Part 2 Glossary

Part 3 General requirements

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Part Title

Part 4 System and project management

Part 5 Communication requirements for functions and device models

Part 6

Configuration description language for communication in electrical

substations related to IEDs

Part 7 Basic communication structure for substation and feeder equipment

Part 7.1 - Principles and models

Part 7.2 - Abstract communication service interface (ACSI)

Part 7.3 - Common data classes

Part 7.4 - Compatible logical node classes and data classes

Part 8 Specific Communication Service Mapping (SCSM)

Part 8.1

- Mappings to MMS (ISO 9506-1 and ISO 9506-2) and to ISO/IEC

8802-3

Part 9 Specific Communication Service Mapping (SCSM)

Part 9.1 - Sampled values over serial unidirectional multidrop point to point link

Part 9.2 - Sampled values over ISO/IEC 8802-3

Part 10 Part 10: Conformance testing

Table 24.8: Structure of IEC 61850 standard

Parts 1 and 2 introduce the standard, provide a summary and

a glossary of all terms used throughout the standard. Parts 3,

4, and 5 of the standard start by identifying the general and

specific functional requirements for communication in a

substation (key requirements stated above). These

requirements are then used as forcing functions to aid in the

identification of the services and data models needed,

application protocol required, and the underlying transport,

network, data link, and physical layers that will meet the

overall requirements.

Part 6 of the standard defines an XML-based Substation

Configuration Language (SCL). SCL allows formal description

of the relations between the substation automation system and

the substation switchyard. Each device must provide an SCL

file that describes its own configuration.

Part 7 specifies the communication structure for substations.

It consists of 4 sub-sections. IEC 61850 abstracts the

definition of the data items and the services from the

underlying protocols. These abstract definitions allow data

objects and services to be mapped to any protocol that can

meet the data and service requirements. The definition of the

abstract services is found in part 7.2 of the standard and the

abstraction of the data objects (referred to as Logical Nodes) is

found in part 7.4. Many of the data objects belong to common

categories such as Status, Control, Measurement, and

Substitution. These are known as Common Data Classes

(CDCs). These CDCs, which define common building blocks for

creating the larger data objects, are defined in part 7.3.

The abstract definitions of data and services can be mapped

onto various suitable protocols. Section 8.1 of the standard

defines the mapping of these onto the Manufacturing

Messaging Specification (MMS). Section 9.2 defines the

mapping of Sample Measured Values onto an Ethernet data

frame. The 9.2 document defines what has become known as

the process bus.

24.5.3 The IEC 61850 data model

A typical communications protocol defines how data is

transmitted over a medium, but does not specify how the data

should be organised in terms of the application. This approach

requires power system engineers to manually configure objects

and map them to power system variables at a low level

(register numbers, index numbers, I/O modules, etc.).

IEC 61850 is different in this respect. In addition to the

protocol elements, it specifies a comprehensive model for how

power system devices should organise data in a manner that is

consistent across all types and brands of devices. This

eliminates much of the tedious non-power system

configuration effort because the devices can configure

themselves.

Some devices use an SCL file to configure the objects. If this is

the case, the engineer needs only to import this SCL file into

the device. The client application will then extract the object

definitions from the device over the network. This significantly

reduces the effort needed to configure the device.

The data model of any IEC 61850 IED can be viewed as a

hierarchy of information, whose nomenclature and

categorisation is defined and standardised in the IEC 61850

specification. The IEC61850 data model is represented

conveniently by Figure 24.21.

Figure 24.21: IEC 61850 device model

The device model starts with a physical device that connects to

the network – typically, the IED. The physical device is defined

by its network IP address. Within each physical device, there

may be one or more logical devices. The IEC 61850 logical

device model allows a single physical device to act as a proxy

or gateway for multiple logical devices.

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Chapter 24  The Digital Substation

24-19

Each logical device contains one or more logical nodes. A

logical node is a named grouping of data and associated

services that is logically related to some power system

function. These logical nodes are categorised into 13 different

groups and 86 different classes. Table 24.9 lists these groups

and specifies the group designators of each.

Logical node groups Group designator

System logical nodes L

Protection functions P

Protection related functions R

Supervisory control C

Generic function references G

Interfacing and archiving I

Automatic control A

Metering and measurement M

Switchgear X

Instrument transformer T

Power transformer and related functions Y

Further power system equipment Z

Sensors S

Table 24.9: Logical node categorisation

The names of these logical nodes have been standardised in

IEC61850 and cannot be changed. The naming convention is

as follows:

<Single letter group designator><three-letter mnemonic

abbreviation of function><instance ID>

For example: PDIR1 belongs to the group “Protection

functions” and is the “Directional element” for the first stage

(of overcurrent protection, typically). A complete list of logical

node names is provided in the standard, and a selection of

those most pertinent to readers is given in appendix C.

Each logical node contains one or more elements of data.

There are several hundred data elements, which can be

broadly categorized into seven groups:

x System information

x Physical device information

x Measurands

x Metered values

x Controllable data

x Status information

x Settings

Each data element has a unique purposeful name determined

by the standard, along with

a set of attributes. These data

names provide a mnemonic description of its function. For

example, a circuit breaker is modelled as an XCBR logical

node. This contains a variety of data including:

Loc

for determining if operation is remote or local

OpCnt

for an operations count

Pos

for the position

BlkOpn

block breaker open commands

BlkCls

block breaker close commands

CBOpCap

for the circuit breaker operating capability

Each element of data conforms to the specification of a

common data class (CDC), which describes the type and

structure of the data within the logical node. There are CDCs

for:

x Status information

x Measured information

x Controllable status information

x Controllable analogue set point information

x Status settings

x Analogue settings

Each CDC has a set of attributes each with a defined name,

defined type, and specific

purpose. A set of functional

constraints (FC) groups these attributes into categories. For

example, there is a CDC called SPS (Single Point Status).

In the Single Point Status (SPS) CDC there are functional

constraints for status (ST) attributes, substituted value (SV)

attributes, description (DC) attributes, and extended definition

(EX) attributes. In this example the status attributes of the SPS

class consist of a status value (stVal), a quality flag (q), and a

time stamp (t).

Example:

Suppose that a logical device called B

Breaker1

consists of a

single circuit breaker logical node X

XCBR1

. To determine if the

breaker is in the remote or local mode of operation, the

following expression would be used:

x Breaker1/XCBR1$ST$Loc$stVal.

The returned value would indicate the mode of operation.

24.5.4 Mapping IEC 61850 to a protocol stack

The IEC 61850 abstract model needs to work over a real set of

protocols, which are convenient and practical to implement,

and which can operate within the computing environments

commonly found in the power industry. The IEC61850

standard takes advantage of existing protocols to achieve each

necessary layer of communication.

Figure 24.22 shows a simplified version of the IEC61850

protocol stack, and how it fits in with the OSI model.

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Network Protection & Automation Guide

24-20

Figure 24.22: IEC 61850 protocol stack

IEC 61850 part 8.1 maps the abstract objects and services to

the Manufacturing Message Specification (MMS) protocols

specified in ISO9506. MMS is the only public ISO-compliant

protocol that can easily support the complex naming and

service models specified by IEC 61850. MMS is used because

it supports complex named objects and a rich set of flexible

services that supports the mapping to IEC 61850 in a

straightforward manner.

Part 8.1 also defines profiles for the lower layers of the

communication stack. MMS operates over connection-

oriented ISO, or TCP/IP. SNTP operates over TCP/IP or

UDP/IP. Sampled Values and GOOSE data map directly into

the Ethernet data frame thereby eliminating processing of any

middle layers and providing very fast response.

24.5.5 Substation Configuration Language

IEC 61850-6-1 specifies an XML-based Substation

Configuration Language (SCL) to describe the configuration of

IEC 61850 based systems. SCL specifies a hierarchy of

configuration files, which enable the various levels of the

system to be described. These are:

 System specification description (SSD)

 IED capability description (ICD)

 Substation configuration description (SCD)

 Configured IED description (CID) files

These files are constructed in the same method and format,

but have different scopes depending on the need. Even though

an IEC 61850 client can extract the configuration from an IED

when it is connected over a network, there are several benefits

of having a formal off-line description language for reasons

other than configuring IEC 61850 client applications. These

benefits are as follows:

 SCL enables off-line system development tools to

generate the files needed for IED configuration

automatically from the power system design. This

significantly reduces the cost and effort associated with

IED configuration by eliminating most of the manual

configuration tasks.

 SCL enables the sharing of IED configuration details

among users and suppliers. This helps to reduce

inconsistencies and misunderstandings in system

configuration requirements. Users can specify and

provide their own SCL files to ensure that IEDs are

configured according to their requirements.

 SCL allows IEC 61850 applications to be configured off-

line without requiring a network connection to the IED.

Figure 24.23 illustrates the position and workflow context of

the configuration files in an IEC61850 project

Figure 24.23: IEC 61850 project configuration

24.5.6 IEC61850-9.2

In IEC61850-9.2, the wiring that traditionally connected

transformers and switchgear to protection control and

monitoring devices is replaced by a process bus, where the

process bus is a high-speed Ethernet communications

network.

Merging units form the data acquisition layer in the network

and present sampled measured values to IEDs via the process

bus.

The interface of the merging unit with the primary plant may

either be in the form of conventional transformers, or with

non-conventional instrument transformers (NCIT), but the

output is the same: time-stamped sampled measured values.

The use of the IEC 61850-9.2 process bus introduces a

number of opportunities for lifecycle cost reduction. This

lifecycle cost comprises configuration, installation and

commissioning costs, plus costs beyond commissioning.

These later-life costs include any need for extension, upgrade

or retrofitting, and also any periodic maintenance.

Some key points where the process bus offers distinct

advantage are described in the following paragraphs:

Mid-life secondary equipment renewal:

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