IEC TR 61850-1-1:2026

IEC TR 61850-1-1 ®
Edition 1.0 2026-02
Corrected version
2026-02
TECHNICAL
REPORT
Communication networks and systems for power utility automation -
Part 1-1: Introduction and overview
ICS 33.200  ISBN 978-2-8327-1081-4

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CONTENTS
FOREWORD . 3
INTRODUCTION . 5
1 Scope . 6
2 Normative references . 6
3 Terms, definitions and abbreviations . 6
3.1 Terms and definitions . 6
3.2 Abbreviated terms. 8
4 Objectives . 9
5 Approach of the IEC 61850 (all parts) [1] standard . 10
5.1 Scope of application . 10
5.2 IEC 61850 (all parts) [1] within the IEC Power Utility control system
reference architecture . 11
5.3 IEC 61850 (all parts) [1] within Smart Grid reference architecture . 12
5.4 Standardization approach . 12
5.5 How to cope with fast innovation of communication technology. 13
5.6 Representation of functions and communication interfaces . 13
5.7 Requirements for a physical communication system . 16
6 Content of IEC 61850 (all parts) [1] . 16
6.1 IEC 61850 (all parts) [1] general requirements (parts 1 to 5) . 16
6.2 Three pillars of interoperability and conformance testing (Part 6 and above) . 17
6.3 Understanding the structure of the IEC 61850 documentation. 18
6.4 IEC 61850 data modelling . 20
6.4.1 Main principle (explained in IEC 61850-7-1 [28]) . 20
6.4.2 Standard name space introduction . 22
6.4.3 Name space extension . 23
6.5 IEC 61850 (all parts) [1] communication services . 23
6.6 IEC 61850 (all parts) [1] SCL language . 25
6.7 IEC 61850 (all parts) [1] data and communication security . 25
6.8 IEC 61850 (all parts) [1] conformance testing . 26
6.9 UCA/IEC 61850 (all parts) [1] international users' group . 26
6.10 IEC 61850 (all parts) [1] maintenance . 26
6.11 Quality assurance process . 27
7 IEC 61850 (all parts) [1] system life cycle . 27
7.1 Reason for inclusion . 27
7.2 Engineering-tools and parameters . 27
7.3 Main tools and configuration data flows . 28
7.4 Quality and life-cycle management . 29
7.5 General requirements. 29
Bibliography . 30

Figure 1 – Scope of application of IEC 61850 (all parts) [1] . 11
Figure 2 – Power utility control system reference architecture (IEC 62357 (all parts) [10]) . 12
Figure 3 – IEC 61850 (all parts) [1] specifying approach . 13
Figure 4 – Interface model within substation and between substations . 14
Figure 5 – Relationship between functions, logical nodes, and physical nodes
(examples). 15
Figure 6 – Links between IEC 61850 (all parts) [1] parts . 19
Figure 7 – IEC 61850 (all parts) [1] Data modelling . 21
Figure 8 – Basic reference model . 24
Figure 9 – Exchange of system parameters . 28

Table 1 – Published versions of this technical report . 5

INTERNATIONAL ELECTROTECHNICAL COMMISSION
____________
Communication networks and systems for power utility automation -
Part 1-1: Introduction and overview

FOREWORD
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8) Attention is drawn to the Normative references cited in this publication. Use of the referenced
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held responsible for identifying any or all such patent rights.
IEC TR 61850-1-1 has been prepared by IEC technical committee 57: Power systems
management and associated information exchange. It is a Technical Report.
This document replaces the second edition of IEC TR 61850-1 published in 2013. The number
has been changed from IEC TR 61850-1 to IEC TR 61850-1-1, as in the meantime there is also
a document with the number IEC 61850-1-2. This edition constitutes a technical revision.
This edition includes the following significant changes with respect to the previous edition:
a) Updates to the TISSUE process.
b) Descriptions of the namespace concepts.
c) Renumbering the document from IEC 61850-1 to 61850-1-1.
The text of this Technical Report is based on the following documents:
Draft Report on voting
57/2859/DTR 57/2890/RVDTR
Full information on the voting for its approval can be found in the report on voting indicated in
the above table.
The language used for the development of this Technical Report is English.
This document was drafted in accordance with ISO/IEC Directives, Part 2, and developed in
accordance with ISO/IEC Directives, Part 1 and ISO/IEC Directives, IEC Supplement, available
at www.iec.ch/members_experts/refdocs. The main document types developed by IEC are
described in greater detail at www.iec.ch/publications.
A list of all parts in the IEC 61850 series, published under the general title Communication
networks and systems for power utility automation, can be found on the IEC website.
The committee has decided that the contents of this document will remain unchanged until the
stability date indicated on the IEC website under webstore.iec.ch in the data related to the
specific document. At this date, the document will be
– reconfirmed,
– withdrawn, or
– revised.
This corrected version of IEC TR 61850-1-1:2026 incorporates the following correction:
– Addition of bibliographic reference numbers in the content
INTRODUCTION
IEC 61850-1-1 is an introduction and overview of the IEC 61850 (all parts) [1] standard series.
It describes the philosophy, work approach and contents of the other parts.
Table 1 gives an overview of all published versions of this technical report.
Table 1 – Published versions of this technical report
Edition Publication date Webstore
Edition 1 2003-04 IEC TR 61850-1:2003
Edition 2 2013-03 IEC TR 61850-1:2013
Edition 1 2026-xx IEC TR 61850-1-1:2026
1 Scope
This technical report is applicable to power utility automation systems (PUAS). It defines the
communication between intelligent electronic devices (IEDs) in such a system, and the related
system requirements.
This part gives an introduction and overview of the IEC 61850 (all parts) [1] standard series. It
refers to and might include text and figures coming from other parts of the IEC 61850 (all parts) [1]
standard series.
2 Normative references
The following documents are referred to in the text in such a way that some or all of their content
constitutes requirements of this document. For dated references, only the edition cited applies.
For undated references, the latest edition of the referenced document (including any
amendments) applies.
IEC 61850 (series), Communication networks and systems for power utility automation
3 Terms, definitions and abbreviations
3.1 Terms and definitions
For the purposes of this document, the terms and definitions given in IEC 61850 (series) and
the following apply.
ISO and IEC maintain terminology databases for use in standardization at the following
addresses:
– IEC Electropedia: available at https://www.electropedia.org/
– ISO Online browsing platform: available at https://www.iso.org/obp
3.1.1
Abstract Communication Service Interface
ACSI
virtual interface to an IED providing abstract communication services, for example connection,
variable access, unsolicited data transfer, device control and file transfer services, independent
of the actual communication stack and profiles used
3.1.2
bay
subpart of a substation, having some common functionality, closely connected to the other
subparts, and forming a substation
3.1.3
data object
part of a logical node object representing specific information, for example, status or
measurement
Note 1 to entry: From an object-oriented point of view, a data object is an instance of a data object class. Data
objects are normally used as transaction objects; i.e., they are data structures.

3.1.4
device
mechanism or piece of equipment designed to serve a purpose or perform a function, for
example, breaker, relay, or substation computer
[SOURCE: IEEE 100:2000, The Authoritative Dictionary of IEEE Standards Terms, Seventh
Edition [2]]
3.1.5
functions
tasks which are performed by the power utility automation system, i.e. by application functions
Note 1 to entry: Generally, functions exchange data with other functions. The details are dependent on the functions
in consideration. Functions are performed by IEDs (physical devices). Functions can be split in parts residing in
different IEDs but communicating which each other (distributed function) and with parts of other functions. These
communicating function parts are called logical nodes.
Note 2 to entry: In the context of this document, the decomposition of functions or their granularity is ruled by the
communication behaviour only. Therefore, all functions considered consist of logical nodes that exchange data.
3.1.6
Intelligent Electronic Device
IED
any device incorporating one or more processors with the capability of receiving or sending
data/controls from or to an external source (for example, electronic multifunction meters, digital
relays, controllers)
3.1.7
interchangeability
ability to replace a device supplied by one manufacturer with a device supplied by another
manufacturer, without making changes to the other elements in the system
3.1.8
interoperability
ability of two or more IEDs from the same vendor, or from different vendors, to exchange
information and use that information for correct execution of specified functions
3.1.9
Logical Node
LN
smallest part of a function that exchanges data
Note 1 to entry: An LN is an object defined by its data and methods.
3.1.10
Logical Device
LD
virtual device that exists to enable aggregation of related logical nodes
3.1.11
open protocol
protocol whose stack is either standardised or publicly available
3.1.12
part
part of the IEC 61850 standard series
EXAMPLE Part 6 refers to IEC 61850-6 [3], Part 7-2 refers to IEC 61850-7-2 [4].
3.1.13
Physical Device
PD
equivalent to an IED as used in the context of this document
3.1.14
process bus
process bus is the communication network which connects the IEDs at primary equipment level
to other IEDs
3.1.15
protocol
set of rules that determines the behaviour of functional units in achieving and performing
communication
3.1.16
Power Utility Automation System
PUAS
set of communicating components or devices (IEDs) arranged in a communication architecture
to perform any type of power utility automation functions
Note 1 to entry: Power Utility Automation System includes de facto Substation Automation system, as one possible
sub-system.
3.1.17
self-description
information contained by a device on its configuration
Note 1 to entry: The representation of this information has to be standardised and has to be accessible via
communication (in the context of this standard series).
3.1.18
station bus
communication network which inter-connects IEDs at bay level and IEDs at station level, and
connects bay-level IEDs to station-level IEDs
3.1.19
system
power utility automation systems
3.1.20
Specific Communication Service Mapping
SCSM
standardised procedure which provides the concrete mapping of ACSI services and objects
onto a particular protocol stack/communication profile
Note 1 to entry: To facilitate interoperability it is intended to have a minimum number of standardized mappings
(SCSM).
Note 2 to entry: An SCSM details the instantiation of abstract services into protocol specific single service or
sequence of services which achieve the service as specified in ACSI. Additionally, an SCSM details the mapping of
ACSI objects into object supported by the application protocol.
Note 3 to entry: SCSMs are specified in Parts 8-x and 9-x of this standard series.
3.2 Abbreviated terms
ACSI Abstract Communication Service Interface
CDC Common Data Class
CIM Common Information Model
DA Data Attribute
DER Distributed Energy Resource
DO Data Object
EMC Electromagnetic Compatibility
GSE Generic Substation Event (communication model)
GSSE Generic Substation State Event (communication model)
GOOSE Generic Object Oriented System Event (communication model)
IED Intelligent Electronic Device
LD Logical Device
LN Logical Node
PD Physical Device
PUAS Power Utility Automation System
SCL System Configuration description Language
SCSM Specific Communication Service Mapping
TLS Transport Layer Security
VLAN Virtual Local Area Network
XML eXtensible Markup Language
4 Objectives
The possibility to build Power Utility Automation Systems (PUAS) rests on the strong
technological development of large-scale integrated circuits, leading to the present availability
of advanced, fast, and powerful microprocessors. The result was an evolution of substation
secondary equipment, from electro-mechanical devices to digital devices. This in turn provided
the possibility of implementing Power Utility Automation Systems using several intelligent
electronic devices (IEDs) to perform the required functions (protection, local and remote
monitoring and control, etc.). As a consequence, the need arose for efficient communication
among the IEDs, especially for a standard protocol. Initially, specific proprietary communication
protocols developed by each manufacturer were used, requiring complicated and costly protocol
converters when using IEDs from different vendors.
The industry's experiences have demonstrated the need and the opportunity for developing
standard semantics, abstract communication services that can be mapped to different
protocols, configuration descriptions and engineering processes, which would support
interoperability of IEDs from different manufacturers. Interoperability in this case is the ability
to operate on the same network or communication path sharing information and commands.
There is also a desire to have IED interchangeability, i.e. the ability to replace a device supplied
by one manufacturer with a device supplied by another manufacturer, without making changes
to the other elements in the system. Interchangeability would also require standardisation of
functions which is beyond the scope of this communication standard series. Interoperability is
a common goal for electric utilities, equipment vendors and standardisation bodies.
The objective of PUAS standardisation is to develop a communication standard that will meet
functional and performance requirements, while supporting future technological developments.
To be truly beneficial, a consensus must be found between IED manufacturers and users on
the way such devices can freely exchange information.
The communication standard must support the operation functions within the substation and
distributed throughout the power grid. Therefore, the standard needs to consider the operational
requirements, but the purpose of the standard is neither to standardise nor limit in any way the
functions involved in substation operation nor their allocation within the Power Utility
Automation System. The application functions will be identified and described in order to define
their interface and then their communication requirements (for example, amount of data to be
exchanged, exchange time constraints, etc.). The communication standard, to the maximum
possible extent, will make use of existing standards and commonly accepted communication
and engineering principles.
The intended standard aims to ensure, among others, the following features:
– That the complete communication profile is based on existing IEC/IEEE/ISO/OSI
communication standards, if available.
– That the protocols used will be open and will support self-descriptive devices. It will be
possible to add new functionality.
– That the standard is based on data objects related to the needs of the electric power
industry.
– That the communication syntax and semantics are based on the use of common data objects
related to the power system.
– That the communication services can be mapped to different state-of-the art protocols.
– That the communication standard considers the implications of the substation being one
node in the power grid, i.e. of the Power Utility Automation System being one element in the
overall power control system.
– That the complete topology of an electrical system (single line diagram), the generated and
consumed information, and the information flow between all IEDs is specified, using a
machine readable language.
5 Approach of the IEC 61850 (all parts) [1] standard
5.1 Scope of application
The main parts of the IEC 61850 (all parts) [1] standard were first published from 2002 to 2005.
The standard was the result of nearly ten years of work within IEEE/EPRI on Utility
Communications Architecture (UCA) (IEEE-SA TR 1550) and within the working group
"Substation Control and Protection Interfaces" of IEC Technical Committee 57. The initial scope
of IEC 61850 was standardisation of communication in power utility automation systems.
The first edition of the standard was primarily related to protection, control and monitoring. From
2009 onwards the original parts of the IEC 61850 (all parts) [1] series have been updated and
extended to cover also measurement (including statistical and historical data handling) and
power quality. New parts of the standard will also be added to handle condition monitoring.
The concepts defined in IEC 61850 (all parts) [1] have been applied beyond the substation
domain:
– The modelling of hydropower plants, steam- and gas turbines (see IEC 61850-7-410 [5])
distributed energy resources (see IEC 61850-7-420 [6]) are also covered by the IEC 61850
series.
– The modelling of wind turbines has been standardized, according to IEC 61850, within
IEC 61400-25 (all parts) [7], Communications for monitoring and control of wind power
plants.
– The communication has also been extended to substation-to-substation communication (see
IEC TR 61850-90-1 [8]).
IEC 61850 is planned to be applied to new areas such as:
– Communication to network control centre (IEC TR 61850-90-2 [9] )
– Feeder automation domain
___________
Under consideration.
Harmonization of IEC 61850 (all parts) [1] modelling with the IEC Common Information Model
(CIM, IEC 61968 series/IEC 61970 series) is also considered as a high priority item to fulfil
Smart Grid objectives.
Given the extended scope, today's naming of the IEC 61850 (all parts) [1] standard is
Communication networks and systems for power utility automation. The final scope of
application of IEC 61850 (and affiliates) is described in Figure 1.

Figure 1 – Scope of application of IEC 61850 (all parts) [1]
5.2 IEC 61850 (all parts) [1] within the IEC Power Utility control system reference
architecture
IEC 61850 (all parts) [1] is one central communication standard of the Power Utility control
system reference architecture of IEC technical committee 57 (IEC 62357 (all parts) [10]) as
shown in Figure 2.
IEC 61850 (all parts) [1] is fully complementary to the Common Information Model Standard
(CIM - IEC 61970 (all parts) [11] - IEC 61968 (all parts) [12]).
Figure 2 – Power utility control system reference architecture (IEC 62357 (all parts) [10])
5.3 IEC 61850 (all parts) [1] within Smart Grid reference architecture
IEC 61850 (all parts) [1] is one central communication standard of the Smart Grid IEC reference
architecture, as published by the IEC Strategic Group 3 on Smart Grid. "Across the IEC Smart
Grid Framework, the Application Domain TCs must use the methods delivered by the
"horizontal" TCs included in the Framework.
IEC 61850 (all parts) [1] (existing and extended) will be used for all communications to field
equipment and systems, while the IEC 61790 and IEC 61968 (all parts) [12] will be used within
control centres for managing information exchanges among enterprise systems.
5.4 Standardization approach
The approach of the IEC 61850 (all parts) [1] series is to blend the strengths of the following
three methods:
– Functional decomposition
– Data flow modelling
– Information modelling
Functional decomposition is used to understand the logical relationship between components
of a distributed function and is presented in terms of logical nodes (LNs) that describe the
functions, subfunctions and functional interfaces.
___________
Extract from Standardization Management Board meeting 137, decision 3 (SMB/4175/R 2010-01-11).
Data flow is used to understand the communication interfaces that must support the exchange
of information between distributed functional components and the functional performance
requirements.
Information modelling is used to define the abstract syntax and semantics of the information
exchanged and is presented in terms of data object classes and types, attributes, abstract
object methods (services), and their relationships.
5.5 How to cope with fast innovation of communication technology
In order to cope with the fast innovation of communication technology, IEC 61850 (all parts) [1]
makes the communication independent from the application by specifying a set of abstract
services and objects. In this way applications can be written in a manner which is independent
from a specific protocol. This abstraction allows both vendors and users to maintain application
functionality and to optimise this functionality when appropriate as explained in Figure 3.
It also allows, as the scope of IEC 61850 (all parts) [1] is wider and wider, to cope with the
diversity of communication solutions required by the new targeted domains, while keeping the
same data model.
Figure 3 – IEC 61850 (all parts) [1] specifying approach
5.6 Representation of functions and communication interfaces
The objective of the standard is to provide a framework to achieve interoperability between the
IEDs supplied from different suppliers.
The allocation of functions to devices (IEDs) and control levels is not fixed. The allocation
normally depends on availability requirements, performance requirements, cost constraints,
state of the art of technology, utilities' philosophies etc. Therefore, the standard will support
any allocation of functions.
In order to allow a free allocation of functions to IEDs, interoperability is provided between
functions to be performed in a power utility automation system but residing in equipment
(physical devices in substation) from different suppliers. The functions might be split into
modules performed in different IEDs but communicating with each other (distributed function).
Therefore, the communication behaviour of such modules (called logical nodes (LNs)) has to
support the requested interoperability of the IEDs.
The functions (application functions) of a Power Utility Automation system are control and
supervision, as well as protection and monitoring of the primary equipment and of the grid.
Other functions (system functions) are related to the system itself, for example supervision of
the communication.
Functions can be assigned to three levels: the station level, the bay level and the process level.
NOTE 1 A substation consists of closely connected subparts with some common functionality called bays. Examples
are the switchgear between an incoming or outgoing line and the busbar, the bus coupler with its circuit breaker and
related isolators and earthing switches, the transformer with its related switchgear between the two busbars
representing the two voltage levels. The bay concept can be applied to one and a half breaker and ring bus substation
arrangements by grouping the primary circuit breakers and associated equipment into a virtual bay. These bays
comprise a power system subset to be protected such as a transformer or a line end, and the control of its switchgear
has some common restrictions such as mutual interlocking or well-defined operation sequences. The identification
of such subparts is important for maintenance purposes (which parts could be switched off at the same time with a
minimum impact on the rest of the substation) or for extension plans (what has to be added if a new line is to be
linked in). These subparts are called bays and can be managed by devices with the generic name "bay controller"
and have protection systems called "bay protection".
The concept of a bay is not commonly used all over the world. The bay level represents an additional control level
below the overall station level.
The logical communication interfaces within substation and between substations are presented
in Figure 4.
NOTE Interface numbers are for notational use in other parts of the IEC 61850 series and have no other
significance.
Figure 4 – Interface model within substation and between substations
The meanings of the interfaces are as follows:
IF1: protection-data exchange between bay and station level.
IF2: protection-data exchange between bay level and remote protection.
IF3: data exchange within bay level.
IF4: CT and VT instantaneous data exchange (especially samples) between process and bay level.
IF5: control-data exchange between process and bay level.
IF6: control-data exchange between bay and station level.
IF7: data exchange between substation (level) and a remote engineer's workplace.
IF8: direct data exchange between the bays especially for fast functions such as interlocking.
IF9: data exchange within station level.
IF10: remote control-data exchange between substation (devices) and a remote network control centre
(called NCC - beyond the scope of the standard).
IF 11: the control-data exchange between different substations.
The devices of a power utility automation system can be physically installed on different
functional levels (station, bay, and process). This refers to the physical interpretation of
Figure 4.
Process level devices are typically remote I/Os, intelligent sensors and actuators.
Bay level devices consist of control, protection or monitoring units per bay.
Station level devices consist of the station computer with a database, the operator's workplace,
interfaces for remote communication, etc.
To reach the standardisation goal of interoperability, common functions in a power utility
automation system have been identified and split into sub-functions (logical nodes). Logical
nodes can reside in different devices and at different levels. Figure 5 shows examples to explain
the relationship between functions, logical nodes, and physical nodes (devices).
A function is termed "distributed" when it is performed by two or more logical nodes that are
located in different physical devices. Since all functions communicate in some way, the
definition of a local or a distributed function is not unambiguous but depends on the definition
of the functional steps to be performed until the function is completed.
When a distributed function is implemented, proper reactions on the loss of a functional
component or an included communication link have to be provided, for example the function
could be blocked completely or shows a graceful degradation if applicable.
NOTE 2 The implementation is beyond the scope of the standard series.

Figure 5 – Relationship between functions, logical nodes, and physical nodes
(examples)
Examples in Figure 5: Physical device 1: Station computer, 2: Synchronised switching device,
3: Distance protection unit with integrated overcurrent function, 4: Bay control unit, 5 and 6:
Current and voltage instrument transformers, 7: Busbar voltage instrument transformers.
Known functions for substation, hydro power, distributed energy resources (DER) applications
have been described in IEC 61850-7-4XX. In addition to this, Annex G of IEC 61850-5:2013
[13] defines:
– task of the function;
– starting criteria for the function;
– result or impact of the function;
– performance of the function;
– function decomposition;
– interaction with other functions.
NOTE 3 Standardising functions is not the intention of the IEC 61850 series; only the interaction of functions is
covered.
Messages communicated using IEC 61850 (all parts) [1] are divided into different types with
different requirements according to IEC 61850-5.
Messages can be sent using different Abstract Communication Service Interface (ACSI)
services (see IEC 61850-7-2 [4]). These can be e.g. reporting, GOOSE or control command
and can be mapped to different protocols according to IEC 61850-8-X and IEC 61850-9-X.
5.7 Requirements for a physical communication system
Logical interfaces can be mapped to physical interfaces in several different ways. A station bus
normally implements the logical interfaces 1, 3, 6, and 9 of Figure 4; a process bus might cover
the logical interfaces 4 and 5. The logical interface 8 ('inter-bay-communication' using GOOSE
messages) can be mapped to either or to both.
Mapping of all logical interfaces to one single bus is possible, if this satisfies the required level
of performance (response time, availability, maintainability, etc.). Mapping sets of logical
interfaces to dedicated buses is also possible.
Network Engineering Guidelines included in IEC TR 61850-90-4 [14] provide definitions and
important recommendations on how to properly specify and design the physical communication
system of a Power Utility Automation system based on IEC 61850, depending on the levels of
requirement.
6 Content of IEC 61850 (all parts) [1]
6.1 IEC 61850 (all parts) [1] general requirements (parts 1 to 5)
The titles and contents of the published or planned parts of the IEC 61850 series are as follows
(refer to 6.3 and Figure 6 for a global overview of the IEC 61850 documentation):
IEC TR 61850-1-1 Introduction and overview
Introduction and overview of IEC 61850 (this document)
IEC TS 61850-1-2 [15]
Guideline on extending IEC 61850
IEC TS 61850-2 [16] Glossary
Collection of terminology and definitions used within the various parts of the standard
IEC 61850-3 [17] General requirements
Quality requirements (reliability, maintainability, system availability, portability, security)
Environmental conditions (including temperature, humidity, EMC and other constraints)
Auxiliary services
Other standards and specifications
IEC 61850-4 [18] System and project management
Engineering requirements (parameter classification, engineering tools, documentation)
System lifecycle (product versions, discontinuation, support after discontinuation)
Quality assurance (responsibilities, test equipment, type tests, system tests, FAT and SAT)
IEC 61850-5:2013 [13] Communication requirements for functions and device models of
a Power Utility Automation system
Basic requirements
Functions
Required logical nodes. Each of them has been described by:
– grouping according to their most common application area;
– short textual description of the functionality;
– IEEE device function number if applicable (for protection and some protection related logical
nodes only, refer to IEEE C37.2);
– relationship between functions and logical nodes in tables and in the functional description.
Logical communication links i.e. logical exchanged information between logical nodes
Performance
"Dynamic scenarios" (information flow requirements for different operational conditions)
6.2 Three pillars of interoperability and conformance testing (Part 6 and above)
In order to fully define how components can interoperate in a Power Utility Automation System,
while remaining independent of the implementation, the IEC 61850 (all parts) [1] standard
provides three main levels of definition:
– A standard namespace of logical nodes, data objects and attributes (parts 7-3 and 7-4), i.e.
the dictionary of standardized function interfaces (logical nodes) and names (data objects
and attributes classes). Such a repository is used to describe the information which has to
be exchanged between the functions of the physical components of the system, its semantic,
its structure and the way this information is exposed. This dictionary is based on a specific
modelling approach of device and function interface.
• The original name space focused mainly on electrical data for protection, monitoring and
control purpose.
• Complementary name spaces have been created to answer for the needs of new
application domains such as distributed energy resources. The new name spaces still
rely on the same modelling principle, and on the same data structure basis.
• Future activities could lead to further extension of the scope of applications of IEC 61850
such as those needed for Smart Grid considerations. Such modelling also supports non-
standardised extensions (refer to 6.4.3).
See 6.4.
– A language (Part 6, System Configuration Language), i.e. a formal grammar enabling the
association of elements defined above, the syntax used in order to make machine-level
sentences and text. This language, based on the XML meta language, is used to describe
IED capabilities and to express how IED are configured. Further, it is used to describe a full
system, encompassing its electrical topology, the interfaces of each of its components, and
the communication network topology and settings. SCL supports both functional and product
specific naming and allows capabilities and configuration information exchange between
communication and application system engineering tools, in a compatible way from different
manufacturers as well as from manufacturer independent tools.
See 6.6.
– A set of communication services to exchange this information in real time (Parts 7-2, 8 and
9). This set of communication services is defined in a way it can easily evolve, to follow
market technology improvement and to be independent of selected communication medium
and protocol. Abstract definitions of such set of services are defined in Parts 7-2, while
implementations of mappings to specific protocols are defined in Parts 8 and 9.
Handling such communication services enable a component to exchange data with others,
with respect of defined constraints such as response-time, time-tagging, integrity, quality
etc.
See 6.5.
In addition, conformance testing requirements are specified in Part 10.
IEC 61850 (all parts) [1] specifications therefore go much further than a traditional
communica
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