S8 Proceedings-Keynote V2 Public

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PROPRIETARY RIGHTS STATEMENT

This document contains information, which is proprietary to the “EU-DEEP” Consortium. Neither this document nor theinformation contained herein shall be used, duplicated or communicated by any means to any third party, in whole or in

parts, except with prior written consent of the “EU-DEEP” consortium

23rd-26th March 2004

Workshop Proceedings

Keynote paper

Work Package 2 – Seminar 8

Data communication needs andstandards

[FP6 Project: SES6-CT-2003-503516]


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Document Name: Keynote paper – Seminar 8 – WP2 Date: 08/10/2004ID: S8_PRO~2 Security: PublicRevision: V2 Page 2/30

Document Information

Document Name: Keynote paper – Seminar 8 – WP2

ID: S8_Proceedings-Keynote_Siemens_V2.doc

WP : WP2

Task : Task 2.1

Revision: V2

Revision Date: 08/10/2004

Author:

Diffusion list

EU-DEEP – Partners Contact Points

Approvals

Name Company Date Visa

Author C. Schwaegerl Siemens AG

Work Package Leader J. Deuse Tractebel

Coordinator E. Gehain GDF

Document history

Revision Date Modification Author

- 22.3.04 keynote paper for workshop C. Schwaegerl /

B. Buchholz

V0 20.4.04 adapted format, revised edition C. Schwaegerl

V1 20.5.04 comments from VTT included C. Schwaegerl


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General purpose of this document

This document is the keynote paper for Session 8 of the EU-DEEP workshop held in Brussels inMarch 2004.

Contributors :

Christine Schwaegerl, Siemens AG, Germany (writing keynote paper)

Bernd Buchholz, Siemens AG, Germany (writing keynote paper)

Fotis Psomadelis, Anco, Greece (providing ideas for chapter 4)


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Content

DOCUMENT INFORMATION ................................................................................................. 2

GENERAL PURPOSE OF THIS DOCUMENT ............................................................................3

CONTENT ............................................................................................................................ 4

1. SCOPE OF THE REVIEW .............................................................................................. 5

2. STATE OF THE ART OF COMMUNICATION SYSTEMS.................................................... 5

2.1. Impact of DER on communications ....................................................................... 5

2.2. Architecture of communication systems ............................................................... 6

2.2.1 Hierarchical levels ................................................................................................. 6

2.2.2 Communication paths............................................................................................ 6

2.2.3 Supervisory system............................................................................................... 7

2.2.4 Transmission media .............................................................................................. 8

2.3. Communication layer ............................................................................................9

2.4. Subject of communication ..................................................................................10

2.4.1 Operational functions .......................................................................................... 10

2.4.2 System Management functions ............................................................................. 11

2.4.3 The Data ........................................................................................................... 11

2.4.4 Data requirements .............................................................................................. 12

2.4.5 Basic requirements for communications ................................................................. 13

2.5. Examples of communication architectures .........................................................15

2.5.1 Autonomous networks ......................................................................................... 15

2.5.2 Grid-connected DER ............................................................................................ 16

3. STANDARDS .............................................................................................................19

3.1. Current state of communication standards and applications .............................. 19

3.2. IEC 61850...........................................................................................................20

3.2.1 Special features.................................................................................................. 20

3.2.2 Parts of the Standard .......................................................................................... 21

3.2.3 Concept of the standard ...................................................................................... 23

3.2.4 Independence of communication from application ................................................... 23

3.2.5 Data modelling and services................................................................................. 24

3.2.6 GOOSE .............................................................................................................. 26

3.3. Future Standard Extensions of IEC 61850 ..........................................................27

4. AREAS WHERE KNOWLEDGE LACKS, BUT MUST BE GATHERED................................. 27

5. WHAT MUST BE ABANDONED FROM THE PAST IN THIS AREA TO FAVOUR DER? ...... 28

6. WHAT NEEDS TO BE OPERATIONAL 5 YEARS FROM NOW? ....................................... 29

7. ABBREVIATIONS ...................................................................................................... 29

8. LITERATURE .............................................................................................................30


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With these additional tasks the volume of communication is significantly increased. The amountof information to be processed rises, and consequently the costs for communication rise.Suitable communication solutions have to be found.

Up to now in low voltage networks and to certain extend in medium voltage networks mostly nocommunication is realised. There is no supervision of voltage; information about the powerproduced is not available. A communication structure for the data transmission from the control

centre to the DER units does not exist. It is not possible to parameterise or control DER onlineto optimise the grid operation using DER. However, the connection of DER at any level makesthe operation of the distribution network similar to transmission with the constraint of lowautomation, large amount of assets and non controlled generation and consumption.

2.2. Architecture of communication systems

2.2.1 Hierarchical levels

Monitoring is done to gather locally or remotely information of operational devices (i.e.

generation plants, power equipment like switchgear, protection units, etc.). Control functions

allow an operator or an automatic function to operate the equipment. Monitoring and control isdone between devices in different hierarchical levels of supply, the process level (with IntelligentElectronic Devices (IEDs), data logger, sensors or voltage and current transformers), the bay

level (power supply components), the plant level and the management level.

Depending on the scope of the level’s functions, different communication tasks must beaccomplished to enable the data exchange between and within the levels. There are different

communication needs of Energy Management Systems (EMS), Supervisory Control and DataAcquisition (SCADA) Systems, Remote Terminal Units (RTUs), IEDs, Substation Automation,Power Plants, and Energy Services to customer sites. Each level has its own corresponding

communication structure (see Figure 1).

Figure 1: Communication relations and hierarchy levels of power supply system control.

2.2.2 Communication paths

For DER and RES units external and internal communication has to be distinguished ( Figure 2).

External Communication

Depending on the system configuration and the location of the intelligence there iscommunication between the generator’s controller and any on-site controller, between the local


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production volumes tend to have much more effect on the equipment price. Instead of minimizing local intelligence it is better to minimize variety of devices, especially hardware.Centralised decisions allow simpler and cheaper on-site equipment but require extended

communication efforts and make response times higher and increases vulnerability. Meetingdata security requirements without local intelligence is a challenge and causes restrictions onpossible system structures and business models. When you have access management,

encryption and fire wall locally the cost of having other equally data processing intensivefunctions is rather insignificant. Also requirement for easy installation or even ‘Plug and Play’ cannot be met without significant embedded intelligence. Fault tolerance requires some localintelligence, too. On the other way if an optimisation is required, i.e. for scheduling the plants

with an energy management system, only central solutions can find a global optimum;optimisation tasks with local intelligence provide only local optima which could be different fromthe global one. For different business plans, generator types and sizes, there are different levelswhere the efforts, costs and therefore the solutions for monitoring and control are consideredacceptable.

Central communication server

Today, within the DER structures there is mostly one central communication server that is

interconnected to the DER units. Communication can take place with normal PCs or with specialhardware/software configurations. The communication server is usually a PC that is located nearor that is identical to the supervision system. It can be integrated in a substation automationsystem, a control centre or a decentralized energy management system and handles all therequired communication for all applications. Billing, maintenance, process management,telecontrol, etc. is also possible, but can also be established by separate systems. Measuredvalues can be directly imported from the meters or imported from a meter management system

that collects all data, checks the plausibility and corrects possible outages.

The PC solution enables coupling to other applications, like SAP or data bases. Additionalinternet services can be implemented like routing, firewall, access server, web server, internetdomain name service, mail- and news server, SMS - gateway (Short Message System), print

service, terminal and file service, time service, network management and alarming system.

2.2.4 Transmission media

A communication media is needed to reach the actors of the energy sector. Depending on thecommunication requirements and the infrastructure available the communication grid has to be

configured. Decisions on network topology and required data volume have to be derived.Transmission media for local data exchange are transmission cables (electrical: V.24/V.28

(RS232) and V.11 (RS485), optical link, etc.).

For data transmission over a geographical distance different communication media can be useddepending on the time requirements:

Power-line carrier (PLC) transmission

Fibre-optic cables (FO converters)

Telephone network (dedicated lines or dial-up lines)

Radio links (GSM, UMTS, GPRS, messaging, etc), (mobile and satellite)

Power Line Carrier (PLC)

PLC is for the low bit rate transmission in CENELEC - band if there is no telephone line available.Costs are higher than those with conventional modem solutions. Access to the telephone grid in

substations must be available. It is used i.e. as internal telecom network of utilities. Thetechnology provides additional possibilities but is still not mature.

Telephone network


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The conventional line bound kind of data transmission via modem (ISDN, analogue) by copperlines is still the cheapest and fasted way.

Mobile transmission

Radio transmission over wide distances requires a GSM network. There are suitable modemsavailable, but only have a low transmission rate. The costs for using GSM services are still high.

Higher transmission rates are achieved by the new UMTS standard.Future trends

In some regions with suitable infrastructure, i.e. close to centres of population, it is possible touse existing communication media like telephone line (analogue, ISDN) or follow the trend is toreplace them with always-on packet-switched access techniques with TCP/IP communication,

using such media as ADSL / VDSL, GPRS and WLAN, Ethernet.Internet connection is possiblewith mature, cheap but reliable PC solutions. If the site enables this technology it will dominatefurther installations. Inexpensive computers equipped with suitable communication and controlsoftware are able to manage the distributed resources. Moreover, the creation of a separate

communication backbone for exclusive usage with DER systems will be a costly attempt. Sharingthe communication infrastructure with several applications is thus an other trend. For remoteinstallations such as bigger wind farms or wave power plants communication will be more

difficult. A more expensive radio transmission (GSM, UMTS) has to be applied.

2.3. Communication layer

Protocols are set of rules that determine the behaviour of functional units in achieving and

performing communication. All 7 layers of the ISO/OSI reference model for open systems(Physical, Data Link, Network, Transport, Session, Presentation, and Application Layer) have tobe specified. In order to minimize the response times, in some protocols only the layers 1,2, and7 are used, in accordance with the three-layer Enhanced Performance Architecture (EPA)

model. The tasks of these layers are described for the current mainstream protocols fordistribution automation such as the IEC 60870-5 series.

Layer 1: Physical Layer

The physical layer performs the tasks:

Conversion of the serial signal into parallel characters, and vice versa

Signal quality monitoring

Synchronization of bits and telegrams

Adding and stripping of telegram delimiters (start / end characters)

Detection of telegram format errors

Safeguarding of the telegrams against loss and errors by generating and verification

of check codes.

Layer 2: Link Layer (including data flow control)

The link layer controls the transmission procedure. It performs essentially the following tasks: Providing the basic services for symmetrical and asymmetrical transmission (e. g.

SEND / CONFIRM; SEND / NO REPLY)

Adding control fields to telegrams with procedure-specific information

Detection of telegram format errors

Detection of telegrams that are addressed to particular stations.

Layer 7: Application Layer

The application layer performs the identification and the actual processing of the telegraminformation. Furthermore, it constitutes the interface with the application processes. It performsessentially the following tasks:

Coding and decoding of telegrams Information type-specific processing of

- Indications


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- Analogue values

- Transformer taps

- Metered values

- Bit patterns

- Protection data

Buffering of process information in process and transmission images Providing transmission mode control with different priorities for

- Spontaneous (event driven) transmission

- Requested transmission (data transfer on demand)

- Cyclic/periodic transmission (all data or only data that has changed since last

transfer)

Command processing and management for

- Pulse commands

- Setpoints

- Organisational commands

Application and communication are not separated in the IEC 60870-5 series. As communicationtechnologies will change in future but data will not a separation of both is the idea of the newstandard IEC 61850 that is explained because of its importance in detail in chapter 2.3. In this

standard the model is based in a hierarchical decomposition of three levels: information models,information exchange methods as service interface, and the communication profiles like themapping to MMS and TCP/IP Ethernet. The main objective of this layering is to keep theinformation (application) free from any information exchange method and communication

network.

2.4. Subject of communication

Basically the communication system must assist operators, users and other interested parties in

performing their tasks, by provision of services. The system must be flexible to support futurerequirements and future developments. It must be open in the sense that “anyone shall be ableto get information on anything from anywhere”, after being authorised. It shall be adapted toindividual users and services by means of configurations, set-ups, etc. The basic functions of the

system can be grouped in two main categories, supervisory, control and data acquisition(SCADA) functions and system management functions.

2.4.1 Operational functions

The operational functions are needed for the normal daily operation of the DER. In thesefunctions a HMI, either local or remote is included. The operational functions are used to presentprocess or system information to an operator or to provide him with the control. These include:

Access security management – access to operational functions has to be controlled by a set

of rules. Access control will allow restricting an authenticated client to a pre-determined setof services and objects.

Supervision – local or remote monitoring of the status and changes of states in operational

devices belonging to the generator itself or to the interconnection subsystem (network part).

Control – control functions allow an operator or an automatic function to operate the

equipment (e.g. switchgear or transformer, a protection, etc). Control is subjected to

miscellaneous filters that check that no damage will be caused by its performing.

Parameter Changes (online) – in addition to single parameters, an application may have

several possible pre-defined parameter sets (but only one active set).

Alarm Management – an alarm is generated when a data of the system goes out from the

limits specified by the operator. In other words, there is a need for attracting attention tosome abnormal state. Alarm management functions allow an operator to visualise,

acknowledge and clear alarms.


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Event and Log Management – functions for continuous scanning of devices searching for

alarms, operator control actions and changes in state, and for recording eventschronologically with date and time information.

Retrieval of configuration data and settings – functions to check parameter setting should

include services to retrieve all parameters (names, values and units for all set points) or toretrieve only those that differ from the default values.

Fault Record Retrieval for displaying or analysing purposes.

Measuring and metering.

2.4.2 System Management functions

System management functions include system support functions and system configuration and

maintenance functions. System support functions are used to manage the system itself (e.g.network management, time synchronisation, self-checking of communication equipment, etc.).The functions support the total system and have no impact on the process. Systemconfiguration or maintenance functions are used to set-up or evolve (maintain) the system. The

system configuration and maintenance functions include the setting and changing of configuration data and the retrieval of configuration information from the system. The most

important examples of System Management functions are:

System Support:

Network Management functions needed to configure and maintain the communicationnetwork. The basic task is the identification of communication objects/devices.

Time Synchronisation of devices within a communication system.

Self-checking detects if an object or device is fully, partially or not operational at all.

System Configuration and Maintenance:

Software Management includes version control, download, activation and retrieval of

software. Configuration Management is used to download, activate and retrieve configuration data.

Operative mode control allows an authorised operator to start and stop functions orobjects within the system, including manual activation or reset of subsystems.

Setting function allows an operator to read and to change offline one or more parametersaffecting the behaviour of the object/device.

Test Mode gives the possibility to check a function avoiding impact on the process

(blocking the process outputs).

System Security Management allows the control and supervision of the security system

against unauthorised access.

2.4.3 The Data

PICOM concept

To describe the data being exchanged the PICOM (Piece of Information for COMmunication)concept introduced by CIGRE WG34.03 can be used. Components or attributes of a PICOM are:

DATA meaning the content of the information and its identification as needed by the

functions (semantic) (established in IEC 61850-5)

TYPE describing the structure of the data, i.e. if it’s an analogue or binary value, if it’s a

single value or a set of data, etc.

PERFORMANCE meaning the permissible transmission time (defined by performance class),

the data integrity and the method or cause of transmission (periodic, event driven,requested ..)

LOGICAL CONNECTION containing the logical source (sending logical node) and the logicalsink (destination or receiving logical node) (A logical node (LN) is the smallest part of afunction that exchanges data).


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There are three types of attributes defined by their purpose.

PICOM attributes to be covered by any message (transmission)

Value: value of the information itself if applicable

Name: for identification of the data

Source: the logical node where the signal comes from

Sink : the logical node where the signal goes Time tag: absolute time to identify the age of the data if applicable

Priority of trans.: to be used for input queues or for relaying of messages

Time requirement : cycle time or overall transfer time to check the validity with help of the

time tag

PICOM attributes to be covered at configuration time only

Value for transmission (see above): test or default value if applicable

Attributes for transmission (see above)

Accuracy: classes or values Tag information: if time tagged or not (most data will be time tagged for validation)

Type: analogue, binary, file, etc.

Kind: alarm, event, status, command, etc.

Importance: high, normal, low

Data integrity: the importance of the transmitted information for checks and

retransmissions

PICOM attributes to be used for data flow calculation only

Value for transmission/configuration (see above): test or default value if applicable

Attributes for transmission/configuration (see above)

Format: value type of the signal (I, UI, R, B, BS, BCD, etc.) Length: the length (i bit, j byte, k word)

State of operation: reference to scenarios

2.4.4 Data requirements

Each specific kind of data has specific requirements on the communication system. Alarms, forexample, need to reach the remote control centre much faster than events and need therefore ahigher transmission priority. Protection data have to be transmitted and processed immediately

within milliseconds, the time span for monitoring and control data transmission is seconds tominutes, occasionally hours.

The different kinds of data can be grouped and named real-time/on-line data,

historical/retrospective data or forecasts/schedules.

Generally there are the following requirements:

Analogue signals. All analogue process values shall be accessible in standard SI-units.Analogue values "at the source" shall be available as real-time on-line instant data, as well astime averaged values (with different average periods). The values may be used for display onoperator HMIs as well as for storage (databases). Updating of analogue on-line values maybe selectable down to an interval of 1 second. All averaged values must be stored in the plantcontroller for retransmission on demand. Some process values are not required as

measurements directly at the source. The values shall be accessible as processed data in acondensed and analysed format.All the analogue measured values should have readable properties like signal quality and

scanning rate. This information does not have to be included in every data transfer. Theaveraging time and the measuring and averaging method should be documented for all data.It should be possible to time stamp all data. Time-stamped data shall be stamped with thelast updated date + time (UTC time).


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Commands. Setting values that have impact on the behaviour of the function of a devicerequire special attention to when (e.g. immediate or deferred) and how (e.g. select beforeoperate) set the values. A handshake procedure is required for all commands that start or

stop a mechanical component, influence the status or operation mode, or change thesoftware.

Alarms. Operational alarms may be transmitted immediately after a triggering. A triggering is

typically initiated at any event that results in an automatic stop of the generator, any eventthat causes an emergency stop or any other alarm-causing event. Alarms should include thetime of the occurrence. Alarms may optionally be stored in a log in the device controller(server).

Events. Operational events shall be stored in an event log in the plant device for transmissionon demand. Log entries shall be time-stamped.

Counters. Counters shall be understood as values accumulated in the process such as hourcounters, production counters, counters for operational modes, timers, counts of transitions

on relays, motors, pumps, etc. The values shall be stored with a corresponding date and timestamp. Updating counters may be selectable down to an interval of 1 second. All values shallbe stored in the plant device for transmission on demand. It should be possible to reset all

the timers and the “reset date” shall be stored as a separate item.

Grouped data. Data values can be grouped based on logical relationships as chronologicallyordered data, as text, etc. Some of the different ways to put together sets of data are:

Data structures (typically include several kinds of related data, for example the data value,

the time stamp, the quality information or the description of an object).

Time series data (time based data values for a specific object attribute, for example

sampled data, metering data, etc.)

Short text messages (text messages exchanged between the generator and the control

centre)

Files (files for upload/download of programs, etc.)

2.4.5 Basic requirements for communications

The communication shall be based on open and widely accepted methods with a high degree of interface possibilities. Decisions on network topology and required data volume have to bederived to enable a reliable, fault-tolerant, powerful und cheap data transmission; but it shallnot be used for the safe and secure internal operation of the unit. Faults in the communication

system shall not cause malfunction of the distributed generator.

For this basic requirements exist:

Security

Remote monitoring and operation of devices requires strict security measures for several

reasons: protect the data from being stolen, corrupted, and intentionally falsified; protect thedevice from unauthorised use or to preserve the privacy of monitoring data. Security servicesmust prevent loss of information and detect false information. To enforce these security

requirements the following functionalities are needed:

• Authentication. Server authentication shall ensure the client that he is truly operating onthe intended site. Client authentication ensures that an authorised client/operator isoperating the equipment. Each user might have different rights to operate functions

and/or to see data on different levels in the object hierarchy.

• Data Integrity . Non-corruption of transferred data is necessary, i.e. the communication

system must be able to deliver data from its origin to its destination with an acceptableresidual error rate. This prevents both malicious and erroneous operation.

• Data confidentiality . Transferred data items might need to be encrypted to prevent both

malicious and erroneous operation, as well as spying.


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Communication via internet should use https (Secure http) as a transmission protocol. VPN(Virtual Private Network), SSL-encoding with client certificates or firewalls are otheralternatives.

Performance

The hardware has to fit with the corresponding communication software. It has to handle the

expected data volume, data throughput and the number of connections. The performance of the communication system is limited by the factors:

• data base access

• data preparation to send/receive

• transmission capacity of data line (linearly depending on data volume)

• program cycle time

The time of response of most operational functions and, therefore, of the relatedcommunication does not need to be much faster than one second. System managementfunctions, which shall be available for the operators and control systems, are of low time

critical nature. Delay in execution of these functions however should not be more than 2seconds.

The use of web technologies can not guarantee the required reaction times for real-time

transmission. All functions regarding safety of people or of the generator like online control orprotection of units supervised have to be enabled by control centre solutions existing or mustbe self-contained in the main controller and will trip automatically.

Regarding optimisation of the operational functions, the communication system has a major

role. The time critical functions include both control and supervision functions. Set points forpower control and start and stop commands are the most critical functions. Periodic on-lineoperational data is essential for the optimisation of the operation. Finally, the operator needs

to know the status of the communication system to be able to rely on the presented data.

The time critical functions shall use short messages with high priority. Delays can occur dueto transmission errors, low capacity or low bandwidth of the transport lines, or due tonetwork faults. It is essential for the design of the communication system to select methods

that minimise such kind of problems. The critical functions must be based on fast and reliabletransmission of a number of selected data types. The overall transfer time for services in timecritical functions shall not be more than 0.5 seconds.

Reliability

Reliability is essential in the sense that data can be retransmitted, reconstructed orreprocessed if lost or inaccessible. Data may be inaccessible because of faults in the maincontroller, faults in data transport or faults in data processing units. It must be possible to

restore information, including the sequence of events. Local procedures for recovery mayinclude redundancy of selected functions and backup of data.

Redundancy in the communication channels will be optional depending on the criticality of thecommunication needs. In that case, automatic procedures for detection of communication

faults and for managing redundancy of the system components shall be established. Thephysical transport lines should be redundant to a certain degree.

Data integrity

Compatibility to other manufacturers must be accomplished.

In case of data transmission errors due to electromagnetic interference, ground potentialdifferences, ageing of components and other causes of noise or interference, an effectiveprotection of the communication ensures that

• bit and telegram errors are detected

• loss of information is detected• no unintended information is generated

• no disturbance or interruption of related information can occur.


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In case of a detected transmission error, i.e. like not completely received data packages, anew transmission is initiated. The data not or not completely received can be again requestedby the communication partner. All errors are documented in a communication protocol.

Transmission data have to be stored in databases that no data loss occurs in case of aconnection failure.

Monitoring of operation

Self-Monitoring of the software ensures the correct function and has to raise an indication incase of any malfunctions. Additionally the availability of the communication hardware has tobe checked. A complete system request of all data transmission devices should regularlyhappen, i.e. every 60 seconds. The results of this cyclic supervision of the operation status of

the transmission devices are stored as status information.

Connection data like time, date, partner identification, initialization, and connection time andstatus information are stored in a communication protocol. This can be a text-based log-fileor a database.

General

The external communication hardware should be operated by grid voltage. There must not be

any interference with other components.

2.5. Examples of communication architectures

The architecture of communication systems should be as open as possible to promote plug andplay and interoperability to the fullest extent possible. The required performance has to be metconsidering requested data throughput, fault tolerance and reliability.

2.5.1 Autonomous networks

Autonomous microgrids are required to install a supply in developing countries or in remote

areas of industrialised countries. Those microgrids are normally small, operating independentlyof a national or international grid. At least one distributed generator forms the network anddetermines voltage and frequency. The control structure of an autonomous decentralised powersystem is similar to the control hierarchy of the electric power system (EPS), the same controllevels are defined here.

Power supply components communicate in decentralised and autonomous systems betweeneach other and with an on-site (local) controller, which belongs to the unit control level. The on-site controller performs the functions of local resource scheduling, operation management, and

monitoring. The transmission of switching commands and acquisition of operational data belongto the main communication tasks. Among them are messages, operating states, networkmeasurements (voltage, frequency, real and reactive power) and values relevant for thedevice’s operation (e.g. storage volume, solar radiation, and wind speed). For this purpose, a

field bus can be applied if the distance is not too long (< 1km).

The established standard buses are particularly suited for the integration of power supply inexisting automation systems. The unit control level is often the highest hierarchy level in small

autonomous systems and performs the functions of central management. If a supervisorysystem exists, then the on-site controller establishes a communication link to the centralmanagement.

The management control level, to which the central management is assigned, performs mainlyplanning and governing tasks. The central management can administrate the operation of several autonomous systems. Usually switching is not performed by the central management,but instead of this, the respective on-site controller is prompted to do it by settingcorresponding parameters. Due to the distances involved, the communication is performed over

signal cables, or radio link system. Figure 3 shows an example of communication infrastructurefor the control and monitoring of decentralised power supply systems.


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Figure 3: Possible communication infrastructure for monitoring and control of a distributed power supply system.

2.5.2 Grid-connected DER

If distributed generators supply an interconnected network, voltage and frequency are

determined by the network. The generators supply either regulated (network supporting mode)or unregulated power into the network. For the purpose of network stability and quality of supply, particularly larger distributed suppliers (i.e. wind parks) should be integrated into the

voltage and frequency regulation of the network. Furthermore, it makes sense to equip manyspatially distributed small generators with technical intelligence, and to monitor and operate

them remotely from a common control centre. To handle a lot of DER units in future, theyshould be easily connectable to the network without individual solutions for every unit.

Standardisation is required.

At present distributed generators supplying the interconnected network still have nocommunication to a higher-level control centre. But at the same time there are a number of indications stressing the need for remote monitoring and control. As already mentioned the

main need is the integration in network operation to enable a reliable operation and to allowenergy management. Further on, private operators want to acquire the energy production of their units and to have it displayed (e.g. on a PC monitor). To do this, many equipment

manufacturers offer their own communication solutions with proprietary protocols, to exchangedata over separately installed lines or power lines. Apart from the data request, the providedsoftware allows to some extent the adjustment of important parameters. If there is an existing

automation system available, a communication pathway can be established over the local bussystem. With few exceptions, it is not feasible at the moment, because of a missingcommunication interface.

Another example can be a power supplier, who sells green electricity, and who can conclude

supply contracts with private operators of PV installations and equip the associated installationswith remote control and monitoring systems. These intelligent system components can then beoperated by a joint control centre. For the operation of this power park, performance andoperational data must be communicated to the control centre. Furthermore, a communication

pathway must be installed to enable control commands. Due to the wide spread structure of devices, a field bus can not be applied here.

For larger distributed installations connected directly to the medium voltage network, the

associated switchgear of the network injection point operates already according to conventionalnetwork control. In addition to the data required by power supply company, a wind parkoperator has an interest in acquiring and evaluating the operational data of individual wind


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turbines for yield control, remote diagnostics and early detection of failures. Data is normallyscanned once a day. As a communication system, dialup telephone line is used, which connectsthe modems of turbine and operator.

Decentralised Energy Management System and Virtual Power Plants

An intelligent decentralized energy management system (DEMS) that predicts loads and

generation and schedules the units, enables to optimise the operation of the units.Communication between the units under control and the management system is required.Measured values, metered values, setpoints and status information have to be transmittedbetween the units. Combining monitoring and control of several DER units leads to “virtualpower plants” that show similar behaviour like conventional central generation plants

The communication realised in different projects operates using switched and dedicated lineswith transmission media PLC, fibro optic, telecom network and radio transmission, to which theindividual elements of generation, storage and load are connected via the generation and loadmanagement system and via automation units. Depending on cost-benefit analysis, larger units

are controlled using two-way communication, whereas in some cases, distributed smaller unitsare provided only with one-way communication. The effect of the control command is thentaken into account by means of estimation. The performance of elements without control

capabilities may be predicted. Specified values for energy import, supply and contracts are inputfrom outside to the energy management system.

Daily profiles can be transmitted via switched lines, while single values with commands or

metered values in a 1 min cycle require a dedicated line (Figure 4). Costs for operation andinstallation of the communication must not be higher than the savings and other operationalbenefits by an optimized management of the units. It has to be decided which units will providea significant weight and will have to be connected to the communication network.

SLSLG

BiomassPower Plant

GG

BiomassPower Plant

DL

G

Blocktype

Power Heat Cogen.

PV-Plant

with Battery Storage

PV-Plant

with Battery Storage

Fuel Cell

Billing

Switched LineProfiles

Large

Virtual

Wind Energy Unit

...

Large

Virtual

Wind Energy Unit

...

Decentralized

Energy M anagmt.System

Purchase Optimization

Contract M anagement

Distributed

small FC

Concentrator

Mod.

ZMod.

Z

Mod.

Z

Mod.

Z Mod.

Z

Z

Mod.Mod.

Z

Mod.

ZMod.

Z

Mod.

Z

Mod.

Z

Mod.

Z

Mod.

Z

Mod.

Z Mod.

Z

Mod.

Z

Z

Mod.

Z

Mod.

Remote Metering

ConcentratedLoads

ConcentratedLoads

Power SystemControl

Communication

Grid

CommunicationCommunication

GridGrid

Weather

Forecast Service

Power Exchange

SL

SL

SLSLSL

SLSL

SLSL

SLSL

SLSL

DL

DL

DL

Dedicated LineIndiv.Values

Distrib.

Loads

Figure 4: Example of communication grid for DEMS.

Specified values for energy import, market impacts, electricity prices and supply contracts areinput to the energy management system from outside. In a liberalised market contractors,aggregators and traders can fulfil supply contracts operating these virtual power plants.

A huge number of very small decentralised generators like PV plants can be integrated in the

energy management systems with data concentrators that reduce those objects to a singleelement with a higher power that is considered in the management system. Groups with similarstructure information like model type, building type, operator identification, kind of communication or grid location are handled like a bigger unit of corresponding type. For anautomated operation connect or disconnect signals with structure information and measuredtime series of the small generators have to be communicated. The data concentrator thenperforms the aggregation of the generator data and transmits it to the DEMS. DER units are

management without individual solutions for every unit.


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In a simpler variant standardised communication protocols could enable real-time costs of powerto be translated into price signals that flow through the entire power system, thus assisting inthe creation of more readily identifiable revenue streams for distributed energy systems to

capture.

With an increased share of DER, a harmonization of the interfaces is required for a reliable andcost-effective communication while up to now mainly different proprietary solutions are applied.


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3. Standards

3.1. Current state of communication standards and

applications

The market is today characterised by vendor specific and hardware oriented solutions. As a

consequence there is a large number of protocols for communication. Devices from differentmanufacturers and even devices from different generations from the same manufacturer cannotcommunicate with each other or only with disproportionate expenditures for development,

engineering and maintenance, i.e. using a gateway to carry out the protocol conversion. Due tothe increasing number of modern information systems, the increase of data and the fact thatthe innovation cycles of hard- and software are constantly becoming shorter the number of incompatible protocols is expected to rise. Costs for data integration and maintenance areexploding. Vendors of power systems have limited resources to implement and apply hundredsof proprietary communication systems. A reduction of variety in a relatively small market isextremely beneficial for both vendors and users. Thus standardisation is the key for the

advancement of the connectivity and interoperability of systems. Through standardisation bothusers and suppliers arrive at economically suitable, reliable solutions.

Today in Europe the communication is done by different media and protocols. Figure 5 showsthe variety of current protocols like the IEC 60870-5 series and DNP 3.0 or 5 or IEC 60870-6

TASE.2 that are applicable between substations, IEDs and control centres. The cloud in thefigures represents every kind of communication connection or association like point-to-point orrouter network, etc. A detailed description of all standards and applications is provided in theannex.

There is a mix of terms all dealing with communication. Thus data exchange is realised via OPC(OLE for Process Control), COM/DCOM/ActiveX (Component Object Model, Distributed COM),XML (eXtensible Mark-up Language), ODBC (Microsoft® Open Database Connectivity), JMS

(Java Messaging System) or web services, all covering different layers in the ISO/OSI referencemodel.

IEC 60870-5-101, -104,

IEC 60870-6 (TASE.2),

IEEE P1525,

ELCOM 90, DNP3 I E C

6 0 8 7

0 - 5 - 1 0 2

Control Centre 1

Metering

Billing

IEC 60870-6 (TASE.2),

ELCOM 90, DNP3,

IEC 60870-5-101, -104

Substation

Power

Plant

Market

ParticipantEC, EDI ISO 9735

Server

IEC 61970 EMS

IEC 61968 DMS

IEC 60870-5-101, -104,

IEC 60870-6 (TASE.2),

ELCOM 90, DNP3

Substation

I E C 6 1 1 0 7

I E C 6 2 0 5

6

IEC 60870-5-101,

IEC 60870-5-104,

IEEE P1525, DNP3

PU

Control

Centre 2

IEC 62195

TR

(IEC 60834, IEEE 1565)

Pole-Top

I EC 618

5 0

I E E E P

15 25

I EC 6 08

7 0 -5

D N P 3

PU

IEC 62210

Figure 5: Current communication standards outside substations.

Some of the communication interfaces and standards are only used in certain parts of a DERsystem, while others may be used in many different parts. Generally, protocols that are used in

hardware interconnection are impossible or not suitable to use in higher-level communication(interfaces between software systems etc), while other protocols offer interfaces between sites


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and supervisory systems and to external systems, but are not used when interfacing directly tothe hardware.

A new global standard, the IEC 61850, was required to improve substation device data

integration and to enable interoperability. The standard provides common data models, servicemodels, protocols, communication physiques, engineering data exchanges and conformancetests.

3.2. IEC 61850

3.2.1 Special features

Since 1995, about 60 experts from 14 countries have been tackling these issues by IEC TC 57Working Groups 10, 11, and 12. They responded to all these challenges and created a single,

global and future-proof standard for substation communications, the IEC 61850 “communicationnetworks and systems in substations”(see also www.61850.com). Very high objectives were setfor the standard:

To cover all the information in substations, down to small digital units for driving the

processes, which thus include digital transducers or sensors, and actuators located close tothe processes.

Openness for extension of the information to be communicated in the future according to

the principle: All that are known are incorporated, and any future applications can be filledin according to the set rules.

Openness for future high-efficiency data transfer.

To promote the idea of interoperability in systems, which surpasses the specifications of data-coding and communication services like IEC 60870-5. The requirements onengineering and on the sustainability of products within the service life of thecorresponding system are included in the standard.

IEC 61850 defines a comprehensive communication standard for substations. This includes a

consistent data and service model at all communication level. Operational information(indications, commands, and measured values) are coded and transmitted in the same way on apossible process bus and station bus. The use of the same application interfaces and protocolstacks at the station bus and process bus levels ensures that "gateway-free" communication

links are established within the station.

The objective of IEC 61850 is to design a communication system that provides interoperabilitybetween the functions to be performed in a substation, but residing in equipment (physical

devices) from different suppliers, meeting the same functional and operational requirements.Functional requirements have to be met independent of substation size and operationalconditions.

IEC 61850 differs from most previous utility protocols in its use of object models of device

functions and device components. There are logical devices composed of logical nodes and dataobjects. These models define common data formats, identifiers, and controls, e.g., forsubstation and feeder devices such as measurement unit, switches, voltage regulators, andprotection relays. The models specify standardized behaviour for the most common device

functions, and allow for significant vendor specialization. These models support multi-vendorinteroperability and ease of integration.

With the new standard only one protocol for all needs is required (Figure 6). All substation

automation functions comprising monitoring, control and protection are fully supported. Thearchitecture is future proof and facilitates future extensions, therefore it safeguardsinvestments. Modelled functions (typicals) are reusable. That simplifies definition, configuration,naming and maintenance of data and their integration to higher levels and saves cost forengineering. The standard defines the availability requirements, environmental conditions and

the auxiliary services of the system. Further on it specifies the engineering process and itssupporting tools, system life cycle and the quality assurance requirements. It provides

engineering and maintenance support by means of the substation configuration language based


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on XML, i.e. documentation is included. A vendor-independent engineering-data exchangebecomes possible.

Power PlantCHP

G

PV Plant

Market

Participant

ControlCentre

IEC 61850

Pole-Top

I E C 61

8 5 0

I E C

6 1 8 5

0

IEC 618

50

I E C

6 1 8 5

0

( I E C 6 1 4 0 0 - 2 5 )

Substation 1

IEC 61850

CT

VT

Substation 2

Metering

Billing

IEC 61850

CT

VT

EnergyManagement

System

influencable loads/DSM solutions

I E C 6 1 8 5 0

I E C 6 1 8 5 0

I E C 6 1 8 5 0

communication

grid

I E C 6 1 8 5 0

I E C 6 1 8 5 0

I E C

6 1 8 5 0

Wind Plant

Power PlantCHP

G

PV Plant

Market

Participant

ControlCentre

IEC 61850

Pole-Top

I E C 61

8 5 0

I E C

6 1 8 5

0

IEC 618

50

I E C

6 1 8 5

0

( I E C 6 1 4 0 0 - 2 5 )

Substation 1

IEC 61850

CT

VT

IEC 61850

CT

VT

Substation 2

Metering

Billing

Substation 2

Metering

Billing

IEC 61850

CT

VT

EnergyManagement

System

influencable loads/DSM solutions

I E C 6 1 8 5 0

I E C 6 1 8 5 0

I E C 6 1 8 5 0

communication

grid

I E C 6 1 8 5 0

I E C 6 1 8 5 0

I E C

6 1 8 5 0

Wind Plant

Figure 6: Trend of future communication standards.

3.2.2 Parts of the Standard

To accomplish interoperability common standardised data model

common standardised service model common standardised protocol common standardised communication physique common standardised engineering data exchange

common standardised conformance test

have to be defined within 10 parts of EC 61850 (Table 1).

Table 1. Parts of the standard series IEC 61850

Parts of IEC 61850

Title

IEC 61850-1 Introduction and Overview

IEC 61850-2 Glossary

IEC 61850-3 General requirements

IEC 61850-4 System and project management

IEC 61850-5 Communication requirements for functions and device models

IEC 61850-6 Configuration description language for communication in a substation related to IEDs

IEC 61850-7-1 Basic communication structure for substations and feeder equipment – Principles and models

IEC 61850-7-2 Basic communication structure for substations and feeder equipment – Abstract communicationservice interface (ACSI)

IEC 61850-7-3 Basic communication structure for substations and feeder equipment – Common data classes

IEC 61850-7-4 Basic communication structure for substations and feeder equipment – Compatible logical nodeclasses and data classes

IEC 61850-8-1 Specific communication service mapping (SCSM) – Mappings to MMS (ISO/IEC 9506) and toISO/IEC 8802-3

IEC 61850-9-1 Specific communication service mapping (SCSM) –Sampled values over serial unidirectionalmultidrop point to point link


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Parts of IEC 61850

Title

IEC 61850-9-2 Specific communication service mapping (SCSM) – Sampled values over ISO/IEC 8802-3

IEC 61850-10 Conformance testing

IEC 61850 does not automatically ensure interoperability. To reach interoperability a well-doneengineering is necessary. Relevant for this are the parts IEC 61850-4 System and projectmanagement (Clause Engineering Requirements) and IEC 61850-6 Configuration description

language for communication.

The Abstract communication service interface (ACSI, 61850-7-2) provides a common set of communication services for data access, reporting, logging, control applications and related

support. The information exchange methods and services shall be as specified in the profile of the ACSI services of the IEC 61850-7-2. To become concrete the abstract ACSI services aremapped to existing communication application layer standards by a Specific CommunicationService Mapping (SCSM). Ethernet/MMS (Manufacturing Message Specification)(ISO 9506) with

100 MBit optical fibre link is the service specification at the moment applied in 61850-8-1.Generally the standard is open for other transmission media like PLC or radio transmission as

long as uniform services are defined.IEC 61850-9-1 specifies the specific communication service mappings for the communicationbetween bay and process level and specially it specifies a mapping on a serial unidirectionalmultidrop point-to-point link. The scope of this part is for the use in substations as a linkbetween electronic current (ECT) or voltage transducers (EVT) and bay devices such asprotection, meter or bay controller. The intended use of this mapping is for low cost applicationswith simple protection schemes, and for retrofitting in existing substations only. If higherrequirements on sampling rate, further sampled measured value data sets in addition to theuniversal data set, inter-bay communication and synchronisation apply, these will be covered by

IEC 61850-9-2.

IEC 61850-9-1 applies to newly manufactured electronic current and voltage transducers (ECTand EVT) having a digital output, for use with electrical measuring instruments and electrical

protective devices. For digital output, IEC 61850-9-1 takes into account a point-to-pointconnection from the electrical transducer to electrical measuring instruments and electricaldevices. This mapping allows interoperability between devices from different manufacturers. IEC61850-9-1 does not specify individual implementations or products, nor does it constrain the

implementation of entities and interfaces within a computer system. IEC 61850-9-1 specifies theexternally visible functionality of implementations together with conformance requirements forsuch functionality.

IEC 61850-9-2 defines the specific communication service mapping for the transmission of sampled values according to the abstract specification in IEC 61850-7-2. The mapping is that of the abstract model on a mixed stack using direct access to an ISO/IEC 8802-3 link for thetransmission of the samples in combination with IEC 61850-8-1. The purpose of this SCSM

definition is to supplement IEC 61850-9-1 to include the complete mapping of the sampledvalue model. This part of IEC 61850 applies to electronic current and voltage transformers (ECTand EVT) having a digital output, merging units, and intelligent electronic devices e.g. protectionunits, bay controllers and meters.

Conformance claims and the establishment of their validity are important parts of theacceptance of systems and equipment. IEC 61850-10 specifies conformance testing methods forconformance testing of devices of substation automation systems and in addition gives

guidelines for setting up test environments and system testing, thus supporting interoperabilityof devices and systems.

The standard IEC 61850 defines no communication network architecture. It provides solutionsfor different communication requirements independent of a station or process bus and defines

Ethernet for all levels.


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3.2.3 Concept of the standard

The model is based in a hierarchical decomposition of three levels (Figure 7): informationmodels, information exchange methods as service interface, and the communication profiles likethe mapping to MMS and TCP/IP Ethernet. The main objective of this layering is to keep theinformation (application) free from any information exchange method and communication

network. This separation of data and communication technologies is the idea behind IEC 61850.Data did not change and will not change but the latter will.

The information models can be easily extended according to specific and flexible rules asrequired by another application domains, for example, for additional functions within substationsor for other application domains such as wind power plants.. Communication stacks may beexchanged following the state of the art in communication technology.

Application(e.g. Protection)

Service(e.g. Control, Report)

Communication(Protocol)

Data ModelData Model

Services, RulesServices, Rules

MappingMapping

IEC 61850:

Data ModelData Model

Services, RulesServices, Rules

MappingMapping

IEC 61850:Separation of:

Data M odelData M odel

Services, RulesServices, RulesServices, RulesServices, Rules

Function

Protection

Communi-

cation Module

MappingMappingMapping

Ethernet MappingMapping

Mapping

Ethernet

Example:

Protection

Device

IEC 61850:

Mapping

XYZ

XYZ

Figure 7a, b: Separation of data and communication technology

3.2.4 Independence of communication from application

To cope with fast innovation of communication technology the standard specifies a set of

abstract services and objects which may allow applications to be written in a manner which isindependent from a specific protocol. This abstraction allows both vendors and utilities tomaintain application functionality and to optimise this functionality when appropriate. A set of abstract services is standardised to be used between applications and ‘application objects’allowing for compatible exchange of information among components of a substation automationsystem. This Abstract Communication Service Interface (ACSI) is a virtual interface to anIntelligent Electronic Device (IED) providing abstract communication services, for exampleconnection, variable access, unsolicited data transfer, device control and file transfer services,

independent of the actual communication stack and profiles used. The concrete implementationof the device internal interface to the ACSI services is a local issue and is beyond the scope of the standard.

However, these abstract services/objects must be instantiated through the use of concreteapplication protocols and communication profiles. The specific syntax (format) and especially theencoding of the messages that carry the service parameters of a service and how these arepassed through a network are defined in a Specific Communication Service Mapping (SCSM)

(Figure 8). The SCSM is a standardised procedure which provides the concrete mapping of ACSIservices and objects onto a particular protocol stack/communication profile.


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Application

ACSI

SCSM nSCSM 2SCSM 1

Physical, Data Link, Network, Transport, Session, Presentation Layer 1- 6

communication stacks

Abstract Interface

Specific

Mapping

Application layer 7

Application

ACSI

SCSM nSCSM 2SCSM 1

Physical, Data Link, Network, Transport, Session, Presentation Layer 1- 6

communication stacks

Abstract Interface

Specific

Mapping

Application layer 7

Figure 8: Basic Reference Model

The standard provides an assortment of mappings in the parts 8-x and 9-x of the series whichcan be used for communication within the substation; the selection of an appropriate mappingdepends on the functional and performance requirements. To facilitate interoperability it isintended to have a minimum number of standardized mappings. One SCSM is the mapping of

the services to MMS and other provisions like TCP/IP and Ethernet.

The concept of the SCSM has been introduced to be independent from communication stacksincluding application protocols.

The SCSM maps the abstract communication services, objects and parameters to the specificapplication layers which provide the concrete coding. Depending on the technology of thecommunication network, these mappings may have different complexities, and some ACSIservices may not be supported directly in all mappings, but equivalent services shall be

provided.

3.2.5 Data modelling and services

The modelling methods of the IEC 81650 series define the information and informationexchange in a way that it is independent of a concrete implementation by using abstract

models. With the concept of virtualisation only those aspects of a real device that are requiredto provide interoperability of devices are defined.

The information model comprises:

Logical node (LN) classes,

Data classes, and

Common data classes.

A logical node (LN) is the smallest part of a function that exchanges data. A LN is an object

defined by its data and methods (concept described in Figure 9). Logical nodes can onlyinteroperate with each other if they are able to interpret and to process the data received(syntax and semantics) and the communication services used. Thus it is necessary tostandardise data objects assigned to logical nodes and their identification within the logicalnodes. The content of the data exchanged between the LNs are the PiCOMs. Common dataclasses are used by the one or the other logical node.


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Function

(e.g. Protection)

Input

Data

Output

Data

Configuration

Figure 9: Concept of a logical node.

The functions still remain vendor specific while the data exchange – the interfaces - becomesstandardised. With the idea of logical nodes there is a data exchange between functions and not

between devices that can cover different functions (Figure 10).

The server represents the external visible behaviour of a device. All other ACSI models are partof this server. A server communicates with a client and sends information to peer devices. The

logical device contains the information produced and consumed by a domain-specific applicationfunction as defined as logical nodes.

Server (network address)

Logical Device(BayA)

LN2(MMXU)

A

PhA

LN1(XCBR)

Pos

PhBStV q

Server

Logical Device

(1 to n)

Logical Node(1 to n)

Data

(1 to n)

Attrib ute

(1 to n)

Figure 10: Hierarchy of the data model.

Within IEC 61850 there are about 90 different logical nodes (Figure 11) covering the mostcommon applications of substations and feeder equipment and more than 350 data classes

(Figure 12). Data provide means to specify typed information.

Group Indicator Logical node groups

A Automatic Control

C Super vi sor y contr ol

G Generic Function References

I I nt erfa ci ng a nd Archi vi ng

L System Logic al Nodes

M Met ering a nd Me asu reme nt

P Pr otect ion functi ons

R Protection related functions

S Sensors

T I ns trume nt Trans former

X Switchgear

Y Power Tra nsformer

Z Fur ther (power system)equipment

MMXU Measuring (Measurand unit)

M M TR M et eri ng

MSQI Sequence and Imbalance

MHAI Harmonics and Inter-harmonics

MDIF Differential Measurements

XCBR Circuit Breaker

XSWI Circuit Switch

PSCH Protection SchemePTEF Transient Earth Fault

PZSU Zero speed or underspeed

PDIS Distance protection

…more

SIMG Insulation medium meas unit

SARC M onitoring and diagnostics

for arcs

SPDC M onitoring and diagnostics

for partial discharge

Figure 11: Example of logical nodes.


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355

66M easurands

14Metered values

36Controllable Data

85Status information

11Physical device information

130Settings

13System information

Number Data Classes

355

66M easurands

14Metered values

36Controllable Data

85Status information

11Physical device information

130Settings

13System information

Number Data ClassesA - Phase to ground amperes for Phases 1, 2, and 3

Amps - Current of a non three phase circuit

Ang - Angle between phase voltage and current

AnIn - Analogue Input used for generic I/O

ChAnVal - Array of analogue channel numbers and

actual values at a certain time (time tag)

CircA - Measured circulating current in a transformer

paralleling application

CtlV - Voltage on secondary of transformer as used for

voltage control.Den - Density of gas or other insulating Medium

DQ0Seq - Direct, quadrature, and zero axis quantity

ECC - This is the measured current through a Petersen

Coil in neutral compensated networks.

FDkm - The distance to a fault in kilometres

FDOhm - The distance to a fault in Ohms

HaRmsA - Current Harmonic RMS (un-normalized

THD) for A, B, C, N

HaRmsV - Voltage Harmonic RMS (un-normalized

THD) for AB, AN, BC, BN, CA, CN, NG

HaTdA - Current Total Harmonic Distortion

HaTdV - Voltage Total Harmonic Distortion

More…..

Figure 12: Example of data classes.

A modelling example in (Figure 13) shows logical nodes of functions within IEDs with acommunication interface. The bay unit with Time Over Current Protection, Control, and

Automatic Recloser contains 4 logical nodes.

IED3IED3

IED1IED1

IED2IED2

Logical Device

IED1

„Bay A“

PTOC

RRECRREC

CSWICSWI

MMXUMMXU

Auto Reclosing

Switch Control

Measurement Unit

XCBRXCBR Circuit Breaker

TCTRTCTR

CurrentTransducer

Time Over Current

Q0T1

Figure 13: Modelling Example.

3.2.6 GOOSE

The GOOSE (Generic Object Oriented Substation Event ) service included in the IEC 61850protocol set enables fast inter-device communication with time critical real time communication

over wide-band communication links.

A device is sending information per multicast. Only the IEDs that have subscribed thisinformation receive the message. A GOOSE message of an IED can therefore be received and

processed by several units at the same time.

Only IEC 61850 makes use of the possibilities of the modern 100 MBIT-Ethernet technology withreal-time data transmission by tagging of GOOSE telegrams (Figure 14). Thus it is possible totransmit different GOOSE messages and i.e. fault records using the same Ethernet.


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bypass for IEC GOOSE

Buffer for normal telegrams

Ethernet-Switch

fast

GOOSE

normal telegram

Figure 14: Priority (tagging) of GOOSE telegrams

3.3. Future Standard Extensions of IEC 61850

Current trends in IEC TC 57 indicate the further extension of IEC 61850. Additionally to theexisting application for substation automation – the main scope of IEC 61850 - the followingapplications are known today:

Remote control and monitoring of wind power plants (IEC 61400-25) Remote control and monitoring distributed power stations, new proposal (IEC

57/660/NP)

Remote control and monitoring water power stations, new proposal(IEC 57/661/NP)

Telecontrol of substations “sTCA”, ongoing(Ad Hoc Working Group 07 in TC 57 of IEC)

Power Quality Monitoring, Addendum to IEC 61850 (initiative started)

Product standard for switchgear equipment (IEC 62271-003)

Metering (EPRI, IEEE) (in discussion)

Gas, Water, etc.(in discussion)

Future tasks will be to continue standardisation for all kinds of DER units and LTS strategies withfurther extensions of IEC 61850.

IEC 61400-25

Work is going on within IEC TC88 project 25 to develop a communication standard formonitoring and control of wind power plants. The future standard IEC 61400-25 providesrequirements relevant to the specification, engineering, use, testing, diagnosis, and

maintenance of the information to be shared in wind power systems. It re-uses portions of IEC61850 to specify information models and information exchange methods. The object models aredetailed data templates for the information exchange needed for monitoring and controlling theDER device within the architecture of the power distribution system.

The approach with an abstract communication service interface has been used. The abstractcommunication service interface provides the ability to specify separate communication profilesfor particular network topologies. MMS and OPC/XML are two candidates to communicationprotocols for the future standard.

4. Areas where knowledge lacks, but must

be gathered

There are several aspects of the communications system design, that still have to be defined toenable a widespread DER integration. The following fundamental information needs at least tobe determined:

1. Functional Requirements


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- What data elements are to be collected from the DER installation to provide an effectivepicture of its current configuration and status? How often should this process take place?

- What conditions within the DER plant constitute a case of alarm, that requires attention?

Classification of alarms is required.

- What conditions within the DER plant constitute an event, that needs to be recorded ?

- What operational functions have to be communicated for the normal daily operation of

the DER unit?

- What operations are envisaged to safeguard the DER unit in case of fault and/orabnormal situation? Which of these operations can be automated, which shall be carriedout manually?

- What procedures are to be applied for DER unit recovery after the occurrence of a fault?Which of these procedures can be automated, which have to be manual, which have tobe communicated?

2. Performance Requirements

- What is the response time required for each identified critical function?

- What is the response time allowed for each identified operation or control function?

- What is the permissible response time for each system management function?

3. Security Requirements

- What rules are to be set for operator access control to services and functions?

- What measures are to be taken for data integrity and confidentiality?

- What level of redundancy shall be provided for the communications links?

Generally there are no guidelines available about the configuration of the communicationsnetwork depending on the different requirements for different locations.

Further no experience exists what will be the best way for the transition from current protocolsto the IEC 61850 protocols that make the specification of communications interfaces of equipment significantly easier. Interfacing to existing equipment or systems is usually muchmore difficult, but it is often necessary. These existing equipment are also rather poor inmeeting the present level of requirements.

5. What must be abandoned from the pastin this area to favour DER?

Up to now monitoring and control of DER is done at lowest extent. If any communication isperformed mostly proprietary solutions, adapted with high engineering efforts, exist. With anincreasing share of DER and with the idea to bring advantages for grid operation communicationof lots of data is required as explained in chapter 2.

Fast, reliable, fault-tolerant, powerful, flexible und cheap communication interfaces must be

available to favour DER. Therefore in a first step requirements (functional, performance andsecurity) for communication have to be clearly defined. Mature data transmission technologieswith a flexible communication architecture based on standardised communication protocols willbe the future way for a widespread DER integration.


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6. What needs to be operational 5 yearsfrom now?

The growing share of DER requires the integration of the units into normal network operation.

Supervision and control of the units must be possible within 5 years to enable a stable networkoperation and to balance the energy produced. Therefore suitable communicative interfaces withopen architecture must be available with mature, reliable and cost effective technologies.

Any new DER device and also some customers with flexible demand connected to powernetworks will have to communicate and operate with each other and the existing transmissionand distribution systems. Therefore interoperability between these systems and equipment fromvarious manufactures must be guaranteed. Communication standards (or at least drafts)

probably based on IEC 61850 for all kinds of DER must be available and successfully tested inselected demonstration projects. Data necessary to fulfil the requirements on DER for differentmarket segments in different countries must be specified. Due to rising transmission costs and

efforts to handle large amounts of gathered information only significant data must betransmitted. Depending on the philosophy of the operator only selected units with a significant

weight will be connected to the communication network. Criteria of significance that filter theselection of the units still have to be defined.

Available transmission possibilities like telephone lines, internet, radio transmission or powerline carrier have to be used. The required performance has to be met considering requesteddata throughput, fault tolerance, reliability, and security.

Intelligent software solutions must be available that distribute as much intelligence throughoutthe network as necessary and economically beneficially.

7. Abbreviations

ACSI Abstract Communication Service Interface

DEMS decentralized energy management system (

DER Distributed Energy Resource

DSM Demand Side Management

EPA Enhanced Performance Architecture

EPS Electrical Power System

HMI Human Machine Interface

IED Intelligent Electronic Device

LN Logical Node

MMS Manufacturing Message Specification

PICOM Piece of Information for Communication

SCSM Specific Communication Service Mapping


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8. Literature

[IEC61850] IEC 61850, Communication networks and system in substations,parts 1 - 10

[DGNet_D13] Deliverable 13, “Communication interface case studies”, outcome of project

ENIRDGNet, 5th EC research programme

[DGNet_D14] Deliverable 14, “Action plan towards standardised communication interfaces”,outcome of project ENIRDGNet, 5th EC research programme

[DGNet_A] Annex to Deliverable 14, “Action plan towards standardised communicationinterfaces”, outcome of project ENIRDGNet,5th EC research programme

Documents

S8 Proceedings-Keynote V2 Public