ABB Review Special Report: IEC 61850

The corporate ABB technical journal review

IEC 61850: The new approach 7 Products for the standard 16 Verification and validation 23 Case studies of IEC 61850 38

Special Report IEC 61850 Communication is more than exchanging data; it means globally understandable information based on syntax and semantic. This is behind IEC 61850, the topic of this issue of ABB Review Special Report.

Electric energy is the backbone of our global society. Its reliable supply from conventional and renewable sources via complex networks requires seamless control that is only possible with the help of a standard providing a high-level and comprehensive description of the information exchanged. ABB serves the power system with substations as well as utility automation solutions. Learn more about IEC 61850 and ABB’s commitment from the onset both to developing the standard and implementing it in products and system solutions.

2 ABB review special report Contents

7 The concept of IEC 61850 Background A new approach for communication in substation automation and beyond

13 Common denominator Innovation and Common components have helped ABB adopt the IEC 61850 substation communication standard in record time development 16 Pushing the limits ABB product development based on the IEC 61850 standard 23 Verified and validated ABB has its own system verification and validation center 29 A testing environment ABB’s comprehensive suite of software testing and commissioning tools for substation automation systems

33 Next generation substations Smarter Impact of the process bus substations

38 IEC 61850 at work Project Five case studies 42 When two become one IEC 61850 in combination with ABB’s award-winning experience Extended Automation System 800xA is opening doors to new and cost-effective solutions

47 IEC 61850 Edition 2 The way forward From substation automation to power utility automation 53 Reliable networking Impact of modern communication technology on system reliability 57 Seamless redundancy Bumpless Ethernet redundancy for substations with IEC 61850

62 IEC 61850 – a success around the world Enabling the Substation automation systems pave the way to a smart grid smarter grid

Contents 3 Editorial IEC 61850 – A unifying global communication standard

Dear Reader, Substations are key components of the power control the devices, and how conformity to grid, facilitating the efficient transmission and the standard should be tested. distribution of electricity. They play a vital role in terms of monitoring and controlling power Following its introduction, the implementation flows and provide the interconnection be- of IEC 61850 has advanced at a remarkable tween generating facilities, transmission and pace. Perhaps never before has an industrial distribution networks and end consumers. standard been accepted with such speed. Substation automation systems make their Within two years of its release, a majority of control and monitoring possible in real time the market was demanding IEC 61850 as the and help maximize availability, efficiency, preferred communication protocol. reliability, safety and data integration. Peter Leupp It is increasingly being used for the integration Head of Power Systems division For decades, the power sector was geo- of electrical equipment into distributed control Member ABB Group graphically split between two major standards systems in process industries. The fact that Executive Committee – IEC (International Electrotechnical Commis- new application areas, such as hydro and sion) and ANSI (American National Standards wind power are being added is yet another Institute). This often proved a deterrent to indication of its success. the development of a global technology offering. The bottom line is about how technology can lower costs, improve reliability and enhance IEC 61850 broke this deadlock. Since its efficiency. IEC 61850 has a proven track publication in 2004, it has been embraced by record of deliverable benefits to both small both the IEC and ANSI communities. The new and large utilities. Communication infrastruc- standard was designed to: ture costs money to install, configure and − Provide a single protocol for a complete maintain. But the savings that IEC 61850 substation delivers by way of substation design, installa- − Implement a common format to describe tion, commissioning, and operation combined the substation and facilitate object model- with new capabilities that are not practical or ing of data required in the substation cost effective using legacy approaches, Claes Rytoft − Define the basic services required to makes it a worthwhile investment. Head of Technology transfer data using different communication Power Systems division protocols This special edition of ABB Review looks at − Allow for interoperability between products this truly global and unifying standard from from different vendors different angles and relates many of our experiences based on the vast installed base The standardization work commenced in the we have built during the years. We shall also mid 1990s and continued for almost a attempt to take a peek into some possible decade, involving more than 60 experts from future developments in this area. utility and technology providers across the globe. ABB was very much a part of this We hope you enjoy reading this dedicated process and some of the contributors are special issue. represented in this report.

IEC 61850 provides a standardized framework for substation integration that specifies the communications requirements, the functional characteristics, the structure of data in devices, the naming conventions for the data, how applications interact and Peter Leupp Claes Rytoft

4 ABB review special report Editorial 5 6 ABB review special report The concept of IEC 61850

A new approach for communication in substation automation and beyond

KLAUS-PETER BRAND, WOLFGANG ubstation automation (SA) is The connection of the SA system with WIMMER – The ability to cope with commonly used to control, the switchgear and instrument trans- the natural migration of technology protect and monitor a substa- formers was still left to analog standards combined with the need for interoper- S tion [1]. However, over the such as 1 A and 3 A for current trans- ability are just some of the reasons the years advances in electronics, informa- formers, and 110 V and 220 V for voltage IEC 61850, an international standard tion and communications technology transformers and contact circuits for that defi nes communication in and have brought about sweeping changes switchgear operations. between electrical substation auto- in the way substations are operated. The mation systems was developed. Using advent of software-based substation au- It took over 20 years before global forc- it’s object-oriented hierarchical data tomation systems (hereafter referred to es, such as international suppliers and model approach with high-level as SA systems) connected by serial links transnational utilities raised their voices standardized semantics, IEC 61850 rather then rigid parallel copper wiring to request a solution, in the form of a enables the abstract defi nition of data gradually became items and services to not only specify the norm rather what data or information needs to than the exception. Using it’s object-oriented hier- be exchanged but also the mechanics Though successful of how it is to be exchanged using and widely accept- archical data model approach mainstream communication and ed, these systems with high-level standardized networking (mainly Ethernet) technolo- were based on ei- gies. In addition, the cost benefi ts of ther the manufac- semantics, IEC 61850 enables implementing IEC 61850 can already turers’ own propri- be seen in the system design phase etary com mu nica- the abstract definition of data and experienced right through to the tion solutions or the items and services. commissioning and operating phases. defi ned use of com- All of these factors help to explain the munication stan- eagerness and speed with which the dards from other application domains, substation communication standard, to fi rst edition of the standard has been such as DNP3 or IEC 60870-5-104. overcome the interoperability prob- accepted around the globe. These solutions made interoperability lem ➔ 1. While interoperability was a ma- between devices from different suppliers, jor concern, it wasn’t the only one. Only and sometimes even between different too aware of the dizzying pace at which versions of devices from the same sup- technologies change, the authors of this plier, an engineering nightmare which new standard, known as IEC 61850, also could only be mitigated by expensive set about finding a way to create a “future protocol conversion or re-engineering. -proof” standard that would be immune

The concept of IEC 61850 7 to any future technological develop- 1 Substation automation (SA) architecture from hardwires over proprietary protocols ments. to IEC 61850

As the IEC 61850 standard evolved, oth- 1965 1985 2005 Year er features, such as the definition of two time-critical services – the fast transmis- Hardwired SA Legacy SA IEC 61850 based SA Location sion of trip-type signals and sampled MMI, Control board analog current and voltage values – were HMI HMI Operating added. These time-critical services en- Gateway Gateway room able the extension of the serial links to be Event recording Copper used between any intelligent electronic Protection cables Serial communication Serial communication (Fiber optics) (Fiber optics) Relay device (IED) and the electronic interfaces room in GIS SCADA-distribution, metering Station bus and near the switchyard equipment. Demand- Proprietary Process bus* Station bus ing market requirements, such as the according to IEC 61850 Relay house shortening of transfer times down to to other bays to other bays in AIS 3 ms and time synchronization in the Copper cables order of 1 µs had also to be considered. Swith yard GIS GIS GIS Perhaps the cornerstone of the standard GIS is the innovative extensible markup lan- or Sensors & AIS guage or XML-based substation configu- Bay cubicle Copper cables Bay cubicleCopper cables Bay cubicle actuators ration description language (SCL). SCL * The process bus is not a must in IEC 61850 but only an option formally describes the configuration of IEDs in terms of functionality (eg, circuit breaker control, measurements and sta- and devices would need to be standard- various technologies employed in a typi- tus values) communication addresses ized, thus blocking any technical evolu- cal substation. For example, fast-chang- and services (eg, reporting). It also de- tion and functional competition. Never- ing mainstream communication technol- scribes the switchyard layout and its re- theless it must be possible to exchange ogy will always need to serve the lation to the functions implemented in faulty IEDs within the lifetime of the slower-changing requirements of protec- the IEDs. SA system. Using IEDs that are com- tion and substation automation. pliant with the same standard in terms The emergence of a new standard of interoperability will facilitate easy To facilitate the use of the standard for When the authors of the IEC 61850 stan- exchangeability. users, the identification of all transmitted dard first sat together, they identified a data should not be based on a limited list of market requirements that would in- Free architecture number scheme derived from contact fluence the form the new standard would For a standard to be termed “global,” it terminal rows, but rather on the object- take. The most important ones were in- must support the operation philosophy oriented grouping of data and a naming teroperability, free architecture and long- of utilities around the world. It has to structure that uses standardized acro- term stability. support an arbitrary allocation of func- nyms understandable to any substation tions to devices and should therefore be engineer. In addition, configuration and Interoperability capable of supporting centralized and engineering tools should be used to cre- To begin with, the standard must be able decentralized system architectures. ate systems with minimum effort and to support all functions in its application with a minimum risk of failure. domain substation. Therefore, in addition Long-term stability to protection, automation, control and Given that the lifetime of a substation The basic approach of IEC 61850 monitoring functions, many service func- (primary equipment) is between 40 and To reach long-term interoperability, ie, to tions, such as time synchronization, self 60 years, it is anticipated that compo- cope with the different time scales of supervision and version handling have nents of the SA system have to be ex- function evolution in the domain substa- also to be supported. These functions changed, on average, around two to tion and with changing communication are executed by software implemented in three times during this period; some technology, the approach taken in the the IEDs. Interoperability in the SA sys- components may need replacements on IEC 61850 standard separates the do- tem means that IEDs from different sup- a more regular basis. Naturally over time main related model for both data and pliers or different versions from the same the substation will have to cope with the communication services from the proto- supplier must be able to exchange and integration of new components from the cols, ie, the ISO/OSI seven-layer stack use information in real time without any same or new suppliers, or it may need to used to code and decode information protocol converters and without the need be extended. The point is that irrespec- into bit strings for communication over a for human interpretation. tive of the changes, interoperability must serial link. This approach not only ac- be maintained indefinitely, or to be more commodates state-of-the-art communi- It is important to distinguish interopera- specific, the standard has to be future- cation technology, but it also safeguards bility from interchangeability. If IEDs were proof. This requirement not only applies investments in applications and engi- also to be interchangeable, the functions to substation devices, but also to the neering (based on the object and com-

8 ABB review special report 2 The split between data model and communication stack 3 The parts of the standard IEC 61850 Edition 1

Slow Communication networks and systems changes Definition in substations Data Data and services according model Domain substation: to the domain substation Part 1: Introduction and overview What data have to be Part 2: Glossary communicated? Part 3: General requirements Mapping Part 4: System and project management SPLIT! Data model to the communication stack Part 5: Communication requirements for Communication functions and device models

technology: Communication Part 6: Configuration description language How are the data Selection for communication in electrical communicated? ISO/OSI ISO/OSI stack from the stack substations related IEDs Fast mainstream Part 7-1: Principles and models changes Part 7-2: Abstract communication service interface Part 7-3: Common data classes Part 7-4: Compatible logical node (LN) munication service model). Therefore, physical device itself are dealt with by an classes and data classes the standard is future-proof. The map- LN class named LPHD. Part 8-1: Mapping to MMS and to ISO/IEC 8802-3 ping of the data model to the communi- Part 9-1: Sampled values over serial cation stack is also standardized in Only if a LN class for some function is unidirectional multidrop IEC 61850 to ensure interoperable com- missing it may be substituted by generic point-to-point link Part 9-2: Sampled values over ISO 8802-3 munication ➔ 2. LN classes that have restricted semantic Part 10: Conformance testing meaning. More demanding, however, is The object-oriented data model the extension of LNs and data according The basic data model structure defined to the strict and restrictive extension in the IEC 61850 standard is application rules of the standard, including name independent. However, depending on spaces as unambiguous references to the scope of the standard, the object semantic meaning. These rules preserve All application model classes, as issued in edition 1 of interoperability, even in cases where ex- the standard ➔ 3 [2], are related to the tensions are required. functions, including domain substation. Object models for the data interfaces wind power [3], hydro power [4] and dis- For the functional identification of each tributed energy resources [5] were added data in the context of the switchyard, a to the primary at a later date. All application functions, hierarchical plant designation system including the data interfaces to the pri- shall be used for the designation of sub- equipment, are mary equipment, are broken down into station objects and functions preferably the smallest feasible pieces, which may according to IEC 61346 [6]. broken down into communicate with each other and, more the smallest fea- importantly, may be implemented sepa- The services of the data model rately in dedicated IEDs. In IEC 61850, Interoperability requires the standardiza- sible pieces, which these basic objects are called logical tion of not only the data objects but also nodes (LNs). The class name of the LN the access to them. Therefore, standard- may communicate refers to the function the data objects ized abstract services also belong to with each other belong to. The data objects contained in IEC 61850. The most common ones a LN may be mandatory, optional or con- include: and be implement- ditional. The data objects themselves – Read: reading data such as the value contain attributes 1, which may be seen of an attribute ed separately in as values or detailed properties of the – Write: for example writing the value of dedicated IEDs. data objects. This hierarchical data mod- a configuration attribute el is illustrated in ➔ 4. – Control: controlling switching devices and other controllable objects using Since the class names of LNs and the full standardized methods such as “select names of data objects and attributes are before operate” or “direct operate” standardized, they formally provide the – Reporting: for example, event driven semantics of all exchanged values within reporting after value changes the scope of IEC 61850. LNs may be – Logging: the local storage of time- grouped into logical devices (LDs) with stamped events or other historical data non-standardized names, and these LDs – Get directory: in other words, to read are implemented in servers residing in out the data model (important part of IEDs. The common properties of the self-description)

The concept of IEC 61850 9 4 Hierarchical data model 5 An illustration of the control service

HMI CSWI XCBR Circuit Physical device (IED) Names not Breaker IED (BIED) breaker defined as Server standardized Select Implementation

Logical device (LD) Breaker controller Control circuit Selected for Grouping commands Logical node (LN) XCBR (circuit breaker) Names Operate standardized Data Operated Indication Data (Object) Pos (position) circuit Properties Started for breaker StVal (status value) position Attribute Intermediate-state/off/on/bad-state New position Selected state Attribute q (quality) good/invalid/reserved/questionable sequence Indication Command Attribute t (time stamp) Cmd time of change termination Value Enhanced security

– File transfer: for configuration, firmation”), which terminates the control GOOSE is the disturbance recording or historical service. data acronym for generic – GOOSE: GOOSE is the acronym for Performance requirements generic object oriented system event The transfer time of messages between object oriented and is a service used for the speedy the sending application (eg, protection system event and transmission of time critical informa- function issuing the trip) and the receiv- tion like status changes, blockings, ing application (breaker function per- is a service used releases or trips between IEDs forming the breaker operation) is deter- – Sampled value (SV): the SV service mined by the requirements of functions for the speedy quickly transmits a synchronized that depend on this message transfer. transmission of stream of current and voltage sam- As a protection trip is time critical, with ples for voltages and currents a worst case taking around 20 ms, it is time critical infor- allocated to the most demanding trans- The control service implementing the fer requirement class, which means 3 ms. mation like status “select before operate with enhanced The transfer of samples using the SV changes, block- security” mode is illustrated in ➔ 5 in service is also assigned to this require- the context of a switch operation: The ment class to avoid, for example, delays ings, releases or SELECT command is issued at the in fault detection by protection. The re- operator’s HMI and communicated to the quirements have to be fulfilled not only trips between IEDs. bay control unit represented by the LN by the IEDs but also by the SA system CSWI. Depending on the system archi- design. The transfer time of a GOOSE tecture the SELECT command is con- message over a serial link is compared firmed either by the bay controller or the in ➔ 6 and ➔ 7 with the response time of circuit-breaker IED, which is represented a hardwired contact circuit. by the LN XCBR. When the operator receives a positive acknowledgement (ie, To properly analyze the sequence of “Selected”) from the CSWI, he then is- events in the system and for post-event sues an OPERATE command. Once per- fault analysis, the events need a time mission has been granted, an operation stamp with an accuracy against real time request is sent via the bay controller to of 1 ms; this incidentally is better than the circuit breaker (XCBR). The execu- any contact change. However, time syn- tion of the command request is positively chronization for current and voltage acknowledged using the message “Op- samples, which are needed for differen- erated.” Additional feedback is provided tial or distance protection or global pha- using the reporting service, which is initi- sor comparison, requires an accuracy of ated by the start of the circuit-breaker the order of 1 µs! The 1 ms accuracy lev- contact movement (“Started”) and when el is achieved using the simple network the end position is reached (“New posi- time protocol (SNTP) directly over a se- tion”). In cases where a command ser- rial communication link, while one pulse vice with enhanced security is chosen, per second (pps) over a separate wire or the end result is confirmed by the com- fiber achieves the 1 µs time synchroniza- mand termination message (“Cmd con- tion. In the future, the IEEE 1588 stan-

10 ABB review special report 6 Transfer time definition with hardwired contacts 7 Transfer time definition with communication stacks

Transfer time t = ta + tb + tc Transfer time t = ta + tb + tc

ta tb tc ta tb tc

Coding Decoding Application Application Application Application Physical link (wire circuit) in the in the function 1 function 2 function 1 function 2 stack stack Physical Physical device PD1 device PD1 Physical device PD1 Physical device PD2

dard [7] will allow high-precision time Edition 2 [8] of the standard scheduled 8 Mapping to the stack synchronization also directly over Ether- for publication in 2010 will define proto- net. cols for the connection of IEDs with Data Model (Data and services) two ports to two redundant communica-

The communication stack and tion systems or the formation of a ring Client-Server GOOSE Sampled values mapping with redundant traffic in both ring direc- IEC 61850 has selected mainstream tions 3. Mapping technology for the communication stack, 7 ie, a stack structure according to the The station and process buses 6 MMS ISO/OSI layers consisting of Ethernet The station bus connects the IEDs for 5 Time critical services 4 (layers 1 and 2), TCP/IP (layers 3 and 4) protection, control and monitoring (ie, TCP 3 and manufacturing messaging specifica- bay units) with station level devices (ie, IP 2 Ethernet link layer with priority tagging tion, MMS, (layers 5 to 7). The object the station computer with HMI and the ISO/OSI Stack Layers 1 Ethernet physical layer with 100 MB/s model and its services are mapped gateway to the network communication to the MMS application layer (layer 7). center (NCC)) using whatever services Only time-critical services, such as SV are required by the applications. The and GOOSE are mapped directly to the process bus connects the bay units with The station bus may be configured in Ethernet 2 link layer (layer 2) ➔ 8. the switchyard devices, and the com- a ring topology with ring redundancy, a munication of status information, com- redundant star for IEDs with dual port Ethernet bus architectures and dual mands and trips is the same as for redundancy or any solutions which fulfill port redundancy the station bus ➔ 9. IEC 61850 uses Ethernet as the basic However, getting communication technology, currently synchronized sam- Such is the potential of with a speed of 100 MBit/s at the IEDs. ples of current and Support of message priorities by man- voltage to the rele- IEC 61850 that in the future aged switches allows time critical re- vant protection IEDs quirements, such as the 3 ms applica- using the SV ser- it is hoped it can be applied tion to application transfer time, to be vice is quite chal- right across the power met. Tree and ring topologies are possi- lenging. ble with switches. However, according system spectrum. to the first edition of the standard, the The conversion of Ethernet ring topology with automatic proprietary signals from nonconventional the requested performance and reliability reconfiguration in case of link or switch instrument transformers for current and requirements. The process bus may also failures is the most common architecture voltage or of the analog values from con- adopt a ring or even a star topology, but for systems. Tree topologies are not used ventional instrument transformers to at the very least one or more point-to- very often because the switch represent- IEC 61850 telegrams is done using an point connections. ing the root is a potential single point of IED called a merging unit (MU). An MU failure. It should be noted that in the ring, merges the 3-phase currents and volt- SCL supported engineering one switch connection has to be always ages, including the zero-components of In order to process data received from open – creating in effect a kind of tree one bay high-precision time-synchro- IEDs, the receiving IED needs to know topology – to avoid endlessly circulating nized by definition. The process bus how this data has been sent; how it has telegrams. The open switch connection functionality for the switchgear is pro- been coded; what it means in the con- is automatically closed if a failure in any vided by the so-called breaker or switch text of the switchyard; and the function- of the ring links or in another switch cre- IEDs (BIED, SIED). The free allocation of ality of the sender. To be able to transfer ates an unwanted second opening (ie, a functions allows the creation of IEDs with this information from one tool to another tree recovery algorithm). both BIED and SIED, and MU functional- in a standardized way, the XML-based ities. SCL language has been defined.

The concept of IEC 61850 11 9 Station and process bus examples 10 Example of engineering with SCL

Network IED Configuration IEDIED Configuration configuration level Description ICD Device Descriptiondescription ICD(ICD) Device in the system capability Station Station Station SCD per IED HMI level computer gateway Device Device (IED) specific tool Station Device data DeviceDevice data data DeviceDevice data data bus Device data Stand-alone device configuration System Bay Protection Control Protection Control Protection configurator level & control System configuration System configuration description (SCD) Device selection Process System specification description (SSD) System and device bus Cu wires configuration and Single-line diagram with data flow MU BIED SIED MU BIED SIED allocated functions “system as built” Process SIEDSIED SIEDSIED Process interface represented by logical nodes (LNs) level System “system as specified” Switchgear/switchyard Reusable for testing, documentation maintenance and extensions

To allow the exchange of data between the system. The principles of engineering Klaus-Peter Brand tools from different manufacturers, with SCL files are shown in ➔ 10. Wolfgang Wimmer IEC 61850 introduces a basic engineer- ABB Substation Automation ing process: Based on the system speci- As the entire IED data model is visible via Baden, Switzerland fication and the description of the IEDs, the communication system, including [email protected] the required device types are selected possible configuration and setting para- [email protected] and their formal description, in the form meter values, and all this can be de- of an ICD file, is loaded into the system scribed in SCL, the SCD file is also a medium usable by other applications in Footnotes 1 The attributes carry the data values. the life-cycle of the system [9], such as 2 Nowadays in communication technology, most The station bus the archiving of the system configuration efforts and money are invested in Ethernet in a standardized form and the transfer technology. In fact Ethernet is now successfully connects the IEDs of protection parameters to protection competing with the traditional field busses. 3 Please refer to "Seamless redundancy " on system configuration tools. It may be page 57 of this issue of ABB Review. for protection, con- used in simulation and testing tools or trol and monitoring to check the configuration (version) state of the running system against the intend- References with station-level ed state. While these applications are [1] Brand, K.P., Lohmann, V., Wimmer, W. (2003) outside the scope of IEC 61850 as a Substation Automation Handbook. UAC, devices while the ISBN 3-85759-951-5. (www.uac.ch). communication standard, they are of ad- [2] IEC 61850 Ed. 1 (2002-2005). Communication process bus con- ditional benefit for the user of the stan- networks and systems in substations. www.iec.ch. dard. [3] IEC 61400-25-2. Communications for nects the bay units monitoring and control of wind power plants – Part 25-2: Information models for Wind turbines. A future-proof outlook with the switchyard [4] IEC 61850-7-410. Communication networks The long-term value of IEC 61850 for and systems for power utility automation – devices. users lies in its object-oriented hierarchi- Part 7-410: Hydroelectric power plants cal data model approach with its high- Communication for monitoring and control. [5] IEC 61850-7-420. Communication networks level standardized semantics and the use and systems for power utility automation – configuration tool. The system configura- of mainstream communication technolo- Part 7-420: Basic communication structure – tion tool then defines the meaning of IED gy, which is dominated by Ethernet. Distributed energy resources logical nodes. functions in the context of the switchyard However, IEC 61850 is much more than [6] IEC 81346. Industrial systems, installations and equipment and industrial products – Structuring by allocating LNs to elements of the just a normal communication protocol. principles and reference designations. switchyard single-line diagram. The data Such is its potential that in the future it is [7] IEEE 1588 – 2008. Standard for a precision flow between all IEDs is then defined, hoped IEC 61850 can be applied right clock synchronization protocol for networked and all IED names and communication across the power system spectrum. measurement and control systems. [8] IEC 61850 Ed2 (scheduled for 2010). related addresses and parameters are Communication Networks and Systems for configured. The resulting SCD file is a A second edition of the standard is Power Utility Automation. www.iec.ch. comprehensive description of the entire scheduled for publication in 2010. It will [9] Baass, W., Brand, K.P., Gerspach, S., Herzig, system in the context of IEC 61850. This contain many additional features, such M., Kreuzer, A., Maeda, T. (2008). Exploiting the IEC 61850 potential for new testing and file is then imported into the device tools as the support of dual port redundancy maintenance strategies. Paper presented at the of the different IEDs to complete their infor IEDs. meeting of the International Council on Large dividual configuration in the context of Electric Systems (CIGRE), Paris, Paper B5-201.

12 ABB review special report Common denominator

MARTIN OSTERTAG – With the advent of the IEC 61850 Common components have standard in 2002, and its growing success in substation helped ABB adopt the automation and later in several other industries, ABB was faced with the challenge of adapting a variety of its prod- IEC 61850 substation commu- ucts to the new technology in a relatively short time. This was successfully accomplished in part due to the develop- nication standard in record time ment of common components designed for use in a wide variety of ABB products.

Common denominator 13 1 Interoperability demonstration between major vendors at the IEEE PSRC meeting in Sun Valley in the United States in 2003

2 Use of common components in a variety of ABB products

MicroSCADA Pro / SYS 600 C COM600REB500

EngineeringEngineering and ttitesting toolstoo

Common IEC 61850 components: IEC 61850 communication – communication stacks – tool libraries

BB was heavily involved in the process of creating the IEC 61850 standard. As the stan- A dardization was in progress, and in order to enable a fast time-to-mar- Relion® 630 series 650 series IEDs 670 series IEDs ket, the standard was already being implemented in products in parallel to the standard's ﬁ nalization between 2002 and Already in its fourth edition, the guideline specification (MMS) and generic object 2004. In order to support the standardiza- serves as a good introduction to the oriented substation event (GOOSE) serv- tion, interoperability tests were arranged soon-to-be-available second edition of ers and clients. More importantly, it hides for these early implementations. As ABB the IEC 61850 standard and defines the the nitty-gritty details from the more ap- believed that the standard would be a stepwise transition from the first edition plication oriented research and develop- success, it realized that a wide variety of to the second. ment found in ABB’s products, thereby products would need to support it. The allowing developers to concentrate on company thus decided to implement re- Based on the principles defined in the providing application value to customers. usable components right from the begin- application guideline, ABB started to Currently, the communication stack is in- ning. The results of these activities were develop reusable reported back to the IEC organization that components for a used them to improve the clarity and qual- variety of products Currently, the IEC 61850 com- ity of the standard. In addition, they were and tools in its presented to the public at the IEEE PSRC portfolio. Two im- munication stack is integrated meeting in Sun Valley, USA in 2003 ➔ 1 portant compo- into more than 12 ABB prod- and at the Hannover Fair in April 2004. nents are the communication stack ucts or product families, with At that time, ABB outlined a clear step- and a set of librar- wise strategy for the introduction of ies that handles a growing number of host IEC 61850 into its solutions in its very IEC 61850 object platforms set to follow suit. own internal IEC 61850 application models and con- guideline. This guideline defines the man- figurations ➔ 2. datory subset of IEC 61850 services that tegrated into more than 12 ABB prod- is supported by all ABB devices, it adds Communication stack ucts or product families, with a growing additional ABB internal convention, and The IEC 61850 communication stack ➔ 3 number of host platforms set to follow clarifies and details certain sections is effectively a piece of software that im- suit as IEC 61850 continues to be ac- where the standard leaves room for in- plements the communication services for cepted by other industries. The benefits terpretation. IEC 61850-8-1 manufacturing message of the IEC 61850 stack include portabili-

14 ABB review special report 3 Use of IEC 61850 stack component 4 Aspects that need to be observed to capitalize on component development

− Always be a step ahead of the products and tools that will use the components. In other words anticipate upcoming or future IEC 61850 specific communication requirements that component users might not even be aware of at the time they are implemented in the product. − Fast reaction and premium support during the integration phase of the products research and development. In other

SYN 5200 / SYN 5201 / SYN 5202 words, the component research and IED Application/Data interface development team must have a very “service provider” oriented mindset in that Layer 4 IEC 61850 IED interface (IAL and direct write/read to application) requests and problems from product research and development teams must be Layer 3 DB IEC 61850 SERVER / CLIENT dealt with relatively quickly. − Version traceability. Keep track of the

handler distributed versions and version SCL-parser

Control Report IEC 61850 GOOSE FileXfer Setting Subst. Mod Configuration Layer 2 handler handler model H. handler handler handler handler handler dependencies, ie, which version of a product contains which version of the

SNTP component. Layer 1 Third-party MMS protocol SW client − Backward compatibility of the component is very important. If substation primary IEC 61850-8-1 MMS/ IEEE802.3 GOOSE equipment can have a life expectancy of between 30 and 40 years, it is an absolute certainty that the substation automation system will be extended and upgraded at ty, and it runs on different real-time oper- XML-based substation configuration lan- least once during this time. As a conse- ating systems as well as under Windows guage (SCL) comes into play. In addition, quence, different versions of products and tools need to co-exist in the same system. for PC-based products and tools. the communication stack, which is a re- This puts certain requirements on the usable component, needs configuration definition of the component’s software information to enable such communica- interfaces and the way functionality is tion to take place. implemented. For the upcoming − The proper clustering of functionality in a way that keeps the level of detail edition 2 of the Configuration tools rely on a software component users need to know about component that interprets and generates IEC 61850 at an appropriate level. This in IEC 61850 com- both SCL and stack configuration files. turn allows the product engineers to focus more on application modeling and concept This component allows the tools to work munication stan- development. on an object-oriented data model rather dard, common than parsing and interpreting raw files. In addition, it helps to avoid syntax and se- shows several important aspects that components will mantic errors and contributes to the high need to be observed to successfully continue to play an quality of ABB’s products. capitalize on component development ➔ 4. important role in Benefits of ABB’s approach The main benefits of such a component For the upcoming edition 2 of the supporting a mar- include: IEC 61850 substation communication ket-driven, phased − The ability to carry out maintenance standard, common components will con- and improvements in one place, tinue to play an important role in sup- upgrade and migra- allowing all products to benefit porting a market-driven, phased upgrade − The uniform implementation of and migration strategy for ABB’s product tion strategy for functionality, which is crucial for and tool portfolio. Close links to IEC ABB’s product and interoperability between devices from working groups combined with imple- ABB and third-parties mentation in parallel to standardization tool portfolio. − Detailed testing and experience in the will allow ABB to maintain and strength- field. Because it is integrated into a en its front-row position in IEC 61850 File handling and object modeling variety of products, its functionality is technology. Each product to be integrated into an tested way beyond what can be achieved IEC 61850-based system needs to have for product-specific implementations. its functionality defined in a standardized Martin Ostertag way that enables it to communicate with, Success factors for component reuse ABB Substation Automation Products and process information from other prod- ABB’s experience in the development of Baden, Switzerland ucts in the system. This is where the common components for IEC 61850 [email protected]

Common denominator 15 Pushing the limits

ABB product development based on the IEC 61850 standard

JANNE STARCK, STEVEN A. KUNSMAN – Since the publication participated in the standardization work from day one, and of the fi rst edition in 2004, the IEC 61850 communication as it was being developed it was decided to upgrade ABB’s standard has practically become the de-facto standard in Relion® protection and control product family to support the the context of substation automation. Almost from the IEC 61850 standard. By the time the standard came into moment of its publication, intelligent electronic devices existence, ABB had already adopted a philosophy of “native (IEDs) supporting IEC 61850 started to appear on the IEC 61850 implementation” in that the standard is imple- market. However, for many of these IEDs, it soon became mented from the start in new product developments. Today, clear that performance and fl exibility were sacrifi ced in the ABB’s IEC 61850-based protection and control products are race to get to the market fi rst. ABB took a somewhat recognized as the number one choice for both utility and different approach. Experts from within the company industrial power systems.

16 ABB review special report 1 Phase time overcurrent (PTOC) overcurrent function design

PTOC Logical Node Class Data Object Explanation Mandatory/ IED Design Name Optional Mod Mode M X Beh Behavior M X Health Health M X NamePlt Name Plate M X OpCnt Operation Counter O OpCntRs Operation Counter Reset O Str Start M X Op Operate M X TmASt Active Curve Characteristic O TmACrv Operating Curve Type O X StrVal Start Value O X TmMult Time Dial Multiplier O MinOpTmms Minimum Operate Time O X MaxOpTmms Maximum Operate Time O OpDITmms Operate Delay Time O X TypRsCrv Type of Reset Curve O X RsDITmms Reset Time Delay O X DirMod Directional mode O

ith the introduction of the As the standard became better known, IEC 61850 implementation” philosophy, IEC 61850 standard, the however, engineers realized the benefits which stated that from then on the stan- world of substation auto- it provided presented them with an op- dard would be implemented in new prod- W mation has taken its big- portunity to rethink IED platform and ar- uct developments. gest technology leap since the intro- chitecture development and introduce duction of microprocessor-based pro- Native IEC 61850 implementation tection and control devices in the early In a typical IEC 61850 native design, the 1980s. Even before its functionality of the IED must consider the entire process, including specification As soon as the standard was published, publication in and evaluation, system and device engi- intelligent electronic devices (IEDs) sup- neering, system commissioning, and op- porting IEC 61850 started to appear on 2004, ABB was erations and maintenance. An IEC 61850 the market. The speed at which this hap- extending the limits native IED should provide: pened was achieved by upgrading exist- – A full set of protection and control ing IED platforms with an internal or ex- of IEC 61850 with data to SA systems, and to other ternal gateway serving as a proxy to IEDs and third-party tools in compli- the IEC 61850 Ethernet-based protocol. its full implementa- ance with the defined data models Because this approach left the IED archi- tion of the stan- and LNs to achieve a high level of tecture, internal software and tools interoperability unchanged, protocol conversion was dard in many of its – Fast communication and application required to enable communication be- performance, which is critical when tween existing IEDs and a modern devices, tools and using generic object oriented substa- IEC 61850-based substation. At the substation automation events (GOOSE) peer-to-peer time, the IEC 61850 standard was just communication for distributed one of a number of protocols to expose tion (SA) systems. protection algorithms, and complex the IED’s internal information, which was station and bay control interlocking mapped to the IEC 61850 data models new conceptual ideas for substation au- schemes over Ethernet in the substa- and logical nodes (LNs). The internal ar- tomation. ABB was taking this approach tion station bus chitecture did not differ from other point even before the standard’s publication – Adherence to data modeling and or register-based communication proto- by fully and genuinely implementing the substation configuration language cols (eg, DNP V3.00 and MODBUS). standard in many of its devices, engi- (SCL) information available for system While these early implementations result- neering and commissioning tools, and engineering, device configuration, ed in a fast time-to-market, performance substation automation (SA) systems. In diagnostics and commissioning and flexibility were sacrificed as a result. fact, ABB had already adopted a “native tools

Pushing the limits 17 2 Visualization of the substation configuration language (SCL) 3 Data structure in a PTOC function

– Ease of adaptation and be future proof fully base the IED’s functionality on the this is dependent on the product and in- to evolving technologies enabled by data model and LNs as defined in the tended application ➔ 1. The supported Ethernet and IEC 61850, for example, standard. As it now stands, protection standard data objects are documented utilizing IEC 61850-9-2 sampled values and control algorithms, which provide in the mandatory model implementation and microsecond-level time synchroni- the core IED functionality, are modeled conformance statement (MICS) docu- zation accuracy via IEEE 1588 and implemented fully according to the ment. IEC 61850 standard rules. In the new ar- ABB’s Relion® protection and control chitecture, the data models are support- In the next stage, the standard LN and product family was one of the first to un- ed directly in the protection and control its selected functionality are modeled dergo the IEC 61850 transformation. The functions, making the LN data directly using the SCL, which describes the func- products required a completely new plat- accessible from the communications tion structures, data objects and data form architecture that would integrate services. With this approach the data types of an LN ➔ 2. With the defined mapping and con- function structures according to the SCL, version process is it is possible to automatically generate ® ABB’s Relion protection and not required, some- the skeleton of the application data ac- thing that is a key cess functions (read, write) for the IED control product family was factor in IED per- system software. These functions are in- formance. IED data herited and directly linked to the protec- one of the first to undergo the are therefore di- tion algorithm (eg, PTOC) data in the IED IEC 61850 transformation, a rectly available with- architecture’s core protection and con- out time-consum- trol subsystem. This direct mapping pro- development that was carried ing additional provides a high-performance interface to cessing. the IED’s IEC 61850 communication out in parallel with the devel- stack, which in turn makes the data ac- opment of the standard. When a new pro- cessible to the station bus ➔ 3. No addi- tection function, tional conversion of protection and con- such as overcur- trol data is required to support the communication services and data repre- rent protection, is implemented, the communication’s architecture and proto- sentation into the core protection and standard phase time overcurrent (PTOC) col. Structures based on LNs can also control applications. This development LN-class definition is the foundation have a function for settings, which are was carried out in parallel with the devel- for modeling the protection algorithm. directly visible to the SA system via the opment of the IEC 61850 standard (pre- Depending on product and application communication stack. 2004) to ensure that the future ABB requirements, all mandatory and select- Relion family was designed from the be- ed optional attributes of the LN-class In general, the IEC 61850 standard pro- ginning to support IEC 61850. are used in the function design. The vides a solid foundation for the design of IEC 61850 standard requires that the native IEC 61850 protection and control Transforming the Relion IEDs mandatory data objects must exist in the IEDs due to the fact that data models One of the key factors that led to suc- data model of the device. The optional have been defined by an international cessful product transformations was to parts are only used when applicable, and working group composed of experts in

18 ABB review special report 4 GOOSE data and message handling 5 IEC 61850 handling in case of a separate communications module

Physical I/O Physical Protection Change GOOSE RX I/O Protection Change IEC Station bus task detector task task detector 61850 Station IED IED bus PTOC PTOC IED GOOSE TX RREC RREC DB task Internal Internal CSWI CSWI bus bus Mod Mod IED Beh Beh Health Health NamePlt NamePlt Loc Loc OpCntRs OpCntRs Pos Pos ctlVal ctlVal operTm operTm stVal stVal Main Comm q q stSeld stSeld pulseConfig pulseConfig

the field. With standard-based data mod- ticular LN structure. After a protection 6 IEC 61850 event handling eling, faster development of IED applica- task cycle completes, the IED process- tion functions and communication inter- ing subsystem performs a signal com- Physical faces can be obtained. The improvements parison to identify new data in the I/O Protection Change IEC 61850 are due to the LN structures, which are IEC 61850 connected datasets. In the task detector MMS stack inherent in the protection application. IEC 61850 data model, most data- This therefore makes data access from change driven activities are based on the IED the IEC 61850 based SA system to the datasets, for example, event reporting PTOC RREC IED IED's internal protection and control al- and GOOSE data publishing. The IED CSWI DB gorithms very computationally efficient change detector identifies changes in Mod Beh and eliminates the need for time-con- the datasets and if a new value is detect- Health NamePlt suming protocol conversion processing. ed, the dataset and its connected func- Loc tionality are triggered. In an IED using OpCntRs Pos The performance of a native GOOSE, the internal high-priority sub- ctlVal Relion IED system executing the GOOSE function is operTm stVal IED architectures designed to support triggered. Subsequently, the modified q stSeld IEC 61850 from the start need to ensure data is sent as quickly as possible pulseConfig that the delay in communicating control through the IED communication interface signals, analog values and other time to the SA system station bus using a critical data between the process and GOOSE multicast message. GOOSE the IEDs is as small as possible. In tradi- multicast messages are unsolicited In IEC 61850-based tional IEDs, the binary and analog signals broadcasts which do not require any cy- were processed by the IED hardware I/O clical data polling mechanism. Data architectures, con- subsystem. In IEC 61850-based archi- structures used in GOOSE include direct tectures, conventional wiring has been access to the IED internal database, and ventional wiring eliminated and these signals are trans- because the internal data model exactly has been eliminat- mitted and received via the communica- matches the IEC 61850 standard, no tions interface. Thus, the communication data conversions are required ➔ 4. ed and binary and interface in the new IEC 61850-based IEDs must be very efficient at processing In the same way, the IED’s IEC 61850 na- analog signals are the communication data. tive design yields high-performance sub- transmitted and scribing GOOSE datasets from other The fast GOOSE performance of a Relion IEDs in the local sub-network. As GOOSE received via the IED is critical in a native IEC 61850 im- messages are processed in the data link plementation to allow control signal pro- layer in the Ethernet stack, this does not communications cessing as if it were a traditional hard- require additional processing through the interface. wired IED. During IED algorithm execution TCP and IP layers. This type of Ethernet or task cycle, the data values of a pro- communication is very fast since the data tection function (eg, the protection start is retrieved directly from the IED commu- in PTOC) can change if an overcurrent is nications hardware interface. The IED’s detected on a feeder, and this in turn up- GOOSE processing capabilities can de- dates the database supporting the par- code the message in less than 1 ms and

Pushing the limits 19 are defined and used in the IED tool and 7 System engineering workflow connectivity packages, and are available

Engineering for the user when an IEC 61850 configu- environment System specification ration (SCL) is exported using the IED (Single line, IEDs,…) tool.

IED Capabilities (LN, DO,…) IED System lib ICD configurator In the new IED architecture, traditional communication protocols, such as Mod- Associations, relation to SCD single line, preconfigured bus, IEC 60870-5-103 and DNP 3.0 are reports, GOOSE mapped from the IEC 61850-based data

Engineering IED model and event datasets. The conve- workplace configurator nience of protocol mapping stems from CID the fact that IEC 61850 includes most of File transfer remote the different data and service types re-

File transfer quired for legacy protocols. A compari- local son of legacy protocols and IEC 61850 Substation File transfer and gateway parametrization with typically shows that legacy protocols IEC 61850 services have a subset of services and data types available. Many customers prefer to use SA system IED IED IED legacy protocols and the internal architecture of an IED must be ready to support multiple protocols. IEC 61850, however, is the preferred superset in terms of deliver only the modified subscribed its associated timestamp and quality at- functionality and services. GOOSE data to the IED’s internal data- tributes are stored in an internal event base, which makes it immediately acces- queue by the IED’s change detector. At System engineering sible to the next execution of the protec- the same time, the IED’s communication IEDs belonging to the Relion product tion and control algorithms. A “put” interface is triggered and starts sending family are configured according to the operation is a single data value copy queued events to clients (eg, the gate- rules defined in the IEC 61850 standard. from a GOOSE frame to the internal LN way or station HMI) on the station The configuration is based on library in- structure database ➔ 4. No conversion is bus ➔ 6. As internal data models and stallable client driver (ICD) files available required as the data in both the IED da- stack data structures are based on the in the IED connectivity packages where tabase and incoming GOOSE message same IEC 61850 data model, there is no these library files include the IED’s data comply with IEC 61850 data types. The need to carry out any additional data model. In the top-down engineering pro- next application execution checks for processing. cess, the system integrator selects the new input values and processes them appropriate library ICD files representing accordingly. ABB has created an internal IEC 61850 the Relion IED types and builds the sys- application guideline that defines the ap- tem configuration description (SCD) ac- If GOOSE was based on a non-native propriate default dataset names and cording to the substation design. In this IEC 61850 implementation, a conver- phase, the substation configuration al- sion from an internal data model to an ready includes all IEDs, the single-line IEC 61850 data model would be needed. The configuration diagram, the GOOSE links between the It would therefore be difficult to achieve devices and the event definitions. The the performance classes for protec- of IEDs belonging SCD file is imported to the IED tool where tion communication as stated in the the IEDs are parameterized and config- IEC 61850 standard. In some architec- to the Relion prod- ured according to the application/power tures, the processing of horizontal com- uct family is based system specifications ➔ 7. munication utilizes a different processor on a separate IED communication card on ICD files avail- In small and simple IEC 61850 based or an external gateway, which would substations, the system engineering of make the performance and configuration able in the IED the substation automation system can even more challenging ➔ 5. connectivity pack- be done using a bottom-up process. The workflow starts from the IED tool, which Reporting events to SCADA systems ages. creates the set of IEDs and exports the using standard buffered or unbuffered initial SCD file to the system configura- reporting services is based on the same uses; for example, StatNrml for protection tool. Using connectivity packages, mechanism that is implemented to de- tion events and StatUrg for primary the IED tool exports the SCD file, includ- tect GOOSE data changes. When a equipment value changes. In this way, ing a default single-line diagram and change of data is activated by an appli- different IEDs in the Relion family have datasets for event reporting. In many cation, for example, a protection start similar properties and are easier to con- cases, these values, as such, fit custom- signal in PTOC, the new data value and figure in the SA system. Default values er specifications. In the system configu-

20 ABB review special report 8 A KEMA certificate 9 IED members of the Relion family and their installation in ABB's UniGear MV switchgear

ration tool, the system engineer can add therefore capable of interoperating with GOOSE links and if required, customize other systems offering IED protocol ser- All Relion IEDs have the details of the single-line diagram and vices and which have SCL files exported event datasets. The system engineer ex- from the IED tool. A typical IEC 61850 been tested and ports the completed SCD file back to the certificate from KEMA is shown in ➔ 8. certiﬁ ed according relay setting tool where the IED's application configuration is finalized. To date the IEC 61850 standard confor- to the IEC 61850 mance test does not test IED perfor- In both top-down and bottom-up system mance. However, part 5 of the standard standard; for end engineering processes, the final result is defines, for example, a performance users and manu- an SCD file which is needed for the con- class P1, type 1A “Trip” for protection figuration of substation SCADA systems purposes using horizontal GOOSE com- facturers, this and gateways. The substation section of munication. According to this definition, the SCD file can be used as an informa- data exchange times between IEDs must means that no non- tion source to create the substation sin- not exceed 10 ms in distribution automa- conformities to the gle-line diagram, which in turn minimizes tion applications. any additional work needed for the de- standard have been sign of the substation’s graphical dia- Two IEDs, the REF630 and REF615, both gram. In this way, the SA system greatly members of the Relion family, were in- found in the behav- benefits from the self-descriptive feature stalled in ABB’s UniGear medium-voltage ior of the IEDs. of the IEC 61850 defined SCL. switchgear cubicles and tested according to the procedures stated in the Testing and using Relion IEDs IEC 62271-3 standard 2 ➔ 9. This stan- The capability of the native IEC 61850 dard, applicable to switchgear and con- implementation and the IED design have trol gear, specifies equipment for digital been thoroughly tested as part of the de- communication with other parts of the velopment validation – as have products substation and its impact on testing. already on the market – at the ABB UCA Specifically, the standard defines perfor- level B certified System Verification test mance test procedures with reference to Center (SVC) 1. The most important test the IEC 61850 performance classes and is the basic IEC 61850 conformance test. the requirements which the IED must ful- All Relion IEDs have been tested and fill for these applications.✎ certified according to the procedures defined in part 10 of the IEC 61850 stan- The test results more than proved the dard. For end users and manufacturers, concept. In fact the functional and per- the certificate states that no nonconfor- formance test results have been nothing mities to the standard have been found short of impressive. The Relion IEDs ful- in the behavior of the IEDs. The IEDs are filled the performance class defined by

Pushing the limits 21 Keep pushing the limits 10 IEC 62271-3 performance test results The introduction of the IEC 61850 standard and its achievement in enabling Protection blocking data exchange time between Relion® IEDs using hard wired signals (max) including protection activation time 32 ms device level interoperability is consid- Protection blocking data exchange time between Relion® IEDs using ered a major advancement over legacy IEC 61850 GOOSE (max) including protection activation time 16 ms and proprietary protocols. ABB’s native Signal transfer time between Relion® IEDs using hard IEC 61850 Relion product family imple- wired signals (max) 24 ms mentation demonstrates that interopera- Signal transfer time between Relion® IEDs using bility is only one goal that can be realized IEC 61850 GOOSE (max) 8 ms by this standard. The product architectures provide increased value and high performance, and are capable of meet- IEC 61850-5 for protection applications SCL. The complete topology of both the ing the most demanding application using GOOSE. In addition, they showed primary and secondary network of a sub- requirements. Another main goal of that the signaling between devices using station is described in the SCD file. This IEC 61850 is that it future proof’s a com- GOOSE was faster than with traditional information source can be used to auto- pany’s investment. This can only be done hardwired signals ➔ 10. matically generate graphical diagrams on when the products meet tomorrow’s an- the station HMI, such as the communi- ticipated performance requirement and The performance capability of the Relion cation network overview including super- engineering tools, and processes can be product family allows the customer to vision data and the station single-line di- easily extended in future station expan- fully exploit the benefits of the IEC 61850 agram. While this reduces the engineering sion. ABB continues to explore advanced standard in SA systems and smart grid work needed, it also improves quality applications and engineering improve- solutions. Based on a native implemen- with respect to consistency because of ments. Its GOOSE performance is best tation, the Relion product technology is the single information source being used. in its class and the goal is to continue to well prepared for tomorrow's challenges. Furthermore, maintenance and extension push the benefits of IEC 61850 well This surely puts ABB's solution in a pre- work becomes more efficient and the beyond what is now possible. eminent position among competitors efforts needed for testing can be auto- worldwide. mated or reduced. Moreover, based on the static information available in the SA application perspectives for SCD file together with the online status IEC 61850 transmission applications information from the substation IEDs, The benefits of IEC 61850 over tradition- new types of applications can be devel- Janne Starck al communication protocols are not oped. ABB Distribution Automation strictly limited to IEDs, open infrastruc- Vaasa, Finland tures and device interoperability in multi- One example of a new application al- [email protected] vendor systems. ready implemented in today’s products, and which is very beneficial to operators, Steven A. Kunsman is dynamic busbar coloring. The primary ABB Substation Automation ABB continues to network layout (ie, conducting equip- Raleigh, United States ment, objects) is known from the SCD [email protected] explore advanced file. Together with the actual positions and measurements reported from the applications and IEDs, all information is available to per- References form this task. [1] IEC 61850 (2003). Communication networks engineering im- and systems in substations, International Standard. provements and A more complex function or application [2] IEC 62271 (2006). High-voltage switchgear and is station interlocking. Algorithms can be controlgear. the goal is to implemented to dynamically adapt the [3] Hakala-Ranta, A., Rintamaki, O., Starck, J. (2009). Utilizing Possibilities of IEC 61850 and continue to push interlocking rules based on the current GOOSE. CIRED, Prague. substation network topology. Again, the the benefits of required information to perform this topology-based interlocking can be re- Footnotes IEC 61850 well trieved from the SCD file and the online 1 The UCA users group maintains the IEC 61850 data provided by the IEDs. standard and defines different levels of certified beyond what is IEC 61850 test centers. Independent labs are generally classed as level A test centers while now possible. And last but not least, the IEC 61850 manufacturer test labs, like ABB SVC, are LNs allow the implementation of distrib- certified as level B test centers. For more uted functions, which will no doubt lead information on SVC, please also read "Verified and validated" on pages 23–28 of this ABB To explain further, major features of the to new applications in the not too distant Review Special Report standard that are used include the self- future. 2 The tests were witnessed and reported by describing IEDs and the standardized KEMA.

22 ABB review special report Verified and validated

STEPHAN GERSPACH, PETER WEBER – When the IEC 61850 standard was ABB has its own introduced, ABB not only implemented it in its product portfolio, but also system verification established a system verifi cation and validation center (SVC), to verify correct implementation. In this test center, each and every product, and vaildation center system component, application and tool is tested in a real-life system environment to demonstrate its specifi ed functionality and performance. Complete systems are verifi ed to ensure that they fully meet the requirements in terms of communication, integration, functionality, security and performance.

Verified and validated 23 Validation means: 1 ABB’s system verification and validation – Is the right product being built? center (SVC) – Is it meeting the operational need in

the designated environment? All actions of the SVC are focused on the following targets: Tests performed as part of SVC validation focus on the behavior of the product – Ensure a common understanding for the system integration of products in the specified system environment. – Ensure a common understanding for the engineering process. Both verification and validation are nec- – Aim at a consistent philosophy within essary throughout the product-develop- ABB systems and products – Identify and initiate the closing of gaps ment cycle ➔ 2. between system requirements and product features UCAIug – Improve the quality of the system The UCA 1 International Users Group solution in architecture, integration and performance (UCAIug) is a not-for-profit consortium of – Decrease demand for specialized leading utilities and their supplier compa- expertise within a customer system project nies. UCAIug is dedicated to promoting – Build up integral know how in testing and the integration and interoperability of system integration of third party products – Reduce cost and execution time of electric/gas/water utility systems through customer projects technology based on international standards. The group is an international or- The SVC’s purpose is to ensure the high ganization and strongly supports open quality of ABB’s system automation system solutions and provide a platform for the standards and the free exchange of in- exchange of experience between IEC 61850 formation. One activity of UCAIug is the experts within ABB. provision of a forum in which members coordinate their efforts in relation to the he purpose and scope of SVC various technical committees. Although The editor of the Testing Quality Assur- is summarized in ➔ 1. The cen- the group does not write standards as ance Program (QAP) was also the editor ter does not only test individu- such, its activities affect the definition of of Part 10, “Testing Requirements”, of T al devices, but also tests their standards as well as the implementation the IEC 61850 document. Furthermore, integration into larger systems and fur- of testing and product certification pro- many members of TC57/WG10 are on thermore provides support and under- grams. One focus has been on the “Com- UCAIug’s Technical Subcommittee for standing of the standard, leading to its munication Networks and Systems in the Resolution of 61850 Issues (Tissues). improved integration and implementa- Substations" section of IEC 61850. The group works closely with standards tion. organizations to support technology transfer, resolution of issues and assists Verification versus validation Each and every users in the testing and implementation The relative concepts of verification and of products. One major focus of UCAI- validation are sometimes a cause of con- product, system ug’s charter is the Testing Quality Assur- fusion. component, appli- ance Program (QAP). Verification means: cation and tool is A recognized IEC 61850 conformance test – Is the product being built according to center the original specification? tested in a real-life UCAIug has qualified SVC as an – Are the specified requirements being IEC 61850 test facility and competence met? system environ- centre. SVC is thereby officially qualified ment to demon- to test and certify the IEC 61850 confor- Verification testing should thus be about mity of products and confer the users’ the product’s conformance to the origi- strate its specified group label to them. nal specification. functionality and SVC is represented on UCA’s IEC 61850 In SVC verification, all tests performed performance. testing subcommittee. This strengthens assure the product accords with the de- the center’s ability to support upcoming fined substation automation require- IEC 61850 test procedures and keeps it ments. These requirements are defined UCAIug complements the activities of informed about UCA- and IEC-driven and reviewed by a group of experts ap- international standards organizations. changes regarding IEC 61850 testing. proximately once per year and have to For example, UCAIug works closely with be implemented in each ABB product. IEC. The convener of IEC TC57/WG10

(IEC 61850) is on several UCAIug com- Footnotes mittees and is an advisor to their board. 1 UCA: Utility Communications Architecture

24 ABB review special report 2 Both verification and validation are part of the product-development cycle. 3 The fact that products conform to the standard does not guarantee interoperability.

System unit products (SAP) Verification and validation IEC 61850 – Engineering SA products with IEC 61850 – Functionality Company C profile ready for gate 5 – Performance SVC – Redundancy System integration, – Security verification and validation Based on “most common use” Interoperable Interoperatbility profile – ABB-products rd – System solutions – 3 party products (Control, Protection, SAS) in ABB systems – System engineering tools and processes – Tools – Definition of system functionality IEC 61850 conformance Company A profile System unit systems (SAS) – IED’s Company B profile – Tools

Various profiles from different products may conform to the standard but may still not be totally interoperable.

Beyond conformance testing: The fact that standard products from dif- system verification and validation ferent suppliers or different products Once a product has passed conformance from the same supplier conform to the testing, it can be accepted for formal standard is in itself no guarantee for their system verification and validation. interoperability. The reason for this is that communication profiles can differ. Interoperability Interoperability testing is neither part of A communication profile defines the the scope of the standard nor is it tested mandatory subset of a standard con- by all UCAIug accredited test centers or sisting of the selected options that are implemented. Thus various pro- An interoperability test looks files from different products may con- at the dynamic interaction form to the stan- of at least two IEDs in a sub- dard but may still not be totally in- station automation system teroperable ➔ 3.

covering (as far as possible) It is the responsi- all potential configurations. bility of the system integrator to check the interoperability in all procedures. However, the verifica- of two or more products. The require- tion of conformance is a very important ments for this are based on the confor- milestone. mance statements of the different products and the system functionality

Verified and validated 25 4 Configuration of the SVC system

SVC system configuration – overview single lines

245 kV voltage level D1 transmission 132 kV voltage level E1 sub transmission

33 kV voltage level H1 distribution 11 kV voltage level H1 distribution

All configurations are based on system unit solutions to ensure "most common use" of the IEDs/SAS

required. For example, one vendor might and XML) is also imporant here. As a The goal of implement only GOOSE 2 and a second side effect, this testing also permits the vendor might implement only GSSE 3. system configuration tool and its inter- IEC 61850 is the Both devices would pass conformance face with the product tools to be veri- tests but would not be able to interoper- fied. interoperability ate. of IEDs in SASs. Test setup, SVC environment An interoperability test looks at the dy- The SVC installation represents all areas The system test namic interaction of at least two IEDs in of ABB’s system-automation activities a substation automation system (SAS) from distribution to transmission appli- should therefore covering (as far as possible) all potential cations (245 kV, 132 kV, 33 kV, 11 kV). All be part of R&D configurations. This is especially impor- configurations are based on system-unit tant for their interaction in executing dis- solutions to ensure ”most common use“ and conformance tributed functions. Furthermore, it per- of the IEDs/SAS. mits the verification of the performance testing. of services provided by communication The primary process is completely simu- equipment such as switches (including lated by process-simulation equipment. delays caused). This test must be per- The related single-line diagrams are formed independently of specific projects shown in ➔ 4. as a kind of type test for the system. Such testing will reduce the risks for cus- From product to lifecycle testing of tomer projects considerably. The interop- SA systems erabillity of the different configuration It is not possible to consider the lifecycle and engineering tools (based on SCL of any SAS without taking into account the lifecycles of all integrated products. The process of creating a substation Footnotes 2 GOOSE: Generic Object Oriented Substation auto mation system involves numerous Event, A data-set format permitting the tests, from the development and produc- exchange of a wide range of possible common tion of an individual IED to the comple- data. tion of the system. Testing improves the 3 GSSE: Generic Substation Status Event. In contrast to GOOSE this supports only a fixed quality and reduces costly risks both for data structure. the supplier and the users.

26 ABB review special report 5 Testing sequence for product testing by R&D, performed 7 Testing sequence for customer project independently of customer project

R&D testing sequence Customer project testing sequence

Device type test Integration test System test Factory test FAT Site test SAT

The base for reliable in-house testing is 6 Overview of R&D testing sequence the quality system of the manufacturer and supplier according to ISO 9001/9002 Test Pre-condition Executed tests Result (as far as applicable). The life-cycle testing related to sequence can be divided into two parts: Device Product Specification and Function and type tests are performed Clearance for – Testing independent of the customer- Type Test development of continuously by the R&D of the Integration new functions … manufacturer Test specific project, handled entirely by … based on an The product with its functions is tested the R&D organization. existing platform as stand-alone unit (“white box”) or IEC 61850 conformance tests – Testing of configurations specific to … based on a the customer project, completely new platform handled by the system supplier or

Integration Product Device type tests Tests are performed in a small, Clearance for system integrator in cooperation with test are finalized well-defined and normally fixed IEC System Test the end-user. successfully 61850 test system Test of IEC 61850 communications and verification of tools including Testing independent of the customer-specific commissioning and application engineering aspects project Focus on the products and its interfaces to the rest of the system The test sequence for the standalone (“Black box”) product (which can be the device or the IED configuration tool will be tested also regarding IEC 61850 aspects like IED) starts with the device’s type test and generation and exchange of SCL Files

System System Integration tests – Verification of products with a clear Release for test are finalized focus on IEC 61850 system aspects use in Several hundred successfully – Tools and their interaction in the customer engineering process (exchange projects IEC 61850 SCL files) IEDs can be simu- – Verification of the system under normal operation, avalanche and lated in the SVC, fault conditions (evaluation IEC 61850 system performance) – System-security testing. helping identify the

Manufac- Product All tests up to SW has dedicated manufacturing test Product limitations of SA turing Test system test available for finalized customer successfully projects Systems.

ends with its integration test ➔ 5. The conformance test is the type test relating to standards such as IEC 61850. The successful passing of type tests is the prerequisite to begin integration testing. Integration testing involves testing the new product in a small and fixed test system. Type tests and integration tests are performed (as a minimum) by the product supplier and (if applicable and requested) by an independent test authority. Normally, the conformance of the IED is confirmed by the issuing of a certificate. In addition, routine tests or manufacturing tests performed in the production chain ensure a constant quality of delivered devices.

The goal of IEC 61850 is the interoperability of IEDs in SASs. Therefore, the sys-

Verified and validated 27 dures for all labs in accordance with 8 Overview of testing sequence for customer project IEC 61850-10 and the UCA Quality As- surance Program (Level A independent Test Pre-condition Executed tests Result lab, Level B manufacturer’s lab). related to

Factory test Customer All tests up to Configuration of the full system The substation The SVC is an active member of UCA project system test Project assembled and pre-tested automation finalized especially regarding project specific system is inter national users group and the successfully and parts; parts not available in the factory running as IEC 61850 testing subcommittee. In products available are simulated on IEC 61850 network. specified for projects Tests performed according to the 2007, SVC extended the test centre to agreed test plan. fulfill new upcoming requirements. Be- sides the verification and validation of Factory Customer All factory tests System test witnessed by the customer Clearance for acceptance project are finalized shipping, ABB products against IEC 61850-8-1, test (FAT) successfully commissioning activities were extended to third party and SAT IED’s, redundancy concepts, and Site test Customer FAT finalized Complete system goes into operation, The complete IEC 61850-9-2. project successfully. fully functional including all connections substation All system to switchgear and remote systems and automation components are work places system is Today the SVC test system comprises a installed. Last adaptations if needed running as specified considerable quantity of relays from ABB as well as from several other manufactur- Site Customer System Complete system will be witnessed by System handed ers. In addition, several hundred IEDs acceptance project commissioned the customer. over to the test on-site customer, incl can be simulated, helping identify the (SAT) ﬁ nal SCD ﬁ le! limitations of SA Systems in terms of architecture, engineering processes, engineering tools, system functionality, system security and performance.

SVC helps ensure the high quality of ABB’s IEC 61850 offerings through its verification and validation capabilities and provide a platform for the exchange of experience between IEC 61850 experts within ABB. SVC actively influences further IEC 61850 developments both within and outside ABB.

tem test should also be part of the R&D site tests are carried out to prepare the testing sequence and conformance test- system for the site acceptance test (SAT). ing. However, as explained above, both The testing sequence for customer proj- the content of IEC 61850-10 and the de- ects consists of project-related tests, tailed test procedures defined by the based on the specification for the system UCAIug only focus on IED (single prod- ordered. Such tests are performed by uct) testing. Today’s conformance certifi- the system supplier or system integrator cates are thus no guarantee for interop- and witnessed by the customer. These erability from a system perspective ➔ 6. tests confirm that the delivered individual SAS is running as specified ➔ 8. In summary: SVC takes care of that part of system testing not covered by the pre- Successful operation of the test center vious quality assurance steps. Following the planning and build-up phase, by mid 2005, SVC was ready for Testing of configurations specific to operation. In 2006, the center was quali- customer-projects fied by the UCAIug for use as an Stephan Gerspach The customer-project testing sequence ➔ 7 IEC 61850 test facility and competence Peter Weber starts with the factory test. This is a proj- centre. SVC was the first manufacturer’s ABB Substation Automation Systems ect-related test that prepares the cus- test lab in the world to earn this level of Baden, Switzerland tomized system for the factory accep- qualification. It meets the high quality [email protected] tance test (FAT). Following the installation, levels set out for common test proce- [email protected]

28 ABB review special report A testing environment

ABB’s comprehensive suite of software testing and commissioning tools for substation automation systems

TETSUJI MAEDA – The testing and he IEC 61850 standard is built the IEC 61850 system integration pro- commissioning of IEC 61850-based mainly on known technologies cess was needed. substation automation systems intro- such as extensible markup duce new challenges and demands T language (XML), Ethernet, ABB’s approach, taken during the initial for advanced software applications. manufacturing messaging specification phase of the introduction of IEC 61850, ABB recognized this at a very early (MMS) and transmission control proto- was to take the existing expert tools and stage of the introduction of IEC 61850 col/Internet protocol (TCP/IP), each of identify clear functional gaps in them. and redesigned the engineering and which have a number of well established This information was then used to de- testing tool landscape to serve these software tools to handle them. Why then velop (and afterwards continuously im- purposes. was it initially quite challenging to deal prove) a comprehensive suite of software with IEC 61850-based systems? testing tools for communication, and protection and control application spe- The crux of the matter lies in the ap- cialists in the field of substation automa- proach taken. IEC 61850 seamlessly tion. combines the underlying technology components and ABB developed the Integrated application aspects from an integral Testing Toolbox, a software system point of view. Existing tools, tool suite used to manage and however, were de- support the IEC 61850 sys- signed to focus on specialized single tem integration process and tasks, for example communication which has proven invaluable analysis, and leave in many turnkey SA projects. out any substation automation application aspects, and are therefore no lon- With the benefit of active participation in ger capable of addressing today’s chal- the IEC 61850 standardization group on lenges. To overcome this problem, it was its side combined with its in-depth knowl- evident a new generation of software edge and experience in designing and tools to efficiently manage and support building substation automation (SA) sys-

A testing environment 29 1 Typical contents of a system 2 Application areas for analytical and 3 Typical features of a diagnosis configuration description (SCD) file diagnostic tools and analysis tool

– Description of complete substation – The use of project specific data (SCD file) topology and primary equipment for configuration − All protection and control devices − Establishing an online communication (servers), and station level automation connection to the IEDs using either static system (clients) including the standardized or dynamic configured data sets and data models of their functionality control blocks for reports − All communication addresses IEC 61850-8-1 − Visualizing the health of the running system − Complete horizontal and vertical data-flow − Checking data consistencies and within the system configuration revisions against the SCD file − Relationship between SA functionality − Analyzing and verifying running and the primary equipment applications IECIE 61850-9-1 − Decoding Ethernet traffic to the substation automation (SA) domain language based on the SCD file − Showing functional (system-oriented) or product-oriented addressing of logged data

tems, ABB developed the Integrated plete SA system ➔ 1. For creation and diagnosis and analysis of the running Testing Toolbox (ITT), a tool suite which maintenance, an IEC 61850 system con- applications. has proven invaluable in over 900 turnkey figuration tool is required. SA projects delivered by the company. Conformance testing From the system point of view, the inter- One very important aspect of IEC 61850 From the very beginning, ABB’s approach faces for each device (client or server) system integration is the selection of was to build a tool suite that would hide connected to the system are described standard complaint intelligent electronic the complexity of the technology compo- in this file. This makes the complete SCD devices (IEDs). Compliant in the sense nents IEC 61850 is built on and focus on file the central part of the IEC 61850 sys- that all selected IEDs have been tested displaying application relevant data only. tem documentation, which makes it in- to ensure that they conform to the While having an in-depth knowledge of teresting to be used for all future activi- IEC 61850 standard and are officially the technologies was necessary to ties performed on the SA system, such certified by a test center which itself is achieve this, the complexity lay in creat- as testing, maintenance and extensions. accredited by the UCA international using the interfaces that would enable the The engineer no longer needs to worry ers group. This certification covers the application and display layer of the test- about error-prone manual configuration verification of the data model, the stan- ing tool to be tailored to project specific of the testing and analysis tool environ- dardized documentation and a black-box configuration data. test of all the communication services the IED supports. The conformance test Substation configuration language ABB’S approach gives a minimum guarantee that the se- (SCL) lected IEDs will interoperate with other One of the greatest achievements of the was to build a tool certified devices if they are configured IEC 61850 standard and one of the and loaded correctly within the system. things that differentiates it from other suite that would This prerequisite relieves the testing tools communication standards was the intro- hide the complexity from research and development related duction of the substation configuration bits and bytes analysis even more. language (SCL). SCL makes it possible of the technology to create files that are used for the ex- Revealing inconsistencies change of configuration data (eg, stan- components There are often situations, specifically dardized object models and data flow IEC 61850 is built during the testing and commissioning configurations of devices in a system) phase of an IEC 61850 based system, between engineering tools. Several file on and focus on where temporary inconsistencies due to types have been defined in IEC 61850, stepwise integration, the configuration of and the content of each type depends displaying applica- systems parts or simply human error re- on the role of a specific tool (e.g., system tion relevant data sult in a situation where distributed func- configuration tool or device configuration tions do not interoperate. Debugging can tool) that it is created for and the different only. be very time consuming and often re- evolution phases of the system integra- quires expert know-how, which is not al- tion process. ways available. To handle such situations ment; all he has to do is simply import ABB has developed a tool called the The system configuration description the project-specific SCD file into the test- ITT600 SA Explorer. It simplifies the diag- (SCD) file is one such file type, and is de- ing tool. This in turn focuses the effort to nosis and troubleshooting of IEC 61850- fined as the master document of a com- where it is most needed, on functional based SA systems by combining a set of

30 ABB review special report 4 Consistency check – comparison of an SCD file with online 5 Decoding the horizontal Ethernet traffic with an IEC 61850 data using ITT600 analyzer (ITT600)

powerful online diagnostic tools with Tools support processes built-in intelligence to interpret IEC 61850 To support the ABB project execution The ITT600 SA data. Typical application areas within an process the IEC 61850 simulation tool SA system where the ITT600 SA Explorer out of the ITT tool suite has proven to be Explorer simplifies can be of great value is shown in ➔ 2, very useful. Specifically during engineer- while typical features of a diagnostic and ing phases or factory acceptance tests the diagnosis and analytical tool are listed in ➔ 3. when not all system components are troubleshooting of physically available but nevertheless ap- Narrowing down a problem source basi- plication tests must proceed, simulation IEC 61850-based cally requires some quick consistency of non-existing devices is essential for checks ➔ 4. One such check that can im- efficient workflows. SA systems by mediately reveal inconsistencies involves combining a set comparing the correct offline configura- The IEC 61850 simulation tool can be tion with the online communication – as connected either to the system bus or of powerful online it actually is – world. directly to an IED ➔ 7. The SCD file that has been created and used during the diagnostic tools The comprehensive decoding by ABB’s engineering process of the specific SA with built-in intelli- ITT600 SA Explorer of an IEC 61850 ge- system, and which is now part of the neric object oriented substation event common system documentation any en- gence to interpret (GOOSE) message, which is used for gineer should have available when he horizontal real-time communication be- goes on site, is then loaded into the IEC 61850 data. tween multiple IEDs, is illustrated in ➔ 5. tool. In both cases the tool could simu- The on-screen display of clear text pro- late one or more user selected clients/ tocol and application information, with servers based on the interface descrip- the mapping of it to the IEC 61850 tion extracted from the SCD file. If the SCD file in the background, gives an ex- SCD file is missing or incomplete, then cellent view of the corresponding online the engineering and configuration work Ethernet traffic. Additional checks on the has to be completed first. Based on this IEC 61850 object model reveal potential simulation, application tests on real sys- sources of interoperability problems. tem components can be performed. If the process bus or additional injection Tools visualize applications hardware is used, then closed loop test- Another way of supporting the testing of ing of an IED is possible. Typical features distributed functions is shown in ➔ 6. of a simulation tool are summarized Here the GOOSE messages from multi- in ➔ 8. ple IEDs can be displayed along a common timeline, making it easy to follow the Various substation automation projects interaction of various applications, such have shown that the most obvious and as interlocking or double command common application for using GOOSE blocking. messages is interlocking. The horizontal GOOSE service uses publisher-subscrib- er communication, which corresponds to

A testing environment 31 6 Horizontal GOOSE communication between multiple IEDs with ITT600 7 Application areas for simulation tools

IEC 61850-8-1

IEC 61850-8-1 IED simulation IEC 61850-9-2

IEC 61850-9-2 Merging unit simulation

vertical server-client communication. In a neering and reloading of the configura- 8 Typical features of a simulation tool situation when a specific IED “publishes” tion. data for interlocking, eg, switch positions – Uses project specific data (SCD file) for have failed (and therefore the IED must A growing trend configuration be taken out of service or disconnected The IEC 61850 standard is complex and − An IED specific configuration can be from the communication bus), the sub- cannot be applied without any signifi- extracted from the SCD file cant software sup- − The consistent simulation of selected IEDs − Real life simulation of communication port. The degrees services There is a strong trend toward of freedom and − Horizontal communication – repeated new possibilities sending of GOOSE messages and cyclic the use of more modern com- that it offers, com- sending of sampled values − Vertical communication – spontaneous bined with varying munication technology to dis- sending of reports levels of IEC 61850 − Setting any data configured in the IEDs tribute critical data and this integration, both in selected for simulation the configuration − Tailored scripts for the simulation of simple applications, such as control applications demands more advanced tools and IEDs double command blocking from different sup- integration and verification pliers, emphasize Note: Receiving IEDs and clients cannot see the challenge even any difference between simulated and real processes. data on the bus the more. scribers of the now missing data on the Evidently, the strong trend toward the bus must be operated in an interlock- use of more modern communication override mode. This is because applica- technology to distribute mission critical tions running on the IEDs usually refuse data demands very advanced integration operations with obsolete data that have and verification processes. To manage not been refreshed in time by the pub- these challenges, engineering, testing lisher. Maintenance concepts for such and commissioning tools have been de- situations must be considered in order to veloped which incorporate all the possi- ensure that the remaining healthy or un- bilities offered by the IEC 61850 stan- affected parts of the system continue to dard. They have been proven to facilitate work undisturbed. This type of situation and ensure the high standards of ABB's can typically occur during the testing and project execution. commissioning phase where the sequen- Tetsuji Maeda tial adding of bays – including their con- ABB Substation Automation Systems trol and protection IEDs – to an energized Baden, Switzerland system should not lead to major re-engi- [email protected]

32 ABB review special report Next generation substations

HANS-ERIK OLOVSSON, THOMAS WERNER, PETER RIETMANN – Substations Impact of the process are a crucial element for the transmission and distribution of electrical bus energy. Their primary role is to transfer and transform electrical energy (stepping-up or down the voltage). This is done with high voltage switching equipment and power transformers. In order to protect and control, instrument transformers supply the status of the primary system to secondary equipment. ABB has the expertise, experience and technology to design and build substations of any size.

Next generation substations 33 1 Development of secondary systems for substations

1975 1995 2010 Year

Traditional SA with station & SA with station bus MMI / control board process bus

NCC NCC NCC Network control

RTU event recording Copper cable 1 protection Gateway/ SAS Gateway/ SAS protocol conv. protocol conv. Station level SCADA-distribution, metering

Station bus Station bus to other bays to other bays Copper cables Process bus

GIS GIS Bay level GIS IED IED Process level IED IED Sensors & Bay cubicleCopper cables Bay cubicle Copper cables Bay cubicle actuators

disconnecting function was still required creases gradually over time the require- but more for maintenance of overhead ment for a secondary system to support lines and power transformers. This led to both CIT and non-conventional instru- the development of two types of solu- ment transformers (NCIT) during this tions with disconnect switches (DSs) in- transition period will become apparent. ince the first substations were tegrated with the CB function. One was This requirement is obvious when ex- built more than 100 years a hybrid (PASSTM), which has a separate tending substations, since the new bays ago, there has been tremen- DS design in the same gas compartment will contain NCITs and existing bays will S dous development of both the as the CB. Another one was the discon- contain CITs. primary equipment (switchgear, power necting CB (DCB), which uses the same transformers, etc.) and the secondary contact for both breaking and discon- The greatest physical impact of process equipment (protection, control and me- necting functions. Due to the reduced bus will be on AIS with live tank CBs or tering, etc). maintenance of CBs and the protection DCBs, where the measuring transform-

by SF6 gas of the DSs’ primary contacts ers can be integrated in the CB or DCB, ABB has been engineering and con- from external pollution, the availability allowing the substation’s footprint to be structing substations from their very be- and reliability of AIS substations using reduced substantially. For hybrid and GIS ginning and has delivered more substa- hybrid or DCB has increased. Further- solutions, the footprint reduction will be tions than any other supplier. The first more the footprint of AIS substations us- less significant as the insulation distance substations deployed had air-insulated ing this technique can now be reduced between primary and secondary equip- switchgear (AIS). The development focus to about 50 percent. ment is already reduced by the use of

for AIS was on circuit breaker (CB) tech- SF6 gas. However, the process bus will nology that would increase reliability and The latest step in substation develop- enable the use of non conventional volt- reduce maintenance. In 1965 ABB deliv- ment comes with the introduction of the age transformers (VTs) making equip- ered the world’s first substation with gas- standard IEC 61850-9-2 for the process ment much lighter (a traditional VT is insulated switchgear (GIS). With GIS the bus interface. For footprint of substations can be reduced primary equipment, by about 60 percent, by housing all pri- this means con- The latest step in substation

mary conductors within earthed SF6 gas- ventional instru- insulated aluminum tubes. Over the years ment transformers development comes with the new generations of GIS have been devel- (CIT) that use cop- introduction of the standard oped, providing today’s GIS with, among per, iron and insu- other things, a considerably smaller foot- lation material pro- IEC 61850-9-2 for the pro- print (for more detail see “Compact and viding analogue reliable” on pages 92-98 of ABB Review values (1 A, 110 V) cess bus interface. issue 1/2009). can be exchanged for fiber-optic sensors that send a pro- quite heavy). Further, the manufacturing Due to the reduced maintenance of CBs, cess bus digital signal via fiber optic ca- time can be reduced since all adapta- new substation design principles bles to metering, protection and control tions can be done with software and the emerged for AIS in the late 1990s. The equipment. As the use of sensors in- hardware can be standardized.

34 ABB review special report ing can be made at the factory before 2 Topology of substation secondary systems delivery to site, leading to a secondary system of higher overall quality. Also the Operator Engineering workplace workplace Control center architecture of the secondary systems will change compared with today’s substations. The bay house principle, in Gateway which the relay and control equipment are decentralized in the switchyard, will IEC 61850 disappear since there will be no copper Switch station bus connections between the switchgear apparatus and metering, protection and control devices, as the process devices Bay Bay IED A IED B IED A IED B can now be mounted directly onto the controller controller primary apparatus. The central control room of the substation will become the IEC 61850 process bus natural location for relay and control equipment connected by fiber optics to

Conventional Modern Modern Modern marshalling cubicles close to the primary switchgear CT / VT’s switchgear CT / VT’s equipment. Interface equipment, such as merging units will be located in the marshalling cubicle.

The introduction of the process bus will IEC 61850 also includes a new standard Process Bus – connecting the also mean changes regarding interfaces for the communication between the high- last mile for CBs and DSs. All signals, digital and voltage apparatus and IEDs, the so called The widely accepted standard IEC 61850 analogue, to and from the control room process bus using the 9-2 profile and defines the complete communications can now be run via process bus in a few communications architecture. The pro- architecture for station and process bus optical fibers instead of tons of copper cess bus has high requirements on band- to ensure a high level of device interoper- cables. The CBs and DSs will include I/O width since it will be used to transfer ability. The standard’s data models and electronics for signal transfer from opti- continuous sampled values from the pri- communication services are the key to cal to electrical and vice versa. mary process. interoperability between multi-vendor substation protection, control devices Secondary side developments On the secondary equipment side the (IEDs), and station computers (gateways) The digital (r)evolution has provided tech- most obvious physical change will be via Ethernet. A substation’s secondary nical solutions for substations. Digital from copper cables to fiber optic cables. system with station and bay level devices technology was first implemented in sub- The massive reduction of secondary ca- communicating over the so-called sta- stations in the 1970s, providing commu- bling will mean reduced cost for cables tion bus has been widely adopted by nication channels from the substations utilities and vendors ➔ 2. to control centers ➔ 1. The widely accept- The cyclic exchange of sampled values, During the early 1990s, with the in- ie, between NCIT and IED devices for creased capacity and speed of comput- ed IEC 61850 protection functions and other purposes ing and communications technology, is also defined in the standard (part 9-2). digital protection and control devices, standard defines The interconnection between sensors, the so called IEDs (intelligent electronic the complete com- actuators, protection and control devic- devices) were installed in substations. es, is referred to as "process bus" (lower Digital communication between the IEDs munications archi- part ➔ 3). This means that not only ana- was introduced using station bus with log data, but also status information from protocols that differed between manu- tecture for station primary switchgear to IEDs, as well as facturers ➔ 1. and process bus to command signals from IEDs to the primary switchgear can be exchanged. This With the introduction of the IEC 61850 ensure a high level interconnection between sensors, actua- standard, substations are moving into a tors, protection and control devices, is new era regarding communications. All of device interoper- referred to as the “process bus” (lower manufacturers can adapt their products ability. part ➔ 2). A vendor-agreed subset under to the same communication model and the umbrella of the utility communication protocol, making it possible for different architecture (UCA) foundation has been manufacturers IEDs to “talk with each and associated equipment such as cable in place since 2004. This subset speci- other” and thus interoperate on the same trenches and installation material. Man fies the exchange of sampled values and station bus, replacing all previous propri- hours for installation and testing on-site is called IEC 61850-9-2LE (light edition). etary protocols. will be reduced and more thorough test- Today, pilot projects utilizing the process

Next generation substations 35 formation and commands through the 3 Control system architecture and its life times process bus.

Network control center Life-cycle – Operator workplaces 6-10 years The location of the electronics depends – SCADA servers – Front-ends on a number of criteria. Primary apparatus with electronics integrated in the drive

Remote communication Life-cycle cubicles is one possibility. On the other – Communication equipment 6-20 years hand, it must be possible to handle cases where the primary equipment does not Substation level Life-cycle – Substation HSI 7-10 years yet contain communication interfaces. – Substation gateway Here, system integrators need to mount the process electronics as near as pos- Bay level Life-cycle sible to the primary equipment, eg, to lo- – Secondary equipment 15-25 years – P & C IEDs cate them within the marshalling kiosks.

Primary equipment Life-cycle Interoperability and architecture on – Switchgear 30-40 years – Transformers the process bus Field experience with sensors has been gathered for more than ten years now, mostly in conjunction with protection and bus for sampled values are in operation control equipment from the same vendor. Both new installa- already and the execution of the first For the process bus, utilities are execut- commercial project for Powerlink Queen- ing an increasing number of pilot installations as well as the sland’s Loganlea 275 kV substation is tions in order to gain experience. Wide- well underway. spread commercial adoption has not yet increasing number taken place. of secondary retro- Modern substations, both new installations as well as the increasing number of Interoperability fit or extension secondary retrofit or extensions installa- Both the communication architectures tions will see both sensor and conven- (9-2, 9-2LE) and the steady-state behav- installations will tional instrument transformer technolo- ior of sensors are defined (IEC 60044). see both sensor gies side-by-side. The same applies for The transient signal response of merging handling signaling commands and posi- units has not yet been standardized. The and conventional tion indications to and from primary latter defines the extent (in terms of angle switchgear. and amplitude) to which a merging unit instrument trans- output signal is allowed to differ from its former technolo- Realizing the process bus corresponding input signal. This is es- With the process bus, new devices such sential since protection algorithms and gies side-by-side. as merging units (MU) for the optical sen- the corresponding data acquisition hard- sors, as well interface units for conven- ware and filtering has so far been “inter- tional instrument transformers, are need- connected” within one device, the IED. ed. In addition switchgear controllers for Now those parts are split up into differ- circuit breakers and disconnectors ent physical devices that can be supplied (“Breaker IEDs”) will be introduced. from different vendors, and therefore a Those devices can be seen as conver- transient signal response standard is es- sion “endpoints” to and from the primary sential for correct functioning. A newly process to the secondary equipment. formed working group with Cigré (B5.24) is addressing signal interoperability and A merging unit, as the name implies, results are expected during 2011. merges various input signals into one digital output signal, eg, three phase Process bus communication architectures sensors can have one common electron- Several different process bus architec- ic unit, which transform the optical sig- tures exist. In fact, depending on factors nals from the sensors into digital sampled such as distance (location of MUs and values and make them available on the IEDs), communication capabilities (single process bus. port, multiple ports), available network bandwidth, availability considerations or A switchgear controller contains elec- communication topologies, such as tronics for handling binary input and out- point-to-point, star or ring configurations put signals (signal and power contacts). the process bus architecture can vary The device will communicate status in- considerably. Both utilities and vendors

36 ABB review special report are working on guidelines for reference system or SCADA, allows continuous equipment such as cable trenches and topologies for such architectures. monitoring of all connected secondary installation material. Testing at site will be equipment. very much reduced and more thorough Refurbishment and extension of testing can be made at the factory. This existing SA systems Increased system and personnel safety will lead to higher quality overall and a The typical life cycle of the primary and Remote control combined with authority reduced time at site. secondary equipment of a substation is and rule-based access and remote test- illustrated in ➔ 3. During the life time of ing, allows increased system safety and Changing to optical sensors (NCIT) will the primary equipment the entire sec- security. Personnel safety is increased increase personnel safety since there will ondary equipment or parts of the sec- since more tests can be done without be no risk of injuries due to the inadver- ondary equipment are replaced between putting the test personnel close to pri- tent opening of current transformer sec- one to four times. mary equipment or without the risk of ondary electrical circuits. inadvertently opening current transform- The most interesting and future prrof mi- er (CT) circuits. For retrofit, the possibility of installing the gration scenarios will be the ones in new 9-2 process bus system in parallel which IEC 61850-based equipment is in- Increased functionality with the existing system will allow the troduced in steps to already installed Fully distributed system architecture substation to remain in service during the systems. There are two main driving fac- coupled with un-restricted communica- main part of the work. This will be a big tors for this: Retrofit and extension of tion and process capability enables the advantage, reducing outages to a mini- substations or of system functionality. system to add new functions easily with mum, during the retrofit process. With the long life of primary equipment zero or minimal outage time, giving the compared to secondary equipment, user additional benefit with respect to there will be a continuous need for sec- safe and secure system operation. ondary equipment replacement, while retaining the existing primary equip- Interoperability ment. By deploying the IEC 61850 compliant solution 1, interoperability with regard to By introducing the process bus it will be communications with other manufactur- possible to make a very efficient retrofit er’s equipment can be achieved. The of protection and control systems with benefit to customers is that IEDs from minimum outage. While keeping the sub- different suppliers can be mixed on the station in service using the old equip- same bus without concern for communi- ment, the new IEC 61850-9-2-based cation incompatibilities. equipment can be installed and tested using new fiber optic cables laid in paral- Prospects lel to existing copper cables. A short out- The introduction of the IEC 61850-9-2 age is necessary to connect the new process bus standard in substations will protection and control equipment to the give the following main advantages: existing primary equipment. When the substation is taken into service again the The footprint of primary switchgear can old protection and control equipment to- be reduced since fiber optic sensors gether with all copper cabling can be re- (NCIT) can replace conventional measur- moved or can remain. ing transformers. This will be most pro- nounced for air-insulated substations, Refurbishment drivers especially when using live tank CBs. Hans-Erik Olovsson There are different reasons for refurbish- ABB Substations ing a substation or parts thereof. These Traditional VTs are quite a heavy part of Västerås, Sweden can depend on the starting point (eg, GIS and by using new sensor technology [email protected] whether starting from a conventional re- for voltage measurement the equipment mote terminal unit, RTU, solution or from can be made much lighter. Further, the Thomas Werner a proprietary numerical control system). manufacturing time can be reduced since Peter Rietmann All of the below drivers may be applicable all adaptations of NCIT can be done with ABB Substation Automation Systems or only a selection of them. software and their hardware can be stan- Baden, Switzerland dardized leading to an overall shorter de- [email protected] Increase system availability livery time. [email protected] Exchanging of electromechanical, static or old fashioned digital secondary equip- On the secondary side the massive re- ment with modern numerical devices duction of secondary cabling by going Footnote bundled to a real-time communication from a lot of copper cables to a few fiber 1 There are a number of solutions slightly different network and connected to a higher level optic communication cables will mean in architecture etc. that will be compliant with system such as a substation automation reduced costs for cables and associated IEC 61850.

Next generation substations 37 Case studies IEC 61850 at work

The goal of IEC 61850 is to facilitate interoperability of substation devices while simplifying engineering and maintenance. The examples described in this section present some of the standard’s successes.

was commissioned, the new IEDs were Retrofitting for the connected to the primary equipment. future The substation was confi gured to enable concurrent operation of the existing and new equipment during this It is inevitable that as substations transition phase. age, their parts will need to be replaced. The 380/220 kV air-insulated After successfully retrofitting the substation (AIS) located in the Alps in 380 kV substation, the 220 kV part Sils, Switzerland was one such case. was integrated into the new control Its secondary infrastructure – ie, system. The existing IEDs were protection, control and metering – equipped with a new IEC 61850 and parts of its primary equipment at engineering processes, helping to communication interface, allowing the 380 kV level – ie, switchgear, keep data and data flow consistent for communication with the new Mi- power transformers and circuit the whole substation. In this project, croSCADA control system and breakers – had reached the end of the horizontal bay-to-bay communica- ensuring that both the 380 kV and their life cycles. The operator KHR tion model GOOSE was used to 220 kV switchyards could be operated (Kraftwerke Hinterrhein) thus turned considerably reduce the copper wiring and monitored from the central control to ABB for an economically feasible, between the bays. All information for system. A hot standby system was standardized and forward-looking interlocking between bays is now put in place to provide backup should solution for one of the most important exchanged between the ABB Relion® a failure occur. nodes of the Swiss transmission 670 series IEDs on the IEC 61850 bus network. The answer: a substation via GOOSE messages. automation retrofi t using IEC 61850 technology. Although testing was a major part of the retrofi t, the greater challenge was Implementing the IEC 61850 standard to avoid a shutdown during commis- enables availability of all necessary sioning. Outage time of individual information – which supports exten- feeders had to be minimized and sions, replacements or upgrades of all coordinated with the grid operator or part of the substation automation months in advance. The complete system – and enables integration of system was manufactured and Marcel Lenzin products from different suppliers. It delivered to the site where, except for ABB Substation Automation Systems also ensures data consistency within the connection to the AIS interfaces, it Baden, Switzerland the complete system and defines the was installed. Once the dedicated bay [email protected]

38 ABB review special report Challenges build partnerships

In 2006, ABB supplied a pioneering substation-automation project to the Brazilian government power transmission utility, Eletrosul. This utility is responsible for electrical transmission in the south of Brazil. The projects delivered were based on the IEC 61850 standard, with applications using messages between IEDs, GOOSE 1, redundant control units and featuring interoperability between systems from different vendors.

The first project consisted of three substations, “Atlântida 2”, “Gravataí 3” and “Osório 2”. These are 230 kV and 138 kV transmission substations. “Atlântida 2” uses 60 IEDs (14 with redundancy and 32 without) for protection, acquisition and control. These are mapped to 13,683 dynamic redundant signals by the receiving monitoring aspects not defined in the objects from a total of 28,786 objects logic. standard (mostly complex interlocks available in the IED. About 3,300 of and automatic logic) the use of GGIOs these were distributed to centers of In this project, GOOSE was widely is still very high. It is hoped that as the higher hierarchy. used both for monitoring the active IEC 61850 standard evolves, more terminal and for interlocks and standard signs will be provided. In IED Redundant control automatic logics. This permitted a protection, it was found that the use Redundant control was one of the considerable saving of cables, as of GGIOs was reduced because of the special challenges of this project. This twice as many signals are generated standard, and because ABB IEDs use philosophy, used by Eletrosul for many and received in this philosophy versus standards for all protection functions. years, uses two control terminals (for a philosophy of simple control. ABB’s projects this meant two The three substation projects fostered REC670s). These have exactly the Interoperability a spirit of partnership between same functionality in terms of control Eletrosul uses SAGE (an open-source Eletrosul and ABB, resulting in new logic, interlocking and automatisms energy-management system) as projects being carried out together for controlling a certain number of SCADA software. SAGE was devel- delivering the benefits of IEC 61850. bays. Both units are active, but just oped by CEPEL, a Brazilian govern- one is monitored by the supervisory ment research center. The MMS system. In case of unavailability of a protocol defined in IEC 61850 was terminal, the SCADA system switches implemented in SAGE in 2006. The to the other IED. ABB project was thus a test of the Maurício Pereira standard’s interoperability. This test ABB Power Systems Based on this philosophy, Eletrosul was passed successfully. Guarulhos, São Paulo, Brazil clearly defines how a system should [email protected] react, for example, in contingency Results situations. Briefly, the terminal Another request from Eletrosul was to Gonzalo Humeres Flores managed by the supervisory system is minimize the number of hours required Eletrosul monitored and executes remote for the preparation of texts in the commands. In case of interlocks, the system database. For this, it encour- two redundant terminals send signals aged the use of generic signs (GGIOs) Footnote to external bays. This affects the to be minimized. Even so, in the 1 GOOSE: Generic Object Oriented Substation philosophy of treatment of these control terminals that use many Event

Case studies 39 starting point and permitted ABB to Portuguese quickly identify the required solution. transmission The Lagoaça substation uses a system substations based on a decentralized Ethernet ring. The main products from ABB are: – MicroSCADA Pro for local HMI, and REN is the main Portuguese utility for automated sequences electrical energy transmission. ABB – COM500i as Gateway, for commu- supplied the utility’s ﬁ rst IEC 61850 nication with network control center system, installing it at the 400/220 kV – IED's 670 for control and protection Lagoaça substation. The installation units is responsible for some of the most – REB 500 Systems for busbar – Remote access via RX1000 routers important interconnection points with protection from RUGGEDCOM the Spanish grid on the 400 kV voltage level. Third party products used were: The adoption of IEC 61850 was – Switches and routers from clearly beneficial. It allows both Of all the benefits of migrating RUGGEDCOM customers and vendors to retain substation automation systems to the – Meinberg GPS servers for SNTP extensive functional freedom in their new standard, the customer was time synchronization definitions and philosophies. It also especially focused on one in particu- – Computers with no-moving parts assures independence from single lar: standardizing the system architec- running Windows XP Embedded suppliers as well as cost savings in ture, ie, using the same network platform both engineering and maintenance. topology and overall arrangement – KVM switches and fallback switches independently of the supplier. from Black-Box – Industrial computers from Advan- ABB brought much experience into tech, for remote access and this project that it had built up in engineering stations. Carlos Caetano previous deliveries to the customer. – RTU servers and local-event ABB Substation Automation Systems The previous platform may have been printing system from SYCOMP Paço de Arcos, Portugal different, but marked an excellent Germany (REN mandatory). [email protected]

dancy concept. Prior to IEC 61850 Wuskwatim such integration would have been transmission challenging if not impossible, especially for large systems due to incon- system sistency of data and engineering.

The IEC 61850 engineering approach In order to strengthen the existing and data structure using SCL language 230kV network, Manitoba Hydro main signifi cantly facilitated the engineering utility in Manitoba contracted with of interfaces between different units. ABB for the design, engineering, The descriptive power of the SCL supply and commissioning of Wusk- language enabled part of the integra- watim Transmission System Complex, tion to occur without having access to messages for bay-to-bay interlocking comprising three new stations and all devices or bay level information. and intertrip reduced the amount of expansion of four existing ones. The copper wiring required. The complete new stations featured distributed Because design, manufacturing and communication of the substations are control, bay protection and a bay testing of the two SA systems was now described and documented in controller concept. The entire control completed in close colaboration SCD-fi les, which is of advantage for the and communication process used the between ABB and Manitoba Hydro, an future maintenance and extension of IEC 61850 standard. attuned and future-proof system was the stations that are now in service. delivered. The IEC 61850 standard Protection devices were sourced from made it possible to combine and inte- Mansour Jalali three different manufacturers. In fact grate ABB, Siemens and Areva Protec- ABB Substation Automation Systems the use of different suppliers was a tion IEDs within the SA and thus to fulfi ll Burlington, Canada requirement of the protection redun- safety requirements. The use of GOOSE [email protected]

40 ABB review special report The Star of Laufenburg shines

The 380 kV Laufenburg substation – one of the largest and most important in Europe – boosts several world premieres. Staying abreast of the development and extension of IEC 61850, its owners, the Swiss utility EGL AG, were the fi rst to equip a high-voltage substation with an IEC 61850 automation system, doing so shortly after the release of the standard in 2004, and even opting for a multi-vendor solution. Two years on, the utility issued the very fi rst open tender based on a SCD (substation confi guration description) fi le, and most recently implemented the 9-2 process bus.

When built in 1967 at the inception of the European grid, the Laufenburg space and simplify maintenance as On the primary side, there is a substation, with its key position in replacement of a complete pole can combined and fully redundant CP-3 terms of interconnection and meter- be performed in less than 24 hours. current and voltage sensor with ing, was dubbed the “Star of Laufen- merging units for protection and burg”. It was extended and upgraded The future-proof secondary retrofit metering. On the secondary side, a from 1979 to 1981. From 2004 to concept addressed the varying REL670 line distance protection IED 2009, EGL undertook the following lifecycles of bay and station-level and a REB500 busbar protection refurbishment work: equipment. With the latter equipment system with three bay units are in – Step 1: retrofit of primary and being retained, ABB integrated its new operation. Metering is performed by secondary equipment IEC 61850 compliant bay control and an L+G energy meter. For supervision – Step 2: replacement of old station protection IEDs (Intelligent Electronic and easy access, a SAS using HMI Devices) to the third-party control IEC 61850 station bus completes – Step 3: pilot project for system using a gateway converting the pilot installation. IEC 61850-9-2 IEC 61850 to IEC 60870-5-101. ABB also successfully integrated a third- The pilot is running in parallel to the Step 1: Bay retrofit party main protection device with an conventional control and protection Both primary and secondary equip- IEC 61850 interface. Consistency of system and enables collection of long- ment of the 17 feeders was replaced bay data during the stepwise upgrade term real-life experience as well as in a bay-by-bay manner, warranting an was supported by pre-configuring and comparison of behavior. Since its almost interruption-free retrofit. The pre-testing using an SCL-based tool. commissioning in 2009, the system migration was supported by a com- has been in continuous operation. pact hybrid solution that connects the Step 2: Station-level replacement new gas-insulated switchgear (GIS) In 2007, ABB won an open tender for modules to the existing air-insulated the replacement of the old station switchgear (AIS) busbar using silicon HMI (human-machine-interface). ABB Petra Reinhardt bushings. The GIS modules compris- installed a new IEC 61850 HMI fully ABB Substations ing circuit breaker, disconnector, re-using the engineering data from the Baden, Switzerland earthing switch and instrument SCD file generated for the bay retrofit. [email protected] transformers were pre-tested to enable short installation times. They Step 3: Introduction of process bus Stefan Meier offer maximum operational safety and The pilot installation contains a ABB Substation Automation Systems high immunity to environmental selection of products and systems Baden, Switzerland conditions. They also require less ready for the IEC 61850 process bus. [email protected]

Case studies 41 When two become one IEC 61850 in combination with ABB’s award-winning Extended Automation System 800xA is opening doors to new and cost-effective solutions.

JOHAN HANSSON, STEFAN BOLLMEYER – The successful process and power generation plant automation. These introduction of the IEC 61850 standard some six years ago plants are controlled and monitored from a central control has already brought huge beneﬁ ts to power distribution and room in which there are typically two different systems substation automation in terms of scalability, interoperability, deployed; one for process control and the other for monitor- safety and data management. Even though it was drafted by ing and controlling the electrical system. Plant operators, in substation automation domain experts, it is by no means their quest to reduce complexity and optimize efﬁ ciency have exclusively reserved for that domain alone. In fact, IEC 61850 been actively seeking solutions that overcome the separation is more than capable of operating in other areas, such as in of the systems and the extra costs associated with it.

42 ABB review special report Even though it was drafted by substation automation domain experts, the IEC 61850 standard is capable of operating in process and power generation plant automation.

he integration of field instru- trol system, IED monitoring and control is IEC 61850 integration in System 800xA ments into process control ap- usually implemented by a separate sub- The combination of ABB’s Extend- plications is based on a limited station automation (SA) system while ed Auto mation System 800xA with T set of industry standards that connectivity between the electrical sys- IEC 61850 not only addresses the above- provide harmonized access to process tem and process control is limited to the mentioned end-user demands, but it also data and diagnostics. For electrical most essential data, eg, for interlocking gives greater synergy and flexibility to equipment, however, a multitude of dif- purposes. Although only a limited set of fully integrated plant operations. ferent, often proprietary communication signals is selected for data exchange, to- protocols is deployed. Therefore electri- day’s practice for this type of electrical Introduced in December 2003, System cal systems, especially those composed and control system interfacing, such as 800xA provides a scalable solution that of equipment from different vendors, are hardwiring or Modbus connectivity, still extends traditional process control by in- often characterized by multiple different requires significant hardware and engi- corporating: safety; discrete logic and interfaces, a broad variety of engineering neering efforts. The presence of two dif- sequence control; production manage- tools, protocol converters and gate- ferent systems also increases costs be- ment; information management; smart ways. cause, for example, different spare parts instrumentation; asset management; and and a duplicated effort to ensure integra- document management. Based on As- Process control systems typically do not tion with enterprise level systems are re- pect Object technology, System 800xA offer built-in support for those communi- quired ➔ 1. is capable of adopting data models from cation protocols and data models. And different disciplines and making them because of this significant engineering To help plant operators overcome these available in a harmonized way through a and adaptation efforts need to be made expensive complexities, IEC 61850, with singular virtual database environment. on a project-by-project basis to make its standardized communication proto- the increasing amount of information, cols and data model, in combination with The integration of IEC 61850 into System which modern intelligent electronic de- ABB’s award-winning Extended Automa- 800xA supports both generic object ori- vices (IEDs) provide, available to a moni- tion System 800xA is opening doors to ented substation events (GOOSE) and toring and control system. Nowadays to new and cost-effective solutions. manufacturing message specification mitigate the impact on the process con- (MMS) protocol options described in the

When two become one 43 zation workflows can be harmonized 1 Traditional process control systems do not offer built-in support for proprietary communication protocols and data models once IED data is available in System 800xA, allowing instrument maintenance engineers and those servicing electrical devices to work from the system’s com- Operator Operator workplace for workplace for mon maintenance workplace. System process automation power automation 800xA’s maintenance structure gives an overview of all plant assets in a single dis- System networks System networks play. Conditions can be monitored, and System servers SCADA Server diagnostics and maintenance related Gateway/ Controllers Protocol converter alarms for electrical devices and process

Fieldbuses instruments are presented in practically Protocol 1 Protocol 3 the same fashion. For further in-depth LV Switchgear Protocol 2 Drives Protection analysis, additional IED data points can Hardwired Motor & Control Serial buses be subscribed to or disturbance records Instruments controllers IEDs can be uploaded. Access-right settings ensure that only authorized people are allowed to perform such detailed analysis.

Process Process Substation Power instrumentation electrification automation management As the ultimate step, System 800xA’s As- Process automation Power automation set Optimization functionality can be integrated with a computerized maintenance management system (CMMS) so standard. GOOSE communication is di- tion configuration file to create all data that work order handling is automatically rectly connected to the AC 800M con- items for vertical integration as well as treated the same for both electrical and troller (one of many from the System the connections for horizontal communi- process equipment. This eliminates the 800xA family of controllers) via a com- cation. Separate gateway configuration need for separate working procedures or munication interface so that the data be- or additional project-specific software in- the adaption of different systems to the comes available in the controller applica- terfaces become obsolete. CMMS. tion. This so-called horizontal integration 1 enables the AC 800M controller to com- To be more specific, System 800xA municate with all other IEDs on the same seamlessly integrates IEC 61850, deliv- The Flåsjö facility IEC 61850 network in real time ➔ 2. ering the features and benefits requested Moreover, the AC 800M controller acts by end users, such as: is one of the ﬁ rst like an IED on the IEC 61850 network, – Reduced cost of ownership through and can therefore be involved in load fewer components and spare parts, hydro power plants shedding or other power management and less system administration. to utilize a combi- applications. – Greater flexibility as integration is much less complicated than before nation of IEC 61850 MMS communication is used for the ver- and the interfaces adapt easier to tical integration of IEC 61850. Via an changes. and System 800xA OPC 2 interface, System 800xA has di- – Centralized data recording, including for process and rect access to all IED data such as cur- the plant-wide sequence of events rent and voltage measurements, status, and a harmonized interface to substation auto- interlocking, time-stamped alarms and enterprise level systems. events. The system can also send open – A complete view of electrical system mation. and close commands to IEDs. Logical data, especially to process operators nodes (LNs) of IEDs are modeled as As- so they can make educated decisions. The possibility of electrical integration pect Objects in System 800xA and there- – Improved operator effectiveness with presented by ABB’s System 800xA in fore all system features, such as freely one user interface that can consis- combination with IEC 61850 has been configurable graphics, faceplates, alarms tently present plant-wide data, enable keenly observed by industries other than and event lists, and historian capabilities data access and display operating power distribution. The Oil & Gas and are available for IED data. procedures. Power Generation industries in particular have been evaluating these new oppor- To engineer IEC 61850 integration, Sys- Because of its flexibility, System 800xA tunities and some have even taken the tem 800xA uses the information con- allows the configuration of individual first steps toward the implementation of tained in the substation configuration workplaces for both electrical and pro- such a system. description (SCD) file, which describes cess operators so that they can retain the the complete substation configuration. graphical displays and workflows familiar System 800xA processes the extensible to them while operating in a single envi- markup language (XML) based substa- ronment. Maintenance and asset optimi-

44 ABB review special report 2 Communication with all other IEDs on the same IEC 61850 network is possible 3 The Flåsjö hydro power plant in real time

Common operator workplace for process and power automation Upstream, Flåsjö is the first of E.ON’s hydropower plants on the 350-kilometer long river Ljungan. The Ljungan runs to the northeast of Helagsfjället and flows into the Gulf of Bothnia just south of Sundsvall. The power plant was built in 1975 and has a System networks System servers maximum waterfall of 46 meters and a flow through the turbine of 60 m3 per second. The Flåsjö plant produces about 73 GWh with an AC 800M Vertical controller integration installed capacity of 24 MW. The plant is unmanned, and controlled and monitored Fieldbuses IEC 61850 from E.ON Vattenkraft’s control center in Horizontal integration Sundsvall. Communications between the LV Switchgear Protection & power plant in Flåsjö and the control center Drives Control IEDs in Sundsvall is via satellite transmission. Instruments Motor controllers

Process Process Substation Power instrumentation electrification automation management

Integrated process and power automation

E.ON integrates substation and For substation automation, the IEDs are process automation the most critical devices in the plant in The use of E.ON Vattenkraft, a subsidiary of E.ON that they provide protection, control and Sverige, is the third largest hydroelectric monitoring of generators and lines from IEC 61850 with power producer in Sweden. In a typical the outgoing high-voltage substation. year it produces about 8 TWh from 77 Three native IEC 61850 compliant ABB a single control hydro power plants, from Kristianstad in Relion® IEDs are integrated with System system provided the south to Lycksele in the north. Most 800xA, two redundant REG670 IEDs are of these plants were built between the used for generator protection and one E.ON with the 1950s and 1970s using what is now con- REL670 for protection of the outgoing sidered legacy technology. Up to 2015, 130 kV line. All the IEDs are integrated means to investi- E.ON plans to invest SEK 6 billion ($763 with the AC 800M controller using gate the benefits million) in safety, renewal and productivity IEC 61850-defi ned GOOSE. This enables improvements in installed power plants. the AC 800M controller to function not of using the stan- All of E.ON's hydro power plants are usu- only as the process controller, but also to ally operated remotely from the central act as an IED on the IEC 61850 network, dard for standard- control center in Sundsvall, and are visit- communicating horizontally with all other ized system inte- ed only for maintenance reasons. IEDs as well as with the control center via satellite communication. Important data gration, application One of these, the Flåsjö hydro power from the IEDs include measurements such plant, was the fi rst upstream plant installed as power, reactive power, voltages and building, installa- on the river Ljungan in northern Swe- currents, together with breaker and dis- tion and testing. den ➔ 3. Since 2009, it holds the distinc- connector statuses ➔ 4. This data is dis- tion of being one of the fi rst hydro power played at the local System 800xA opera- plants in the world to utilize a combination tor workplace and the control center in of IEC 61850 and System 800xA for both Sundsvall some 260 km away from where process and substation automation. the system is usually monitored and controlled ➔ 5. In addition, alarms and events In the installation at Flåsjö, the original from the combined process and substa- relay-based system was replaced by one tion automation system are also transmit- System 800xA together with an AC 800M ted to Sundsvall, providing operators with controller. Process control handles appli- valuable information about the plant. At cations such as turbine control, vibration the control center, the operators monitor protection and synchronization. Process and control the plant using an ABB Net- electrification and control of auxiliaries work Management System. They also and pumps are done using Profibus have remote access to the System 800xA communication with ABB’s modular low- operator workplace, providing a redun- voltage switchgear MNS. dant connection to the control system.

When two become one 45 4 IED data include power, reactive power, voltage and current 5 The control center in Sundsvall from which all of E.ON’s measurements hydropower plants in Sweden are controlled and monitored

Main benefits when so many power plants are con- 6 Assar Svensson is involved in many of E.ON The use of IEC 61850 with a single controlled from one location, it’s very impor- Vattenkraft’s upgrades and modernizations trol system in the Flåsjö hydro power tant that there is a standard on which plant was a pilot installation for E.ON. It everything is based. provided the means from which the company could investigate the benefits of us- From an E.ON point of view, there are ing the renowned global standard for many benefits of using IEC 61850 and substation automation not only as a System 800xA: communication protocol for devices, but – Complete system configuration is also for standardized system integration, more efficient and safer because application building, installation and test- standardized solutions for IED ing. The success of this pilot project is configuration, substation automaton very important to E.ON because it will in- design and control system program- fluence the upgrade of the substation ming are used. and process control systems in other – The testing of protection, control and hydro power plants. monitoring functions can be carried out before installation begins, and this “I now have major expectations regarding Assar Svensson worked on technology helps to minimize the downtime our supplier’s ability to give us additional assessment and plant design for the needed for installation and commis- capabilities to standardize and simplify power plant in Flåsjö and is now involved sioning. construction of electrical and control in the majority of E.ON Vattenkraft’s up- – IEC 61850 is standard for Ethernet- systems for hydropower plants. With the grades and modernizations ➔ 6. Of the based communication solutions and installation in Flåsjö, we have hopefully renewal plans for the hydropower plants, that means reduced wiring, which in just opened the door to the future.” he says, “this is an extensive conversion turn leads to shorter installation time job we have ahead of us. We’re therefore and reduced sources of errors during looking for standardized solutions in ac- operations. Johan Hansson cordance with IEC 61850. Thus far, it – With improved access to electrical ABB AB only concerns relay protection.” For and process data from the entire Västerås, Sweden E.ON, IEC 61850 will provide new op- plant, the focus is shifted from [email protected] portunities to increase availability and troubleshooting to more preventive simplify engineering. Several standard- maintenance. The system itself can Stefan Bollmeyer ized components provide the capability indicate when a component needs ABB Automation GmbH to build plants in a more structured man- servicing or replacing. Minden, Germany ner. “We want to be able to receive deliv- – A common event list for both the [email protected] eries in which all components can be process and electrical monitoring tested together prior to initiating opera- makes it easier to monitor errors and tions.” Another important reason for a draft maintenance plans. Footnotes more standardized structure for the con- 1 Horizontal integration can also replace the trol systems is that all E.ON Vattenkraft These benefits are such that according hardwiring traditionally used for interlocking signals. facilities in Sweden are controlled from a to Assar Svensson, E.ON will continue to 2 Object linking and embedding (OLE) for process single control center. Svensson says that ask for IEC 61850 in its specifications: control

46 ABB review special report IEC 61850 Edition 2 From substation automation to power utility automation

KLAUS-PETER BRAND, WOLFGANG WIMMER – The fi nal part of IEC 61850 Edition 1 “Communica- tion Networks and Systems in Substation Automation” [1] was published in June 2005. Among the standard’s greatest achievements and benefi ts are the use of standardized semantics and a formal system description (the latter being the key to effi cient engineering of substation automation systems) as well as it being embedded into the broader scope of power-system management. Since its introduction, IEC 61850 has established itself as global standard for substation automation. An example from Switzerland is the system installed in Sils ➔ 1 [2]. This is, however, far from the conclusion of its development. Additional application areas are being considered by IEC. The standard is thus being extended.

IEC 61850 Edition 2 47 changes. In many cases, only a These extensions do not only concern subset of them is needed. the application-data model itself, but – The basic substation-automation also the capabilities of the SCL (substa- related data model has to be extend- tion configuration language) to support ed only by additional logical node new data models and enhanced engi- classes needed for functions from neering processes. these other domains. – The communication stack used is very Remaining challenges from Edition 1 common (especially TCP/IP and 61850-9-2 defines the standardized Ethernet). communication of current and voltage samples across an Ethernet-based serial The standard extends beyond the link. Besides transmitting such analog switch yard samples, the link also transmits switch There is a signiﬁ cant advantage for utili- positions, commands and protection ties if data from substation IEDs can be trips. According to IEC 61850-8-1, this used directly on higher system levels for combination results in a complete pro- control and monitoring purposes, without cess bus between primary and second- there being a need for protocol converters ary equipment ➔ 3. or having to handle numerous different protocols. Therefore two working groups The response time and throughput re- of IEC TC57 have looked at the use of quirements on this bus are determined IEC 61850 for real-time applications such mainly by the samples. The advantages as line protection and also other applica- of such a process bus are: tions that involve communication between – It permits the replacement of many substations as well as monitoring and copper cables by a few optical cables control applications involving communi- (lower cabling costs) cation between substations and network – Optical cables achieve the galvanic he development of the control centers. The results will be pub- decoupling of primary and secondary IEC 61850 standard is con- lished as technical reports. equipment (makes maintenance and tinuing. This work is primarily replacement easier). T aimed at remedying various The report that handles communication – The serial interface makes the applica- shortcomings that were identified during between substations is published as tions independent of the physical the first installations, but it also seeks to IEC TR 61850 90 1 [8]. Its results are principle of the instrument transformer enhance its application range – as is re- being integrated into the second edition (electromagnetic, capacitive, optical, flected in its changed title “Communica- of the base standard. Besides discuss- others) allowing more flexibility on the tion Networks and Systems for Power ing direct tunneling of Ethernet-level primary equipment side. Utilities” [3]. This work is resulting in Edi- messages on high-bandwidth links, it tion 2 of the standard, which is being also looks at the usage of proxy gate- Edition 1 of the standard did not define a published in 15 parts during 2010. ways with low-bandwidth links ➔ 2. solution for the time synchronization required for the communication of samples Expanding into new application areas The report handling communications at rates in the region of microseconds. IEC 61850 was originally defined exclu- between substations and network con- Therefore, and to achieve the accep- sively for substation automation systems trol centers will be published as IEC tance of a faster process bus, the user (including protection applications). It has TR 61850-90-2 [9] and any resulting add- organization, UCA International [11], de- since been extended to other application ons to the base standard will be integrat- veloped an application recommendation areas. These are automation of wind ed into an amend- power systems [4], hydro power systems ment to Edition 2, [5], and distributed energy resources or at the latest in IEC 61850 was originally such as combined heat and power sys- Edition 3 of the tems or photovoltaic plants [6]. The fact base standard. defined exclusively for substa- that the standard is being applied in the domain of distributed energy resources Work on a third re- tion automation systems, but indicates the significance of IEC 61850 port handling the has since been extended to for smart grids. automated transformation and map- other application areas. Aspects of the extension of IEC 61850 to ping between the these domains include the following: IEC 61850 data – The services of IEC 61850 have been model and the IEC 61970 Common known as IEC 61850-9-2LE (Light Edi- proven to fulfill the known require- Information Model (CIM, [10]) has just tion). This recommendation is based on ments of these other domains and begun. the concept of a merging unit (MU) that may hence be applied without delivers all current and voltage samples

48 ABB review special report 1 IEC 61850 based substation automation system in Sils. This implementation is also discussed on page 38.

Engineering workstation Station HMI Remote control

GPS Station Backup server (NAS) Redundant gateways

Ethernet switch RSG2100 Bay side Ethernet switch RSG2100 Ethernet switch RSG2100 Transformer 2 Transformer 1

BBP/BFP central unit REB500 REC670 7SA612REC670 7SA612 REC670 7SA612 REC670 7SA612 REC670 7SA612

REL670 REL670 REL670 REL670 REL670 BCM800 BCM800 BCM800 BCM800 BCM800

SIMEAS R SIMEAS R SIMEAS R SIMEAS R SIMEAS R

L+G ZMQREB500 BU L+G ZMQ REB500 BU L+G ZMQ REB500 BU L+G ZMQ REB500 BU L+G ZMQ REB500 BU

MWU MWU MWU MWU DSAS-RTU

380 kV BBP 380 kV line 1 380 kV coupler 380 kV transformer 2 380 kV transformer 1 380 kV line 2

from a given bay in a time-synchronized the conventional current transformer of manner. It defines a telegram format type TPY for protection. This allows the More components containing voltages and currents from type testing of the combined set of NCIT the three phases and the zero compo- and MU. This has been done success- will facilitate the nents. It specifies two sample rates (80 fully for ABB’s NCIT CP, (combined cur- and 256 samples per period) and a time rent and voltage sensors for GIS) which adoption of the synchronization by a pulse per second are now ready for use. architecture of the (1 pps) with a synchronization accuracy class of T4 (± 4 µs). Meanwhile, a profile Some questions remain unresolved, es- SA system and of the standard IEEE 1588 [12] is being pecially how the signal from a conven- worked on, which will support high-pre- tional transformer (CIT) is changed due permit the better cision time synchronization across to digitalization in the MU. These ques- physical distribu- switch-based Ethernet. tions are addressed by the IEC TC38 (In- strument Transformers) that has started tion of the primary The numerous features and benefits that replacing IEC 60444 by new standard the process bus offers are considered in IEC 61869 [14] in a step by step manner. equipment, provid- a discussion on optimal processes in It will define in its part 9 the “digital inter- ing the full advan- connection with communication archi- face” covering the whole issue of MUs. tecture. The interoperable application The result will not be available in time to tage of the process has been delayed, however, because the be referenced in Edition 2 of IEC 61850. dynamic behavior (step and frequency bus. response) of the samples has not been Several manufacturers are already offer- sufficiently defined to guarantee applica- ing MUs as pilot products. However, the tion-level interoperability. The behavior of electronic interface to a switch (often conventional instrument transformers is called a breaker IED or BIED) is rare even defined in the standard IEC 60044 [13] as as a pilot product. Sometimes “normal” is the behavior of electronic current and controllers are used in a similar way to voltage transformers, thus summarizing BIEDs, eg, by receiving GOOSE (Generic all NCITs. It is stated, eg, that the elec- Object Oriented Substation Event) trips tronic current transformer behaves as from protection devices. This can for ex-

IEC 61850 Edition 2 49 2 Communication principles between substations based on 3 Process bus with merging unit (MU), switch interface (BIED) and IEC 61850 external Ethernet switch

Fiber optical Special Station bus Station A Communication Station B Mechanism Currents (I) Function Function (typically low Voltages (U) MU A1 A1 bandwidth) Merging Unit IED Protection Fiber optical Process bus Function Proxy Function Trip decision BIED A2 B2 B2 Breaker Protection trip Interface

“Teleprotection Equipment” IEC 61850-90-1 acting as Gateway Secondary equipment Primary equipment

ample be used for the two affected verified that the Edition 1 devices used It is possible to breakers of a 1 ½ breaker switchyard di- already implement resolutions of all tech- ameter, or for breaker failure protection. nical problems identified up to Edition 2. use Edition 2 engi- This can be done by means of the so There are also ideas to combine a MU called TICS document, which should be neering and SCL and a BIED into one product. However, available from the manufacturer for each descriptions with this is not a matter for IEC 61850 but for certified IED type. the optimized application of the process IEDs still having an bus. The benefits of process bus appli- Beyond Edition 2 cations can already be reaped today. IEC standards are being developed in a Edition 1 data More components will facilitate the adop- time-consuming procedure involving model. tion of the architecture of the SA system commenting and voting by the national and permit the better physical distribu- committees in several steps and via dif- tion of the primary equipment, providing ferent drafts as they work towards the the full advantage of the process bus. final international standard (IS). There- fore, some task forces have already IEC 61850 Edition 2 started work on topics for amendments Besides the correction of errors and or for a future Edition 3, which will fulfill many small details, Edition 2 will contain further user requirements. Some of the the add-ons laid out in ➔ 5. topics being considered are: – Ethernet network architectures within It is planned to publish all parts of Edition substations including redundancy and 2 with the exception of 7-5xy as an inter- Ethernet switch configuration. national standard during the course of – A setup for the supervision and diagno- 2010. The question of when correspond- sis of primary equipment, called CMD ing tools and products will appear on the (condition monitoring and diagnosis). market depends on the manufacturers and appropriate requirements from cus- To provide an overview of the standard’s tomers and is difficult to predict. All error fast-growing data model for both present corrections, clarifications and restrictions and future application domains, and to contained in Edition 2 with respect to be able to realize extensions more quick- Edition 1, however, should already be ly than is possible in the normal stan- followed by the next releases of Edition 1 dardization process, the introduction of devices. In this context it should also be an IEC database for model definitions is mentioned that it is possible to use Edi- under discussion. This would be acces- tion 2 engineering and SCL descriptions sible via Internet. A standardized formal with IEDs still having an Edition 1 data description of the model definitions de- model. Edition 2 and all following edi- fined in Edition 2 will help with the rapid tions will be backwards compatible to integration of new models into the tools. Edition 1 (with the exception of error corrections). A customer or supplier today IEC 61850 and Smart Grids deciding to apply IEC 61850 Edition 1 The discussion around the future of the will thus benefit from all present advan- power grid with more and more decen- tages and future benefits of this stan- tralized power generation, flexible power dard. To assure as much compatibility to buying and high grid reliability often labels future editions as possible, it should be this objective as “smart grid”. An as-

50 ABB review special report 5 IEC 61850 Edition 2

Besides the correction of errors and many small details, Edition 2 of – Management hierarchies of logical devices: Especially complex IEC 61850 will contain the following add-ons: multifunctional protection IEDs require more functional levels for the management of common parameters. For an example see ➔ 5b: The – Clarifications of unclear parts such as: logical device Ocp controls the mode of the lower level logical devices – buffered reporting OpcPhs and OpcGnd by group reference (GrRef) which additionally could – mode switch (test mode) be controlled individually. – control access hierarchy (local / remote) – New data objects and concepts for testing of function parts in the – Data model and SCL extensions for communication between running system: This feature allows now a standardized application of substations: discussed above and outlined in ➔ 2 the test and test-blocked mode which was already introduced in Edition – Support for redundant IED interfaces: discussed in "Seamless 1 and is now clarified in Edition 2. It supports the handling of test redundancy” on pages 57-61 of this ABB Review Special Report. messages in parallel to the real messages. – Data model extensions for new application functions: supervision of – SCL extensions to describe new IED properties and better support non electrical quantities, etc. (These new logical nodes have been mainly of engineering processes and retrofit: The data exchange between introduced by other application domains such as hydro-power plants) different projects in a controlled way allows coordinated engineering in – Statistical evaluations of measurements as contained in the logical parallel running subprojects. nodes MMXU and MMXN: Triggered by power-quality discussions and – SCL implementation conformance statement (SICS): stating other application domains such as wind power ➔ 5a. mandatory and optional features of IED tools and system tools. This – Support for tracking and logging of services and service responses: feature allows judging the degree of interoperability between different This feature makes service parameters and service handling visible engineering tools, system tools as well as IED tools. without the use of protocol analyzers by the standard’s existing reporting – An informative part 7-5x with examples of modeling important and logging facilities and allows, eg, the logging of negative answers on application functions in the system: This part is intended to support service requests (negative acknowledgements). This feature is useful both common understanding of modeling and to move towards broadly for commissioning and security supervision. accepted modeling solutions

5a Example for statistical methods (ClcMth) applied on MMXU 5b Management hierarchy for logical devices

MMXU 1 Clc Mth MMXU 2 IED1 Ocp TotW Total Active Power TotW Total Active Power PRES LLNO TotVAr Total Reactive TotVAr Total Reactive TRUE_RMS Power Power PEAK_FUNDAMENTAL TotVA Total Apparent TotVA Total Apparent RMS_FUNDAMENTAL Power Power GrRef = IED1.Ocp.LLN0 MIN TotPF Average Power TotPF Average Power MAX Factor Factor AVG OcpGnd OcpPhs PPV Phase to phase PPV Phase to phase SDV Voltages Voltages PREDICTION LLNO LLNO V Phase to ground V Phase to ground RATE Voltages Voltages PTOC 1 PTOC 1 A Phase Currents A Phase Currents ...... RDIR 1 RDIR 1

sumed prerequisite to the functioning of References [9] IEC/TR 61850-90-2, Communication networks such a grid is that more information can [1] IEC 61850 (Ed 1), Communication Networks and systems for power utility automation – Part be made available in a reliable and timely and Systems in Substations, 14 Parts, 90-2: Use of IEC 61850 for the communication manner to more and more distributed ap- 2003-2005, http://www.iec.ch. between substation and network control [2] Brand, K.P, Reinhardt, P, 2008, Experience center, in work plications and users, permitting control to with IEC 61850 based Substation Automation [10] IEC 61970-301, Energy management system be optimized. This will assure the grid’s Systems, Praxis Profiline – IEC 61850, 66-71 application program interface (EMS-API) – Part stability, make electrical energy available [3] IEC 61850 Ed 2, Communication Networks 301: Common Information Model (CIM) Base, where needed, and permit interactive and Systems for Power Utility Automation, 2003-11 scheduled for 2010, http://www.iec.ch [11] IEC 61850-9-2LE (Light edition) Implementa- communication with consumers. This re- [4] IEC 61400-25-x, Wind turbines – Part 25-1: tion Guideline for Digital Interface to Instrument quires the needed data to be made avail- Communications for monitoring and control of Transformers using IEC 61850-9-2, UCA able within a common information net- wind power plants, 2006-12 International Users Group, www.ucainterna- work and according to standardized data [5] IEC 61850-7-410, Communication networks tional.org and systems for power utility automation – Part [12] IEEE 1588, Precision Clock Synchronization semantics. This is precisely where IEC 7-410: Hydroelectric power plants – Communi- Protocol for Networked Measurement and 61850 fits in. Therefore IEC 61850 has cation for monitoring and control, 2007-08 Control Systems been taken up alongside IEC 61970 in a [6] IEC 61850-7-420, Communication networks [13] IEC 60444 Instrument transformers and systems for power utility automation – Part [14] IEC 61869, Instrument transformers – Part 1: smart-grid related report from EPRI [15] 7 420: Basic communication structure – Distri- General requirements, 2007-10 (others parts in and adopted by NIST as a key interest. buted energy resources logical nodes, 2009-03 work) [7] Swiss Chapter of IEEE PES, Hydro Power [15] Electric Power Research Institute (EPRI), Klaus-Peter Brand Workshop I (Handeck, 2008) und Workshop II Report to NIST on the Smart Grid Interoper- (Genf, 2009), http://pes.ieee.ch ability Standards Roadmap, June 17, 2009 Wolfgang Wimmer [8] IEC/TR 61850-90-1, Communication (www.nist.gov/smartgrid ) ABB Substation Automation networks and systems for power utility Baden, Switzerland automation – Part 90-1: Use of IEC 61850 for [email protected] the communication between substations, to be published summer 2009 [email protected]

IEC 61850 Edition 2 51 52 ABB review special report Reliable networking

Impact of modern communication technology on system reliability

KLAUS-PETER BRAND, WOLFGANG ubstation automation (SA) is include the maximum allowed response WIMMER – The communication stan- commonly used to control, time for an action. Ethernet was origi- dard IEC 61850 was introduced to protect and monitor substa- nally designed to be tolerant of failures, standardize the communication for S tions [1]. Up to now, the com- but not to guarantee response times. substation automation so that all munication for SA has used proprietary Therefore for this purpose special rules devices, no matter their origin, could serial communication systems comple- must be applied so that the Ethernet can communicate using a standard mented by conventional parallel copper be used for time critical application func- protocol replacing wires with serial wiring, especially from the bay level tions. communication. Based on mainstream to the switchgear. With the advent of communication technology, like that IEC 61850 [2], a comprehensive global Failure modes and services of the Ethernet, IEC 61850 benefi ts standard for all communication needs in A failure means that some component in from a high degree of fl exibility with the substation is available. the SA system is not working as intend- regard to communication architecture. ed, which impacts the functionality of the Any solution, however, has to fulfi ll The reliability of SA communication ar- SA system. Failures can be permanent or stringent reliability requirements to chitectures is of great importance for the temporary. Failures produce errors in the ensure a constant power supply in reliability of the power supply from the intended system functionality. The result transmission and distribution grids to power transmission and distribution grid. of a permanent failure may be the loss of accomplish the safety-critical mission Up until now a dedicated communica- power supply, loss of processing elec- of substation automation. Mainstream tion system has been used, however the tronics, or loss of communication ports, Ethernet connections do not neces- IEC 61850 uses a standard mainstream like failing diodes for fiber optic links. sarily provide the required reliability. communication means like Ethernet, These kinds of errors can be accommo- The IEC 61850 reaches the required which provides a high degree of flexibili- dated by appropriate redundancy strate- level of communication reliability for ty, but does it bring reliability? gies as discussed in the context of com- substation automation by confi guring munication in the previous article (see appropriate message fi ltering and Reliability according to IEC 60870-4 [3] is "Seamless redundancy" on page 57 of checking the load for worst case defined as a measure of the equipment this issue of the ABB Review Special application scenarios for time critical or a system to perform its intended func- Report). communication traffi c. tion, under specified conditions, for a specified period of time. Often investiga- Often, especially in the context of com- tions concentrate on reliability with re- munication, temporary errors can occur gard to hardware faults. In the case of as a result of electromagnetic distur- time-critical functions, like protection or bances or the intermittent failure of com- load shedding based on serial communi- ponents. These may be caused by tem- cation, the “specified conditions’ also perature fluctuations, the distortion of

Reliable networking 53 the delay, which for a 1,000 Byte (8 kBit) 1 Collision on a bus with hubs 2 Switches with “store-and-forward” message and 100 MBit / s Ethernet, equates to about 100 µs. This is typically collision much more than the routing time within a Hub Switch switch. Assuming a ring with 20 switch-

IED IED IED IED es, for example, an additional delay of message Hop 1 2 ms can occur between sender and

message Hop 2 receiver. message IED IED IED IED

IED IED IP-based traffic normally has a determined destination. Thus a switch can learn to route a corresponding Ethernet optical cables that have been bent too The GOOSE service is meant for fast message to a particular port, as shown much or similar, leading to temporarily sending of process state changes in ➔ 2. The disadvantage of this point to disturbed or missed messages in the (events). Therefore, to overcome tempo- point traffic is that the sender has to send communication system. These kinds of rary errors on single messages, the mes- separate messages to each intended re- failures are typically detected by high- sage is repeated in case a value in the ceiver. For real-time messages there is level protocols like transmission control GOOSE message changes a few times often more than one receiver of the same protocol (TCP), and are handled by tell- very quickly (eg, within 4 ms intervals). message. The interlocking function, for ing the sender about a missed message After this, a fall back to the periodic example, needs the state (switch posi- and then repeating its dispatch. For this background period occurs in the order of tions) of the bus coupler at all bay con- reason all IEC 61850-based communica- a second (see “The concept of IEC 61850” trollers of all bays at the same voltage tions, which are not time critical, are built on page 7 of this issue of the ABB Re- level. Therefore, the GOOSE and SV ser- on the TCP protocol. To allow additional view Special Report). The time span be- vices use Ethernet-level multicast ad- routing in arbitrary communication net- tween three or four fast sendings is a dresses. These configurable, hardware- works, TCP runs on top of the Internet configuration parameter, which typically independent link level addresses also networking protocol (IP). depends on the maximum tolerable delay. make maintenance easier. As a switch These services can be used for protec- does not know where the receivers of Unfortunately, the handling of message tion and other safety related functions [4]. multicast messages are, it typically for- errors through repetition results in further wards the messages to all devices con- message delays. The detection of a failed Ethernet specific challenges nected to it, thus producing a lot of pos- message and its repeated dispatch in Ethernet was originally developed as a sibly unwanted load for the receivers. TCP is based on an acknowledgement bus system, in which several devices are Considering the interlocking function for mechanism with timeouts that may lead coupled to a common communication 30 bays, where each bay sends the state to delays in the order of seconds. How- medium. This mechanism leads to colli- of its busbar related primary switches to ever, the acceptable maximum delay for sions if two devices a time critical application function is in try to send data at the order of 10 ms to 100 ms. TCP- the same time ➔ 1. The reliability of SA communi- based services, therefore, are not suit- Due to such colli- able for many automation and protection sions, the response cation architectures is of great functions. For this reason IEC 61850 in- times during burst troduces the GOOSE (generic object ori- situations are un- importance for the reliability ented system event) and SV (sampled predictable, and the of the power supply from value) services for functions needing maximum through- real-time performance. Both services are put is less than 10 the power transmission and directly mapped onto the Ethernet link to 20 percent of the layer. Both periodically send sequentially raw bit rate of the distribution grid. numbered messages, which allow a re- bus. This is over- ceiver to detect missing messages as come by using Ethernet switches with all other bays in the same voltage level well as permanent failures. Sampled val- duplex connections between them and with a background period of 1 s, this re- ues are transmitted with a high rate cor- to the end devices. sults in a background load of 30 mes- responding to the sampling rate of cur- sages per second. This load is needed at rents and voltages, eg, 80 messages per Switches work with a “store-and-for- the controllers, however not at the pro- cycle being 4,000 messages / s for a ward” principle like IP level routers ➔ 2. tection devices, which instead might 50 Hz system, thus replacing a missed They receive a message completely, and need other GOOSE messages eg, for the sample by the next one very quickly. It is then forward it to the known output port, breaker failure function. up to the receiving application to handle thereby avoiding message collisions single lost values, eg, by interpolating completely by prioritizing messages To separate wanted load from unwanted the received well-known ones already within the switches. The disadvantage of load, Ethernet switches support the con- from any A/D conversion. switched Ethernet is, that each hop from cept of multicast message filtering. This one respective switch to another adds to can be based on multicast addresses as

54 ABB review special report are lost due to insufficient buffer 3 Logical data flow in a small system space.

These challenges can be tackled with Interlock P2KA1 StatUrgC1 appropriate tools. The IEC 61850 data REC 316-4 StatUrgM1 P2WA1 MeasFlt flow allows the intended destinations for Interlock Interlock Interlock Positions P2KA4 all kinds of messages to be described, REC 316-4 thus defining the required data flow at P2WA1 the application level. An example for GooseSt P2KA2 MMXU1URptMxDs C264 GOOSE (green) and TCP based (blue) P2WA1 data flow is shown in ➔ 3. The load situation based on the presumed data flow can be determined easily at each receiv-

DataSet1 P2KA3 StatUrg er in normal and burst situations ➔ 4. Siprotec-7SJ6xx Comparing this with the input capacity of P2WA1 the devices gives a quick check as to ProtTrip P2FA1 StatUrg REL 316-4 whether the intended function distribu- P2WA1 tion and data flow at application level is GOOSE traffic P2Y1 COM581 reasonable and will work from a commu- TCP traffic ***GW*** nication point of view.

The boxes in ➔ 3 represent intelligent well as on the introduction of virtual LANs To a certain extent this can be handled electronic devices (IEDs), whose names (VLAN). Therefore, IEC 61850 introduces by the Ethernet priority feature. TCP- are written in the first line, and which all a separately configurable multicast ad- based time uncritical traffic has no prior- communicate within the SubNetwork dress as well as a separate VLAN identi- ity and can also be delayed by appropri- P2WA1 (third line in each box). The IEDs fication for each GOOSE or SV message ate configuration at the sender by 50 to P2KA1, P2KA2, P2KA3 and P2KA4 are source. This leads to additional engineer- 200 ms. GOOSE and SV traffic gets pri- controllers sending GOOSE messages ing effort to identify the flow of multicast ority in the switches and is put first into for interlocking to each other. The IED messages from the source to all intended the output message queues. Thus it is P2FA1 is a protection device, which destinations through the switch network not delayed by TCP traffic, just by other sends a trip with GOOSE to the control- and to configure the concerned switches GOOSE and SV messages. ler P2KA1 to trigger a disturbance re- accordingly. corder. The IED P2Y1 is a gateway to a To sum up: network control center, which receives Another challenge, with the store-and- – The IEC 61850 usage of switched reports from all other devices. forward principle of switches, is the re- Ethernet for time critical applications lated intermediate buffering (storing) of can guarantee maximum response ➔ 4 shows the load calculated from a messages in case of bursts. In such a times down to a few milliseconds. substation configuration language (SCL) situation, a lot of messages from differ- – To reach this performance and also to description of this system for all receiv- ent input ports arrive at a switch, which restrict unwanted load on the end ers based on the configured data flow. typically has to be forwarded through a devices, the Ethernet must be built This results in the required load for a single output port eg, to the station level. with duplex connections to and switch network that is correctly config- If the inputs of 10 ports are routed to one between managed switches, ie, ured. If the allowed message input rate output port with the same bit rate, then switches supporting priorities and to an application IED is known, it can be nine messages have to be buffered in VLAN or multicast address-based checked if the application would really between. This leads to additional mes- filtering. work. ➔ 5 now contains the calculated sage delays, and in extreme cases may – It is necessary to configure priorities, load based on the configured virtual local result also in message losses due to in- VLAN IDs and multicast addresses at area network (VLAN) identifications. By sufficient buffer capacity. the GOOSE and SV sources as well comparison with ➔ 4 it can be easily seen as appropriate message filtering at that this configuration using mainly VLAN It should be kept in mind that the reliabil- the switches for the intended high- 000, ie, no VLAN, leads to a suboptimal ity of GOOSE messages depends on the performance multicast data flow. situation. Even the gateway P2Y1, which prerequisite that not more than two con- should only receive reports and does not secutive messages are lost. This prereq- Solutions to remaining problems belong to any VLAN, is loaded with uisite has been validated by a lot of tests Two main challenges remain: GOOSE messages, and the protection based on physical disturbance scenari- – Configuring VLAN or Multicast filtering device P2FA1, which should receive os. However, if in a busbar trip situation, into the switches nothing, gets 3 GOOSE messages / s. GOOSE messages are lost in the switch- – Assuring that for big systems the For this small system the resulting load, es due to insufficient buffer size, delayed maximum delay in the switch network even during a burst, is no problem at all. GOOSE-based actions may result. fits within the required maximum However, for a bigger system a better response time, and that no messages VLAN configuration should be used to

Reliable networking 55 4 Expected load at receivers due to configured data flow 5 Actual load in normal situation due to configured VLANs

Received load per IED based on client allocation Received SV/GOOSE load per IED due to VLAN config, and VLAN list

IED name kBit/s Msgs/s Burst msgs IED name kBit/s Msgs/s Burst msgs VLAN IDs

P2KA1 11 2 6 P2KA1 12 2 9 000

P2KA4 16 2 9 P2KA4 17 2 12 001 000

P2KA2 10 1 3 P2KA2 21 3 9 000

P2KA3 10 1 3 P2KA3 22 3 12 000

P2Y1 5 5 25 P2FA1 21 3 9

P2Y1 22 3 12

get closer to the minimum message rate delays in worst case situations. The main This bottleneck can be easily found by needed for the application level engi- problem here is to know what are the just analyzing the receiver load for nor- neering as shown ➔ 4. worst case situations seen from the pro- mal data flow based on the SCD file ➔ 4. cess point of view, and how do they This kind of analysis is recommended for In a ring network, the filtering configura- manifest themselves in message load for a system without process bus, if it han- tion at the switches can be derived from the devices hosting application func- dles more than 30 bays. The trend to put the logical data flow. To avoid filter recon- tions. One typical scenario is a busbar more and more devices to 100 MBit / s figuration in case of switch ring reconfig- trip, resulting in a change of all measure- Ethernet will make this analysis more and uration, the filtering should only be con- ments and the tripping of all circuit break- more urgent, since it is the receiving end figured for the receiving devices or ers within a very short time span, with devices that have the bottlenecks and between different rings, while all ports the addition of 10 alarms from the switch- not the communication system itself. between switches should allow all used yard or protection system. Other scenar- VLANs. The filter to the receiving devices ios depend on the switch yard configura- To conclude, networking can be highly re- can be automatically calculated together tion and its place in the power network liable for substations and utility automa- with the receiver load. As an example ➔ 5 and must be defined by the utilities. If tion is possible using modern main stream contains the VLAN identifications, which these scenarios and the resulting mes- communication technology, such as Eth- should be configured at the switches to sage load are known, the system de- ernet, in accordance with IEC 61850. be sent to the port where the correspond- scription as IEC 61850 SCL file allows for ing device is connected. As VLAN 000 a tool to determine the resulting mes- just means “ignore the VLAN and send sages and their flow to the end devices everywhere”, here the only thing to be as illustrated above. With a description configured is the VLAN 001 as output to of the physical structure, the flow through the device P2KA4. In a similar way a re- the switch network may be calculated lated configuration for filtering based on also; this includes the required maximum Klaus-Peter Brand multicast addressing can be generated. buffer size to ensure that no message is Wolfgang Wimmer lost, as well as the maximum delay in the ABB Substation Automation For tree networks a similar strategy output queues. This allows the maximum Baden, Switzerland could be used. However, if within the tree GOOSE and SV message delay to be de- [email protected] network appropriate filtering is also termined in advance, and the buffer size [email protected] needed, an additional formal description of the switches to be check against their of the physical network, as defined in required size. If this is not consistent, IEC 61850-6 Ed2 [5], also permits the then redesigning the communication ar- References switch filter configuration to be automat- chitecture might be a solution. More buf- [1] Brand, K.P., Lohmann, V., Wimmer, W. (2003) ically derived from the logical data flow. fer space in the switches might be re- Substation Automation Handbook, UAC. ISBN 3-85759-951-5. Retrieved June 6 2010 quired, or in the worst case the application from www.uac.ch Finally the configuration data must be implementation itself may need to be [2] IEC 61850 (2002 2005) Communication manually loaded into the switches (differ- changed to reduce the communication networks and systems in substations. Retrieved ently per switch manufacturer). This load required. June 6, 2010 from www.iec.ch [3] IEC 60870-4 (1990) Telecontrol equipment and should change in the future, since IEC systems; Part 4 – Performance requirements. TC57 WG10 is working on a standard- However, these kinds of problems only Retrieved June 6, 2010 from www.iec.ch ized switch configuration description in arise in very big systems or systems [4] Brand, K.P., Ostertag, M., Wimmer, W. (2003) SCL, which should then be used as input where SV messages are used between Safety related distributed functions in Substations and IEC 61850. IEEE BPT Bologna, to switch engineering tools. several bays. It is common today in big Paper 660 systems without process bus and only a [5] IEC 61850-6Ed2 (2009) Communication The formal description of the physical few GOOSE-based functions to find bot- networks and systems for power utility structure also supports handling of the tle necks typically at the station level de- automation – Part 6: Configuration description language for communication in electrical last problem: probable message loss due vices, may be at the human machine in- substations related to IEDs. Retrieved June 6, to insufficient buffer size and additional terface (HMI), or may be at the gateway. 2010 from http://electronics.ihs.com

56 ABB review special report Seamless redundancy Bumpless Ethernet redundancy for substations with IEC 61850

HUBERT KIRRMANN – The IEC 61850 standard has become the the station bus as well as for the process bus. It is based on backbone of substation automation, allowing for the fi rst time two complementary protocols defi ned in the IEC 62439-3 interoperation between protection, measurement and control standard: parallel redundancy protocol (PRP) and high-avail- devices from different manufacturers on the same Ethernet ability seamless redundancy (HSR) protocol. Both are able to local area network, station or process bus. This network is overcome the failure of a link or switch with zero switchover duplicated in substations that require a very high availability. time, while allowing clock synchronization according to IEEE Interoperability requires that all devices use the same redun- 1588 to operate reliably. Developed by ABB in collaboration dancy concept. IEC 61850 now specifi es a network redundan- with other companies, both PRP and HSR will be part of the cy that fulfi lls the requirements of substation automation, for second edition of the IEC 61850 standard.

Seamless redundancy 57 1 A non-redundant station bus

loggergg GPS network control centre printer station supervisory operator level workplace gateway

switch S optical fibre links station bus (ring)

switch 1 switch 2 switch N

main main main IED IED IED … backup backup backup

IED IED copper IED control controllinks control IED IED IED bay 1 bay 2 bay N

all transmitted information and provide 2 A ring with switching end nodes zero-switchover time if links or switches fail, thus fulfilling all the difficult real-time requirements of substation automation. operator workplace network control centre PRP (IEC 62439-3 Clause 4) specifies gateway that each device is connected in parallel to two local area networks of similar to-

he IEC 61850 standard re- pology. HSR (IEC 62439-3 Clause 5) ap- station bus as ring places the numerous busses plies the PRP principle to rings and to and links in use today by a hi- rings of rings to achieve cost-effective erarchy of well specified redundancy. To this effect, each device T IED IED IED IED switched Ethernet networks, namely the incorporates a switch element that for- switch station bus between the bays and the wards frames from port to port. element IED process bus within a bay. To achieve interoperability, IEC 61850 Edition 2 speci- IEC 61850 network topology fies in greater detail the underlying proto- IEC 61850 encompasses two busses physical Ethernet network could carry cols of these busses. Two indispensable based on switched Ethernet technology both the station and the process bus network features for a real-time system [4]: traffic. are given particular attention: time syn- – The station bus [5] interconnects all chronization and network redundancy. bays and the station supervisory level; For the station bus, the network topology Time synchronization is solved by the it mainly carries control information, generally adopted in large substations is simple network time protocol (SNTP) [1], such as measurements, interlocking that each voltage level uses a ring of with stricter requirements taken care of and select-before-operate. Typically switches, which connect the main pro- by the IEEE standard 1588 [2]. Redun- the manufacturing messaging specifi- tection, backup protection and control dancy was a major hurdle, since the lack cation (MMS) protocol is used to IEDs ➔ 1. In smaller medium-voltage of a commonly accepted redundancy transfer data between station level substations, a cost-effective arrange- protocol prompted manufacturers to and bay level intelligent electronic ment uses IEDs that include a switch ele- market incompatible proprietary solu- devices (IEDs) while generic object ment, which can be chained into a ring tions. oriented substation events (GOOSE) topology, making the network resilient to looks after bay IED to bay IED data the loss of one link ➔ 2. IEC 61850 edition 2 now includes two transfer. redundancy protocols, which are defined – The process bus [6] interconnects the In large substations, the different voltage in the IEC standard 62439-3 [3] and ap- IEDs within a bay and mainly carries level rings are connected to the station plicable to substations of any size and measurements, known as sampled level in a tree formation, allowing the sta- topology for the station bus as well as for values (SV), for protection. The SV are tion bus to exhibit a mixed ring and tree the process bus: parallel redundancy sampled at a nominal value of 4 kHz topology. Alternatively, a ring of rings for- protocol (PRP) and high-availability in 50 Hz grids (4.8 kHz in 60 Hz mation can also be used. seamless redundancy (HSR). In both grids). protocols, each node has two identical At the process bus level, IEDs are typically Ethernet ports for one network connec- IEC 61850 does not prescribe a topolo- simple measurement and control devices tion. They rely on the duplication of gy, tree, star or ring. Indeed, the same connected to the protection and control

58 ABB review special report 3 A process bus topology 5 Redundancy in the nodes

U/I sensors UAS UAL PI SAN DANP DANP A1 I sensors IA1 IAL PI

switch control PI

PI IA2 PMC1 I sensors switch switch PI IB1 switched local area switched local area 9-2 traffic network (ring) LAN_A network (tree) LAN_B actor PI switch switch switch switch PMC2 IB2 PI I sensors C1 I PI 8-1 traffic SAN SAN SAN PI switch control A2 B1 B2 PI RedBox I sensors IC2 ICL DANP DANP DANP PI: Process interface PMC: Protection, U/I sensors UCS UCL PI SAN SAN measurement, control R1 R2

control sequence is issued. The process 4 Recovery times compiled by the IEC TC57 WG10 bus, which carries time-critical data from In a redundant the measuring units, requires a determin-

Communicating Communicating Recovery istic mode of operation, with maximum network, the most partners partners Time delays in the order of 4 ms. The recovery important param- SCADA to IED times compiled by IEC technical commit- client-server station bus 100 ms tee 57 (TC57) working group 10 (WG10) eter is the recovery IED to IED are summarized in ➔ 4. interlocking station bus 4 ms time needed to IED to IED Redundancy will be regularly checked at reverse blocking station bus 4 ms intervals of less than one minute for the restore error-free bus bar protection station bus 0 ms complete network. Only one device, sta- operation after a sampled values process bus 0 ms tion operator or gateway to the network communication center (NCC) is needed failure. Both PRP to monitor the network. Configuration errors are reported to the station operator and HSR offer zero units, which interface to the station or the NCC gateway. recovery time. bus ➔ 3. A ring topology at this level also offers a cost-effective wiring solution. Highly available network topology IEC 62439 [3] is applicable to all indus- Timing requirements in substation trial Ethernet networks [7], since it con- networks siders only protocol-independent meth- The timing requirements for the station ods. It contemplates two basic methods and process buses are distinct; they dic- to increase the availability of automation tate how redundancy is used. networks through redundancy: − Redundancy in the network. The The time during which the substation tol- network offers redundant links and erates an outage of the automation sys- switches, but nodes are individually tem is called the “grace” time, and the attached to the switches through network recovery time must be lower non-redundant links. The gain in than the grace time. As well as applying availability is small since only part of in cases of failure, the recovery time also the network is redundant. Redundancy applies to the reinsertion of repaired is normally not active, and its insertion components. costs a recovery delay. A typical example of such a method is the rapid When the station bus carries only com- spanning tree protocol (RSTP IEEE mand information, delays of some 100 ms 802.1D [8]). However, RSTP can only are tolerated. However, a delay of only guarantee a recovery time of less than 4 ms is tolerated when interlocking, trip a second in a restricted topology. and reverse blocking signals are carried, Nevertheless, RSTP is a good choice although it is unlikely that a failure will for the station bus in non-redundant take place exactly when an (infrequent) systems, such as that shown in ➔ 1.

Seamless redundancy 59 6 A duplicated station bus with parallel redundancy protocol (PRP) 7 A high-availability seamless redundancy (HSR) protocol ring

singly attached nodes DANP DANP source destinations

node node switch “C”-frame “D”-frame interlink

switch Red Box “A”-frame “B”-frame switch (HSR) (HSR)

switch switch switch

B A DANP DANP … DANP

DANP DANP SAN Red node node node node node Box DANP SAN SAN destinations

− Redundancy in the nodes. A node is nicate only with DANPs and SANs at- ring and every node forwards the frames attached to two different redundant tached to the same network), or are at- it receives from one port to the other. networks of arbitrary topology by two tached through what is known as a red When the originating node receives a ports ➔ 5. Each node independently box, a device that behaves like a frame it sent itself, it discards it to avoid chooses the network to use. This DANP ➔ 6. loops; therefore, no special ring protocol scheme supports any network is needed. topology; the redundant networks can The nodes detect the duplicates with a even exhibit a different structure. The sequence number inserted in the frames To detect duplicates, the Ethernet frames cost of implementing this redundancy after the payload. This allows full trans- include a sequence number incremented method is about twice that of the parency of PRP (DANP) and non-PRP by the source for each sent frame. Con- redundancy method discussed in the (SANP) nodes. The complete PRP proto- trary to PRP, the sequence number is not previous bullet, but the gain in col can be executed in software. Node inserted after the payload, but in the availability is large. The only non- failures are not covered by PRP, but du- header so the switch element can recog- redundant parts are the nodes plicated nodes may be connected via a nize the duplicates before they are re- themselves. PRP network. ceived entirely. Therefore, cut-through operation with less than 5 µs per node is With regard to PRP, IEC 62439-3 Clause HSR possible. 4 specifies redundancy in devices in HSR applies the PRP principle of parallel which the nodes use the two networks operation to a single ring, treating the With respect to a single ring, the bus simultaneously. This offers zero recovery two directions as two virtual LANs. This traffic is roughly doubled, but the aver- time, making PRP suited for all difficult allows a significant reduction in hardware age propagation time is reduced, allow- real-time applications. costs because no switches are used and ing the ring to support a similar number only one link is added. However, all of devices. Individually attached nodes, IEC 62439-3 Clause 5 defines another such as laptops and printers are at- redundancy-in-the-nodes solution with tached through a “redundancy box” that HSR, in which a switch element is inte- PRP offers easy acts as a ring element. grated in each device. The operating mode is the same as for PRP. integration of non- A pair of redundancy boxes can be used to attach a seamless ring to a duplicated PRP operating principle redundant devices, PRP network. In this case, each red box Each PRP node, called a doubly attached while HSR offers sends the frames in one direction only. node with PRP (DANP) is attached to This overcomes the basic limitation of a two independent local area networks cost-effective ring ring, and enables the construction of a (LANs) operated in parallel. The networks hierarchical or peer network ➔ 8. are completely separated to ensure fail- topologies. ure independence and can have different Precision clock synchronization topologies. Both networks operate in nodes of the ring must be switching The PRP/HSR scheme presents a chal- parallel, thus providing zero-time recov- nodes, ie, they have two ports and inte- lenge for time synchronization as defined ery and the continuous checking of re- grate a switch element, preferably imple- in IEEE 1588 because the delays over dundancy to avoid lurking failures ➔ 5. mented in hardware, as shown in ➔ 7. the two redundant networks are different. Here, some restriction to IEEE 1588 Non-PRP Nodes, called singly attached For each frame sent, a node sends two actually enabled the robustness and pre- nodes (SAN) are either attached to one frames – one over each port. Both frames cision of the clock system to be in- network only (and can therefore commu- circulate in opposite directions over the creased.

60 ABB review special report 8 HSR ring of rings 9 A system overview using PRP

operator workplace printer MicroSCADA 1 GPS GPS MicroSCADA 2 GPS clock

upper ring (station level) Switch Switch Switch Switch Switch Switch quadboxes

voltage level 1 voltage level 2 voltage level 3 Redundant Ethernet Bus

sub-ring REC 670 REC 670 REC 670 ....

REC 670 REC 670 REC 670 mmaintenance laptop

The bay control units (REC670) are con- Hubert Kirrmann 10 PRP and HSR features nected by two completely separated net- ABB Switzerland work rings. The entire system is synchro- Corporate Research PRP and HSR provide ideal redundancy schemes for IEC 61850-based substations in nized using SNTP sent in parallel to both Baden, Switzerland that they: networks using two independent GPS [email protected] receivers with integrated SNTP time – Fulfill all requirements of substation servers. The communication system is automation according to IEC 61850 References – Can be used in a variety of topolgies, eg, supervised using SNMP and the failure of [1] Internet RFC 2030 simple network time rings, trees. the redundant connection of any device protocol (SNTP) Version 4 (1996) from IPv4, – Are transparent to the application is immediately reported to the system. IPv6 and OSI. – Tolerate any single network [2] The Institute of Electrical and Electronic component failure Engineers. IEEE Std 1588: Standard for a – Achieve zero recovery time, making it Ideal redundancy schemes precision clock synchronization protocol for suitable for the most time-critical processes PRP and HSR make an important contri- networked measurement and control systems. – Do not rely on higher layer protocols bution in achieving interoperability – with [3] International Electrotechnical Commission, – Are compatible with RSTP respect to redundant communication – Geneva IEC 62439 (2010). Highly available – PRP allows nodes not equipped for redun- automation network suites. dancy to operate on the same network between protection, measurement and [4] The Institute of Electrical and Electronic – Use off-the shelf network components control devices from different manufac- Engineers, (2005). CSMA/CD access method (tools, controllers, switches and links) turers ➔ 10. Their success relies on the and physical layer specifications. IEEE Std – Support precision time synchronization ability of ABB to team up with competi- 802.3. according to IEEE 1588 [5] International Electrotechnical Commission, – Have been proven in the field in tors and suppliers to ensure device in- Geneva. IEC 61850-8: Communication high-voltage substations teroperability in the customer’s interest. networks and systems in substations. Part 8-1: Specific communication service mapping (SCSM) – Mappings to MMS (ISO 9506-1 and Field experience ISO 9506-2) and to ISO/IEC 8802-3. The first substation automation (SA) sys- [6] International Electrotechnical Commission, Geneva. IEC 61850-9-2: Communication tem for a high-voltage substation with networks and systems in substations. Part 9-2: control devices operating under PRP is Specific communication service mapping now ready for installation. The tests have (SCSM) – Sampled values over ISO/IEC 8802-3. proven that the technology is mature for [7] International Electrotechnical Commission, Geneva (2006). IEC 61784-2, Additional profiles substation automation devices and it for ISO/IEC 8802.3 based communication performs as expected. One of the major networks in real-time applications. requirements for this project was to have [8] The Institute of Electrical and Electronic fully redundant communication down to Engineers, (2004). ANSI/IEEE Std 801.2D, Media access control (MAC) Bridges. the bay level IEDs to remove any single point of failure in the substation control. This called for full duplication, with re- Futher reading dundant station computers (MicroSCA- – International Electrotechnical Commission, Geneva TC57 WG10 IEC 6185090-4. Network DA 1 and MicroSCADA 2 in hot stand-by engineering guidelines (in preparation). configuration for control and monitoring – Dzung, D., and Kirrmann, H. (2006). Selecting a at the substation level as well as redun- standard redundancy method for highly dant gateway functionality for telecontrol. available industrial networks. WFSC 2006 Torino. For bay level control, ABB’s latest control – Meier, S. (2007, January 25). ZHW InES – PRP: device for high-voltage applications, the Doppelt gemoppelt hält besser. Electrosuisse, REC670, is used ➔ 9. ITG Fachtagung, Zurich-Kloten.

Seamless redundancy 61 IEC 61850 – a success story around the world

Substation automation systems pave the way to a smarter grid

PETRA REINHARDT – Since the publication of the IEC 61850 standard and the commissioning of the world’s ﬁ rst multi-vendor project in Laufenburg in 2004, ABB has supported numerous customers in accomplishing the paradigm change associated with introducing IEC 61850 substation 1 automation systems. Meanwhile, more than a thousand systems and a vast 3 number of products have been delivered to around 70 countries resulting in comprehensive experience with new installations, retroﬁ t and migration 4 projects. 5

he development of powerful technologies such as sensors integrated tools and efficient processes via the process bus. simplifies the implementation 6 T of IEC 61850 across the port- The continuous commitment to the global folio of products, applications and sys- IEC 61850 standard from the mid nineties tems. Full compliance to the standard is and into the future with expert engage- verified by an in-house system verifica- ment in new editions as well as extensions tion center, the world’s first vendor- into other domains such as power gener- owned test laboratory to earn qualifica- ation, communication between substation by the UCA International Users tions and to network control centers al- Group. lows ABB to support customers wanting to benefi t from these developments. enable effi cient power system manage- The state-of-the-art product portfolio ment and integrate substations that are along with proven system integration ca- Offering its comprehensive domain knowl- reliably supplying energy from conven- pabilities enables ABB to realize the edge both of the power value chain and tional and renewable resources to millions standard’s full potential in substation au- industrial processes, ABB provides utility of people or are powering industrial pro- tomation systems. This is equally en- and industry customers with SA systems ductivity, into the smart grid. sured in systems with centralized and leveraging both current and future per- decentralized architectures, GOOSE- spectives and benefi ts of the standard. This map shows a selection of IEC 61850 based and distributed functions as well Facilitating enterprise-wide data integra- implementations around the world with as multi-vendor integration and latest tion, the IEC 61850 automation systems ABB participation.

62 ABB review special report ABB Review Special Report IEC 61850 August 2010

Editorial Council

Peter Terwiesch Chief Technology Officer Group R&D and Technology

Claes Rytoft Head of Technology Power Systems division [email protected]

Hugo E. Meier Head of Global Product Management Substation Automation [email protected]

Harmeet Bawa Head of Communications Power Systems and Power Products [email protected]

Petra Reinhardt Communications Manager Business Unit Substations [email protected]

Andreas Moglestue Chief Editor, ABB Review [email protected]

Publisher 10 ABB Review is published by ABB Group R&D and Technology.

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ABB Review is free of charge to those with an interest in ABB’s technology and objectives. For a sub scription, please contact your nearest 7 8 11 ABB representative or subscribe online at 9 www.abb.com/abbreview 12 14 Partial reprints or reproductions are permitted subject to full acknowledgement. Complete reprints require the publisher’s written consent.

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Layout DAVILLA Werbeagentur GmbH New installation AT-6900 Bregenz/Austria Retrofit/migration Disclaimer The information contained herein reflects the views of the authors and is for informational purposes ➔ 1 Teck Cominco’s Waneta 230/63 kV S/S, Canada only. Readers should not act upon the information ➔ 2 EGL’s Laufenburg 380 kV Substation, Switzerland contained herein without seeking professional ➔ 3 EDP Distribuiçao Energia’s six HV/MV stations, Portugal advice. We make publications available with the ➔ 4 Senelec’s Hann 90/30 kV S/S, Senegal understanding that the authors are not rendering ➔ 5 ENELVEN’s and ENELCO’s Soler & Médanos S/Ss, Venezuela technical or other professional advice or opinions ➔ 6 Eletrosul’s three 230/69 kV S/Ss, Brazil on specific facts or matters and assume no ➔ 7 EWA’s Financial Harbour, Sitra & Buquwwah S/Ss, Bahrain liability whatsoever in connection with their use. The companies of the ABB Group do not make any ➔ 8 DEWA SA frame contracts, Dubai warranty or guarantee, or promise, expressed or ➔ 9 Transco’s and ADWEA’s new 400 - 11 kV GIS S/Ss, Abu Dhabi implied, concerning the content or accuracy of the ➔ 10 Federal Grid Company’s Ochakovo 500/220/110 kV S/S, Russia views expressed herein. ➔ 11 NTC’s six new 161/22.8 kV S/Ss, Taiwan ➔ 12 Six new HV substations for PGCIL, India ISSN: 1013-3119 ➔ 13 SA for PT PLN’s five retrofit 150 kV S/Ss, Indonesia ➔ 14 NGCP’s Pitogo S/S and Meralco’s Amadeo S/S, Philippines www.abb.com/abbreview ➔ 15 Rio Tinto/Hamersley Iron’s 220 kV Juna Downs S/S, Australia

63 Power under control? Absolutely.

The IEC 61850 open communication standard provides a common framework for substation automation and facilitates interoperability across devices and systems. ABB’s IEC 61850 compliant systems enable real-time control and monitoring and help maximize availability, efficiency, reliability and safety. They enable flexibility for multi-vendor integration and extension, in addition to supporting enterprise-wide data integration for efficient power system management. With an unparalleled installed base and a proven track record of technology and innovation, ABB is a substation partner you can depend on. www.abb.com www.abb.com/substationautomation

ABB Switzerland Ltd Tel. +41 58 585 77 44 Fax. +41 58 585 55 77 Email: [email protected]