Protection History

Authors: Walter Schossig, Germany, and Thomas Schossig, OMICRON electronics GmbH, Austria

IEC 61850 ? The Implementations (Part 2)

In the last issues the road to IEC 61850 was described in detail. We started to explain the implementation history of several vendors. This will be continued and finalized within this article. The information is based on selected material and statements provided by the different vendors or is taken from the Internet.
Naturally this article makes no claim for completeness. Vendors’ information is randomized, neither considering chronological order nor rating it. Any comments and further inputs are most welcome.
We will start with AREVA/ ALSTOM/ ALSTOM Grid and its predecessors and successors.  The interesting and important history of development of digital protection in Stafford and other offices was already covered some issues ago. Figure 1 summarizes the history until 2014. ALSTOM is now a GE company.

The MiCOM series was the base for IEC 61850 implementations (released in 1999).  The SAS system (PACiS digital control system) followed in 2002. Since 2009 ALSTOM was certified by UCA International Users Group for conformance testing.

ALSTOM was driving forward digital substations from the beginning. The company was very active in interoperability projects and pushed the implementation of Sampled Values. 1998 came the idea to transmit “Sampled Values” by digital communication with the first proposal described in the standard IEC 60044-8. ALSTOM and the French RTE have already successfully experimented with an optical CT in Vielmoulin (400 kV). In 2002, an “Interoperability" project has been launched between several major vendors and the choice of a protocol has been proposed.

An implementation Guideline, called “LE” (for “Light Edition”) fixed the major parameters of the protocol; A successful first demo was shown at the CIGRE 2004. They developed COSI (COmpact Sensor Intelligence Solutions)- an Optical sensing technology bringing new features:

  • Enhanced safety:
    • No risk of explosion, no wired CT secondary circuit hazards, no fire
  • Measurement precision coupled with protection dynamic range
  • No saturation, ferroresonance or unwanted transients
  • No limitation with voltage increase
  • Long-term assured accuracy
  • Outstanding seismic resilience
  • Reliability, full self-diagnostics, zero maintenance
  • Lightweight, compact and flexible
  • Cabling simplification

Figure 3 shows an example setup with 2 metering + 4 protection functions per phase. A very important project was the installation at Energinet (Denmark, 2013). ALSTOM’s task was the supply of COSI optical digital instrument transformers and MiCOM P546 process bus line differential protection. A similar solution - digital instrument transformers plus MiCOM P546 line differential, were used for line to cable transition stations in hybrid circuit applications at 400kV. This was an “environmental beautifying project”- associated with moving underground the overhead circuits.

The protected circuits are hybrid lines, consisting of 400kV overhead lines, and “cabled portions” laid sub-sea. 
The operational demands are such that autoreclosing is required for faults on the overhead lines, but not for faults within the underground cable sections (Figure 4). Figure 2 shows the installation of COSI.

The Agile series (Px40 Agile) coming with Merging Units, switchgear controller units, and protection relays was released in 2013. Figure 5 shows the standalone Merging Units (SAMU). Wiring became quite easy with Sampled Values- Figure 6 shows the connection to MiCOM relays.         

In 2010 Schneider Electric and Alstom signed the agreement for the acquisition of Areva T&D. Schneider Electric is also very active in IEC 61850 and actively participating in IEC and UCAIUG developing this new substation communication technology. Following successful interoperability demonstrations at CIGRE 2004 and many other events, Schneider Electric Automation has been busy adapting its Protection (MiCOM P range) and Control (MiCOM C range) devices to support this new international standard. Figure 8 shows the bay controller C264.

Schweitzer Engineering Laboratories (SEL) in the US was mentioned already in detail when discussing the first activities (GOMSFE and others) and also when describing the first GOOSE implementations. They are quite active in the different standardization groups (UCA, IEC TC 57 …) and contribute continuously.

The Utility Communication Architecture (UCA) meetings were held several times and hosted by Kay Clinard of KC Associates.  They were a forum to discuss development and usage of UCA products, and demonstrate UCA capable products. Participants who have implemented the UCA Generic Object Oriented Substation Event (GOOSE) peer-to-peer communications service are given recognition for their achievement. This recognition was called a GOOSE Award and was accompanied by the LUCY GOOSEY Beany Baby (Figure 7).

In January of 2000, SEL received this prestigious GOOSE award because it was the first time that GOOSE was exchanged between two different manufacturers.  They received this joint award with GE because they both subscribed to one another's GOOSE. 

SEL mapped the status of a front panel push button into GOOSE publication and then provoked status changes in the GOOSE data set.  Then, after successful subscription of the GE GOOSE, SEL was able to run logic based on this and display on the front panel and light an LED.

SEL joined all UCA demonstrations and Interoperability Tests (IOPs) that took place so far (Figure 10.)

After the 2004 CIGRE show the number of SEL customers using IEC 61850 jumped to over 550 customers in the year 2005. 2005 also saw some important GOOSE, data modeling, and MMS demonstrations first at the Dolan Laboratory at AEP and then at the Western Protective Relay Conference (WPRC).  AEP hosted the May 27 UCA International User Group (IUG) meeting at their Dolan Laboratory where AEP designs were being tested and they had begun performing KEMA testing of third party IEDs.  AEP was one of the first utilities to use SEL and SEL was invited to again demonstrate UCA2 and IEC 61850 GOOSE, data modeling, and MMS interoperability with other manufacturers as shown in Figure 9. The WPRC demonstration was not a UCA event but was organized by Siemens and included numerous manufacturers.  SEL demonstrated UCA2 and IEC 61850 GOOSE, data modeling, and MMS interoperability with other manufacturers via several SEL products including: SEL operator workstation computer, communications switch, and several relays.  Also shown were support of IEEE synchrophasors, web pages, FTP, and Telnet on the same shared LAN. In 2006, SEL designed and built the first multi-vendor IEC 61850 system for CFE in Mexico. Other SEL prototype process bus SV installations followed including Chicoasen 400kV substation yard in Chicoasen, Chiapas, Mexico   (both will be covered in the next issue).

SEL also provided 9-2LE and IEEE 1588-2008 technology for the system built for the Russian Federal Grid Company in FGC research institute, Moscow, Russia.  The panels were commissioned in December 2011. In 2011, SEL participated in the UCA IOP interoperability demonstration hosted by EDF in France.  SEL subscribed to 9-2LE SV from numerous manufacturers merging units and also demonstrated that the SEL ICON WAN multiplexers were precise enough to transport SV messages between substations. And then in 2012, SEL provided 9-2LE and IEEE 1588-2008 technology for the Elgaugol Company mining the Elginskoye Coal Deposit in Russia. These prototypes were again installed as sampled value subscribers as part of a multiple manufacturer system.

In 2007, SEL began the modernization project of 30 substations for Elektro Eletricidade e Serviços S.A., a large electric distribution utility in Brazil.  This was an important milestone because it was the first substation to use GOOSE protection signals to perform tripping. 

The systems also provided dramatic cost savings by eliminating most of the copper field wiring. The system provided seamless integration of GOOSE and MMS to exchange control data between relays, programmable automation controllers, load-tap-changer controls, and rugged computers and used DNP3 LAN/WAN (local-area network/wide-area network) to provide data to the remote control center.  In this system, the feeder, bay control, and transformer relays communicate using peer-to-peer IEC 61850 GOOSE messages for the protection and control schemes, including breaker failure and bus protection, interbay interlocking, event report triggers, and automatic transfer between two 138 kV lines. The adoption of IEC 61850 made it possible to build a decentralized automation system, distributed over several intelligent electronic devices (IEDs).  This substation was considered the first Digital Substation by today’s definitions because the relays were used as IEC 61850 intelligent merging units, did the protection out in the yard, and published digital messages over fiber to the control house relays. In 2007, Pennsylvania Power and Light standardized on their next-generation substation (NGS) design based on networked Ethernet intelligent electronic devices (IEDs) communicating via IEC 61850. This document discusses the new technical design details of networking IEDs over Ethernet, and more importantly, how engineering, installation, and testing practices had to change to accommodate the new technology.

PPL methodically replaced their previous protection and control design with a design that provides more functionality while migrating to IEC 61850 communications from multiple IED vendors. In the end, over 50 percent of the hardware, 60 percent of the hardwired connections, many programmable devices, and several software programs were eliminated. New testing techniques were developed to test IEC 61850 communications, and wiring drawings were replaced with GOOSE messaging tables so that test technicians could identify the endpoints of the “virtual” wires. In 2008 SEL installed several SEL relays, controllers, and rugged computers at Southern California Edison (SCE) to demonstrate performance of SEL products and interoperability with other manufacturers. The relays were acting as contingency monitors and mitigation devices for a wide area remedial action scheme (RAS).

 

The SEL rugged computer ran a centralized RAS algorithm and reacted to contingency signals received via GOOSE by publishing mitigation signals via GOOSE as well. More details in the next issue. Another milestone was reached in 2010 when SEL installed digital merging units for CFE for their new transmission project at the Tabasco substation.  This was the first time CFE used IEC 61850 protocols to replace field wiring with merging units communicating over fiber.

In 2011, the Republic of Georgia became the site of the first country wide RAS scheme relying on IEC 61850 GOOSE messages to exchange contingency and mitigation control signals.  Georgian State Electrosystem (GSE) is responsible for operations, management, and dispatching within the Georgian power system and has responsibility for the operation of the 500 kV, 220 kV, 110 kV, and 35 kV transmission facilities while maintaining power system stability. The system comprises 3,000 kilometers of transmission lines (500 kV, 220 kV, 110 kV, and 35 kV) and 89 substations dispersed in the Georgian territory.  The system deployed in 2011 was a decentralized emergency control system (ECS) installed quickly and efficiently to prevent blackouts.  GSE performed a live test early in the morning with conditions that would normally provoke a blackout.  It did not happen.  The IEC 61850 GOOSE RAS scheme quickly acted across the entire country to balance generation and shed load to prevent a blackout. After installation, the system correctly operated within the first week which saved GSE enough money to pay for the entire ECS system.  It operated another 11 times within the first month using GOOSE messages across long distances to prevent blackouts.  Since 2011, the system has been updated to also include centralized RAS logic that collects and acts on much more power system decision making information and performs more discrete controls.  Based on their experience with IEC 61850 for their RAS system, GSE is now modernizing their substation automation systems based on IEC 61850 as well.

In Germany SIEMENS was very active in IEC 61850. And so the histories of IEC 61850 and SIPROTEC are strongly interconnected. SIEMENS contributed to the definition of UCA 2.0 for substation automation (1994) as well as after the merge of IEC TC57 and UCA activities (1997).

SIPROTEC 4 series was released in 1998. Even if focusing on serial protocols (such as IEC 60870-5-103) at this time the devices have been ready for the upcoming IEC 61850. With the official publication of IEC 61850 in the year 2004 the race for the first implementation project of the new standard started. Honor to whom honor is due- SIEMENS put the first substation with IEC 61850 into operation in November 2004. Since this was the first worldwide substation with IEC 61850 – here are some more details. The customer ATEL in Switzerland ordered the project Winznauschachen in April 2004. The 16-kV-substation delivers power for 2 towns - Winznau and Dulliken, Figure 12 shows the network arrangement.

The Substation Automation System (SAS) contains 9 IEC 61850 devices (8 IEDs, 1 station controller), they are communicating via one 100 Mbit/s Ethernet ring. The connection to the national control center is realized with IEC 60870-5-101 (Figure 13, Figure 14, and Figure 15).

SIPROTEC 4 was also the first certified IEC 61850 Edition 1 server (2005). Already in 2008 SIEMENS could announce more than 100,000 protection devices with IEC 61850 in operation. In 2009 at RWE SIEMENS and others joined the first interoperable multivendor process bus project. This we will cover in the next issue of the magazine. The official publication of IEC 61850 Edition 2 was in 2012. This was also the year of SIPROTEC 5 market launch featuring IEC 61850 Edition 2. SIPROTEC 5 (Figure 16) is the first certified IEC 61850 Edition 2 server (2012), and SICAM PAS/PQS the first certified IEC 61850 client (2015). Siemens offers PRP/HSR redundancy in SIPROTEC 4 / 5 since 2013.

A main topic from the beginning was testing. OMICRON joined the standardization community and was involved from the beginning. Already at the “Vancouver demo” in May 2001 GOOSE could be tested (Figure 11). Products for testing UCA-GSSE and GOOSE became available soon. And already in 2005 the first tests with Sampled Values could be performed (Figure 18). At the CIGRE 2006 UCA International demonstrated interoperability.  Merging Units from ABB, AREVA and SIEMENS have been working together with OMICRON’s CMC 256 stimulating MUs and publishing Sampled Values (Figure 17).

Testing is not just protection testing with real time data as GOOSE and Sampled Values. A test client allows access to IED’s data model. The stack vendor Tamarack Consulting developed “Tamarack browzer” to perform such tasks. Together with OMICRON they made out of it “IEDScout- the Engineer's Universal Tool for Working with IEC 61850 IEDs”. The first version was released in 2006 (Figure 19). The software became quite successful. Version 4.0, released in 2014 contained an OMICRON stack and came with a new user interface (Figure 21). In 2016 an IEC 61850 client became a part of the OMICRON’s Test Universe (Figure 22).

Other testing equipment vendors joined the community and developed test sets and testing solutions. Megger came with their GOOSER in 2010. The GOOSER can convert a GOOSE message received on its rear Ethernet port into binary output and it can convert a binary input into a GOOSE message and publish it at its rear Ethernet port. The conversion time is typically 0.6 ms. The GOOSER is equipped with 10 binary inputs and 10 binary outputs. Using these it can convert simultaneously up to 20 GOOSE messages. Binary inputs of the GOOSER can react on DC-voltage presence (voltage sense or "wet" contact mode) or can independently detect an applied closed/open contact (contact sense or "dry" contact mode) - (Figure 20).

With Megger’s GOOSE configurator integrated IEC 61850 testing is possible for their test sets (as SMRT 46).

Doble’s test equipment became also capable for IEC 61850. Simulate, monitor and test IEDs on digital substation network is possible with Doble’s 61850 Test software. With Doble’s F6150sv and Protection Suite software it is possible to apply sampled values (SV) and generic substation event (GSE) simulations to functionally test, receive status messages and get more data from substation devices.  The DOBLE F6150 combined with F6860 option is capable for IEC 61850 since 2007.

This finalizes the history of IEC 61850 covering by the vendors. The next issue will report important projects, especially focusing on interoperability and will be the end of the IEC 61850 series.

walter.schossig@pacw.org        www.walter-schossig.de     
thomas.schossig@omicronenergy.com

Relion advanced protection & control.
Protecting your electrical assets? today and tomorrow