Authors: Richards, S., Alstom Grid, UK, Pavaiya, N., Omicron Electronics, Boucherit, M. and Ferret, P., Alstom Grid, France, Diemer P., Energinet.dk, Denmark
Non-conventional fully-digital instrument transformers were selected due to their low mass and slim line construction, replacing conventional wound current transformers. Correct application of IEC 61850 standards allowed a lot more of the substation engineering to be undertook in the controlled environment of the factory, rather than on the substation site – where outage times and site labor are at a premium.
The article also discusses advantages beyond the Energinet.dk project, such as digital control systems also using an IEC 61850-8-1 station bus. Full protection and control can extend the IEC 61850 implementation to both station and process buses. Process bus deployments replace the traditional hardwiring to primary equipment with an Ethernet link, and also convert the primary current and voltage measurement channels into protection relays and other IEDs (intelligent electronic devices) to fiber-optic. Digital implementation helps to reduce the substation physical size, move as much configuration and testing to the FAT stage (factory acceptance testing), and also decouples the often dissimilar renewal cycles of the primary and secondary equipment.
The Digital Substation
Firstly, one might ask “what is a digital substation?” and this will yield a variety of possible replies, as there is no standard definition. Clearly as most substations today are switching and routing AC power at high/extra high voltage, it is not the primary flow which is digital. This means that we are talking about the secondary systems, and all the protection, control, measurement, condition monitoring, recording and supervisory systems associated with that primary “process.”
In general terms, a full digital substation is one in which as much as possible of the data related to the primary process is digitized immediately, at the point where it is measured. Thereafter, the exchange of that measured data between devices which may need to subscribe to it is via Ethernet, as opposed to the many kilometers of copper hardwiring which may exist in a conventional substation.
Digital substations imply a solution and architecture in which the substation’s functionality is predominantly now achieved in the software, with lesser reliance on hardware implementations such as hardwiring
Drivers toward Digital Substations
A. The process level
A digital substation is based on a communicating architecture, whereby real-time operational measurements are polled from the primary system. This data is obtained using sensors, embedded within the primary system. It is communicated to devices which must act on those measurements by means of a “process bus.” Most important is that smart devices and systems within the substation can immediately process this operational data.
By subscribing as clients to this data flow over an Ethernet process bus, the information from the “eyes and ears” of the power system is distributed and communicated much more efficiently to the bay level than in conventional hardwired schemes.
A digital substation is based on a communicating architecture, whereby real-time operational measurements and other data are polled from the primary system. This data is obtained using sensors, embedded within the primary system, which is termed as the electrical process.
It is communicated to devices which must act on those process-level measurements (pressure or temperatures in GIS switchgear, current and voltage measurements derived from optical or Rogowski-effect digital instrument transformers, or switch positional status information) by means of a “process bus”.
Most important is that smart devices and systems within the substation, (protection relays, recorders, phasor measurement units, bay controllers, wide area controllers or asset managers), can immediately process this operational data. By subscribing as clients to this data flow over an Ethernet process bus, the information from the “eyes and ears” of the power system is distributed and communicated much more efficiently to the bay level than in conventional hardwired schemes.
The process bus is also the link by which the primary equipment information from out in the yard travels back to the substation control house – it links the field back to the substation.
In a fully digital architecture, control commands (switchgear operator commands, protection trips) also are routed to the primary devices via the process bus, in the opposite direction.
The process bus is therefore supporting time-critical services.
B. The protection and control level
Between the process bus and the station bus are devices historically identified as the “secondary equipment.” In the digital substation, these devices are IEDs (intelligent electronic devices), interacting with the field via the process bus, and with other peer devices in the bay, to other bays, and the digital control system via the station bus (Figure 1).
C. The station control area
The digital substation station bus is much more than a traditional SCADA bus, as it permits multiple clients to exchange data, supports peer-to-peer device communication, and links to gateways for inter-substation wide-area communication. GOOSE is more often than not used as high-speed exchange of binary status information/commands.
The IEDs perform their time critical functions such as protection, point-on-wave switching supervision and other tasks via direct interaction with the process bus.
However, other clients in the substation may require information-sharing of some or all of this pre-processed data. For example, protection and control schemes may be distributed amongst multiple IEDs, typically in the case of auto-reclose, breaker fail, interlocking and dynamic reconfiguration (“fast transfer”) schemes to name but a few. Often, this will be IEC 61850 GOOSE-based.
In addition to the need for distributed intelligence between IEDs at the station level, there is the need to distribute the information to local or remotely-stationed control operators to visualize the operational status of the substation. This requires substation HMIs (human-machine interfaces) and proxy server links to remote HMIs and control servers, to communicate pertinent data in real-time. One or several workstations apply the instructions assigned by regional dispatchers, or can be used as an engineering workstation for IED configuration, or for local concentration and archiving of power system data. On-line condition monitoring may have specific workstations for alerts, and to manage the database history of each primary device.
Decades of extensive research has delivered proven non-conventional instrument transformers, designed to be accurate, intelligent, safe, cost-effective and - importantly – core-less.
The root of many of the limitations of conventional instrument transformers is the reliance upon an iron core.
The core is a source of inaccuracy, due to the need to magnetize it, but not to overflux it. In the case of conventional CTs, achieving the low-level accuracy and dynamic range to satisfy both measurement and protection duties is a challenge. Instead of an iron core, the translation from primary to secondary measurement may use optical, Rogowski or capacitive technology, with the optimum choice for AIS (Air-Insulated Substation) and GIS (Gas-Insulated Substation) driven by the respective digital device size, which in turn permits size optimization of the switchgear.
Some examples of the principles are as follows, considering just the CT function here for brevity:
Optical sensors (AIS) use the Faraday effect, whereby a fiber optic loop sensor carrying a polarized light beam encircles the power conductor. This light will experience an angular deflection due to the magnetic field, generated by the primary current flow. The sensor’s intelligence is to accurately determine the primary current based on the real-time optical measurement
Rogowski sensors (GIS) dispense with the conventional CT core and instead implement windings as tracks on a multi-layer printed circuit board. Four quadrants of the board are clamped together to form a toroid around the primary conductor. The sensor output becomes a low-level voltage measurement, which can be accurately correlated to the primary current
Capacitive sensors for AIS are a capacitor divider, which can be fitted as a stack within a slimline construction VT. For GIS the GVT sensor is laid on the inner face of a bus duct, such that a pliable printed circuit board carrying wraps the complete circumference. The electrodes on the PCB have an exact, picofarad capacitive coupling with the power conductor.
Enhanced safety: no risk of explosion, no wired CT secondary circuit running cross-site
In this project, the protected circuits are hybrid lines, consisting of 400kV lines, and cabled portions laid underground for environmental beautification. There are paralleled pairs of cables each 5km length, and the operational demands are such that auto reclosing is required for faults on the overhead lines, but not for faults within the underground cable sections. The differential protection is thus used for fast and precise detection of faults within the cables. The cables are a part of the two main 400kV connections running from the south to the northern part of Denmark.
The equipment supplied includes 72 optical CT units, 24 merging units and 24 line differential relays which subscribe to the sampled values in a process bus protection scheme.
A lightweight dry type insulator and window head design allow mounting of the Optical CT (COSI) and CVT on a single pedestal saving valuable yard space. For Energinet, Denmark, a single structure and foundation per phase carries the larger mass of the cable, plus the optical CT support on a cantilever frame extending to 2 meters horizontal distance.
The reduced size and weight are attractive benefits over conventional combined units, allowing placement in compact substations where space may be limited. Its broad dynamic range makes this CT particularly suited for independent merchant plants where extreme accuracy at both full power output and station service draw is demanded. In order to improve safety, the removal of wired cross-site current transformer circuits reduces the risk of lethal injury due to inadvertent opening of the circuit by personnel. The avoidance of oil in instrument transformers reduces explosion risks too (Figure 3).
All protection relays and merging units are mounted in 19” racks. Fiber connections from the cable management box (CMB) in the yard to protection panel are spliced at a patch box mounted inside the cubicle. Fiber connections between GPS time synchronizing units and merging unit/current differential relays are done directly via patch cables on the rear of the panel in the 19” rack (Figures 4 and 5).
An Omicron test set was used to inject current directly through the primary of the COSI-CTs. In order to limit the required magnitude of current to be injected, multiple turns were passed through the COSI-CT. This enables the scheme to be tested as an in-service simulation, proving the scheme from primary current through to current differential protection. Two main categories of tests were done to prove the current differential protection, these are the bias characteristic and the operating time. The bias characteristic was plotted to show the implementation of the sampled values has no impact on the protection characteristic. To further prove the operation of the protection scheme, the operating times for internal faults were also submitted during the FAT.
Conclusion: Digital substation implementation allows the lifetime total cost of ownership of the substation to be reduced. The reduced size and weight of digital instrument transformers, and the protection and control panels provide attractive benefits, allowing placement in compact substations where space may be limited.
The Energinet project shows the increasing confidence in the application of digital substations within Europe. This is essential at this network voltage level, where cost savings and health and safety are of paramount importance. As such, this project is a valuable return on experience for other utilities to follow in a similar manner for both new and refurbishment projects.
Simon Richards is Products Marketing Director for Alstom's Substation Automation Solutions product line. He is responsible for managing the life cycle of the Products activity portfolio. Before joining Alstom, Simon held a 25kV electrification Distribution Engineer position for the 500km West Coast Main Line railway in the U.K. Prior to his current role, Simon held different protection application engineering and regional business development positions within Alstom Grid. He is the Digital Substation Marketing coordinator for Alstom Grid as a whole. He holds a number of patents in the domain of substation electronic devices. Simon has a B.Eng (Hons) in Electrical and Electronic Engineering from the University of Bath, and is a Chartered Engineer, and MIET.
Neha Pavaiya is an Applications Engineer for Omicron Electronics, UK. She graduated from Northumbria University at Newcastle-Upon-Tyne with a BEng (Hons) in Electrical & Electronic Engineering. She joined Alstom Grid's Graduate Development Programme in 2007 and later the Substation Automation Solutions business of Alstom Grid as an Applications Engineer. She primarily specializes in testing and IEC61850 applications support, now at Omicron.
Mehamed Boucherit is a Developer on LPIT (Low Power Instrument Transformers). He graduated from the University of Physics of Rouen, France in Laser Diagnostic and Optical metrology. He started with ALSTOM in 1999 involved with R&D. Later he worked on Industrial development of the CT, VT and Rogowski solutions, and as Coordination engineer for NxtPhase integration. He is the author of the first 9-2LE analyzer. He is recognized as an expert on LPIT. He is active member of TC38WG37 for the new IEC 61869.
Paul Ferret is a Design Engineer for ALSTOM GRID the South West Europe and Africa Solutions Group. He graduated from IUT2 Lyon1 University at Villeurbanne in 1976 with a DUT in Electrical & Automatism Engineering. He joined Alstom Grid in 1978 and worked during twelve years as a Design Engineer for High Voltage Substation projects, before specializing in Digital Control Systems for substation control and supervision. Three years ago, he joined the High Voltage Sensors and Electronics department to support the integration platform dedicated to Digital Substation tests.
Peter Diemer is a system integrator engineer at Energinet.dk (TSO) Denmark. Peter Graduated from Københavns Teknikum in June 1997 with a B.Sc. in Electrical Engineering. He Joined ABB Energy as a SCADA and protection Engineer in 1996. The position at ABB also consisted of a training consultant position, both in SCADA and protection engineering. In 2007 Peter joined Energinet.dk as a protection engineer. Peter primarily specializes in design and implementation protection Schemes in the 132, 150 and 400kV networks in Denmark. Furthermore he specialises in integration of IEC61850 schemes.