The digital impulse: the fully automated future

22 February 2013

Digital devices in substations are prevalent but technology now permeates all areas, to the point where transmission susbstations can become fully digitised. Simon Richards and Denis Chatrefou of Alstom Grid outline the drivers towards digital.

What is a digital substation? This question yields a variety of possible replies because there is no standard definition. Because most substations today are switching and routing AC power at high or extra-high voltage, it is not the primary flow that is digital. This means that we are talking about secondary systems: all the protection, control, measurement, condition monitoring, recording and supervisory systems associated with the primary process.

In general terms, a fully digital substation is one in which as much as possible of the data related to the primary process is digitised immediately, at the point where it is measured. Thereafter, the exchange of measured data between devices that may need to subscribe to it is via ethernet, as opposed to the many kilometres of copper hardwiring that may exist in a conventional substation. In reality, many utilities will wish to go fully digital at a pace that suits their engineering capabilities and technology aspirations.

As showcased by Alstom Grid on its stand at CIGRE 2012 in Paris this August, where all the components of a fully digital transmission substation were brought together and exhibited for the first time, the technology is now mature. Fifteen years of prototyping, site trials and perfecting of the technology have passed, to the point where this technology is offered as a real commercial proposition, with a number of contracts currently under execution.

In such digital substations, functionality is predominantly achieved in the software, with lesser reliance on hardware implementations such as hardwiring. Here, we suggest some of the steps that could be taken, and how adherence to international standards ensures interoperability can be built-in.

Drivers towards digital

1. Increased reliability and availability. The extensive self-diagnosis capability of digital devices ensures maximised uptime of the substation. Any degradation in the performance of an asset is pinpointed in real-time. Inherent redundancy in the system may be employed to self-heal the operation, which permits troubleshooting without the need for any primary system outage.
2. Optimised operation of assets. The intelligence within digital substation schemes allows close monitoring of the load-flow capacity of plant equipment, compared to its design ratings. This dynamic load analysis permits operation of lines, cables, transformers and other grid equipment closer to their limits.
3. Improved 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.
4. Reduced maintenance costs. The digital substation closely monitors all substation assets in terms of operational conditions, effective load capacity and asset health indicators. Intelligent systems analyse the data and provide recommendations on maintenance and repair actions to conduct. This allows a shift to predictive maintenance, avoiding unplanned outages and emergency repair costs. It is in this regard that ongoing operational cost savings may be made, such that the lifetime total cost of ownership of the substation will be reduced. Additionally, asset optimisation and loss-of-life monitoring tools facilitate the identification of weak areas on the primary system, which need to be reinforced.

5. Easier renovation and extension of existing substations. Interoperable solutions and the use of fibre-optics instead of copper wires reduce the duration and cost of onsite work for the refurbishment of secondary equipment. Design of the substation plans for mid-life refurbishment of secondary schemes while primary equipment can be left as-is, given that decades of serviceable life may still remain. This permits refurbishment to be done with the absolute minimum of primary system outage.
6. Improved communications capabilities. Data exchange between intelligent devices, intra and inter substation, is optimised through ethernet communications. Smart local and wide area control units (WACUs) can allow data exchange between voltage levels in substations, and between substations. Direct inter-substation communication without the need to transit via a control centre reduces the response times, for fast, real-time applications.
7. IEC 61850: a crucial enabler. Modern sensors and other intelligent electronic devices (IEDs) must be connected to communicate within the substation and with the greater grid system at large. In the past, there were many different protocols and a lot of effort went into making them communicate. For many years, insufficient standardisation, fear of degraded reliability and lack of return on investment slowed down the emergence of a fully digital substation. But the IEC 61850 standard has changed all that and
facilitates interoperability between different equipment and suppliers.

"A fully digital substation is one in which as much as possible of the data related to the primary process is digitised immediately, at the point where it is measured."

IEC 61850 is the international standard for ethernet-based communication in substations. It is more than just a protocol; it is a comprehensive standard designed for utilities, to deliver functionality that is not supported in legacy communication protocols. Introduced in 2004, the standard is increasingly accepted across the world because its main objective is to ensure interoperability between equipment coming from various suppliers. The standard is growing to encompass the needs identified by the industry's user group, to ensure that it caters for all substation needs.

IEC 61850 allows for the full digitisation of signals in a substation and is necessary to allow the large amount of data associated with real-time management of a smarter power grid to be organised and communicated. It is designed for interoperability and longevity, in order to achieve independence from any one supplier or generator of equipment.

The architecture of a digital substation

Primary equipment process level. The primary equipment process level includes capture of voltage and current signals, consolidation, processing and transmission of data via fibre-optics, with intelligent primary devices (electronic power and instrument transformers, circuit-breakers and disconnectors, for example) and fibre-optic replacing traditional current transformer (CT) and voltage transformer (VT) systems and conventional hardwiring.

8. Protection and control level. Between the process bus and the station bus is the secondary equipment (protection, measurement devices, bay controller, recorders, etc). In the digital substation, these devices are IEDs, 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.
9. The station control area. The station control area includes communication within the substation and control system, coordination with the substation operational function and the station-level support function. The digital substation station bus is much more than a traditional SCADA bus, because it permits multiple clients to exchange data, supports peer-to-peer device communication and links to gateways for inter-substation wide-area communication.
10. Digital instrument transformers. A key feature of the digital substation is the use of digital instrument transformers. 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 magnetise it, but not to over flux 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.
11. Analogue signal conversion, merging and switchgear control. Primary converters associated with each CT and VT convert analogue signals from the primary equipment into digital signals. The converters interface with merging units to perform all the digital data processing necessary to produce a precise output data stream of sampled values according to the IEC 61850-9-2 standard. For retrofitting, or where there is a preference to retain traditional instrument transformers, analogue merging units are available, such as the MU Agile AMU, digitising the CT and VT outputs at any convenient kiosk. Digital controllers are the fast, real-time interface to switchgear, mounted close to the plant they command. They replace hardwiring of inputs/outputs by an ethernet interface to the yard.
12. Numerical protection relays. In a fully digital architecture, protection relays receive currents and voltages as IEC 61850-9-2 sampled values, and issue trip or alarm signals using IEC 61850-8-1 GOOSE. Alstom's MiCOM IEDs extend the supervision facilities to include comprehensive addressing and Plausibility checking of the incoming sampled values from the process bus. This addresses the fact that the traditional task of current and voltage sampling is now external to the device, and is connected via ethernet. The supervision compensates for any latency or mismatch in the network, provides ridethrough intelligent compensation in the event of several missing samples or jitter, and blocks/alarms if the quality of incoming data would compromise the secure and reliable protection operation of the IED. This ensures maximum security, dependability and speed.
13. Digital control systems. Any digital substation will need a system by which operation and control data can be obtained and communicated to operational personnel by an intuitive human-machine interface. These personnel may be local to the substation, or at a remote control centre. This information flow from the substation to the HMI might be deemed the monitor direction, and the DCS supplements this in the control direction by allowing the operator to interact with the primary plant.

2012 saw the launch of Alstom's DS Agile control system, the intelligence that binds the digital substation. DS Agile is central to the flow, management and presentation of all components in the digital substation.

Particular focus has been on networking operational and plant condition monitoring data, for the first time, within what would have traditionally been exclusively a protection and control system. This avoids the need to overlay multiple ethernet networks, because the system is deployed as a generic whole. In addition, attention has been paid to how data can be presented as simple dashboards so that staff can clearly see what is happening on the network.

All of Alstom's digital substation architectures can be set up as an IEC 62439 standards-compliant self-healing ring (HSR protocol) or dual-homing star (PRP protocol), both of which are "bumpless" redundant. This means that data is exchanged between devices on two paths, and should one of these paths fail, data is instantly available hot from the other, with zero delay.

"2012 saw the launch of Alstom’s DS Agile control system, the intelligence that binds the digital substation."

Fibre-optic networks link all the system's components, together and with the operator interface (HMI), through a full range of ethernet switches. WACUs offer the possibility to exchange IEC 61850 GOOSE data between voltage levels within a substation and also between neighbouring substations.
14. Online condition monitoring and asset management. Online condition monitoring functions are delivered for power transformers, circuit breakers, disconnectors and gas insulated switchgear. Physical parameters are continuously monitored and real-time measurements are combined and compared to models in order to generate specific recommendations regarding operation and maintenance, as well as alarms when necessary. An interface with an asset management system yields additional features such as
remaining lifetime or dynamic rating capabilities. The new architecture enables operational and maintenance teams to have an overview of the condition of all substations in real time, and take appropriate and strategic asset management decisions.
15. Cyber security. Intrusion protection and protection against virus attacks is recommended for all switches and IEDs. Cyber security provides protection against unauthorised access to equipment and unauthorised transfer, modification or destruction of data - whether deliberate or accidental. Particularly when wide area networks extend beyond the traditional substation fence, cyber-security measures are essential. Security procedures, controls, firewalls and role-based access are all examples of this.

The extensive self-diagnosis capability of digital devices ensures maximised uptime of the substation.

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