By Steven A. Kunsman, Director of Product Management & Applications
ABB | abb.com
A utility-scale wind farm must be accompanied by a substation or two. Equipment in the substation transforms voltage and governs the interface to the transmission grid. The substation plays a critical role and essentially acts as the motherboard of the power industry, controlling and directing power on demand, and essentially making sure the lights stay on.
Digital substations can boost the flexibility and responsiveness of transmission and distribution grids by capturing and using accurate, real-time data to control grid stability and react quickly to changing grid conditions.
To do so, electrical substations have typically used miles of copper cabling for point-to-point connections, measuring currents and voltages, and controlling the circuit breakers for power switching and protecting substation equipment. However, copper is expensive. It also has limited capacity for one measurement or a single control signal (important for power delivery and condition monitoring), and introduces potential safety risks to workers and equipment.
This conventional design and aging control equipment results in costly testing and maintenance, and restricts the communication of important information useful for identifying an asset’s health and determining when equipment maintenance is required. Grid operators of conventional copper-run substations must make periodic site visits to collect information on equipment, efficiency, faults, or failures.
If operators were able to leverage digital technology and power systems in real time, it would mean significant improvements in grid reliability, increased site and worker safety, and reduced power interruptions.
Enter, the digital revolution. Digital substations reduce the electrical connection between high-voltage equipment, let the grid run more efficiently, and create a safer work site. This is done by replacement of copper signal wires with fiber-optic connectivity. Additionally, the industrial internet of things (IIoT) is able to offer data on demand to optimize overall substation performance — often letting operators work from the comfort and safety of an offsite office.
Digital substations are not a new idea to the power industry, but the technology has been slow to adopt because of old processes, regulations, and an aging transmission grid. Times are changing, however, thanks to advances in fiber-optic communications and digital technologies.
From copper wires to digital pathways
Every copper wire in a substation is a potential electrical-shock risk, whether it is from a current transformer (or CT — which is used to measure ac power), a potential circuit (or PT, a voltage transformer), or a 125 volts DC (Vdc) control wire. The secondary circuit on a highly inductive current transformer poses the largest safety risk. A potential hazard results when an energized current transformer wire is unknowingly disconnected.
From inductive circuit theory, current flowing through an inductive circuit does not change instantly from five to zero amps. When an open CT circuit occurs, the inductive circuit can produce hazardous, high-voltage conditions that pose a safety threat. Depending on the secondary load, high voltages may build and lead to flashovers and arcing, which puts substation personnel at risk of serious injury or worse. In addition, there is possible equipment damage and downtime from arcing or fire, which means lost power and revenue.
The defining feature of a digital substation is the process bus replacing CTs and PTs with non-conventional instrument transformers. This is when sensor technology digitalizes the analog power system measurements. Additionally, the process bus means copper control wires are replaced with digitized binary information for breaker status and control. A switch to digital can cut the quantity of copper wires in a substation by more than 80%, which is a significant cost savings. Most importantly, the elimination of open-current circuits and the replacement of the copper control wires minimizes exposure to high-voltage electricity and reduces the risk of damaging equipment.
Going digital
Digital substations are gaining traction as commercial installations are recognizing the benefits. There are several reasons for this including the availability of new, high-performance digital sensors and stand-alone merging units that are easy to install. The units also offer cost savings and shorter installation times because fewer copper wires are required.
High-voltage measurement has also recently improved to offer more reliable sensors with greater accuracy, better performance, and the ability of direct digital outputs to the process bus. By going digital, the sensors preserve signal integrity and ease of connections through fiber communications. Also, unlike previous optical sensors, which were far from reliable in some cases, new fiber-optic current sensors combine the optical-current with redundant systems. Redundancy ensures fault tolerance and, in the event one system goes down, the secondary or redundant system is active.
For example, one modern non-conventional instrument transformer (NCIT) family of combi-sensors, use redundant sets of Rogowski coils for current measurement and two independent capacitive dividers for voltage measurement. A Rogowski coil accurately measures alternating current without the impact of saturation typically experienced in conventional CT’s. The design’s redundancy (which includes the associated electronics for digitaliziation) allows for two completely independent and parallel protection systems. The result is excellent availability, accuracy, stability, and performance.
Another advantage: This modern sensor contains no oil that is typical in a conventional CT so it is environmentally friendly and extremely safe. Stand-alone merging units that bridge the gap between analog conventional instrument transformers (ITs) and the digital process bus. This is important because older, conventional substations were never built for a digital network, and IT replacement for substation retrofits are costly. So, stand-alone merging units allow for the use of existing CT and PT while upgrading the protection and control system to digital technology.
NCIT sensors and merging units digitalize CT or PT signals but to achieve interoperability from different manufactures, the industry relies on adherence to open standards.
Meeting standards
Wide-scale adoption of digital messaging for substation communication is only possible if it is based on a common standard. The use of NCIT and stand-alone merging units digital outputs must adhere to IEC 61850 process bus communication standard. The International Electrotechnical Commission’s IEC 61850, Communication Networks and Systems for Power Utility Automation, is a comprehensive standard defining a communication architecture and philosophies that specify how substation devices should work and communicate. This includes what is important to communicate, and how fast.
Guidelines and standards are essential in achieving multi-vendor interoperability and the benefits of a digital substation. IEC 61850-9-2 process bus standard in substations has provided a platform that all manufacturers can develop to achieve the goal of interoperability.
For process bus communications, IEC 61850-9-2’s (released in 2004 and revised within the past few years) provides the streaming sampled measure values. That means modern sensors digitalize the power system current or voltage measurements into a package of synchronized values that are “communicated” to the protection and control devices.
Interestingly, the standard does not define the sensor types or specific means for the digital transformation. Instead, it defines a merging unit that collects the sensor information and prescribes a standard way to package and communicate the output. This means the intelligent electronic devices or IEDs — the microprocessor-based controllers (for protecting and controlling the transformers and circuit breakers) — from different suppliers can be mixed on the same bus without concern for communication incompatibilities.
The exchange of sampled values between modern sensors or non-conventional instrument transformers, and intelligent electronic devices for protection functions, allows for the real-time digital information exchange.
Substation automation systems have largely replaced conventional equipment at the station level in modern substations. However, there is still a significant quantity of conventional equipment and copper wiring at the bay and process levels, between the primary and secondary equipment. (Note: IEC 61850 is the standard that defines substation communication protocols and the need for interoperability between systems from different vendors.)
The advantages to replacing copper with a digital process bus include:
- Increased system availability by replacing electro-mechanical, static, or even outdated digital secondary equipment with modern numerical devices bundled to a real-time communication network
- Lower costs of materials by going from many copper cables to a few fiber-optic communication cables — which means reduced costs for cables and associated equipment, such as cable trenches and installation material
- Greater system and personnel safety, replacing CTs with NCITs, there is zero risk of inadvertently opening CT circuits and testing bits and bytes over fiber versus troubleshooting the DC control wires
- Improved functions come from a fully distributed architecture, coupled with advanced communication and process capability. These allow easily extending or adding new functions with minimal outage time.
- Higher standardization through IEC 61850 compliant and interoperability with various manufacturers’ equipment
- Faster, more efficient communication and asset health information availability connecting to a higher-level system, such as one for substation automation, Asset Health Center or SCADA software, allows continuous monitoring of all connected equipment
Communicating over fiber
Faster, more efficient communication is an important benefit of going digital. It generally means quicker response times, maintenance and service, and increased system availability. This is partially done by replacing copper wires with fiber-optic connectivity.
However, to realize its full value, a digital substation needs more than just digital sensors feeding data into control centers. It needs autonomous intelligence shared between substation equipment and the utility network control center, and this is where the industrial internet of things comes into play.
One of many benefits with IIoT means data can be collected via sensors on equipment in the field through cloud-based software, filtered, and analyzed in real time, 24/7. Algorithms can then help to provide insight for predictive and prescriptive maintenance and risk reduction that continually optimize the grid and improve a substation’s efficiency and cost effectiveness.
What’s more is IIoT can prove just as useful for the end-user and utility customers as it can at the digital substation and control center. IIoT can obtain, analyze, and predict electricity use and enhance consumer experiences by ensuing the lights stay on when needed and power off when not. In this way, power is saved and so are utility costs.
As power-generation sources become increasingly distributed, intermittent, and volatile, achieving high levels of control and performance requires a more intelligent and reliable grid. This is now possible thanks to advances in grid automation technology in recent years, including the development of digital substations. A fully digital substation is smaller, more reliable and has reduced life-cycle costs. It also offers increased safety and is more efficient than its conventional analog equivalent.
Add in the industrial internet of things, and that digital data can be optimized for safe and efficient use for utilities and customers.
Filed Under: News
