For single-line-to-ground faults on critical transmission lines, Single-pole tripping is sometimes utilized to avoid the negative impact of the “unnecessarily” three-phase tripping on power system transient stability. Single-pole tripping is normally followed by a single-pole automatic reclosing to restore the tripped phase and for non-permanent faults, the restoration is successful. However, occasionally, and due to the other two phases being energized, a secondary arc is formed rendering the single-pole reclosing attempt unsuccessful. To avoid such a failed reclosing attempt, and the need for a full three-phase trip and reclose with its dire consequences on the system stability, relay engineers set the dead time delay long enough to account for the typical secondary-arc extinguishing time in addition to some margin. The dead time delay is set based on prior experience with arcing faults on that specific line, or in the utility system where single-pole tripping is applied. In this paper, a novel algorithm to detect secondary arc after single-pole tripping events is discussed. Further, case-studies where this algorithm has been applied are shown. Comparison between this new reclosing function and the traditional method is also provided. The main benefit of applying this method is that, when there is no secondary arc, or when the secondary arc extinguishes relatively fast, a successful reclosing attempt is be made without the need to wait for the static dead time delay setting. Implementing this adaptive approach would lead to fully harvest the benefits of using single-pole tripping since the restoration is achieved as soon as the secondary arc has extinguished leading to a more robust system.
The increased penetration of distributed energy resources requires new protection and control algorithms to maintain stability and reliability of the distribution grid. These algorithms heavily rely on live data from the field devices to make fast operational decisions during the fault events. When a line fault occurs, the protection scheme is expected to interrupt the fault current and quickly disconnect other power sources to protect the Distributed Generation (DG) site from any damages, ensuring that it will not feed into a faulted circuit while line repairs are made by field crews. This is achieved via Direct Transfer Trip (DTT) signals, traditionally sent between substations and remote DG sites using leased telephone lines. Due to the highly specialized and critical nature of DTT systems, the equipment, including the communication infrastructure, must be extremely reliable and conform to highest substation standards. The use of traditional leased lines is becoming more and more problematic as telecommunication companies are moving away from this technology or even not providing this as a service. Fiber utilization is not always feasible due to the installation cost for long distances. A cost-effective alternative is wireless communication, including cellular systems provided by the major carriers nationwide. The cellular communication infrastructure supports tunneling of the Layer II traffic, therefore DTT applications can employ IEC61850 protocol with GOOSE messaging to perform peer-to-peer data exchange between Intelligent Controllers in the DTT/Protection system.
This paper contains a review of communication technologies commonly used for digital substations. It provides communications fundamentals, comparative analysis, standard references and recommendations, based on experiences from deployed digital substation projects. Fundamentals and protocols used for communication redundancy are included, as a topic of common confusion. Discussions based on field installations are used to illustrate the main points made.
Recently introduced Digital twin technology is based on the concept of a virtual device that can mimic an actual physical device to its greatest degree. Virtual testing of protection systems is made possible today using digital twin technology. A digital twin of a relay would include protection functions, algorithms, interfaces that can be validated by virtual testing, which would be equivalent to the testing of the physical relay itself. This would not only help engineers verify design and performance of an individual asset in a substation virtually but would also be able to validate the complete protection system without being in the real substation. Virtual testing includes digital twin of relay test equipment that performs a virtual injection of voltages and currents to the virtual analog inputs of the digital twin of the protection relay. The response is analyzed using the event records created in the relay or simply using the feedback from the HMI of the relay's digital twin. This is referred to as “Open Loop Testing”. Digital twin of a relay and a test set increases accessibility to a cost effective and well-rounded training which provides hands-on experience for all technicians and engineers. With the virtual set-up, costs associated with rental equipment, and travel could be eliminated. In this paper, the concept of digital twin technology, virtual testing of protection systems and the associated benefits are explained in detail. Virtual validation of protection systems using digital twin is explored with the help of testing and results. Specifically, a line distance protection relay is tested virtually using a virtual test system by using the digital twins of protection relay and of the relay test set, as well as physically by using the physical twins of the protection relay and relay test set. The results are then compared. Additionally, the paper sheds light on possible advantages of virtual testing towards commissioning and maintenance testing of protection systems.
This paper discusses how Silicon Valley Power (SVP) has addressed numerous constraints during rebuilding SCADA for its decades-old substations. SVP has leveraged diverse SCADA hardware offerings to achieve its goals of retrofitting SCADA for existing substations. SVP used distributed architecture of Remote Terminal Units (RTUs) to address aging wires and limited conduit space by introducing a communication-based distributed system and added Web-based Human Machine Interface (HMI) to replace annunciators and provide complete stations visibility from anywhere in SVP system. SVP innovations include the use of existing wires as communication media, and placement of measurement devices close to data sources. SVP upgrades were completed transparently to operation and without lifting a single control wire to eliminate re-commissioning.
