A substation asset management method can include the steps of: determining whether to compensate a reliability model by element of the substation by comparing reliability of a reference reliability model by substation type with reliability depending on health index by element thereof generated based on state data and real-time monitoring data by element of the substation; compensating the reference reliability model by substation type and generating a unique reliability model by element of the substation as a result of the determination; evaluating system reliability and economic feasibility by maintenance scenario based on a reference system reliability model for each candidate element subject to maintenance among the elements of the substation; and drawing a maintenance scenario of the elements of the substation by using a fitness function of maintaining the substation based on the result drawn through the evaluation of the system reliability and the economic feasibility.

Systems and methods for network failover in digital substations are provided. One method includes receiving, by an intelligent electronic device (IED) from a process interface unit (PIU), in parallel a pre-configured data stream via a point-to point connection and one or more other data streams via an Ethernet network. The method further includes determining that at least one of the following failure conditions is satisfied: a frame in the pre-configured data stream is lost or delayed, quality of the data in the frame in the data stream is below a first threshold, period of the time associated with the data in the frame in the data stream is below a second threshold, or a health indicator associated with the PIU is below a third threshold. The method further allows identifying at least one redundant frame in the one or more other data streams. If the quality of data in redundant frame is satisfactory, the method proceeds to use the redundant frame for further processing.

A system and method for inferring schematic and topological properties of an electrical distribution grid is provided. The system may include Remote Hubs, Subordinate Remotes, a Substation Receiver, and an associated Computing Platform and Concentrator. At least one intelligent edge transmitter, called a Remote Hub Edge Transmitter, may transmit messages on the electrical distribution grid by injecting a modulated current into a power main that supplies an electric meter. The Subordinate Remotes, Remote Hubs, the Substation Receiver, and the associated Computing Platform and Concentrator may contain processing units which execute stored instructions allowing each node in the network to implement methods for organizing the on-grid network and transmitting and receiving messages on the network. The Substation Receiver, Computing Platform, and Concentrator may detect and infer schematic grid location attributes of the network and publish the detected and inferred attributes to other application systems including geospatial information systems.

An IEC 61850 Network Control Center (NCC) server is provided at a gateway intelligent electronic device (IED) of a Substation Automation (SA) system. The NCC server serves, via the MMS/TCP/IP part of IEC 61850, process data from substation Intelligent Electronic Devices IEDs to a NCC. The NCC server uses functional names for gateway Logical Nodes (LN) corresponding to substation LNs. The functional names are devoid of any reference to a substation IED related name of the substation LNs, but can be automatically translated to substation IED related names in case of changing SA communication and substation IED architecture. Thereby, functional names as defined by the substation section within a SCD file of the SA system are used for the communication link between the gateway IED and the NCC.

An apparatus and method for ensuring the reliability of a trip protection of an intelligent substation. The apparatus comprises a main CPU and an auxiliary CPU connected together, and a main FPGA and an auxiliary FPGA connected together. The main FPGA and the auxiliary FPGA are connected to a physical layer of a protection apparatus, and the main CPU and the auxiliary CPU are connected to a state monitoring data output end of a protected device. The main CPU sends a processing result to the main FPGA, the auxiliary CPU sends the processing result to the auxiliary FPGA, and the auxiliary FPGA synchronizes current information with the main FPGA after receiving information sent by the auxiliary CPU. When the main FPGA receives trip information, the main FPGA comparing the consistency of current trip information obtained from the main CPU with current trip information obtained from the auxiliary FPGA.

Systems and methods for network failover in digital substations are provided. One method includes receiving, by an intelligent electronic device (IED) from a process interface unit (PIU), in parallel a pre-configured data stream via a point-to point connection and one or more other data streams via an Ethernet network. The method further includes determining that at least one of the following failure conditions is satisfied: a frame in the pre-configured data stream is lost or delayed, quality of the data in the frame in the data stream is below a first threshold, period of the time associated with the data in the frame in the data stream is below a second threshold, or a health indicator associated with the PIU is below a third threshold. The method further allows identifying at least one redundant frame in the one or more other data streams. If the quality of data in redundant frame is satisfactory, the method proceeds to use the redundant frame for further processing.

This disclosure relates to systems and methods for configuration-less process bus. In one embodiment, the system includes at least one process interface unit (PIU). The PIU includes at least one pre-configured communication port defined by one of a factory setting or a product code order. The at least one PIU is operable to transmit and receive a data stream. The data stream includes at least one dataset. The dataset includes at least one field for sampled values measured at least at one source. The source includes one of a current transformer or a voltage transformer. The dataset can further include a timestamp and a unique identifier associated with the source. The system can include at least one intelligent electronic device (IED) communicatively coupled to the PIU. The IED can be operable to receive the data stream from the PIU and transform the sampled values based on user-defined transformation factors.

A system and a method for locally controlling delivery of electrical power along the distribution feeder by measuring certain electricity parameters of a distribution feeder line using a substation phasor measurement unit (PMU) electrically coupled to a substation distribution bus at a first node on the feeder line, and at least one customer site PMU electrically coupled to a low voltage end of a transformer at a customer site, wherein the transformer is coupled by a drop line to a second node on the distribution feeder line and the customer site is coupled by another drop line to the transformer, and by controlling at least one controllable reactive power resource and optionally a real power resource connected to the second node or at the customer site. Related apparatus, systems, articles, and techniques are also described.

Techniques are described for disaggregation of renewable energy generation on an electricity distribution system. Aggregate power measurements are identified a distribution substation. Active power load of the distribution substation and active power generated by renewable energy sites can be disaggregated from the aggregate power measurements.

A system and method for inferring schematic and topological properties of an electrical distribution grid is provided. The system may include Remote Hubs, Subordinate Remotes, a Substation Receiver, and an associated Computing Platform and Concentrator. At least one intelligent edge transmitter, called a Remote Hub Edge Transmitter, may transmit messages on the electrical distribution grid by injecting a modulated current into a power main that supplies an electric meter. The Subordinate Remotes, Remote Hubs, the Substation Receiver, and the associated Computing Platform and Concentrator may contain processing units which execute stored instructions allowing each node in the network to implement methods for organizing the on-grid network and transmitting and receiving messages on the network. The Substation Receiver, Computing Platform, and Concentrator may detect and infer schematic grid location attributes of the network and publish the detected and inferred attributes to other application systems including geospatial information systems.