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.

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.

A method and system for a distributed communications and control network that manages Distributed Energy Resources (DER) on a power utility grid. Such a network uses a three-tiered network architecture (FIG. 2) named DERCOM comprised of two or three components:

E-DERM An edge DER module (required)

D-DERM A distributed DER module (required)

C-DERM A centralized DER module (optional). The DERCOM network can begin as D-DERM/E-DERM installations (FIG. 3; FIG. 4) which can later integrate with an existing or future centralized C-DERM deployment. The E-DERM module being an edge device, physically located at each DER Point of Common Coupling (PCC), provides communications and protocol translations between DER and utility grid over wired or wireless connections. The E-DERM may also be located at utility device locations to control such devices. E-DERM communicates with D-DERM. The D-DERM module being a distributed system controller, physically located at the utility substation and managing multiple DER sites via E-DERM devices, on a circuit and substation aggregate basis. A D-DERM hosts multiple algorithms providing various grid optimization applications. The D-DERM may also manage non-DER utility devices for distribution automation and demand response applications. D-DERM communicates with E-DERM and C-DERM. The C-DERM module being a management software application typically located at a regional utility control center. The C-DERM communicates with one or many D-DERM substation controllers to implement broad overall control strategies. DERCOM provides the four fundamental roles of a DERM system:

Aggregate: Aggregates the services of many individual DER and presents them as a smaller, more manageable, number of aggregated virtual resources

Simplify: Handles the granular details of DER settings and presents simple grid-related services

Optimize: Optimizes the utilization of DER within various groups to get the desired outcome at minimal cost and maximum power quality

Translate: Translates individual DER languages, and presents to the upstream calling entity in a cohesive way.

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.

Systems and a method for forecasting data at noninstrumented substations from data collected at instrumented substations is provided. An example method includes determining a cluster id for a noninstrumented substation, creating a model from data for instrumented substations having the cluster id, and forecasting the data for the noninstrumented station from the model.

A voltage control and conservation (VCC) system is provided, which includes three subsystems, including an energy delivery (ED) system, an energy control (EC) system and an energy regulation (ER) system. The VCC system is configured to monitor energy usage at the ED system and determine one or more energy delivery parameters at the EC system. The EC system may then provide the one or more energy delivery parameters to the ER system to adjust the energy delivered to a plurality of users for maximum energy conservation.

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.

Adaptive protection methods and systems for protecting agains) extreme fault currents in a power system are provided. Communication capabilities and protocols defined in IEC 61850 can be used to provide smart cascading switching actions for removing the fault from the power system. A supervisory protection algorithm can be used, and the protection can be activated if the fault current is higher than a breaking capacity of the circuit breakers of the power system.

A method for enabling communication over a cellular network between a first communication device of a first substation and a second communication device of a second substation. The substations are connected to a power transmission line. The method includes the steps of: receiving multicast communication from the first communication device, wherein the multicast communication including a plurality of multicast packets, and each multicast packet includes a phasor value associated with the first substation and a sequence number; receiving an acknowledgement from the second communication device, the acknowledgement including a plurality of sequence numbers of the most recently received multicast packets, that the second communication device has received from the first communication device; and determining a packet loss to the second communication device when there is a mismatch between the sequence numbers of the acknowledgment, when compared with the sequence numbers of the received multicast communication.

The disclosure provides a method for fast reconfiguration of power supply grid in tens of milliseconds after power grid failure. The master station of fast reconfiguration of power grid concentrates the network status information from the client stations at transformer substations or power plants, and compares it with the built-in control strategy table which deals with possible faults. When an expected power gird disconnection fault is detected, the pre-start switch-on instruction is sent to the client stations with multiple breakers which can reconnect the grid. When the fault is cleared, the client stations shall identify the fault clearing time according to the local information, and send the instruction of synchronous switch-on to the corresponding local breakers which can reconnect the separated grids. At the same time, the master station independently monitors the removal of the fault, and sends the backup switch-on signal with synchronism check to the corresponding breakers which can reconnect the separated grids. Based on the above mechanism, the disconnected grid can be reconnected within 150 ms after disconnecting. After the interconnection of the grid is restored, the breakers that form the electromagnetic ring network switch off