Abstract: Systems and methods including improving availability of protection of an electric power delivery system even upon unavailability of power system signals. Such protection relays may provide protection using signals from the power system and provide the signals to an integrator or another device. Upon unavailability of power system signals to a protection relay, the integrator sends substitute power system signals may be provided to the protection relay. The protection relay may continue to provide protection using the substitute power system signals.

Abstract: Disclosed herein are systems for maintaining protection of electric power delivery systems in the event of a control power failure or other anomaly. A reliable power module conditions electric power from multiple independent sources and provides electrical operational power to electric power delivery system protective loads. The reliable power module includes a power storage device for providing operational power even upon loss of all control power sources. The power storage may be sufficient to ride through expected losses such as a time to start up backup generation. The power storage may be sufficient to power a trip coil. Thus, electric power system protection is maintained even upon loss of control power.

Abstract: Systems and methods for facilitating selected communications among primary protection relays using a supervisory system with a configurable input/output (IO) map. Primary protection relays may obtain signals from equipment associated with an electric power delivery system and provide primary protection without need for communication. The primary protection relays may communicate a unique identifier as well as signal values, states, and commands to the supervisory system. The supervisory system may route specifically identified communications among primary protection relays in accordance with a configurable IO map by transmitting selected portions of the communications on a port associated with the receiving primary protection relay. The primary protection relays may perform secondary protection and other operations using the communicated information.

Abstract: The present disclosure pertains to systems and methods for generating a virtual display using a unidirectional communication channel. In one embodiment, a system may comprise a transmitting device including a processing subsystem to generate a representation of an encoded signal comprising information to be displayed on a virtual display. A virtual display transmission subsystem may transmit the encoded signal. A receiving device may comprise a virtual display reception subsystem to receive the encoded signal. A processing subsystem may extract the information to be displayed on the virtual display from the encoded signal and generate a representation of the virtual display. A virtual display subsystem may display the representation of the virtual display. The virtual display transmission subsystem and the virtual display reception subsystem may create a unidirectional communication channel from the transmitting device to the receiving device.

Abstract: Systems and methods may maintain protection of electric power delivery systems in the event of an attack on protection and/or control features of the power system. Primary protective functions may be physically isolated from other functions in primary protection relays. Integrators may facilitate non-primary protection functions and disconnect all communication with primary protection relays in the event of an attack. Primary protection relays maintain protection functions even during the attack or unavailability of the integrators.

Abstract: The present application discloses systems and methods to determine loss of at least one electric power transmission line in an electric power transmission system. In various embodiments, a system consistent with the present disclosure may include an electrical parameter monitoring subsystem configured to receive electrical parameter measurements and to determine a change of the electrical measurements. An analysis subsystem may determine whether a change in the electrical measurements is indicative of loss of at least one transmission line and may calculate a number of transmission lines lost based on the change. In some embodiments, a remedial action subsystem may be configured to implement a remedial action in response to loss of at least one transmission line. The number of transmission lines lost may be determined based on an angle difference ratio and a power ratio between two buses in electrical transmission system.

Abstract: A system for determining a disturbance in an electrical power delivery system external to a distributed site based on rate of change of frequency and power flow at the distributed site. The system may open a breaker to isolate the distributed site from the electric power delivery system upon detection of a disturbance external to the distributed site.

Abstract: The present disclosure relates to systems and methods of simulating a power system using field data. For example, an embodiment may include a processor operatively coupled to a memory. The processor may receive a power system model representative of an actual power system. The processor may receive field data from the actual power system. The processor may initialize the power system model based on the field data to represent a state of the actual power system. The processor may simulate at least one scenario on the power system model. The processor may provide results of simulating the at least one scenario.

Abstract: The present disclosure describes load shedding management systems and methods. A load shedding management system may simulate multiple load shedding actions. Based on the simulations the load shedding management system may select a load shedding action. The load shedding management system may send a signal to trip a set of breakers to implement the load shedding action.

Abstract: The present disclosure describes load shedding management systems and methods. A load shedding management system may simulate multiple load shedding actions. Based on the simulations the load shedding management system may select a load shedding action. The load shedding management system may send a signal to trip a set of breakers to implement the load shedding action.

Abstract: The present disclosure provides systems and methods for managing an electric power delivery system. The systems and methods may limit generated power of the power delivery system from surpassing a load demand, in order to avoid system instability. The systems and methods may receive an excess generation value and manage generators to runback and/or shed to maintain excess generation below a threshold. The systems and methods may determine a plurality of generator groups for runback. The runback capacity of the generators may be compared against the excess generation. If the excess generation is not greater than the runback capacity, the systems and methods may select generator groups until the runback capacity of the selected groups is greater than the excess generation, and may runback those generators according to runback set points. The unselected generators may continue normal operation to be available for another runback request.

Abstract: The present disclosure provides systems and methods for managing an electric power delivery system. The systems and methods may limit generated power of the power delivery system from surpassing a load demand, in order to avoid system instability. The systems and methods may receive an excess generation value and manage generators to runback and/or shed to maintain excess generation below a threshold. The systems and methods may determine a plurality of generator groups for runback. The runback capacity of the generators may be compared against the excess generation. If the excess generation is not greater than the runback capacity, the systems and methods may select generator groups until the runback capacity of the selected groups is greater than the excess generation, and may runback those generators according to runback set points. The unselected generators may continue normal operation to be available for another runback request.

Abstract: Protective IEDs in an electrical power system, such as distributed controllers, may periodically or in real-time communicate updated protection settings to a wide-area controller, such as a coordination controller, that defines and/or implements a remedial action scheme to protect the electrical power system. The wide-area controller may utilize real-time protection setting information from a plurality of protective IEDs to perform dynamic transient model simulations based on (1) the current topology of the power system, (2) real-time measurements from the system, and (3) the updated, real-time protection settings of various IEDs within the system. The results of the updated transient model simulations may be used to dynamically adjust the remedial actions scheme of the wide-area controller.

Abstract: Protective IEDs in an electrical power system, such as distributed controllers, may periodically or in real-time communicate updated protection settings to a wide-area controller, such as a coordination controller, that defines and/or implements a remedial action scheme to protect the electrical power system. The wide-area controller may utilize real-time protection setting information from a plurality of protective IEDs to perform dynamic transient model simulations based on (1) the current topology of the power system, (2) real-time measurements from the system, and (3) the updated, real-time protection settings of various IEDs within the system. The results of the updated transient model simulations may be used to dynamically adjust the remedial actions scheme of the wide-area controller.

Abstract: A system for determining a disturbance in an electrical power delivery system external to a distributed site based on rate of change of frequency and power flow at the distributed site. The system may open a breaker to isolate the distributed site from the electric power delivery system upon detection of a disturbance external to the distributed site.

Abstract: The present disclosure pertains to distributed controllers configured to control a plurality of electrical generators in an electrical generation and distribution system. In one embodiment, a distributed controller consistent with the present disclosure may include a communication subsystem configured to communicate via a network. The communication system may receive a first plurality of time-stamped electrical parameter measurements associated with a first electrical generator. A measurement analysis subsystem may detect a change caused by an event in the measurements associated with the first electrical generator, and may detect a change in a second plurality of time-stamped electrical parameter measurements associated with a second electrical generator. A magnitude of the event may be determined based on the first and second plurality of time-stamped electrical parameter measurements.

Abstract: The present disclosure pertains to distributed controllers configured to control a plurality of electrical generators in an electrical generation and distribution system. In one embodiment, a distributed controller consistent with the present disclosure may include a communication subsystem to obtain a first plurality of time-stamped electrical parameter measurements from a first node. A measurement analysis subsystem may compare the first plurality of time-stamped electrical parameter measurements and the second plurality of time-stamped electrical parameter measurements. The first node and the second node may be associated in an electrical island by a topology detection subsystem based on the correlation. A control subsystem may be configured to implement a control action based on the association of the first node and the second node in the electrical island.

Abstract: Disclosed herein are methods for detecting and correcting a fault induced delayed voltage recovery event in an electric power transmission and distribution system. In some embodiments, a fault detection subsystem may receive an indication of a fault in the electric power transmission and distribution system. The system may also include a load analysis subsystem to analyze a plurality of loads supplied by the electric power system and to generate an estimated response of the loads. A fault analysis subsystem may analyze a plurality of factors relating to the fault and to determine a probability of the fault generating a fault induced delayed voltage recovery event. A control system may then implement a control strategy within a control window following the fault based on the probability of the fault generating a fault induced delayed voltage recovery event and the estimated response of the at least one load.

Abstract: The present disclosure pertains to distributed controllers configured to control a plurality of electrical generators in an electrical generation and distribution system. In one embodiment, a distributed controller consistent with the present disclosure may include a communication subsystem configured to communicate via a network. The communication system may receive a first plurality of time-stamped electrical parameter measurements associated with a first electrical generator. A measurement analysis subsystem may detect a change caused by an event in the measurements associated with the first electrical generator, and may detect a change in a second plurality of time-stamped electrical parameter measurements associated with a second electrical generator. A magnitude of the event may be determined based on the first and second plurality of time-stamped electrical parameter measurements.

Abstract: The present disclosure pertains to distributed controllers configured to control a plurality of electrical generators in an electrical generation and distribution system. In one embodiment, a distributed controller consistent with the present disclosure may include a communication subsystem to obtain a first plurality of time-stamped electrical parameter measurements from a first node. A measurement analysis subsystem may compare the first plurality of time-stamped electrical parameter measurements and the second plurality of time-stamped electrical parameter measurements. The first node and the second node may be associated in an electrical island by a topology detection subsystem based on the correlation. A control subsystem may be configured to implement a control action based on the association of the first node and the second node in the electrical island.