Disclosed herein are systems and methods that use blockchain technology to protect power system data. For example, a receiving device may receive a smart contract. The receiving device may obtain the encrypted power system measurements from the smart contract via distributed ledger. The receiving device may decrypt the power system measurements from the smart contract using a private key of the receiving device. The receiving device may display the decrypted power system measurements on a display of the receiving device.

Disclosed is a reliable resilient router for a wide-area phasor measurement system of a power grid. The reliable resilient router includes a Data-type data packet processing module, a RetransReq data packet processing module, a RetransReport data packet processing module, a basic data packet processing module, a multi-path forwarding state table module, a content storage queue module and a physical port. The reliable resilient router of the present invention realizes active detection of a lost data packet and a single or batch retransmission mechanism, so that the lost data packet can be directly recovered in the grid from an upstream router through which the lost data packet passes, which improves the recovery time success rate and the high efficiency of the lost data packet, and guarantees the safe and stable operation of the wide-area phasor measurement system of the power grid.

Disclosed is a reliable resilient router for a wide-area phasor measurement system of a power grid. The reliable resilient router includes a Data-type data packet processing module, a RetransReq data packet processing module, a RetransReport data packet processing module, a basic data packet processing module, a multi-path forwarding state table module, a content storage queue module and a physical port. The reliable resilient router of the present invention realizes active detection of a lost data packet and a single or batch retransmission mechanism, so that the lost data packet can be directly recovered in the grid from an upstream router through which the lost data packet passes, which improves the recovery time success rate and the high efficiency of the lost data packet, and guarantees the safe and stable operation of the wide-area phasor measurement system of the power grid.

A subspace-based approach to synchrophasor estimation is provided. Embodiments described herein provide two improvements to subspace-based phasor measurement unit (PMU) algorithms based on estimation of signal parameters via rotational invariance techniques (ESPRIT) frequency estimation. The first is a dynamic, real-time thresholding method to determine the size of the signal subspace. This allows for accurate ESPRIT-based frequency estimates of the nominal system frequency as well as the frequencies of any out-of-band interference or harmonic frequencies. Since other frequencies are included in the least squares (LS) estimate, the interference from frequencies other than nominal can be excluded. This results in a near flat estimation error over changes in a) nominal system frequency, b) harmonic distortion, and c) out-of-band interference. Second, the computational burden of ESPRIT is reduced and the proposed algorithm runs in real time on resource-constrained platforms.

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 synergic identification method for dynamic stability of a power system is provided, including: acquiring each dominant oscillation mode; acquiring a critical wavelet scale factor range corresponding to each dominant oscillation mode; calculating an oscillation modality of the dominant oscillation mode corresponding to the critical wavelet scale factor range by a right singular vector corresponding to a maximum value among first singular values of each reconstructed wavelet coefficient matrix in the critical wavelet scale factor range; calculating, according to the relation between left and right feature vectors and the estimated oscillation modality, a left feature vector corresponding to each dominant oscillation mode and calculating a participation factor of each measurement channel in this dominant oscillation mode; calculating direction cosines between measurement channels by the oscillation modality of the dominant oscillation mode, and classifying coherent generator groups or coherent bus groups in the system by the direction cosines.

Systems, methods, and devices relating to operating a power generation facility to contribute to the stability of the power transmission system. A controller operates on the power generation facility to modulate real power or reactive power or both in a decoupled manner to contribute to the stability of the power transmission system. Real power produced by the power generation facility can be increased or decreased between zero and the maximum real power available from the PV solar panels, as required by the power system. Reactive power from the power generation facility can be exchanged (injected or absorbed) and both increased or decreased as required by the power transmission system. For solar farms, the solar panels can be connected or disconnected, or operated at non-optimal power production to add or subtract real or reactive power to the power transmission system.

An impedance injection unit (IIU) system is coupled to a high-voltage (HV) transmission line. The IIUs are activated in sequences of activation in successive time periods. This injects an impedance waveform onto the HV transmission line. The ordering of IIUs in the sequences of activation is repeatedly changed in successive time periods. This equalizes electrical stress across the IIUs used, leading to overall improvement in IIU system lifetimes.

A synergic identification method for dynamic stability of a power system is provided, including: acquiring each dominant oscillation mode; acquiring a critical wavelet scale factor range corresponding to each dominant oscillation mode; calculating an oscillation modality of the dominant oscillation mode corresponding to the critical wavelet scale factor range by a right singular vector corresponding to a maximum value among first singular values of each reconstructed wavelet coefficient matrix in the critical wavelet scale factor range; calculating, according to the relation between left and right feature vectors and the estimated oscillation modality, a left feature vector corresponding to each dominant oscillation mode and calculating a participation factor of each measurement channel in this dominant oscillation mode; calculating direction cosines between measurement channels by the oscillation modality of the dominant oscillation mode, and classifying coherent generator groups or coherent bus groups in the system by the direction cosines.

Technologies for controlling forced oscillations in electrical power grids include a processing unit and a phasor measurement unit and a control device coupled to a power grid. The processing unit receives a measurement indicative of active power in the power grid from the phasor measurement unit and determines a frequency of a forced oscillation active in the power grid based on the measurement. The processing unit injects a corrective signal with the control device into the power grid. The processing unit determines a corrective phase and a corrective amplitude in response to injecting the corrective signal. The processing unit continues to inject the corrective signal with the corrective phase and the corrective amplitude. The control device may be a static VAR compensator, a synchronous generator, a static synchronous compensator, a synchronous condenser, an electric storage device, or a solar power plant. Other embodiments are described and claimed.