WO2010033839A1 - Protection différentielle de la commutation distribuée utilisant des données horodatées - Google Patents

Protection différentielle de la commutation distribuée utilisant des données horodatées Download PDF

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Publication number
WO2010033839A1
WO2010033839A1 PCT/US2009/057533 US2009057533W WO2010033839A1 WO 2010033839 A1 WO2010033839 A1 WO 2010033839A1 US 2009057533 W US2009057533 W US 2009057533W WO 2010033839 A1 WO2010033839 A1 WO 2010033839A1
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WIPO (PCT)
Prior art keywords
current
measurements
topology
node
time
Prior art date
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PCT/US2009/057533
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English (en)
Inventor
Marcos A. Donolo
Armando Guzman-Casillas
Edmund O. Schweitzer
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Schweitzer Engineering Laboratories, Inc.
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Publication date
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Priority to MX2011002467A priority Critical patent/MX2011002467A/es
Priority to CA2736044A priority patent/CA2736044C/fr
Publication of WO2010033839A1 publication Critical patent/WO2010033839A1/fr

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Classifications

    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02H—EMERGENCY PROTECTIVE CIRCUIT ARRANGEMENTS
    • H02H3/00—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection
    • H02H3/26—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents
    • H02H3/28—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents involving comparison of the voltage or current values at two spaced portions of a single system, e.g. at opposite ends of one line, at input and output of apparatus
    • H02H3/30—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents involving comparison of the voltage or current values at two spaced portions of a single system, e.g. at opposite ends of one line, at input and output of apparatus using pilot wires or other signalling channel
    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02H—EMERGENCY PROTECTIVE CIRCUIT ARRANGEMENTS
    • H02H7/00—Emergency protective circuit arrangements specially adapted for specific types of electric machines or apparatus or for sectionalised protection of cable or line systems, and effecting automatic switching in the event of an undesired change from normal working conditions
    • H02H7/22—Emergency protective circuit arrangements specially adapted for specific types of electric machines or apparatus or for sectionalised protection of cable or line systems, and effecting automatic switching in the event of an undesired change from normal working conditions for distribution gear, e.g. bus-bar systems; for switching devices
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E40/00—Technologies for an efficient electrical power generation, transmission or distribution
    • Y02E40/70—Smart grids as climate change mitigation technology in the energy generation sector
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E60/00—Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
    • Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
    • Y04S10/00—Systems supporting electrical power generation, transmission or distribution
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
    • Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
    • Y04S10/00—Systems supporting electrical power generation, transmission or distribution
    • Y04S10/22—Flexible AC transmission systems [FACTS] or power factor or reactive power compensating or correcting units

Definitions

  • Figure 1 is a block diagram of one embodiment of a substation state and topology processor in communication with a substation, electrical power system network;
  • Figure 2A is a block diagram of an embodiment of a substation, electrical power system network
  • Figure 2B depicts an embodiment of branch input data structure
  • Figure 2C depicts an embodiment of a node input list data structure
  • Figure 3 is a data flow diagram of one embodiment of a substation state and topology processor
  • Figure 4 is a block diagram of a substation state and topology processor
  • Figure 5 is a block diagram of a state and topology processor
  • Figure 6 is a block diagram of a substation, electrical power system network
  • Figure 7A is a flow diagram of a method for processing merged branches in a current branch-to-node data structure
  • Figure 7B is a flow diagram of a method for processing merged branches in a voltage branch-to-node data structure
  • Figure 8A is a flow diagram of one embodiment of a method for generating a current node vector
  • Figure 8B is a flow diagram of one embodiment of a method for generating a voltage node vector
  • Figure 9 is a representation of a current and/or voltage node vector
  • Figure 10 is a flow diagram of a method for monitoring a substation, electrical power system network using a current topology and a plurality of current measurements;
  • Figure 11 is a block diagram of a polarity convention;
  • Figure 12A is a flow diagram of a method for performing a current consistency check
  • Figure 12B is a graphical depiction of a current and/or voltage consistency check
  • Figure 13A is a flow diagram of a method for performing a Kirchhoff's Current
  • Figure 13B is a block diagram of a portion of a substation, electrical power system network;
  • Figure 14 is a flow diagram of a method for performing a phase current unbalance check and symmetrical components check;
  • Figure 15 is a flow diagram of a method for performing a voltage consistency check, measurement refinement, and symmetrical components check
  • Figure 16 depicts one embodiment of an application for visualizing a substation power system network
  • Figure 17 depicts one embodiment of an application for visualizing measurement and/or alarm details
  • Figure 18 depicts one embodiment of a power system comprising plural buses;
  • Figure 19 is a block diagram of a state and topology processor configured to provide distributed bus differential protection;
  • Figure 20 is a functional block diagram of one embodiment of a current differential element
  • Figure 21 is a functional block diagram of one embodiment of an external fault detection logic module
  • Figure 22 is a block diagram of a system for distributing a common time source and/or absolute time to distributed devices
  • Figure 23 is a block diagram of a data processor
  • Figure 24 is a flow diagram of one embodiment of a method for providing distributed bus differential protection.
  • Figure 1 depicts an exemplary substation, electrical power system network
  • the SEPSN 100 may comprise various elements used for electrical power transmission and/or power distribution.
  • the SEPSN 100 may comprise a generator 1 10, which may be connected to a bus 120 via a circuit breaker 1 13.
  • a load 1 17 may be connected to the bus 120 via a circuit breaker 1 15.
  • a circuit breaker (such as circuit breakers 1 13 and 115) may refer to any device capable of interrupting and/or altering an electric circuit and/or an electrical connection (such as a connection between generator 1 10 and load 1 17).
  • a bus 130 may be connected to bus 120 via power transmission line 132.
  • a power transmission line 132 may comprise circuit breakers 133 and 135.
  • a bus 140 may be connected to the bus 120 via a power transmission line 142.
  • the power transmission line 142 may comprise circuit breakers 143, and 147.
  • One or more Intelligent Electronic Devices (IED) 150, 152, and 154 may be communicatively coupled to one or more elements of the SEPSN 100.
  • IED Intelligent Electronic Devices
  • an IED may refer to any one or combination of a central processing unit (CPU)-based relay and/or protective relay, communication processor, digital fault recorder, phasor measurement unit (PMU), phasor measurement and control unit (PMCU), phasor data concentrator (PDC), relay with phasor measurement capabilities, or any other device capable of monitoring an electrical power system.
  • CPU central processing unit
  • PMCU phasor measurement and control unit
  • PDC phasor data concentrator
  • a PMU 150 may be configured to measure or otherwise sample a signal ⁇ e.g., a phase current and/or phase voltage waveform) on bus 120.
  • the waveform may comprise a voltage and/or current waveform corresponding to one or more components of a three-phase system.
  • PMU 152 may be configured to sample a signal waveform present on bus 130
  • PMU 154 may be configured to sample a signal waveform present on bus 140.
  • the PMUs 150, 152, and 154 may be configured to process sampled signal waveforms to calculate, for example, current and/or voltage phasors.
  • the PMUs 150, 152, and 154 may read one or more correction factors (that may be input by the user) for modifying the magnitude and/or phase of a phasor measurement.
  • "measurement data” may refer to a phasor measurement of a sinusoidal signal.
  • measurement data may refer to a measurement of a three-phase, phase current and/or voltage signal ⁇ e.g., a measurement may comprise three separate measurements of each phase of a three-phase system).
  • the PMUs 150, 152, and 154 may be configured to apply a timestamp to data. This may be done using any phasor measurement and/or timestamping technique and/or methodology known in the art, including, but not limited to the techniques and methods described in: U.S. Patent No. 6,662,124 entitled, “Protective Relay with Synchronized Phasor Measurement Capability for Use in Electric Power Systems," to Schweitzer, III et al.; U.S. Patent No. 6,845,333 entitled, “Protective Relay with Synchronized Phasor Measurement Capability for Use in Electric Power Systems," to Anderson et al.; and U.S. Application Pub. No.
  • the measurement data obtained by the PMUs 150, 152, and 154 may be communicated to a Data Processor (DP) 160.
  • DP Data Processor
  • one or more of the PMUs 150, 152, and 154 may communicate dynamic topology data to the DP 160.
  • This dynamic topology data may comprise the state of the circuit breakers and/or switches 1 13, 1 15, 133, 135, 143, 147 of the SEPSN 100, and the like.
  • switch may refer to a switch component, a disconnect switch, and/or a disconnect component.
  • dynamic topology data may be combined with static network topology data to generate an operating topology of the SEPSN 100.
  • the static topology data may comprise information, such as: the number of nodes in the SEPSN 100, the connection between various nodes in the SEPSN 100 the measurements available for each node and/or branch in the SEPSN 100, phase current and/or voltage measurement correction factors, and the like.
  • a "node” may refer to a bus, such as buses 120, 130, and 140 of the SEPSN 100
  • a "branch,” as used herein may refer to a path of conduction and/or connection between one or more nodes ⁇ e.g., a power transmission line comprising zero or more circuit breakers or the like).
  • Elements 150, 152, and 154 may comprise IEDs, such as PMUs and/or PMCUs, which may be configured to gather measurement data and dynamic topology data for transmission to DP 160.
  • This data may comprise, but is not limited to: one or more phase current measurements on a branch and/or voltage measurements on a node 120, 130, and/or 140; the status of circuit breakers and/or disconnect switches 1 13, 1 15, 133, 135, 143, 147; the quality status of these circuit breakers and/or disconnect switches; and the like.
  • the DP 160 may comprise configuration data including one or more user-defined thresholds. These user-defined thresholds may be used in one or more monitoring functions of the DP 160. For example, the DP 160 may receive phase measurements and dynamic topology data from PMUs 150, 152, and 154. The DP 160 may use this data to evaluate and/or monitor the state of the SEPSN 100. This monitoring may comprise comparing the received measurement and network topology data to the user-defined thresholds. The DP 160 may process the measurements received from the PMUs 150, 152, and 154 and may set one or more alarms responsive to the processing.
  • FIG. 2A depicts an embodiment of a SEPSN 200 ⁇ e.g., substation, electrical power system network).
  • the SEPSN 200 may comprise ten (10) nodes denoted N1 through N10.
  • the SEPSN 200 may further comprise thirteen (13) branches denoted B1 through B13.
  • the SEPSN 200 may comprise one or more IEDs (elements IED1 -IED5) communicatively coupled thereto.
  • IED1 may be communicatively coupled to current transformers (CTs) CT1 and CT2.
  • CT1 and CT2 may be used to obtain current measurements on branches in the SEPSN 200.
  • one or more voltage transformers may be used to obtain phase voltage measurements on one or more of the nodes (N1 -N10) of the SEPSN 200.
  • the CT1 may measure a current between N1 and N4, and CT 2 may measure a current from N3 to N4, and so on.
  • the IEDs coupled to the SEPSN 200 may be in communication with branch elements of the SEPSN 200.
  • IED2 may be communicatively coupled to branch B1 and B2, and may be configured to detect the state of branch B1 and B2 ⁇ e.g., whether the branches B1 and/or B2 are closed, and the like).
  • the SEPSN 200 may comprise a plurality of IEDs 1 - 5 monitoring one more aspects of the SEPSN 200, including topology data of the
  • SEPSN 200 ⁇ e.g., the state of branches B1 -B11 ) and/or measurement data ⁇ e.g., phase current measurements obtained by current transformers CT1 -CT8).
  • the data collected by the IEDs 1 -5 may be transmitted to a state and topology processor (not shown) and made available to various protective and monitoring functions running thereon in one or more data structures. Various embodiments of such data structures are described below in conjunction with figures 2B and 2C.
  • two data structures may be used to describe the SEPSN 200, a branch input list data structure (shown in Figure 2B) and a node input list data structure (shown in Figure 2C).
  • the branch input list data structure may comprise information about a branch in a SEPSN 200 ⁇ e.g., branches B1 -B11 in Figure 2A).
  • the branch input list data structure may comprise an entry for each branch in the network, and each entry may comprise data describing the branch.
  • the branch input list data structure may comprise:
  • a branch input data structure for each branch comprising: a) A FROM node identifier; b) A TO node identifier; c) Branch Closed Status (whether the branch is closed) d) Branch Close Status Quality (whether the branch close status is good) e) Number of current measurements on the branch
  • A-Phase measurements i) Current measurements ii) Current correction factors g) B-Phase measurements i) Current measurements ii) Current correction factors h) C-Phase measurements i) Current measurements ii) Current correction factors i) Threshold data i) Current consistency threshold ii) Current unbalance threshold iii) Positive, negative, and zero sequence overcurrent threshold
  • Figure 2B depicts one embodiment 210 of data structure 220, comprising a branch input list data structure 230 corresponding to the SEPSN 200 of Figure 2A.
  • a top-level node 220 of the tree data structure 210 may be labeled INPUT_DATA.
  • the INPUT_DATA node 220 may be configured to contain a branch list 230, which comprises one or more branch input list data structures 240 described above. Additionally, the INPUT_DATA node 220 may comprise a "list_of_nodes" entry (not shown), which will be described in detail below in conjunction with Figure 2C.
  • Each node of the SEPSN 200 depicted in Figure 2A may have a corresponding branch instance 240 ⁇ e.g., a branch input list instance 240 for each of the eleven (1 1 ) branches in SEPSN 200).
  • Branch three (3) (B3 in Figure 2A) may be described by branch instance 250.
  • Branch instance 250 may comprise one or more child instances defining the branch configuration, the branch state, phase-current measurements on the branch, phase- current correction factors, and one or more user-defined threshold values.
  • a "from_node” 251 may identify the source node of the branch (and a "to_node” 252 may identify a destination node of the branch to accurately reflect the topology of the SEPSN 200; referring back to Figure 2A, branch 3 (B3) is coupled to nodes N4 and N3.
  • closed_status_quality instance 255 may indicate that branch (B3) is closed and that the closed quality status is good.
  • the "number_of_current_measurements" instance 256 may indicate the number of measurements available on the branch (e.g., two (2) measurements for branch B3).
  • branch B3 comprises two CTs (CT2 and CT3) communicatively coupled thereto.
  • the "branch" instance 250 may comprise one or more phase-current measurements and phase-current correction factors 260, 270, and 280 associated with the branch 250.
  • An “A_phase” instance 260 may comprise the A phase current measurements and correction factors of the branch 250.
  • a “B_phase” instance 270 may comprise the B phase current measurements and correction factors of branch 3 250.
  • a “C_phase” instance 280 may comprise the C phase current measurements and correction factors of branch three (3) 250.
  • Each phase measurement/correction factor instance 260, 270, and 280 may comprise a current measurement instance ⁇ e.g., instance 261 ) and a correction factor instance ⁇ e.g., instance 263) for each current measurement on the branch.
  • instance 256 indicates that branch 3 250 comprises two (2) current measurements.
  • the A_phase current measurement instance 261 may comprise two (2) A phase current measurements instances 261.1 and 261.2 under instance 261 and two (2) A phase current correction factors 263.1 and 263.2 under current correction factor instance 263.
  • a "current_measurement” instance 261.1 may comprise a measured current magnitude measurement 261.1A
  • a "current_phase_measurement” instance 261.1.B may comprise a corresponding phase measurement.
  • the current measurement instance 261.2 may comprise similar measurements (not shown).
  • the "current_correction_factor" instance 263 may comprise a first current correction factor 263.1 associated with the first current measurement instance 261.1.
  • the "current_correction_factor[1]" instance 263 may comprise child instances 263.1A and 263.1 B defining a magnitude correction factor 263.1 A and a phase-angle correction factor 263.1 B. The use of correction factors 263.1 and 263.2 are discussed in more detail below.
  • the "current_correction_factor[2]” instance 263.2 may comprise current correction factors for current measurement 2, 261.2.
  • the B_phase instance 270 and the C_phase instance 280 may each comprise one or more current measurements (not shown) and current correction factors (not shown) for the B and C phases of a three-phase current system, respectively.
  • the branch instance 250 may comprise one or more user defined constants 257. As discussed above, a branch constant 257 may comprise a current consistency threshold 257.1 , a current unbalance threshold 257.2, and a positive, negative, and zero sequence overcurrent threshold. The use of constants 257 is described in more detail below.
  • the "INPUT_DATA” instance 210 may further comprise a "node_input_list” (not shown in Figure 2B), which may comprise data describing one or more nodes in a SEPSN ⁇ e.g., SEPSN 200 of Figure 2A).
  • the "node_input_list” entry may comprise a sub-entry for each node in the network, and each sub-entry therein may comprise data describing the node and any phase voltage measurements thereon.
  • a node input list structure may comprise: 1 ) Number of nodes in the SEPSN 200 ⁇ e.g., 10) 2) A node_input_data structure for each node, comprising: a) KCL node information b) A-Phase measurements at the node i) Number of voltage measurements ii) Voltage measurements iii) Voltage correction factors c) B-Phase measurements at the node i) Number of voltage measurements ii) Voltage measurements iii) Voltage correction factors d) C-Phase measurements at the node i) Number of voltage measurements ii) Voltage measurements iii) Voltage correction factors e) Positive -sequence undervoltage threshold f) Negative-sequence overvoltage threshold g) Zero-sequence overvoltage threshold
  • Figure 2C depicts one embodiment of a data structure 210 comprising a "nodejist” instance 235.
  • the "INPUT_DATA” instance 220 may comprise a "list_of_branches” instance 230 containing data describing one or more branches in a SEPSN.
  • the "INPUT_DATA” node 220 may further comprise a "list_of_nodes” instance 235, which may comprise a "number_of_nodes” instance 247, indicating the number of nodes in the SEPSN.
  • a container instance 249 may comprise a data structure corresponding to each node in the SEPSN. For example, in the
  • the container instance 249 may comprise ten (10) instances 265, one for each node in the network 200.
  • a node instance 265 may comprise a KCL instance 271 , which may indicate whether the node is suitable for KCL check. As will be discussed below, a node may be suitable for KCL check if all of the branches reaching the node are accounted for in the substation model. In addition, as will be discussed below, a KCL check may be possible where all the nodes in a particular node group are KCL nodes, and all the branches leaving the group of nodes are metered. [0063] The node instance 265 may further comprise an "A_phase" instance 273 comprising a "number_of_voltage_measurements" instance 274 and a voltage measurement instance 275. The voltage measurement instance 275 may comprise one or more A phase voltage measurement instances 275.1.
  • the "voltage_measurement” instance 275.1 may comprise an A phase magnitude 275.1 A and A phase angle 275.1 B.
  • a B_phase instance 283 and a C_phase instance 293 may comprise similar voltage measurement nodes.
  • A_phase instance 275 may further comprise a "voltage_correction_factor" instance 277, which may comprise one or more correction factor instances 277.1.
  • the correction factor instance 277.1 may comprise magnitude 277.1 A and phase 277.1 B correction factors associated with the voltage measurement 275.1. The use of correction factors 275.1 is described in more detail below.
  • the B_phase instance 283 and the C_phase instance 293 may comprise similar voltage correction factors.
  • the "node[1 ]" instance 265 may comprise one or more user-defined thresholds 295.
  • the user-defined thresholds 295 may comprise a positive-sequence undervoltage threshold, a negative-sequence overvoltage threshold, and/or a zero-sequence overvoltage threshold.
  • the use of the user-defined thresholds 295 is discussed in more detail below.
  • Figure 3 depicts a data flow diagram 300 of one embodiment of a State and Topology Processor (STP) 360.
  • the STP 360 may receive a static topology data input 354, a dynamic topology data input 355, and measurement data input 356. In response to these inputs, the STP 360 may output refined measurements 361 and alarms 362.
  • the dynamic topology data may include data such as breaker status, switch status, and the like.
  • the static topology data 354 may comprise a data structure, such as input list data structure 210 of Figures 2B and 2C, describing a topology of a SEPSN.
  • the static topology may be input into the STP 360 from an external storage location.
  • the STP may comprise data storage means ⁇ e.g., memory, disk, or the like) for storing the static topology data 354.
  • the static topology data 354 may comprise data describing: the nodes in the SEPSN; the branches in the SEPSN; the number of phase current and/or phase voltage measurements available on each node and/or branch; phase voltage and/or current measurement correction factors; and the like.
  • the STP 360 may receive dynamic topology data 355.
  • the dynamic topology data 355 may comprise data relating to the status of one or more circuit breakers, switches, conductors, conduits, or the like in a SEPSN.
  • the dynamic topology data 355 may be obtained by one or more IEDs and/or PMUs (not shown) communicatively coupled one or more components of the SEPSN.
  • the dynamic topology may be used along with the static topology 354 to determine an operating topology of the SEPSN.
  • the operating topology may be embodied as a data structure, such as the tree data structured discussed above in conjunction with Figures 2B and 2C.
  • dynamic topology data 355 may comprise data relating to the state of closed branches 254 and/or closed_status_quality node 255 in Figure 2B.
  • STP 360 may receive measurement data 356.
  • Measurement data 356 may comprise one or more phase current and/or phase voltage measurements obtained by one or more IEDs, PMUs and/or PMCUs (now shown) communicatively coupled to the SEPSN.
  • the phase voltage and/or current measurements 356 (as well as the dynamic topology data 355) may comprise timestamp information to allow the STP 360 to time align the measurements to a common time standard.
  • the STP 360 may be configured to produce one or more normalized and/or refined phase current and/or phase voltage measurements 361. These refined measurements may be used in protective and/or monitoring functions of the SEPSN (not shown).
  • STP 360 may produce one or more alarms 362.
  • the alarms 362 may be produced if one or more measurements 354, 355, 356, and/or derivatives thereof exceed or otherwise fall outside of one or more user-defined operating thresholds of STP 360 ⁇ e.g., thresholds 257 of Figure 2B and/or thresholds 295 of Figure 2C).
  • DP 420 may be communicatively coupled to one or more IEDs, such as relays, phasor measurement and control units (PMCU) and/or phasor measurement units (PMU) 401 or relays and 416 located within and/or communicatively coupled to a SEPSN.
  • IEDs such as relays, phasor measurement and control units (PMCU) and/or phasor measurement units (PMU) 401 or relays and 416 located within and/or communicatively coupled to a SEPSN.
  • the DP 420 is depicted as communicatively coupled to sixteen (16) PMCUs labeled PMCU_401 -PMCU_416.
  • the PMCU_401 -416 may be configured to communicate with the DP 420 using a communication standard, such as the IEEE C37.1 18 standard (hereafter "118 standard").
  • the 1 18 standard is a standard for synchronized phasor measurement systems in power systems.
  • the 1 18 standard is not media dependent and, as such, may be used on EIA-232 and Ethernet communications connections. Accordingly, PMCU_401 -416 and DP 420 may be referred to as "118 devices" configured to interact with the PMCU_401 -416 using the 1 18 standard.
  • 118 devices configured to interact with the PMCU_401 -416 using the 1 18 standard.
  • the PMCU_401 -416 and the DP 420 could be configured to use any communications standard and/or protocol known in the art. As such, this disclosure should not be read as limited to any particular communications standard and/or protocol.
  • the PMUs 410 through 416 may be communicatively coupled to the DP 420 via Fast Message protocol or the like.
  • the PMCU_401 -416 may provide measurement data and/or network topology data to the DP 420. This data may comprise timestamp information according to the 1 18 standard, or some other time alignment technique.
  • the messages transmitted by the PCMU_401 -416 may comprise time stamping information ⁇ e.g., may comprise synchrophasors transmitted according to the 1 18 standard).
  • the time alignment module 430 may time align such messages using the time stamping information.
  • the time alignment module 430 may time align messages from the PMCU_401 -416 to a common time reference (not shown), which may provide a common time reference to the DP 420, the PMCU_401 - 16 communicatively thereto, and/or to other IEDs communicatively coupled to the DP 420.
  • the common time reference may be provided by various time sources including, but not limited to: a Global Positioning System (GPS); a radio time source, such as the short-wave WWV transmitter operated by the National Institute of Standards and Technology (NIST) at 2.5 MHz, 5 MHz, 10 MHz, 15 MHz, and 20 MHz, or a low frequency transmitter, such as WWVB operated by NIST at 60 Hz; a cesium clock; an atomic clock; over an IEEE-1588 time-over-Ethernet system; and the like.
  • GPS Global Positioning System
  • NIST National Institute of Standards and Technology
  • the time alignment module 430 may modify the magnitude and/or phase of phase measurements received from the PMCU_401 -416 to conform to the common time reference (not shown) and/or the PMCU_401 -416 may be configured to modify one or more of a magnitude and/or phase measurement to align the measurement to the common time reference (not shown).
  • the time alignment module 430 may comprise a buffer memory or other buffering means to time align incoming messages from the PMCU_401 -416.
  • a time reference (not shown) may not be required since the messages themselves may comprise time alignment information (e.g., the messages transmitted by the PMCU_401 -416 may comprise synchrophasors or the like).
  • a super packet maker module 440 may receive the time-aligned measurement and dynamic topology data from time alignment module 430, and may generate a single composite packet comprising the time-aligned data received from PMCU_401 -416.
  • the super packet maker 440 may be configured to communicate with the time alignment module using the 1 18 standard.
  • the super packet maker 440 may transmit the packet comprising the time- aligned phasor measurement and/or topology data to Run Time System (RTS) 450.
  • RTS Run Time System
  • the super packet maker module 440 may transmit the composite packet to RTS 450 using the 1 18 standard.
  • the RTS 450 may comprise a 118 protocol gateway module 452, which may be configured to communicate with the super packet maker module 440 using the 1 18 protocol.
  • the RTS 450 may make the time-aligned phase current and/or phase voltage measurements and dynamic topology data received from PMCUs 01 -16 401 -416 available to a state and topology processor (STP) 460.
  • STP state and topology processor
  • the RTS 450 may comprise a data storage module 454, which may be used to store static network topology information relating to the SEPSN monitored by the system and/or PMCU_401 -416.
  • the STP 460 may be communicatively coupled to a data storage module 454, and may be configured to load network topology data therefrom.
  • the network topology data stored in the data storage module 454 may comprise a data structure, such as an input list data structure depicted in Figures 2B and 2C ⁇ e.g., input list data structure 210), and may include a static topology of the monitored SEPSN.
  • the STP 460 may be configured to load the data structure from storage module 454, and to then update the structure with the phase-current and/or voltage measurements and dynamic topology data ⁇ e.g., status of circuit breakers, switches, and the like) received from the PMCUs 01 -16.
  • the STP 460 may access the static and dynamic topology data to refine the received measurements and to perform one or more protective functions and/or system checks. The operation of the STP 460 is described in more detail below.
  • a human-machine interface (HMI) module 470 may be communicatively coupled to the DP 420 and the STP 460.
  • HMI human-machine interface
  • the HMI module 470 may be configured to display or otherwise make available to a human operator the refined current measurements, the refined phase voltage measurements, and/or alarms (if any) produced by the STP 460. Accordingly, the HMI module 470 may comprise a user interface or other display means to display of the state of the electrical power system to a user.
  • a local PMCU 480 may be communicatively coupled to the STP 460 and may be configured to receive the refined measurements and/or alarms (if any) produced by the STP 460.
  • the local PMCU 480 may be communicatively coupled (via a communications network supporting, for example, the 1 18 standard or some other protocol) to an external device 485.
  • the external device 485 may be an IED or other device configured to communicate with the PMCU 480.
  • the external device 485 may be capable of configuring and/or controlling one or more components of the SEPSN ⁇ e.g., open and/or close one or more circuit breakers and/or switches, remove and/or add one or more loads or the like).
  • the local PMCU 480 may cause the device 485 to reconfigure and/or control the SEPSN to thereby provide protection and/or additional control services to the SEPSN.
  • the external device 485 may be configured to send an alarm indicating undesired operating conditions, cause a circuit breaker to open and/or close, a load to be shed, or the like.
  • the STP 460 outputs station topology, refined measurements, measurement alarms, unbalanced currents and sequence quantities to the Run Time System 450, including the local PMCU 480 and a user programmable task module 490.
  • the user programmable task module 490 may comprise one or more pre-configured and/or user programmable tasks.
  • the user programmable task module 490 may comprise an IEC 61 131 -3 compliant device ⁇ e.g., a programmable device that complies with the IEC 61 131 -3 standard).
  • the tasks implemented on the user programmable task module 490 may use the data produced by the STP 460 to monitor the power system.
  • a bus differential protection module (not shown) may be implemented on the user programmable task module 490.
  • Figure 5 is a block diagram of one embodiment of a state and topology Processor (STP) 560.
  • the STP may receive inputs 562 from a run time engine, such as the Run Time System 450 discussed above.
  • the STP 560 may comprise a topology processor 570, which may receive branch input data 572.
  • the branch input data 572 may be derived from the static and dynamic topology data discussed above.
  • the branch input data 572 may reflect a state of a SEPSN, and as such, may comprise a combination of static SEPSN configuration data and dynamic SEPSN data.
  • the combination of static and dynamic topology data generated by the topology processor 570 may be referred to as an "operating topology" of a SEPSN.
  • the topology processor 570 may use branch input data 572 to generate a current topology 582 and a voltage topology 592. Jointly, the current topology 582 and the voltage topology 592 may comprise an operating topology of the SEPSN. The current topology 582 feeds a current processor 580 and the voltage topology 592 feeds a voltage processor 590.
  • the topology processor 570 may merge network nodes to create node groups according to the closed status of the branches within topology data 572. To create the current topology 582, the topology processor 570 may merge nodes when the non-metered branches are closed or when the branch closed status quality of the branch is false. To create the voltage topology 592, topology processor 570 may merge nodes when branches are closed. A more detailed description of current topology 582 and voltage topology 592 are provided below.
  • the current processor 580 may receive the current topology 582, node data 573, and current measurements 584 and produce outputs 585, which may comprise refined current measurements 585.1 , current unbalance conditions 585.3, and sequence currents 585.4. In addition, current processor 580 may provide user-defined alarms 585.2 for current unbalance and symmetrical component conditions. Systems and methods for generating outputs 585 are described in additional detail below. [0086]
  • the voltage processor 590 may receive the voltage topology 592, node data 573, and voltage measurements 594 and produce outputs 595, which may comprise refined voltage measurements 595.1 and sequence voltages 595.3. In addition, the voltage processor 590 may provide user-defined alarms 595.2 for voltage symmetrical component conditions, measurement consistency.
  • the topology processor 570 may use branch input data 572 (comprising the static topology and the dynamic topology data) to generate an operating topology of the SEPSN comprising a current topology 582 and a voltage topology 592.
  • the current topology may comprise the list of groups of nodes and the branch to node list.
  • the nodes inside every group of nodes are connected by closed branches that have no current measurements.
  • the branches to node list may specify which metered closed branches connect which group of nodes.
  • the voltage topology may comprise a list of groups of nodes and a branches to node list.
  • the nodes inside every group of nodes are connected by closed branches (with or without current measurements).
  • the branches to node list may specify which open branches with closed status quality equal to false connect which groups of nodes.
  • Nodes N6.1 , N6.2, N6.3 and N6.4 may comprise a voltage transformer (respectively VT6.1 , VT6.2, VT6.3, and VT6.4) attached and/or communicatively coupled thereto to measure a voltage on Nodes N6.1 through N6.4.
  • the current processor branch-to-node data may be represented by table 1 below:
  • Nodes in the current topology branch-to-node data may be merged when a non-metered branch is closed or when the branch close status quality of the non- metered branch is FALSE.
  • the topology processor may replace all instances of the non-metered branch TO node identifier with the FROM node identifier in the branch-to-node data array.
  • the TO node identifier and FROM node identifier may be defined in a structure, such as data structure 210, discussed above in conjunction with Figure 2B.
  • the dynamic topology data 572 associated with the SEPSN 600 may indicate that branch 10 (BR6.10) has closed.
  • Closing branch BR6.10 may merge nodes N6.1 and N6.2.
  • the branch-to-node data of Table 1 may be updated as shown in Table 2, such that the TO node ID of the merged branch (BR6.2) is replaced by the FROM node ID of the merged branch:
  • the topology processor 570 may generate groups of nodes for consistency checks and/or current refinement.
  • Table 3 may represent a group of nodes and branch list generated from Table 2 for current topology 582:
  • the voltage topology branch- to-node data may comprise branch to node interconnection information. As discussed above, this information may be determined by evaluating static and dynamic topology data. For the purposes of the voltage topology branch-to-node data, the topology processor 570 may merge a branch if the branch status is closed ⁇ e.g., element 254 of Figure 2B) and the close status quality indicator is TRUE for the branch ⁇ e.g., element 255 of Figure 2B).
  • a voltage branch-to-node data for the SEPSN 600, before closing branch BR6.2, is provided in Table 4:
  • the topology processor may merge nodes N6.1 and N6.3, and all instances of the branch TO node may be replaced with the FROM node ID in the voltage branch-to-node data array. This change is reflected in the updated voltage branch-to-node data of Table 5:
  • the topology processor 570 may generate groups of nodes for voltage consistency checks and/or voltage measurement refinement.
  • Table 6 may represent a voltage node group generated from Table 5:
  • Table 6 [00102] In Table 6, only nodes having voltage measurements thereon may be included (e.g., only node IDs N6.1 -N6.4). Nodes 1 and 3 (N6.1 , N6.3) are in the same group, since after closing branch 9 (BR6.2), these nodes may be at a common voltage level.
  • FIG. 7 A is a flow diagram of one embodiment of a method 700 for processing merged branches in a current processor branch-to-node data structure.
  • a branch-to-node data array may be obtained.
  • Step 710 may comprise accessing the topology data ⁇ e.g., the input 572 of Figure 5).
  • the topology data may be used to initialize a current processor branch-to-node data array.
  • the current processor branch-to-node data of step 720 may be initialized by analyzing static and dynamic topology data to determine the state of the interconnections therein.
  • the result of step 720 may be one or more branch-to-node data arrays as depicted in tables 1 , 2, and 3.
  • method 700 may loop through every non-metering branch defined in the current topology branch-to-node data array obtained at step 720.
  • the merged status of a branch may be determined. As discussed above, for a current branch-to-node data, a branch may be merged if the topology data indicates that the branch is closed ⁇ e.g., element 254 of Figure 2B, "closed” node has value TRUE) and/or the closed quality status is false ⁇ e.g., element 255 of Figure 2B, "closed_quality_status").
  • the branch-to-node data structure may be updated to reflect the merged status of the branch. As discussed above, this may comprise replacing all instances of the TO node ID in the merged branch with the FROM node ID in the current branch-to-node data structure.
  • method 700 may determine whether all the branches in the branch-to-node data have been processed per steps 740-750. If not, the flow may continue at step 740 where the next branch in the current processor branch-to-node data may be processed; otherwise, the flow may terminate at step 770.
  • Figure 7B is a flow diagram of one embodiment of a process 701 for merging nodes in a voltage processor branch-to-node data structure. Process 701 may be substantially the same as process 700 discussed above in conjunction with Figure 7A with the exception of step 741 (740 in Figure 7A).
  • a branch in the voltage branch-to-node data may be merged if the topology data indicates that the branch is closed ⁇ e.g., element 254 of Figure 2B, "closed” node has a value of TRUE) and/or the closed quality status is true ⁇ e.g., element 255 of Figure 2B, "closed_quality_status"). If step 741 determines that the branch is merged, the flow may continue to step 751 ; otherwise, the flow may continue to step 761. After determining the status of each branch in the voltage processor branch-to-node array substantially as described above, the flow may terminate at step 771.
  • the topology processor 570 may create one or more node groups of nodes ⁇ e.g., groups such as the current topology group of table 3 and the voltage topology group of table 6).
  • the current group(s) may be based upon the current branch-to-node data structure and may comprise group(s) with current measurements on every branch leaving the group.
  • a current processor module ⁇ e.g., current processor module 580 of Figure 5 may use these group(s) to perform current consistency checks, KCL check, measurement refinement, and the like.
  • the voltage group(s) may be based upon the voltage branch-to-node data structure and may comprise group(s) of nodes.
  • a voltage processor module ⁇ e.g., voltage processor module 590 of Figure 5 may use these group(s) to perform voltage consistency checks, measurement refinement, and the like.
  • the current group(s) may be formed from a current node vector.
  • nodes may be grouped by whether they have been "merged" with one or more other nodes in the array. For example, if a particular node ⁇ e.g., node X) is merged into a branch (it is the TO node ID of a merged branch), the number of nodes associated with node X may be zero (0). If node X is by itself ⁇ e.g., not merged, nor has any nodes merged therein), the number of nodes associated with node X may be one (1 ). If other nodes are merged into node X ⁇ e.g., it is the FROM node ID of a merged branch), the number of nodes associated with node X may be the number of merged nodes plus one (1 ).
  • the voltage group(s) may be formed from a voltage node vector.
  • nodes may be grouped by whether they have been "merged" with one or more other nodes in the array. For example, as above, if a particular node ⁇ e.g., node Y) is merged with another node due to a closed branch (it is the TO node of a merged branch), the number of nodes associated with node Y may be zero (0). If the node Y is by itself ⁇ e.g., not merged into another node, nor has any nodes merged therein), the number of nodes associated with node Y may be one (1 ). If other nodes are merged into node Y ⁇ e.g., it is the FROM node of a merged branch), the number of nodes associated with node Y may be the number of merged nodes plus one (1 ).
  • FIG 8 is a flow diagram of one embodiment of a method 800 for generating a current node vector.
  • the node vector may be initialized from SEPSN topology data (static and/or dynamic) and a current branch-to-node data structure may be obtained.
  • the input data received at step 810 may comprise a current branch-to-node data array produced by method 700 of Figure 7A.
  • each node in the topology may be processed ⁇ e.g., steps 820 through 835 may be performed on each node in the topology), and at step 820, each branch in the branch-to-node data arrays may be processed ⁇ e.g., steps 825 through 830 may be performed for each branch).
  • process 800 may determine if the TO node I D and the FROM node ID in the branch being processed are the same as the current node ⁇ e.g., if the node was merged per process 700 of Figure 7A). If so, the flow may continue to step 830; otherwise, the flow may continue to step 835.
  • the TO ID and the FROM ID branch nodes may be added to a current node vector (or any other data structure capable of holding a number of entries), which may contain nodes belonging to the same group (hereafter current node vector).
  • the current node vector may comprise one or more pointers (or other data references) to the nodes comprising the group.
  • the current node vector may comprise a counter indicating the number of nodes in a particular entry. Accordingly, at step 830, the counter may be incremented if necessary.
  • method 800 may determine whether there are additional branches to process. If so, the flow may continue to step 820; otherwise, the flow may continue to step 840. At step 840, method 800 may determine whether there are additional nodes to process. If so, the flow may continue to step 815; otherwise, the flow may continue to step 845.
  • method 800 may again iterate over all of the nodes in the topology ⁇ e.g., may perform steps 850 through 860 on each node).
  • process 800 may determine whether the node is in the current node vector ⁇ e.g., linked to and/or referenced by an entry in the current node vector). If the node is in the current node vector, the flow may continue to step 860; otherwise, the flow may continue to step 855.
  • the node may be added to the current node vector. This step may be required where the node is "by itself". As such, at step 855, the node may be added to a new node vector comprising only the node itself.
  • process 800 may determine whether there are additional nodes to process. If so, the flow may continue at step 845 where the next node may be processed; otherwise, the flow may terminate at step 865. [00122] As described above, method 800 of Figure 8 may be used to generate a current node vector. In addition, method 800 may generate a voltage node vector.
  • vectors may be generated separately ⁇ e.g., in separate iterations of method 800) or concurrently ⁇ e.g., in the same iteration of method 800).
  • FIG. 8B is a flow diagram of a method 801 for generating a voltage node vector.
  • Method 801 may be performed substantially as described above: at step 81 1 , a voltage node vector may be initialized; at step 816, method 801 may iterate over all of the nodes in the topology; at step 821 , each branch in the voltage branch-to-node data structure may be processed; and, at step 826, each node is compared to each branch in the voltage branch-to-node data structure.
  • the node ID may be compared to the TO node ID and the From node ID in the voltage branch-to-node data structure.
  • step 826 If the condition of step 826 is true (the node ID matches the TO node ID and the FROM node ID), the flow continues to step 831 where the node is added to the voltage node vector; otherwise, the flow continues to step 836. [00124] After processing each node over steps 821 -841 , the flow continues to step 846 where each node in the topology is processed. At step 851 , method 801 determines whether the node is in the voltage node vector. If not, the flow continues to step 856 where the node is added to the voltage node vector substantially as described above; otherwise, the flow continues to step 861 where the next node is processed.
  • the topology processor 570 may perform an embodiment of methods 700 and 800 on the topology data included in branch input data 572.
  • the result may be a current branch-to-node data structure, a voltage branch- to-node data structure, a current node vector, and a voltage node vector.
  • Applying process 800 to the SEPSN 600 depicted in Figure 6, and current branch-to-node data structure depicted in Table 2, may result in a node vector 900 depicted in Figure 9.
  • Figure 9 depicts exemplary data structures 900 as processed by a topology processor (e.g., topology processor 570 of Figure 5).
  • a data structure 903 may represent a current branch-to-node data structure corresponding to the SEPSN depicted in Figure 6. As such, data structure 903 may represent an equivalent set of data as depicted in Table 1. Data structure 903 is replicated in Figure 9 to allow for a better depiction of the current node vector 910.
  • the data structure 905 may represent a current branch-to-node data structure after merging branch 10 ⁇ e.g., BR6.10 of Figure 6). Data structure 905 may represent an equivalent set of data as depicted in Table 2. Data structure 905 is replicated in Figure 9 to allow for a better depiction of the current node vector 910.
  • the current topology branch-to-node data 903 may represent the current-branch topology of the SEPSN 600 of Figure 6 before closing branch BR6.10.
  • references to the merged node 2 (N6.2) may be replaced with node 1 (N6.1 ).
  • the current branch-to-node data 905 depicts an update to the branch-to-node data reflecting this change.
  • references to node 2 (N6.2) in branch 3-5 (BR6.3 - BR6.5) have been replaced with references to node 1 (N6.1 ).
  • the TO node ID in branch 10 (BR6.10) has been changed to node 1 (N6.1 ).
  • the current node vector 910 depicts one embodiment of a current node vector structure 910 corresponding to branch-to-node data structures 903 and 905.
  • the current node vector 910 may be formed by applying an embodiment of method 800, depicted in Figure 8, to the topology of Figure 6 and its corresponding current branch-to-node data 905.
  • the current node vector 910 comprises a group node listing 920.
  • the group node list 920 comprises a group entry (e.g., G.1 ) for each node in the topology.
  • the group node list 920 depicted in Figure 9 corresponds to a SEPSN having eleven (1 1 ) nodes, as such, the group node list 920 comprises eleven (11 ) group entries 920.
  • Each entry G.1 through G.1 1 in the group list 920 comprises: a group identifier; the number of nodes in the group; and a pointer or other reference into a node vector 940.
  • group G.1 may comprise a group identifier "1 " G.1 A, the number of nodes in the group G.1 B (two (2)), and a reference G.1 C to the node vector 940.
  • B6.10 After merging branch 10 (B6.10) in the SEPSN 600 of Figure 6, a group comprising node 1 (N6.1 ) and node 2 (N6.2) may be formed. This may be reflected by group 1 (G.1 ) of the current node vector 910.
  • Group G.1 may be identified as group 1 at entry G.1 A.
  • Entry G.1 B may indicate that there are two (2) nodes comprising group 1.
  • Entry G.1 C may comprise a pointer or other reference into node vector 940.
  • the reference of G.1 C may point to the first node in the group (i.e., node 1 (N6.1 )).
  • the nodes comprising the group can be determined by traversing node vector G.1 B two (2) times.
  • group G.1 may comprise nodes demarcated by 940.1 , N6.1 , and N6.2.
  • a group whose node has been merged into another group may comprise zero (0) nodes.
  • Group two (2) G.2 is such a group. This is because in the Figure 9 embodiment, node 2 (N6.2) has been merged into group 1 (G.1 ) with the closing of branch 10 (BR6.10). As such, the number of nodes in group G.2 is zero and the reference into the reference vector may be zero (0) and/or null.
  • a group may comprise a single node.
  • Groups G.3 through G.1 1 are such groups. Accordingly, G.1 1 comprises one (1 ) node (N6.1 1 ) and points to the node vector location comprising node eleven (1 1 ) (N6.1 1 ) in node vector 940.
  • a voltage node vector may be generated using data structures substantially equivalent to data structures 903, 905, 910, and 940 depicted in Figure 9.
  • the topology processor 570 may produce an operating topology of the SEPSN comprising a current topology 582 for the current processor 580.
  • the current topology 582 may comprise a current branch-to-node data array, and a current node vector, and associated node vector.
  • the current processor 580 may also receive current measurements 584.
  • the current measurements 584 may be obtained by one or more PMUs (not shown) and/or PMCUs or relay (not shown) disposed within a substation power system network, the current measurements 584 may be time-aligned substantially as described above.
  • the current topology data 582 and current measurements 584 may be input to the current processor 580 as a tree structure (e.g., the branch input list 220 described in conjunction with Figure 2B).
  • FIG. 10 depicts a flow diagram of one embodiment of a method 1000 for performing these functions.
  • method 1000 may receive a current topology, which, as discussed above, may comprise a current topology of the SEPSN ⁇ e.g., comprise a current branch-to-node data, etc.).
  • the method 1000 may receive one or more current measurements associated with the current topology.
  • one or more correction factors may be read.
  • the correction factors read at step 1020 may be read from the topology data discussed above.
  • the correction factors may be used to normalize the current measurements with respect to the topology data received at step 1010.
  • Figure 1 1 depicts one embodiment of a SEPSN topology that may be used to illustrate the use of one or more current correction factors at step 1020.
  • node 1 110 may be in electrical communication with node 1 120 via a power transmission conductor 1 130 to allow a current /1132 to flow therebetween.
  • An IED 1 1 12 such as a PMU and/or PMCU or relay, may be communicatively coupled to transmission conductor 1 130 at or near node 1 1 10 to measure a current / 1112 thereon.
  • Another IED 1 122 which may be an IED, relay, a PMU and/or PMCU, may be communicatively coupled to transmission conductor 1130 at or near node 1 120 to measure a current /1122 thereon.
  • Equation 1.1 a first measurement correction factor for the measurement obtained at IED 11 12, Zc 1 may be 1 at 0 Q since the current flowing from node 1 1 10 to node 1 120 may cause a secondary current to enter IED 1 1 12.
  • a second measurement correction factor for the measurement obtained at IED 1 122, Zc 2 may be 1 at 180 Q (i.e., -1 ) since the primary current 1 132 flowing from node 11 10 to node 1 120 may cause a secondary current to leave IED 1 122.
  • Equation 1.1 may be rewritten as shown in Equation 1.2:
  • the current correction factors discussed above may also be adapted to take into account properties of the device (e.g., current transformer) used to obtain the current measurement.
  • a current correction factor may account for a turn ratio of the current transformer and/or IED used to obtain a current measurement ⁇ e.g., 1 1 12 and/or 1 122 of Figure 1 1 ).
  • a current correction factor may address any phase shifting introduced by the current transformer and/or IED. This may allow the current correction factor to normalize measurements obtained by different current transformer types and/or configurations.
  • a current correction factor may comprise a magnitude correction factor and/or a phase correction factor.
  • the magnitude and/or phase component of a particular current correction factor may be derived from any of the current measurement properties discussed above including, but not limited to: an orientation of the current measurement in a current topology; a current magnitude adjustment ⁇ e.g., due to current transformer turn ratio or the like); a current phase adjustment ⁇ e.g., due to current transformer phase shift); combinations thereof; and the like.
  • Voltage correction factors may be used to normalize voltage measurements obtained by the IEDs ⁇ e.g., IED 1 1 12 and/or 1 122 of Figure 1 1 ). Like the current correction factors discussed above, the voltage correction factors may be used to address voltage measurement differences introduced by the transformer and/or IED used to obtain the measurements ⁇ e.g., magnitude, phase shift, and the like).
  • Voltage correction factors may also be used to address the orientation of voltage measurements in a voltage topology ⁇ e.g., account for the polarity of a voltage measurement and the like).
  • a voltage correction factor may address a voltage base value of a measurement ⁇ e.g., the measurement may be taken relative to a voltage base).
  • method 1000 may read and/or otherwise determine correction factors for every current measurement received at step 1010.
  • the correction factors may be static, such that they only need to be read or determined once.
  • one or more factors may be recalculated as the topology of the SEPSN changes ⁇ e.g., in response to dynamic topology data).
  • correction factors associated with one or more measurements may be user supplied and stored in data structure, such as data structure 210 of Figure 2B ⁇ e.g., element 263 of Figure 2B).
  • the flow may continue to step 1030.
  • the current measurements received at step 1010 may be scaled ⁇ e.g., normalized) using the correction factors of step 1020.
  • the scaled current measurements may be stored in a data structure for use in subsequent steps ⁇ e.g., steps 1040-1060) of method 1000.
  • the flow may then continue to step 1040.
  • method 1000 may perform a current measurement consistency check on the scaled current measurements. One embodiment of a method to perform such a check is described below in conjunction with Figures 12A and B. The flow may then continue to step 1050.
  • method 1000 may refine one or more of the current measurements.
  • One embodiment of a method for refining current measurements is described below in conjunction with Figures 13A and 13B. The flow may then continue to step 1060.
  • method 1000 may perform current unbalance and symmetrical component checks. One embodiment of a method for performing these checks is described below in conjunction with Figure 14. The flow may then terminate at step 1070.
  • Figure 12A is a flow diagram of one embodiment of a method 1200 for performing a current consistency check.
  • topology data and one or more scaled current measurements may be received. This data may be provided by an output of method 1 100 described above in conjunction with Figure 1 1.
  • method 1200 may iterate each branch and phase within the topology data received at step 1210. As such, method 1200 may perform steps 1230 through 1280 for each branch and phase within the topology data of step 1210.
  • method 1200 may determine whether current measurements are available for the branch. This information may be provided in the topology data of step 1210 ⁇ e.g., number_of_current_measurements entry 256 of Figure 2B). If there are measurements available in the branch, the flow may continue to step 1240; otherwise, the flow may continue to step 1280.
  • one or more scaled current measurements associated with the branch may be obtained.
  • the scaled current measurements of step 1240 may be made available by another process ⁇ e.g., process 1 100 described above in conjunction with Figure 11 ) or may be computed at step 1240 given one or more correction factors provided in the topology data of step 1210.
  • a current measurement median may be determined. This may comprise computing the median value from the available current measurements. In an alternative embodiment, step 1250 may use the average value.
  • a consistency check may be performed on each of the current measurements for the current branch. This consistency check may comprise calculating a difference between each current measurement for the branch to the median measurement value of the branch (calculated at step 1250) against a consistency threshold value per Equation 1.4:
  • Equation 1.4 q may be a branch current measurement corresponding to one or more current phases, ⁇ B may be the median or mean current measurement for the branch and e& may be the consistency threshold for the phase and branch. If the inequality of Equation 1.4 is satisfied, the flow may continue to step 1280; otherwise, the flow may continue at step 1270.
  • a consistency alarm may be set indicating that one or more current measurements and/or phases of a current measurement fail to satisfy the consistency check of step 1260.
  • the alarm may identify the branch, phase, and/or the one or more measurements that produced the inconsistency.
  • the flow may continue to step 1280.
  • method 1200 may determine whether there are additional branches to process. If so, the flow may continue to step 1220; otherwise, the flow may terminate at step 1290.
  • FIG 12B a visual depiction of process 1200 is provided.
  • measurements 1211 corresponding to a particular branch may be plotted on plot 1201 , comprising an imaginary axis 1203 and a real axis 1205.
  • a median value 1213 of the measurements 121 1 may be determined.
  • a consistency threshold associated with the phase and branch may be depicted as 1221. The radius of 1221 may correspond to the consistency threshold value.
  • a measurement 1215 that differs from the mean and/or media value 1213 by more than a threshold 1221 may cause a consistency alarm to be asserted.
  • topology data and two (2) or more scaled current measurements may be received.
  • the data received at step 1310 may be provided by an output of a method, such as 1 100 described above in conjunction with Figure 1 1.
  • method 1300 may iterate over each node ⁇ e.g., each entry in a current merged node array) in the topology data received at step 1310.
  • method 1300 may iterate over each phase measurement available for the node and/or group of step 1320 ⁇ e.g., each phase of a three-phase, phase current, or other signal measurement).
  • method 1300 may determine whether a KCL check may be performed on the node.
  • a KCL check may require that all currents reaching a node be available. This requirement may be imposed since method 1300 may operate under the axiom that the sum of currents reaching a node should be substantially zero (0) per Kirchhoff's Current Law (KCL). If one of the current measurements is unavailable, however, the KCL axiom may not hold, and as such, process 1300 may not yield meaningful results.
  • a KCL check may be possible if all nodes in the group are KCL nodes ⁇ e.g., have current measurements on their associated branches). If a KCL check can be performed on the node and/or node group, the flow may continue to step 1340; otherwise, the flow may continue to step 1380 where the next node and/or phase may be processed.
  • the scaled current measurements reaching the node may be summed and compared to a KCL threshold value per Equation 1.5:
  • N may be the number of branches reaching a particular node group
  • Q may be a particular phase-current measurement
  • KCL_thre may be the KCL threshold ⁇ e.g., instance 231 of Figure 2B).
  • method 1300 may determine whether the inequality of Equation 1.5 is satisfied. If the inequality is satisfied (i.e., the absolute value of the sum is less that the KCL threshold), the flow may continue to step 1360; otherwise, the flow may continue to step 1370 where the next node and/or phase may be processed.
  • the current measurements associated with the node may be flagged appropriately (e.g., marked as satisfying the threshold of step 1340), and the flow may continue to step 1365 where the phase-current measurements may be refined.
  • the phase-current measurements may be refined.
  • refinement may comprise refining the measurements relative to an overall error metric e.
  • the phase-current measurements may be refined such that the overall error e is minimized.
  • Figure 13B depicts a segment 1301 of a SEPSN.
  • the segment 1301 may comprise a node 131 1 having three branches connected thereto, each comprising a scaled current measurement: 1313 (Ai), 1315 (A 2 ), and 1317 (A 3 ).
  • the current measurements 1313, 1315, and 1317 may correspond to a single phase of a three- phase, current signal reaching the node 131 1.
  • Equation 1.6 the threshold condition of node 131 1 may be given as Equation 1.6:
  • Equation 1.7 may represent the metered and/or refined phase-current measurements reaching node 131 1. Accordingly, Equation 1.7 equally distributes any measurement error between the three current measurements 1313 (Ai), 1315 (A 2 ), and
  • Equation 1.8 Equation 1.8
  • Equation 1.8 the problem becomes one of minimizing error e. To do so, the pseudo inverse of the matrix of Equation 1.8 may be obtained, and Equation 1.8 may be rewritten as Equation 1.9:
  • Equation 1.9 may remain constant as the number of currents reaching the node (e.g., node 131 1 ) changes.
  • Equation 1.10 may represent the number of currents reaching a particular node and / and j may be the indices of the matrix in Equation 1.9. As such, for node 131 1 of Figure 13B, n may be three (3). [00183] To refine the phase-current estimates, Equation 1.10 may be applied to obtain entries in the matrix of Equation 1.9, and then multiply the matrix by the measurement vector (i.e., the A ⁇ n vector). A closed form may be written as Equation 1.1 1 :
  • Equation 1.1 1 may be applied to the phase-current measurements A to thereby obtain refined measurements /,.
  • the refined measurements may be output to a HMI interface (e.g., output 585.1 in Figure 5 to an HMI 470 of Figure 4).
  • method 1300 may determine whether there are remaining current phases to processes. If so, the flow may continue to step 1325 where a next set of phase-current measurements of a multi-phase current (e.g., three (3)-phase current) may be processed; otherwise, the flow may continue to step 1380.
  • method 1300 may determine whether there are remaining nodes to process. If so, the flow may continue to step 1320 where the next node and/or node group may be processed; otherwise, the flow may terminate at step 1390.
  • topology data and one (1 ) or more scaled current measurements may be received.
  • the data received at step 1410 may be provided by an output of a method, such as 1 100 described above in conjunction with Figure 1 1.
  • method 1400 may iterate over all of the branches in the topology data received at step 1410.
  • method 1400 may determine whether all phase current measurements of the particular branch are available. If so, the flow may continue at step 1440; otherwise, the flow may continue at step 1480 where the next branch may be processed.
  • an unbalanced branch check may be performed.
  • the check of step 1440 may comprise determining a reference current (/ REF ) value, which, in some embodiments, may be the median value of the phase current magnitudes at the branch.
  • the / REF may be an average value
  • a ratio of the magnitude of each phase ⁇ e.g., each phase of a three (3)-phase current) to the reference current / REF may be calculated per equation
  • Equation 1.13 U ⁇ O A may be the magnitude of the ratio of a magnitude of the A phase current measurement (I A ) to the reference current, / REF minus 1. Equation 1.13, may be used to calculate the unbalance for each current phase ⁇ e.g., phases A, B, and C of a three (3)-phase current). The unbalance of Equation 1.13 may be expressed in terms of a percentage as in Equation 1.14:
  • each of the phase-current unbalances may be compared to a user-defined unbalance threshold value associated with the branch.
  • the topology data received at step 1410 may include these threshold values ⁇ e.g., i_unb_thre element 257.2 of Figure 2B). If any of the phases exceeds its respective unbalance threshold, the flow may continue at step 1465; otherwise, the flow may continue to step 1470.
  • a current unbalance alarm may be set on the current measurement. The alarm of step 1465 may be set for all phases of a multi-phase current ⁇ e.g., three (3)-phase current) and/or only the phases that fail to satisfy the unbalance threshold of steps 1450.
  • step 1470 the symmetrical components (negative, positive, and zero) of the three-phase current may be calculated.
  • the symmetrical components may be compared to the user-defined threshold values associated with the branch symmetrical components.
  • the topology data received at step 1410 may include these threshold values ⁇ e.g., as one or more values in data structure 210 of Figure 2B). If one or more symmetrical components exceeds its associated threshold, the flow may continue to step 1475; otherwise, the flow may continue to step 1480.
  • the symmetrical component alarm(s) may be set on the current and branch. After setting the alarm, the flow may continue to step 1480.
  • step 1480 the next unprocessed branch (if any) may be checked, and the flow may continue to step 1420. If no branches remain to be processed, the flow may terminate at step 1490.
  • current processor 580 may perform method 700 (described above in conjunction with Figure 7), which may comprise applying one or more correction factors to current measurements 584, computing a current measurement mean or median for each branch, checking branch current consistency, refining current measurements, and checking current balance and symmetrical components as described in conjunction with Figures 8-14. [00202] If current refinement is possible, current processor 580 may output refined current values 585.1. In addition, the checks mentioned above ⁇ e.g., consistency, KCL, unbalance, etc.) may comprise setting an alarm relating to one or more checked current phases, currents, and/or branches. As such, after processing one or more alarms 585.2 may be output from current processor 580.
  • method 700 described above in conjunction with Figure 7
  • current processor 580 may perform method 700 (described above in conjunction with Figure 7), which may comprise applying one or more correction factors to current measurements 584, computing a current measurement mean or median for each branch, checking branch current consistency, refining current measurements, and checking current balance and symmetrical components as described in conjunction with Figure
  • these alarms may be routed to a HMI module ⁇ e.g., element 470 of Figure 4) and/or a local PMCU ⁇ e.g., element 480).
  • a HMI may display one or more alarms to an operator of the state and topology processor, and a local PMCU may use the alarm data to invoke one or more protective functions including, but not limited to: sending an alarm, tripping one or more circuit breakers, changing the configuration of one or more switches, removing and/or adding one or more loads, or the like.
  • Current unbalance percentage values calculated by current processor module 580 ⁇ e.g., per method 1400 described above in conjunction with Figure 14) may be provided via output 585.3.
  • the voltage processor module 590 of STP 560 may receive voltage measurement data 594 and voltage topology data 592 from the topology processor 570. As discussed above, this data may be conveyed via a data structure similar to the tree data structure described above in conjunction with Figures 2B and 2C.
  • the voltage processor 590 may be configured to apply voltage correction factors to the voltage measurement data 594, calculate median phase-voltage measurement values at each node in topology data 592, perform one or more voltage consistency checks, refine the voltage measurements 594, and perform symmetrical component analysis on voltage measurements 594.
  • a voltage processor module such as voltage processor module 590 of Figure 5, may perform method 1500.
  • method 1500 may receive network topology data ⁇ e.g., a node list data structure and/or voltage merged node group), and/or one or more phase voltage measurements.
  • the topology and phase voltage measurement data may be conveyed in a data structure similar to the "input data" data structure described above in conjunction with Figures 2B and 2C.
  • method 1500 may iterate over all of the node groups in the topology data received at step 1510 ⁇ e.g., all node groups in the merged group data structure).
  • one or more correction factors may be applied to the voltage measurements received at step 1510.
  • the correction factors may be stored in the network topology data of step 1510 in, for example, voltage correction factors 277 of Figure 2C.
  • a median value for each phase-voltage measurement may be determined.
  • an average phase-voltage measurement may be calculated at step 1530.
  • a voltage consistency check may be performed.
  • the voltage consistency check of step 1540 may be similar to the current consistency check described above in conjunction with Figure 12A.
  • the consistency check may comprise calculating a difference between each phase-voltage measurement of a particular node and/or node group to the median phase-voltage measurement calculated at step 1530.
  • the consistency check of step 1540 may be performed for all phases of each phase voltage measurement available at a particular node group.
  • a user-defined threshold e.g., defined in data structure 210 described above in conjunction with Figures 2A-C
  • a voltage consistency alarm may be set.
  • the alarm may identify the voltage phase, measurement, node, and/or node group corresponding to the alarm.
  • the flow may then continue to step 1560.
  • the symmetrical components for each group and/or node phase-voltage measurement may be calculated.
  • these components may be compared to corresponding user-defined symmetrical component threshold(s). These thresholds may be stored in the data received at step 1510 ⁇ e.g., in an input data structure 210 described above in Figures 2B and 2C). If one or more components exceed its associated threshold, the flow may continue at step 1575; otherwise, the flow may continue to step 1580.
  • the symmetrical component alarms may be set. These alarms may identify the node and/or node group and/or the measurement producing the alarms. The flow may then continue to step 1580.
  • method 1500 may determine whether there are nodes and/or node groups remaining to process. If so, the flow may continue to step 1520 where the next node and/or node group may be processed; otherwise, the flow may terminate at step 1590.
  • the voltage processor 590 may perform method 1500 (described above in conjunction with Figure 15), which may comprise applying one or more correction factors to voltage measurements 594, computing a voltage measurement median or mean for each node and/or node group, checking measurement consistency, and/or performing a symmetrical components check.
  • the checks discussed above may comprise setting an alarm relating to one or more phase voltages on one or more node groups, voltages, nodes, and/or node groups.
  • one or more alarms 595.2 may be output from voltage processor 590.
  • alarm(s) 595.2 may be routed to HMI module ⁇ e.g., HMI 470 of Figure 4) for display to a user.
  • the alarms may be routed to a local PMCU ⁇ e.g., PMCU 480 of Figure 4), which may invoke one or more protective functions responsive to the alarm(s) 595.2.
  • These protective functions may include, but are not limited to: sending an alarm, tripping one or more circuit breakers, changing the configuration of one or more switches, removing and/or adding one or more loads, or the like. Additionally, one or more symmetrical components corresponding to voltage measurements 594 may be output at 595.3.
  • the DP 420 may be communicatively coupled to a human machine interface (HMI) 470.
  • HMI human machine interface
  • the HMI 470 may be used to display monitoring information to a user of the DP 420.
  • Such information may comprise refined measurements, alarms, and the like.
  • Figure 16 depicts one embodiment of an visualization interface 1600.
  • the visualization interface 1600 may be displayed within a computer display and/or application 1610.
  • the application 1610 may be executable on a general and/or special purpose computing device comprising a processor (not shown), input devices (not shown), such as a keyboard, mouse, or the like, data storage (not shown), such as a disc drive, memory, or the like, and one or more output devices (not shown), such as display, audio speakers, or the like.
  • the application 1610 may be presented on the display of the computing device (not shown) and may comprise custom and/or general purpose software communicatively coupled to a state and topology processor and/or time aligned data processor ⁇ e.g., the DP 420 and/or STP 460 of Figure 4).
  • the application 1610 may be configured to display a portion of the substation power system network to which the STP is connected.
  • the display of the power system may be based upon topology data received from the DP and/or STP.
  • the topology display may comprise the real-time operating topology as determined by the DP and/or STP. As such, the display may show the current state of one or more breakers, switches, and other connective components in the power system.
  • the topology display may further include indications of one or more bus differential protection zones determined by the current processor.
  • a bus differential protection zone may include one or more busbars or nodes, and may be used to provide distributed bus differential protection to the power system.
  • the application 1610 may display refined current and/or voltage measurements 1622 and 1624 received from the DP and/or STP. Although Figure 16 depicts only two (2) such measurements displayed on the application 1610, one skilled in the art would recognize that any number of measurements could be displayed in the application 1610 according to the configuration of the STP and/or the power system network. [00222] The refined measurements 1622 and 1624 may be obtained substantially as described above.
  • a refined current measurement may represent a combination of multiple current measurements as refined using an error minimization metric.
  • refined voltage measurements may comprise a median, average, and/or error minimized voltage measurements.
  • One or more alarms 1612, 1614, and/or 1616 may be displayed in the application 1610. The alarms displayed on one or more components of the electrical power system, such as electrical power system nodes ⁇ e.g., N1 , N2, and so on), electrical power system branches, bus bars, or the like.
  • the alarms 1612, 1614, and/or 1616 may be generated responsive to any one or more of the alarm conditions described above ⁇ e.g., KCL, symmetrical components, unbalance, or the like).
  • the alarms 1612, 1614, and/or 1616 may related to current conditions, voltage condition, branch conditions, or the like. In addition, one or more of the alarms 1612, 1614, and/or 1616 may be related to a busbar fault detected by a distributed bus differential protection scheme discussed below.
  • the application 1610 may be selectable such that selection of a particular node, branch, and/or alarm may display detailed information relating to the respective component. For example, selection of the alarm 1616 on branch B3 may cause application 1610 to display details regarding the measurements and/or alarms associated with the branch B3.
  • a display 1700 is provided in Figure 17.
  • an application 1710 may display additional information relating to a particular component within the power system network displayed the application 1610.
  • Figure 17 displays details related to a branch B3 shown in Figure 16.
  • the application 1710 may comprise a measurement consistency check 1720 component, which may display each of the measurements 1721 and 1723 available at the particular component.
  • Each measurement 1721 and 1723 may comprise a three- current measurement 1722 and 1724.
  • a refined current measurement may be displayed at 1726, which may comprise three-phase refined measurements 1727 and/or symmetrical components 1728 of the refined measurement.
  • the application 1710 may further display alarms 1732 associated with the particular component.
  • a KCL 1734 and unbalance alarm 1736 may be displayed.
  • the alarms could comprise voltage consistency alarms or the like.
  • the KCL alarm may 1734 be shown as "OK" indicating that the measurements 1721 and 1723 satisfy KCL, and the unbalance alarm 1736 may indicate an unbalance condition at the branch.
  • the application 1710 may be adapted to display information relevant to a distributed bus differential protection scheme.
  • a display component may include a differential protection component 1742, which may provide a list 1744 of the busbars or nodes that are included in the protection zone and/or a list 1746 of the branches included in the protection zone. Additional protection zone information, such as restraining current values, operating current values, slope characteristic values, pickup current thresholds, and the like may also be included (not shown).
  • a bus also referred to as a busbar or node
  • a bus may provide a connection for electric power transmission, generation, and loads. If a fault occurs on a bus, all circuits supplying fault current may be required to trip in order to isolate the fault. Thus, a bus fault may result in extensive loss of service.
  • the electrical power system may be capable of dynamically modifying its configuration (e.g., dynamically connecting/disconnecting power system components, such as buses or nodes).
  • Monitoring and/or protecting a complex, dynamic bus arrangement may comprise determining, in real-time, one or more bus differential protection zones (also referred to as "protection zones") within the arrangement.
  • a current differential protection function may be provided within each of the protection zones.
  • Bus monitoring and protection may be increasingly difficult when the arrangement has many terminals and/or spans large distances.
  • the IEDs that monitor and/or protect other buses in the arrangement may be located at great distances from one another, which may preclude a centralized monitoring system.
  • the buses themselves may be situated at great distances from each other, as may the IEDs that are configured to protect and monitor the system.
  • communicatively coupling the IEDs may require long communication paths and complex communication arrangements.
  • FIG. 18 is a block diagram of one embodiment of an electrical power system 1800 comprising a data processor 1890 configured to provide distributed bus differential protection.
  • a data processor 1890 is configured to receive time-stamped measurement data from the IEDs 1840, 1842, 1844, 1846, and 1848 (referred to herein as the Figure 18 IEDs).
  • the Figure 18 IEDs may be communicatively coupled to various portions of the power system 1800 and, as such, may be distributed at various locations therein. In some embodiments, the Figure 18 IEDs may be separated by significant distances from each other and/or the data processor 1890.
  • the Figure 18 IEDs may be communicatively coupled to respective time sources ⁇ e.g., a common time source). Therefore, the Figure 18 IEDs may be time synchronized to one another. Accordingly, time-stamps applied to measurement data acquired by the Figure 18 IEDs may be consistent with one another ⁇ e.g., may be capable of being time aligned as described above).
  • time-stamps applied to measurement data acquired by the Figure 18 IEDs may be consistent with one another ⁇ e.g., may be capable of being time aligned as described above).
  • a scheme for distributing a common time source and/or synchronizing distributed IEDs such as the Figure 18 IEDs, is described below in conjunction with Figure 22.
  • the data processor 1890 may be configured to time-align the measurements received from the Figure 18 IEDs and to implement a distributed bus differential protection scheme using the time-aligned measurement data.
  • a distributed bus differential protection scheme may implement dynamic zone selection to assign terminal current information to appropriate protection zones.
  • the Figure 18 power system illustrates one example of a bus arrangement capable of comprising a plurality of dynamic ⁇ e.g., changing) bus differential protection zones.
  • the power system 1800 includes four buses, including bus 1850, bus 1860, bus 1870, and bus 1880.
  • One or more protection zones may be defined within the power system 1800.
  • a bus differential protection zone (or protection zone) may refer to an area of protection formed by one or more buses. Merging two or more buses may result in a single protection zone that includes the merged buses.
  • the protection zone of an unmerged bus may include only the bus itself.
  • the power system 1800 includes three switches: switch 1834 is configured to selectively connect buses 1850 and 1860; switch 1836 is configured to selectively connect buses 1850 and 1870; and switch 1838 is configured to selectively connect buses 1860 and 1880.
  • Closing a switch 1834, 1836, and/or 1838 may cause two or more of the buses 1850, 1860, 1870, and/or 1880 to merge into a protection zone with multiple buses(e.g., the buses may merge into a "single" bus differential protection zone for the purposes of the differential current protection scheme). For example, closure of the switch 1834 while the switches 1836 and 1838 are open causes buses 1850 and 1860 to merge into a protection zone that includes buses 1850 and 1860, while the buses 1870 and 1880 remain in separate respective protection zones.
  • the power system 1800 would include three protection zones: a first protection zone comprising the buses 1850 and 1860, a second protection zone comprising the bus 1870, and a third protection zone comprising the bus 1880. Bus differential protection may be provided within each of the three protection zones.
  • the power system 1800 includes circuit breakers 1802, 1804, 1806, 1808, 1810, 1812, 1814, and 1816 (the Figure 18 circuit breakers).
  • the Figure 18 circuit breakers may be electrically coupled to respective conductors 1801 , 1803, 1805, 1807, 1809, 1811 , 1813, and 1815 to selectively interrupt power flow thereon.
  • each of the conductors 1801 , 1803, 1805, 1807, 1809, 1811 , 1813, and/or 1815 could include multiple lines ⁇ e.g., a conductor line for each phase of a three-phase system)
  • the Figure 18 circuit breakers may be communicatively coupled to respective IEDs ⁇ e.g., IEDs 1840, 1842, 1844, 1846, and/or 1848).
  • the Figure 18 IEDs may be configured to monitor conditions on the conductors 1801 , 1803, 1805, 1807, 1809, 1811 , 1813, and/or 1815.
  • the Figure 18 IEDs may be configured to cause one or more of the Figure 18 breakers to trip to isolate the fault.
  • the data processor 1890 may direct the operation of multiple Figure 18 IEDs to isolate bus faults spanning multiple buses and/or IEDs.
  • the Figure 18 IEDs may receive current measurements from one or more measurement devices located at various locations within the power system 1800: the IED 1840 receives current information from the CT 1818; the IED 1842 receives current information from CTs 1822, 1824, and 1826; the IED 1844 receives current information from CTs 1830 and 1832; the IED 1846 receives current information from the CT 1828; and the IED 1848 receives current information from CT 1820.
  • the Figure 18 IEDs may obtain dynamic topology information, such as the status of the Figure 18 circuit breakers, the status of the Figure 18 switches ⁇ e.g., switches 1834, 1836, 1838), the status of other switch components (not shown) in the power system 1800, and/or the real-time status and/or state of other components (terminals, transformers, switchgear, etc.).
  • the Figure 18 IEDs may comprise phasor measurement units
  • the Figure 18 IEDs may transmit the current information received from the CTs as synchrophasors ⁇ e.g., according to IEEE C37.1 18).
  • the Figure 18 IEDs may transmit the measurement data ⁇ e.g., comprising time-stamped current and/or dynamic topology data) to a data processor 1890, which, as described above in conjunction with Figure 4, may comprise a time alignment module 1892 and a real-time system 1894.
  • the time alignment module 1892 may time- align the time-stamped data received from the Figure 18 IEDs as described above.
  • the run-time system 1894 may provide for fast and accurate protection of the power system 1800. Accordingly, the run-time system 1894 may be configured to process the dynamic topology data received from the Figure 18 IEDs to determine a current topology of the power system 1800, which may include one or more bus differential protection zones. The current topology and/or protection zone information may be used to detect busbar faults within the power system 1800 using the time- stamped current measurements received from the Figure 18 IEDs.
  • the run-time system 1894 may include a state and topology processor (STP) 1896, which may be configured to dynamically determine one or more protection zones within the power system 1800 in real-time.
  • STP state and topology processor
  • a bus differential protection zone may comprise one or more buses; buses that are electrically connected (by one or more of the switches 1834, 1836, and/or 1838 or other component) may be merged into a single protection zone, and unmerged buses may be included in their own, separate protection zones.
  • the buses 1850 and 1870 may be included in the same protection zone, which may include the IEDs 1848 and 1842.
  • the STP 1896 may manage the monitoring and/or protection of the protection zone across the IEDs 1848 and 1842, which may provide for faster and more accurate protection of the protection zone that would be possible by either of the IEDs 1848 and/or 1842 separately.
  • the STP 1896 may use current and/or dynamic topology information received from both of the IEDs 1848 and 1842 to monitor the protection zone for faults and/or direct protective actions taken thereby.
  • the data processor 1890 and/or the STP 1896 may comprise and/or be implemented within an IED capable of receiving electric power information from various conductors ⁇ e.g., via respective current transformers), calculating synchrophasors therefrom, operating circuit breakers, and/or coordinating the operation of other IEDs in a real-time basis.
  • the data processor 1890 and/or the STP 1896 could be implemented within and/or in conjunction with one or more of the Figure 18 IEDs.
  • the STP 1896 may be configured to provide the monitoring and/or protective functions described above in conjunction with the STP 560 of Figure 5. Alternatively or in addition, the STP 1896 may be configured to provide distributed bus differential protection. One example of an STP 1896 configured to provide distributed bus differential protection is described below in conjunction with Figure 19. [00246]
  • Figure 19 is a block diagram 1900 of one embodiment of a STP 1996 configured to provide distributed differential bus protection.
  • the STP 1996 of Figure 19 may include a topology processor 1970, a current processor 1980 and/or a voltage processor 590, which may operate similarly to the modules 570, 580 and 590 described above in conjunction with the STP 560 of Figure 5.
  • the voltage processor 590 (along with the voltage topology 592 data, voltage measurement date 594, and corresponding outputs 595) may be omitted.
  • the topology processor 1970 may receive dynamic topology data ⁇ e.g., switch status, breaker status, etc.) and may output a current topology 1982 and/or corrected current measurements (not shown) as described above ⁇ e.g., as described in connection with the topology processor 570 of Figure 5 and/or Figure 7A, 8A, and/or 10).
  • the topology processor 1970 may be configured to dynamically determine one or more bus differential protection zones based on the topology data ⁇ e.g., according to electrical connection(s) between one or more buses).
  • a bus differential protection zone may be defined as a list of current branches within the protection zone ⁇ e.g., the current branches that are electrically connected to the busbars within the protection zone).
  • the bus differential protection zones may be included in the current topology 1982 and/or may be provided as a separate output 1982.1 of the topology processor 1970.
  • the current processor 1980 may be configured to output refined current measurements 585.1.
  • the refined current measurements 585.1 may flow to the current differential element 1906 for use in the distributed bus differential protection scheme.
  • the current differential element 1906 may use raw and/or corrected current measurements provided by the topology processor 1970.
  • the protection zone information 1982.1 and the refined current measurements 585.1 may flow to a current differential element 1906, which may be configured to implement a bus differential protection scheme for each of the protection zones.
  • the current differential element 1906 may be implemented within the STP 1996 and/or as a separate component ⁇ e.g., outside of the STP 1996).
  • the current differential element may be included as a component of and/or within the current processor 1980.
  • the current differential element 1906 may use the protection zone information 1982.1 and the refined, time-aligned current measurements 585.1 to detect faults using a current differential element and/or based upon the evaluation of a current differential operating condition.
  • the STP 1996 and/or the current differential element 1906 may be capable of concurrently providing protection to any number of protection zones. Accordingly, the STP 1996 and/or the current differential element 1906 may incorporate multiple current differential elements (such as 1906) capable of operating in parallel.
  • the STP 1996 and/or current differential element 1906 may be capable of implementing bus differential protection for a large number of protection zones in serial ⁇ e.g., the STP 1996 and/or current differential element 1906 may operate at a higher clock frequency than the sample frequency of the current measurements 584, which may allow plural protection zones to be protected during each measurement period). Accordingly, the STP 1996 should not be considered to be limited as to the number of current differential element(s) 1906 provided therein and/or to the number of bus differential protection zones that may be concurrently protected.
  • the STP 1996 and/or the current differential element 1906 may be configured to generate one or more protective control signals 1924.
  • the protective control signals 1924 may be configured to isolate or clear the fault, inform other devices of the fault ⁇ e.g., other protective devices or IEDs), or the like.
  • the protective control signals 1924 include one or more alarm signals for display to a user via a HMI (not shown).
  • the protective control signals 1924 may include circuit breaker trip commands configured to trip breakers on the conductors that are supplying current to the fault.
  • the protective control signals 1924 may be issued to the one or more IEDs to which the circuit breakers are coupled.
  • the protective control signals 1924 may be issued directly to the one or more of the circuit breakers.
  • the protective control signals may be adapted according to the current topology information 1982.
  • the current topology information 1982 may indicate which branches are supplying current to the faulted protection zone.
  • the protective control signals 1924 may be adapted according to the protective and/or control components available in the electrical power system.
  • the current differential element 1906 may evaluate a current differential operating condition. Evaluating the operating condition may comprise calculating a restraining current for and an operating current l O p.
  • the current differential element 1906 may operate ⁇ e.g., detect a fault within the protection zone) if the operating condition of the element 1906 is satisfied.
  • the operating condition may be satisfied if the operating current / OP is greater than the scaled restraining current for (scaled by a slope characteristic) and a pickup current threshold
  • the restraining current for and the operating current l O p may be calculated in a number of different ways. Equations 2.1 and 2.2 below provide one example; however, any means for calculating the restraining current Wand the operating current / OP could be used under the teachings of this disclosure:
  • IRT IU + IO2I + IU + IZ 04 I - + KnI Eq. 2.1
  • the current values hi through I n may be measurements of the currents flowing into a protection zone ⁇ e.g., on the branches within the protection zone).
  • the measurements may be corrected for polarity and other factors ⁇ e.g., current transformer characteristics) according to the current topology information 1982 as described above.
  • the measurements may be refined current measurements 585.1 generated by the current processor 1980.
  • the restraining current I RT may be scaled by a slope characteristic SLP, which may be defined on a per-protection zone and/or per-bus basis ⁇ e.g., defined in the static and/or dynamic current topology information 1982).
  • the value of the slope characteristic SLP may determine the sensitivity of the differential element.
  • Some embodiments may employ a dual slope and/or adaptive slope characteristic, which may be used to change the sensitivity of the element responsive to conditions in the power system ⁇ e.g., an external fault or the like). Examples of various slope characteristics are described in United States Patent No. 6,356,421 to Armando Guzman-Casillas et al., and entitled, "System for Power Transformer Differential Protection" which is hereby incorporated by reference in its entirety.
  • the current differential element 1906 may include a harmonic blocking module and/or be harmonically restrained. The harmonic blocking and harmonic restraint elements may operate in parallel. Examples of current differential elements incorporating harmonic blocking and harmonic restraint in parallel are described in United States Patent Application No.
  • one or more protective control signals 1924 Responsive to detecting a busbar fault within a particular protection zone ⁇ e.g., detecting that the operating current / O pis greater than both the scaled restraining current I RT and the pickup current threshold Ip ⁇ ), one or more protective control signals 1924 may be issued.
  • the protective control signals 1924 may be adapted to isolate the busbar fault and, as such, may be configured to trip circuit breakers coupled to the one or more conductors supplying current to the fault.
  • the circuit breakers may be selected according to the current topology information 1982 and/or protection zone information 1982.1.
  • the protective control signals 1924 may be transmitted to one or more IEDs communicatively coupled to the respective circuit breakers (not shown).
  • a protection zone may include plural IEDs. Accordingly, the STP 1996 may direct the operation of multiple IEDs by receiving topology and current information from the IEDs and directing the protective actions taken by the IEDs (according to the current topology information 1982).
  • Figure 20 is a functional block diagram of one embodiment of a current differential element, such as the current differential element 1906 of Figure 19.
  • the differential element 2006 may receive an operating current l O p input 2010 and a restraining current I RT input 2012.
  • the lop input 2010 may be calculated according to Equation 2.2 and the I RT input 2012 may be calculated according to Equation 2.1.
  • an alternative technique for calculating the operating current l O p and/or the restraining current I RT may be used.
  • the inputs 2010 and 2012 flow to the differential element characteristic 2002, which may scale the restraining current l RT by one of the slope characteristics SLP1 2026 or SLP22028.
  • the selection of the slope characteristic 2026 or 2028 may be based upon an operating mode of the current differential element 2006.
  • the differential element 2006 may be configured to operate in a normal mode and a high-security mode.
  • the operating mode may be determined by an external fault signal 2003 produced by an external fault detection logic module 2004.
  • the current differential element 2006 may be configured to operate in the high-security mode.
  • the differential characteristic 2002 may scale the restraining current I RT input 2012 by the less-sensitive, high-security slope constant SLP2 2028; otherwise, the slope constant SLP1 2026 may be used.
  • an external fault detection logic module 2004 is described below in conjunction with Figure 21.
  • the characteristic 2002 asserts an FDIF output 2018 if the operating current / OP input 2010 is greater than the scaled restraining current.
  • An output 870 2016 is asserted if the operating current / OP input 2010 is greater than the pickup current threshold I PU .
  • the outputs 2016 and 2018 flow to an AND gate 2006, which asserts the signal P87R 2022 if the operating current l O p input 2010 is greater than both the scaled restraining current and the pickup current threshold l P ⁇ .
  • the signal P87R 2022 may be used as a bus fault detection signal.
  • the P87R 2022 signal flows to an adaptive security timer 2008, which may assert a bus fault detection signal 87R 2024 if the P87R 2022 signal is maintained in an asserted state for a pre-determined time period and/or for a pre-determined number of measurements. If the P87R signal 2022 is asserted for the required time period, the bus fault detection signal 87R 2024 may be asserted.
  • the adaptive security timer 2008 may be capable of operating in a normal mode and in a high-security mode in accordance with the external fault signal 2003. When the external fault signal 2003 is asserted, the adaptive security timer 2008 may operate in the high-security mode. Operation in the high-security mode may cause the adaptive security timer 2008 to increase the pre-determined time period (or predetermined number of measurements).
  • the 87R 2024 output may indicate detection of a bus fault within a particular protection zone.
  • the signal 2024 may be used to generate one or more protective control signals ⁇ e.g., signals 1924 of Figure 19). Accordingly, the signal 2024 may flow to a local PMCU (such as the local PMCU 480 described in conjunction with Figure 4) or another protective device.
  • the bus fault detection signal 2024 may cause one or more protective control signals to be issued, which, in turn, may cause one or more protective actions to take place.
  • one or more of the protective control signals (not shown) may be issued to IEDs coupled to the circuit breakers that control the conductors that are supplying current to the fault.
  • a protective zone may include multiple IEDs.
  • the protective control signal(s) issued as a result of assertion of the 87R 2024 signal may be transmitted to multiple IEDs (in accordance with the configuration of the protective zone and/or the current topology information).
  • the current differential element 2006 and/or the STP 1996 of Figure 19 may be implemented within and/or in conjunction with a local IED and/or PMCU (not shown).
  • the signal 2024 may cause the local device to trip the appropriate circuit breakers to clear the fault.
  • Figure 21 is a functional block diagram of one embodiment of an external fault detection logic module 2104, such as the module 2004 of Figure 20.
  • the external fault detection logic module 2104 may detect an external fault condition based upon changes in the restraining current I RT and the operating current l O p with respect to time. For example, if there is a significant change in the restraining current I RT and a small (less than a pre-determined threshold) change in operating current l O p , an external fault condition may be detected.
  • a comparator 21 14 compares a restraining current change ⁇ I RT input 2102 to a restraining current change threshold value ⁇ I RT _THRESHOLD 2101.
  • a DRT output 2128 of the comparator 21 14 is asserted if the restraining current change ⁇ I RT input 2102 is greater than the threshold 2101.
  • a comparator 2116 compares an operating current change ⁇ I O p input 2106 to an operating current change threshold value ⁇ I O P_THRESHOLD 2105.
  • a DOP output 2130 of the comparator 2116 is asserted if the operating current change ⁇ I O p input 2106 is greater than the threshold 2105.
  • the restraining current change ⁇ I RT input 2102 and the operating current change ⁇ I O p input 2106 may be generated by calculating respective time derivatives of the restraining current I RT and the operating current lop ⁇ e.g., using a numerical technique).
  • the derivatives may be discrete if the restraining current I RT and/or the operating current lop are based on measurement samples ⁇ e.g., comprise discrete measurements made at a particular sampling rate) and/or may be continuous if the restraining current I RT and/or the operating current l O p are based on continuous current values.
  • the DRT signal 2128 flows to an input of an AND gate 2120, and the DOP signal 2130 flows to an inverted input of the AND gate 2120. Accordingly, the output
  • the output 2121 of the AND gate 2120 may assert if the DRT signal 2128 is asserted and the DOP 2130 signal is deasserted ⁇ e.g., if the restraining current change ⁇ I RT input 2102 is greater than the threshold 2101 and the operating current change ⁇ I O p input 2106 is less than the threshold 2105).
  • the output 2121 flows to the external fault condition block 2122, which may comprise a security timer or other device configured to assert the output 2123 if the input 2121 is asserted for a pre-determined time period and/or pre-determined number of measurements.
  • the output 2123 of the external fault condition block is the output 2123 of the external fault condition block
  • the hold timer 2124 may be configured to keep the external fault output 2103 asserted for a pre-determined time period and/or predetermined number of cycles ⁇ e.g., 60 measurements) after the input 2123 is deasserted.
  • FIG 22 is a block diagram of one embodiment of a system 2200 for distributing time information to various IEDs, such as the Figure 18 IEDs discussed above.
  • a master clock 2202 provides time information to various slave clocks 2204 and 2206.
  • the slave clocks 2204 and 2206 may be time- coordinated with the master clock 2202.
  • the slave clocks 2204 and 2206 may be configured to provide a common time (originating from the master clock 2202) to the IEDs 2208 and 2210 (although only two IEDs 2208 and 2210 are depicted, the system 2200 could include any number of IEDs).
  • the IEDs 2208 and 2210 may operate on a common time ⁇ e.g., may be synchronized).
  • timestamp information applied by the IEDs 2208 and 2210 ⁇ e.g., to measurement data obtained thereby) may be capable of being time-aligned to one another.
  • the master clock 2202 may be any clock or clock signal available to the slave clocks 2204 and 2206.
  • the master clock 2202 may provide a common time to the slave clocks 2204 and 2206 ⁇ e.g., act as an absolute time or time reference to the slave clocks 2204 and 2206).
  • the master clock 2202 may be implemented as an IRIG time signal from a GPS system, a WWB signal, a WWVB signal, an atomic clock, or any other time source.
  • the slave clocks 2204 and 2206 may be clocks available within a particular building, substation, or the like. Further, the slave clocks may be within the IEDs 2208 and/or 2210. The IEDs 2208 and 2210 may apply timestamp information to data collected from a power system (not shown). As discussed above, the measurement information may include phase current measurements, phase voltage measurements, topology measurements, and the like. The timestamp information may be supplied by the respective slave clocks sources 2204 and/or 2206 communicatively coupled to the IEDs 2208 and 2210. The time-stamped data may be communicated to a data processor 2290 via a network, such as a WAN or a LAN 2212.
  • a network such as a WAN or a LAN 2212.
  • FIG. 23 is a block diagram 2300 of one embodiment of a data processor 2302 capable of sending commands to one or more IEDs (such as IEDs 2304, 2306, 2308).
  • the data processor 2302 may include a plurality of communications channels for receiving power system data from a plurality of power system devices or elements (such as IEDs 2304, 2306, 2308) associated with an SEPSN. As discussed above, the power system data may be communicated to the data processor 2302 according to any of a number of different protocols.
  • the data processor 2302 may include a time alignment module 2310 configured to correlate and time align incoming power system data ⁇ e.g., measurements, topology information, and the like).
  • the time-aligned power system data is provided to the run-time system 2320.
  • the run-time system 2320 may include one or more modules, including a power calculation (PWRC) module 2322, a phase angle difference monitor (PADM) 2324, a modal analysis (MA) module 2326, a substation state and topology processor (SSTP) 2328, and a command module 2314.
  • PWRC power calculation
  • PADM phase angle difference monitor
  • MA modal analysis
  • SSTP substation state and topology processor
  • the run-time system 2320 may further include a user-programmable tasks module 2330 that may operate according to the IEC 61 131 -3 specification.
  • a bus differential protection scheme as described herein may be provided by the run-time system 2320.
  • the bus differential protection scheme may be provided by the user-programmable tasks module 2330. Responsive to the bus differential protection scheme detecting a fault on a particular bus, the data processor 2320 and/or user-programmable tasks module 2330 may be configured to cause one or more protective actions to take place. For example, a command may be sent to a particular IED (2304, 2306, and/or 2308) to trip a breaker, trip one or more buses, assert one or more alarms, or the like.
  • the data processor 2302 may issue commands using the command module 2314, which may be configured to communicate with the IEDs 2304, 2306, and/or 2308 according to various protocols and/or messaging formats.
  • the data processor 2302 may transmit a message to the command module 2314, which may send a corresponding message to the recipient IED(s) 2304, 2306, and/or 2308 in a particular protocol and/or message format, such as fast operate, IEC 61850 GOOSE, Mirrored Bits® communication, or the like (Mirrored Bits® is a registered trademark of Schweitzer Engineering Laboratories, Inc. of Pullman, WA).
  • the data processor 2302 may be capable of receiving measurements and other data from the SEPSN (from various IEDs or other devices), providing a bus differential protection scheme, and sending commands to take one or more protective actions to one or more IEDs 2304, 2306, and/or 2308 distributed within the SEPSN based on the results of the bus differential protection scheme in a time-sensitive manner.
  • Figure 24 is a flow diagram of one embodiment of a method 2400 for providing distributed bus differential protection.
  • the method may start and be initialized, which may comprise loading one or more computer-readable instructions from a computer-readable storage medium, accessing one or more communications interfaces, accessing one or more measurement devices ⁇ e.g., current transformers, IEDs, PMUs, or the like), and so on.
  • the instructions comprising the method 2400 may be embodied as one or more discrete software modules on a computer-readable storage medium. Certain of the instructions and/or steps of the method 2400 may be implemented as hardware components, such as digital logic components, analog circuits, or the like. Moreover, one or more of the instructions may be adapted to interface with particular hardware components, such as communications interfaces, measurement devices, or the like.
  • time-stamped measurement data may be received from one or more IEDs.
  • the time-stamped measurement data may be embodied as synchrophasor measurements according to IEEE C37.118.
  • the measurements may be transmitted to the method 2400 over a network by one or more IEDs located within a power system (e.g., the power system 1800 of Figure 18).
  • the IEDs may be positioned at a significant distance from one another and/or the computing device implementing the method 2400 ⁇ e.g., a state and topology processor or the like).
  • the IEDs may be electrically and/or communicatively coupled to the electrical power system via one or more current transformers (or other devices) to obtain the measurement data therefrom.
  • Receiving the measurement data at step 2420 may comprise time-aligning the measurement data using the timestamp information associated therewith, accessing correction factors associated with the measurement data (according to a topology of the power system and/or properties of the measurement device(s) used to acquire the measurements), applying the correction factors to the data, and the like as described above ⁇ e.g., in conjunction with Figure 10).
  • the current measurements may be refined as described above.
  • the measurement data may comprise time-stamped current measurements obtained at various branches within the electrical power system.
  • the measurement data may further comprise dynamic topology data, such as the state of one or more switches, circuit breakers, branches, and the like.
  • a current topology may be determined. As described above ⁇ e.g., in conjunction with Figures 7A, 8A, 9, and 10), the current topology may be determined using the dynamic topology data received at step 2420, as well as static topology data associated with the electrical power system.
  • the static topology data may be stored in a computer-readable storage medium and may describe the topology of the electrical power system.
  • the dynamic topology data (received at step 2420) may indicate the state of various components of the power system ⁇ e.g., the state of circuit breakers, switches, and other components within the power system that may determine a dynamic topology of the bus arrangement).
  • the current topology may be used to identify one or more bus differential protection zones.
  • a protection zone may include one or more buses. Buses that are merged (as indicated by the dynamic topology information received at step 2420) may be included in the same protection zone.
  • a protection zone may comprise and/or be defined by a list of current branches within the protection zone.
  • the method 2400 may iterate over each of the protection zones identified at step 2440. The iteration may allow the method 2400 to implement a current differential protection function within each protection zone. Although this is depicted in Figure 24 as a serial iteration over each of the protection zones, in other embodiments, the method 2400 could perform current differential protection for multiple protection zones in parallel ⁇ e.g., using multiple current differential elements operating in parallel). [00278] At step 2460, the method may implement a current differential protection function for a particular protection zone.
  • this may comprise evaluating a current differential operating condition for the protection zone, which may comprise calculating a restraining current Wand an operating current / OP for the protection zone ⁇ e.g., according to the current topology determined at step 2430 and the protection zone determination of step 2440).
  • the protection zone may be defined as a set of branches within the protection zone ⁇ e.g., that supply current to/from the busbars in the protection zone). Accordingly, at step 2460, Equations 2.1 and 2.2 may be applied to the current measurements (received and processed at step 2420) corresponding to the branches of the protection zone identified at step 2440 to calculate the restraining current Wand the operating current l O p.
  • the current differential protection of step 2460 may comprise selecting an operating mode, which may comprise selecting one of a plurality of slope characteristics and/or time thresholds.
  • the current differential element 1996 discussed above in conjunction with Figure 19 may be capable of operating in a plurality of different operational modes, which may include an operational mode for normal operation, and a less-sensitive, high-security operational mode used under certain circumstances ⁇ e.g., upon detection of an external fault).
  • step 2460 may comprise detecting an external fault ⁇ e.g., based upon the rate of change of the restraining and operating currents W and / OP as described above in conjunction with Figure 21 ). For instance, at step 2460, an external fault may be detected (and a high-security operational mode may be selected) if a change in the restraining current I RT exceeds a restraining current change threshold and a change in the operating current l O p does not exceed an operating current change threshold for a predetermined time period and/or a pre-determined number of measurements.
  • the current differential protection step 2460 may comprise scaling the restraining current l RT by a slope characteristic, which may be selected according to the operational mode determined above.
  • a first slope characteristic may be used, and, if an external fault is detected, a second, less-sensitive, high-security slope characteristic may be used.
  • a current differential operating condition of the particular bus differential protection zone may be evaluated.
  • the current differential operating condition may be evaluated by comparing the operating current / O pto the scaled restraining current I RT and a pickup current threshold l P ⁇ . If the operating condition is satisfied ⁇ e.g., if the operating current lop is greater than both values) a bus fault may be detected and the flow may continue at step 2470; otherwise, the flow may continue to step 2480.
  • the detection of a bus fault may be supervised by a security timer.
  • step 2462 may include the evaluation of the security timer.
  • the security timer may indicate the time and/or the number of measurements that the operating condition has been satisfied ⁇ e.g., the time that the operating current l O p has been greater than the scaled restraining current Wand the pickup current threshold Ipu).
  • the security timer may be compared to a pre-determined time threshold, which may specify the time and/or number of measurements that the operating condition must be maintained before a bus fault is detected.
  • the time threshold may be adaptable according to conditions detected within the power system.
  • a first time threshold may be used under normal conditions, and a second, high-security time threshold may be used if an external fault is detected.
  • step 2462 is described as including a security timer evaluation step, in other embodiments, the security timer may be omitted ⁇ e.g., a bus fault may be detected as soon as the operating current exceeds the restraining current l RT an ⁇ the pickup current threshold
  • a bus fault signal for the particular protection zone may be asserted.
  • assertion of the bus fault signal may include generating and/or transmitting one or more protective control signals to one or more IEDs or other protective devices.
  • the protective control signals may be adapted according to the current topology determined at steps 2430 and 2440 and/or the protective components available in the power system ⁇ e.g., circuit breakers, switches, etc.).
  • the protective control signals may be transmitted to the IEDs via a network using a communications interface.
  • the protective control signals may be used to directly configure one or more protective devices.
  • the method 2400 may determine whether additional protection zones remain to be processed. If so, the flow may continue to step 2450 where the next protection zone may be processed; otherwise, the flow may terminate at step 2490. [00286]
  • Embodiments may include various steps, which may be embodied in machine-executable instructions to be executed by a general-purpose or special- purpose computer (or other electronic device). Alternatively, the steps may be performed by hardware components that include specific logic for performing the steps, or by a combination of hardware, software, and/or firmware. [00289] Embodiments may also be provided as a computer program product including a computer-readable medium having stored instructions thereon that may be used to program a computer (or other electronic device) to perform processes described herein.
  • the computer-readable medium may include, but is not limited to: hard drives, floppy diskettes, optical disks, CD-ROMs, DVD-ROMs, ROMs, RAMs, EPROMs, EEPROMs, magnetic or optical cards, solid-state memory devices, or other types of media/machine-readable medium suitable for storing electronic instructions.
  • a software module or component may include any type of computer instruction or computer executable code located within a memory device and/or computer-readable storage medium.
  • a software module may, for instance, comprise one or more physical or logical blocks of computer instructions, which may be organized as a routine, program, object, component, data structure, etc., that perform one or more tasks or implements particular abstract data types.
  • a particular software module may comprise disparate instructions stored in different locations of a memory device, which together implement the described functionality of the module.
  • a module may comprise a single instruction or many instructions, and may be distributed over several different code segments, among different programs, and across several memory devices.
  • Some embodiments may be practiced in a distributed computing environment where tasks are performed by a remote processing device linked through a communications network.
  • software modules may be located in local and/or remote memory storage devices.
  • data being tied or rendered together in a database record may be resident in the same memory device, or across several memory devices, and may be linked together in fields of a record in a database across a network.

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  • Engineering & Computer Science (AREA)
  • Power Engineering (AREA)
  • Remote Monitoring And Control Of Power-Distribution Networks (AREA)

Abstract

L'invention concerne un système de protection de barre omnibus distribuée utilisant des données horodatées recueillies à partir de dispositifs de mesure dans un agencement de jeu de barres de système d'alimentation électrique par des dispositifs électroniques intelligents (IED) respectifs. Les IED peuvent obtenir les informations d'horodatage à partir d'une horloge ou d'une autre source de synchronisation, qui peut être synchronisée avec une source de synchronisation commune et/ou le temps absolu. Les données de mesure horodatées peuvent être utilisées par un dispositif de protection pour surveiller et/ou protéger le système d'alimentation électrique. Le dispositif de protection peut comprendre un processeur de vecteur en temps réel qui peut effectuer un réglage de temporisation des données horodatées, déterminer une ou plusieurs zones de protection différentielle de la commutation et mettre en œuvre une fonction de protection différentielle dans chacune des zones de protection. Un ou plusieurs signaux de commande protecteurs peuvent être transmis aux IED pour déclencher les coupe-circuits correspondants et supprimer le défaut bus.
PCT/US2009/057533 2008-09-19 2009-09-18 Protection différentielle de la commutation distribuée utilisant des données horodatées WO2010033839A1 (fr)

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MX2011002467A MX2011002467A (es) 2008-09-19 2009-09-18 Proteccion diferencial de bus distribuido usando datos marcados en tiempo.
CA2736044A CA2736044C (fr) 2008-09-19 2009-09-18 Protection differentielle de la commutation distribuee utilisant des donnees horodatees

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US61/098,267 2008-09-19

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CN107147086A (zh) * 2017-04-19 2017-09-08 南京南瑞继保电气有限公司 通过母线主接线图可视化配置形成母差构成的方法
CN107147086B (zh) * 2017-04-19 2019-02-22 南京南瑞继保电气有限公司 通过母线主接线图可视化配置形成母差构成的方法
CN111817752A (zh) * 2020-07-16 2020-10-23 国网河南省电力公司周口供电公司 载波至少两种通信信号的编码方法
CN111817752B (zh) * 2020-07-16 2021-09-28 国网河南省电力公司周口供电公司 使载波承载至少两种通信信号的编码方法
CN114400632A (zh) * 2022-01-07 2022-04-26 许继电气股份有限公司 一种基于无线通道的纵联保护数据传输方法
CN114400632B (zh) * 2022-01-07 2023-12-12 许继电气股份有限公司 一种基于无线通道的纵联保护数据传输方法

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