DETAILED ACTION
Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA . The rejections from the Office Action of 5/14/2025 are hereby withdrawn. New grounds for rejection are presented below.
A request for continued examination under 37 CFR 1.114, including the fee set forth in 37 CFR 1.17(e), was filed in this application after final rejection. Since this application is eligible for continued examination under 37 CFR 1.114, and the fee set forth in 37 CFR 1.17(e) has been timely paid, the finality of the previous Office action has been withdrawn pursuant to 37 CFR 1.114. Applicant's submission filed on 10/2/2025 has been entered.
Claim Rejections - 35 USC § 101
35 U.S.C. 101 reads as follows:
Whoever invents or discovers any new and useful process, machine, manufacture, or composition of matter, or any new and useful improvement thereof, may obtain a patent therefor, subject to the conditions and requirements of this title.
Claims 1-10 and 12-20 are rejected under 35 U.S.C. 101 because the claimed invention is directed to an abstract idea without significantly more. The claim(s) recite(s) the abstract idea of a mathematical algorithm and/or mental activity algorithm for performing anomaly detection in a multiphase power distribution network.
This judicial exception is not integrated into a practical application because the performance of the underlying power distribution network is not improved in any manner through use of the algorithm.
The claim(s) does/do not include additional elements that are sufficient to amount to significantly more than the judicial exception because the recitations regarding the configuration of the power distribution network and its corresponding power meters are well-understood, routine, and convention features of such a network [See the discussion of Taft (US 20150002186 A1), below]. The use of the power meters would have been necessary in gathering the data necessary for performing the algorithm. The recitation of general-purpose computer elements in performing the algorithm does not serve to distinguish the claims from the recitation of the abstract idea itself (see Alice Corp. v. CLS Bank International, 573 U.S. 208 (2014)). The recitation of the electrical meters comprising a circuit board and input pins amounts to the recitation of a well-understood, routine, and conventional sensing arrangement [See the discussion of Cook (US 20140223218 A1), below]. The transmission of the algorithm results amounts to mere extra-solution activity with regards to implementing the algorithm in conjunction with a distributed monitoring system.
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
Claim(s) 1-10 and 12-20 is/are rejected under 35 U.S.C. 102(a)(1) as being anticipated by Taft (US 20150002186 A1) and Cook (US 20140223218 A1).
Regarding Claim 1, Taft discloses a system for multiphase meter anomaly detection [Abstract – “An outage intelligence application receives event messages indicative of occurrences associated with various devices within a power grid. The outage intelligence application determines a state of the various devices based on the event messages. Based on the event messages, the outage intelligence application can determine can determine and confirm an outage condition associate with a particular device. A fault intelligence application receives synchrophasor data for each phase in a multi-phase power grid. The synchrophasor includes phasor magnitude and phasor angle information for each phased. Based on the synchrophasor data, the fault intelligence application determines the presence of a fault involving one or more of the phases and identifies a particular fault type.”] comprising:
one or more electrical meters [Paragraph [0080] – “The INDE DEVICE 188 group may comprise any variety of devices within the smart grid, including various sensors within the smart grid, such as various distribution grid devices 189 (e.g., line sensors on the power lines), meters 163 at the customer premises, etc. The INDE DEVICE 188 group may comprise a device added to the grid with particular functionality (such as a smart Remote Terminal Unit (RTU) that includes dedicated programming), or may comprise an existing device within the grid with added functionality (such as an existing open architecture pole top RTU that is already in place in the grid that may be programmed to create a smart line sensor or smart grid device). The INDE DEVICE 188 may further include one or more processors and one or more memory devices.”Paragraph [0089] – “As another example, a line sensor, which includes additional intelligence using processing and/or memory capability, may produce grid state data in a portion of the grid (such as a feeder circuit).”Paragraph [0174] – “FIG. 22 is an operational flow diagram of the outage intelligence application configured to determine faults recognized by one or more fault circuit indicators (FCIs). A particular FCI may be located within the power grid.”Paragraph [0205] – “Synchrophasor data for each phase within the power grid may be obtained from a phasor measurement unit (PMU) data collection head located in the INDE SUBSTATION 180 group or may be located centrally in a central authority to the power grid. The PMU measures and may provide phase information including the synchrophasor data, such as phasor magnitude and phasor angle data, for each phase, A, B, and C, may be generated and analyzed to determine if a fault is present and determine the type of fault.”], and
one or more power lines [See Paragraph [0005], particularly – “One or more feeder circuits may emanate from the distribution substations. For example, four to tens of feeder circuits may emanate from the distribution substation. The feeder circuit is a 3-phase circuit comprising 4 wires (three wires for each of the 3 phases and one wire for neutral).”];
wherein the one or more power lines are configured to transmit electrical power to the one or more electrical meters [See Paragraph [0005], particularly – “One or more feeder circuits may emanate from the distribution substations. For example, four to tens of feeder circuits may emanate from the distribution substation. The feeder circuit is a 3-phase circuit comprising 4 wires (three wires for each of the 3 phases and one wire for neutral).”Paragraph [0089] – “As another example, a line sensor, which includes additional intelligence using processing and/or memory capability, may produce grid state data in a portion of the grid (such as a feeder circuit).”];
wherein the one or more electrical meters are configured to detect a presence of multiple phases within the electrical power [Paragraph [0205] – “Synchrophasor data for each phase within the power grid may be obtained from a phasor measurement unit (PMU) data collection head located in the INDE SUBSTATION 180 group or may be located centrally in a central authority to the power grid. The PMU measures and may provide phase information including the synchrophasor data, such as phasor magnitude and phasor angle data, for each phase, A, B, and C, may be generated and analyzed to determine if a fault is present and determine the type of fault.”];
wherein each of the one or more electrical meters comprise one or more meter computers comprising one or more meter processors and one or more meter non-transitory computer readable media, the one or more meter non-transitory computer readable media comprising instructions stored thereon [Paragraph [0080] – “The INDE DEVICE 188 group may comprise any variety of devices within the smart grid, including various sensors within the smart grid, such as various distribution grid devices 189 (e.g., line sensors on the power lines), meters 163 at the customer premises, etc. The INDE DEVICE 188 group may comprise a device added to the grid with particular functionality (such as a smart Remote Terminal Unit (RTU) that includes dedicated programming), or may comprise an existing device within the grid with added functionality (such as an existing open architecture pole top RTU that is already in place in the grid that may be programmed to create a smart line sensor or smart grid device). The INDE DEVICE 188 may further include one or more processors and one or more memory devices.”] that when executed cause the one or more meter computers to:
monitor, by the one or more meter processors, an active status and an inactive status of each of the phases through a discovery signal internal to the one or more electrical meters; generate, by the one or more meter processors, an anomaly signal associated with at least one phase of the multiple phases even if one or more other phases of the multiple phases are still energized; and send, by the one or more meter processors, an unsolicited abnormal condition message to a remote command center automatically when the anomaly signal is detected [Paragraph [0204] – “Each fault type may be identified based on a plurality of predetermined qualities regarding the phasor magnitudes and phasor angles of each phase, such as A, B, and C. In one example, the individual phasors (magnitude and angle) may be analyzed, as well as the inter-phasors, which may refer to the relative phasor values between the phasors, such as A-B, B-C, and A-C. As indicated in Table 5 below, the real-time phasor values and nominal phasor values of each phase may be used to determine fault occurrences and fault type.”See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”Paragraph [0209] – “At block 2626, the number of consecutive readings of the possible fault conditions may be compared to predetermined consecutive reading criteria. As shown in Table 5, possible fault conditions identified may be required to present for a number consecutive readings prior to determining that a particular fault type is present. If the number of consecutive readings is met at block 2626, a fault message may be generated by the fault intelligence application at block 2628, which may be transmitted to other devices in the power grid that may be affected by the fault or may be used to alert interested parties of the particular fault type. If the number of consecutive readings is not met, the operational flow diagram may return to the block 2600.”Paragraph [0008] – “According to one aspect of the disclosure, an outage management system for a power grid is disclosed. The outage management system may include an outage intelligence application executable on one or more processors configured to receive event messages from various devices and portions of the power grid.”].
Taft fails to disclose that each of the one or more electrical meters comprises a circuit board comprising a plurality of input pins; a first input pin of the plurality of input pins is configured to receive a first phase voltage; and a second input pin of the plurality of input pins is configured to receive a second phase voltage.
However, Cook discloses a power meter board [Paragraph [0009] – “FIG. 2 illustrates an exemplary power meter board.”] and an arrangement where a microcontroller uses separate input pins for detecting the voltage/current of separate phases of a 3-phase AC power distribution system [Paragraph [0038] – “Referring to FIG. 3, to determine the frequency of the signal for a phase of the power distribution system, a sense phase A 200 may be interconnected to phase A (or whatever phase is considered to be phase A) of the power distribution system, such as the voltage and/or the current. The sense phase A 200 signal may be processed to provide a series of rectangular pulses 210 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0039] – “Referring to FIG. 4, to determine the frequency of the signal a sense phase B 300 may be interconnected to phase B (or whatever phase is considered to be phase B) of the power distribution system, such as the voltage and/or the current. The sense phase A 300 signal may be processed to provide a series of rectangular pulses 310 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0040] – “Referring to FIG. 5, to determine the frequency of the signal a sense phase C 400 may be interconnected to phase B (or whatever phase is considered to be phase B) of the power distribution system, such as the voltage and/or the current. The sense phase A 400 signal may be processed to provide a series of rectangular pulses 410 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0013] – “FIG. 6 illustrates multiple signals to multiple pins of a microcontroller.”Paragraph [0041] – “Referring to FIG. 6, each of the rectangular signals 210, 310, and 410 may be provided to a microprocessor 500 (e.g., microcontroller, logic gates, FPGA, ASIC, etc.) for the power system to determine the frequency of the respective signals. In this configuration, each of the signals is continually available to the microprocessor for processing and thus avoiding the need to multiplex the signals to the microprocessor 500, and the limitations associated therewith.”].
It would have been obvious to use such a scheme in monitoring the 3-phase electrical power distribution system discovery signals of Taft [Paragraph [0204] – “Each fault type may be identified based on a plurality of predetermined qualities regarding the phasor magnitudes and phasor angles of each phase, such as A, B, and C. In one example, the individual phasors (magnitude and angle) may be analyzed, as well as the inter-phasors, which may refer to the relative phasor values between the phasors, such as A-B, B-C, and A-C. As indicated in Table 5 below, the real-time phasor values and nominal phasor values of each phase may be used to determine fault occurrences and fault type.”See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”] because Cook discloses this is an effective manner of monitoring the state of such a system.
Regarding Claim 2, Taft discloses that the system is configured to use an internal anomaly detection alert from the one or more electrical meters to generate the anomaly signal [Paragraph [0174] – “FIG. 22 is an operational flow diagram of the outage intelligence application configured to determine faults recognized by one or more fault circuit indicators (FCIs). A particular FCI may be located within the power grid.”Paragraph [0175] – “If the outage intelligence application receives a "local FCI fault" message 2208, the outage intelligence application may determine that a fault has occurred at the particular FCI. Upon receipt of the particular FCI fault message 2208, the outage intelligence application may determine that the particular FCI is in a fault current detect state at block 2210. While transitioning to determining that the particular FCI is in the fault current detect state, the outage intelligence application may generate a fault message 2211 to various applications such as the fault intelligence application and to upstream FCIs.”].
Regarding Claim 3, Taft discloses that the system is able to detect a wire down condition comprising a deenergized power line in a 3 wire electrical distribution system [Paragraph [0125] – “Specifically, faults may be detected using the fault intelligent processes. A fault is typically a short circuit caused when utility equipment fails or alternate path for current flow is created, for example, a downed power line.”Paragraph [0204] – “Each fault type may be identified based on a plurality of predetermined qualities regarding the phasor magnitudes and phasor angles of each phase, such as A, B, and C. In one example, the individual phasors (magnitude and angle) may be analyzed, as well as the inter-phasors, which may refer to the relative phasor values between the phasors, such as A-B, B-C, and A-C. As indicated in Table 5 below, the real-time phasor values and nominal phasor values of each phase may be used to determine fault occurrences and fault type.”See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”].
Regarding Claim 4, Taft discloses that the 3 wire electrical distribution system comprises 3 phases and no neutral wire [Paragraph [0204] – “Each fault type may be identified based on a plurality of predetermined qualities regarding the phasor magnitudes and phasor angles of each phase, such as A, B, and C. In one example, the individual phasors (magnitude and angle) may be analyzed, as well as the inter-phasors, which may refer to the relative phasor values between the phasors, such as A-B, B-C, and A-C. As indicated in Table 5 below, the real-time phasor values and nominal phasor values of each phase may be used to determine fault occurrences and fault type.”See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”].
Regarding Claim 5, Taft discloses that the system is able to detect a wire down condition comprising a deenergized power line in a 4 wire distribution system [Paragraph [0005] – “The feeder circuit is a 3-phase circuit comprising 4 wires (three wires for each of the 3 phases and one wire for neutral).”See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”].
Regarding Claim 6, Taft discloses that the 4 wire distribution system comprises 3 phases and a neutral wire [Paragraph [0005] – “The feeder circuit is a 3-phase circuit comprising 4 wires (three wires for each of the 3 phases and one wire for neutral).”].
Regarding Claim 7, Taft discloses that the one or more electrical meters comprises one or more smart meters [Paragraph [0080] – “The INDE DEVICE 188 group may comprise any variety of devices within the smart grid, including various sensors within the smart grid, such as various distribution grid devices 189 (e.g., line sensors on the power lines), meters 163 at the customer premises, etc. The INDE DEVICE 188 group may comprise a device added to the grid with particular functionality (such as a smart Remote Terminal Unit (RTU) that includes dedicated programming), or may comprise an existing device within the grid with added functionality (such as an existing open architecture pole top RTU that is already in place in the grid that may be programmed to create a smart line sensor or smart grid device). The INDE DEVICE 188 may further include one or more processors and one or more memory devices.”]; and
that the system is configured to use the one or more smart meters to detect a location of a broken electrical utility component on an electrical distribution circuit [Paragraph [0008] – “The outage intelligence application may notify a central power authority of an outage occurrence enabling location and correction of the outage.”Paragraph [0127] – “The fault intelligence may also determine fault location. Fault location in the distribution system may be a difficult task due to its high complexity and difficulty caused by unique characteristics of the distribution system such as unbalanced loading, three-, two-, and single-phase laterals, lack of sensors/measurements, different types of faults, different causes of short circuits, varying loading conditions, long feeders with multiple laterals and network configurations that are not documented. This process enables the use a number of techniques to isolate the location of the fault with as much accuracy as the technology allows.”].
Regarding Claim 8, Taft discloses that the electrical distribution circuit includes one or more electrical utility components located external to the one or more smart meter’s internal components [Paragraph [0005] – “One or more feeder circuits may emanate from the distribution substations. For example, four to tens of feeder circuits may emanate from the distribution substation.”].
Regarding Claim 9, Taft discloses that each of the one or more electrical meters are a three phase electrical meter [Paragraph [0204] – “Each fault type may be identified based on a plurality of predetermined qualities regarding the phasor magnitudes and phasor angles of each phase, such as A, B, and C. In one example, the individual phasors (magnitude and angle) may be analyzed, as well as the inter-phasors, which may refer to the relative phasor values between the phasors, such as A-B, B-C, and A-C. As indicated in Table 5 below, the real-time phasor values and nominal phasor values of each phase may be used to determine fault occurrences and fault type.”]; and
that the system is configured to use discovery signals from one or more electrical meters to determine if one phase of three phases has lost voltage [See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”].
Regarding Claim 10, Taft discloses that the instructions cause the one or more meter computers to send, by one or more meter processors, unsolicited messages when abnormal conditions are detected [Paragraph [0174] – “The outage intelligence application may receive event messages from a monitoring device included in the FCI to determine that the FCI is in a normal state at block 2200. While determining that the particular FCI is in a normal state, the outage intelligence application may process event messages from the particular FCI. Upon receipt of a "downstream FCI faulted" message 2202, the outage intelligence application may determine that the particular FCI is in an FCI failure state at block 2204. While determining that the particular FCI is in the FCI failure state at block 2204, the outage intelligence application may suspend message processing from the particular FCI.”].
Regarding Claim 12, Taft discloses that the discovery signal is used to detect partial out circuits on a 3 wire distribution circuit [Paragraph [0204] – “Each fault type may be identified based on a plurality of predetermined qualities regarding the phasor magnitudes and phasor angles of each phase, such as A, B, and C. In one example, the individual phasors (magnitude and angle) may be analyzed, as well as the inter-phasors, which may refer to the relative phasor values between the phasors, such as A-B, B-C, and A-C. As indicated in Table 5 below, the real-time phasor values and nominal phasor values of each phase may be used to determine fault occurrences and fault type.”See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”].
Regarding Claim 13, Taft discloses that the distribution network includes 4 wire distribution circuits [Paragraph [0005] – “The feeder circuit is a 3-phase circuit comprising 4 wires (three wires for each of the 3 phases and one wire for neutral).”], but fails to explicitly disclose that the discovery signal is used to detect partial out circuits on 4 wire distribution circuits.
However, it would have been obvious to apply Taft’s teaching of fault analysis of a 3-phase circuit [Paragraph [0204] – “Each fault type may be identified based on a plurality of predetermined qualities regarding the phasor magnitudes and phasor angles of each phase, such as A, B, and C. In one example, the individual phasors (magnitude and angle) may be analyzed, as well as the inter-phasors, which may refer to the relative phasor values between the phasors, such as A-B, B-C, and A-C. As indicated in Table 5 below, the real-time phasor values and nominal phasor values of each phase may be used to determine fault occurrences and fault type.”See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”] to such a 4 wire circuit because such a circuit is also a 3-phase circuit [Paragraph [0005] – “The feeder circuit is a 3-phase circuit comprising 4 wires (three wires for each of the 3 phases and one wire for neutral).”]. Doing so would have provided the advantage of providing the capability for monitoring for 3-phase faults in the 4 wire circuit.
Regarding Claim 14, Cook discloses that at least one of the plurality of input pins is configured to detect a voltage fluctuation and/or voltage outages occurring in one or more input phases [Paragraph [0038] – “Referring to FIG. 3, to determine the frequency of the signal for a phase of the power distribution system, a sense phase A 200 may be interconnected to phase A (or whatever phase is considered to be phase A) of the power distribution system, such as the voltage and/or the current. The sense phase A 200 signal may be processed to provide a series of rectangular pulses 210 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0039] – “Referring to FIG. 4, to determine the frequency of the signal a sense phase B 300 may be interconnected to phase B (or whatever phase is considered to be phase B) of the power distribution system, such as the voltage and/or the current. The sense phase A 300 signal may be processed to provide a series of rectangular pulses 310 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0040] – “Referring to FIG. 5, to determine the frequency of the signal a sense phase C 400 may be interconnected to phase B (or whatever phase is considered to be phase B) of the power distribution system, such as the voltage and/or the current. The sense phase A 400 signal may be processed to provide a series of rectangular pulses 410 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0013] – “FIG. 6 illustrates multiple signals to multiple pins of a microcontroller.”Paragraph [0041] – “Referring to FIG. 6, each of the rectangular signals 210, 310, and 410 may be provided to a microprocessor 500 (e.g., microcontroller, logic gates, FPGA, ASIC, etc.) for the power system to determine the frequency of the respective signals. In this configuration, each of the signals is continually available to the microprocessor for processing and thus avoiding the need to multiplex the signals to the microprocessor 500, and the limitations associated therewith.”].
Regarding Claim 15, the combination would disclose that the one or more meter computers [Paragraph [0013] of Cook – “FIG. 6 illustrates multiple signals to multiple pins of a microcontroller.”] are configured to identify an abnormal power condition [Paragraph [0204] of Taft – “Each fault type may be identified based on a plurality of predetermined qualities regarding the phasor magnitudes and phasor angles of each phase, such as A, B, and C. In one example, the individual phasors (magnitude and angle) may be analyzed, as well as the inter-phasors, which may refer to the relative phasor values between the phasors, such as A-B, B-C, and A-C. As indicated in Table 5 below, the real-time phasor values and nominal phasor values of each phase may be used to determine fault occurrences and fault type.”See item 002 in Table 5 of Taft – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”] using a signal from at least one of the plurality of input pins [Paragraph [0038] of Cook – “Referring to FIG. 3, to determine the frequency of the signal for a phase of the power distribution system, a sense phase A 200 may be interconnected to phase A (or whatever phase is considered to be phase A) of the power distribution system, such as the voltage and/or the current. The sense phase A 200 signal may be processed to provide a series of rectangular pulses 210 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0039] of Cook – “Referring to FIG. 4, to determine the frequency of the signal a sense phase B 300 may be interconnected to phase B (or whatever phase is considered to be phase B) of the power distribution system, such as the voltage and/or the current. The sense phase A 300 signal may be processed to provide a series of rectangular pulses 310 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0040] of Cook – “Referring to FIG. 5, to determine the frequency of the signal a sense phase C 400 may be interconnected to phase B (or whatever phase is considered to be phase B) of the power distribution system, such as the voltage and/or the current. The sense phase A 400 signal may be processed to provide a series of rectangular pulses 410 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0013] of Cook – “FIG. 6 illustrates multiple signals to multiple pins of a microcontroller.”Paragraph [0041] of Cook – “Referring to FIG. 6, each of the rectangular signals 210, 310, and 410 may be provided to a microprocessor 500 (e.g., microcontroller, logic gates, FPGA, ASIC, etc.) for the power system to determine the frequency of the respective signals. In this configuration, each of the signals is continually available to the microprocessor for processing and thus avoiding the need to multiplex the signals to the microprocessor 500, and the limitations associated therewith.”].
Regarding Claim 16, Taft discloses that the system is configured to determine an approximate location of a power loss in a power line using the one or more electrical meters [Paragraph [0008] – “The outage intelligence application may notify a central power authority of an outage occurrence enabling location and correction of the outage.”Paragraph [0127] – “The fault intelligence may also determine fault location. Fault location in the distribution system may be a difficult task due to its high complexity and difficulty caused by unique characteristics of the distribution system such as unbalanced loading, three-, two-, and single-phase laterals, lack of sensors/measurements, different types of faults, different causes of short circuits, varying loading conditions, long feeders with multiple laterals and network configurations that are not documented. This process enables the use a number of techniques to isolate the location of the fault with as much accuracy as the technology allows.”].
Regarding Claim 17, Taft discloses that the one or more electrical meters comprise two or more electrical meters [Paragraph [0080] – “The INDE DEVICE 188 group may comprise any variety of devices within the smart grid, including various sensors within the smart grid, such as various distribution grid devices 189 (e.g., line sensors on the power lines), meters 163 at the customer premises, etc. The INDE DEVICE 188 group may comprise a device added to the grid with particular functionality (such as a smart Remote Terminal Unit (RTU) that includes dedicated programming), or may comprise an existing device within the grid with added functionality (such as an existing open architecture pole top RTU that is already in place in the grid that may be programmed to create a smart line sensor or smart grid device). The INDE DEVICE 188 may further include one or more processors and one or more memory devices.”Paragraph [0089] – “As another example, a line sensor, which includes additional intelligence using processing and/or memory capability, may produce grid state data in a portion of the grid (such as a feeder circuit).”Paragraph [0174] – “FIG. 22 is an operational flow diagram of the outage intelligence application configured to determine faults recognized by one or more fault circuit indicators (FCIs). A particular FCI may be located within the power grid.”Paragraph [0205] – “Synchrophasor data for each phase within the power grid may be obtained from a phasor measurement unit (PMU) data collection head located in the INDE SUBSTATION 180 group or may be located centrally in a central authority to the power grid. The PMU measures and may provide phase information including the synchrophasor data, such as phasor magnitude and phasor angle data, for each phase, A, B, and C, may be generated and analyzed to determine if a fault is present and determine the type of fault.”]; and
that the system is configured to determine an approximate location of a power loss in a power line using the two or more electrical meters [Paragraph [0008] – “The outage intelligence application may notify a central power authority of an outage occurrence enabling location and correction of the outage.”Paragraph [0127] – “The fault intelligence may also determine fault location. Fault location in the distribution system may be a difficult task due to its high complexity and difficulty caused by unique characteristics of the distribution system such as unbalanced loading, three-, two-, and single-phase laterals, lack of sensors/measurements, different types of faults, different causes of short circuits, varying loading conditions, long feeders with multiple laterals and network configurations that are not documented. This process enables the use a number of techniques to isolate the location of the fault with as much accuracy as the technology allows.”].
Regarding Claim 18, Taft discloses that the one or more power lines transmit the electrical power from an electrical power source upstream through one or more electrical components located at various locations [Paragraph [0005] – “One or more feeder circuits may emanate from the distribution substations. For example, four to tens of feeder circuits may emanate from the distribution substation.”] to a downstream electrical power sink [See item 002 in Table 5 – “Phase A: Single-line-to-ground (SLG) fault,” “Drop in one phasor magnitude; no inter-phasor angle changes”];
that at least a first electrical meter of the two or more electrical meters is located upstream of the approximate location [Paragraph [0089] – “As another example, a line sensor, which includes additional intelligence using processing and/or memory capability, may produce grid state data in a portion of the grid (such as a feeder circuit).”]; and
that at least a second electrical meter of the two or more electrical meters is located downstream of the approximate location [Paragraph [0080] – “The INDE DEVICE 188 group may comprise any variety of devices within the smart grid, including various sensors within the smart grid, such as various distribution grid devices 189 (e.g., line sensors on the power lines), meters 163 at the customer premises, etc. The INDE DEVICE 188 group may comprise a device added to the grid with particular functionality (such as a smart Remote Terminal Unit (RTU) that includes dedicated programming), or may comprise an existing device within the grid with added functionality (such as an existing open architecture pole top RTU that is already in place in the grid that may be programmed to create a smart line sensor or smart grid device). The INDE DEVICE 188 may further include one or more processors and one or more memory devices.”].
Regarding Claim 19, Taft discloses that the system is configured to not send the anomaly signal if a partial voltage event is logged for less than a predetermined period of time [Paragraph [0165] – “If a voltage check fail condition 2008 is present, the outage intelligence application may determine that the particular meter 163 to the outage confirmed state 2010. In transitioning from the determination of the normal service state at block 2000 to the outage confirmed state at block 2010, a "sustained outage event" message 2012 may be generated and transmitted.”Paragraph [0166] – “While determining the normal service state at block 2000, the outage intelligence application may receive a "power outage notification (PON)" message 2014 indicating that an outage may have occurred associated with the particular smart meter 163. The message may be received from the particular smart meter 163 or other devices upstream of the particular smart meter 163. Upon receipt of the PON message 2014, the outage intelligence application may determine that the particular smart meter 163 is in an "outage sensed" state at block 2016. In the outage sensed state, the outage intelligence application may suspend further action for a predetermined period of time. If the predetermined period of time elapses, a "timeout" condition 2018 may occur, resulting in the outage intelligence application determine that the particular meter is in the outage confirmed state at block 2010. During the transition to the outage confirmed state, the outage intelligence application may generate the sustained outage event message 2012.”Paragraph [0167] – “If the outage intelligence application receives a power restoration notification (PRN) message 2013 from the meter collection data engine prior to the elapsing of the predetermined period of time, the outage intelligence application may generate a "momentary outage event" message 2020 indicating that the sensed outage was only momentary and the particular smart meter 163 is currently functioning correctly with no outage condition indicated by the particular smart meter 163.”].
Regarding Claim 20, Taft discloses that the instructions are configured to send the anomaly signal to a command center [Paragraph [0162] – “The sustained outage event message 2012 may be transmitted to the outage management system 155, which may allow the location of the sustained outage event to be determined. In other examples, the sustained outage event message 2012 may be transmitted to the fault intelligence application (see FIG. 14) and to a log file. In alternative examples, the message 2012 may be routed to other systems and processes configured to process the message 2012.”Outage Management System 155 is a component of operations control center level 116, See Fig. 1C.]; and
that the command center comprises one or more command center computers comprising one or more command center processors and one or more command center non-transitory computer readable media, wherein the one or more command center computers are configured to monitor and/or control one or more components in an electrical distribution system [Paragraph [0008] – “According to one aspect of the disclosure, an outage management system for a power grid is disclosed. The outage management system may include an outage intelligence application executable on one or more processors configured to receive event messages from various devices and portions of the power grid.”Paragraph [0037] – “Further, certain aspects relate to the functional capabilities of the central management of the power grid. These functional capabilities may be grouped into two categories, operation and application. The operations services enable the utilities to monitor and manage the smart grid infrastructure (such as applications, network, servers, sensors, etc).”].
Response to Arguments
Applicant argues:
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748
792
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132
788
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Examiner’s Response:
The Examiner respectfully disagrees. The instant Claims are directed to the abstract idea of a mathematical algorithm and/or mental activity algorithm for performing anomaly detection in a multiphase power distribution network. See Electric Power Group, LLC v. Alstom S.A. (Fed. Cir. August 1, 2016).
Applicant argues:
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197
785
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Greyscale
Examiner’s Response:
The Examiner respectfully disagrees. The recitation of the electrical meters comprising a circuit board and input pins amounts to the recitation of a well-understood, routine, and conventional sensing arrangement [See the discussion of Cook (US 20140223218 A1), below]. The transmission of the algorithm results amounts to mere extra-solution activity with regards to implementing the algorithm in conjunction with a distributed monitoring system (i.e., conventional general-purpose client-server architecture).
Applicant argues:
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229
784
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…
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99
785
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Examiner’s Response:
The Examiner respectfully disagrees. Taft discloses a variety of meters, all of which measure and report signals indicating anomalies [Paragraph [0080] – “The INDE DEVICE 188 group may comprise any variety of devices within the smart grid, including various sensors within the smart grid, such as various distribution grid devices 189 (e.g., line sensors on the power lines), meters 163 at the customer premises, etc. The INDE DEVICE 188 group may comprise a device added to the grid with particular functionality (such as a smart Remote Terminal Unit (RTU) that includes dedicated programming), or may comprise an existing device within the grid with added functionality (such as an existing open architecture pole top RTU that is already in place in the grid that may be programmed to create a smart line sensor or smart grid device). The INDE DEVICE 188 may further include one or more processors and one or more memory devices.”Paragraph [0089] – “As another example, a line sensor, which includes additional intelligence using processing and/or memory capability, may produce grid state data in a portion of the grid (such as a feeder circuit).”Paragraph [0174] – “FIG. 22 is an operational flow diagram of the outage intelligence application configured to determine faults recognized by one or more fault circuit indicators (FCIs). A particular FCI may be located within the power grid.”Paragraph [0205] – “Synchrophasor data for each phase within the power grid may be obtained from a phasor measurement unit (PMU) data collection head located in the INDE SUBSTATION 180 group or may be located centrally in a central authority to the power grid. The PMU measures and may provide phase information including the synchrophasor data, such as phasor magnitude and phasor angle data, for each phase, A, B, and C, may be generated and analyzed to determine if a fault is present and determine the type of fault.”].
Applicant argues:
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339
786
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Examiner’s Response:
The Examiner respectfully disagrees. Cook discloses a power meter board [Paragraph [0009] – “FIG. 2 illustrates an exemplary power meter board.”] and an arrangement where a microcontroller uses separate input pins for detecting the voltage/current of separate phases of a 3-phase AC power distribution system [Paragraph [0038] – “Referring to FIG. 3, to determine the frequency of the signal for a phase of the power distribution system, a sense phase A 200 may be interconnected to phase A (or whatever phase is considered to be phase A) of the power distribution system, such as the voltage and/or the current. The sense phase A 200 signal may be processed to provide a series of rectangular pulses 210 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0039] – “Referring to FIG. 4, to determine the frequency of the signal a sense phase B 300 may be interconnected to phase B (or whatever phase is considered to be phase B) of the power distribution system, such as the voltage and/or the current. The sense phase A 300 signal may be processed to provide a series of rectangular pulses 310 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0040] – “Referring to FIG. 5, to determine the frequency of the signal a sense phase C 400 may be interconnected to phase B (or whatever phase is considered to be phase B) of the power distribution system, such as the voltage and/or the current. The sense phase A 400 signal may be processed to provide a series of rectangular pulses 410 corresponding to the input signal, such as the zero crossings of a sinusoidal signal.”Paragraph [0013] – “FIG. 6 illustrates multiple signals to multiple pins of a microcontroller.”Paragraph [0041] – “Referring to FIG. 6, each of the rectangular signals 210, 310, and 410 may be provided to a microprocessor 500 (e.g., microcontroller, logic gates, FPGA, ASIC, etc.) for the power system to determine the frequency of the respective signals. In this configuration, each of the signals is continually available to the microprocessor for processing and thus avoiding the need to multiplex the signals to the microprocessor 500, and the limitations associated therewith.”]. No substantial redesign or reconstruction would have been necessary to implement Cook’s power meter board in performing power metering.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure:
US 20220399718 A1 – DISTANCE-TO-FAULT POWER OUTAGE NOTIFICATION
US 20210055839 A1 – LOCATING A POWER LINE EVENT DOWNSTREAM FROM A POWER LINE BRANCH POINT
US 20200064392 A1 – ACCURATE FAULT LOCATION METHOD BASED ON LOCAL AND REMOTE VOLTAGES AND CURRENTS
US 20070211401 A1 – INTELLIGENT FAULT DETECTOR SYSTEM AND METHOD
US 20050040809 A1 – Power Line Property Measurement Devices And Power Line Fault Location Methods, Devices And Systems
US 6310412 B1 – Three-phase AC Distribution System And Method For Printed Circuit Boards
Any inquiry concerning this communication or earlier communications from the examiner should be directed to KYLE ROBERT QUIGLEY whose telephone number is (313)446-4879. The examiner can normally be reached 11AM-9PM EST.
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/KYLE R QUIGLEY/Primary Examiner, Art Unit 2857