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 .
Response to Arguments
Applicant’s arguments filed on 07/17/2026 with respect to claims 1 and 11 have been considered but are moot because the new ground of rejection does not rely on any reference applied in the prior rejection of record for any teaching or matter specifically challenged in the argument.
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.
Claims 1-4 and 11-14 are rejected under 35 U.S.C. 103 as being unpatentable over Manson (US Publication No. 20130018521) in view of Zhang et al (US Publication No. 20220316443).
Regarding claim 1, Manson discloses a method for tripping energy loads (i.e., such as method for tripping energy loads as shedding loads; for instance, power imbalances in an electrical power delivery system may be associated with a fall (or rise) in the frequency of the electrical power system fundamental voltage. Consistent with embodiments disclosed herein, when a threshold UF (or OF) level is crossed, loads may be disconnected (e.g., shed) from the electrical power system or generators or other active power producing components on the electric power system may be shed or run-back to rebalance the system. By shedding selective loads, shedding generators, or running back generators or other active power producing power system components and rebalancing the system, the negative effects of unbalanced system conditions may be mitigated; see for example fig. 1, para. [0017]) in an energy transmission system (i.e., such as energy transmission system 100; for instance, the electric power generation and delivery system 100 may include generation, transmission, distribution, and power consumption equipment. For example, the system 100 may include one or more generators 110-116 that, in some embodiments, may be operated by a utility provider for generation of electrical power for the system 100; see for example fig. 1, para. [0019]) based on Rate of Change of Frequency (RoCoF) (i.e., such as Rate of Change of Frequency (RoCoF) as in equation #3 Pacc = 2 * Hsystem * fRoCoF; for instance, determining an amount of load to shed, which may be expressed in terms of Pacc, may be calculated according to the following: J system = J generator _ 1 + J generator _ 2 + J generator _ n + J load _ 1 + J load _ 2 + J load _ n ( 1 ) H system = J system 2 MVA rating ( 2 ) Pacc = 2 H system fRoCoF ( 3 ). where J.sub.system is the rotating inertia of the system, J.sub.generator.sub.--.sub.n is the rotating inertia of a particular generator included in the system, J.sub.load.sub.--.sub.n is the rotating inertia of a particular load included in the system, H.sub.system is the total spinning inertia of the system, Pacc is the amount of additional mechanical power contribution required or amount of load to be shed, f is the operating frequency, and RoCoF is the rate of change of the operating frequency; see for example fig. 1, para. [0057]), the method (i.e., such as method for tripping energy loads as shedding loads; for instance, power imbalances in an electrical power delivery system may be associated with a fall (or rise) in the frequency of the electrical power system fundamental voltage. Consistent with embodiments disclosed herein, when a threshold UF (or OF) level is crossed, loads may be disconnected (e.g., shed) from the electrical power system or generators or other active power producing components on the electric power system may be shed or run-back to rebalance the system. By shedding selective loads, shedding generators, or running back generators or other active power producing power system components and rebalancing the system, the negative effects of unbalanced system conditions may be mitigated; see for example fig. 1, para. [0017]) comprising: detecting an initial RoCoF (i.e., such as detecting initial RoCoF of electrical voltage; for instance, in some embodiments, one or more remote IEDs associated with loads and/or generators in a system may store operating frequencies and one or more RoCoF thresholds. The one or more remote IEDs may generate quantized and/or binary representations of the operating frequencies and a RoCoF based on a comparison with the one or more RoCoF thresholds and transmit this information to one or more centralized IEDs operating as a centralized controller. The one or more remote IEDs may further transmit power consumption and generation information from associated loads and/or generators. Based on the information received from the one or more remote IEDs, the one or more centralized IEDs may determine an estimated Hand Pacc for the system utilizing, at least in part, Equations 1-3. Utilizing the estimated H and Pacc, the one or more centralized IEDs may determine which loads and/or generators of the system should be sent trip signals and/or run-back or reject signals; see for example fig. 1, para. [0061]) of electrical voltage (i.e., such electrical voltage; for instance, the information generated by the power array calculation module 212 may be provided to a load shedding selection module 210 included in the IED 200 along with the priority indication provided by the user adjustable parameter module 202. The load shedding selection module 210 may further receive information related to an amount of load to shed from the load reduction calculation module 204. Based on the received information (e.g., the amount of load to shed, the priority of the loads, and the amount of power consumed by the loads), the load shedding selection module 210 may determine which loads should be shed to reduce the effects of the detected UF event in the system. That is, the load shedding selection module 210 may match the amount of power to shed with the power used by each of the loads, prioritized by the priority information, and determine which loads to shed; see for example fig. 1, para. [0037]) in the energy transmission system (i.e., such as energy transmission system 100; for instance, the electric power generation and delivery system 100 may include generation, transmission, distribution, and power consumption equipment. For example, the system 100 may include one or more generators 110-116 that, in some embodiments, may be operated by a utility provider for generation of electrical power for the system 100; see for example fig. 1, para. [0019]); determining (i.e., such as determining; for instance, based on the UF event indications received from IEDs 222, IED 200 may determine whether specific loads are exhibiting UF events and whether such loads can be disconnected (e.g., shed) to limit and/or avoid UF events and systems disturbances. This functionality may be achieved using one or more functional modules 202-220 included in the IED 200. For example, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200. In certain embodiments, UF level array calculation module 208 may be configured to order UF events and their associated information based on time stamps indicating when the UF events were received by their associated IEDs 222 (e.g., UF events may be ordered based on their time of occurrence); see for example fig. 1, para. [0032]) that the initial RoCoF falls within (i.e., such as initial RoCoF falls within; for instance, in some embodiments, one or more remote IEDs associated with loads and/or generators in a system may store operating frequencies and one or more RoCoF thresholds. The one or more remote IEDs may generate quantized and/or binary representations of the operating frequencies and a RoCoF based on a comparison with the one or more RoCoF thresholds and transmit this information to one or more centralized IEDs operating as a centralized controller. The one or more remote IEDs may further transmit power consumption and generation information from associated loads and/or generators. Based on the information received from the one or more remote IEDs, the one or more centralized IEDs may determine an estimated Hand Pacc for the system utilizing, at least in part, Equations 1-3. Utilizing the estimated H and Pacc, the one or more centralized IEDs may determine which loads and/or generators of the system should be sent trip signals and/or run-back or reject signals; see for example fig. 1, para. [0061]) one of n predetermined frequency bands (i.e., such as within n predetermined frequency bands of over-frequency/OF and under-frequency/UF ranges/bands; for instance, IEDs 102-108 may be further configured to indicate when an operating frequency falls below a predetermined level. In certain embodiments, an IED may have a number of different UF levels and may indicate when an operating frequency falls below one or more of the UF levels. An UF event having a 59 Hz UF level and a RoCoF of 2 Hz/sec may occur with two generators and eight loads experiencing UF events within 6 milliseconds of each other. Utilizing Equations 1-3, a solution for preventing a blackout condition caused by an underfrequency event may be determined. For example, based on the above-described illustrative system parameters, J.sub.generator for each generator is 800 kg-m.sup.2, J.sub.load for each load is 30 kg-m.sup.2, J.sub.system the island experiencing the UF event is system of 1,840 kg-m.sup.2, H.sub.system of the island is 9.2 seconds, and Pacc power deficiency is therefore 60 MW. Three of the 25 MW loads may be selected for shedding (i.e., totally 75 MW collectively), ensuring that the island does not experience a blackout condition. Utilizing Equations 1-3, a solution for preventing a blackout condition caused by an OF event may also be determined. For example, based on the above-described illustrated system parameters, J.sub.system of the island experiencing an OF event is 2,460 Mkg-m.sup.2, H.sub.system of the island experiencing the OF event 12.3 seconds, and Pacc power excess is therefore 187 MW. To ensure the island does not experience a blackout condition, one of the 100 MW generators may be shed, while another may be run-back to 87 MW output to account for the 187 MW of excess power; see for example fig. 1, para. [0060); in response to determining (i.e., such as in response to determining; for instance, based on the UF event indications received from IEDs 222, IED 200 may determine whether specific loads are exhibiting UF events and whether such loads can be disconnected (e.g., shed) to limit and/or avoid UF events and systems disturbances. This functionality may be achieved using one or more functional modules 202-220 included in the IED 200. For example, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchro phasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200. In certain embodiments, UF level array calculation module 208 may be configured to order UF events and their associated information based on time stamps indicating when the UF events were received by their associated IEDs 222 (e.g., UF events may be ordered based on their time of occurrence); see for example fig. 1, para. [0032]) that the initial RoCoF falls within (i.e., such as initial RoCoF falls within; for instance, in some embodiments, one or more remote IEDs associated with loads and/or generators in a system may store operating frequencies and one or more RoCoF thresholds. The one or more remote IEDs may generate quantized and/or binary representations of the operating frequencies and a RoCoF based on a comparison with the one or more RoCoF thresholds and transmit this information to one or more centralized IEDs operating as a centralized controller. The one or more remote IEDs may further transmit power consumption and generation information from associated loads and/or generators. Based on the information received from the one or more remote IEDs, the one or more centralized IEDs may determine an estimated Hand Pacc for the system utilizing, at least in part, Equations 1-3. Utilizing the estimated H and Pacc, the one or more centralized IEDs may determine which loads and/or generators of the system should be sent trip signals and/or run-back or reject signals; see for example fig. 1, para. [0061]) one of n predetermined frequency bands (i.e., such as within n predetermined frequency bands of over-frequency/OF and under-frequency/UF ranges/bands; for instance, IEDs 102-108 may be further configured to indicate when an operating frequency falls below a predetermined level. In certain embodiments, an IED may have a number of different UF levels and may indicate when an operating frequency falls below one or more of the UF levels. An UF event having a 59 Hz UF level and a RoCoF of 2 Hz/sec may occur with two generators and eight loads experiencing UF events within 6 milliseconds of each other. Utilizing Equations 1-3, a solution for preventing a blackout condition caused by an underfrequency event may be determined. For example, based on the above-described illustrative system parameters, J.sub.generator for each generator is 800 kg-m.sup.2, J.sub.load for each load is 30 kg-m.sup.2, J.sub.system the island experiencing the UF event is system of 1,840 kg-m.sup.2, H.sub.system of the island is 9.2 seconds, and Pacc power deficiency is therefore 60 MW. Three of the 25 MW loads may be selected for shedding (i.e., totally 75 MW collectively), ensuring that the island does not experience a blackout condition. Utilizing Equations 1-3, a solution for preventing a blackout condition caused by an OF event may also be determined. For example, based on the above-described illustrated system parameters, J.sub.system of the island experiencing an OF event is 2,460 Mkg-m.sup.2, H.sub.system of the island experiencing the OF event 12.3 seconds, and Pacc power excess is therefore 187 MW. To ensure the island does not experience a blackout condition, one of the 100 MW generators may be shed, while another may be run-back to 87 MW output to account for the 187 MW of excess power; see for example fig. 1, para. [0060), arming (i.e., such as arming an amount of energy load to trip as loads to shed; for instance, determining an amount of load to shed, which may be expressed in terms of Pacc, may be calculated according to the following: J system = J generator _ 1 + J generator _ 2 + J generator _ n + J load _ 1 + J load _ 2 + J load _ n ( 1 ) H system = J system 2 MVA rating ( 2 ) Pacc = 2 H system fRoCoF ( 3 ). where J.sub.system is the rotating inertia of the system, J.sub.generator.sub.--.sub.n is the rotating inertia of a particular generator included in the system, J.sub.load.sub.--.sub.n is the rotating inertia of a particular load included in the system, H.sub.system is the total spinning inertia of the system, Pacc is the amount of additional mechanical power contribution required or amount of load to be shed, f is the operating frequency, and RoCoF is the rate of change of the operating frequency; see for example fig. 1, para. [0057]) an amount of energy load (i.e., such as arming an amount of energy load to trip as loads to shed; for instance, determining an amount of load to shed, which may be expressed in terms of Pacc, may be calculated according to the following: J system = J generator _ 1 + J generator _ 2 + J generator _ n + J load _ 1 + J load _ 2 + J load _ n ( 1 ) H system = J system 2 MVA rating ( 2 ) Pacc = 2 H system fRoCoF ( 3 ). where J.sub.system is the rotating inertia of the system, J.sub.generator.sub.--.sub.n is the rotating inertia of a particular generator included in the system, J.sub.load.sub.--.sub.n is the rotating inertia of a particular load included in the system, H.sub.system is the total spinning inertia of the system, Pacc is the amount of additional mechanical power contribution required or amount of load to be shed, f is the operating frequency, and RoCoF is the rate of change of the operating frequency; see for example fig. 1, para. [0057]) to trip (i.e., such as arming an amount of energy load to trip as loads to shed; for instance, determining an amount of load to shed, which may be expressed in terms of Pacc, may be calculated according to the following: J system = J generator _ 1 + J generator _ 2 + J generator _ n + J load _ 1 + J load _ 2 + J load _ n ( 1 ) H system = J system 2 MVA rating ( 2 ) Pacc = 2 H system fRoCoF ( 3 ). where J.sub.system is the rotating inertia of the system, J.sub.generator.sub.--.sub.n is the rotating inertia of a particular generator included in the system, J.sub.load.sub.--.sub.n is the rotating inertia of a particular load included in the system, H.sub.system is the total spinning inertia of the system, Pacc is the amount of additional mechanical power contribution required or amount of load to be shed, f is the operating frequency, and RoCoF is the rate of change of the operating frequency; see for example fig. 1, para. [0057]) that corresponds to the one of n predetermined frequency bands (i.e., such as within n predetermined frequency bands of over-frequency/OF and under-frequency/UF ranges/bands; for instance, IEDs 102-108 may be further configured to indicate when an operating frequency falls below a predetermined level. In certain embodiments, an IED may have a number of different UF levels and may indicate when an operating frequency falls below one or more of the UF levels. An UF event having a 59 Hz UF level and a RoCoF of 2 Hz/sec may occur with two generators and eight loads experiencing UF events within 6 milliseconds of each other. Utilizing Equations 1-3, a solution for preventing a blackout condition caused by an underfrequency event may be determined. For example, based on the above-described illustrative system parameters, J.sub.generator for each generator is 800 kg-m.sup.2, J.sub.load for each load is 30 kg-m.sup.2, J.sub.system the island experiencing the UF event is system of 1,840 kg-m.sup.2, H.sub.system of the island is 9.2 seconds, and Pacc power deficiency is therefore 60 MW. Three of the 25 MW loads may be selected for shedding (i.e., totally 75 MW collectively), ensuring that the island does not experience a blackout condition. Utilizing Equations 1-3, a solution for preventing a blackout condition caused by an OF event may also be determined. For example, based on the above-described illustrated system parameters, J.sub.system of the island experiencing an OF event is 2,460 Mkg-m.sup.2, H.sub.system of the island experiencing the OF event 12.3 seconds, and Pacc power excess is therefore 187 MW. To ensure the island does not experience a blackout condition, one of the 100 MW generators may be shed, while another may be run-back to 87 MW output to account for the 187 MW of excess power; see for example fig. 1, para. [0060); after detecting (i.e., such as after detecting the initial RoCoF; for instance, in some embodiments, one or more remote IEDs associated with loads and/or generators in a system may store operating frequencies and one or more RoCoF thresholds. The one or more remote IEDs may generate quantized and/or binary representations of the operating frequencies and a RoCoF based on a comparison with the one or more RoCoF thresholds and transmit this information to one or more centralized IEDs operating as a centralized controller. The one or more remote IEDs may further transmit power consumption and generation information from associated loads and/or generators. Based on the information received from the one or more remote IEDs, the one or more centralized IEDs may determine an estimated Hand Pacc for the system utilizing, at least in part, Equations 1-3. Utilizing the estimated H and Pacc, the one or more centralized IEDs may determine which loads and/or generators of the system should be sent trip signals and/or run-back or reject signals; see for example fig. 1, para. [0061]) the initial RoCoF (i.e., such as after detecting the initial RoCoF; for instance, in some embodiments, one or more remote IEDs associated with loads and/or generators in a system may store operating frequencies and one or more RoCoF thresholds. The one or more remote IEDs may generate quantized and/or binary representations of the operating frequencies and a RoCoF based on a comparison with the one or more RoCoF thresholds and transmit this information to one or more centralized IEDs operating as a centralized controller. The one or more remote IEDs may further transmit power consumption and generation information from associated loads and/or generators. Based on the information received from the one or more remote IEDs, the one or more centralized IEDs may determine an estimated Hand Pacc for the system utilizing, at least in part, Equations 1-3. Utilizing the estimated H and Pacc, the one or more centralized IEDs may determine which loads and/or generators of the system should be sent trip signals and/or run-back or reject signals; see for example fig. 1, para. [0061]), starting (i.e., such as at least one tripping delay timer as timer to provide time synchronized indications; for instance, in some embodiments, IEDs 222 may be programmed with a predetermined UF set point (e.g., level) and be configured to provide time synchronized indications of UF events to the IED 200. In some embodiments, IEDs 222 may include one or more set points (e.g., levels) and be configured to provide time synchronized indications of UF events (e.g., when one or more of the set points are crossed) to the IED 200. Further, in certain embodiments, IEDs 222 may indicate the UF set point (e.g., level) breached, a time indication of the UF event, the power consumed by a load associated with the IED, and/or synchrophasor data which may include a load angle. For example, the UF level event calculation module 206 may determine that a particular set of UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on their occurrence within a particular time period (e.g, a 10 ms period). Based on the UF events occurring within a particular time period, the UF level array calculation module 208 may determine that the loads associated with the UF events are associated with a power sub-grid experiencing a UF condition and provide this information to a load reduction calculation module 204; see for example fig. 1, para. [0032]) at least one tripping delay timer (i.e., such as at least one tripping delay timer as timer to provide time synchronized indications; for instance, in some embodiments, IEDs 222 may be programmed with a predetermined UF set point (e.g., level) and be configured to provide time synchronized indications of UF events to the IED 200. In some embodiments, IEDs 222 may include one or more set points (e.g., levels) and be configured to provide time synchronized indications of UF events (e.g., when one or more of the set points are crossed) to the IED 200. Further, in certain embodiments, IEDs 222 may indicate the UF set point (e.g., level) breached, a time indication of the UF event, the power consumed by a load associated with the IED, and/or synchro phasor data which may include a load angle. For example, the UF level event calculation module 206 may determine that a particular set of UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on their occurrence within a particular time period (e.g, a 10 ms period). Based on the UF events occurring within a particular time period, the UF level array calculation module 208 may determine that the loads associated with the UF events are associated with a power sub-grid experiencing a UF condition and provide this information to a load reduction calculation module 204; see for example fig. 1, para. [0032]); while the at least one tripping delay timer (i.e., such as at least one tripping delay timer as timer to provide time synchronized indications; for instance, in some embodiments, IEDs 222 may be programmed with a predetermined UF set point (e.g., level) and be configured to provide time synchronized indications of UF events to the IED 200. In some embodiments, IEDs 222 may include one or more set points (e.g., levels) and be configured to provide time synchronized indications of UF events (e.g., when one or more of the set points are crossed) to the IED 200. Further, in certain embodiments, IEDs 222 may indicate the UF set point (e.g., level) breached, a time indication of the UF event, the power consumed by a load associated with the IED, and/or synchrophasor data which may include a load angle. For example, the UF level event calculation module 206 may determine that a particular set of UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on their occurrence within a particular time period (e.g, a 10 ms period). Based on the UF events occurring within a particular time period, the UF level array calculation module 208 may determine that the loads associated with the UF events are associated with a power sub-grid experiencing a UF condition and provide this information to a load reduction calculation module 204; see for example fig. 1, para. [0032]) is running (i.e., such as at least one tripping delay timer is running to provide time synchronized indications; for instance, in some embodiments, IEDs 222 may be programmed with a predetermined UF set point (e.g., level) and be configured to provide time synchronized indications of UF events to the IED 200. In some embodiments, IEDs 222 may include one or more set points (e.g., levels) and be configured to provide time synchronized indications of UF events (e.g., when one or more of the set points are crossed) to the IED 200. Further, in certain embodiments, IEDs 222 may indicate the UF set point (e.g., level) breached, a time indication of the UF event, the power consumed by a load associated with the IED, and/or synchrophasor data which may include a load angle. For example, the UF level event calculation module 206 may determine that a particular set of UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on their occurrence within a particular time period (e.g, a 10 ms period). Based on the UF events occurring within a particular time period, the UF level array calculation module 208 may determine that the loads associated with the UF events are associated with a power sub-grid experiencing a UF condition and provide this information to a load reduction calculation module 204; see for example fig. 1, para. [0032]), (i) detecting a deceleration RoCoF (i.e., such as deceleration RoCoF of electrical voltage as an UF event/condition; for instance, based on the UF event indications received from IEDs 222, IED 200 may determine whether specific loads are exhibiting UF events and whether such loads can be disconnected (e.g., shed) to limit and/or avoid UF events and systems disturbances. This functionality may be achieved using one or more functional modules 202-220 included in the IED 200. For example, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200. In certain embodiments, UF level array calculation module 208 may be configured to order UF events and their associated information based on time stamps indicating when the UF events were received by their associated IEDs 222 (e.g., UF events may be ordered based on their time of occurrence). Information from the UF level array calculation module 208, including one or more ordered UF events may be provided to a coinciding UF level event calculation module 206. The UF level event calculation module 206 may be configured to determine whether the one or more UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on the time stamps associated with the one or more UF events; see for example fig. 1, para. [0032]) of electrical voltage (i.e., such electrical voltage; for instance, the information generated by the power array calculation module 212 may be provided to a load shedding selection module 210 included in the IED 200 along with the priority indication provided by the user adjustable parameter module 202. The load shedding selection module 210 may further receive information related to an amount of load to shed from the load reduction calculation module 204. Based on the received information (e.g., the amount of load to shed, the priority of the loads, and the amount of power consumed by the loads), the load shedding selection module 210 may determine which loads should be shed to reduce the effects of the detected UF event in the system. That is, the load shedding selection module 210 may match the amount of power to shed with the power used by each of the loads, prioritized by the priority information, and determine which loads to shed; see for example fig. 1, para. [0037]) in the energy transmission system (i.e., such as energy transmission system 100; for instance, the electric power generation and delivery system 100 may include generation, transmission, distribution, and power consumption equipment. For example, the system 100 may include one or more generators 110-116 that, in some embodiments, may be operated by a utility provider for generation of electrical power for the system 100; see for example fig. 1, para. [0019]), and (ii) detecting (i.e., such as detecting that frequency; for instance, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200; see for example fig. 1, para. [0032]) that a frequency (i.e., such as detecting that frequency; for instance, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchro phasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200; see for example fig. 1, para. [0032]) of the electrical voltage (i.e., such electrical voltage; for instance, the information generated by the power array calculation module 212 may be provided to a load shedding selection module 210 included in the IED 200 along with the priority indication provided by the user adjustable parameter module 202. The load shedding selection module 210 may further receive information related to an amount of load to shed from the load reduction calculation module 204. Based on the received information (e.g., the amount of load to shed, the priority of the loads, and the amount of power consumed by the loads), the load shedding selection module 210 may determine which loads should be shed to reduce the effects of the detected UF event in the system. That is, the load shedding selection module 210 may match the amount of power to shed with the power used by each of the loads, prioritized by the priority information, and determine which loads to shed; see for example fig. 1, para. [0037]) has decayed (i.e., such as decay; for instance, in a system having two sub-grids within a greater grid topology of an electric power delivery system, the probability of both sub-grids experiencing the same frequency decay rate in a system UF condition is low. In certain conditions, the frequency in one sub-grid may increase while the frequency in the other sub-grid may decrease. Moreover, even in conditions where both sub-grids exhibit a decay in frequency, the frequency decays will likely reach set UF threshold levels at differing times. Based on the above, by analyzing the decay rates and times of loads within a system, the IED 200 may determine which loads are associated with a particular power sub-grid. For example, if certain loads exhibit similar frequency decay rates occurring at similar times (e.g., within a 2 ms period), the IED 200 may determine that the loads are associated with a particular power sub-grid; see for example fig. 1, para. [0040]) past a tripping frequency threshold (i.e., such as tripping frequency threshold; for instance, at 504, a determination may be made whether detected operating frequency deviations of detected islands are above or below certain thresholds. If frequency deviations are below set thresholds (e.g., in an UF condition), at 506, an amount of additional mechanical power contribution required from generators associated with the island may be predicted according to a formula utilizing an operating frequency, a rate of change of the operating frequency, and a total spinning inertia of the detected island (i.e., "H"). In certain embodiments, the additional mechanical power may be denoted as "Pacc" and may be measured in Watts. An amount of load to be shed in the detected island may be calculated based on the predicted additional mechanical power contribution, a load priority list, and a measured power consumption of each load in the detected island. In embodiments where system generators include fast feed-forward increase capability (e.g., generator "run-up" capabilities), in lieu of shedding loads, the additional mechanical power required by the Pacc term can be accomplished by quickly increasing the power output of generators. For example, power electronic based generation such as photovoltaic, battery, or other similar power electronic inverter style generation may use such run-up to quickly increase the power output of the generators. If frequency deviations are above set thresholds (e.g., in an OF condition), at 508, an amount of mechanical power reduction required from the generators associated with the island may be predicted according to a formula utilizing the operating frequency, the rate of change of the operating frequency, and the total spinning inertia of the detected island (i.e., "H"). In certain embodiments, the amount of mechanical power reduction may be measured in Watts. An amount of power generation to be shed in the detected island may be calculated based on the predicted amount of mechanical power reduction, a generator priority list, and a measured power production of each generator in the detected island. In embodiments where system generators include fast feed-forward reduction capability (e.g., generator "run-back" or "load rejection" capabilities), the amount of generator Watts to be reduced may instead be achieved by running back generation instead of tripping generators offline with circuit breakers; see for example fig. 5, para. [0054]); in response (i.e., such as detecting that frequency; for instance, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200; see for example fig. 1, para. [0032]) to detecting (i.e., such as detecting that frequency; for instance, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200; see for example fig. 1, para. [0032]) that the frequency (i.e., such as detecting that frequency; for instance, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200; see for example fig. 1, para. [0032]) of the electrical voltage (i.e., such electrical voltage; for instance, the information generated by the power array calculation module 212 may be provided to a load shedding selection module 210 included in the IED 200 along with the priority indication provided by the user adjustable parameter module 202. The load shedding selection module 210 may further receive information related to an amount of load to shed from the load reduction calculation module 204. Based on the received information (e.g., the amount of load to shed, the priority of the loads, and the amount of power consumed by the loads), the load shedding selection module 210 may determine which loads should be shed to reduce the effects of the detected UF event in the system. That is, the load shedding selection module 210 may match the amount of power to shed with the power used by each of the loads, prioritized by the priority information, and determine which loads to shed; see for example fig. 1, para. [0037]) has decayed (i.e., such as decay; for instance, in a system having two sub-grids within a greater grid topology of an electric power delivery system, the probability of both sub-grids experiencing the same frequency decay rate in a system UF condition is low. In certain conditions, the frequency in one sub-grid may increase while the frequency in the other sub-grid may decrease. Moreover, even in conditions where both sub-grids exhibit a decay in frequency, the frequency decays will likely reach set UF threshold levels at differing times. Based on the above, by analyzing the decay rates and times of loads within a system, the IED 200 may determine which loads are associated with a particular power sub-grid. For example, if certain loads exhibit similar frequency decay rates occurring at similar times (e.g., within a 2 ms period), the IED 200 may determine that the loads are associated with a particular power sub-grid; see for example fig. 1, para. [0040]) past the tripping frequency threshold (i.e., such as tripping frequency threshold; for instance, at 504, a determination may be made whether detected operating frequency deviations of detected islands are above or below certain thresholds. If frequency deviations are below set thresholds (e.g., in an UF condition), at 506, an amount of additional mechanical power contribution required from generators associated with the island may be predicted according to a formula utilizing an operating frequency, a rate of change of the operating frequency, and a total spinning inertia of the detected island (i.e., "H"). In certain embodiments, the additional mechanical power may be denoted as "Pacc" and may be measured in Watts. An amount of load to be shed in the detected island may be calculated based on the predicted additional mechanical power contribution, a load priority list, and a measured power consumption of each load in the detected island. In embodiments where system generators include fast feed-forward increase capability (e.g., generator "run-up" capabilities), in lieu of shedding loads, the additional mechanical power required by the Pacc term can be accomplished by quickly increasing the power output of generators. For example, power electronic based generation such as photovoltaic, battery, or other similar power electronic inverter style generation may use such run-up to quickly increase the power output of the generators. If frequency deviations are above set thresholds (e.g., in an OF condition), at 508, an amount of mechanical power reduction required from the generators associated with the island may be predicted according to a formula utilizing the operating frequency, the rate of change of the operating frequency, and the total spinning inertia of the detected island (i.e., "H"). In certain embodiments, the amount of mechanical power reduction may be measured in Watts. An amount of power generation to be shed in the detected island may be calculated based on the predicted amount of mechanical power reduction, a generator priority list, and a measured power production of each generator in the detected island. In embodiments where system generators include fast feed-forward reduction capability (e.g., generator "run-back" or "load rejection" capabilities), the amount of generator Watts to be reduced may instead be achieved by running back generation instead of tripping generators offline with circuit breakers; see for example fig. 5, para. [0054]), determining a time (i.e., such as determining time; for instance, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]) at which to trip the amount of energy load (i.e., such as trip the amount of energy load as shed/disconnect load; for instance, FIG. 4 illustrates one embodiment of a method 400 for protection and control of an electric power delivery system. At 402, a central IED may receive system information from a remote IEDs each associated with a load. In certain embodiments, the system information may include information relating to the operating frequencies of the loads, the power consumption of the loads, synchrophasor information, an indication that an operating frequency of a load has reached a predetermined level, and the like. Based on this system information, at 404, the central IED may determine which loads are associated with a particular sub-grid of the electric power delivery system experiencing an UF condition. In certain embodiments, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]), based (i.e., such as deceleration RoCoF of electrical voltage as an UF event/condition; for instance, based on the UF event indications received from IEDs 222, IED 200 may determine whether specific loads are exhibiting UF events and whether such loads can be disconnected (e.g., shed) to limit and/or avoid UF events and systems disturbances. This functionality may be achieved using one or more functional modules 202-220 included in the IED 200. For example, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200. In certain embodiments, UF level array calculation module 208 may be configured to order UF events and their associated information based on time stamps indicating when the UF events were received by their associated IEDs 222 (e.g., UF events may be ordered based on their time of occurrence). Information from the UF level array calculation module 208, including one or more ordered UF events may be provided to a coinciding UF level event calculation module 206. The UF level event calculation module 206 may be configured to determine whether the one or more UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on the time stamps associated with the one or more UF events; see for example fig. 1, para. [0032]) at least in part on the deceleration RoCoF (i.e., such as deceleration RoCoF of electrical voltage as an UF event/condition; for instance, based on the UF event indications received from IEDs 222, IED 200 may determine whether specific loads are exhibiting UF events and whether such loads can be disconnected (e.g., shed) to limit and/or avoid UF events and systems disturbances. This functionality may be achieved using one or more functional modules 202-220 included in the IED 200. For example, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a UF level array calculation module included in the IED 200. In certain embodiments, UF level array calculation module 208 may be configured to order UF events and their associated information based on time stamps indicating when the UF events were received by their associated IEDs 222 (e.g., UF events may be ordered based on their time of occurrence). Information from the UF level array calculation module 208, including one or more ordered UF events may be provided to a coinciding UF level event calculation module 206. The UF level event calculation module 206 may be configured to determine whether the one or more UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on the time stamps associated with the one or more UF events; see for example fig. 1, para. [0032]) of electrical voltage (i.e., such electrical voltage; for instance, the information generated by the power array calculation module 212 may be provided to a load shedding selection module 210 included in the IED 200 along with the priority indication provided by the user adjustable parameter module 202. The load shedding selection module 210 may further receive information related to an amount of load to shed from the load reduction calculation module 204. Based on the received information (e.g., the amount of load to shed, the priority of the loads, and the amount of power consumed by the loads), the load shedding selection module 210 may determine which loads should be shed to reduce the effects of the detected UF event in the system. That is, the load shedding selection module 210 may match the amount of power to shed with the power used by each of the loads, prioritized by the priority information, and determine which loads to shed; see for example fig. 1, para. [0037]); and tripping (i.e., such as tripping the amount of energy load as shedding/disconnecting load; for instance, FIG. 4 illustrates one embodiment of a method 400 for protection and control of an electric power delivery system. At 402, a central IED may receive system information from a remote IEDs each associated with a load. In certain embodiments, the system information may include information relating to the operating frequencies of the loads, the power consumption of the loads, synchrophasor information, an indication that an operating frequency of a load has reached a predetermined level, and the like. Based on this system information, at 404, the central IED may determine which loads are associated with a particular sub-grid of the electric power delivery system experiencing an UF condition. In certain embodiments, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]) the amount of energy load (i.e., such as tripping the amount of energy load as shedding/disconnecting load; for instance, FIG. 4 illustrates one embodiment of a method 400 for protection and control of an electric power delivery system. At 402, a central IED may receive system information from a remote IEDs each associated with a load. In certain embodiments, the system information may include information relating to the operating frequencies of the loads, the power consumption of the loads, synchrophasor information, an indication that an operating frequency of a load has reached a predetermined level, and the like. Based on this system information, at 404, the central IED may determine which loads are associated with a particular sub-grid of the electric power delivery system experiencing an UF condition. In certain embodiments, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]) at the determined time (i.e., such as determined time; for instance, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]).
Manson does not explicitly disclose a deceleration of a RoCoF.
Zhang discloses a method for controlling a wind turbine system (i.e., see for example fig. 4, para. [0107]- [0168]); wherein a deceleration of a RoCoF (i.e., such as deceleration of RoCoF 402; see for example fig. 4, para. [0107]- [0168]).
Therefore, it would have been obvious to a person of ordinary skill in the art before the effective filing date of the claimed invention to have optionally included the deceleration of a RoCoF in Manson, as taught by Zhang, as it provides the advantage of optimizing the circuit design.
Regarding claim 2, Manson in view of Zhang and the teachings of Manson as modified by Zhang have been discussed above.
Manson further discloses the method for tripping energy loads (i.e., such as method for tripping energy loads as shedding loads; for instance, power imbalances in an electrical power delivery system may be associated with a fall (or rise) in the frequency of the electrical power system fundamental voltage. Consistent with embodiments disclosed herein, when a threshold UF (or OF) level is crossed, loads may be disconnected (e.g., shed) from the electrical power system or generators or other active power producing components on the electric power system may be shed or run-back to rebalance the system. By shedding selective loads, shedding generators, or running back generators or other active power producing power system components and rebalancing the system, the negative effects of unbalanced system conditions may be mitigated; see for example fig. 1, para. [0017]); wherein the method (i.e., such as method for tripping energy loads as shedding loads; for instance, power imbalances in an electrical power delivery system may be associated with a fall (or rise) in the frequency of the electrical power system fundamental voltage. Consistent with embodiments disclosed herein, when a threshold UF (or OF) level is crossed, loads may be disconnected (e.g., shed) from the electrical power system or generators or other active power producing components on the electric power system may be shed or run-back to rebalance the system. By shedding selective loads, shedding generators, or running back generators or other active power producing power system components and rebalancing the system, the negative effects of unbalanced system conditions may be mitigated; see for example fig. 1, para. [0017]) is performed by control circuitry (i.e., such as control circuitry IEDs 102-108; for instance, IEDs 102-108 may be configured to control, monitor, protect, and/or automate the electric power system 100. As used herein, an IED may refer to any microprocessor-based device that monitors, controls, automates, and/or protects monitored equipment within an electric power system. An IED may include, for example, remote terminal units, differential relays, distance relays, directional relays, feeder relays, overcurrent relays, voltage regulator controls, voltage relays, breaker failure relays, generator relays, motor relays, automation controllers, bay controllers, meters, recloser controls, communications processors, computing platforms, programmable logic controllers (PLCs), programmable automation controllers, input and output modules, motor drives, and the like. In some embodiments, IEDs 102-108 may gather status information from one or more pieces of monitored equipment. Further, IEDs 102-108 may receive information concerning monitored equipment using sensors, transducers, actuators, and the like. Although FIG. 1 illustrates separate IEDs monitoring a signal (e.g., IED 104) and controlling a breaker (e.g., IED 108), these capabilities may be combined into a single IED; see for example fig. 1, para. [0022]) of a relay (i.e., such as relay; for instance, IEDs 102-108 may be configured to control, monitor, protect, and/or automate the electric power system 100. As used herein, an IED may refer to any microprocessor-based device that monitors, controls, automates, and/or protects monitored equipment within an electric power system. An IED may include, for example, remote terminal units, differential relays, distance relays, directional relays, feeder relays, overcurrent relays, voltage regulator controls, voltage relays, breaker failure relays, generator relays, motor relays, automation controllers, bay controllers, meters, recloser controls, communications processors, computing platforms, programmable logic controllers (PLCs), programmable automation controllers, input and output modules, motor drives, and the like. In some embodiments, IEDs 102-108 may gather status information from one or more pieces of monitored equipment. Further, IEDs 102-108 may receive information concerning monitored equipment using sensors, transducers, actuators, and the like. Although FIG. 1 illustrates separate IEDs monitoring a signal (e.g., IED 104) and controlling a breaker (e.g., IED 108), these capabilities may be combined into a single IED; see for example fig. 1, para. [0022]) of the energy transmission system (i.e., such as energy transmission system 100; for instance, the electric power generation and delivery system 100 may include generation, transmission, distribution, and power consumption equipment. For example, the system 100 may include one or more generators 110-116 that, in some embodiments, may be operated by a utility provider for generation of electrical power for the system 100; see for example fig. 1, para. [0019]).
Regarding claim 3, Manson in view of Zhang and the teachings of Manson as modified by Zhang have been discussed above.
Manson further discloses the method for tripping energy loads (i.e., such as method for tripping energy loads as shedding loads; for instance, power imbalances in an electrical power delivery system may be associated with a fall (or rise) in the frequency of the electrical power system fundamental voltage. Consistent with embodiments disclosed herein, when a threshold UF (or OF) level is crossed, loads may be disconnected (e.g., shed) from the electrical power system or generators or other active power producing components on the electric power system may be shed or run-back to rebalance the system. By shedding selective loads, shedding generators, or running back generators or other active power producing power system components and rebalancing the system, the negative effects of unbalanced system conditions may be mitigated; see for example fig. 1, para. [0017]); wherein the amount of energy load to trip (i.e., such as tripping the amount of energy load as shedding/disconnecting load; for instance, FIG. 4 illustrates one embodiment of a method 400 for protection and control of an electric power delivery system. At 402, a central IED may receive system information from a remote IEDs each associated with a load. In certain embodiments, the system information may include information relating to the operating frequencies of the loads, the power consumption of the loads, synchro phasor information, an indication that an operating frequency of a load has reached a predetermined level, and the like. Based on this system information, at 404, the central IED may determine which loads are associated with a particular sub-grid of the electric power delivery system experiencing an UF condition. In certain embodiments, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]) is proportional (i.e., such as proportional as in equations 1-3; for instance, determining an amount of load to shed, which may be expressed in terms of Pacc, may be calculated according to the following: J system = J generator _ 1 + J generator _ 2 + J generator _ n + J load _ 1 + J load _ 2 + J load _ n ( 1 ) H system = J system 2 MVA rating ( 2 ) Pacc = 2 H system fRoCoF ( 3 ). where J.sub.system is the rotating inertia of the system, J.sub.generator.sub.--.sub.n is the rotating inertia of a particular generator included in the system, J.sub.load.sub.--.sub.n is the rotating inertia of a particular load included in the system, H.sub.system is the total spinning inertia of the system, Pacc is the amount of additional mechanical power contribution required or amount of load to be shed, f is the operating frequency, and RoCoF is the rate of change of the operating frequency; see for example fig. 1, para. [0057]) to the initial RoCoF (i.e., such as initial RoCoF; for instance, in some embodiments, one or more remote IEDs associated with loads and/or generators in a system may store operating frequencies and one or more RoCoF thresholds. The one or more remote IEDs may generate quantized and/or binary representations of the operating frequencies and a RoCoF based on a comparison with the one or more RoCoF thresholds and transmit this information to one or more centralized IEDs operating as a centralized controller. The one or more remote IEDs may further transmit power consumption and generation information from associated loads and/or generators. Based on the information received from the one or more remote IEDs, the one or more centralized IEDs may determine an estimated Hand Pacc for the system utilizing, at least in part, Equations 1-3. Utilizing the estimated H and Pacc, the one or more centralized IEDs may determine which loads and/or generators of the system should be sent trip signals and/or run-back or reject signals; see for example fig. 1, para. [0061]), according to the one of n predetermined frequency bands (i.e., such as within n predetermined frequency bands of over-frequency/OF and under-frequency/UF ranges/bands; for instance, IEDs 102-108 may be further configured to indicate when an operating frequency falls below a predetermined level. In certain embodiments, an IED may have a number of different UF levels and may indicate when an operating frequency falls below one or more of the UF levels. An UF event having a 59 Hz UF level and a RoCoF of 2 Hz/sec may occur with two generators and eight loads experiencing UF events within 6 milliseconds of each other. Utilizing Equations 1-3, a solution for preventing a blackout condition caused by an underfrequency event may be determined. For example, based on the above-described illustrative system parameters, J.sub.generator for each generator is 800 kg-m.sup.2, J.sub.load for each load is 30 kg-m.sup.2, J.sub.system the island experiencing the UF event is system of 1,840 kg-m.sup.2, H.sub.system of the island is 9.2 seconds, and Pacc power deficiency is therefore 60 MW. Three of the 25 MW loads may be selected for shedding (i.e., totally 75 MW collectively), ensuring that the island does not experience a blackout condition. Utilizing Equations 1-3, a solution for preventing a blackout condition caused by an OF event may also be determined. For example, based on the above-described illustrated system parameters, J.sub.system of the island experiencing an OF event is 2,460 Mkg-m.sup.2, H.sub.system of the island experiencing the OF event 12.3 seconds, and Pacc power excess is therefore 187 MW. To ensure the island does not experience a blackout condition, one of the 100 MW generators may be shed, while another may be run-back to 87 MW output to account for the 187 MW of excess power; see for example fig. 1, para. [0060) in which the initial RoCoF falls (i.e., such as initial RoCoF falls within; for instance, in some embodiments, one or more remote IEDs associated with loads and/or generators in a system may store operating frequencies and one or more RoCoF thresholds. The one or more remote IEDs may generate quantized and/or binary representations of the operating frequencies and a RoCoF based on a comparison with the one or more RoCoF thresholds and transmit this information to one or more centralized IEDs operating as a centralized controller. The one or more remote IEDs may further transmit power consumption and generation information from associated loads and/or generators. Based on the information received from the one or more remote IEDs, the one or more centralized IEDs may determine an estimated Hand Pacc for the system utilizing, at least in part, Equations 1-3. Utilizing the estimated H and Pacc, the one or more centralized IEDs may determine which loads and/or generators of the system should be sent trip signals and/or run-back or reject signals; see for example fig. 1, para. [0061]).
Regarding claim 4, Manson in view of Zhang and the teachings of Manson as modified by Zhang have been discussed above.
Manson further discloses the method for tripping energy loads (i.e., such as method for tripping energy loads as shedding loads; for instance, power imbalances in an electrical power delivery system may be associated with a fall (or rise) in the frequency of the electrical power system fundamental voltage. Consistent with embodiments disclosed herein, when a threshold UF (or OF) level is crossed, loads may be disconnected (e.g., shed) from the electrical power system or generators or other active power producing components on the electric power system may be shed or run-back to rebalance the system. By shedding selective loads, shedding generators, or running back generators or other active power producing power system components and rebalancing the system, the negative effects of unbalanced system conditions may be mitigated; see for example fig. 1, para. [0017]); wherein determining (i.e., such as determining time; for instance, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]) the time (i.e., such as determining time; for instance, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]) at which to trip the amount of energy load (i.e., such as trip the amount of energy load as shed/disconnect load; for instance, FIG. 4 illustrates one embodiment of a method 400 for protection and control of an electric power delivery system. At 402, a central IED may receive system information from a remote IEDs each associated with a load. In certain embodiments, the system information may include information relating to the operating frequencies of the loads, the power consumption of the loads, synchro phasor information, an indication that an operating frequency of a load has reached a predetermined level, and the like. Based on this system information, at 404, the central IED may determine which loads are associated with a particular sub-grid of the electric power delivery system experiencing an UF condition. In certain embodiments, determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads. At step 406, the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to IEDs associated with the one or more loads directing the IEDs to disconnect the loads. As discussed above, in some embodiments, determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads; see for example fig. 4, para. [0048]) comprises determining whether to (i) extend (i.e., such as extend as adjust; for instance, the IED 200 may also include a user adjustable parameter module 202 that, in some embodiments, includes parameters defining an amount of load to be shed for a particular UF-level. In some embodiments, the amount of load to be shed may be in the form of a power/frequency value (e.g., MW/Hz). Information regarding the amount of load to be shed for a particular UF-level may be provided to the load reduction calculation module 204. The user adjustable parameter module 202 may include a parameter that includes a priority indication for loads associated with the IEDs 222. For example, the priority indication may include a priority queue indicating the order in which loads should be shed from the system in the event of an UF condition. Accordingly, the priority indication may indicate certain loads (e.g., a hospital) that should stay connected to the system in the event of an UF condition. The information generated by the power array calculation module 212 may be provided to a load shedding selection module 210 included in the IED 200 along with the priority indication provided by the user adjustable parameter module 202; see for example fig. 2, para. [0037]) the at least one tripping delay timer (i.e., such as at least one tripping delay timer as timer to provide time synchronized indications; for instance, in some embodiments, IEDs 222 may be programmed with a predetermined UF set point (e.g., level) and be configured to provide time synchronized indications of UF events to the IED 200. In some embodiments, IEDs 222 may include one or more set points (e.g., levels) and be configured to provide time synchronized indications of UF events (e.g., when one or more of the set points are crossed) to the IED 200. Further, in certain embodiments, IEDs 222 may indicate the UF set point (e.g., level) breached, a time indication of the UF event, the power consumed by a load associated with the IED, and/or synchro phasor data which may include a load angle. For example, the UF level event calculation module 206 may determine that a particular set of UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on their occurrence within a particular time period (e.g, a 10 ms period). Based on the UF events occurring within a particular time period, the UF level array calculation module 208 may determine that the loads associated with the UF events are associated with a power sub-grid experiencing a UF condition and provide this information to a load reduction calculation module 204; see for example fig. 1, para. [0032]), or (ii) immediately trip the amount of energy load.
Regarding claim 11, Manson in view of Zhang and the teachings of Manson as modified by Zhang have been discussed above.
Manson further discloses a relay apparatus (i.e., such as relay apparatus IEDs 102-108; for instance, IEDs 102-108 may be configured to control, monitor, protect, and/or automate the electric power system 100. As used herein, an IED may refer to any microprocessor-based device that monitors, controls, automates, and/or protects monitored equipment within an electric power system. An IED may include, for example, remote terminal units, differential relays, distance relays, directional relays, feeder relays, overcurrent relays, voltage regulator controls, voltage relays, breaker failure relays, generator relays, motor relays, automation controllers, bay controllers, meters, recloser controls, communications processors, computing platforms, programmable logic controllers (PLCs), programmable automation controllers, input and output modules, motor drives, and the like; see for example fig. 1, para. [0022]). And, for the rest of the limitations/features in claim 11 is rejected for the same reasons that have already been stated/discussed above in rejected claim 1. {See rejection of claim 1}
Regarding claim 12, is rejected for the same reasons that have already been stated/discussed above in rejected claim 2. {See rejection of claim 2}
Regarding claim 13, is rejected for the same reasons that have already been stated/discussed above in rejected claim 3. {See rejection of claim 3}
Regarding claim 14, is rejected for the same reasons that have already been stated/discussed above in rejected claim 4. {See rejection of claim 4}
Allowable Subject Matter
Claims 5-10 and 15-19 are objected to as being dependent upon a rejected base claim, but would be allowable if rewritten in independent form including all of the limitations of the base claim and any intervening claims.
The following is a statement of reasons for the indication of allowable subject matter:
Regarding claim 5, Manson in view of Zhang teaches the invention set forth above. However, neither Manson nor Zhang particularly teaches wherein detecting the initial RoCoF of electrical voltage comprises: detecting that the frequency of electrical voltage has decayed past a first frequency threshold; simultaneously starting a set of initial timers, with each consecutive initial timer of the set of initial timers being configured to assert after a progressively increasing initial timer interval has elapsed; after starting the set of initial timers, detecting that the frequency of electrical voltage has decayed past a second frequency threshold; in response to detecting that the frequency of electrical voltage has decayed past the second frequency threshold, determining which initial timers of the set of initial timers have asserted; and determining that the initial RoCoF has a value that corresponds to the initial timers of the set of initial timers that have asserted.
Hence claim 5 will be deemed allowable if rewritten in an independent form.
Claims 6-8 depend on objected claim 5, consequently claims 6-8 will also be deemed allowable.
Regarding claim 9, Manson in view of Zhang teaches the invention set forth above. However, neither Manson nor Zhang particularly teaches further comprising: conducting at least one simulation of an under-frequency event in the energy transmission system; based on results of the at least one simulation, determining optimized values for the n predetermined frequency bands, for the amounts of load to trip that correspond to the n predetermined frequency bands, and for the at least one tripping delay timer; and reconfiguring control circuitry of the energy transmission system based on the optimized values.
Hence claim 9 will be deemed allowable if rewritten in an independent form.
Claim 10 depends on objected claim 9, consequently claim 10 will also be deemed allowable.
Regarding claim 15, Manson in view Zhang teaches the invention set forth above. However, neither Manson nor Zhang particularly teaches wherein detecting the initial RoCoF of electrical voltage comprises: detecting that the frequency of electrical voltage has decayed past a first frequency threshold; simultaneously starting a set of initial timers, with each consecutive initial timer of the set of initial timers being configured to assert after a progressively increasing initial timer interval has elapsed; after starting the set of initial timers, detecting that the frequency of electrical voltage has decayed past a second frequency threshold; in response to detecting that the frequency of electrical voltage has decayed past the second frequency threshold, determining which initial timers of the set of initial timers have asserted; and determining that the initial RoCoF has a value that corresponds to the initial timers of the set of initial timers that have asserted.
Hence claim 15 will be deemed allowable if rewritten in an independent form.
Claims 16-18 depend on objected claim 15, consequently claims 16-18 will also be deemed allowable.
Regarding claim 19, Manson in view of Zhang teaches the invention set forth above. However, neither Manson nor Zhang particularly teaches comprising: an initial RoCoF detector logic component; a secondary RoCoF deceleration detector logic component; a fast transient filter component; an under-voltage inhibitor logic component; a supervised under-frequency trip logic component; and a supervised automatic load restoration logic component configured to determine whether to restore the energy load by a predetermined amount.
Hence claim 19 will be deemed allowable if rewritten in an independent form.
Claim 20 is allowed.
The following is an examiner’s statement of reasons for allowance:
Regarding claim 20, Manson (US Publication No. 20130018521) in view of Zhang et al (US Publication No. 20220316443) substantially teaches the claim limitations as indicated in claim 1. However, neither Manson nor Zhang teaches or suggests a method for tripping energy loads in an energy transmission system based on Rate of Change of Frequency (RoCoF), the method comprising: detecting that the frequency of electrical voltage has decayed past a first frequency threshold; simultaneously starting a set of initial timers, with each consecutive initial timer of the set of initial timers being configured to assert after a progressively increasing initial timer interval has elapsed; after starting the set of initial timers, detecting that the frequency of electrical voltage has decayed past a second frequency threshold; in response to detecting that the frequency of electrical voltage has decayed past the second frequency threshold, determining which initial timers of the set of initial timers have asserted; determining that an initial RoCoF of electrical voltage in the energy transmission system has a value that corresponds to the initial timers of the set of initial timers that have asserted; determining that the initial RoCoF falls within one of n predetermined frequency bands; in response to determining that the initial RoCoF falls within one of n predetermined frequency bands, arming an amount of energy load to trip that corresponds to the one of n predetermined frequency bands; after detecting the initial RoCoF, starting at least one tripping delay timer; while the at least one tripping delay timer is running, (i) detecting a deceleration RoCoF of electrical voltage in the energy transmission system, and (ii) detecting that a frequency of the electrical voltage has decayed past a tripping frequency threshold; in response to detecting that the frequency of the electrical voltage has decayed past the tripping frequency threshold, determining a time at which to trip the amount of energy load, based at least in part on the deceleration RoCoF of electrical voltage; and tripping the amount of energy load at the determined time.
Conclusion
Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to MUAAMAR Q AL-TAWEEL whose telephone number is (571)270-0339. The examiner can normally be reached 0730-1700.
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/MUAAMAR QAHTAN AL-TAWEEL/Examiner, Art Unit 2838
/THIENVU V TRAN/ Supervisory Patent Examiner, Art Unit 2838
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