WO2007086944A2 - Systeme, appareil et procede pour compenser la sensibilite d'un element de sequence dans un relais differentiel de courant du secteur dans un systeme de puissance - Google Patents

Systeme, appareil et procede pour compenser la sensibilite d'un element de sequence dans un relais differentiel de courant du secteur dans un systeme de puissance Download PDF

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Publication number
WO2007086944A2
WO2007086944A2 PCT/US2006/035175 US2006035175W WO2007086944A2 WO 2007086944 A2 WO2007086944 A2 WO 2007086944A2 US 2006035175 W US2006035175 W US 2006035175W WO 2007086944 A2 WO2007086944 A2 WO 2007086944A2
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WIPO (PCT)
Prior art keywords
current
fault
sequence
phasor
local
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PCT/US2006/035175
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English (en)
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WO2007086944A3 (fr
Inventor
Joseph B. Mooney
Gabriel Benmouyal
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Schweitzer Engineering Laboratories, Inc.
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Priority claimed from US11/337,894 external-priority patent/US7660088B2/en
Application filed by Schweitzer Engineering Laboratories, Inc. filed Critical Schweitzer Engineering Laboratories, Inc.
Publication of WO2007086944A2 publication Critical patent/WO2007086944A2/fr
Publication of WO2007086944A3 publication Critical patent/WO2007086944A3/fr

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Classifications

    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02H—EMERGENCY PROTECTIVE CIRCUIT ARRANGEMENTS
    • H02H3/00—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection
    • H02H3/26—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents
    • H02H3/28—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents involving comparison of the voltage or current values at two spaced portions of a single system, e.g. at opposite ends of one line, at input and output of apparatus
    • H02H3/283—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents involving comparison of the voltage or current values at two spaced portions of a single system, e.g. at opposite ends of one line, at input and output of apparatus and taking into account saturation of current transformers
    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02H—EMERGENCY PROTECTIVE CIRCUIT ARRANGEMENTS
    • H02H3/00—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection
    • H02H3/26—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents
    • H02H3/28—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents involving comparison of the voltage or current values at two spaced portions of a single system, e.g. at opposite ends of one line, at input and output of apparatus
    • H02H3/30—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents involving comparison of the voltage or current values at two spaced portions of a single system, e.g. at opposite ends of one line, at input and output of apparatus using pilot wires or other signalling channel
    • H02H3/307—Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition with or without subsequent reconnection ; integrated protection responsive to difference between voltages or between currents; responsive to phase angle between voltages or between currents involving comparison of the voltage or current values at two spaced portions of a single system, e.g. at opposite ends of one line, at input and output of apparatus using pilot wires or other signalling channel involving comparison of quantities derived from a plurality of phases, e.g. homopolar quantities; using mixing transformers
    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02H—EMERGENCY PROTECTIVE CIRCUIT ARRANGEMENTS
    • H02H7/00—Emergency protective circuit arrangements specially adapted for specific types of electric machines or apparatus or for sectionalised protection of cable or line systems, and effecting automatic switching in the event of an undesired change from normal working conditions
    • H02H7/26—Sectionalised protection of cable or line systems, e.g. for disconnecting a section on which a short-circuit, earth fault, or arc discharge has occured
    • H02H7/261—Sectionalised protection of cable or line systems, e.g. for disconnecting a section on which a short-circuit, earth fault, or arc discharge has occured involving signal transmission between at least two stations
    • H02H7/263—Sectionalised protection of cable or line systems, e.g. for disconnecting a section on which a short-circuit, earth fault, or arc discharge has occured involving signal transmission between at least two stations involving transmissions of measured values

Definitions

  • the present invention generally relates to power system protection, and more specifically, to a system, apparatus and method for compensating the sensitivity of a sequence element in a line current differential relay in a power system.
  • Electric power systems are designed to generate, transmit and distribute electrical energy to loads.
  • power systems generally include a variety of power system elements such as electrical generators, electrical motors, power transformers, power transmission lines, buses and capacitors, to name a few.
  • power systems typically include protective devices and associated procedures to protect the power system elements from abnormal conditions such as electrical short circuits, overloads, frequency excursions, voltage fluctuations, and the like.
  • a protective device and associated procedure acts to isolate some power system element(s) from the remainder of the power system upon detection of the abnormal condition or a fault in, or related to, the power system element(s).
  • Logically grouped zones of protection, or protection zones utilizing the protective devices and procedures, are established to efficiently manage faults or other abnormal conditions occurring in the power system elements.
  • protection zones may be classified into six types including:
  • Such protective devices may include different types of protective relays, surge protectors, arc gaps and associated circuit breakers and reclosers.
  • each of the six types of protection zones uses protective devices that are based on the characteristics of the power system elements in that category. More specifically, different protective relays utilizing a variety of protective schemes (e.g., differential current comparisons, magnitude comparisons, frequency sensing), are required to protect the various power system elements.
  • a line current differential relay having electrical connections to the transmission line via current transformers (designed to step-down the primary current to a magnitude suitable for use by the line current differential relay), is designed to monitor current flowing in a transmission line by measuring the current flowing into and out of terminal points of the transmission line, and calculating inter alia, the sum of all measured current, or the operate current.
  • I reslraint (
  • the line current differential relay requires that the operate current exceeds a minimum pickup value and some percentage of the total current flowing through the protection zone before the line current differential relay may issue a breaker tripping signal.
  • Typical protection of a transmission line is generally performed using two line current differential relays coupled to the transmission line via current transformers as described above, with each relay located at different extremities of the line.
  • a communication channel e.g., microwave channel, telephone grade channel, fiber optics, etc.
  • Providing line current differential protection for a transmission line generally includes incorporation of both phase elements and sequence elements in the line current differential relay; that is, incorporation of an A- phase element, a B-phase element and a C-phase element, and a possibly a zero-sequence or ground element and a negative-sequence element.
  • phase and/or sequence elements will operate to cause the line current differential relay to assert and subsequently issue a trip signal to an associated power circuit breaker(s).
  • the A-phase element, the zero-sequence element, and the negative- sequence element may operate.
  • the A-phase element, the zero- sequence element, and/or the negative-sequence element may fail to operate properly when certain conditions exist. For example, if the fault resistance, R f1 of the A-phase-to-ground fault is above the resistive limit of sensitivity, the A- phase element may fail to properly detect the fault.
  • phase elements A-, B- and/or C-phase current elements
  • dissequence elements zero-sequence phase element and/or the negative- sequence phase element
  • a fault may go undetected by some or all of the three phase and/or the two sequence elements of the line current differential relay(s), possibly resulting in removal from operation a larger portion of the power system network by the back-up protection.
  • a system, an apparatus and a method is provided in a current differential protective device to compensate for, or to adjust the sensitivity of, the negative- and zero-sequence elements of the current differential protective device in order to ensure their proper operation during a phase-to-ground fault with a high fault resistance, occurring during a pole-open condition.
  • an apparatus and method compensate the sensitivity of a line current differential element of a first current differential relay providing differential protection for a transmission line of a power system during a single-phase pole-open condition.
  • One apparatus includes a first delta filter configured to remove a first pre-fault current from a first fault current of the transmission line to form a compensated first current.
  • the apparatus also includes a second delta filter configured to remove a second pre-fault current from a second fault current of the transmission line to form a compensated second current.
  • the line current differential element is configured to receive the compensated first and second current phasors to compensate the sensitivity of the at least one line current differential element.
  • the first current differential relay is operatively coupled to a first end of the transmission line and in communication with a second current differential relay operatively coupled to a second end of the transmission line.
  • the apparatus derives a first pre-fault current phasor from instantaneous values of the first pre-fault current measured by the first current differential relay. It also derives a first fault current phasor from instantaneous values of the first fault current measured by the first current differential relay.
  • the apparatus also derives a second pre-fault current phasor from instantaneous values of the second pre-fault current measured by and received from the second current differential relay and derives a second fault current phasor from instantaneous values of the second fault current measured by and received from the second current differential relay. Subtraction of the second pre-fault current phasor from the second fault current phasor forms the second phasor.
  • the line current differential element may be a zero-sequence current element, a negative-sequence current element, A-phase current element, a B- phase current element or a C-phase current element.
  • a method compensates the sensitivity of a line current differential element of a first current differential relay providing differential protection for a transmission line of a power system during a single-phase pole-open condition.
  • the method includes removing a first pre-fault current from a first fault current of the transmission line to form a compensated first current, removing a second pre-fault current from a second fault current of the transmission line to form a compensated second current, and. providing a first phasor representative of the compensated first current and a second phasor representative of the second compensated current to the line current differential element to compensate the sensitivity of the line current differential element.
  • a system compensates the sensitivity of a first line current differential sequence element of a local current differential relay.
  • the local current differential relay is operatively coupled to a first end of a transmission line of a power system and in communication with a remote current differential relay operatively coupled to a second end of the transmission line.
  • the system includes a first delta filter operatively coupled to the first line current differential sequence element.
  • the first delta filter includes a first delay filter configured to receive a first local sequence current phasor at a first time and to generate a first delayed local sequence current phasor at a second time.
  • the first delta filter also includes a first adder configured to subtract the first delayed local sequence current phasor from a second local sequence current phasor received at the second time to form a compensated local sequence current phasor.
  • the system also includes a second delta filter operatively coupled to the first line current differential sequence element.
  • the second delta filter includes a second delay filter configured to receive a first remote sequence current phasor at the first time and to generate a first delayed remote sequence current phasor at the second time.
  • the second delta filter also includes a second adder configured to subtract the first delayed remote sequence current phasor from a second remote sequence current phasor received at the second time to form a compensated remote sequence current phasor.
  • the first line current differential element is configured to receive each of the compensated local and remote sequence current phasors to compensate the sensitivity of the first line current differential element.
  • an apparatus for compensates the sensitivity of at least one line current differential sequence element of a local current differential relay during a single-phase pole-open condition of a transmission line of a power system is operatively coupled to a first end of the transmission line and in communication with a remote current differential relay operatively coupled to a second end of the transmission line.
  • the apparatus includes a first delta filter configured to remove a pre-fault local current contribution from each of a plurality a local current phasors calculated by the local current differential relay using instantaneous local current values measured during a fault in the transmission line to form a plurality of compensated local current phasors.
  • the apparatus also includes a second delta filter configured to remove a pre-fault remote current contribution from each of a plurality a remote current phasors calculated by the local current differential relay using instantaneous remote current values measured by the remote current differential relay during the fault to form a plurality of compensated second current phasors.
  • the pre-fault local current contribution is latched into a memory of the first delta filter, and the pre- fault remote current contribution is latched into a memory of the second delta filter.
  • the at least one line current differential element is configured to receive corresponding local and remote sequence current phasors of the plurality of compensated local and remote sequence current phasors to compensate the sensitivity of the at least one line current differential element.
  • a method is provided to compensate the sensitivity of a line current differential sequence element of a local current differential relay during a single-phase pole-open condition of a transmission line of a power system.
  • the local current differential relay is operatively coupled to a first end of the transmission line and in communication with a remote current differential relay operatively coupled to a second end of the transmission line.
  • the method includes subtracting a pre-fault local current phasor from each of a plurality of local current phasors derived from instantaneous local current values measured by the local current differential relay during a fault in the transmission line to form a plurality of compensated local current phasors.
  • the pre-fault local current phasor is stored in a first memory location of the local current differential relay.
  • the method also includes subtracting a pre-fault remote current phasor from each of a plurality of remote current phasors derived from instantaneous remote current values measured by the remote current differential relay during the fault to form a plurality of compensated second current phasors.
  • the pre-fault remote current phasor is stored in a second memory location of the local current differential relay. Pairs of corresponding local and remote sequence current phasors of the plurality of compensated local and remote sequence current phasors are provided to the line current differential element to compensate the sensitivity of the line current differential element.
  • a system compensates the sensitivity of a first line current differential sequence element of a local current differential relay.
  • the local current differential relay is operatively coupled to a first end of the transmission line and in communication with a remote current differential relay operatively coupled to a second end of the transmission line.
  • the system includes a first adder, a first memory register and a first delay filter operatively coupled to the first adder and first memory register.
  • the first delay filter is configured to delay a local sequence current phasor calculated prior to detecting an occurrence of a fault in the transmission line.
  • the first memory register is configured to store the delayed local sequence current phasor to form a stored local sequence current phasor in response to receipt of a latching signal indicating the fault.
  • the first adder is configured to subtract one of the delayed local sequence current phasor and the stored local sequence current phasor from each of a plurality of local sequence current phasors calculated after the fault to form a plurality of compensated local sequence current phasors.
  • the system also includes a second adder, a second memory register and a second delay filter operatively coupled to the second adder and the second memory register.
  • the second delay filter is configured to delay a remote sequence current phasor calculated prior to the fault.
  • the second memory register is configured to store the delayed remote sequence current phasor to form a stored remote sequence current phasor in response to receipt of the latching signal.
  • the second adder is configured to subtract one of the delayed remote sequence current phasor and the stored remote sequence current phasor from each of a plurality of remote sequence current phasors calculated after the fault to form a plurality of compensated remote sequence current phasors. Pairs of corresponding compensated local and remote sequence current phasors of the plurality of compensated local and remote sequence current phasors are provided to the first line current differential element to compensate the sensitivity of the first line current differential element.
  • an apparatus for compensates the sensitivity of a line current differential element of a protective relay providing differential protection for a transmission line of a power system.
  • the apparatus includes a delta filter arrangement configured to form compensated first and second current phasors based upon corresponding first and second pre-fault and fault current phasors.
  • the delta filter arrangement includes a first delta filter coupled to receive the first pre-fault and fault current phasors and to generate the compensated first current phasor.
  • the delta filter arrangement also includes a second delta filter coupled to receive the second pre-fault and fault current phasors and to generate the compensated second current phasor.
  • Each of the first and second pre-fault and fault current phasors is derived from corresponding measured currents at first and second locations of the transmission line.
  • a method compensates the sensitivity of a line current differential element of a protective relay providing differential protection for a transmission line of a power system.
  • the method includes forming a compensated first signal based on a first pre- fault current and a first fault current measured at a first end of the transmission line, and forming a compensated second signal based on a second pre-fault current and a second fault current measured at a second end of the transmission line.
  • the method also includes providing compensated first and second current phasors to the current differential element thereby compensating the line current differential element.
  • Each of the compensated first and second current phasors is derived from corresponding compensated first and second signals.
  • FIGURE 1 is a single line schematic diagram of a power system that may be utilized in a typical wide area.
  • FIGURE 2 is a block diagram of an exemplary configuration of the local line current differential relay of FIG.1 , according to an embodiment of the invention.
  • FIGURE 3 is a block diagram of the logic of the local line current differential relay of FIG. 1 , according to an embodiment of the invention.
  • FIGURE 4 is an exemplary alpha-plane that may be used to determine a trip condition based on current ratio trajectories calculated by the local and remote line current differential relays of FIG. 1.
  • FIGURE 5 is an exemplary schematic diagram of a short transmission line having negligible shunt capacitance, according to an embodiment of the invention.
  • FIGURE 6 is sequence network diagram that may be used to resolve an
  • FIGURE 7 is another sequence network diagram that may be used to resolve a B-phase pole open condition in the short transmission line of FIG. 5.
  • FIGURE 8 is yet another sequence network diagram that may be used to resolve an A-phase-to-ground fault occurring during the B-phase pole open condition in the transmission line of FIG. 5.
  • FIGURE 9 is yet another alpha plane that may be used to plot the negative-sequence current ratio trajectories under the conditions of FIG. 8.
  • FIGURE 10 is yet a further alpha plane illustrating the compensated negative-sequence current ratio trajectories verses the un-compensated compensated negative-sequence current ratio trajectories, according to an embodiment of the invention.
  • FIGURE 11 is an exemplary logic circuit diagram for compensating the sensitivity of a negative-sequence element scheme of the local line current differential relay of FIG. 1 , according to an embodiment of the invention.
  • FIGURE 12 is a more detailed diagram of a delta filter of the logic circuit of FIG. 11.
  • FIGURE 13 is a latching delta filter system that may be used the logic circuit of FIG. 11 to maintain the local and remote reference signal for a time period longer than the delay time interval.
  • each current-ratio trajectory is computed as a phasor ratio of the two corresponding phase (or sequence) currents entering and leaving the protected transmission line (e.g. the "local" A- phase current and the "remote” A-phase current), as measured by two communicating line current differential relays placed a distance from each other on the protected transmission line.
  • a current-ratio trajectory that should fall within a trip area of the alpha plane may instead fall in a stability area of the alpha plane and therefore go undetected.
  • An apparatus and method are provided in a protective device to compensate, or adjust the sensitivity of, the negative- and zero-sequence elements of the protective device in order to ensure their proper operation during a phase-to-ground fault with a high fault resistance, occurring during a pole-open condition.
  • the method includes removal of the pre-fault zero-sequence current from both of the zero-sequence currents forming the zero-sequence current ratio used by the zero-sequence element, and removal of the pre-fault negative-sequence current from both of the negative-sequence currents forming the negative-sequence current ratio used by the negative-sequence element.
  • another embodiment of the invention may include attenuation, rather than total removal, of the pre-fault zero-sequence current and/or the pre-fault negative-sequence current from respective zero-sequence and negative-sequence currents.
  • FIGURE 1 is a single line schematic diagram of a power system 10 that may be utilized in a typical wide area. As illustrated in FIG.
  • the power system 10 includes, among other things, three generators 12a, 12b and 12c configured to generate three-phase sinusoidal waveforms, for example, to generate three-phase 12 kV sinusoidal waveforms.
  • the power system 10 also includes three step-up power transformers 14a, 14b and 14c configured to increase the generated three-phase sinusoidal waveforms to a higher voltage such as 138 kV, and a number of circuit breakers 18 that operate to disconnect respective portions of the power system from the remainder of the power system 10 during an associated trip condition.
  • the step-up power transformers 14a, 14b, 14c provide the higher voltage sinusoidal waveforms to a number of long distance transmission lines such as the transmission lines 20a and 20b.
  • a first substation 15 may be defined to include the generators 12a, 12b, two of the step-up transformers 14a, 14b and associated circuit breakers 18 interconnected via a first bus 19.
  • a second substation 22 includes two step-down power transformers 24a and 24b to transform the higher voltage sinusoidal waveforms to lower voltage sinusoidal waveforms (e.g., 15 kV) suitable for distribution via distribution lines to the end-users 26 and/or loads 30.
  • the power system 10 utilizes many types of protective devices and associated procedures to protect the power system elements from faults or other abnormal conditions.
  • the power system 10 also includes a first line current differential relay designated as a local line current differential relay 50 ("local differential relay 50") and a second line current differential relay designated as a remote line current differential relay 52 (“remote differential relay 52").
  • the differential relays 50 and 52 are used to protect a transmission line, denoted as a transmission line 22, from faults occurring between respective circuit breakers 18.
  • current differential relays such as the differential relays 50 and 52 may be implemented via line current differential elements such as A-phase, B-phase and/or C-phase current elements, and/or zero-sequence and negative- sequence current elements.
  • line current differential elements are configured to periodically calculate a current ratio of a local ' current (current entering the transmission line) and a remote current (current leaving the transmission line), and then to compare each calculated current ratio to a characteristic, or an area of stability, imbedded in an alpha plane of the line current differential element.
  • each current ratio includes the ratio of two phasors representative of the local and remote currents; a complex number.
  • the alpha plane is a complex plane (i.e., a plane having one real axis and one imaginary axis) where the trajectory of the each current ratio is geometrically represented.
  • a more detailed description of line current differential protection using a characteristic imbedded in an alpha plane is provided by U. S. Patent No. 6,590,397, entitled “Line Differential Protection System for a Power Transmission Line", issued on July 8, 2003, to Jeffrey B. Roberts, assigned to Schweitzer Engineering Laboratories, Inc., the contents of which are hereby incorporated by reference.
  • the local differential relay 50 is positioned on the "left-side” or the local end, while the remote differential relay 52 is positioned on the "right-side” or the remote end of the transmission line.
  • FIG. 2 is a block diagram of an exemplary configuration of the local differential relay 50.
  • the local differential relay 50 is coupled to the transmission line 22 via current transformers that operate to step down the primary three-phase current to secondary currents suitable for use by the relay.
  • secondary current waveforms 64, 66, and 68 received via
  • I A , I B and I c the current transformers
  • secondary current waveforms 64, 66 and 68 are shown in FIG. 2 for ease of illustration and discussion, it should be understood that additional secondary current waveforms may be utilized by the local differential relay 50.
  • secondary current waveforms 64, 66 and 68 received by the local differential relay 50 are further transformed into corresponding voltage waveforms via respective current transformers 75, 77 and 79 and resistors (not separately illustrated), and filtered via respective low pass filters 80, 82 and 84 .
  • An analog-to-digital (A/D) converter 86 multiplexes, samples and digitizes the filtered secondary current waveforms to form corresponding digitized current waveform signals 87.
  • the A/D converter 86 is coupled to a microcontroller
  • microprocessor 90 or FPGA
  • program memory 92 e.g., a Flash EPROM
  • parameter memory 94 e.g., an EEPROM
  • the microprocessor 90 executing a computer program or relay logic scheme (discussed below) processes each of the digitized current signals to extract corresponding phasors, in this case current phasors and sequence quantity phasors, and then performs various calculations using the extracted phasors (and received phasor quantities) to determine whether a short circuit exists in the transmission line 22.
  • the local differential relay 50 also includes a receiver/transmitter means such as, for example, a UART 98, configured to enable transmission of phasor quantities to the remote differential relay 52 and to enable receipt of phasor quantities from the remote differential relay 52.
  • a receiver/transmitter means such as, for example, a UART 98, configured to enable transmission of phasor quantities to the remote differential relay 52 and to enable receipt of phasor quantities from the remote differential relay 52.
  • the remote differential relay 52 is substantially similarly configured and operable.
  • each of the phasors derived from the three secondary current waveforms 64, 66 and 68 is of equal magnitude and has a phase shift of 120 degrees.
  • phase shift 120 degrees.
  • a fault condition typically results in an "unbalanced" condition yielding, for example, A-, B- and C- current phasors having varied magnitudes with phase angles that are not 120 degrees apart.
  • the level of unbalance can be assessed by computing, at each line extremity and therefore in each relay, the negative (I2) and the zero (I0) sequence phasors as provided by:
  • FIG. 3 is a block diagram of relay logic of the local line current differential relay 50 according to an embodiment of the invention. Although only the relay logic of local differential relay 50 is discussed in detail, it should be noted that the remote line current differential relay 52 is equivalents configured and operable.
  • the relay logic includes a phasor calculation function 102 where three- phase current phasors are extracted from both local digitized current signals of the local differential relay 50 and time-aligned remote digitized current signals received from the remote differential relay 52.
  • the current phasors denoted as
  • the relay logic also includes a sequence quantity function 103 where a
  • I CR current phasor denoted as I CR
  • I CR current phasor denoted as I CR
  • I CR local negative-sequence current phasor
  • I 2L a remote negative-sequence current phasor denoted as
  • I 2R are calculated using the three-phase current phasors
  • A-phase element 111 configured to generate a binary output 87LA
  • B-phase element 112 configured to generate a binary output 87LB
  • C-phase element 113 configured to generate a binary output 87LC
  • the zero-sequence or ground element 114 is configured to generate a binary output 87LG and a negative-sequence element 115 is configured to generate a binary output 87L2.
  • the A-phase element 111 will pickup in the event of an A-phase-to-ground fault
  • the B-phase element 112 will pickup in the event of a B-phase-to-ground fault
  • the C-phase element 113 will pickup in the event of a C-phase-to-ground fault.
  • the A-phase element 111, B-phase element 112 or C-phase element 113 may become blind to a phase-to-ground fault and fail to pick-up and subsequently issue a trip signal.
  • the zero sequence element 114 and the negative sequence element 115 are included in the relay logic because they operate regardless of the fault resistance.
  • neither the zero sequence element 114 nor the negative sequence element 115 can detect a "balanced" three-phase fault.
  • the second AND-gate 118 are included to enable blocking of the outputs 87LG and 87L2 in the event of current transformer saturation.
  • the first AND-gate 117 includes a first input coupled to the zero-sequence element output and a second inverting input coupled to an output of the CT saturation detector 116, and the second AND-gate 118 includes a first input coupled to the negative- sequence element output and a second inverting input coupled to the output of the CT saturation detector 116.
  • Each of the A-phase element 111 , the B-phase element 112, the C- phase element 113, the zero-sequence element 114 and the negative- sequence element 115 operate with respect to an alpha plane having a real and an imaginary axis.
  • current-ratio trajectories e.g.,
  • I AR 11 AL in the alpha plane are computed as a phasor ratio of the two
  • the alpha plane provides a geometrical representation of the current-ratio trajectories in the complex plane. It is well established that any percentage differential characteristic can be mapped into the alpha plane such that the area of stability (“stability area”) where tripping does not occur, and the area of tripping ("trip area”) where tripping does occur, can be determined as a function of basic relay characteristic parameters.
  • FIG. 4 is an exemplary alpha-plane 140 that may be used to determine a trip condition based on a current ratio trajectory.
  • a differential element characteristic is embedded in the alpha-plane 140.
  • the alpha-plane 140 includes a real axis 141 , an imaginary axis 142, a stability area 143 configured in a rainbow fashion, and a trip area 144.
  • Current ratios are computed by dividing the remote current by its corresponding local current. For example, when computing an A-phase current
  • the remote A-phase current phasor I M is divided by the A-phase
  • the trajectory of the vector, or the current-ratio trajectory, either in the trip area 144 or the stability area 143, is determinative of whether the corresponding current element binary output (e.g., 87LA) has high value (e.g., 1) or a low value (e.g., 0). It should be noted that prior to computing the current ratio, verification is made that the absolute value of the sum of the local and remote current
  • phasors e.g., I l A ⁇ _ +IAR I
  • a minimum pickup current a.k.a.
  • the current ratio trajectory resulting from a fault occurring on the transmission line 22 may be affected by a number of factors. These factors include the nature of the current ratio, phase or sequence currents, the transmission line loading and length, the level of fault resistance, the level of current transformer saturation, if any, the presence of a pole open, and the presence of capacitive series compensation. The most complex current ratio trajectories will depend upon a combination of these factors.
  • fault resistance R F is a factor in the determining current
  • FIG. 5 is an exemplary schematic diagram 150 of a short transmission line 152 having negligible shunt capacitance, that may be used to understand the
  • the schematic diagram 150 includes first and second generators 154 and 156, a first (left) bus 158 and a second (right) bus 160.
  • a fault occurring on a transmission line such as an A-phase-to-ground fault occurring on the short transmission line 152, at the fault location d 162
  • FIG. 6 is sequence network 170 that may be used to resolve the A-phase-to-ground fault at location d indicated in FIG. 5.
  • the superposition principle includes applying a voltage at the fault location d 162 to the "faulted" sequence network 170.
  • the applied voltage is equal to a voltage existing at the fault location d 162, prior to the fault.
  • a total fault current at some location on the sequence network 170 is equal to the load current existing before the fault, plus the pure-fault current (current void of any load) existing on the faulted network.
  • a total fault current (e.g., 20 KA) is the sum of the pre-fault current or load current (e.g., 1000A), plus the pure fault current (e.g., 19KA) [0059]
  • the pre-fault current or load current e.g. 1000A
  • the pure fault current e.g., 19KA
  • ZlM is the impedance between the left-source VA at the first generator 154 and the fault location d 162 where:
  • ZlN is defined as:
  • sequence network 170 is:
  • ZOM and ZON being defined as:
  • sequence current is equal to the source voltage E f divided by the total
  • I2F and /OF are equal to the pure fault positive-sequence
  • the left-side positive-sequence current RL , the left-side negative- sequence current I2L and the left-side zero-sequence current /OI at the relay location close to the left bus 158 are provided as:
  • I1L C1 * I1F (11 )
  • C1 and CO are the sequence current distribution factors at the relay location close to the left bus 158, and are equal to:
  • the right-side positive-sequence current /Ii? , the right-side negative- sequence current I2R and the right-side zero-sequence current I0R at the relay location close to the right bus 160 are provided as:
  • IAR [2 (1- Cl) +(l- CO)] HF - I LD IAL ⁇ (2 Cl + CO) IlF + I 1 LD
  • the current ratio at the relay (either the left-side or right- side) is dependent on the sequence current distribution factors CO and C1, and
  • sequence current I ⁇ F decreases.
  • the pure fault positive-sequence current I ⁇ F is equal to zero, and the current ratio is simply
  • IAR IAL but are out of phase by 180 degrees. Accordingly, the current ratio falls in the stability area 143 in the alpha plane 140 (see, FIG. 4).
  • IAR current ratio is independent from the pure fault positive-sequence current
  • IAR the A-phase current ratio, or A-phase fault current ratio can be
  • Equation 27 indicates that the A-phase current ratio depends upon another ratio of the load current (current flowing into the A-phase line prior to the fault) upon the pure fault positive-sequence current HF at the fault.
  • the A-phase element becomes insensitive to a fault when the ratio of the load current over pure fault positive-sequence current HF assumes low
  • phase elements 111 , 112 and 113 become blind to the fault.
  • sequence elements 114 and 115 are typically added to a relay's current differential protective scheme in order to detect highly resistive faults that may go undetected by phase elements 111-113 that have become insensitive to the fault.
  • sequence network impedances e.g., ZRl, ZZl, ZS 1 I .
  • the zero-sequence and negative-sequence elements 114 and 115 of FIG. 3 utilize a minimum sequence (negative or zero) differential pick-up current. As a result, they will
  • the load current I LD is the current that existed in the
  • IAR load current L n is removed from the A-phase current ratio , like the zero- w IAL
  • A-phase current ratio depends only on the sequence current distribution factors CO, Cl and accordingly, on the fault location d 162 and the sequence network
  • the zero- sequence element 114 and/or the negative-sequence 115 may fail to operate properly for highly resistive faults (i.e., high fault resistance )R f .
  • highly resistive faults i.e., high fault resistance
  • FIG. 7 is a sequence network diagram 200 that may be used to resolve a
  • the positive-sequence node (N1) includes a left-side source positive- sequence impedance ZSl 201 , a right-side source positive-sequence impedance ZRl 203, and a line positive-sequence impedance ZLl 202.
  • the negative-sequence node (N2) includes a left-side source negative-sequence impedance ZSl 205, a right-side source negative- sequence impedance ZRl 207, and a line negative-sequence impedance ZLl 206.
  • the zero-sequence node includes a left-side source zero-sequence impedance ZSO 209, a right-side source zero-sequence impedance ZRO 211 and a line zero-sequence impedance ZLO 208.
  • sequence voltages Fj ⁇ , V 2 ⁇ , V 0 between x and y may be expressed as:
  • the sequence network diagram 200 of FIG. 7 may be used to resolve unknown positive-, negative- and zero-sequence currents RL 212, 721 214 and/01 216, as follows:
  • I ⁇ L pr ⁇ , I2L pr ⁇ , I0L pre ⁇ during the B-phase pole open condition may be
  • IAR pr ⁇ The A-phase pre-fault current on the right-side, denoted as IAR pr ⁇ , is
  • FIG. 8 is yet another sequence network diagram 220 that may be used to resolve an A-phase-to-ground fault occurring during the B-phase pole open condition of the transmission line of FIG.5.
  • the positive-sequence node includes the left-side source positive-sequence impedance ZSl 201 , the right- side source positive-sequence impedance ZRl 203 and the line positive- sequence impedance ZLl 202.
  • the negative-sequence node includes the left-side source negative-sequence impedance ZS2 205, the right-side source negative-sequence impedance ZRl 207 and the line negative- sequence impedance ZL2 206.
  • the zero-sequence node includes the left-side source zero-sequence impedance ZSO 209, the right-side source zero- sequence impedance ZRO 211 and the line zero-sequence impedance ZLQ
  • the sequence network diagram 220 of FIG. 8 is equivalent to the sequence network diagram 200 of FIG. 7 with the addition of the A- phase-to-ground fault, after occurrence of the A-phase-to-ground fault, the new sequence currents HL 222, /21 224 and /OZ 226 may be expressed as Equation (41) where:
  • the pure fault positive sequence current HF at the fault location (fault current 228) and the left-side sequence currents RL 222, /21 224 and /OZ 226 after the A-phase-to- ground fault may be expressed as:
  • the A-phase-to-ground fault may be computed as a sum of the three left-side sequence currents RL 222, III 224 and /OZ 226 after the A-phase-to-ground fault:
  • the right-side sequence currents /Ii? 230, I2R 232 and /Oi? 234 after the A-phase-to-ground fault may be expressed as:
  • the right-side A-phase current after the A-phase-to-ground fault is equal to the sum of the right-side sequence currents /Ii? 230, I2R 232 and /Oi? 234:
  • equations (47) - (49) associated with the right bus 160, and the pre- fault sequence current equations (36) - (38), the equations for the sequence currents at both extremities (i.e., the left and the right) include a first pre-fault
  • left- and right-side A-phase current equations (46) and (50) may be expressed as:
  • IAR IAR pr ⁇ J 2 + P ⁇ q -0.5( mi +2 ni ) + 3m ⁇ np ⁇ m+2 n ⁇ 2m) [00102]
  • I I pre fl, + func (d, ZSl, ZLl, ZRl, ZSO, ZLO, ZRO) HF (59)
  • any current may be expressed as the sum of the current existing before the fault, plus the product of a function "func" by the pure fault positive sequence current HF flowing into the fault in its respective sequence network.
  • the function "func” is a function of the fault location d 162 and network impedances only.
  • the pure fault positive sequence current HF is a function of the fault location d 162, network impedances, the voltages generated by the first and second
  • IF func (d, ZSl, ZLl, ZRl, ZSO, ZLO, ZRO, Rf , VA, VB) (60)
  • the current ratio of the A-phase element 111 (see, FIG. 3) during an A-to-ground fault under a B-phase pole open condition is provided as:
  • the pure fault positive sequence current HF is given as a function of the distance d to the fault, the network impedances and the two sources voltages.
  • equation (61) shows that the current ratio trajectory of the A-phase element 111 (see, FIG. 3) for a single pole-open condition is dependant upon the fault location d, the network
  • the A- phase element 111 becomes insensitive to the fault at a threshold fault
  • both of the zero-sequence element 114 and the negative-sequence element 115 are dependant on the pure fault
  • FIG. 9 is yet another alpha plane 260 that may be used to plot the negative-sequence current ratio trajectory of the transmission line of FIG. 5 under the conditions of FIG. 8.
  • the alpha plane 260 includes the stability area 242.
  • the negative-sequence current ratio trajectory I2L enters the stability area 242 at about 27 ohms.
  • equation (30) removal of the load current existing prior to the fault (see, equation (21)) removes the dependency of the A-, B-, and C-phase elements 111-113 on the fault resistance, thereby restoring their ability to operate properly at higher fault resistances.
  • the A-, B-, and C-phase elements 111-113 operate properly to detect a fault while the zero-sequence and negative- sequence elements 114, 115 do not operate due to the "balanced" conditions.
  • FIG. 10 is yet a further alpha plane 280 illustrating the compensated vs. non-compensated negative-sequence current ratio trajectories during a single- pole open condition and concurrent single-phase-to-ground fault, according to an embodiment of the invention. As illustrated in FIG.
  • a first trajectory 282 representative of the non-compensated negative-sequence current ratio falls within the stability area 242. Accordingly, the A-phase-to-g round fault remains undetected by the negative-sequence current element 115; the negative- sequence current element 115 is insensitive to the fault.
  • a second trajectory 284, representative of the compensated negative-sequence current ratio where the pre-fault sequence current is removed does not fall within the stability area 242. Rather, it falls in the trip area. Accordingly, the A-phase-to-ground fault is detected by the negative- sequence current element 115 during the pole open condition; the negative- sequence current element 115 is sensitive to the fault and operates properly.
  • removal of the pre-fault sequence currents during a phase-to-ground fault with a concurrent pole-open condition renders both of the negative-sequence element 115 and the zero-sequence element 114
  • a long transmission line typically includes a shunt or charging current component.
  • each of the A-, B- and C-phase currents will include a shunt component representing the current drawn by the shunt capacitance, and a load current component representing the current flowing in the transmission line.
  • corresponding Iocal and remote shunt currents will have a phase difference close to zero degrees, each of the local and remote shunt currents is perceived by the A-phase element 111 , the B-phase element 112 and the C-phase element 113 as an internal fault.
  • the pickup current setting for each of the A-phase element 111 , the B-phase element 112 and the C-phase element 113 is preferably selected to be equal to a value that is twice the maximum shunt current tb avoid erroneous relay operation.
  • the shunt components of the A-phase, B-phase and C-phase currents are balanced, yielding an almost zero negative-sequence and zero-sequence current and rendering the impact of shunt currents on the zero-sequence element 114 and the negative- sequence element 115 negligible.
  • the shunt components of the A-phase, B-phase and C-phase currents are unbalanced. As a result, the shunt components are seen by the zero-sequence and the negative-sequence elements 114, 115 as an internal fault.
  • the pickup current setting for each of the zero-sequence and the negative-sequence elements 114, 115 is preferably equal to twice the maximum phase shunt current (where the zero-sequence and the negative- sequence shunt current at each extremity is equal to one-third of the magnitude of each shunt phase current).
  • FIG. 11 is an exemplary logic circuit diagram 300 for compensating the sensitivity of a negative-sequence element scheme of the local line current differential relay 50, according to an embodiment of the invention.
  • the remote line current differential relay 52 may be identically configured and operable.
  • the logic of FIG. 11 is equally applicable to the zero-sequence element 114 as well as to all three phase elements 111 , 112 and 113 of the local line current differential relay 50. Further, the logic of FIG. 11 is also applicable to phase and sequence elements of other suitable protective relays. [00119] FIG.
  • first and second negative-sequence elements 302, 304 similarly configured and operable as described in connection with FIGs. 3 and 4. Unlike FIG. 3 however where only one negative-sequence element is included in the relay logic, inclusion of the second negative-sequence element 304 enables the local differential relay 50 to respond to additional power system conditions. As described below, the first negative-sequence element 302 utilizes conventional phasor inputs while the second negative-sequence element 304 utilizes compensated inputs.
  • the first delta filter 306 includes a first phasor input configured to receive a local negative-sequence current phasor 309 I2L , and a first output configured to provide a local delta filter output signal 311 , in this case a compensated local negative sequence current phasor, to the second negative-sequence element 304.
  • the second delta filter 308 includes a second phasor input configured to receive a remote negative-sequence current phasor 313 I2R , and a second output configured to provide a remote delta filter output signal 315, in this case a compensated remote negative-sequence current phasor, to the second negative-sequence element 304.
  • Logic circuit diagram 300 also includes first and second timers 310 and
  • first and second AND-gates 314 and 316, and first and second OR-gates 318 and 320 are used to delay issuance of a trip signal to an associated breaker in the event of a fault where a magnitude of digitized current signal (representative of a measured secondary current) is greater than or equal to a . predetermined pickup value. More specifically, in addition to being used to delay issuance of a trip signal, under certain conditions the first and second timers 310, 312 are independently used to delay operation of the first and second negative sequence elements 302, 304.
  • the first timer 310 when enabled via an occurrence of a single pole-open condition (occurring subsequent to the clearing of a phase-to-ground fault), the first timer 310 prevents the second negative-sequence element 304 from operating for a number of power cycles, for example, four power cycles. This delay provides the time necessary to ensure that constant shunt current present in the protected line is removed from the local and remote delta filter output signals 311 , 315 received by the second negative-sequence element 304. While described as preferably having a four power cycle time-out period, it is contemplated that the first and second timers 310 and 312 may have other time-out periods, such as five power cycles or three power cycles, depending on the parameter settings of the associated protective relay.
  • a binary low value at the inverting input of the second timer 312 initiates a second timer countdown.
  • a binary high value for the second AND-gate output signal 337 temporarily prevents the second negative-sequence element 304 from operating for a number of power cycles of the second timer countdown, for example, five power cycles.
  • operation of the second negative-sequence element 304 resumes.
  • the first AND-gate 314 includes one inverting input configured to receive a first timer output, one non-inverting input configured to receive a first inhibit logic signal 330 upon an occurrence of a single pole-open condition and an output configured to provide a first AND-gate output signal 333 to the second OR-gate 320.
  • the second AND-gate 316 includes two inverting inputs, one configured to receive a second timer output signal and one configured to receive a three open-pole logic signal, and an output configured to provide a second AND-gate output signal 337 to the second OR-gate 320.
  • the first OR- gate 318 includes an input configured to receive an 87L2_A output signal, or a first negative-sequence element output signal 341 , and an input configured to receive an 87L2_B output signal, or a second negative-sequence element output signal 343.
  • the first OR-gate also includes an output configured to provide an 87L2 output signal, or a final negative-sequence output signal 332.
  • a binary logic high value for the final negative-sequence output signal 332 indicates a trip condition (e.g., one of the negative-sequence current ratios
  • FIG. 12 is a more detailed diagram of the first delta filter 306.
  • the second delta filter 308 is identically configured and operable to the first delta filter 306.
  • the first delta filter 306 includes a delay filter 322 and an adder 326.
  • the delay filter 322 includes an input to receive a time- invariant form of the local negative-sequence current phasor 309 I2L .
  • An output of the delay filter 322 provides a local reference signal 323 to an adder 326.
  • the local reference signal 323 is a delayed phasor provided by the delay filter 322 as a delayed version of the local negative-sequence current phasor 309 /21.
  • the delay is equal to a predetermined number of power cycles determined by a delay timer interval DT . For example, if the delay time interval is two, then two power cycles after it is received by the delay filter 322, the local negative-sequence current phasor is provided to the adder 326 as the local reference signal 323.
  • the local reference signal 323 is subtracted from the local negative-sequence current phasor 309 I2L to form the local delta filter output signal 311. Accordingly, the local delta filter output signal 311 is equal to the time-invariant form of the local negative-sequence current phasor 309 /21 minus the same time-invariant form of the local negative-sequence current phasor I2L , delayed by the delay time interval DT . Thus, upon a phase-to-ground fault, the local delta filter output 311 is equal to the negative-sequence current minus the negative sequence pre-fault current, but only during the subsequent delay time interval DT .
  • each of the first and second negative-sequence elements 302 and 304 is determined by the conditions and configuration of the power system 10. In general, both of the first and second negative-sequence elements 302, 304 operate simultaneously. It should be noted however, that when no poles are open and no fault is occurring, the power system 10 is "balanced". As a result, each of the local and remote delta filter output signals 311 , 315 is almost zero, yielding a binary logic low value for the second negative-sequence element output signal 343.
  • Other operation conditions of the logic of FIG. 11 include:
  • an enable single-pole tripping signal 335 prevents operation of the second negative-sequence element 304 via a binary logic high value for the second inhibit logic signal 339 provided by the second OR-gate 320.
  • both the first and second negative-sequence elements 302 and 304 operate simultaneously.
  • the first inhibit logic signal 330 has the binary logic high value as long as the single-phase pole-open condition persists; the first negative-sequence element 302 is disabled.
  • the second negative-sequence element 304 is temporarily disabled for a number of power cycles determined by the first timer 310.
  • operation of the second negative-sequence element 302 resumes.
  • temporary disabling of the second negative-sequence element 304 enables shunt current components to be removed from the local and remote delta filter output signals 311 , 315 utilized by the second negative-sequence element 304. .
  • the first negative-sequence element 302 during normal operation, when the first inhibit logic signal 330 is, for example, a binary low value (e.g., a logic 0), indicating the absence of a pole-open condition on the monitored line, the first negative-sequence element 302 utilizes the local negative-sequence current phasor I2L 309 and the remote negative-sequence current phasor I2R 313 to determine the (binary) value of first negative-sequence element output signal 341 as described in connection with FIG. 3. If the first negative-sequence element output signal 341 has a binary low value, then the trajectory of the corresponding negative-sequence
  • Temporarily inhibiting operation of the second negative-sequence element 304 for a period of a few power cycles provides the time necessary to remove any undesirable shunt current effects appearing in the local and remote delta filter output signal 311 , 315.
  • shunt current components are included in the local and remote negative-sequence current phasors 309, 313 (and the zero-sequence currents) upon an occurrence of the single open-pole condition as the power system 10 transitions from a balanced state to an "unbalanced" state.
  • the local reference signal 323 is equivalent to the local negative-sequence current phasor 309 delayed by the delay time interval DT .
  • the time delay interval DT is preferably less than the countdown period of both the first and second timers 310 and 312, it is contemplated that the time delay interval DT may be equal to the countdown period of one or more of the first and second timers 310 and 312.
  • the local delta filter output signal 311 remains equal to the fault sequence current phasor minus the sequence current phasor existing before the fault occurrence.
  • FIG. 13 is a latching delta filter system 350 that may be used to maintain the local and remote reference signal 323, 325 for a time period longer than the delay time interval DT .
  • the latching filter system 350 includes a local latching delta filter 352 and a remote latching filter 354 operatively coupled to a latching and toggle control circuit 356. Although only the local latching delta filter 352 is shown is shown in detail, it should be understood that the remote latching delta filter 354 is configured and operable as described in connection with the local latching delta filter 352.
  • the local latching delta filter 352 includes a first input configured to receive the local negative-sequence current phasor 309, a second input configured to receive a latching signal 351 , a third input configured to receive a toggle control signal 353, and a output configured to provide local latching delta filter output signal 355 to the second negative-sequence element 304.
  • the local latching delta filter 352 also includes the delay filter 322, the adder 326, a latched memory register 358, and a toggle switch 360 operatively coupled to the delay filter 320, the adder 326 and the latched memory register 358.
  • the latched memory register 358 includes an input for receiving the local reference signal 323, and an output configured to provide a latched local reference signal 371.
  • the local reference signal 323 associated with the fault i.e., the reference signal that reflected the current just prior to the occurrence of the fault
  • the latched local reference signal 323 is constant and non-changing and can be used over a time interval beyond the delay time interval DT , thus extending the fault detection interval during an open pole condition.
  • the delay time interval DT of the delay filter 320 may be reduced to one power cycle.
  • the latching and toggle control circuit 356 includes a rising-edge triggered mono-stable pulse generator, or pulse generator 362, having an input configured to receive a latching condition signal 363 and an output configured to provide an edge-triggered pulse 365 to the latched memory register 358 when the latching condition signal 363 has a binary high value. Also included is a control timer 366 having an input configured to receive the latching condition signal 363, and toggle control AND-gate 364 having a first input configured to receive the latching condition signal 363, a second inverting input configured to receive a control timer output signal 367, and an output configured to provide a toggle control signal 353 to the toggle switch 360.
  • the toggle switch 360 is configured in a first position to route the local reference signal 323 directly to the adder 326 for operation as described above in connection with FIGs. 11 and 12.
  • the latching condition signal 363 transitions from a binary low value to a binary high value.
  • a latching signal 351 provided by the pulse generator 362 causes the current local reference signal 323 to be latched into the latched memory register 358.
  • the binary high value for the latching condition signal 363 also initiates a countdown timer period of the control timer 366.
  • the value of time period of countdown is pre-selected and may therefore be one of any number of countdown timer periods (e.g., five power cycles).
  • a binary high value of the toggle control signal 353 causes the toggle switch 360 to be configured in a second position such that the latched local reference signal 371 is provided to the adder 326.
  • the toggle control signal 353 transitions to a binary low value and the toggle switch 360 reverts back to its first position.
  • the latched local reference signal 371 is provided for use local negative-sequence element 115 for a time period equivalent to the toggle switch countdown timer period rather than for the shorter the delay time interval DT provided by the delay filter 322.
  • a system, an apparatus and a method disclosed herein enables current differential protection during a single-phase pole-open condition via compensating, or adjusting the sensitivity of, the negative- and zero-sequence elements of the protective device in order to ensure their proper operation during a phase-to-ground fault with a high fault resistance.
  • the compensation is accomplished via the removal of pre-fault currents from the post-fault currents utilized by the negative- and zero-sequence elements to provided the differential protection.

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Abstract

L'invention concerne un appareil et un procédé qui compensent la sensibilité d'au moins un élément différentiel de courant du secteur d'un premier relais différentiel de courant procurant une protection différentielle pour une ligne de transmission d'un système de puissance pendant un état de pôle monophasé ouvert. L'appareil inclut un premier filtre en triangle configuré pour éliminer un premier courant de pré défaut à partir d'un premier courant de défaut de la ligne de transmission afin d'en déduire un premier vecteur compensé de Fresnel en courant. L'appareil inclut également un second filtre en triangle configuré pour éliminer un second courant de pré défaut à partir d'un second courant de défaut de la ligne de transmission pour en déduire un second vecteur compensé de Fresnel en courant. Les premier et second vecteurs compensés de Fresnel en courant sont appliqués à l'élément ou aux éléments différentiels de courant du secteur afin de compenser la sensibilité du ou des éléments différentiels de courant du secteur.
PCT/US2006/035175 2006-01-23 2006-09-08 Systeme, appareil et procede pour compenser la sensibilite d'un element de sequence dans un relais differentiel de courant du secteur dans un systeme de puissance WO2007086944A2 (fr)

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