1MRK 505 377-UEN Rev. P Section 7 Differential protection Section 7 7.1 7.1.1 Differential protection High impedance differential protection, single phase HZPDIF Identification IP14239-1 v4 M14813-1 v4 IEC 61850 identification Function description High impedance differential protection, single phase IEC 60617 identification Id HZPDIF ANSI/IEEE C37.2 device number 87 SYMBOL-CC V2 EN-US 7.1.2 Functionality M13071-3 v13 High impedance differential protection, single phase (HZPDIF) functions can be used when the involved CT cores have the same turns ratio and similar magnetizing characteristics. It utilizes an external CT secondary current summation by wiring. Actually all CT secondary circuits which are involved in the differential scheme are connected in parallel. External series resistor, and a voltage dependent resistor which are both mounted externally to the IED, are also required. The external resistor unit shall be ordered under IED accessories in the Product Guide. HZPDIF can be used to protect tee-feeders or busbars, reactors, motors, auto-transformers, capacitor banks and so on. One such function block is used for a high-impedance restricted earth fault protection. Three such function blocks are used to form three-phase, phase-segregated differential protection. 7.1.3 Function block M13737-3 v3 HZPDIF ISI* BLOCK BLKTR TRIP ALARM MEASVOLT IEC05000363-2-en.vsd IEC05000363 V2 EN-US Figure 39: 7.1.4 HZPDIF function block Signals IP14244-1 v2 PID-6990-INPUTSIGNALS v1 Table 83: HZPDIF Input signals Name Type Default Description ISI GROUP SIGNAL - Single phase current input BLOCK BOOLEAN 0 Block of function BLKTR BOOLEAN 0 Block of trip Line differential protection RED670 Technical manual 147 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P PID-6990-OUTPUTSIGNALS v1 Table 84: HZPDIF Output signals Name 7.1.5 Type Description TRIP BOOLEAN Trip signal ALARM BOOLEAN Alarm signal MEASVOLT REAL Measured RMS voltage on CT secondary side Settings IP14245-1 v2 PID-6990-SETTINGS v1 Table 85: HZPDIF Group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Off / On U>Alarm 5 - 500 V 1 10 Alarm voltage level in volts on CT secondary side tAlarm 0.000 - 60.000 s 0.001 5.000 Time delay to activate alarm U>Trip 10 - 900 V 1 100 Operate voltage level in volts on CT secondary side SeriesResistor 50 - 20000 Ohm 1 250 Value of series resistor in Ohms 7.1.6 Monitored data PID-6990-MONITOREDDATA v1 Table 86: HZPDIF Monitored data Name MEASVOLT 7.1.7 Type REAL Values (Range) - Unit kV Operation principle Description Measured RMS voltage on CT secondary side IP14242-1 v2 M13075-3 v11 High impedance protection system is a simple technique which requires that all CTs, used in the protection scheme, have relatively high knee point voltage, similar magnetizing characteristic and the same ratio. These CTs are installed in all ends of the protected object. In order to make a scheme all CT secondary circuits belonging to one phase are connected in parallel. From the CT junction points a measuring branch is connected. The measuring branch is a series connection of one variable setting resistor (or series resistor) RS with high ohmic value and an over-current element. Thus, the high impedance differential protection responds to the current flowing through the measuring branch. However, this current is result of a differential voltage caused by this parallel CT connection across the measuring branch. Non-linear resistor (that is, metrosil) is used in order to protect entire scheme from high peak voltages which may appear during internal faults. Typical high impedance differential scheme is shown in Figure 40. Note that only one phase is shown in this figure. 148 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection RS 3 I U 1 I> (50) 5 4 2 GUID-5CEAF088-D92B-45E5-B98F-3083894A694C V1 EN-US Figure 40: HZPDIF scheme Where in the Figure: 1. 2. shows one main CT secondary winding connected in parallel with all other CTs, from the same phase, connected to this scheme. shows the scheme earthing point. It is of utmost importance to insure that only one earthing point exists in such protection scheme. 3. 4. shows the setting (stabilizing) resistor RS. shows the over-current measuring element. The series connection of stabilizing resistor and over-current element is designated as measuring branch. 5. 6. 7. shows the non-linear resistor (that is, metrosil). U is the voltage across the CT paralleling point (for example, across the measuring branch). I is the current flowing through the measuring branch. U and I are interrelated in accordance with the following formula U=RS × I. Due to the parallel CT connections the high impedance differential relay can only measure one current and that is the relay operating quantity. That means that there is no any stabilizing quantity (that is, bias) in high-impedance differential protection schemes. Therefore in order to guaranty the stability of the differential relay during external faults the operating quantity must not exceed the set pickup value. Thus, for external faults, even with severe saturation of some of the current transformers, the voltage across the measuring branch shall not rise above the relay set pickup value. To achieve that a suitable value for setting resistor RS is selected in such a way that the saturated CT secondary winding provides a much lower impedance path for the false differential current than the measuring branch. In case of an external fault causing current transformer saturation, the non-saturated current transformers drive most of the spill differential current through the secondary winding of the saturated current transformer and not through the measuring brunch of the relay. The voltage drop across the saturated current transformer secondary winding appears also across the measuring brunch, however it will typically be relatively small. Therefore, the pick-up value of the relay has to be set above this false operating voltage. See the application manual for operating voltage and sensitivity calculation. Line differential protection RED670 Technical manual 149 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 7.1.7.1 1MRK 505 377-UEN Rev. P Logic diagram M13075-9 v5 The logic diagram shows the operation principles for the 1Ph High impedance differential protection function HZPDIF, see Figure 41. The function utilizes the raw samples from the single phase current input connected to it. Thus the twenty samples per fundamental power system cycle are available to the HZPDIF function. These current samples are first multiplied with the set value for the used stabilizing resistor in order to get voltage waveform across the measuring branch. The voltage waveform is then filtered in order to get its RMS value. Note that used filtering is designed in such a way that it ensures complete removal of the DC current component which may be present in the primary fault current. The voltage RMS value is then compared with set Alarm and Trip thresholds. Note that the TRIP signal is intentionally delayed on drop off for 30 ms within the function. The measured RMS voltage is available as a service value from the function. The function has block and trip block inputs available as well. IEC05000301 V1 EN-US Figure 41: 7.1.8 Logic diagram for 1Ph High impedance differential protection HZPDIF Technical data IP14246-1 v1 M13081-1 v13 Table 87: HZPDIF technical data Function Range or value Accuracy Operate voltage (10-900) V I=U/R ±1.0% of Ir at I ≤ Ir ±1.0% of I at I > Ir Reset ratio >95% at (30-900) V - Maximum continuous power See1) - Operate time at 0 to 10 x Ud Min. = 5 ms Max. = 15 ms Reset time at 10 x Ud to 0 Min. = 75 ms Max. = 95 ms Critical impulse time 2 ms typically at 0 to 10 x Ud - Table continues on next page 150 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Function Range or value Accuracy Operate time at 0 to 2 x Ud Min. = 25 ms Max. = 35 ms Reset time at 2 x Ud to 0 Min. = 50 ms Max. = 70 ms Critical impulse time 15 ms typically at 0 to 2 x Ud - 1) The value U2Trip/ R should always be lower than Stabilizing resistor thermal rating to allow continuous activation during testing. If this value is exceeded, testing should be done with a transient faults. Typical value for the thermal rating of the resistor is 100W. 7.2 7.2.1 Low impedance restricted earth fault protection REFPDIF Function revision history Document revision 7.2.2 Product revision IP14640-1 v6 GUID-BFAA47D8-C2B6-4EC2-9129-B031333BAD19 v2 History A 2.2.1 - B 2.2.1 - C 2.2.1 - D 2.2.2 - E 2.2.2 - F 2.2.2 - G 2.2.3 - H 2.2.3 - J 2.2.3 - K 2.2.3 - L 2.2.4 - M 2.2.4 The upper limit of ROA setting range is changed from 90 degrees to 119 degrees. N 2.2.5 - Identification M14843-1 v6 Function description Restricted earth fault protection, low impedance IEC 61850 identification IEC 60617 identification REFPDIF ANSI/IEEE C37.2 device number 87N IdN/I SYMBOL-AA V1 EN-US Line differential protection RED670 Technical manual 151 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 7.2.3 1MRK 505 377-UEN Rev. P Functionality IP12418-1 v2 M13047-3 v20 Restricted earth-fault protection, low-impedance function (REFPDIF) can be used on all directly or low-impedance earthed windings. The REFPDIF function provides high sensitivity and high speed tripping as it protects each winding separately and thus does not need inrush stabilization. The REFPDIF function is a percentage biased function with an additional zero sequence current directional comparison criterion. This gives excellent sensitivity and stability during through faults. REFPDIF can also protect autotransformers. Five currents are measured at the most complicated configuration as shown in Figure 42. CT YNdx CT CT CB CB d Y CB CB Autotransformer CT IED The most typical application CT CB CB CT The most complicated application - autotransformer IEC05000058-2-en.vsd IEC05000058-2 V1 EN-US Figure 42: 7.2.4 Examples of applications of the REFPDIF Function block M13736-3 v9 REFPDI F I3P* I3PW1CT1* I3PW1CT2* I3PW2CT1* I3PW2CT2* BLOCK TRIP START DIROK BLK2H IRES IN IBIAS IDIFF ANGLE I2RATIO IEC06000251-3-en.vsdx IEC06000251 V3 EN-US Figure 43: REFPDIF function block 152 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P 7.2.5 Section 7 Differential protection Signals IP12658-1 v2 PID-7411-INPUTSIGNALS v1 Table 88: REFPDIF Input signals Name Type Default Description I3P GROUP SIGNAL - Group signal for neutral current input I3PW1CT1 GROUP SIGNAL - Group signal for primary CT1 current input I3PW1CT2 GROUP SIGNAL - Group signal for primary CT2 current input I3PW2CT1 GROUP SIGNAL - Group signal for secondary CT1 current input I3PW2CT2 GROUP SIGNAL - Group signal for secondary CT2 current input BLOCK BOOLEAN 0 Block of function PID-7411-OUTPUTSIGNALS v1 Table 89: REFPDIF Output signals Name 7.2.6 Type Description TRIP BOOLEAN Trip by restricted earth fault protection function START BOOLEAN Start by restricted earth fault protection function DIROK BOOLEAN Directional Criteria has operated for internal fault BLK2H BOOLEAN Block due to 2-nd harmonic IRES REAL Magnitude of fund. freq. residual current IN REAL Magnitude of fund. freq. neutral current IBIAS REAL Magnitude of the bias current IDIFF REAL Magnitude of fund. freq. differential current ANGLE REAL Direction angle from zerosequence feature I2RATIO REAL Second harmonic ratio Settings IP12660-1 v2 PID-7411-SETTINGS v1 Table 90: REFPDIF Non group settings (basic) Name Values (Range) GlobalBaseSel Table 91: 1 - 12 Unit - Step 1 Default 1 Description Selection of one of the Global Base Value groups REFPDIF Group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Off / On IdMin 4.0 - 100.0 %IB 0.1 10.0 Maximum sensitivity in % of IBase CTFactorPri1 1.0 - 10.0 - 0.1 1.0 CT factor for HV side CT1 (CT1rated/ HVrated current) Table continues on next page Line differential protection RED670 Technical manual 153 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Name Values (Range) Unit Step Default Description CTFactorPri2 1.0 - 10.0 - 0.1 1.0 CT factor for HV side CT2 (CT2rated/ HVrated current) CTFactorSec1 1.0 - 10.0 - 0.1 1.0 CT factor for MV side CT1 (CT1rated/ MVrated current) CTFactorSec2 1.0 - 10.0 - 0.1 1.0 CT factor for MV side CT2 (CT2rated/ MVrated current) Table 92: REFPDIF Group settings (advanced) Name Values (Range) Unit ROA 60 - 119 7.2.7 Monitored data Step Deg 1 Default 60 Description Relay operate angle for zero sequence directional feature if protected winding neutral point is grounded via resistor increase ROA to 115 degrees PID-7411-MONITOREDDATA v1 Table 93: Name REFPDIF Monitored data Type Values (Range) Unit Description IRES REAL - A Magnitude of fund. freq. residual current IN REAL - A Magnitude of fund. freq. neutral current IBIAS REAL - A Magnitude of the bias current IDIFF REAL - A Magnitude of fund. freq. differential current ANGLE REAL - deg Direction angle from zerosequence feature I2RATIO REAL - - Second harmonic ratio 7.2.8 Operation principle 7.2.8.1 Fundamental principles of the restricted earth fault protection IP16290-1 v2 M5447-3 v16 Restricted earth fault protection, low impedance function (REFPDIF) detects earth faults on earthed power transformer windings, most often an earthed star winding. REFPDIF is a unit protection of the differential type. Since REFPDIF is based on the zero sequence current, which theoretically only exists in case of an earth fault, REFPDIF can be made very sensitive regardless of normal load currents. It is the fastest protection a power transformer winding can have. The high sensitivity and the high speed tend to make such a protection unstable. Special measures must be taken to make it insensitive to conditions for which it should not operate, for example, heavy through faults of phaseto-phase type or heavy external earth faults. REFPDIF is a differential protection of the low impedance type. All three-phase currents, and the neutral point current, must be fed separately to REFPDIF. The fundamental frequency components of all currents are extracted from all input currents, while other eventual zero sequence components, such as the 3rd harmonic currents, are fully suppressed. Then the residual current phasor is calculated from the three line current phasors. This zero sequence current phasor is added to the neutral current vectorially, in order to obtain differential current. The following facts may be observed from Figure 44 and Figure 45, where the three line CTs are shown as connected together in order to measure the residual 3Io current, for the sake of simplicity. 154 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection These three zero-sequence currents are not measured zone of protection Izs1 L1 Power system L1 Izs1 L2 L2 Izs1 L3 L3 3Izs1 Uzs IL1+ IL2+IL3 = 3I0 3I0 = 3Izs1 Ifault Current in the neutral (measured as IN ) serves as a directional reference because it has the same direction for both internal and external faults. IN = -3Izs1 (Summation in the IED) Return path through transformer Return path via power system External fault region block operate Zero-sequence differential current for external fault Idiff = abs(3I0 + IN ) Idiff = 3Izs1 - 3Izs1 = 0 IN 3I0 block ROA External fault region Internal fault region block ROA = Relay Operate Angle IEC09000107-3-en.vsd IEC09000107-3 V1 EN-US Figure 44: Zero sequence currents at an external earth fault zone of protection L1 Power system L2 L3 Izs2 Izs1 Izs2 Izs1 Izs2 Izs1 L1 L2 L3 3Izs1 Uzs IL1+ IL2+IL3 = 3I0 3I0 = -3Izs2 IN = -3Izs1 Ifault (Summation in the IED) Current in the neutral (measured as IN ) serves as a directional reference because it has the same direction for both internal and external faults. Return path through transformer Return path via power system External fault region block 3I0 block External fault region operate ROA block IN (reference) Zero-sequence differential current for internal fault Idiff = abs(3I0 + IN ) Idiff = 3Izs2 + 3Izs1 > 0 Idiff = Ifault Internal fault region ROA = Relay Operate Angle IEC09000108-3-en.vsd IEC09000108-3 V1 EN-US Figure 45: 1. 2. Zero sequence currents at an internal earth fault For an external earth fault (Figure 44), the residual current 3Io and the neutral current IN have equal magnitude, but they are seen within the IED as 180 degrees out-of-phase if the current transformers are connected as in Figure 44, which is the Hitachi Power grids recommended connection. The differential current becomes zero as both CTs ideally measure exactly the same component of the earth fault current. For an internal fault, the total earth fault current is composed generally of two zero sequence currents. One zero sequence current (3IZS1) flows towards the power transformer neutral point and into the earth, while the other zero sequence current (3IZS2) flows into the connected power system. These two primary currents can be expected to have approximately opposite directions (about the same zero sequence impedance angle is assumed on both sides of the earth fault). Line differential protection RED670 Technical manual 155 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P 3. 4. However, on the secondary CT sides of the current transformers, they will be approximately in phase if the current transformers are oriented as in Figure 42, which is the orientation recommended by Hitachi Power grids. The magnitudes of the two currents may be different, dependent on the magnitudes of zero sequence impedances on both sides. No current can flow towards the power system, if the only point where the system is earthed, is at the protected power transformer. Likewise, no current can flow into the power system, if the winding is not connected to the power system (circuit breaker open and power transformer energized from the other side). For both internal and external earth faults, the current in the neutral connection IN always has the same direction, which is towards the earth (except in case of autotransformers where the direction can vary). The two internally processed zero sequence currents are 3Io and IN. The vectorial sum is the REFPDIF differential current, which is equal to Idiff = IN +3Io . The line zero sequence (residual) current is calculated from 3 line (terminal) currents. A bias quantity must give stability against false operations due to high through fault currents. To stabilize REFPDIF at external faults, an operate-bias characteristic is used. REFPDIF should also be stable against heavy phase-to-phase internal faults, not including earth. These faults may also give false zero sequence currents due to saturated line CTs. Such faults, however are without neutral current, and can thus be eliminated as a source of danger. As an additional measure against unwanted operation, a directional check is made in agreement with the above points 1 and 2. Operation is only allowed if the currents 3Io and IN (as shown in Figure 44 and Figure 45) are both within the operating region. By taking a smaller ROA, REFPDIF can be made more stable under heavy external fault conditions, as well as under the complex conditions, when external faults are cleared by other protections. 7.2.8.2 Restricted earth fault protection, low impedance differential protection M5447-20 v14 Restricted earth fault protection, (REFPDIF) is a protection of low impedance differential type, a unit protection, whose settings are independent of any other protection. It has some advantages compared to the transformer differential protection. It is less complicated, as no current phase correction or magnitude correction is needed, not even in the case of an eventual on-load tap changer (OLTC). REFPDIF is not sensitive to inrush and overexcitation currents. The thing to take into account is an eventual current transformer saturation. The differential protection REFPDIF calculates a differential current and a bias current. In case of internal earth faults, the differential current is theoretically equal to the total earth fault current. The bias to give stability to REFPDIF. The bias current is a measure of how high the currents are and how difficult the conditions are under which the CTs operate. With a high bias, difficult conditions can be suspected, and it will be more likely that the calculated differential current has a component of a false current, primarily due to CT saturation. This “law” is formulated by the operate-bias characteristic. This characteristic divides the Idiff - Ibias plane in two areas. The area above the operate-bias characteristic is the operate area (trip), while the one below is the restrain (block) area, see Figure 47. Calculation of operate bias characteristic End of zone 1: Endzone1 = 125% End of zone 2: Endzone2 = 156 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection EndZone2 = 125 + (100 − IdMin) 0.7 (Equation 2) IECEQUATION20201 V1 EN-US SlopeSection2: The slope in section 2 (see Figure 47) of operate-restrain characteristic is fixed to 70%. The slope section 2, starts at end of zone 1, continues until end of zone 2. SlopeSection3: The slope in section 3 (see Figure 47) of operate-restrain characteristic is fixed to 100%. The slope section 3, starts at end of zone 2 and continues. REFPDIF uses an operate-bias characteristic shown in Figure 47, using a setting IdMin see Table 7. Table 95: Setting range of IdMin, end zones and slopes IdMin default (zone 1) % of IBase IdMin min (zone 1) % of IBase 10 4 IdMin max (zone 1) % of IBase 100 End of zone 1 (fixed) % of IBase 125 Slope section 2 (fixed) % of IBase 70 Slope section 3 (fixed) % of IBase 100 IEC20000410-1-en.vsdx IEC20000410 V1 EN-US Figure 47: Representation of Operate-bias characteristics at different IdMin setting values Figure 47 represents the Operate-bias characteristics at different IdMin setting values The highest individual current contribution is taken as a common bias (restrain) current among all phase currents or neutral current. This "maximum principle" makes the differential protection more secure, with less risk to operate for external faults and in the same time brings more meaning to the breakpoint settings of the operate-restrain characteristic. 7.2.8.3 Calculation of differential current and bias current M5447-47 v13 The differential current (operate current), as a fundamental frequency phasor, is calculated as (with designations as in Figure 44 and Figure 45): Line differential protection RED670 Technical manual 157 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Idiff = IN + 3 Io (Equation 3) EQUATION1533 V1 EN-US where: IN is current in the power transformer neutral as a fundamental frequency phasor. 3Io is residual current of the power transformer terminal currents as a phasor. If there are two three-phase CT inputs, as in breaker-and-a-half configurations, then their respective residual currents are added within the REFPDIF function so that: I3PW1 = I3PW1CT1 + I3PW1CT2 where the signals are defined in the input and output signal tables for REFPDIF. The bias current is a measure (expressed internally as a true fundamental frequency current in Amperes) of how difficult the conditions are under which the instrument current transformers operate. Dependent on the magnitude of the bias current, the corresponding zone (section) of the operatebias characteristic is applied, when deciding whether to trip, or not to trip. In general, the higher the bias current, the higher the differential current required to produce a trip. The bias current is the highest current of all separate input currents to REFPDIF, that is, of current in phase L1, phase L2, phase L3, and the current in the neutral point (designated as IN in Figure and in Figure Figure). If there are two feeders included in the zone of protection of REFPDIF, as in case of an autotransformer with two feeders included on both sides, then the respective bias current is found as the relatively highest of the following currents: current 1 = max( I 3PW 1CT1) 1 CTFactor Pr i1 (Equation 4) EQUATION1526 V2 EN-US current 2 = max( I 3PW 1CT 2) 1 CTFactor Pr i 2 (Equation 5) EQUATION1527 V2 EN-US current 3 = max( I 3PW 2CT1) 1 CTFactorSec1 (Equation 6) EQUATION1528 V2 EN-US current 4 = max( I 3PW 2CT 2) 1 CTFactorSec2 (Equation 7) EQUATION1529 V2 EN-US current 5 = IN (Equation 8) EQUATION1530 V2 EN-US The bias current is thus generally equal to none of the input currents. If all primary ratings of the CTs were equal to IBase, then the bias current would be equal to the highest current in Amperes. IBase shall be set equal to the rated current of the protected winding where REFPDIF function is applied. 7.2.8.4 Detection of external earth faults M5447-75 v12 External faults are more common than internal earth faults for which the restricted earth fault protection should operate. It is important that the restricted earth fault protection remains stable 158 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection during heavy external earth and phase-to-phase faults, and also when such a heavy external fault is cleared by some other protection such as overcurrent, or earth fault protection. The conditions during a heavy external fault, and particularly immediately after the clearing of such a fault may be complex. The circuit breaker’s poles may not open exactly at the same moment, some of the CTs may still be highly saturated, and so on. The detection of external earth faults is based on the fact that for such a fault a high neutral current appears first, while a false differential current only appears if one or more current transformers saturate. An external earth fault is thus assumed to have occurred when a high neutral current suddenly appears, while at the same time the differential current Idiff remains low, at least for a while. This condition must be detected before a trip request is placed within REFPDIF. Any search for external fault is aborted if a trip request has been placed. A condition for a successful detection is that it takes not less than 4ms for the first CT to saturate. For an internal earth fault, a true differential current develops immediately, while for an external fault it only develops if a CT saturates. If a trip request comes first, before an external fault could be positively detected, then it must be an internal fault. If an external earth fault has been detected, then the REFPDIF is temporarily desensitized. Directional criterion M5447-110 v13 The directional criterion is applied in order to positively distinguish between internal and external earth faults. This check is an additional criterion, which should prevent malfunctions at heavy external earth faults, and during the disconnection of such faults by other protections. Earth faults on lines connecting the power transformer occur much more often than earth faults on a power transformer winding. It is important that the Restricted earth fault protection, low impedance (REFPDIF) must remain stable during an external fault, and immediately after the fault has been cleared by some other protection. For an external earth faults with no CT saturation, the residual current in the lines (3Io) and the neutral current (IN in Figure 44) are theoretically equal in magnitude and are 180 degrees out-ofphase. The current in the neutral (IN) serves as a directional reference because it has the same direction for both internal and external earth faults. The directional criterion in REFPDIF protection makes it a current-polarized protection. However, if one or more CTs saturate under external fault conditions, then the measured currents 3Io and IN may no longer be equal, nor will their positions in the complex plane be exactly 180 degrees apart. There is a risk that the resulting false differential current Idiff enters the operate area of the operate-restrain characteristic under external fault conditions. If this happens, a directional test may prevent a malfunction. A directional check is only executed if: 1. 2. a trip request signal has been issued (REFPDIF function START signal set to 1) the residual current in lines (3Io) is at least 3% of the IBase current. If a directional check is either unreliable or not possible to do, due to too small currents, then the direction is cancelled as a condition for an eventual trip. If a directional check is executed, the REFPDIF protection operation is only allowed if currents 3Io and IN (as seen in Figure 44 and Figure 45) are both within the operating region determined by the set value of ROA, in degrees. ROA = 60 to 119 deg; where ROA stands for Relay Operate Angle. Second harmonic analysis M5447-106 v13 When energizing a transformer a false differential current may appear in earth fault protection, low impedance function (REFPDIF). The phase CTs may saturate due to a high DC component with a Line differential protection RED670 Technical manual 159 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P long duration, but the current through the neutral CT does not have either the same DC component or the same amplitude and the risk for saturation of this CT is not as high. As a result, the differential current due to the saturation may be so high that it reaches the operate characteristic. A calculation of the content of 2nd harmonic in the neutral current is made when the neutral current, residual current and bias current are within some windows and some timing criteria are fulfilled. If the ratio between second and fundamental harmonic exceeds the preset value of 40% 40%, REFPDIF is blocked. 7.2.8.5 Algorithm of the restricted earth fault protection M5447-95 v14 1. Check if current in the neutral Ineutral (IN) is less than 50% of the base sensitivity Idmin. If yes, only service values are calculated, and rest of the REFPDIF algorithm is not executed. 2. If current in the Ineutral (IN) is more than 50% of Idmin, then determine the bias current Ibias. 3. Determine the differential (operate) current Idiff as a phasor, and calculate its magnitude. 4. Check if the point P(Ibias, Idiff) is above the operate-bias characteristic. If yes, increment the trip request counter by 1. If the point P(Ibias, Idiff) is found to be below the operate-bias characteristic, then the trip request counter is reset to zero. 5. If the trip request counter is still zero, search for an eventual heavy external earth fault. The search is only made if the neutral current is at least 50% of the Idmin current. If an external earth fault has been detected, a flag is set which remains set until the external fault has been cleared. The external fault flag is reset to zero when Ineutral falls below 50% of the base sensitivity Idmin. Any search for an external fault is aborted if trip request counter is greater than zero. 6. As long as the external fault persists, an additional temporary trip condition is introduced. This means that REFPDIF is temporarily desensitized. 7. If point P(Ibias, Idiff) is found to be above the operate-bias characteristic), so that trip request counter is greater than zero, a directional check can be made. The directional check is made only if Iresidual (3Io) is more than 3% of the IBase current. If the result of the check means “external fault”, then the internal trip request is reset. If the directional check cannot be executed, then direction is no longer a condition for a trip. 8. When neutral current, residual current and bias current are within some windows and some timing criteria are fulfilled, the ratio of 2nd to fundamental harmonic is calculated. If it is found to be above 40%, the trip request counter is reset and TRIP remains zero. 9. If point P(Ibias, Idiff) is found to be above the operate-bias characteristic), a directional check can be made. The directional check is made only if Iresidual (3Io) is more than 3% of the IBase current. If the result of the check means “external fault”, then the internal trip request is reset. If the directional check cannot be executed, then the direction is no longer a condition for a trip. 10. Finally, the trip request counter is checked. If the trip request counter is greater or equal than 2 and at the same time the actual bias current is at least 50% of the highest bias current Ibiasmax (Ibiasmax is the highest recording of any of the three phase currents measured during the disturbance), REFPDIF will set output TRIP to 1. Otherwise, the TRIP signal remains zero. 11. Finally, a check is made if the trip request counter is equal to, or higher than 2. If yes, and at the same instance of time tREFtrip, the actual bias current at this instance of time tREFtrip is at least 50% of the highest bias current Ibiasmax (Ibiasmax is the highest recording of any of the three phase currents measured during the disturbance), then REFPDIF sets output TRIP to 1. If the counter is less than 2, the TRIP signal remains zero. 7.2.9 Technical data IP12661-1 v1 M13062-1 v23 Table 96: REFPDIF technical data Function Range or value Accuracy Operating characteristic Adaptable ±1.0% of Ir at I ≤ Ir ±1.0% of I at I > Ir Reset ratio > 95% - Minimum pickup, IdMin (4.0-100.0)% of IBase ±1.0% of Ir Table continues on next page 160 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Function Range or value Accuracy Directional characteristic Fixed 180 degrees or ±60 to ±119 degrees ±2.0 degrees Operate time, trip at 0 to 10 x IdMin Min. = 15 ms Max. = 30 ms - Reset time, trip at 10 x IdMin to 0 Min. = 15 ms Max. = 30 ms - Second harmonic blocking 40.0% of fundamental ±1.0% of Ir 7.3 Line differential protection L4CPDIF 7.3.1 Function revision history Document revision 7.3.2 Product revision GUID-611723D0-41E1-4F50-B9F6-8E97948D348F v3 History A 2.2.1 - B 2.2.1 - C 2.2.1 - D 2.2.2 - E 2.2.2 - F 2.2.2 - G 2.2.3 Added charging currents ICL1, ICL2, and ICL3 as service values H 2.2.3 - J 2.2.3 - K 2.2.3 - L 2.2.4 - M 2.2.4 - N 2.2.5 - Identification GUID-690568A1-7B01-4FB6-B82E-7A50A886DE9D v2 Function description High speed line differential protection for 4 CT sets, 2-3 line ends IEC 61850 identification IEC 60617 identification L4CPDIF 3Id/I> ANSI/IEEE C37.2 device number 87L SYMBOL-HH V1 EN-US 7.3.3 Functionality GUID-57872A74-462D-4513-B75B-A46ADCE03522 v2 High speed line differential protection for 4 CT sets, 2-3 line ends (L4CPDIF) is a unit type protection system with typical operate time less than one cycle. These types of systems are suitable for the protection of complex transmission network configurations because they exhibit good performance during evolving, inter-circuit, and cross-country faults. They are also highly immune to power swings, mutual coupling and series impedance unbalances. High speed line differential protection requires 2 Mbit/s communication channel to transfer analog signals. Line differential protection RED670 Technical manual 161 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P The L4CPDIF function applies the Kirchhoff's law, and compares currents entering and leaving the protected multi-end circuit consisting of overhead power lines and cables. Under normal load conditions, the sum of currents is small or close to zero. The function is phase-segregated: each phase has its own differential, bias and incremental currents. L4CPDIF measures currents at all ends of a protected circuit. At each physical end, currents are mostly measured by one and sometimes by two three-phase current transformer (CT) groups. The voltages at all ends are also measured if the exact method is selected for charging current compensation. The protected zone is determined by the positions of the CTs at all ends of the protected circuit. L4CPDIF protects all electrical equipment, such as power lines, circuit breakers and small tap transformers, that are within the protected zone. The information on all locally measured currents is transmitted via communication channels to remote IEDs. Then L4CPDIF compares these currents using a classical current differential principle supplemented by an additional advanced internal fault detector. This results in fast protection with very high dependability (relay operates correctly with faults it was designed for) and very high security (relay does not operate with faults it was not designed for). 7.3.3.1 Possible configurations GUID-566BF5F0-3E2D-42D8-9D53-BCAFB7F0BEA9 v3 The simplest and most common configuration is the protection of a conventional two-end power line (see Figure 48). Circuit breakers (CBs) at both ends can be included in the protected zone depending on their positions relative to the current transformers (CTs). Protected zone IED IEC05000039 V3 EN-US Figure 48: Communication channel IED IEC05000039-3-en.vsd Two-end power line with one CB and one CT group at each end It is also possible to protect a two-end power line that has two CB and CT groups at one end and one CB and CT group at the other end (see Figure 49). All currents from the three CTs must be fed separately to L4CPDIF which processes the measured currents independently from each other. Summing up the CTs’ secondary currents at the end with two CB and CT groups is not allowed. CBs at both ends can be included in the protected zone depending on their positions relative to the CTs. IEC15000459-1-en.vsd IEC15000459 V1 EN-US Figure 49: Two-end power line with two CB and CT groups at one end If there are two CB and CT groups at both ends of a two-end power line, information on currents must be fed to all four current inputs of both IEDs. Current values at the remote end are obtained via a communication channel as shown in Figure 50. Summing up the CTs’ secondary currents at the end with two CB and CT groups is not allowed. CBs at both ends can be included in the protected zone depending on their positions relative to the CTs. 162 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection IEC15000460-1-en.vsd IEC15000460 V1 EN-US Figure 50: Two-end power line with two CB and CT groups at each end Figure 51 shows a three-end power line configuration where one end has two CB and CT groups. All four current inputs to IEDs are used. Current from each CT is fed to an IED, and currents from different CTs are processed separately by the protection algorithm. Summing up the CTs’ secondary currents at the end with two CB and CT groups is not allowed. CBs at all ends can be included in the protected zone depending on their positions relative to the CTs. IEC15000461-1-en.vsd IEC15000461 V1 EN-US Figure 51: Three-end power line with two CB and CT groups at one end The locally measured current samples are exchanged between all IEDs at line ends (in mastermaster mode) or sent for evaluation to one master IED from all slave IEDs (in master-slave mode). In master-master mode, all IEDs at different ends of a protected zone execute exactly the same program code with exactly the same information so the same response is expected from all masters. In master-slave mode, only one IED has access to all currents in the protected zone. It is always recommended to select the master-master mode if allowed by the number of communication links. When communication failure occurs, L4CPDIF function will be blocked. Under the blocking period, COMFBLKD will be set to indicate that L4CPDIF function is blocked by communication failure. Line differential protection RED670 Technical manual 163 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 7.3.4 1MRK 505 377-UEN Rev. P Function block GUID-E2714077-37D7-45A1-991D-03C3DBFB7173 v2 L4CPDIF I3P1* I3P2* I3P3* I3P4* U3P1* U3P2* U3P3* U3P4* BLOCK LOWSENEN CCBLK TRIP TRL1 TRL2 TRL3 START STL1 STL2 STL3 STUNR COMFBLKD BLKHL1 BLKHL2 BLKHL3 OPENCT DIFLBLKD TRLOCAL TRREMOTE ALARM INTFLTL1 INTFLTL2 INTFLTL3 SYNLOSS CHARGEN IDL1 IDL2 IDL3 IDL1MAG IDL2MAG IDL3MAG IBIASL1 IBIASL2 IBIASL3 IREQSTL1 IREQSTL2 IREQSTL3 IEC15000481‐3‐en.vsdx IEC15000481 V3 EN-US Figure 52: 7.3.5 L4CPDIF function block Signals PID-7277-INPUTSIGNALS v1 Table 97: Name L4CPDIF Input signals Type Default Description I3P1 GROUP SIGNAL - Three phase current samples, group 1 I3P2 GROUP SIGNAL - Three phase current samples, group 2 I3P3 GROUP SIGNAL - Three phase current samples, group 3 I3P4 GROUP SIGNAL - Three phase current samples, group 4 U3P1 GROUP SIGNAL - Three phase voltage samples, group 1 U3P2 GROUP SIGNAL - Three phase voltage samples, group 2 U3P3 GROUP SIGNAL - Three phase voltage samples, group 3 U3P4 GROUP SIGNAL - Three phase voltage samples, group 4 Table continues on next page 164 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Name Type Default Description BLOCK BOOLEAN 0 Block of function LOWSENEN BOOLEAN 0 Input for forcing the function enable low sensitivity CCBLK BOOLEAN 0 Block CCC (local) PID-7277-OUTPUTSIGNALS v1 Table 98: L4CPDIF Output signals Name Type Description TRIP BOOLEAN Common, main, trip output signal TRL1 BOOLEAN Trip signal from phase L1 TRL2 BOOLEAN Trip signal from phase L2 TRL3 BOOLEAN Trip signal from phase L3 START BOOLEAN Common, main, start output signal STL1 BOOLEAN Start signal from phase L1 STL2 BOOLEAN Start signal from phase L2 STL3 BOOLEAN Start signal from phase L3 STUNR BOOLEAN Start of unrestrained differential protection COMFBLKD BOOLEAN Block due to communication failed BLKHL1 BOOLEAN Block signal due to 2nd or 5th harmonic, phase L1 BLKHL2 BOOLEAN Block signal due to 2nd or 5th harmonic, phase L2 BLKHL3 BOOLEAN Block signal due to 2nd or 5th harmonic, phase L3 OPENCT BOOLEAN An open CT was detected DIFLBLKD BOOLEAN Local line differential function blocked TRLOCAL BOOLEAN Trip from local differential function TRREMOTE BOOLEAN Trip from remote differential function ALARM BOOLEAN Alarm for sustained differential current INTFLTL1 BOOLEAN Internal fault has been detected in phase L1 INTFLTL2 BOOLEAN Internal fault has been detected in phase L2 INTFLTL3 BOOLEAN Internal fault has been detected in phase L3 SYNLOSS BOOLEAN Loss of data synchronism was detected CHARGEN BOOLEAN Charging current compensation is enabled IDL1 REAL Instantaneous differential current, phase L1 IDL2 REAL Instantaneous differential current, phase L2 IDL3 REAL Instantaneous differential current, phase L3 IDL1MAG REAL Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL Magnitude of fund. freq. differential current, phase L3 IBIASL1 REAL Magnitude of the bias current, L1 IBIASL2 REAL Magnitude of the bias current, L2 IBIASL3 REAL Magnitude of the bias current, L3 IREQSTL1 REAL Required current level to start, phase L1 IREQSTL2 REAL Required current level to start, phase L2 IREQSTL3 REAL Required current level to start, phase L3 Line differential protection RED670 Technical manual 165 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 7.3.6 1MRK 505 377-UEN Rev. P Settings PID-7277-SETTINGS v1 Table 99: L4CPDIF Non group settings (basic) Name Values (Range) Unit Step Default Description GlobalBaseSel 1 - 12 - 1 1 Selection of one of the Global Base Value groups NoOfUsedCTs 2-4 - 1 2 Total number of 3-Ph CT sets connected to diff protection TapTransformer Off On - - Off Small tap transformer included in the protected zone DiffMode Master Slave - - Master Differential function mode Master/Slave ReleaseLocal Block all Release local - - Block all Release of local terminal for trip under test mode TestModeSet Off On - - Off Test Mode Off/On Table 100: L4CPDIF Group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Mode Off / On IdMin 0.20 - 2.00 IB 0.01 0.30 Oper - restr charact., section 1 sensitivity, multiple of IBase IdMinHigh 0.20 - 10.00 IB 0.01 0.80 Initial lower sensitivity, as multiple of IBase tIdMinHigh 0.000 - 60.000 s 0.001 1.000 Time interval of initial lower sensitivity, in s IdUnre 1.00 - 100.00 IB 0.01 10.00 Unrestrained differential current limit, multiple of IBase OpenCTEnable Off On - - On Open CTEnable Off/On tOCTResetDelay 0.100 - 10.000 s 0.001 0.250 Reset delay in s. After delay, diff. function is activated OCTBlockEn Off On - - On Enable Open CT blocking function trip Off/On IdiffAlarm 0.05 - 1.00 IB 0.01 0.15 Sustained differential current alarm, multiple of IBase tAlarmDelay 0.000 - 60.000 s 0.001 10.000 Delay for alarm due to sustained differential current, in s LossSynEn Off On - - Off Loss of data synchronism detection Off/On tLossSynReset 0.100 - 60.000 s 0.001 1.000 Loss of data synchronism detection reset delay in s. After delay, diff. function is activated CCCOpMode Off U based IDiff reduction - - Off Operation mode of charging current compensation VTOnLineGrp1 No Yes - - No Voltage transformer installed on the line at the end, the currents of which are connected to group 1 Table continues on next page 166 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Name Section 7 Differential protection Values (Range) Unit Step Default Description VTOnLineGrp2 No Yes - - No Voltage transformer installed on the line at the end, the currents of which are connected to group 2 VTOnLineGrp3 No Yes - - No Voltage transformer installed on the line at the end, the currents of which are connected to group 3 VTOnLineGrp4 No Yes - - No Voltage transformer installed on the line at the end, the currents of which are connected to group 4 C0 0.001 - 1000.000 uF 0.001 0.001 Total zero sequence capacitance of the protected line, in microfarad C1 0.001 - 1000.000 uF 0.001 0.001 Total positive sequence capacitance of the protected line, in microfarad NoOfLineEnds 2-3 - 1 2 Number of physical line ends of the protected line circuit, 2 ends or 3 ends NoOfCTSetsGrp1 1-2 - 1 1 Number of 3-ph CTs at line end, the currents of which are connected to group 1 (1 or 2) NoOfCTSetsGrp2 1-2 - 1 1 Number of 3-ph CTs at line end, the currents of which are connected to group 2 (1 or 2) NoOfCTSetsGrp3 1-2 - 1 1 Number of 3-ph CTs at line end, the currents of which are connected to group 3 (1 or 2) NoOfCTSetsGrp4 1-2 - 1 1 Number of 3-ph CTs at line end, the currents of which are connected to group 4 (1or 2) tChargCurrDelay 0.010 - 60.000 s 0.001 0.100 Delay for compensation of charging current due to initial voltage oscillation, in s Table 101: L4CPDIF Group settings (advanced) Name Values (Range) Unit Step Default Description EndSection1 0.20 - 2.00 IB 0.01 1.00 End of section 1, as multiple of reference current IBase EndSection2 1.00 - 10.00 IB 0.01 3.00 End of section 2, as multiple of reference current IBase SlopeSection2 10.0 - 100.0 % 0.1 50.0 Slope in section 2 of operate-restrain characteristic, in % SlopeSection3 30.0 - 100.0 % 0.1 100.0 Slope in section 3 of operate-restrain characteristic, in % I2/I1Ratio 5.0 - 100.0 % 1.0 10.0 Max. ratio of 2nd harm. to fundamental harm dif. curr. in % I5/I1Ratio 5.0 - 100.0 % 1.0 10.0 Max. ratio of 5th harm. to fundamental harm dif. curr. in % SendInterTrip No Yes - - Yes Send inter-trip to remote ends Line differential protection RED670 Technical manual 167 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 7.3.7 1MRK 505 377-UEN Rev. P Monitored data PID-7277-MONITOREDDATA v1 Table 102: L4CPDIF Monitored data Name Type Values (Range) Unit Description IDL1MAG REAL - A Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL - A Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL - A Magnitude of fund. freq. differential current, phase L3 IBIASL1 REAL - A Magnitude of the bias current, L1 IBIASL2 REAL - A Magnitude of the bias current, L2 IBIASL3 REAL - A Magnitude of the bias current, L3 ICL1 REAL - A Amount of compensated charging current, phase L1 ICL2 REAL - A Amount of compensated charging current, phase L2 ICL3 REAL - A Amount of compensated charging current, phase L3 7.3.8 Operation principle 7.3.8.1 Differential currents Instantaneous differential currents GUID-BC1C8ADA-B281-43F8-A04D-4D90AFB999DB v2 Instantaneous differential currents represent sums of all synchronized instantaneous currents (current samples) from all ends of a protected line. They also include charging currents since instantaneous differential currents are formed by directly measured raw currents (true current samples). Instantaneous differential currents are generated because they can be analyzed with higher harmonic Fourier filters. Higher harmonics are calculated only when a start signal has been issued and a disturbance has not been recognized as an internal fault. The 2nd and 5th harmonic differential currents are compared to the fundamental frequency differential current. If the measured ratio is greater than the values specified by settings I2/I1Ratio and I5/I1Ratio respectively, and the disturbance has not been recognized as internal, L4CPDIF does not issue a trip command. Fundamental frequency differential currents GUID-AAFA17A5-9890-465C-8D32-C6596F90E0E7 v2 Fundamental frequency differential current is a vector sum of current phasors measured at all ends of a protected line. Input currents are first Fourier filtered so that each current is expressed as a phasor with its real and imaginary component. Calculating the fundamental frequency differential current in a given phase is performed using operation on complex numbers. All real and imaginary parts of currents from different ends are summed separately. Each differential current is thus a phasor with a real and imaginary component, and the magnitude of the current can be calculated from those components. In normal conditions, the sum of all load currents in a given phase should be zero as defined by Kirchhoff's law. However, some minor differential current composed of capacitive currents may flow into the protected zone through all ends of the protection. The sum of these relatively small capacitive currents is typically 5–15% of IBase (IBase reflects the nominal current of a power line). L4CPDIF can compensate for the capacitive currents, and the resulting differential current is therefore close to zero. Even though these currents are compensated for, sensitivity for setting IdMin 168 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection must be set above the total value of the uncompensated charging currents. It is recommended to set IdMin ≥ 125% of the maximum value of the total charging current at rated voltage. Fundamental frequency differential current is compared to a value required to trip. This value is a function of the set operate-restrain characteristic where the bias (restrain) current acts as the independent variable. The bias (restrain) current is considered the highest total current of all currents in a phase from all separate ends of a protected line. If the differential current higher than the actual trip value, it is likely that an internal fault has occurred. However, this may not always be the case as a relatively high false differential current can arise also with severe external faults with transient CT saturation. The internal fault detector must confirm, based on incremental currents, that the fault is internal. 7.3.8.2 Internal fault detector GUID-BF5AFA0F-9440-4716-807C-7276071A6FD8 v2 The internal fault detector used in L4CPDIF is a new feature in an otherwise classical differential protection. Each phase has its own detector, and they function completely independently from each other. The internal fault detector calculates the relative angle between purely fault current components (incremental current components expressed as phasors). Incremental currents of an internal fault flow into the protected zone, and incremental currents of an external fault flow through the protected zone. The internal fault detector is very reliable, and information gained from it is mostly used to enhance the dependability of L4CPDIF. This is achieved by declaring a fault as internal very quickly, which results in an immediate trip command with no regard to eventual 2nd or 5th harmonic in the instantaneous differential current. When a fault is declared as internal (typically in 3 ms), the harmonic block scheme is deactivated and a trip command is issued very fast when it is still unlikely that a CT can reach saturation and produce high amounts of harmonics. At internal faults, the relative angle between incremental currents is ideally zero, but can slightly deviate from that. This depends on the different X/R factors of equivalent circuits on both sides of the equivalent electrical circuit as seen from the position of the internal fault. If the relative angle is less than 55 degrees, a fault is recognized as internal. A boolean start signal is produced to indicate this internal fault. The harmonic block logic scheme is deactivated for as long as the internal fault signal exists. This ensures fast tripping even in the presence of higher harmonics. With external faults, the relative angle between incremental currents is theoretically 180 degrees, but can be less (even down to approximately 120 degrees) if CT saturation sets in. Calculating pre-fault average currents to determine incremental currents GUID-6238F0A8-9B51-4759-B7FB-E25212B7F798 v2 The average of every total pre-fault normal load current, based on the last period, is calculated to have a reliable and stable pre-fault current reference value so that the incremental (purely fault) component of every current can be determined. The average values of the currents, expressed as phasors with their real and imaginary parts, are calculated based on current values from the last period. The on-line calculated average values are sequentially memorized in a special memory for one period back in time. The oldest average stored is thus one period old. It is this oldest average that serves as the reference for the pre-fault normal current if a fault occurs. The averaging operation is executed continuously until a disturbance (possibly an internal fault) is detected. A disturbance is suspected when the differential current exceeds the set value for IdMin. The pre-fault current calculation is stopped after the disturbance, and the oldest stored average - not affected by the disturbance - is used as a reference for the normal pre-fault current to calculate the incremental (pure fault) current. This process takes place independently in all three phases (see Figure 53). Line differential protection RED670 Technical manual 169 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P IEC15000474-1-en.vsd IEC15000474 V1 EN-US Figure 53: Simplified logic diagram for the internal fault detector shown for a two-end power line (one detector for each phase) The pre-fault current calculation resumes when the disturbance has disappeared, that is, when the differential current falls below 0.95 x IdMin. Incremental currents are determined by subtracting the pre-fault (load) currents from the actual total currents (fault and load), and this happens separately for each phase. Incremental currents are calculated continuously regardless of the status of pre-fault current calculation. Under stable load condition, these incremental currents are practically zero. If there are more than two ends in a protected line, the system is automatically reduced to a two-end equivalent line before the relative angle is determined. Calculating the relative angle between incremental currents GUID-63CAB758-64B5-4665-BFA7-A07705C44D26 v2 Incremental currents are expressed as phasors so that the relative angle between them can be calculated. This angle makes it possible to determine if a fault is internal. Normal sudden change in symmetrical load is felt as an external disturbance. In that case, incremental currents at both ends of a single power line have the same direction: through the power line and out. An external fault is, in principle, identical to a sudden change in load so the incremental currents at both ends of a power line have the same direction: through the power line and out. On the other hand, at internal faults, both incremental currents are flowing towards the fault point so they have opposite directions in relation to the power line (see Figure 54). 170 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection IEC15000462-1-en.vsd IEC15000462 V1 EN-US Figure 54: Incremental currents flowing towards the internal fault point with a default orientation of CTs However, keeping in mind the default orientation of CTs at all ends of a power line, the relative angle is approximately 180 degrees for external and 0 degrees for internal faults. With internal faults, the angle can deviate a little from 0 degrees depending on possible different source impedance angle of equivalent electrical circuits at opposite ends of an internal fault. With CT saturation, the angle value for an external fault can differ somewhat from 180 degrees, and for an internal fault from 0 degrees. However, measurement of the angle is stopped before severe CT saturation occurs because a fault is characterized as internal (or external) very quickly (typically in 3-5 ms). Measurement of the angle does not resume until the disturbance disappears. The relative angle is only determined if each incremental current is equal to or greater than 2.5% of IBase in a protected power line. In normal load conditions with no or slow/small changes in load, no big enough incremental currents occur to measure the relative angle with the required high precision. In that case, the angle is automatically set to 90 degrees, which usually means that neither internal nor external disturbances exist. With internal faults, such as single-phase earth faults, the angle between the incremental currents at both ends falls quickly to approximately 0 degrees. If a protected power line circuit is delimited by more than two CT groups, a reliable algorithm is applied to measure the angle between incremental currents. In that case, the protected power line is reduced to a two-end line. This is done so that first the highest incremental current among all incremental currents in a given phase is found, and then the relative angle between this highest incremental current and the geometrical sum of other currents is calculated. For example, if a protected line has three physical line ends with a CT group in each of them and the incremental current at end 1 is found to be the highest, the angle between that current and the geometric sum of incremental currents at ends 2 and 3 is calculated. 7.3.8.3 Operate-restrain characteristic GUID-5978B231-F7EF-4730-9ACD-C73DD1E32611 v2 L4CPDIF uses two limits, and the actual magnitudes of the three fundamental frequency differential currents are compared to these limits at each execution of the function. The unrestrained (non-stablized) part of L4CPDIF is used for very high differential currents when it should be clear that a fault is internal. This limit is a constant and not proportional to the bias (restrain) current. No harmonic or any other restrain is applied to it, and that is why it is called the unrestrained limit. When this limit is set, a value higher than the highest short circuit current for an external fault plus some extra margin must be used. The restrained (stabilized) part of L4CPDIF calculates the differential (operate) and the bias (restrain) currents in each phase, and applies them to the operate-restrain characteristic. The function can also provide the instantaneous operate level as outputs (IREQSTLX) to indicate the required value to start according to the characteristic. If any differential current enters the operate region above the characteristic, a start signal is issued, and it is quickly followed by a trip command if the fault is internal. Line differential protection RED670 Technical manual 171 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P In L4CPDIF, the operate-restrain characteristic is represented by a three-section, double-slope and double-breakpoint characteristic as shown in Figure 55. The operate value is a function of the bias (restrain) current. The restrain characteristic is determined by five settings: • • • • • IdMin: sensitivity of section 1, set as multiple of IBase EndSection1: end of section 1, set as multiple of IBase EndSection2: end of section 2, set as multiple of IBase SlopeSection2: slope of section 2, set as percentage SlopeSection3: slope of section 3, set as percentage Operate current [ x IBase ] Operate 5 unconditionally UnrestrainedLimit 4 Operate 3 conditionally 2 Section 1 Section 2 Section 3 SlopeSection3 1 IdMin SlopeSection2 Restrain 0 0 1 2 3 EndSection1 EndSection2 4 Restrain current [ x IBase ] IEC15000463-1-en.vsd IEC15000463 V1 EN-US Figure 55: 5 Description of the restrained and unrestrained operate characteristics where: slope = D Ioperate × 100% D Irestrain EQUATION1246 V1 EN-US and where the restrained characteristic is defined by settings: 1. IdMin 2. EndSection1 3. EndSection2 4. SlopeSection2 5. SlopeSection3 Section 1 is the most sensitive part on the operate-restrain characteristic. In this section, normal currents flow through the protected circuit and its CTs, and the risk for higher false differential currents is relatively low. Charging currents present a typical example of false differential currents 172 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection here. The slope in section 1 is always 0%. The default value for sensitivity IdMin = 0.30 of IBase. The default length of section 1 is 1.00 of IBase. Section 2 introduces a minor slope to cope with false differential currents that are proportional to higher than normal currents through the CTs. The default slope in section 2 is 50%. The default length of section 2 is 2.00 of IBase, which means that, when section 1 is included, section 2 ends at 3.00 of IBase. Section 3 has a more pronounced slope designed to result in higher tolerance of substantial CT saturation at high through-fault currents which may be expected in this section. The default slope in section 3 is 100%. The operate-restrain characteristic is tailor-made so it can be constructed by the user. Construction for a given protection application should be done so that with internal faults, the differential currents are always safely (with a good margin) above, and with external faults below the operate-restrain characteristic. It is not always possible to achieve both of these requirements. However, the default operate-restrain characteristic is known to give good results in majority of applications. The reset ratio in all parts of the characteristic equals to 0.95. 7.3.8.4 2nd and 5th harmonics GUID-BC40AE81-D38E-4ABD-A2CA-FCB03FC3B506 v2 High stability against unwanted operations under severe external faults is achieved by using the operate-restrain characteristic and applying the 2nd and the 5th harmonic block scheme. Even though a good operate-restrain characteristic ignores the majority of external disturbances, some severe external faults can produce enough false differential current at a relatively low bias current so that the operate region of the characteristic is entered. This causes an unwanted trip command if not prevented by the 2nd or the 5th harmonic. The generated false differential current has a substantial 2nd or 5th harmonic component. The 2nd harmonic component produced by transient CT saturation is high, typically 20–60% of the false fundamental harmonic differential current. A relatively low value, such as 10%, is recommended for the relative limit of the 2nd harmonic in comparison to the fundamental frequency differential current. It can be expected that under severe external faults, the 2nd harmonic differential current is always greater than 10% of the fundamental frequency component of the differential current. This is the classical solution that efficiently helps prevent an unwanted trip for external faults. The 2nd harmonic has traditionally been used to prevent unwanted operation of differential protection in cases like energizing power transformers. It has also been used to prevent unwanted operation under external fault conditions where a false differential current can arise only if one or more CTs are transiently saturated. This false differential current is characterized by a high amount of the 2nd harmonic. Without CT saturation, there is usually no or very little differential current under external faults. In such cases the external fault will not be felt by the protection at all. Using the 2nd and the 5th harmonic makes most traditional differential protections slow in cases of severe internal faults with transient CT saturation. This does not apply to L4CPDIF. In L4CPDIF, the 2nd and the 5th harmonic block logic is always active except in cases where the internal fault or switch-on-to-fault condition is detected. The switch-on-to-fault condition is identified if only one end currents are high and the rest currents are below the limit (2.5% of IBase). A small tap transformer (up to 10–15% of the power line transmission capacity) can be included somewhere in the protected line without its currents being measured. Any currents flowing through this transformer are thus felt as differential currents. Switching a tap transformer on the protected line (a legal event) may cause inrush currents that are correctly detected as internal faults. Fortunately these instantaneous differential currents are rich with the 2nd harmonic which is used to prevent an unwanted operation of L4CPDIF. The 5th harmonic is also calculated in the instantaneous differential current. This is done to prevent an unwanted trip command at sudden over-excitation of the tap transformer. Line differential protection RED670 Technical manual 173 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Setting TapTransformer = On is used to specify if a tap transformer is included and connected/ disconnected to/from the protected zone. The default value for TapTransformer = Off. If TapTransformer = On, harmonic blocking is checked whenever the bias current is less than the relatively low value of 1.25 x IBase. An internal fault is not declared if the bias current is lower than 1.25 x IBase. This leaves the harmonic block logic scheme active. The 5th harmonic is also calculated in the instantaneous differential current. This is done to prevent an unwanted trip command at sudden over-excitation of the tap transformer. Relative limits for the harmonics are specified as follows: • • 2nd harmonic: setting I2/I1Ratio, default value 0.10 5th harmonic: setting I5/I1Ratio, default value 0.10 Low setting values can be used since the harmonic block is deactivated under internal fault conditions, and cannot delay the protection response for those faults. 7.3.8.5 Charging current compensation GUID-0750DEF2-8B50-412A-B366-42D921AE635E v3 Underground cables and long overhead lines generate charging currents which L4CPDIF detects as differential currents. Charging currents on overhead lines increase with the length of the power line.. They are relatively low, typically 5–15% of IBase, which is significant for the setting and operation of L4CPDIF. Power cables can, at fundamental frequency, have charging currents high enough to significantly influence the necessary setting of the minimum operating current. This, in turn, can impact the sensitivity of the algorithm applied by L4CPDIF. To improve this, L4CPDIF uses charging current compensation. This compensation is a special algorithm, included in the L4CPDIF Even if charging current compensation is applied, the best sensitivity (IdMin) of L4CPDIF must still be above the total maximum charging current. This is because charging current can shortly appear as a false differential current in its full value under some dynamic conditions such as line re-closing. L4CPDIF offers two methods to perform charging current compensation: • • The exact method that processes both currents and voltages. When using this method, protected circuit capacitances must be known and the information on voltage must be available. The approximate method that processes only currents. This method assumes that persistent, small differential currents in normal steady state represent capacitive charging currents. These small currents are subtracted in a phase-wise manner. When a tap transformer or shunt reactor is included in the protected zone, charging current cannot be calculated using the exact method because the capacitive current is partly compensated for by the tap power transformer or shunt reactor. In that case, the approximate method should be used instead. Under the condition that any terminal goes out of service (all data from that terminal will be forced to zero), the charging current compensation function will automatically switch to approximate method if the exact method was selected previously. During the transition period, 200% of IdMin will be applied for 200 ms. When all terminals are back to service again, the charging current compensation function will switch back to the exact method as selected previously. Charging current calculation using the exact method GUID-748E13D3-E102-4D21-891A-461E885B78F6 v3 Charging currents of cables and overhead lines are capacitive and of the positive-sequence. They relate to distributed capacitances between line phase conductors and between each phase conductor and earth. These capacitances give rise to line charging currents which L4CPDIF detects as false differential currents as shown in Figure 56. 174 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection IC1 Idi ff, false = IC1 + IC2 IED Communication channel IC2 IED IEC15000464-1-en.vsd IEC15000464 V1 EN-US Figure 56: Charging currents fed from all voltage sources Charging current in a transmission line or cable is proportional to the capacitance and time derivative of voltage. Time derivative of a signal can be estimated through straightforward numerical differentiation: dy yk yk 1 dt t (Equation 9) IECEQUATION15157 V1 EN-US When calculating capacitance in one phase, both capacitance to earth (Cn) and to other phases (Cp) must be considered (see Figure 57). L1 (UL1) Cp Cp L3 (UL3) L2 (U L2) Cn IEC15000465-1-en.vsd IEC15000465 V1 EN-US Figure 57: Capacitances for phaseL1 of a transmission line Charging currents in phase L1 are calculated as: d (uL1 0) d (uL1 uL 2) d (uL1 uL 3) Cp Cp dt dt dt duL1 duL1 duL 2 duL1 duL 3 icL1 Cn Cp Cp Cp Cp dt dt dt dt dt duL1 duL 2 duL 3 icL1 (Cn 2Cp) Cp Cp dt dt dt icL1 Cn (Equation 10) IECEQUATION15158 V1 EN-US Line differential protection RED670 Technical manual 175 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P In real power systems, zero and positive sequence capacitances C0 and C1 are usually known instead of Cn and Cp. The zero sequence capacitance per phase is calculated as: C 0 Cn (Equation 11) IECEQUATION15160 V1 EN-US The positive sequence capacitance is calculated from Cp and Cn (by applying delta-star transformation) as: C1 3 Cp Cn (Equation 12) IECEQUATION15159 V1 EN-US Using the above equations, Cn and Cp can be expressed in terms of C0 and C1: Cn C 0 C1 C 0 Cp 3 (Equation 13) IECEQUATION15161 V1 EN-US When studying all three phases, charging currents can be expressed as: duL1 icL1 (2C1 C 0) / 3 (C 0 C1) / 3 (C 0 C1) / 3 dt duL 2 icL 2 (C 0 C1) / 3 (2C1 C 0) / 3 (C 0 C1) / 3 dt icL 3 (C 0 C1) / 3 (C 0 C1) / 3 (2C1 C 0) / 3 duL 3 dt (Equation 14) IECEQUATION15162 V1 EN-US The calculated capacitive charging currents are fed into fundamental frequency Fourier filters. Output from these filters represents charging currents expressed as phasors with their real and imaginary parts: IcL1, IcL2 and IcL3. These capacitive charging currents are then subtracted from total differential currents which are also expressed as phasors: IdiffcompL1 IdiffL1 IcL1 IdiffcompL 2 IdiffL 2 IcL 2 IdiffcompL 3 IdiffL 3 IcL 3 (Equation 15) IECEQUATION15163 V1 EN-US 176 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection where: IdiffcompLx denotes compensated differential currents (as phasors) to be used in the differential algorithm Figure 58 shows an example of Charging Current Compensation using exact current. In the example, the charging current is approximate 92 A in normal condition and subtracted from each of the three phases. TOTAL COMPENSATED CURRENT IN PHASE L1 CCC starts after 100 ms 92 A subtracted from the fundamental frequency differential current fault 37 A subtracted under fault conditions TOTAL COMPENSATED CURRENT IN PHASE L2 fault 92 A subtracted 37 A subtracted TOTAL COMPENSATED CURRENT IN PHASE L3 92 A subtracted fault 37 A subtracted Time in seconds IEC15000466-1-en.vsd IEC15000466 V1 EN-US Figure 58: Charging current compensation using the exact method (CCCOpMode = U based) As seen on the Figure 58 current compensation starts 100 ms after the power line was switched on to normal load. Under normal load conditions, approximately 92 A is subtracted in this particular example, which results in all fundamental frequency differential currents being close to zero. Under fault conditions with very low voltage at the fault and decreased voltages at both ends, the charging current is smaller, and only 37 A is subtracted from the differential currents. When CCBLK input is TRUE, the exact method charging current compensation will be disabled. During blocking period, 200% of Idmin will be applied in order to avoid mal-operation due to the stop of charging current compensation. Charging current compensation using the approximate method GUID-B23CD440-BB53-4A89-B111-A0078F6F3FD8 v2 The approximate method does not calculate the exact charging currents in separate phases using an algorithm that processes voltages and power line capacitances. Instead, it assumes that relatively small persistent differential currents, equal or smaller than IdMin in all 3 phases, represent the resultant total charging currents in each phase. These relatively small differential currents are considered as charging currents, and they are subtracted from differential currents in a phase-wise way. The resultant differential currents are thus approximately zero. The approximate method can be used as an alternative in cases where voltages at all ends are not available or where shunt reactors are switched on and off on a daily basis without available information on their status to L4CPDIF. The amount of pre-fault differential current that can be subtracted is limited by 75% of the base sensitivity of L4CPDIF, and the limit is defined by setting IdMin. It is recommended to set IdMin to 125–150% of the total charging current even when the charging currents are eliminated. Since false pre-fault differential currents are continuously subtracted, the magnitude of the pre-fault fundamental frequency differential current is zero or close to zero. Under fault conditions, when a start signal exists, the subtraction algorithm continues to subtract the pre-fault charging currents. Therefore, under fault conditions, fundamental frequency differential currents are generated exclusively because of faults. Line differential protection RED670 Technical manual 177 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Because L4CPDIF does not know the voltage profiles, it assumes that the relatively small pre-fault differential currents are mostly due to capacitive charging currents. All small pre-fault differential currents are subtracted regardless of their origin. In addition to the true charging currents, the following currents are also eliminated: • • Small false differential currents generated because of small errors (inequalities) in CTs. Load currents of small tap transformers if included in the protected zone. A tap transformer that is connected to a protected zone, reduces the capacitive charging currents, but its load current is considered and treated as charging currents. If a communication failure is signalled to L4CPDIF, the elimination process of charging currents based on approximate method is interrupted and all values reset. The process is resumed after the communication failure signal SUBSTITUTE is reset to FALSE (0). All L4CPDIF outputs are blocked during communication failure and for 200 ms after it has been cleared. Figure 59 shows the charging current that is subtracted from each of the three phases. TOTAL COMPENSATED CURRENT IN PHASE L1 CCC compensated in app. 100 ms 92 A subtracted from the fundamental frequency differential current fault 92 A subtracted under fault conditions TOTAL COMPENSATED CURRENT IN PHASE L2 92 A subtracted fault 92 A subtracted TOTAL COMPENSATED CURRENT IN PHASE L3 92 A subtracted fault 92 A subtracted Time in seconds IEC15000467-1-en.vsd IEC15000467 V1 EN-US Figure 59: Charging current compensation using the approximate method (CCCOpMode = Idiff reduction) Charging current compensation is achieved 100 ms after the power line was switched on to normal load. Under normal load conditions, in the example case, shown in Figure 59, approximately 92 A is subtracted, which results in all fundamental frequency differential currents being close to zero. Since voltage profiles are not known, the approximate method continues, even under fault conditions, to subtract the pre-fault charging current of 92 A. With low resistance faults, the 55 A difference of the approximate method in comparison to the exact method, is relatively small when considering high fault currents. With high-resistance faults, the charging current will not change much so it is acceptable to continue subtracting the pre-fault values of charging currents. 7.3.8.6 Open CT detection GUID-FE8DF833-02E1-4923-A1A6-48BCA863AD41 v3 L4CPDIF has a built-in, advanced open CT detection feature. A suddenly and inadvertently opened CT circuit may cause an unexpected and unwanted operation of L4CPDIF in normal load conditions. Damage to secondary equipment may occur due to high voltage from open CT circuit outputs. It is thus advantageous from security and reliability point-of-view that open CT detection blocks the L4CPDIF function, and produces an alarm signal so that the open CT condition can be quickly corrected. Open CT detection is enabled/disabled using setting OpenCTEnable (On/Off). When enabled, it tries to prevent mal-operation when a loaded main CT, connected to L4CPDIF, is open-circuited by mistake on the secondary side. Open CT detection can only detect the interruption of one CT phase 178 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection current at a time. It will thus not operate if two or all three-phase currents of a CT group are accidentally interrupted at precisely the same time. L4CPDIF generates a trip signal if the false differential current is sufficiently high. An open CT circuit is typically detected in 12–14 ms, and if the load in the protected circuit is relatively high (close to nominal load), it is not always possible to prevent this unwanted trip. However, it is still vital to receive information on what caused the unwanted trip command. The principle applied to detect an open CT circuit is based on simple pattern recognition method. Current in a phase with an open CT circuit suddenly drops to zero (detected by L4CPDIF) while currents in the other two phases stay on the same level as before. Open CT detection detects an open CT circuit under normal conditions, that is, when the protected multi-end circuit is under normal load (12–125% of the rated load). If the load currents are very low or zero, open CT detection cannot detect an open CT circuit. In addition to load condition requirements, open CT detection checks the differential current in a faulty phase. If the differential current is lower than 10% of IBase, open CT circuit is not detected. If there is an open CT circuit at one end of a protected line, there are no immediate changes in currents at other ends. Therefore, open CT condition is only declared if the zero sequence current (iL1 + iL2 + iL3) is relatively high at the faulty end and low at all other ends. The limit for checking the zero sequence current is set to 10 % of IBase. Searching for an open CT starts if the bias current has been higher than energization limit for 1s and has entered the 12–125% range. When an open CT circuit is detected, output OPENCT is set to 1. If setting OCTBlockEnable = On, all differential functions, except for the unrestrained (instantaneous) differential function, are blocked. Otherwise, open CT detection sets OPENCT to indicate an open CT circuit so that no action is taken to prevent the trip from differential functions. When the open CT condition is removed (that is, the previously open CT circuit is reconnected), the functions remain blocked for a specified time interval defined by setting tOCTResetDelay. This is to prevent an eventual mal-operation immediately after re-connecting the previously open CT circuit. The open CT detection algorithm provides detailed information on the location of the defective CT circuit. The algorithm clearly indicates the IED side, CT input and phase of the open CT circuit. These indications are provided from the Transformer differential protection function via the following outputs: • • • OPENCT: provides instant information to indicate that an open CT circuit has been detected. OPENCTIN: provides information on local HMI about which open CT circuit has been detected (1 = CT input No 1, 2 = CT input No 2, and so on). OPENCTPH: provides information on local HMI about the phase in which an open CT circuit has been detected (1 = Phase L1, 2 = Phase L2, 3 = Phase L3). Once an open CT condition is declared, the algorithm stops to search for further open CT circuits, and waits until the first open CT circuit has been corrected. The open CT condition can be reset automatically in L4CPDIF (this is not possible through external reset). To do this, the following conditions must be fulfilled: • • Open CT condition in the defective CT circuit has been corrected (for example, current asymmetry disappears). The corrected CT circuit has remained reconnected for a longer time than specified by setting tOCTResetDelay. If an open CT circuit has been detected in a separate group of three CTs, the algorithm is reset either when the missing current returns to the normal value or when all three currents become zero. After the reset, the open CT detection algorithm restarts to search for open CT circuits within the protected zone. Line differential protection RED670 Technical manual 179 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P IEC15000468-2-en.vsdx IEC15000468 V2 EN-US Figure 60: 7.3.8.7 Simplified logic for open CT detection Loss of data synchronism detection GUID-F229078D-F0E8-4351-A4B8-D70F8C034C7B v2 L4CPDIF has a build-in feature to detect a loss of data synchronism condition and, as a result, block the L4CPDIF function. L4CPDIF calculates the current difference from all IEDs in the protection scheme. To obtain the correct differential current, the current samples must be correctly time-aligned and synchronized. When a synchronization error occurs, current phasors on different sides slowly drift apart, and a false differential current emerges which will eventually cause the relay to mal-operate. Loss of data synchronism detection is enabled/disabled with setting LossSynEn (On/Off). If enabled, the feature tries to prevent mal-operation when loss of data synchronism occurs. L4CPDIF is blocked as soon as loss of data synchronism condition is detected. The operation of loss of data synchronism detection is based on all three-phase differential currents having practically the same magnitudes at a relatively low bias current when loss of data synchronism occurs between IEDs. This type of situation would not occur as a result of a threephase fault where the fault currents would be much higher than normal. Loss of data synchronism detection detects a synchronization error under normal conditions, that is, when a protected circuit is under normal load (less than 110% of the rated load). If the load currents are very low or higher than 110% of the rated load, synchronization error cannot be detected When the load condition is fulfilled, loss of data synchronism detection starts to check the differential currents. If all three-phase differential currents are within the range between IdMin and 2 x IBase, loss of data synchronism condition is detected. Figure 61 shows the operate region for loss of data synchronism detection. 180 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection IEC15000469-1-en.vsd IEC15000469 V1 EN-US Figure 61: Operate region for loss of data synchronism detection When loss of data synchronism is detected, output SYNLOSS is set to TRUE and L4CPDIF is blocked. If SYNLOSS is set, that is TRUE, for more than 120 ms, a settable reset delay tLossSynReset is added when the function output is reset. If SYNLOSS is set, that is TRUE, for more than 5 s, it will be latched, and reset when all three-phase differential currents drop below IdMin. IEC15000470-1-en.vsd IEC15000470 V1 EN-US Figure 62: 7.3.8.8 Simplified logic for loss of synchronism detection Line differential coordination logic GUID-1159CC47-43BE-4B74-8F12-8B41F1F8ACCF v3 Line differential coordination logic gathers and coordinates remote IED signals between L4CPDIF and the LDCM communication module. For example, when local IED decides to trip, the local trip command is transferred to other IEDs by the coordination logic. The sending of the local trip to the Line differential protection RED670 Technical manual 181 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P other IEDs can be controlled with the setting SendInterTrip. If setting SendInterTrip is set to No, the trip will only be activated locally. When L4CPDIF in a local IED is set to Test mode, the coordination logic sets the remote IEDs to remote Test mode and blocks the trip outputs in those IEDs. Figure 63 shows the block signal handling by the coordination logic. When L4CPDIF receives a local block, local test mode or local open CT signal, it is blocked and this blocking signal is sent out to remote ends. TestModeRemoteTerm1 TestModeRemoteTerm2 TestModeRemoteTerm3 TestModeRemoteTerm4 OR 50 ms t OR BlockRemoteTerm1 BlockRemoteTerm2 BlockRemoteTerm3 BlockRemoteTerm4 OR LocalDiffBlock LOCADIFFBLOCKED OR 50 ms CTFAIL t CTFailToRemote (signal to LDCM) TestModelnput AND 50 ms AND TestModeTo Remote t AND TestModeset 1 TripToRemoteBlock OR ReleaseLocal RemoteTripBlock OR TERMINALOUTOFSERVICE OR BLOCK 100 ms t BlockToRemote OR IEC15000471-1-en.vsd IEC15000471 V1 EN-US Figure 63: Block signal logic for line differential coordination logic When the coordination logic receives a trip signal from a remote IED, the signal is transferred to the local IED in the protected zone. Figure 64 shows the trip signal handling by the coordination logic. The common trip signal is initiated either by a local trip from L4CPDIF or by trips from the remote ends. 182 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection LocalDiffBlocked RemoteTripBlock IEC15000472-1-en.vsd IEC15000472 V1 EN-US Figure 64: Trip signal logic for line differential coordination logic Some of the signals in the block and trip logic diagrams are used as internal signals by the coordination logic (see Table 103). Table 103: Internal signals Internal signals Source of destination Description testModeRemoteTerm1 Signal from LDCM Test mode from remote terminal 1 testModeRemoteTerm2 Signal from LDCM Test mode from remote terminal 2 testModeRemoteTerm3 Signal from LDCM Test mode from remote terminal 3 testModeRemoteTerm4 Signal from LDCM Test mode from remote terminal 4 blockRemoteTerm1 Signal from LDCM Block from remote terminal 1 blockRemoteTerm2 Signal from LDCM Block from remote terminal 2 blockRemoteTerm3 Signal from LDCM Block from remote terminal 3 blockRemoteTerm4 Signal from LDCM Block from remote terminal 4 testModeInput Signal from test mode function Input for forcing the function into test mode diffTripL1 Signal from differential function Trip from local differential function in phase L1 Table continues on next page Line differential protection RED670 Technical manual 183 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Internal signals 7.3.9 Source of destination Description diffTripL2 Signal from differential function Trip from local differential function in phase L2 diffTripL3 Signal from differential function Trip from local differential function in phase L3 tripL1RemoteTerm1 Signal from LDCM Trip from remote terminal 1 in phase L1 tripL1RemoteTerm2 Signal from LDCM Trip from remote terminal 2 in phase L1 tripL1RemoteTerm3 Signal from LDCM Trip from remote terminal 3 in phase L1 tripL1RemoteTerm4 Signal from LDCM Trip from remote terminal 4 in phase L1 tripL2RemoteTerm1 Signal from LDCM Trip from remote terminal 1 in phase L2 tripL2RemoteTerm2 Signal from LDCM Trip from remote terminal 2 in phase L2 tripL2RemoteTerm3 Signal from LDCM Trip from remote terminal 3 in phase L2 tripL2RemoteTerm4 Signal from LDCM Trip from remote terminal 4 in phase L2 tripL3RemoteTerm1 Signal from LDCM Trip from remote terminal 1 in phase L3 tripL3RemoteTerm2 Signal from LDCM Trip from remote terminal 2 in phase L3 tripL3RemoteTerm3 Signal from LDCM Trip from remote terminal 3 in phase L3 tripL3RemoteTerm4 Signal from LDCM Trip from remote terminal 4 in phase L3 tripL1ToRemote Signal to LDCM Trip to remote terminals phase L1 tripL2ToRemote Signal to LDCM Trip to remote terminals phase L2 tripL3ToRemote Signal to LDCM Trip to remote terminals phase L3 localDiffBlock Signal to differential function Block local line differential function operation blockToRemote Signal to LDCM Block to be sent to remote terminals testModeToRemote Signal to LDCM Test mode indication to be sent to remote terminals Logic diagrams GUID-F67293D2-2C80-4FDA-9DEF-9320A0C04D4A v2 Simplified logic diagram for L4CPDIF is shown in Figure 65. Open CT detection feature, approximate charging current compensation method and loss of data synchronism detection feature are not included. 184 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection IEC15000473-1-en.vsd IEC15000473 V1 EN-US Figure 65: Simplified logic for L4CPDIF L4CPDIF is fed by instantaneous values of all currents through raw current and voltage samples. Voltages are required only if the exact method of charging current compensation is needed. Raw current samples are used to calculate instantaneous differential currents. These currents are used for harmonic analysis, which means that the 2nd and the 5th harmonics are extracted from the currents using Fourier filtering. The analysis is done only on a phase with a start signal. If the fault is characterized as internal, the harmonic block logic is deactivated. The charging current compensation algorithm is fed by both voltage and current samples. Capacitive charging currents are calculated based on instantaneous values. When total capacitive currents are calculated separately for each phase, these currents are fed to the fundamental frequency Fourier filters. Applying the charging current compensation algorithm results in three charging currents expressed as phasors with their real and imaginary parts. These currents are then geometrically subtracted from the fundamental frequency differential currents in a phase-wise manner if the charging current compensation algorithm is activated. Samples of all input currents, separate for each end of a protected line for all three phases, are fed to the internal fundamental frequency Fourier filters. This results in separate currents expressed as phasors with their real and imaginary parts. These current are used to form the fundamental frequency differential current, one for each phase. The internal fault detector also uses currents expressed as phasors with their real and imaginary parts as shown in Figure 66. Line differential protection RED670 Technical manual 185 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P IEC15000474-1-en.vsd IEC15000474 V1 EN-US Figure 66: Simplified logic for the internal fault detector shown for a two-end power line (one detector for each phase) Pre-fault normal load currents are processed so that a reliable reference can be assured after a fault has been detected. An average value of each current stored for one fundamental frequency period (20 ms in 50 Hz power systems) before the fault is used to form the pure fault (incremental) currents. An incremental current is obtained if the pre-fault average current is subtracted geometrically from the total fault current. The relative angle between two incremental currents at both ends in a given phase provides reliable indication on whether a fault is internal or external. If the internal fault detector classifies the fault as internal, the harmonic block scheme is deactivated, and a trip is issued immediately after a trip request has been confirmed three times in succession. L4CPDIF consists of three totally independent internal fault detectors, one for each phase. In this way, an event in one phase (for example external fault in phase L1) has no negative impact on an event in another phase (for example internal fault in phase L1). 7.3.10 Technical data IP14336-1 v1 GUID-6746298E-4C29-44C6-AB59-41EBF408A5E4 v5 Table 104: L4CPDIF with 2 Mbit/s communication technical data Function Range or value Accuracy Minimum operate current (20-200)% of IBase ±1.0% of Ir at I ≤ Ir ±1.0% of I at I > Ir SlopeSection2 (10.0-100.0)% - SlopeSection3 (30.0-100.0)% - EndSection1 (20–200)% of IBase - EndSection2 (100–1000)% of IBase - Unrestrained limit function (100–10000)% of IBase ±1.0% of Ir at I ≤ Ir ±1.0% of I at I > Ir Table continues on next page 186 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Function Range or value Accuracy Second harmonic blocking (5.0–100.0)% of fundamental ±1.0% of Ir Note: fundamental magnitude = 100% of Ir Fifth harmonic blocking (5.0–100.0)% of fundamental ±3.0% of Ir Note: fundamental magnitude = 100% of Ir Critical impulse time 2 ms typically at 0 to 10 x IdMin - Operate time with two input groups' currents, restrained function, in a 50 Hz system1) Min. = 10 ms Max. = 20 ms - Operate time with two input groups' currents, restrained function, in a 60 1) Hz system Min. = 8 ms Max. = 17 ms - Operate time, restrained function at 2) 0 to 10 x IdMin, in a 50 Hz system Min. = 10 ms Max. = 20 ms - Operate time, restrained function at 2) 0 to 10 x IdMin, in a 60 Hz system Min. = 8 ms Max. = 17 ms - Reset time, restrained function at 2) 10 x IdMin to 0 Min. = 45 ms Max. = 65 ms - Operate time, unrestrained function at 0 to 10 x IdUnre2) Min. = 5 ms Max. = 17 ms - Reset time, unrestrained function at 2) 10 x IdUnre to 0 Min. = 45 ms Max. = 65 ms - The data in the table are valid for single IED with 2 Mbit/s communication in loop-back mode. The operate (trip) time is measured from general operate (trip) signal. In case of phase selective trip, the discrepancy between different phases might be few milliseconds for a three-phase fault. 1) This data is obtained by applying two three-phase input groups' currents to simulate an internal fault with default settings. Ir is applied to both input groups as pre- and post-fault currents. The fault is performed by simultaneously increasing one group's currents to 10 x IdMin and decreasing the other group's currents to 0. 2) This data is obtained by applying one three-phase input group's currents only. Line differential protection RED670 Technical manual 187 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P 7.4 Line differential protection 7.4.1 Identification IP13934-1 v1 M14844-1 v4 Function description Line differential protection, 3 CT sets, 2-3 line ends IEC 61850 identification IEC 60617 identification L3CPDIF 3Id/I> ANSI/IEEE C37.2 device number 87L SYMBOL-HH V1 EN-US Line differential protection, 6 CT sets, 3-5 line ends L6CPDIF 3Id/I> 87L SYMBOL-HH V1 EN-US Line differential protection 3 CT sets, with in-zone transformers, 2-3 line ends LT3CPDIF 3Id/I> 87LT SYMBOL-HH V1 EN-US Line differential protection 6 CT sets, with in-zone transformers, 3-5 line ends LT6CPDIF Line differential logic LDLPSCH 3Id/I> 87LT SYMBOL-HH V1 EN-US - 87L 7.4.2 Functionality 7.4.2.1 Line differential protection, 3 or 6 CT sets L3CPDIF, L6CPDIF M14917-3 v7 Line differential protection applies the Kirchhoff's law and compares the currents entering and leaving the protected multi-terminal circuit, consisting of overhead power lines and cables. Under the condition that there are no in-line or tap (shunt) power transformers within the zone of protection, it offers a phase segregated fundamental frequency current based differential protection with high sensitivity and provides phase selection information for single-pole tripping L3CPDIF is used for conventional two-terminal lines with or without a 1½ circuit breaker arrangement in one end, as well as three-terminal lines with single breaker arrangements at all terminals. Protected zone IED IEC05000039 V3 EN-US Figure 67: Communication channel IED IEC05000039-3-en.vsd Example of application on a conventional two-terminal line 188 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection L6CPDIF is used for conventional two-terminal lines with 1½ circuit breaker arrangements in both ends, as well as multi-terminal lines with up to five terminals. Protected zone Comm. Channel IED IED Comm. Channel Comm. Channel IED IEC05000040_2_en.vsd IEC05000040 V2 EN-US Figure 68: Example of application on a three-terminal line with 1½ breaker arrangements The current differential algorithm provides high sensitivity for internal faults and it has excellent stability for external faults. Current samples from all CTs are exchanged between the IEDs in the line ends (master-master mode) or sent to one IED (master-slave mode) for evaluation. A restrained dual biased slope evaluation is made where the bias current is the highest phase current in any line end, giving a secure through-fault stability even with heavily saturated CTs. In addition to the restrained evaluation, an unrestrained (instantaneous) high differential current setting can be used for fast tripping of internal faults with very high currents. A special feature with this function is that applications with small power transformers (rated current less than 50% of the differential current setting IdMin) connected as line taps (that is, as shunt power transformers), without measurements of currents in the tap, can be handled. The normal load current is considered to be negligible, and special measures must be taken in the event of a short circuit on the LV side of the transformer. In this application, the tripping of the differential protection can be time-delayed for low differential currents to achieve coordination with downstream overcurrent IEDs. The local protection of the small tap power transformer is given the time needed to disconnect the faulty transformer. A line charging current compensation provides increased sensitivity of line differential protection. 7.4.2.2 Line differential protection 3 or 6 CT sets, with in-zone transformers LT3CPDIF , LT6CPDIF M14932-3 v9 Two two-winding power transformers or one three-winding power transformer can be included in the line differential protection zone. In such application, the differential protection is based on the ampere turns balance between the transformer windings. Both two- and three-winding transformers are correctly represented with vector group compensations made in the algorithm. The function includes 2nd and 5th harmonic restraint and zero-sequence current elimination. The phase-segregated differential protection with single-pole tripping is usually not possible in such applications. Line differential protection RED670 Technical manual 189 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Protected zone Comm. Channel IED Comm. Channel IED Comm. Channel IED IEC05000042_2_en.vsd IEC05000042 V2 EN-US Figure 69: 7.4.2.3 Example of application on a three-terminal line with an in-line power transformer in the protection zone Analog signal transfer for line differential protection M13647-3 v9 The line differential protection function can be arranged as a master-master system or a masterslave system alternatively. In the former, current samples are exchanged between all IEDs, and an evaluation is made in each IED. This means that a 64 kbits/s or 2 Mbit/s communication channel is needed between every IED included in the same line differential protection zone. In the latter, current samples are sent from all slave IEDs to one master IED where the evaluation is made, and trip signals are sent to the remote ends when needed. In this system, a 64 kbits/s or 2 Mbit/s communication channel is only needed between the master and each one of the slave IEDs. The Master-Slave condition for the differential function appears automatically when the setting Operation for the differential function is set to Off. For line differential protection we recommend that all feeder ends use the same version of RED670 and the line data communication module LDCM. The line differential protection in the latest version of RED670 is compatible with older versions of RED670. Older versions than 670 1.2.3 must be verified with Hitachi Power Grids. Protected zone IED IED Comm. Channels IED IED IED IEC0500043_2_en.vsd IEC05000043 V2 EN-US Figure 70: Five terminal lines with master-master system 190 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Protected zone IED IED Comm. Channels IED IED IED IEC050000 44-2en.vsd IEC05000044 V2 EN-US Figure 71: Five terminal line with master-slave system Current samples from IEDs located geographically apart from each other, must be time coordinated so that the current differential algorithm can be executed correctly, this is done with the echo method. Networks with fixed routes where symmetric time delay is applied, or networks with fixed route switching where both directions have the symmetric time delay even after route switching has been performed. In these types of networks, different channel delay times are automatically compensated for, and echo timing can be used. Networks with unspecified route switching require that the line differential protection IED's built-in GPS receiver, PTP or IRIG-B is used. This way the protection function can operate correctly independent of the symmetric delays in communication channels. The communication link is continuously monitored, and an automatic switchover to a standby link is possible after a preset time. Line differential protection RED670 Technical manual 191 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 7.4.3 1MRK 505 377-UEN Rev. P Function block SEMOD54630-1 v1 M14921-3 v3 L3CPDIF I3P1* I3P2* I3P3* TRIP TRL1 TRL2 TRL3 STARTRES STARTUNR STARTENH START STL1 STL2 STL3 INTFAULT EXTFAULT BLK2H BLK2HL1 BLK2HL2 BLK2HL3 BLK5H BLK5HL1 BLK5HL2 BLK5HL3 ALARM OPENCT OPENCTAL IDL1 IDL2 IDL3 IDL1MAG IDL2MAG IDL3MAG IBIAS IDNSMAG IEC06000252-3-en.vsd IEC06000252 V3 EN-US Figure 72: L3CPDIF function block M14920-3 v3 L6CPDIF I3P1* I3P2* I3P3* I3P4* I3P5* I3P6* TRIP TRL1 TRL2 TRL3 STARTRES STARTUNR STARTENH START STL1 STL2 STL3 INTFAULT EXTFAULT BLK2H BLK2HL1 BLK2HL2 BLK2HL3 BLK5H BLK5HL1 BLK5HL2 BLK5HL3 ALARM OPENCT OPENCTAL IDL1 IDL2 IDL3 IDL1MAG IDL2MAG IDL3MAG IBIAS IDNSMAG IEC06000253-3-en.vsd IEC06000253 V3 EN-US Figure 73: L6CPDIF function block 192 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection M14937-3 v3 LT3CPDIF I3P1* I3P2* I3P3* TRIP TRL1 TRL2 TRL3 STARTRES STARTUNR STARTENH START STL1 STL2 STL3 INTFAULT EXTFAULT BLK2H BLK2HL1 BLK2HL2 BLK2HL3 BLK5H BLK5HL1 BLK5HL2 BLK5HL3 ALARM OPENCT OPENCTAL IDL1 IDL2 IDL3 IDL1MAG IDL2MAG IDL3MAG IBIAS IDNSMAG IEC06000254-3-en.vsd IEC06000254 V3 EN-US Figure 74: LT3CPDIF function block M14936-3 v2 LT6CPDIF I3P1* I3P2* I3P3* I3P4* I3P5* I3P6* TRIP TRL1 TRL2 TRL3 STARTRES STARTUNR STARTENH START STL1 STL2 STL3 INTFAULT EXTFAULT BLK2H BLK2HL1 BLK2HL2 BLK2HL3 BLK5H BLK5HL1 BLK5HL2 BLK5HL3 ALARM OPENCT OPENCTAL IDL1 IDL2 IDL3 IDL1MAG IDL2MAG IDL3MAG IBIAS IDNSMAG IEC06000255-3-en.vsd IEC06000255 V3 EN-US Figure 75: LT6CPDIF function block Line differential protection RED670 Technical manual 193 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P M12591-3 v4 LDLPSCH CTFAIL OUTSERV BLOCK TRIP TRL1 TRL2 TRL3 TRLOCAL TRLOCL1 TRLOCL2 TRLOCL3 TRREMOTE DIFLBLKD IEC13000302-1-en.vsd IEC13000302 V1 EN-US Figure 76: 7.4.4 LDLPSCH function block Signals PID-6750-INPUTSIGNALS v1 Table 105: L3CPDIF Input signals Name Type Default Description I3P1 GROUP SIGNAL - Three phase current grp1 samples and DFT values I3P2 GROUP SIGNAL - Three phase current grp2 samples and DFT values I3P3 GROUP SIGNAL - Three phase current grp3 samples and DFT values PID-6750-OUTPUTSIGNALS v1 Table 106: L3CPDIF Output signals Name Type Description TRIP BOOLEAN Common, main, trip output signal TRL1 BOOLEAN Trip signal from phase L1 TRL2 BOOLEAN Trip signal from phase L2 TRL3 BOOLEAN Trip signal from phase L3 STARTRES BOOLEAN Start of restrained differential protection STARTUNR BOOLEAN Start of unrestrained differential protection STARTENH BOOLEAN Start of enhanced restrained differential protection START BOOLEAN Common, main, start output signal STL1 BOOLEAN Start signal from phase L1 STL2 BOOLEAN Start signal from phase L2 STL3 BOOLEAN Start signal from phase L3 INTFAULT BOOLEAN Internal fault has been detected EXTFAULT BOOLEAN External fault has been detected BLK2H BOOLEAN Common block signal, due to 2nd harmonic BLK2HL1 BOOLEAN Block signal due to 2nd harmonic, phase L1 BLK2HL2 BOOLEAN Block signal due to 2nd harmonic, phase L2 BLK2HL3 BOOLEAN Block signal due to 2nd harmonic, phase L3 BLK5H BOOLEAN Common block signal, due to 5-th harmonic BLK5HL1 BOOLEAN Block signal due to 5th harmonic, phase L1 BLK5HL2 BOOLEAN Block signal due to 5th harmonic, phase L2 Table continues on next page 194 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Name Section 7 Differential protection Type Description BLK5HL3 BOOLEAN Block signal due to 5th harmonic, phase L3 ALARM BOOLEAN Alarm for sustained differential current OPENCT BOOLEAN An open CT was detected OPENCTAL BOOLEAN Open CT Alarm output signal. Issued after a delay ... IDL1 REAL Instantaneous differential current, phase L1 IDL2 REAL Instantaneous differential current, phase L2 IDL3 REAL Instantaneous differential current, phase L3 IDL1MAG REAL Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL Magnitude of fund. freq. differential current, phase L3 IBIAS REAL Magnitude of the bias current, common for L1, L2, L3 IDNSMAG REAL Magnitude of the negative sequence differential current PID-6748-INPUTSIGNALS v1 Table 107: L6CPDIF Input signals Name Type Default Description I3P1 GROUP SIGNAL - Three phase current grp1 samples and DFT values I3P2 GROUP SIGNAL - Three phase current grp2 samples and DFT values I3P3 GROUP SIGNAL - Three phase current grp3 samples and DFT values I3P4 GROUP SIGNAL - Three phase current grp4 samples and DFT values I3P5 GROUP SIGNAL - Three phase current grp5 samples and DFT values I3P6 GROUP SIGNAL - Three phase current grp6 samples and DFT values PID-6748-OUTPUTSIGNALS v1 Table 108: L6CPDIF Output signals Name Type Description TRIP BOOLEAN Common, main, trip output signal TRL1 BOOLEAN Trip signal from phase L1 TRL2 BOOLEAN Trip signal from phase L2 TRL3 BOOLEAN Trip signal from phase L3 STARTRES BOOLEAN Start of restrained differential protection STARTUNR BOOLEAN Start of unrestrained differential protection STARTENH BOOLEAN Start of enhanced restrained differential protection START BOOLEAN Common, main, start output signal STL1 BOOLEAN Start signal from phase L1 STL2 BOOLEAN Start signal from phase L2 STL3 BOOLEAN Start signal from phase L3 INTFAULT BOOLEAN Internal fault has been detected EXTFAULT BOOLEAN External fault has been detected BLK2H BOOLEAN Common block signal, due to 2nd harmonic Table continues on next page Line differential protection RED670 Technical manual 195 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Name Type Description BLK2HL1 BOOLEAN Block signal due to 2nd harmonic, phase L1 BLK2HL2 BOOLEAN Block signal due to 2nd harmonic, phase L2 BLK2HL3 BOOLEAN Block signal due to 2nd harmonic, phase L3 BLK5H BOOLEAN Common block signal, due to 5-th harmonic BLK5HL1 BOOLEAN Block signal due to 5th harmonic, phase L1 BLK5HL2 BOOLEAN Block signal due to 5th harmonic, phase L2 BLK5HL3 BOOLEAN Block signal due to 5th harmonic, phase L3 ALARM BOOLEAN Alarm for sustained differential current OPENCT BOOLEAN An open CT was detected OPENCTAL BOOLEAN Open CT Alarm output signal. Issued after a delay ... IDL1 REAL Instantaneous differential current, phase L1 IDL2 REAL Instantaneous differential current, phase L2 IDL3 REAL Instantaneous differential current, phase L3 IDL1MAG REAL Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL Magnitude of fund. freq. differential current, phase L3 IBIAS REAL Magnitude of the bias current, common for L1, L2, L3 IDNSMAG REAL Magnitude of the negative sequence differential current PID-3701-INPUTSIGNALS v4 Table 109: LT3CPDIF Input signals Name Type Default Description I3P1 GROUP SIGNAL - Three phase current grp1 samples and DFT values I3P2 GROUP SIGNAL - Three phase current grp2 samples and DFT values I3P3 GROUP SIGNAL - Three phase current grp3 samples and DFT values PID-3701-OUTPUTSIGNALS v4 Table 110: LT3CPDIF Output signals Name Type Description TRIP BOOLEAN Common, main, trip output signal TRL1 BOOLEAN Trip signal from phase L1 TRL2 BOOLEAN Trip signal from phase L2 TRL3 BOOLEAN Trip signal from phase L3 STARTRES BOOLEAN Start of restrained differential protection STARTUNR BOOLEAN Start of unrestrained differential protection STARTENH BOOLEAN Start of enhanced restrained differential protection START BOOLEAN Common, main, start output signal STL1 BOOLEAN Start signal from phase L1 STL2 BOOLEAN Start signal from phase L2 STL3 BOOLEAN Start signal from phase L3 INTFAULT BOOLEAN Internal fault has been detected EXTFAULT BOOLEAN External fault has been detected Table continues on next page 196 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Name Section 7 Differential protection Type Description BLK2H BOOLEAN Common block signal, due to 2nd harmonic BLK2HL1 BOOLEAN Block signal due to 2nd harmonic, phase L1 BLK2HL2 BOOLEAN Block signal due to 2nd harmonic, phase L2 BLK2HL3 BOOLEAN Block signal due to 2nd harmonic, phase L3 BLK5H BOOLEAN Common block signal, due to 5-th harmonic BLK5HL1 BOOLEAN Block signal due to 5th harmonic, phase L1 BLK5HL2 BOOLEAN Block signal due to 5th harmonic, phase L2 BLK5HL3 BOOLEAN Block signal due to 5th harmonic, phase L3 ALARM BOOLEAN Alarm for sustained differential current OPENCT BOOLEAN An open CT was detected OPENCTAL BOOLEAN Open CT Alarm output signal. Issued after a delay ... IDL1 REAL Instantaneous differential current, phase L1 IDL2 REAL Instantaneous differential current, phase L2 IDL3 REAL Instantaneous differential current, phase L3 IDL1MAG REAL Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL Magnitude of fund. freq. differential current, phase L3 IBIAS REAL Magnitude of the bias current, common for L1, L2, L3 IDNSMAG REAL Magnitude of the negative sequence differential current PID-3699-INPUTSIGNALS v4 Table 111: LT6CPDIF Input signals Name Type Default Description I3P1 GROUP SIGNAL - Three phase current grp1 samples and DFT values I3P2 GROUP SIGNAL - Three phase current grp2 samples and DFT values I3P3 GROUP SIGNAL - Three phase current grp3 samples and DFT values I3P4 GROUP SIGNAL - Three phase current grp4 samples and DFT values I3P5 GROUP SIGNAL - Three phase current grp5 samples and DFT values I3P6 GROUP SIGNAL - Three phase current grp6 samples and DFT values PID-3699-OUTPUTSIGNALS v4 Table 112: LT6CPDIF Output signals Name Type Description TRIP BOOLEAN Common, main, trip output signal TRL1 BOOLEAN Trip signal from phase L1 TRL2 BOOLEAN Trip signal from phase L2 TRL3 BOOLEAN Trip signal from phase L3 STARTRES BOOLEAN Start of restrained differential protection STARTUNR BOOLEAN Start of unrestrained differential protection STARTENH BOOLEAN Start of enhanced restrained differential protection Table continues on next page Line differential protection RED670 Technical manual 197 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Name Type Description START BOOLEAN Common, main, start output signal STL1 BOOLEAN Start signal from phase L1 STL2 BOOLEAN Start signal from phase L2 STL3 BOOLEAN Start signal from phase L3 INTFAULT BOOLEAN Internal fault has been detected EXTFAULT BOOLEAN External fault has been detected BLK2H BOOLEAN Common block signal, due to 2nd harmonic BLK2HL1 BOOLEAN Block signal due to 2nd harmonic, phase L1 BLK2HL2 BOOLEAN Block signal due to 2nd harmonic, phase L2 BLK2HL3 BOOLEAN Block signal due to 2nd harmonic, phase L3 BLK5H BOOLEAN Common block signal, due to 5-th harmonic BLK5HL1 BOOLEAN Block signal due to 5th harmonic, phase L1 BLK5HL2 BOOLEAN Block signal due to 5th harmonic, phase L2 BLK5HL3 BOOLEAN Block signal due to 5th harmonic, phase L3 ALARM BOOLEAN Alarm for sustained differential current OPENCT BOOLEAN An open CT was detected OPENCTAL BOOLEAN Open CT Alarm output signal. Issued after a delay ... IDL1 REAL Instantaneous differential current, phase L1 IDL2 REAL Instantaneous differential current, phase L2 IDL3 REAL Instantaneous differential current, phase L3 IDL1MAG REAL Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL Magnitude of fund. freq. differential current, phase L3 IBIAS REAL Magnitude of the bias current, common for L1, L2, L3 IDNSMAG REAL Magnitude of the negative sequence differential current PID-3560-INPUTSIGNALS v6 Table 113: LDLPSCH Input signals Name Type Default Description CTFAIL BOOLEAN 0 CT failure indication from local CT supervision OUTSERV BOOLEAN 0 Input for indicating that the terminal is out of service BLOCK BOOLEAN 0 Block of function PID-3560-OUTPUTSIGNALS v7 Table 114: LDLPSCH Output signals Name Type Description TRIP BOOLEAN General trip from differential protection system TRL1 BOOLEAN Trip signal from phase L1 TRL2 BOOLEAN Trip signal from phase L2 TRL3 BOOLEAN Trip signal from phase L3 TRLOCAL BOOLEAN Trip from local differential function TRLOCL1 BOOLEAN Trip from local differential function in phase L1 TRLOCL2 BOOLEAN Trip from local differential function in phase L2 Table continues on next page 198 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Name 7.4.5 Type Description TRLOCL3 BOOLEAN Trip from local differential function in phase L3 TRREMOTE BOOLEAN Trip from remote differential function DIFLBLKD BOOLEAN Local line differential function blocked Settings PID-6750-SETTINGS v1 Table 115: L3CPDIF Group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Off / On IdMin 0.20 - 2.00 IB 0.01 0.30 Oper - restr charact., section 1 sensitivity, multiple IBase IdMinHigh 0.20 - 10.00 IB 0.01 0.80 Initial lower sensitivity, as multiple of IBase tIdMinHigh 0.000 - 60.000 s 0.001 1.000 Time interval of initial lower sensitivity, in sec IdUnre 1.00 - 50.00 IB 0.01 10.00 Unrestrained differential current limit, multiple of IBase NegSeqDiffEn Off On - - On Off/On selection for internal / external fault discriminator NegSeqROA 30.0 - 120.0 Deg 1.0 60.0 Internal/external fault discriminator Operate Angle, degrees IMinNegSeq 0.01 - 0.20 IB 0.01 0.04 Min. value of neg. seq. curr. as multiple of IBase CrossBlockEn No Yes - - No Off/On selection of the cross -block logic ChargCurEnable Off On - - Off Off/On selection for compensation of charging currents AddDelay Off On - - Off Off/On selection for delayed diff. trip command IMaxAddDelay 0.20 - 5.00 IB 0.01 1.00 Below limit, extra delay can be applied, multiple of IBase tDefTime 0.000 - 6.000 s 0.001 0.000 Definite time additional delay in seconds tMinInv 0.001 - 6.000 s 0.001 0.010 Inverse Delay Minimum Time. In seconds CurveType ANSI Ext. inv. ANSI Very inv. ANSI Norm. inv. ANSI Mod. inv. ANSI Def. Time L.T.E. inv. L.T.V. inv. L.T. inv. IEC Norm. inv. IEC Very inv. IEC inv. IEC Ext. inv. IEC S.T. inv. IEC L.T. inv. IEC Def. Time Programmable RI type RD type - - IEC Def. Time 19 curve types. Example: 15 for definite time delay. Table continues on next page Line differential protection RED670 Technical manual 199 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection Name 1MRK 505 377-UEN Rev. P Values (Range) Unit Step Default Description k 0.05 - 1.10 - 0.01 1.00 Time Multiplier Setting (TMS) for inverse delays IdiffAlarm 0.05 - 1.00 IB 0.01 0.15 Sustained differential current alarm, factor of IBase tAlarmdelay 0.000 - 60.000 s 0.001 10.000 Delay for alarm due to sustained differential current, in s Table 116: L3CPDIF Group settings (advanced) Name Unit Step EndSection1 Values (Range) 0.20 - 1.50 IB 0.01 Default 1.25 Description End of section 1, as multiple of reference current IBase EndSection2 1.00 - 10.00 IB 0.01 3.00 End of section 2, as multiple of reference current IBase SlopeSection2 10.0 - 50.0 % 0.1 40.0 Slope in section 2 of operate-restrain characteristic, in % SlopeSection3 30.0 - 100.0 % 0.1 80.0 Slope in section 3 of operate- restrain characteristic, in % I2/I1Ratio 5.0 - 100.0 % 1.0 10.0 Max. ratio of 2nd harm. to fundamental harm dif. curr. in % I5/I1Ratio 5.0 - 100.0 % 1.0 25.0 Max. ratio of 5th harm. to fundamental harm dif. curr. in % p 0.01 - 1000.00 - 0.01 0.02 Settable curve parameter, userprogrammable curve type. a 0.01 - 1000.00 - 0.01 0.14 Settable curve parameter, userprogrammable curve type. b 0.01 - 1000.00 - 0.01 1.00 Settable curve parameter, userprogrammable curve type. c 0.01 - 1000.00 - 0.01 1.00 Settable curve parameter, userprogrammable curve type. OpenCTEnable Off On - - On Open CTEnable Off/On tOCTAlarmDelay 0.100 - 10.000 s 0.001 1.000 Open CT: time in s to alarm after an open CT is detected tOCTResetDelay 0.100 - 10.000 s 0.001 0.250 Reset delay in s. After delay, diff. function is activated OCTBlockEn Off On - - On Enable Open CT blocking function trip Off/On Table 117: L3CPDIF Non group settings (basic) Name Values (Range) Unit Step Default Description GlobalBaseSel 1 - 12 - 1 1 Selection of one of the Global Base Value groups NoOfUsedCTs 2 3 - - 2 Total number of 3-Ph CT sets connected to diff protection 200 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection PID-6748-SETTINGS v1 Table 118: L6CPDIF Group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Off / On IdMin 0.20 - 2.00 IB 0.01 0.30 Oper - restr charact., section 1 sensitivity, multiple IBase IdMinHigh 0.20 - 10.00 IB 0.01 0.80 Initial lower sensitivity, as multiple of IBase tIdMinHigh 0.000 - 60.000 s 0.001 1.000 Time interval of initial lower sensitivity, in sec IdUnre 1.00 - 50.00 IB 0.01 10.00 Unrestrained differential current limit, multiple of IBase NegSeqDiffEn Off On - - On Off/On selection for internal / external fault discriminator NegSeqROA 30.0 - 120.0 Deg 1.0 60.0 Internal/external fault discriminator Operate Angle, degrees IMinNegSeq 0.01 - 0.20 IB 0.01 0.04 Min. value of neg. seq. curr. as multiple of IBase CrossBlockEn No Yes - - No Off/On selection of the cross -block logic I2/I1Ratio 5.0 - 100.0 % 1.0 10.0 Max. ratio of 2nd harm. to fundamental harm dif. curr. in % I5/I1Ratio 5.0 - 100.0 % 1.0 25.0 Max. ratio of 5th harm. to fundamental harm dif. curr. in % ChargCurEnable Off On - - Off Off/On selection for compensation of charging currents AddDelay Off On - - Off Off/On selection for delayed diff. trip command IMaxAddDelay 0.20 - 5.00 IB 0.01 1.00 Below limit, extra delay can be applied, multiple of IBase tDefTime 0.000 - 6.000 s 0.001 0.000 Definite time additional delay in seconds tMinInv 0.001 - 6.000 s 0.001 0.010 Inverse Delay Minimum Time. In seconds CurveType ANSI Ext. inv. ANSI Very inv. ANSI Norm. inv. ANSI Mod. inv. ANSI Def. Time L.T.E. inv. L.T.V. inv. L.T. inv. IEC Norm. inv. IEC Very inv. IEC inv. IEC Ext. inv. IEC S.T. inv. IEC L.T. inv. IEC Def. Time Programmable RI type RD type - - IEC Def. Time 19 curve types. Example: 15 for definite time delay. Table continues on next page Line differential protection RED670 Technical manual 201 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection Name 1MRK 505 377-UEN Rev. P Values (Range) Unit Step Default Description k 0.05 - 1.10 - 0.01 1.00 Time Multiplier Setting (TMS) for inverse delays IdiffAlarm 0.05 - 1.00 IB 0.01 0.15 Sustained differential current alarm, factor of IBase tAlarmdelay 0.000 - 60.000 s 0.001 10.000 Delay for alarm due to sustained differential current, in s Table 119: L6CPDIF Group settings (advanced) Name Unit Step EndSection1 Values (Range) 0.20 - 1.50 IB 0.01 Default 1.25 Description End of section 1, as multiple of reference current IBase EndSection2 1.00 - 10.00 IB 0.01 3.00 End of section 2, as multiple of reference current IBase SlopeSection2 10.0 - 50.0 % 0.1 40.0 Slope in section 2 of operate-restrain characteristic, in % SlopeSection3 30.0 - 100.0 % 0.1 80.0 Slope in section 3 of operate- restrain characteristic, in % p 0.01 - 1000.00 - 0.01 0.02 Settable curve parameter, userprogrammable curve type. a 0.01 - 1000.00 - 0.01 0.14 Settable curve parameter, userprogrammable curve type. b 0.01 - 1000.00 - 0.01 1.00 Settable curve parameter, userprogrammable curve type. c 0.01 - 1000.00 - 0.01 1.00 Settable curve parameter, userprogrammable curve type. OpenCTEnable Off On - - On Open CTEnable Off/On tOCTAlarmDelay 0.100 - 10.000 s 0.001 1.000 Open CT: time in s to alarm after an open CT is detected tOCTResetDelay 0.100 - 10.000 s 0.001 0.250 Reset delay in s. After delay, diff. function is activated OCTBlockEn Off On - - On Enable Open CT blocking function trip Off/On Table 120: L6CPDIF Non group settings (basic) Name Values (Range) Unit Step Default Description GlobalBaseSel 1 - 12 - 1 1 Selection of one of the Global Base Value groups NoOfUsedCTs 2 3 4 5 6 - - 2 Total number of 3-Ph CT sets connected to diff protection PID-6605-SETTINGS v3 Table 121: LT3CPDIF Group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Off / On IdMin 0.20 - 2.00 IB 0.01 0.30 Oper - restr charact., section 1 sensitivity, multiple IBase IdMinHigh 0.20 - 10.00 IB 0.01 0.80 Initial lower sensitivity, as multiple of IBase Table continues on next page 202 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Name Section 7 Differential protection Values (Range) Unit Step Default Description tIdMinHigh 0.000 - 60.000 s 0.001 1.000 Time interval of initial lower sensitivity, in sec IdUnre 1.00 - 50.00 IB 0.01 10.00 Unrestrained differential current limit, multiple of IBase NegSeqDiffEn Off On - - On Off/On selection for internal / external fault discriminator NegSeqROA 30.0 - 120.0 Deg 1.0 60.0 Internal/external fault discriminator Operate Angle, degrees IMinNegSeq 0.01 - 0.20 IB 0.01 0.04 Min. value of neg. seq. curr. as multiple of IBase CrossBlockEn No Yes - - No Off/On selection of the cross -block logic ChargCurEnable Off On - - Off Off/On selection for compensation of charging currents AddDelay Off On - - Off Off/On selection for delayed diff. trip command IMaxAddDelay 0.20 - 5.00 IB 0.01 1.00 Below limit, extra delay can be applied, multiple of IBase tDefTime 0.000 - 6.000 s 0.001 0.000 Definite time additional delay in seconds tMinInv 0.001 - 6.000 s 0.001 0.010 Inverse Delay Minimum Time. In seconds CurveType ANSI Ext. inv. ANSI Very inv. ANSI Norm. inv. ANSI Mod. inv. ANSI Def. Time L.T.E. inv. L.T.V. inv. L.T. inv. IEC Norm. inv. IEC Very inv. IEC inv. IEC Ext. inv. IEC S.T. inv. IEC L.T. inv. IEC Def. Time Programmable RI type RD type - - IEC Def. Time 19 curve types. Example: 15 for definite time delay. k 0.05 - 1.10 - 0.01 1.00 Time Multiplier Setting (TMS) for inverse delays IdiffAlarm 0.05 - 1.00 IB 0.01 0.15 Sustained differential current alarm, factor of IBase tAlarmdelay 0.000 - 60.000 s 0.001 10.000 Delay for alarm due to sustained differential current, in s Table 122: LT3CPDIF Group settings (advanced) Name Unit Step EndSection1 Values (Range) 0.20 - 1.50 IB 0.01 Default 1.25 Description End of section 1, as multiple of reference current IBase EndSection2 1.00 - 10.00 IB 0.01 3.00 End of section 2, as multiple of reference current IBase SlopeSection2 10.0 - 50.0 % 0.1 40.0 Slope in section 2 of operate-restrain characteristic, in % Table continues on next page Line differential protection RED670 Technical manual 203 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection Name 1MRK 505 377-UEN Rev. P Unit Step SlopeSection3 Values (Range) 30.0 - 100.0 % 0.1 Default 80.0 Description Slope in section 3 of operate- restrain characteristic, in % I2/I1Ratio 5.0 - 100.0 % 1.0 10.0 Max. ratio of 2nd harm. to fundamental harm dif. curr. in % I5/I1Ratio 5.0 - 100.0 % 1.0 25.0 Max. ratio of 5th harm. to fundamental harm dif. curr. in % p 0.01 - 1000.00 - 0.01 0.02 Settable curve parameter, userprogrammable curve type. a 0.01 - 1000.00 - 0.01 0.14 Settable curve parameter, userprogrammable curve type. b 0.01 - 1000.00 - 0.01 1.00 Settable curve parameter, userprogrammable curve type. c 0.01 - 1000.00 - 0.01 1.00 Settable curve parameter, userprogrammable curve type. OpenCTEnable Off On - - On Open CTEnable Off/On tOCTAlarmDelay 0.100 - 10.000 s 0.001 1.000 Open CT: time in s to alarm after an open CT is detected tOCTResetDelay 0.100 - 10.000 s 0.001 0.250 Reset delay in s. After delay, diff. function is activated OCTBlockEn Off On - - On Enable Open CT blocking function trip Off/On Table 123: LT3CPDIF Non group settings (basic) Name Values (Range) Unit Step Default Description GlobalBaseSel 1 - 12 - 1 1 Selection of one of the Global Base Value groups NoOfUsedCTs 2 3 - - 2 Total number of 3-Ph CT sets connected to diff protection ZerSeqCurSubtr Off On - - Off Off/On for elimination of zero seq. from diff. and bias curr TraAOnInpCh No Transf A 1 2 3 - - No Transf A Power transformer A applied on input channel X RatVoltW1TraA 1.0 - 9999.9 kV 0.1 130.0 Transformer A rated voltage (kV) on winding 1 (HV winding) RatVoltW2TraA 1.0 - 9999.9 kV 0.1 130.0 Transformer A rated voltage (kV) on winding 2 (LV winding) ClockNumTransA 0 [0 deg] 1 [30 deg lag] 2 [60 deg lag] 3 [90 deg lag] 4 [120 deg lag] 5 [150 deg lag] 6 [180 deg lag] 7 [210 deg lag] 8 [240 deg lag] 9 [270 deg lag] 10 [300 deg lag] 11 [330 deg lag] - - 0 [0 deg] Transf. A phase shift in multiples of 30 deg, 5 for 150 deg TraBOnInpCh No Transf B 1 2 3 - - No Transf B Power transformer B applied on input channel X Table continues on next page 204 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Name Section 7 Differential protection Unit Step Default RatVoltW1TraB Values (Range) 1.0 - 9999.9 kV 0.1 130.0 Description Transformer B rated voltage (kV) on winding 1 (HV winding) RatVoltW2TraB 1.0 - 9999.9 kV 0.1 130.0 Transformer B rated voltage (kV) on winding 2 (LV winding) ClockNumTransB 0 [0 deg] 1 [30 deg lag] 2 [60 deg lag] 3 [90 deg lag] 4 [120 deg lag] 5 [150 deg lag] 6 [180 deg lag] 7 [210 deg lag] 8 [240 deg lag] 9 [270 deg lag] 10 [300 deg lag] 11 [330 deg lag] - - 0 [0 deg] Transf. B phase shift in multiples of 30 deg, 2 for 60 deg PID-6606-SETTINGS v3 Table 124: LT6CPDIF Group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Off / On IdMin 0.20 - 2.00 IB 0.01 0.30 Oper - restr charact., section 1 sensitivity, multiple IBase IdMinHigh 0.20 - 10.00 IB 0.01 0.80 Initial lower sensitivity, as multiple of IBase tIdMinHigh 0.000 - 60.000 s 0.001 1.000 Time interval of initial lower sensitivity, in sec IdUnre 1.00 - 50.00 IB 0.01 10.00 Unrestrained differential current limit, multiple of IBase NegSeqDiffEn Off On - - On Off/On selection for internal / external fault discriminator NegSeqROA 30.0 - 120.0 Deg 1.0 60.0 Internal/external fault discriminator Operate Angle, degrees IMinNegSeq 0.01 - 0.20 IB 0.01 0.04 Min. value of neg. seq. curr. as multiple of IBase CrossBlockEn No Yes - - No Off/On selection of the cross -block logic I2/I1Ratio 5.0 - 100.0 % 1.0 10.0 Max. ratio of 2nd harm. to fundamental harm dif. curr. in % I5/I1Ratio 5.0 - 100.0 % 1.0 25.0 Max. ratio of 5th harm. to fundamental harm dif. curr. in % ChargCurEnable Off On - - Off Off/On selection for compensation of charging currents AddDelay Off On - - Off Off/On selection for delayed diff. trip command IMaxAddDelay 0.20 - 5.00 IB 0.01 1.00 Below limit, extra delay can be applied, multiple of IBase tDefTime 0.000 - 6.000 s 0.001 0.000 Definite time additional delay in seconds tMinInv 0.001 - 6.000 s 0.001 0.010 Inverse Delay Minimum Time. In seconds Table continues on next page Line differential protection RED670 Technical manual 205 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection Name 1MRK 505 377-UEN Rev. P Values (Range) Unit Step Default Description CurveType ANSI Ext. inv. ANSI Very inv. ANSI Norm. inv. ANSI Mod. inv. ANSI Def. Time L.T.E. inv. L.T.V. inv. L.T. inv. IEC Norm. inv. IEC Very inv. IEC inv. IEC Ext. inv. IEC S.T. inv. IEC L.T. inv. IEC Def. Time Programmable RI type RD type - - IEC Def. Time 19 curve types. Example: 15 for definite time delay. k 0.05 - 1.10 - 0.01 1.00 Time Multiplier Setting (TMS) for inverse delays IdiffAlarm 0.05 - 1.00 IB 0.01 0.15 Sustained differential current alarm, factor of IBase tAlarmdelay 0.000 - 60.000 s 0.001 10.000 Delay for alarm due to sustained differential current, in s Table 125: LT6CPDIF Group settings (advanced) Name Values (Range) Unit Step Default Description EndSection1 0.20 - 1.50 IB 0.01 1.25 End of section 1, as multiple of reference current IBase EndSection2 1.00 - 10.00 IB 0.01 3.00 End of section 2, as multiple of reference current IBase SlopeSection2 10.0 - 50.0 % 0.1 40.0 Slope in section 2 of operate-restrain characteristic, in % SlopeSection3 30.0 - 100.0 % 0.1 80.0 Slope in section 3 of operate- restrain characteristic, in % p 0.01 - 1000.00 - 0.01 0.02 Settable curve parameter, userprogrammable curve type. a 0.01 - 1000.00 - 0.01 0.14 Settable curve parameter, userprogrammable curve type. b 0.01 - 1000.00 - 0.01 1.00 Settable curve parameter, userprogrammable curve type. c 0.01 - 1000.00 - 0.01 1.00 Settable curve parameter, userprogrammable curve type. OpenCTEnable Off On - - On Open CTEnable Off/On tOCTAlarmDelay 0.100 - 10.000 s 0.001 1.000 Open CT: time in s to alarm after an open CT is detected tOCTResetDelay 0.100 - 10.000 s 0.001 0.250 Reset delay in s. After delay, diff. function is activated OCTBlockEn Off On - - On Enable Open CT blocking function trip Off/On 206 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Table 126: LT6CPDIF Non group settings (basic) Name Values (Range) Unit Step Default Description GlobalBaseSel 1 - 12 - 1 1 Selection of one of the Global Base Value groups NoOfUsedCTs 2 3 4 5 6 - - 2 Total number of 3-Ph CT sets connected to diff protection ZerSeqCurSubtr Off On - - Off Off/On for elimination of zero seq. from diff. and bias curr TraAOnInpCh No Transf A 1 2 3 4 5 6 - - No Transf A Power transformer A applied on input channel X RatVoltW1TraA 1.0 - 9999.9 kV 0.1 130.0 Transformer A rated voltage (kV) on winding 1 (HV winding) RatVoltW2TraA 1.0 - 9999.9 kV 0.1 130.0 Transformer A rated voltage (kV) on winding 2 (LV winding) ClockNumTransA 0 [0 deg] 1 [30 deg lag] 2 [60 deg lag] 3 [90 deg lag] 4 [120 deg lag] 5 [150 deg lag] 6 [180 deg lag] 7 [210 deg lag] 8 [240 deg lag] 9 [270 deg lag] 10 [300 deg lag] 11 [330 deg lag] - - 0 [0 deg] Transf. A phase shift in multiples of 30 deg, 5 for 150 deg TraBOnInpCh No Transf B 1 2 3 4 5 6 - - No Transf B Power transformer B applied on input channel X RatVoltW1TraB 1.0 - 9999.9 kV 0.1 130.0 Transformer B rated voltage (kV) on winding 1 (HV winding) RatVoltW2TraB 1.0 - 9999.9 kV 0.1 130.0 Transformer B rated voltage (kV) on winding 2 (LV winding) ClockNumTransB 0 [0 deg] 1 [30 deg lag] 2 [60 deg lag] 3 [90 deg lag] 4 [120 deg lag] 5 [150 deg lag] 6 [180 deg lag] 7 [210 deg lag] 8 [240 deg lag] 9 [270 deg lag] 10 [300 deg lag] 11 [330 deg lag] - - 0 [0 deg] Transf. B phase shift in multiples of 30 deg, 2 for 60 deg Line differential protection RED670 Technical manual 207 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P PID-3560-SETTINGS v6 Table 127: LDLPSCH Non group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Off / On TestModeSet Off On - - Off Test mode On/Off ReleaseLocal Block all Release local - - Block all Release of local terminal for trip under test mode 7.4.6 Monitored data PID-6750-MONITOREDDATA v1 Table 128: L3CPDIF Monitored data Name Type Values (Range) Unit Description IDL1MAG REAL - A Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL - A Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL - A Magnitude of fund. freq. differential current, phase L3 IBIAS REAL - A Magnitude of the bias current, common for L1, L2, L3 IDNSMAG REAL - A Magnitude of the negative sequence differential current NSANGLE REAL - deg Angle between local and remote neg. seq. currents ICHARGE REAL - A Amount of compensated charging current PID-6748-MONITOREDDATA v1 Table 129: L6CPDIF Monitored data Name Type Values (Range) Unit Description IDL1MAG REAL - A Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL - A Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL - A Magnitude of fund. freq. differential current, phase L3 IBIAS REAL - A Magnitude of the bias current, common for L1, L2, L3 IDNSMAG REAL - A Magnitude of the negative sequence differential current NSANGLE REAL - deg Angle between local and remote neg. seq. currents ICHARGE REAL - A Amount of compensated charging current 208 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection PID-3701-MONITOREDDATA v3 Table 130: LT3CPDIF Monitored data Name Type Values (Range) Unit Description OPENCTIN INTEGER - - Open CT on Input : 1 for input 1, 2 for input 2 OPENCTPH INTEGER - - Open CT in Phase : 1 for L1, 2 for L2, 3 for L3 IDL1MAG REAL - A Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL - A Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL - A Magnitude of fund. freq. differential current, phase L3 IBIAS REAL - A Magnitude of the bias current, common for L1, L2, L3 IDNSMAG REAL - A Magnitude of the negative sequence differential current NSANGLE REAL - deg Angle between local and remote neg. seq. currents ICHARGE REAL - A Amount of compensated charging current PID-3699-MONITOREDDATA v3 Table 131: LT6CPDIF Monitored data Name Type Values (Range) Unit Description OPENCTIN INTEGER - - Open CT on Input : 1 for input 1, 2 for input 2 OPENCTPH INTEGER - - Open CT in Phase : 1 for L1, 2 for L2, 3 for L3 IDL1MAG REAL - A Magnitude of fund. freq. differential current, phase L1 IDL2MAG REAL - A Magnitude of fund. freq. differential current, phase L2 IDL3MAG REAL - A Magnitude of fund. freq. differential current, phase L3 IBIAS REAL - A Magnitude of the bias current, common for L1, L2, L3 IDNSMAG REAL - A Magnitude of the negative sequence differential current NSANGLE REAL - deg Angle between local and remote neg. seq. currents ICHARGE REAL - A Amount of compensated charging current 7.4.7 Operation principle 7.4.7.1 Algorithm and logic M13652-3 v7 The Line differential protection function evaluates measured current values from local and remote line ends in order to distinguish between internal or external faults or undisturbed conditions. The local currents are fed to the IED via the analog input modules and then they pass the analog-todigital converter, as shown in Figure 77. Line differential protection RED670 Technical manual 209 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Remote end Local end Remote end IED LDCM Local end IED Analog Input Module Current samples from local end A/D Converter Current samples from remote end LDCM Pre-processing Block CH1IL2RE CH1IL2IM Currents from all ends as phasors Calculation of fundamental frequency differential currents (3x) & bias current Magnitudes of differential currents Bias current Trip by unrestrained differential protection Differential and bias currents applied to operate / bias -, and unrestrained characteristics ³1 Start L1 Start L2 St L2 low sens St L3 low sens CH1IL2SM CH1IL3SM CH2IL1SM Curr. samples from all ends Calculation of instantaneous differential currents (3x) 2nd h. block [samples] Instantaneous differential currents (samples) Harmonic analysis nd th ( 2 and 5 ) Output logic: Start L3 St L1 low sens CH1IL1SM 5th h. block - 2nd - 5th - CH1INSRE CH1INSIM Neg. seq. currents from all ends as phasors Calculation of negative-sequence differential current (1x) Two to six contributions to neg. seq. differential current as phasors High sensitive internal/external fault discriminator Cross block logic - TRL1 TRL2 TRL3 STARTRES STARTUNR STARTENH START STL1 STL2 STL3 - Decreased sensitivity for external faults Internal fault External fault harmonic block harmonic block - Enhanced trip for internal faults - CH1INSRE CH1INSIM TRIP Conditional trip for simultaneous external and internal faults Conditional extra time delay for trip signals BLK2H BLK2HL1 BLK2HL2 BLK2HL3 Information [magnitude] CH1IL1RE CH1IL1IM Trip commands Line Diffferential Function BLK5H BLK5HL1 BLK5HL2 BLK5HL3 INTFAULT EXTFAULT IEC05000294-4-en.vsd IEC05000294 V3 EN-US Figure 77: A simplified block diagram of the power line differential protection The IED receives the remote currents as samples via a communication link. When entering the IED, they are processed in the Line Differential Communication Module (LDCM) where they are timecoordinated with the local current samples, and interpolated in order to be comparable with the local samples. In the preprocessing block, the real and imaginary parts of the fundamental frequency phase currents and negative sequence currents are derived by means of fundamental frequency numerical Fourier filters. Together with the current samples, which are required to internally estimate the 2nd and the 5th 210 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection harmonic contents in the instantaneous differential currents, they are then forwarded to the differential function block where three kinds of analyses are carried out. The first analysis is the classical differential and bias current evaluation with the characteristic as seen in Figure 78. Line differential protection is phase-segregated where the differential current is the vectorial sum of all measured currents taken separately for each phase. The bias current, on the other hand, is considered the greatest phase current in any line end and it is common for all the tree phases. The two slopes (SlopeSection1, SlopeSection2) and breakpoints (EndSection1, EndSection2) can be set in PCM600 or via the local human-machine interface (LHMI). Current values found to be above the characteristic formed by IdMin and the dual slope will give a start in that phase. The level IdMinHigh is a setting value that is used to temporarily decrease the sensitivity in situations when the protected line circuit is just energized, that is, connected to the power system at one end. There is also an unrestrained high differential current setting that can be used for fast tripping of internal faults with very high currents. This unrestrained protection is phase-segregated, that is, it is known which phase(s) require a trip command. Line differential protection RED670 Technical manual 211 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Operate current [ in pu of IBase] Operate 5 unconditionally UnrestrainedLimit 4 Operate 3 IdMinHigh C conditionally A B 2 Section 1 Section 2 Section 3 SlopeSection3 1 IdMin SlopeSection2 Restrain 0 0 1 2 3 EndSection1 EndSection2 4 5 Restrain current [ in pu of IBase] en05000300.vsd IEC05000300 V1 EN-US Figure 78: Description of the restrained and the unrestrained operate characteristics where: slope = D Ioperate × 100% D Irestrain EQUATION1246 V1 EN-US and where the restrained characteristic is defined by the settings: 1. IdMin 2. EndSection1 3. EndSection2 4. SlopeSection2 5. SlopeSection3 The second analysis is the 2nd and 5th harmonic analysis of the three instantaneous differential currents. Occurrence of these harmonics over a level that is set separately for each one blocks tripping action from the biased slope evaluation. Harmonics blocking based on 2nd and 5th harmonics is used only used if one of the following conditions are fulfilled: • • • When a power transformer is included in the protected zone. When the bias current is less than 125 % Ibase. When an external fault has been detected by the negative sequence internal/external fault discriminator and 200 ms after that. The third analysis is the negative sequence current analysis. Effectively this is a fault discriminator that distinguishes between internal and external faults. The directional test is made so that the end with the highest negative sequence current is found. Then, the sum of the negative sequence currents at all other circuit ends is calculated. Finally, the relative phase angle between these two 212 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection negative sequence currents is determined. The characteristic for this fault discriminator is shown in Figure 79, where the directional characteristic is defined by the two setting parameters IminNegSeq and NegSeqRoa. 90 deg 120 deg If one or the other of currents is too low, then no measurement is done, and 120 degrees is mapped Internal/external fault boundary NegSeqROA (Relay Operate Angle) 180 deg 0 deg IMinNegSeq Internal fault region External fault region 270 deg en05000188-3-en.vsd IEC05000188 V3 EN-US Figure 79: Operate characteristic of the internal/external fault discriminator The reference direction (that is, the positive direction) of currents in a power line is considered to be towards the line. Thus, when both negative sequence currents to be compared have this direction, the phase difference between them is ideally zero. In reality, the angle will usually be greater than zero, and this because of the possible different negative sequence impedance angles on both sides as seen from the fault location. An internal fault can be suspected. In the opposite case, when one negative sequence current is entering and the other is leaving the protected object, the phase difference will ideally be 180 degrees. An external fault can be suspected. If either the local or the sum of the remote negative sequence currents or both is below the set level, the fault discriminator does not make any fault classification and the value 120 degrees is set. This value is an indication that negative sequence directional comparison has not been possible. In this case, neither internal nor external fault is signalized. When an external fault is detected, the 2nd and 5th harmonic analysis is activated for 200 ms. This gives better stability against unwanted trips. Under an external fault condition, the cross block logic algorithm is active as well. When a fault is classified as internal by the negative sequence fault discriminator, a trip command is issued under the condition that at least one start signal has been issued, while all eventual block signals (issued by the harmonic analysis of the instantaneous differential currents) are ignored. For all differential functions it is the common trip that shall be used to initiate a trip of a breaker. The separate trip signals from the different parts lacks the safety against maloperation. This does in some cases result in a 6 ms time difference between, for example restrained trip is issued and common trip is issued. The separate trip signals shall only be used for information purpose of which part that has caused the trip. Line differential protection RED670 Technical manual 213 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P With reference to Figure 77, the outputs from the three analysis blocks are fed to the output logic. Figure 80 shows a simplified block diagram of this output logic where only trip commands and no alarm signals are shown for simplicity. Trip unrestrained L1 Trip unrestrained L2 OR TRIP Trip unrestrained L3 Start L1 AND AND OR Start L2 TRL1 OR OR Start L3 TRL2 OR AND AND OR OR AND OR St L1 IdMinHigh TRL3 OR AND OR St L2 IdMinHigh St L3 IdMinHigh Internal fault AND NegSeqDiffEn AND External fault tIdMinHigh t tIdMinHigh t Line energizing Diff curr L1 2nd harm Diff curr L1 5th harm Diff curr L2 2nd harm Diff curr L2 5th harm OR OR Diff curr L3 5th harm AND OR AND OR AND nd Diff curr L3 2 harm OR OR OR OR AND CrossBlockEn IEC05000295-4-en.vsd IEC05000295 V4 EN-US Figure 80: Simplified block diagram Remembering that current values plotted above the characteristic formed by IdMin and the dual slope in Figure 79 are said to give a start, the output logic can be summarized as follows: • A start in one phase, gives a trip under the condition that the content of the 2nd and the 5th harmonic is below the set level for these harmonics in the phase with start, if CrossBlockEn = OFF. If CrossBlockEn = ON, then all phases with their start signals set, must be free of their respective harmonic block signals; otherwise no trip command is issued. Otherwise it is blocked as long as the harmonic is above the set level. However, when a line is energized the current setting value IdMinHigh is used. Effectively this means that the line A-B-C in Figure 78 forms the characteristic. The harmonic block scheme is generally not applied if there are no in-line or shunt power transformers within the protection zone. In other words, if there are no in-line or tap 214 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P • • • Section 7 Differential protection (shunt) power transformers within the protection zone, then no harmonics can prevent a trip command. This makes the response of the differential protection faster in approximately 90% of all cases. Current values above the unrestrained limit, gives a trip irrespective of any presence of harmonics. Classification of a fault as internal by the negative sequence currents based fault discriminator, gives a trip under the condition that at least one start signal has been issued, that is, set to 1 (TRUE). The negative sequence current based fault discriminator itself is not phase-sensitive, and the start signals are required to determine which phases were affected by the fault. Any harmonic blocking is then ignored. The harmonic block scheme is not applied if there are no inline or tap (shunt) power transformers within the protection zone. In other words, if there are no in-line or tap power transformers within the protection zone, then harmonics cannot prevent a trip command. This makes the response of the protection faster in the majority of cases. If there is no power transformer within the protected circuit, then the 2nd and 5th harmonic analysis is only activated temporarily under external fault conditions, or when the bias current is lower than 1. 25 ⅹ IBase. Classification of a fault as external by the negative sequence fault discriminator will cause the harmonic logic scheme to be applied under the duration of the external fault signal, at least for 200 ms. Even the cross block logic scheme is then active. The compensation of charging currents can be selected active or inactive by setting ChargCurEnable Yes or No. The compensation works so that the fundamental frequency differential current that is measured under steady state undisturbed conditions, is identified and then subtracted making the resulting differential current zero (or close to zero). This action is made separately for each phase. The magnitude of the subtracted pre-fault currents in Amperes can be read at any time as the service value ICHARGE. Values of the pre-fault differential currents are not updated under disturbance conditions. The updating process is resumed 50 ms after normal conditions have been restored. Normal conditions are only assumed if there are no start signals, neither internal nor external fault is declared, the power system is symmetrical. The change in the charging current that the fault causes by decreasing the system voltage is not considered in the algorithm. For more information, see the application manual. Note that the subtraction of the charging current is limited to a value specified by IdMin. Observe as well that IdMin must always be set at least 25 % - 50 % above the value of charging currents. Note that all small pre-fault differential currents are subtracted, regardless of their origin. Besides the true charging currents, the following currents are eliminated: • • • 7.4.7.2 Small false differential currents due to small errors (inequalities) of current transformers. Small false differential currents because of off-nominal load tap changer positions when a power transformer is included in the protected zone. Load currents of tap power transformers included in the protected zone. Time synchronization SEMOD52396-4 v5 In a numerical line differential protection, current samples from protections located geographically apart from each other, must be time coordinated so that the currents from the different line ends can be compared without introducing irrelevant errors. Accuracy requirements on this time coordination are extremely high. As an example, an inaccuracy of 0.1 ms in a 50 Hz system gives a maximum amplitude error approximately around 3% whilst an inaccuracy of 1 ms gives a maximum amplitude error of approximately 31%. The corresponding figures for a 60 Hz system are 4% and 38% respectively. In Line differential protection, the time coordination is made with the so-called echo method. The echo method can be complemented with GPS synchronization as an option. Line differential protection RED670 Technical manual 215 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Each IED has an accurate local clock with a very small time drift. This clock makes time tagging of telegrams, and the echo method is then used to find out the time difference between the clocks in two ends of a power line. Referring to Figure 81, it works such that the transmission time to send a message from station B to station A (T1 → T2) and receive a message from A to B (T3 → T4) is measured. The time instances T2 and T3 are taken with the local clock reference of station A, and the time instances T1 and T4 are taken with the local clock reference of station B. T2 A B T3 T1 T4 en05000293.vsd IEC05000293 V1 EN-US Figure 81: Measuring time differences Calculation of the delay time one-way Td and the time difference Δt between the clocks in A and B is then possible to do with equation 17 and equation 18, which are only valid under the condition that the send and receive times are equal. Td = (T2 - T1 ) + (T4 - T3 ) 2 (Equation 17) EQUATION1358 V1 EN-US Dt = (T1 + T4 ) - (T2 + T3 ) 2 (Equation 18) EQUATION1359 V1 EN-US Δt is calculated every time a telegram is received, and the time difference is then used to adjust and interpolate the current measurements from the remote end before the current differential algorithm is executed. The echo method can be used in telecommunications transmission networks with varying signal propagation delay as long as there is delay symmetry, that is, the send and receive delays are equal. The delay variation can depend on the signal going different routes in the network from time to other. When the delay symmetry is lost, the expression for Δt given above is no longer valid. Under these conditions GPS synchronization of the local IED clocks must be used. Including the optional GPS, means that there will be one GPS receiver module in each IED, synchronizing its local IED clock. As GPS synchronization is very accurate, in the order of 1 μs, all IEDs in the same line differential scheme will have the same clock reference. It is then possible to detect asymmetric transmission time delay and compensate for it. When the IED is equipped with GPS, this hardware is integrated in the IED. Besides the GPS receiver itself, it also consists of filters and regulators for post processing of the GPS time synch pulse, which is necessary to achieve a reliable GPS synchronization. Especially short interruptions and spurious out of synch GPS signals are handled securely in this way. When GPS synchronization is used, an interruption in the GPS signal leads to freewheeling during 8 seconds that is, during this time the synchronization benefits from the stability in the local clocks. If the interruption persists more than 8 seconds, either fall back to the echo synchronization method or 216 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection blocking of Line differential protection function is made, as selected through setting parameter GPSSyncErr. 7.4.7.3 Analog signal communication for line differential protection SEMOD52424-1 v1 Communication principle SEMOD52415-4 v3 For a two-terminal line, the current from the local CT needs to be communicated over a 64 kbit/s channel to the remote line end, and the remote end current communicated back on the same channel. If there is, for example, a three terminal line another 64 kbit/s channel will be needed to exchange the same local current with the third line end current. In one-and-a-half breaker arrangements, there are two local currents meaning two 64 kbit/s channels to each remote substation. Alternatively, it is possible to add together the two local currents before sending them and in that way reduce the number of communication channels needed. This is achieved by selecting proper setting for parameter TransmCurr (CT-SUM, CT-DIFF1 or CT-DIFF2). However, information about bias currents is reduced if the alternative option is followed. For further information and discussions on this matter, refer to the Application manual. The communication can be arranged as a master-master system or a master-slave system alternatively. Figure 82 shows a master-master system for a five-terminal line. Here current samples are exchanged between all IEDs, and an evaluation is made in each IED. This means that a 64 kbit/s communication channel is needed between every IED included in the same line differential protection zone. Protected zone IED IED Comm. Channels IED IED IED IEC05000292_2_en.vsd IEC05000292 V2 EN-US Figure 82: 5–terminal line with master-master system In the master-slave system, current samples are sent from all slave IEDs to one master IED where the evaluation is made and trip signals are sent to the remote ends when needed. In this system, a 64 kbit/s communication channel is only needed between the master, and each one of the slave IEDs, as shown in figure 83. Protected zone IED IED Comm. Channels IED IED IED IEC05000291_2_en.vsd IEC05000291 V2 EN-US Figure 83: 5–terminal line with master-slave system Line differential protection RED670 Technical manual 217 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P The master-slave configuration is achieved by setting parameter Operation in the slaves to Off for Line differential protection function, and setting parameter ChannelMode to On for the LDCMs in the slaves. Test mode SEMOD52415-48 v2 Line differential protection function in one IED can be set in test mode. This can block the trip outputs on that IED, and set the remote IEDs in a remote test mode, so that injected currents can be echoed back phase shifted and with a settable amplitude. The trip outputs in the remote IEDs can also be blocked automatically. For further information, refer to the installation and commissioning manual. Communication of current sampled values SEMOD52415-22 v2 The currents are sampled twenty times per power system cycle in the protection terminals, but the communication exchange is made only once every 5 ms. This means that at in each telegram sent, 5 consecutive current samples in a 50 Hz system and 6 consecutive current samples in a 60 Hz system (three phases each sampling instant) are included. Figure 84 shows the principle. Current sample telegram sent Current sample telegram sent Current sample telegram sent Current sample telegram sent Current sample telegram sent Current sample telegram sent Current sample telegram sent 5 10 15 20 25 30 35 0 Current sample telegram sent Time (ms) en05000290.vsd IEC05000290 V1 EN-US Figure 84: Communication of current sampled values. where: x is the current sampling moment Redundant communication channels SEMOD52415-25 v5 With redundant communication channels, as shown in figure 85, both channels are in operation continuously but with one of them favoured as a primary channel. Telecom. Network LD CM LD CM IEC05000289 V1 EN-US Figure 85: Telecom. Network Primary channel Secondary redundant channel LD CM LD CM en05000289.vsd Direct fiber optical connection between two IEDs with LDOM over longer distances. If communication is lost on the primary channel, switchover to the secondary channel is made after a settable time delay RedChSwTime. Return of the primary channel will cause a switchback after another settable time delay RedChRturnTime. 218 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection For a three-, four- or five-terminals line in a master-master configuration, a loss of one communication channel will not cause the line differential protection to be unserviceable. Instead it will automatically revert to a partial master-slave mode with the two IEDs that have an unserviceable communication link between them, will serve as slaves. For more details about the remote communication see section remote communication and the application manual. 7.4.7.4 Open CT detection feature GUID-5B7ACC4D-4EC9-40F1-B18D-561F13945FE3 v1 Line differential protection has a built-in, advanced open CT detection feature. A sudden inadvertently opened CT circuit may cause an unexpected and unwanted operation of the Line differential protection under normal load conditions. Damage of secondary equipment may occur due to high voltage from open CT circuit outputs. It is always an advantage, from the point of view of security and reliability, to have the open CT detection function to block the line differential protection function in case of an open CT condition, and produce an alarm signal to the operational personnel to quickly correct the open CT condition. The built-in open CT feature can be enabled or disabled by the setting parameter OpenCTEnable (Off/On). When enabled, this feature tries to prevent mal-operation when a loaded main CT connected to line differential protection is by mistake open circuited on the secondary side. Note that this feature can only detect interruption of one CT phase current at a time. If two or even all threephase currents of one set of CTs are accidentally interrupted at precisely the same time, this feature cannot operate. Line differential protection generates a trip signal if the false differential current is sufficiently high. An open CT circuit is typically detected in 12–14 ms, and if the load in the protected circuit is relatively high, about the nominal load, the unwanted trip cannot always be prevented. Still, the information about what was the cause of the open CT secondary circuit, is vital. The principle applied to detect an open CT is a simple pattern recognition method, similar to the waveform check used by the Power transformer differential protection in order to detect the magnetizing inrush condition. The open CT detection principle is based on the fact that for an open CT, the current in the phase with the open CT suddenly drops to zero (that is, as seen by the protection), while the currents of the other two phases continue as before. The open CT function is supposed to detect an open CT under normal conditions, that is, with the protected multi-terminal circuit under normal load (10...120% of the rated load). If the load currents are very low or zero, the open CT condition cannot be detected. In addition to load condition requirement, Open CT function also checks the differential current on faulty phase. If the differential current is lower than 10% of IBase, the open CT condition cannot be detected. Therefore, the Open CT algorithm only detects an open CT if the load on the power transformer protected object is 10...120% of rated load and the differential current is higher than 10% of IBase on that phase. The search for an open CT starts 60 seconds (50 seconds in 60 Hz systems) after the bias current has entered the 10...120% range. The Open CT detection feature can also be explicitly deactivated by setting: OpenCTEnable = 0 ( Off). The open CT function can be selected to either block the differential function or issue the alarm signal via the setting OCTBlockEn. When the setting OCTBlockEn is set to ON and an open CT is detected, the output OPENCT is set to 1 and all the differential functions are blocked, except the unrestrained (instantaneous) differential. An alarm signal is also produced after a settable delay (tOCTAlarmDelay) to report to operational personnel for quick remedy actions once the open CT is detected. When the open CT condition is removed (that is, the previously open CT is reconnected), the functions remain blocked for a specified interval of time, which is also defined by a setting (tOCTResetDelay). This is to prevent an eventual mal-operation after the reconnection of the previously open CT secondary circuit. Otherwise when the setting OCTBlockEn is set to OFF, only an alarm signal is issued once an open CT is detected. Line differential protection RED670 Technical manual 219 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P The open CT algorithm provides detailed information about the location of the defective CT secondary circuit. The algorithm clearly indicates the IED side, CT input and phase in which an open CT condition has been detected. These indications are provided via the following outputs from the Line differential protection function: 1. 2. 3. 4. Output OPENCT provides instant information to indicate that an open CT circuit has been detected. Output OPENCTAL provides a time-delayed alarm that the open CT circuit has been detected. Time delay is defined by the parameter tOCTAlarmDelay. Integer output OPENCTIN provides information on the local HMI regarding which open CT circuit has been detected (1=CT input No 1; 2=CT input No 2). Integer output OPENCTPH provides information on the local HMI regarding in which phase an open CT circuit has been detected (1=Phase L1; 2= Phase L2; 3= Phase L3). Once the open CT condition is declared, the algorithm stops to search for further open CT circuits. It waits until the first open CT circuit has been corrected. Note that once the open CT condition has been detected, it can be reset automatically within the differential function. It is not possible to externally reset an open CT condition. To reset the open CT circuit alarm automatically, the following conditions must be fulfilled: • • • Bias current is for at least one minute smaller than 120% The open CT condition in the defective CT circuit has been corrected (for example, current asymmetry disappears) The above two conditions are fulfilled for a longer time than defined by the setting parameter tOCTResetDelay If an open CT has been detected in a separate group of three CTs, the algorithm is reset either when the missing current returns to the normal value, or when all three currents become zero. After the reset, the open CT detection algorithm starts again to search for open CT circuits within the protected zone. 7.4.7.5 Binary signal transfer SEMOD52489-4 v4 There is space for eight binary signals integrated in the telegram of the line differential analog communication. 7.4.7.6 Line differential protection logic LDLPSCH GUID-687F26CE-20EF-424A-A355-6308CED80E6C v7 Line differential protection logic (LDLPSCH) is a support function to the Line differential protection functions. The function gathers and coordinates local IED signals and the signals from remote IEDs between the Line differential protection functions and the LDCM communication module. The function acts as the interface to and from Line differential protection. The task of LDLPSCH is to transfer the signals via LDCM between IEDs in the protection zone. Once LDLPSCH receives a block or trip signal from one IED, this block or trip signal is transferred to other IEDs by LDLPSCH function. When the line differential protection function in local IED is set to test mode, LDLPSCH sets the remote IEDs in a remote test mode and block the trip outputs in the remote IEDs. Figure 86 shows a simplified block diagram which illustrates block signal handling by LDLPSCH. 220 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection TestModeRemoteTerm1 TestModeRemoteTerm2 TestModeRemoteTerm3 OR 50 ms t TestModeRemoteTerm4 OR BlockRemote Ter m1 BlockRemote Ter m2 BlockRemote Ter m3 BlockRemote Ter m4 OR LocalDiffB lock OR LOCAL DIFFB LOCKED 50 ms OPE N CT BLK t CTFailOCTToRemote (signal to L DCM) TestModeInpu t AND TestModeToRemote 50 ms t AND TestModeS et AND OR Block Remote Tri p ReleaseLo cal OR Block Remote Tri p TERMINALOUTOFSERVICE OR BLO CK 100 ms t OR BlockToRe mo te IEC13000259-4-en.vsd IEC13000259 V4 EN-US Figure 86: Block signal logic of LDLPSCH When LDLPSCH receives the trip signal from local IED (or remote IED), this trip signal is transferred to remote IEDs (or local IED) in the protection zone. Figure 87 shows a simplified block diagram which illustrates trip signal handling by LDLPSCH. Line differential protection RED670 Technical manual 221 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P TRL OCL1 DiffTripL1 AND TRL1 OR TripL1ToRemote AND TRIP OR TripL1Remote Te rm1 TripL1Remote Te rm2 TripL1Remote Te rm3 OR AND TripL1Remote Te rm4 TRL OCL2 DiffTripL2 AND TRL2 OR AND TripL2ToRemote AND TripL2Remote Te rm1 OR TRL OCAL TripL2Remote Te rm2 TripL2Remote Te rm3 OR TripL2Remote Te rm4 TRL OCL3 DiffTripL3 AND BlockLocalTrip TRL3 OR BlockTripToRemo te TripL3ToRemote AND TripL3Remote Te rm1 TripL3Remote Te rm2 TripL3Remote Te rm3 TripL3Remote Te rm4 OR TRREMOTE OR AND BlockRemote Trip IEC130 00260-3-en.vsd IEC13000260 V3 EN-US Figure 87: Trip signal logic of LDLPSCH Some of the signals in the above block diagrams are used as the internal signals by LDLPSCH. Table Internal signals describes the source or destination of these internal signals. Table 132: Internal signals Internal signals Source of destination Description testModeRemoteTerm1 Signal from LDCM Test mode from remote terminal 1 testModeRemoteTerm2 Signal from LDCM Test mode from remote terminal 2 testModeRemoteTerm3 Signal from LDCM Test mode from remote terminal 3 testModeRemoteTerm4 Signal from LDCM Test mode from remote terminal 4 blockRemoteTerm1 Signal from LDCM Block from remote terminal 1 blockRemoteTerm2 Signal from LDCM Block from remote terminal 2 blockRemoteTerm3 Signal from LDCM Block from remote terminal 3 blockRemoteTerm4 Signal from LDCM Block from remote terminal 4 testModeInput Signal from test mode function Input for forcing the function into test mode Table continues on next page 222 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Internal signals 7.4.8 Source of destination Description diffTripL1 Signal from differential function Trip from local differential function in phase L1 diffTripL2 Signal from differential function Trip from local differential function in phase L2 diffTripL3 Signal from differential function Trip from local differential function in phase L3 tripL1RemoteTerm1 Signal from LDCM Trip from remote terminal 1 in phase L1 tripL1RemoteTerm2 Signal from LDCM Trip from remote terminal 2 in phase L1 tripL1RemoteTerm3 Signal from LDCM Trip from remote terminal 3 in phase L1 tripL1RemoteTerm4 Signal from LDCM Trip from remote terminal 4 in phase L1 tripL2RemoteTerm1 Signal from LDCM Trip from remote terminal 1 in phase L2 tripL2RemoteTerm2 Signal from LDCM Trip from remote terminal 2 in phase L2 tripL2RemoteTerm3 Signal from LDCM Trip from remote terminal 3 in phase L2 tripL2RemoteTerm4 Signal from LDCM Trip from remote terminal 4 in phase L2 tripL3RemoteTerm1 Signal from LDCM Trip from remote terminal 1 in phase L3 tripL3RemoteTerm2 Signal from LDCM Trip from remote terminal 2 in phase L3 tripL3RemoteTerm3 Signal from LDCM Trip from remote terminal 3 in phase L3 tripL3RemoteTerm4 Signal from LDCM Trip from remote terminal 4 in phase L3 tripL1ToRemote Signal to LDCM Trip to remote terminals phase L1 tripL2ToRemote Signal to LDCM Trip to remote terminals phase L2 tripL3ToRemote Signal to LDCM Trip to remote terminals phase L3 localDiffBlock Signal to differential function Block local line differential function operation blockToRemote Signal to LDCM Block to be sent to remote terminals testModeToRemote Signal to LDCM Test mode indication to be sent to remote terminals Technical data IP14336-1 v1 M16023-1 v13 Table 133: L3CPDIF, L6CPDIF, LT3CPDIF , LT6CPDIF single IED without communication technical data Function Range or value Accuracy Minimum operate current (20-200)% of IBase ±1.0% of Ir at I ≤ Ir ±1.0% of I at I > Ir SlopeSection2 (10.0-50.0)% - SlopeSection3 (30.0-100.0)% - EndSection 1 (20–150)% of IBase - Table continues on next page Line differential protection RED670 Technical manual 223 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Function Range or value Accuracy EndSection 2 (100–1000)% of IBase - Unrestrained limit function (100–5000)% of IBase ±1.0% of Ir at I ≤ Ir ±1.0% of I at I > Ir Second harmonic blocking (5.0–100.0)% of fundamental ±1.0% of Ir Note: fundamental magnitude = 100% of Ir Fifth harmonic blocking (5.0–100.0)% of fundamental ±2.0% of Ir Note: fundamental magnitude = 100% of Ir *Inverse characteristics, see table 1292,1294 and table 1296 16 curve types See table 1292,1294 and table 1296 Critical impulse time 2ms typically at 0 to 10 x IdMin - Charging current compensation On/Off - LT3CPDIF and LT6CPDIF (With in-zone transformer enabled and tIdMinHigh set to 0) : *Operate time, restrained function at 0 to 10 x IdMin Min. = 25 ms Max. = 35 ms - *Reset time, restrained function at 10 x IdMinto 0 Min. = 5 ms Max. = 15 ms - *Operate time, unrestrained function at 0 to 10 x IdUnre Min. = 5 ms Max. = 15 ms - *Reset time, unrestrained function at 10 x IdUnreto 0 Min. = 15 ms Max. = 30 ms - **Operate time, unrestrained negative sequence function Min. = 10 ms Max. = 25 ms - **Reset time, unrestrained negative sequence function Min. = 10 ms Max. = 30 ms - L3CPDIF and L6CPDIF (With tIdMinHigh set to 0): *Operate time, restrained function at 0 to 10 x IdMin Min. = 10 ms Max. = 20 ms - *Reset time, restrained function at 10 x IdMinto 0 Min. = 15 ms Max. = 30 ms - *Operate time, unrestrained function at 0 to 10 x IdUnre Min. = 5 ms Max. = 15 ms - *Reset time, unrestrained function at 10 x IdUnreto 0 Min. = 15 ms Max. = 30 ms - **Operate time, unrestrained negative sequence function Min. = 10 ms Max. = 20 ms - **Reset time, unrestrained negative sequence function Min. = 10 ms Max. = 35 ms - The data in the table are valid for a single IED with two local current input groups. *Note: Data obtained with single three-phase input current group. **Note: Data obtained with two three-phase input current groups. The rated symmetrical currents are applied on both sides as pre- and post-fault currents. The fault is performed by increasing one phase current to double on one side and decreasing same phase current to zero on the other side. 224 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Table 134: L3CPDIF, L6CPDIF, LT3CPDIF , LT6CPDIF with 64 Kbit/s communication technical data Function Range or value Accuracy Minimum operate current (20-200)% of IBase ±4.0% of Ir at I ≤ Ir ±4.0% of I at I > Ir SlopeSection2 (10.0-50.0)% - SlopeSection3 (30.0-100.0)% - EndSection 1 (20–150)% of IBase - EndSection 2 (100–1000)% of IBase - Unrestrained limit function (100–5000)% of IBase ±4.0% of Ir at I ≤ Ir ±4.0% of I at I > Ir Second harmonic blocking (5.0–100.0)% of fundamental ±3.0% of Ir Note: fundamental magnitude = 100% of Ir Fifth harmonic blocking (5.0–100.0)% of fundamental ±10.0% of Ir Note: fundamental magnitude = 100% of Ir *Inverse characteristics, see table 1292,1294 and table 1296 16 curve types See table 1292,1294 and table 1296 Critical impulse time 2 ms typically at 0 to 10 x IdMin - Charging current compensation On/Off - LT3CPDIF and LT6CPDIF (With in-zone transformer enabled and tIdMinHigh set to 0) : *Operate time, restrained function at 0 to 10 x IdMin Min. = 30 ms Max. = 50 ms - *Reset time, restrained function at 10 x IdMinto 0 Min. = 10 ms Max. = 25 ms - *Operate time, unrestrained function at 0 to 10 x IdUnre Min. = 10 ms Max. = 25 ms - *Reset time, unrestrained function at 10 x IdUnreto 0 Min. = 20 ms Max. = 40 ms - **Operate time, unrestrained negative sequence function Min. = 15 ms Max. = 35 ms - **Reset time, unrestrained negative sequence function Min. = 20 ms Max. = 35 ms - L3CPDIF and L6CPDIF (With tIdMinHigh set to 0): *Operate time, restrained function at 0 to 10 x IdMin Min. = 10 ms Max. = 35 ms - *Reset time, restrained function at 10 x IdMinto 0 Min. = 20 ms Max. = 45 ms - *Operate time, unrestrained function at 0 to 10 x IdUnre Min. = 10 ms Max. = 25 ms - *Reset time, unrestrained function at 10 x IdUnreto 0 Min. = 20 ms Max. = 50 ms - Table continues on next page Line differential protection RED670 Technical manual 225 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Function Range or value Accuracy **Operate time, unrestrained negative sequence function Min. = 15 ms Max. = 35 ms - **Reset time, unrestrained negative sequence function Min. = 15 ms Max. = 40 ms - The data in the table are valid for a single IED with 64 Kbits/s communication in the loop-back mode. *Note: Data obtained with single three-phase input current group. The operate and reset times for L3CPDIF are valid for the static output from SOM. **Note: Data obtained with two three-phase input current groups. The rated symmetrical currents are applied on both sides as pre- and post-fault currents. The fault is performed by increasing one phase current to double on one side and decreasing same phase current to zero on the other side. Table 135: L3CPDIF, L6CPDIF, LT3CPDIF , LT6CPDIF with 2 Mbits/s communication technical data Function Range or value Accuracy Minimum operate current (20-200)% of IBase ±1.0% of Ir at I ≤ Ir ±1.0% of I at I > Ir SlopeSection2 (10.0-50.0)% - SlopeSection3 (30.0-100.0)% - EndSection 1 (20–150)% of IBase - EndSection 2 (100–1000)% of IBase - Unrestrained limit function (100–5000)% of IBase ±1.0% of Ir at I ≤ Ir ±1.0% of I at I > Ir Second harmonic blocking (5.0–100.0)% of fundamental ±1.0% of Ir Note: fundamental magnitude = 100% of Ir Fifth harmonic blocking (5.0–100.0)% of fundamental ±3.0% of Ir Note: fundamental magnitude = 100% of Ir *Inverse characteristics, see table 1292,1294 and table 1296 16 curve types See table 1292,1294 and table 1296 Critical impulse time 2 ms typically at 0 to 10 x IdMin - Charging current compensation On/Off - LT3CPDIF and LT6CPDIF (With in-zone transformer enabled and tIdMinHigh set to 0) : *Operate time, restrained function at 0 to 10 x IdMin Min. = 25 ms Max. = 40 ms - *Reset time, restrained function at 10 x IdMinto 0 Min. = 5 ms Max. = 20 ms - *Operate time, unrestrained function at 0 to 10 x IdUnre Min. = 5 ms Max. = 20 ms - *Reset time, unrestrained function at 10 x IdUnreto 0 Min. = 15 ms Max. = 35 ms - **Operate time, unrestrained negative sequence function Min. = 10 ms Max. = 25 ms - **Reset time, unrestrained negative sequence function Min. = 10 ms Max. = 30 ms - L3CPDIF and L6CPDIF (With tIdMinHigh set to 0): *Operate time, restrained function at 0 to 10 x IdMin Min. = 10 ms Max. = 20 ms - *Reset time, restrained function at 10 x IdMinto 0 Min. = 15 ms Max. = 30 ms - Table continues on next page 226 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection Function Range or value Accuracy *Operate time, unrestrained function at 0 to 10 x Id Min. = 5 ms Max. = 20 ms - *Reset time, unrestrained function at 10 x IdUnreto 0 Min. = 15 ms Max. = 35 ms - **Operate time, unrestrained negative sequence function Min. = 10 ms Max. = 25 ms - **Reset time, unrestrained negative sequence function Min. = 10 ms Max. = 30 ms - The data in the table are valid for a single IED with 2 Mbits/s communication in loop-back mode. *Note: Data obtained with single three-phase input current group. **Note: Data obtained with two three-phase input current groups. The rated symmetrical currents are applied on both sides as pre- and post-fault currents. The fault is performed by increasing one phase current to double on one side and decreasing same phase current to zero on the other side. 7.5 Additional security logic for differential protection LDRGFC GUID-0E064528-0E70-4FA1-87C7-581DADC1EB55 v2 7.5.1 Identification GUID-3081E62B-3E96-4615-97B8-2CCA92752658 v2 Function description Additional security logic for differential protection 7.5.2 IEC 61850 identification LDRGFC IEC 60617 identification - Functionality ANSI/IEEE C37.2 device number 11 GUID-8F918A08-E50E-4E7B-BDCA-FF0B5534B289 v3 Additional security logic for differential protection (LDRGFC) can help the security of the protection especially when the communication system is in abnormal status or for example when there is unspecified asymmetry in the communication link. It helps to reduce the probability for mal-operation of the protection. LDRGFC is more sensitive than the main protection logic to always release operation for all faults detected by the differential function. LDRGFC consists of four sub functions: • • • • Phase-to-phase current variation Zero sequence current criterion Low voltage criterion Low current criterion Phase-to-phase current variation takes the current samples as input and it calculates the variation using the sampling value based algorithm. Phase-to-phase current variation function is a major one to fulfill the objectives of the startup element. Zero sequence criterion takes the zero sequence current as input. It increases the security of protection during the high impedance fault conditions. Low voltage criterion takes the phase voltages and phase-to-phase voltages as inputs. It increases the security of protection when the three-phase fault occurred on the weak end side. Low current criterion takes the phase currents as inputs and it increases the dependability during the switch onto fault case of unloaded line. The differential function can be allowed to trip as no load is fed through the line and protection is not working correctly. Features: Line differential protection RED670 Technical manual 227 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P • • • Startup element is sensitive enough to detect the abnormal status of the protected system Startup element does not influence the operation speed of main protection Startup element would detect the evolving faults, high impedance faults and three phase fault on weak side It is possible to block the each sub function of startup element Startup signal has a settable pulse time • • 7.5.3 Function block GUID-A205A0BB-C09E-42E2-B664-1863E1FF2A0A v2 LDRGFC I3P* U3P* BLOCK BLKCV BLKUC BLK3I0 BLKUV REMSTUP START STCVL1L2 STCVL2L3 STCVL3L1 STUC ST3I0 STUV IEC14000015-1-en.vsd IEC14000015 V1 EN-US Figure 88: 7.5.4 LDRGFC function block Signals PID-3558-INPUTSIGNALS v9 Table 136: LDRGFC Input signals Name Type Default Description I3P GROUP SIGNAL - Group signal for current input U3P GROUP SIGNAL - Group signal for voltage input BLOCK BOOLEAN 0 Block of function BLKCV BOOLEAN 0 Block of ph to ph current variation criterion BLKUC BOOLEAN 0 Block of the low current criterion BLK3I0 BOOLEAN 0 Block of zero sequence current criterion BLKUV BOOLEAN 0 Block of under voltage criterion REMSTUP BOOLEAN 0 Startup signal of remote end PID-3558-OUTPUTSIGNALS v9 Table 137: LDRGFC Output signals Name Type Description START BOOLEAN General startup signal STCVL1L2 BOOLEAN Start signal for current variation criterion for phase L1L2 STCVL2L3 BOOLEAN Start signal for current variation criterion for phase L2L3 STCVL3L1 BOOLEAN Start signal for current variation criterion for phase L3L1 STUC BOOLEAN Start signal for low current criterion ST3I0 BOOLEAN Start signal for zero sequence current criterion STUV BOOLEAN Start signal for under voltage criterion 228 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P 7.5.5 Section 7 Differential protection Settings PID-3558-SETTINGS v9 Table 138: LDRGFC Group settings (basic) Name Values (Range) Unit Step Default Description Operation Off On - - Off Operation Off/On tStUpReset 0.000 - 60.000 s 0.001 7.000 Reset delay for startup signal OperationCV Off On - - On Operation current variation Off/On ICV> 1 - 100 %IB 1 20 Fixed threshold for ph to ph current variation criterion OperationUC Off On - - On Operation low current criterion Off/On IUC< 1 - 100 %IB 1 5 Start value for low current operation in % of IBase Operation3I0 Off On - - On Operation zero sequence current criterion Off/On I3I0> 1 - 100 %IB 1 10 Start value for zero sequence current criterion in % of IBase OperationUV Off On - - On Operation under voltage criterion Off/On UPhN< 1 - 100 %UB 1 60 Start value for phase voltage criterion in % of UBase UPhPh< 1 - 100 %UB 1 60 Start value for ph to ph voltage criterion in % of UBase Table 139: LDRGFC Group settings (advanced) Name Values (Range) tCV 0.000 - 0.005 s 0.001 0.002 Time delay for phase to phase current variation tUC 0.000 - 60.000 s 0.001 0.200 Time delay for low current criterion t3I0 0.000 - 60.000 s 0.001 0.000 Time delay for zero sequence current criterion tUV 0.000 - 60.000 s 0.001 0.000 Time delay for low voltage criterion Unit Step Default Description Table 140: LDRGFC Non group settings (basic) Name Values (Range) GlobalBaseSel 7.5.6 Unit 1 - 12 Step - 1 Default 1 Description Selection of one of the Global Base Value groups Monitored data PID-3558-MONITOREDDATA v8 Table 141: LDRGFC Monitored data Name Type Values (Range) Unit Description IL1 REAL - A Current RMS value for phase L1 IL2 REAL - A Current RMS value for phase L2 IL3 REAL - A Current RMS value for phase L3 3I0 REAL - A Zero sequence current value Table continues on next page Line differential protection RED670 Technical manual 229 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P Name 7.5.7 Type Values (Range) Unit Description UL1 REAL - kV Voltage RMS value for phase L1 UL2 REAL - kV Voltage RMS value for phase L2 UL3 REAL - kV Voltage RMS value for phase L3 UL12 REAL - kV Voltage RMS value for ph to ph L1L2 UL23 REAL - kV Voltage RMS value for ph to ph L2L3 UL31 REAL - kV Voltage RMS value for ph to ph L3L1 Operation principle GUID-60091A2A-AC10-4E04-B4B8-C190E3E07D3E v6 The additional security logic for differential protection (LDRGFC) takes the current samples, current RMS values, phase voltage values, phase-to-phase voltage values, zero sequence current and remote side startup signals as inputs. Startup signal becomes activated when any one of the current variation startup signal, zero sequence current startup signal, voltage startup signal, and current startup signal is activated. Phase-to-phase current variation takes current samples and generates the startup signal by comparing with the start value. If the zero sequence current value is greater than the start value of zero sequence current then the zero sequence current startup signal will be activated. Voltage startup signal becomes activated when the any of phase voltage and line voltage is less than the voltage start value and the remote startup signal has to be activated. Current startup signal becomes activated when the current value in all phases is less than current start value. Phase-to-phase current variation The phase-to-phase current variation is the main startup element. It covers most of the abnormal conditions of the system. The phase-to-phase current variation fails in high impedance faults, threephase faults on weak side and switch onto fault on unloaded line because of low sensitivity in these cases. Phase-to-phase current variation takes the current samples as input and the signal is evaluated using the sampling value based algorithm. The phase-to-phase current variation criterion is shown below: DiFF > 1.8DIT + DI ZD EQUATION2255 V1 EN-US Where: ΔiФФ sampling value of phase-to-phase current variation ΔIZD setting of fixed threshold, which corresponds to setting ICV>. The default value for the setting is 0.2·IBase, where IBase is the base current. ΔIT float threshold It is the full-circle integral of the phase-to-phase current variation 230 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P DI T = Section 7 Differential protection 1 2T -1 å | DiFF (t - n) | T n =T EQUATION2256 V1 EN-US Where: T count of sample values in one cycle ΔiФФ is calculated using the below formula: Di (k ) = [i ( k ) - i (k - N )] - [i (k - N ) - i (k - 2 N )] = i ( k ) - 2i ( k - N ) + i (k - 2 N ) EQUATION2257 V1 EN-US N is the number of samples in one cycle. tCV STCVL1L2 t Current variation subfunction I3P i cont tCV STCVL2L3 t tCV STCVL3L1 t OR STCV cont IEC10000295-1-en.vsd IEC10000295 V1 EN-US Figure 89: Current variation logic diagram tCV is the time setting for the change of current criterion. Phase current samples are included in input signal I3P. Zero sequence current criterion Zero sequence criterion is mainly for detection of remote IED high resistance faults or some gradual faults. The criterion takes the zero sequence current as input. Zero sequence current is compared with I3I0> for the t3I0 time to generate the zero sequence current startup signal. Line differential protection RED670 Technical manual 231 © 2017 - 2021 Hitachi Power Grids. All rights reserved Section 7 Differential protection 1MRK 505 377-UEN Rev. P I3P a b I3IO> BLK3I0 BLOCK a>b t3I0 t AND ST3I0 OR IEC09000778-2-en.vsd IEC09000778 V2 EN-US Figure 90: Zero sequence current criterion logic diagram I3I0> is the setting of the maximum possible non-faulted zero sequence current for the protected line. The default value for this setting is 0.1 · IBase where IBase is the rated current of the CT. t3I0 is the time setting for the zero sequence current criterion. The zero sequence current criterion can be blocked by activating the BLK3I0 input signal. Low voltage criterion Low voltage criterion is mainly for detection of the three phase faults occurring on weak side with prefault no load condition. The low voltage criterion takes the voltage phase values, voltage phase-tophase values and remote startup signals as inputs. The logic for low voltage criterion is shown below: U3P (UPhN) a UPhN< U3P (UPhPh) b a UPhPh< b a<b OR a<b tUV REMSTUP (Recived) AND t STUV BLKUV OR BLOCK IEC09000779-2-en.vsd IEC09000779 V2 EN-US Figure 91: Low voltage criterion logic diagram Voltage phase value is compared with the start value of voltage phase and voltage phase-to-phase value is compared with the start value of voltage phase-to-phase. If any of the phase voltage or phase-to-phase voltages is below the set voltage levels for some time duration (tUV) then the low voltage START signal becomes activated after receiving the remote startup signal. Low voltage criterion can be blocked by activating BLKUV input signal. If there are more than one remote IED, all the startup signals of the remote ends are logically OR to obtain the REMSTUP signal from the remote side as input. Low current criterion The current in each phase is compared to the set current level. If all currents are below setting IUC<, the STUC output is activated after the set delay tUC. 232 Line differential protection RED670 Technical manual © 2017 - 2021 Hitachi Power Grids. All rights reserved 1MRK 505 377-UEN Rev. P Section 7 Differential protection I3P a IUC< b BLKUC BLOCK a<b tUC AND t STUC OR IEC09000780-2-en.vsd IEC09000780 V2 EN-US Figure 92: Low current criterion logic diagram Security logic for differential protection The configuration for the additional security logic for differential protection is shown in Figure 93. The function will release tripping of the line differential protection up to the end of timer tStUpReset. Phase-phase current variation STCV Zero sequence current criterion ST3IO i I0 > tStUpReset t Low voltage criterion STUV START OR ULOW < Local side start-up Send signal to remote side AND REMSTUP Low current criterion STUC I0 < IEC10000296-3-en.vsd IEC10000296 V3 EN-US Figure 93: 7.5.8 Additional security logic for differential protection. Logic diagram for start up element. Technical data GUID-0BD8D3C9-620A-426C-BDB5-DAA0E4F8247F v5 Table 142: LDRGFC technical data Function Range or value Accuracy Operate current, zero sequence current (1-100)% of lBase ±1.0% of Ir Operate current, low current operation (1-100)% of lBase ±1.0% of Ir Operate voltage, phase to neutral (1-100)% of UBase ±0.5% of Ur Operate voltage, phase to phase (1-100)% of UBase ±0.5% of Ur Independent time delay, zero sequence current at 0 to 2 x Iset (0.000-60.000) s ±0.2% or ±35 ms whichever is greater Independent time delay, low current operation at 2 x Iset to 0 (0.000-60.000) s ±0.2% or ± 35 ms whichever is greater Independent time delay, low voltage operation at 2 x Uset to 0 (0.000-60.000) s ±0.2% or ±35 ms whichever is greater Reset time delay for startup signal at 0 to 2 x Uset (0.000-60.000) s ±0.2% or ±35 ms whichever is greater Line differential protection RED670 Technical manual 233 © 2017 - 2021 Hitachi Power Grids. 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