1 00:00:18,375 --> 00:00:20,241 Restricted Earth Fault 2 00:00:20,466 --> 00:00:27,999 This document reviews the operating principle of five common relays with respect to the low-impedance REF function. 3 00:00:28,733 --> 00:00:34,466 For each relay, the function behavior is first examined in the same manner as described in the relay manual. Then 4 00:00:34,867 --> 00:00:39,400 the method for designing a complete test plan for that function is presented. 5 00:00:39,639 --> 00:00:50,866 The relays covered in this document are MiCOM P632, Siemens 7UT6x, Siemens 7UT8x, ABB RET521, and ABB RET620. 6 00:00:57,400 --> 00:01:00,133 In some of the listed relays 7 00:01:00,533 --> 00:01:07,066 relay operation is based on comparing the neutral-branch current with the zero-sequence current calculated by the relay. 8 00:01:07,533 --> 00:01:13,800 In practice, the relay operates based on the difference, or differential quantity, between these two currents. 9 00:01:14,266 --> 00:01:22,266 In some other relays, however, the comparison of these two currents is used only for relay stability by determining whether the fault is inside or outside the protection zone. 10 00:01:22,667 --> 00:01:26,800 In those cases, relay operation is based only on the neutral-branch current, 11 00:01:27,067 --> 00:01:30,866 and the differential quantity between the two currents is not used for relay operation. 12 00:01:32,467 --> 00:01:44,399 Restricted Earth Fault (REF) protection is used to detect earth faults inside different equipment such as transformers, autotransformers, reactors, motors, and similar apparatus. 13 00:01:44,723 --> 00:01:47,856 Because of its high accuracy and sensitivity, 14 00:01:48,190 --> 00:01:55,190 this protection can largely cover the areas that are not fully covered by transformer differential protection and conventional earth-fault protection. 15 00:01:55,590 --> 00:02:01,056 REF protection can be applied only when it is possible to measure the current flowing through the neutral point. 16 00:02:01,323 --> 00:02:07,256 During normal system operation, Isp and 3I0 are approximately zero. As 17 00:02:07,523 --> 00:02:17,056 As soon as an earth fault occurs, both currents change. Depending on the fault conditions, their values may be equal or may differ from one another. 18 00:02:19,923 --> 00:02:22,856 MiCOM P632 19 00:02:23,457 --> 00:02:33,123 The ground differential protection of this relay is based on comparing the vector sum of the phase currents on the relevant transformer side with the neutral-point current IY. 20 00:02:33,323 --> 00:02:40,256 To begin analyzing the behavior of this function, the relay parameters are first reviewed according to the relay manual. 21 00:02:40,857 --> 00:02:46,323 The first parameter used by this relay is the Matching Factor, which is calculated as follows. 22 00:02:47,923 --> 00:02:51,123 The following conditions apply to the Matching Factors: 23 00:02:51,523 --> 00:02:54,923 The Matching Factor must always be less than 16. 24 00:02:55,390 --> 00:02:58,989 The Matching Factor must always be greater than 0.5. 25 00:02:59,590 --> 00:03:05,323 If the Matching Factor does not satisfy the above conditions, an alarm is issued and the function is blocked. 26 00:03:05,856 --> 00:03:11,723 Two operating modes are described for this relay in the manual. Each mode is reviewed separately below. 27 00:03:12,123 --> 00:03:14,323 Low imped. / sum(IP) 28 00:03:14,723 --> 00:03:21,656 In this mode, the difference between each phase current and the neutral current is calculated as the differential current. 29 00:03:21,990 --> 00:03:25,523 The bias current is also considered to be the phase current. 30 00:03:26,723 --> 00:03:30,323 Low imped. / IP, max 31 00:03:31,057 --> 00:03:37,190 For this operating mode, the differential current and the bias current are defined as follows. 32 00:03:37,590 --> 00:03:42,856 Compared with the "Low imped. / Sum (IP)" operating mode 33 00:03:43,057 --> 00:03:46,190 a dual-slope characteristic is used here. 34 00:03:46,523 --> 00:03:47,457 Test Procedure 35 00:03:48,857 --> 00:03:55,390 To test this function, REF must be selected as the Protection Function in the Differential room. 36 00:03:55,523 --> 00:04:00,856 In the Primary column, the phase-side information (Main Side) must be entered, and 37 00:04:01,057 --> 00:04:05,256 and in the Secondary column, the neutral-side information must be entered. 38 00:04:06,723 --> 00:04:10,723 In the Protection Device tab and the Characteristic Definition tab, 39 00:04:10,923 --> 00:04:15,323 the information must be entered according to the operating mode selected in the relay. 40 00:04:16,057 --> 00:04:19,056 Low imped. / Sum (IP) 41 00:04:19,457 --> 00:04:25,856 Considering the bias-current formula for this mode, in which the phase current is used as the bias current, 42 00:04:26,257 --> 00:04:29,656 the appropriate formula is Max(Ip,Is). 43 00:04:29,923 --> 00:04:36,390 By default, the software assumes Ip to be the larger current, which causes the selected formula to match the relay formula. 44 00:04:36,857 --> 00:04:41,390 Since the REF characteristic-curve data are fixed, the information for Idiff>, Idiff>>, 45 00:04:41,923 --> 00:04:45,523 and the Characteristic Definition tab can be entered as shown below. 46 00:04:45,857 --> 00:04:50,723 In this mode, the information in the relay settings does not affect the characteristic curve. 47 00:04:51,590 --> 00:04:54,990 Low imped. / Ip,max 48 00:04:57,789 --> 00:05:03,923 In this mode, the selected bias-current formula is (|IP| + |IS|) / 2. This 49 00:05:04,923 --> 00:05:11,256 This is because, for each single-phase Fault Type, the tester injects current from only one phase on each side; 50 00:05:11,523 --> 00:05:21,190 therefore, Ip = 3I0. For the characteristic-curve data, the relay settings must be checked and the relay characteristic curve must be completed accordingly. 51 00:05:21,856 --> 00:05:26,922 Siemens 7UT6x (SIPROTEC 4) 52 00:05:27,590 --> 00:05:37,390 As mentioned earlier, REF protection uses two currents, Isp and 3I0, to perform the protection process. In 53 00:05:38,123 --> 00:05:47,190 In this process, the only operate current is Isp, while 3I0 is used to determine whether the system fault is internal or external. 54 00:05:48,057 --> 00:05:53,590 . During normal system operation, Isp and 3I0 are approximately zero. 55 00:05:54,057 --> 00:05:57,256 . As soon as an earth fault occurs, both currents change. 56 00:05:57,590 --> 00:06:01,990 Depending on the fault conditions, they may be equal or may differ from one another. 57 00:06:03,123 --> 00:06:09,190 If the fault occurs inside the protection zone, both Isp and 3I0 will flow. 58 00:06:09,590 --> 00:06:16,323 Considering that the directions of these currents are toward the inside of the transformer, both currents are considered positive. 59 00:06:19,257 --> 00:06:24,390 If the fault occurs outside the protection zone, both Isp and 3I0 will flow 60 00:06:24,790 --> 00:06:29,256 Isp flows toward the inside of the transformer and is considered positive, 61 00:06:29,457 --> 00:06:33,523 whereas 3I0 flows out of the transformer and is considered negative. 62 00:06:33,790 --> 00:06:39,390 To prevent REF protection from producing a false operation for faults outside the protection zone, 63 00:06:39,657 --> 00:06:44,323 a stabilizing method must be defined for the relay in addition to defining an operate current. 64 00:06:44,790 --> 00:06:50,056 Based on this explanation, IREF and Istab are defined as follows. 65 00:06:50,523 --> 00:06:54,990 To clarify the concept, three different fault conditions are described below. 66 00:06:56,123 --> 00:07:01,056 External-zone fault with equal magnitudes of Isp and 3I0 67 00:07:01,456 --> 00:07:06,256 In this condition, assuming equal magnitudes for Isp and 3I0, 68 00:07:06,523 --> 00:07:11,656 the direction of Isp is toward the inside of the transformer and is considered positive, 69 00:07:12,057 --> 00:07:16,523 while the direction of 3I0 is out of the transformer and is considered negative. 70 00:07:16,923 --> 00:07:25,056 In this condition, the stabilizing current is twice the operate current, and REF protection remains stable. 71 00:07:28,323 --> 00:07:32,123 Internal-zone fault with the fault fed only from the star point 72 00:07:32,657 --> 00:07:39,856 In this condition, Isp is toward the inside of the transformer and positive, while 3I0 is zero. 73 00:07:40,057 --> 00:07:45,190 In this condition, REF protection is at its highest sensitivity and will trip. 74 00:07:45,990 --> 00:07:50,723 Internal-zone fault with the fault fed equally from the star point and the system 75 00:07:53,123 --> 00:08:01,723 In this condition, the directions of Isp and 3I0 are both toward the inside of the transformer and are considered positive. 76 00:08:02,457 --> 00:08:05,390 In this condition, Istab is negative. 77 00:08:05,723 --> 00:08:11,190 Therefore, it is set to zero, and REF protection operates at its highest sensitivity and will trip. 78 00:08:12,257 --> 00:08:18,990 According to the explanations above, for an internal-zone fault the relay has no stabilizing current and will trip. 79 00:08:19,657 --> 00:08:25,523 For an external-zone fault, however, a large stabilizing current exists and the relay will not trip. 80 00:08:26,256 --> 00:08:34,123 In all the examples above, it was assumed that the directions of Isp and 3I0 are either the same 81 00:08:34,323 --> 00:08:40,923 or have a 180-degree angular difference. This assumption is valid for primary quantities. However, for secondary quantities, 82 00:08:41,257 --> 00:08:52,390 conditions such as CT saturation and angle measurement errors may create angular deviations and reduce the value of ISTAB. 83 00:08:52,590 --> 00:08:58,056 Based on the method described above, assuming equal magnitudes for Isp and 3I0, 84 00:08:58,323 --> 00:09:05,656 if the angle between Isp and 3I0 is 90 degrees, the value of ISTAB becomes zero. 85 00:09:05,856 --> 00:09:06,856 Example: 86 00:09:07,257 --> 00:09:14,390 In the Siemens relay, a parameter called Limit Angle is defined, and its value is 100 degrees 87 00:09:14,790 --> 00:09:21,990 If the angle between Isp and 3I0 is greater than this value, the relay will remain stable. 88 00:09:22,390 --> 00:09:29,990 The REF operating characteristic based on the angle between Isp and 3I0 is shown below. 89 00:09:30,923 --> 00:09:32,390 Test Procedure 90 00:09:32,790 --> 00:09:41,590 Because the REF function in Siemens SIPROTEC 4 relays is not designed as a differential function and no differential characteristic curve is defined for it, 91 00:09:42,057 --> 00:09:47,190 it cannot be tested in the Differential room. It must be tested in the AMT Sequencer room. 92 00:09:47,390 --> 00:09:53,256 For this purpose, one current from group A and one current from group B must be activated in the Hardware Config. 93 00:09:53,590 --> 00:09:58,190 Current IA is connected to the phase side, and current IB is connected to the neutral side. 94 00:09:59,857 --> 00:10:02,990 In the first test step, the Setting value must be tested. 95 00:10:03,257 --> 00:10:06,723 For example, for a value of 0.15In, 96 00:10:06,923 --> 00:10:12,990 current must be injected only from the neutral side using a Step Ramp, increasing the current in 2.5 mA steps. 97 00:10:13,323 --> 00:10:18,790 Note that in this relay, In is considered based on the transformer rated current, not the CT rated current. 98 00:10:19,123 --> 00:10:26,056 For example, if the rated current on the HV side is 250 A and the CT used is 300/1, 99 00:10:26,790 --> 00:10:38,656 then with the 0.15In setting the intended value is 0.15 × 250 = 37.5 A on the primary side and 0.125 A on the secondary side. 100 00:10:40,057 --> 00:10:47,190 In the next test step, the stabilizing method and the angle between the neutral current and the phase current must be tested. 101 00:10:47,523 --> 00:10:53,856 To test the stabilizing method, the phase current must be injected with the same magnitude as the neutral current. 102 00:10:54,057 --> 00:11:01,590 In the first case, it must be in phase with the neutral current; in the second case, it must have a 180-degree angular difference. 103 00:11:02,057 --> 00:11:08,990 In the in-phase condition, the relay trips, while in the 180-degree condition the relay must remain stable. 104 00:11:10,990 --> 00:11:15,990 In the final step, the Limit Angle, whose value is 100 degrees, must be tested. 105 00:11:16,457 --> 00:11:24,590 To do this, it is sufficient to select Quick mode and manually change the angle so that the relay behavior dependent on this angle can be tested and verified. 106 00:11:25,390 --> 00:11:29,923 Siemens 7UT8x (SIPROTEC 5) 107 00:11:31,323 --> 00:11:39,523 This relay uses IY, which is the neutral current, and 3I0, which is the zero-sequence current, for its calculations. 108 00:11:39,790 --> 00:11:44,590 From these two parameters, a differential current and a bias current are calculated. 109 00:11:45,123 --> 00:11:54,123 The characteristic curve provided for this function is in the form of Ichar versus Ibias. Ichar has separate definitions for pickup and trip, 110 00:11:54,523 --> 00:11:59,790 and therefore REF pickup operation and REF trip operation must be analyzed separately. 111 00:12:00,790 --> 00:12:02,723 Trip Operation 112 00:12:03,523 --> 00:12:13,456 For relay trip, the ratio of the neutral current to the Ichar value corresponding to Ibias on the characteristic curve is evaluated. 113 00:12:13,857 --> 00:12:19,056 According to the information provided in the relay manual, in order for the relay to issue a trip, 114 00:12:19,323 --> 00:12:27,656 the value of Itrip must first be greater than 1. In addition, relay trip depends on the angle between the neutral current and 3I0. 115 00:12:27,923 --> 00:12:32,256 If this angle is less than 90 degrees, the fault is considered internal. 116 00:12:32,457 --> 00:12:40,390 If it is greater than 90 degrees, the fault is identified as either internal or external depending on the ratio of IY to 3I0. 117 00:12:41,923 --> 00:12:43,590 Pickup Operation 118 00:12:43,856 --> 00:12:48,122 The pickup of this function is independent of the angle between the currents. 119 00:12:48,390 --> 00:12:53,256 If the calculated Idiff is greater than Ichar, the relay will pick up. 120 00:12:55,657 --> 00:12:56,790 Test Procedure 121 00:12:57,390 --> 00:13:04,923 Since the REF trip characteristic curve in Siemens SIPROTEC 5 relays is not treated as a differential characteristic curve, 122 00:13:05,189 --> 00:13:08,188 relay trip cannot be tested in the Differential room. 123 00:13:08,590 --> 00:13:12,456 The trip test must be performed in the AMT Sequencer room. 124 00:13:12,923 --> 00:13:18,923 Note that the characteristic curve has bias on the horizontal axis and Ichar on the vertical axis. 125 00:13:19,323 --> 00:13:26,723 For relay trip, this vertical axis represents IY; therefore, relay trip cannot be tested in the Differential room. 126 00:13:27,657 --> 00:13:34,790 For testing in the Sequencer room, three currents from group A and one current from group B must be activated in the Hardware Config. 127 00:13:35,057 --> 00:13:40,523 The three group-A currents are connected to the phase side, and current IB is connected to the neutral side. 128 00:13:41,657 --> 00:13:44,990 In the first test step, the Setting value must be tested. 129 00:13:45,657 --> 00:13:49,456 To do this, current must be injected into one of the three phases, 130 00:13:49,723 --> 00:13:53,190 and then the neutral current must be increased step by step. After 131 00:13:53,657 --> 00:13:59,056 After the relay trips, the neutral current that caused the trip must be matched with the characteristic curve. 132 00:13:59,657 --> 00:14:07,856 For this matching, the corresponding bias current must first be calculated using the provided equation, and then IY must be compared with Ichar. 133 00:14:10,057 --> 00:14:17,456 In the next test step, the stabilizing method and the angle between the neutral current and the phase current must be tested. 134 00:14:18,390 --> 00:14:23,590 To test the stabilizing method, the phase current must be injected with a specified magnitude, 135 00:14:24,123 --> 00:14:27,456 and the neutral current must also be injected under different conditions. 136 00:14:27,657 --> 00:14:37,856 For this purpose, current must be injected into both the phase side and the neutral side and adjusted so that the IY current lies in the operating area of the relay characteristic curve. 137 00:14:38,323 --> 00:14:43,123 To test this condition, the current magnitudes must be kept constant in Quick mode, 138 00:14:43,390 --> 00:14:50,990 and the angle must be checked at the threshold value, for example 90 degrees, to verify correct relay operation. As shown in the curve on the right, 139 00:14:51,457 --> 00:14:58,390 the angle threshold varies depending on the ratio of IY to 3I0, which can be considered during testing. 140 00:15:00,657 --> 00:15:06,790 For testing relay pickup, the Differential room can be used because, according to the relay manual, 141 00:15:06,990 --> 00:15:15,923 the vertical axis of the Ichar-Ibias characteristic curve is the differential quantity between the neutral current and the zero-sequence current. 142 00:15:18,923 --> 00:15:28,323 For testing in the Differential room, in the Test Object window, the Differential block must be configured by selecting REF as the Protection Function. 143 00:15:28,856 --> 00:15:35,256 Then, the Main Side and Neutral information must be completed according to the side on which this function is applied. 144 00:15:35,790 --> 00:15:39,390 The Ibias formula must be entered as IP + IS. 145 00:15:39,722 --> 00:15:45,990 Since only one phase current is injected during a single-phase fault, this formula corresponds to the relay formula. 146 00:15:47,387 --> 00:15:50,456 ABB RET521 147 00:15:51,323 --> 00:15:55,990 To detect an internal-zone earth fault, the relay uses two elements: the 148 00:15:56,123 --> 00:15:59,656 the diff-bias characteristic curve and a directional element. 149 00:16:00,257 --> 00:16:08,256 In this relay, the neutral current (IN) is--- considered the directional reference because its direction is fixed in both internal and external fault conditions. 150 00:16:08,857 --> 00:16:13,256 For this relay, the equations given for Idiff and Ibias are as follows. 151 00:16:13,723 --> 00:16:19,256 Based on the structure provided in this relay manual, the phase-side CTs must be grounded toward the transformer, 152 00:16:19,457 --> 00:16:23,656 while the neutral-side CT must be grounded in the opposite direction to the transformer. 153 00:16:23,857 --> 00:16:27,990 For this reason, the negative sign in the Idiff calculation becomes meaningful. 154 00:16:28,123 --> 00:16:34,123 In general, in order for the relay to identify an earth fault inside the protection zone, 155 00:16:34,323 --> 00:16:39,256 the directions of the currents seen by the relay must be opposite to each other. 156 00:16:40,723 --> 00:16:45,790 For faults outside the protection zone, the differential quantity is approximately zero. 157 00:16:45,990 --> 00:16:50,590 Based on the relay definition, the direction of the current in both CTs is the same, which 158 00:16:50,923 --> 00:16:54,990 which causes the relay to identify the fault as being outside the protection zone. 159 00:16:55,990 --> 00:17:00,856 The diff-bias characteristic curve provided by the relay consists of three sections. 160 00:17:01,190 --> 00:17:06,523 In the first section, the threshold current is adjustable by the user from 5% to 50%, while 161 00:17:06,857 --> 00:17:09,123 while the other sections are defined and fixed. 162 00:17:09,590 --> 00:17:10,723 Test Procedure 163 00:17:11,323 --> 00:17:16,790 This function in the RET521 relay can be tested in the Differential room. 164 00:17:17,123 --> 00:17:22,456 The following points must be considered when entering the information for this protection function. 165 00:17:22,923 --> 00:17:28,656 To test this function, REF must be selected as the Protection Function in the Differential room. 166 00:17:29,190 --> 00:17:37,323 The phase-side information (Main Side) must be entered in the Primary column, and the neutral-side information must be entered in the Secondary column. 167 00:17:37,590 --> 00:17:45,590 The Starpoint Grounding direction for the Neutral side must be selected as Toward Line, and the Ibias relation must be selected as Max(Ip,Is). 168 00:17:46,590 --> 00:17:52,656 In this example, the differential characteristic curve has been drawn for an operating threshold of 0.3. 169 00:17:53,457 --> 00:17:56,190 ABB RET620 170 00:17:56,590 --> 00:18:06,590 For REF protection, this relay uses the differential quantity between the phase zero-sequence current (3I0) and the neutral current IY. 171 00:18:07,057 --> 00:18:11,923 A bias current is also defined for the diff-bias characteristic curve of this function, 172 00:18:12,123 --> 00:18:14,789 which is the average of the three phase currents of the relay. 173 00:18:15,057 --> 00:18:17,590 According to the points stated in the relay manual, 174 00:18:17,857 --> 00:18:25,923 COSphi is considered equal to 1 when the angle between the neutral current (IY) and the phase zero-sequence current (3I0) is 180 degrees. 175 00:18:26,190 --> 00:18:30,523 If the angle between them is less than 90 degrees, COSphi is considered zero. 176 00:18:30,857 --> 00:18:39,057 Therefore, the relay will trip only when the angle between the neutral current (IY) and the phase zero-sequence current (3I0) is greater than 90 degrees. 177 00:18:39,323 --> 00:18:41,456 Two Connection Types are defined for this relay. 178 00:18:41,590 --> 00:18:48,257 In summary, if the CTs on both sides are grounded either toward the equipment or away from the equipment, 179 00:18:48,656 --> 00:18:59,086 the connection is Type 1. If one CT is grounded toward the transformer and the other is grounded in the opposite direction, the connection is Type 2. 180 00:19:00,687 --> 00:19:03,620 Internal and External Fault Identification 181 00:19:04,087 --> 00:19:11,820 In the relay manual, the structure below (Type 1) is used to explain internal and external faults and to analyze relay behavior. 182 00:19:12,687 --> 00:19:21,286 In this structure, if the angle between 3I0 and IY is less than 90 degrees, the fault is identified as external and the function is blocked. 183 00:19:21,887 --> 00:19:23,419 Test Procedure 184 00:19:23,687 --> 00:19:28,486 This function in the RET620 relay can be tested in the Differential room. 185 00:19:28,687 --> 00:19:33,753 The following points must be considered when entering the information for this protection function. 186 00:19:34,020 --> 00:19:39,486 To test this function, REF must be selected as the Protection Function in the Differential room. 187 00:19:39,753 --> 00:19:44,219 In the Primary column, the phase-side information (Main Side) must be entered, 188 00:19:44,620 --> 00:19:48,419 and in the Secondary column, the neutral-side information must be entered. 189 00:19:48,820 --> 00:19:56,020 If the Connection Type in the relay is Type 1, the Starpoint Grounding direction of both CTs must be selected as Toward Object; 190 00:19:56,353 --> 00:19:59,553 otherwise, the neutral-side CT must be selected as Toward Line. 191 00:19:59,820 --> 00:20:08,553 The Ibias relation must be selected as Max(Ip,Is) / K1, with K1 = 3. 192 00:20:09,220 --> 00:20:15,820 In this example, the differential characteristic curve has been drawn for an operating threshold of 0.3.