A Detailed Testing Procedure of Numerical Differential Protection Relay for EHV Auto Transformer

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Introduction
In modern Extra High Voltage (EHV) power networks, the protection of the power system is continuously being upgraded by the replacement of old electromechanical protection relays with the new microprocessor based numerical protection relays known as Intelligent Electronic Devices (IEDs). Retrofitting of numerical protection relays is essential and currently an ongoing process throughout power transmission networks. If it is not In the literature, very few research articles are published that discuss theoretical details of IEDs and different testing techniques. In [4], theoretical aspects in testing of the microprocessor based numerical protection relays are discussed. The author discusses the concepts, such as vector group of transformers, interposing CTs, and zero sequence filtering in detail. Moreover, the authors also describe the concepts for pickup test and bias characteristics test. However, the paper lacks a double phase pickup test and harmonic restraint testing of numerical differential relay that are of vital importance. In [5], a study of differential relay is presented considering power system disturbances and the behavior of the numerical differential relay is analyzed in detail; however, its exact threshold settings and set points are not verified. A novel technique for determining the settings of numerical differential relay is proposed in [6]. The authors have used a software-based simulator that utilizes iterations for the determination of settings. Furthermore, enhancement techniques for power transformer differential protection are described in [7], in which the author also discussed internal and external fault cases for differential protection and conducted a simulation testing through real-time digital simulation.
The actuation of transformer differential protection is conditional to the presence of existing internal transformer faults that may deteriorate a transformer's health. Several methods have been developed to perform condition monitoring of a transformer's health [8]. One such method is Frequency Response Analysis (FRA), which deals with analyzing the frequency response of a transformer on application of signal with frequency ranging from several hundred to several mega Hertz (low, mid, and high frequency bands) and compares it with the pre-commissioning or factory testing signal of transformers. In [8], Energies 2021, 14, 8447 3 of 21 the authors provide comprehensive guidelines for interpretation and evaluation of FRA of transformers. Moreover, in [9], the authors discuss valuable insight on understanding FRA signatures and the effect of several transformer faults on FRA signature. The faults include axial displacement, bushing fault, radial deformation, loss of clamping pressure, inter-disk fault, and short circuit fault.
To the best of the author's knowledge, there is no formal guideline and detailed study available to the research community and power system protection experts that thoroughly discusses the testing procedures for numerical differential relays as a single document. Therefore, to fill this literature gap, the main purpose of this research work is to prepare and compose a step-by-step detailed manual that can provide a complete guideline for the practical implementation of relay testing procedures and thorough numerical analysis that one can follow to check the health and functionality of a differential protection relay installed at EHV auto transformer. A real-time result analysis is performed on the differential relay installed for protection of 160 MVA, 220/132 kV Auto Transformer located at 220 kV Grid Station NTDC Kala Shah Kaku, Lahore, Pakistan. The experimental results are scrutinized to document a detailed theoretical and technical analysis. In light of the above stated actualities, the main contributions of the paper are: • Detailed insight analysis of numerical differential relay settings including connection details, operating principle, and biasing characteristics. Moreover, important transformer considerations are also discussed. • A detailed testing procedure of numerical differential relay is conducted through secondary injection testing with actual settings. The testing results include measurement test, pickup test, trip-time test, stability test, bias characteristics test, 2nd and 5th harmonic restraints test, and high stage 1 and high stage 2 test. • A detailed theoretical and technical analysis is conducted and documented to analyze the practical results.
The remaining paper is organized as follows: Section 2 discusses differential relay architecture and differential relay considerations for transformer application briefly. Section 3 focuses towards Matching Current Transformers or Interposing Current Transformers. The key settings implemented in the relay under test are described in Section 4. Section 5 discusses the testing of differential relay in detail. Section 6 focuses on a result discussion of the tests performed. The paper is concluded in Section 7 along with future suggestions. Figure 2a shows the single line diagram for connections of differential relay based on Kirchhoff's current law [10]. In Figure 2a, the current transformers are used as current sensors that essentially stepdown current with high fidelity [11]. The relay receives input from CTs, and continuously monitors and compares current. If any mismatch is observed beyond the defined setting, then the trip command is initiated, which isolates the protected object from the power system. Differential relay compares the magnitude and phase angle of the currents available at its terminals and remains stable if the vector sum of compared currents is less than the threshold setting in its internal differential coils [5]. Figure 2b explains the single-phase schematic drawing for basic operating principle of the differential relay. The comparison or vector sum is performed in the differential coil C of the relay and resultant current is called differential current I di f f . The I di f f is zero if vector sum of currents from side A (I A ) and side B (I B ) is zero. The minimum value of the differential current I di f f at which the relay operates is controlled by a setting called I di f f pickup. A minute spill current normally flows through the relay due to the CT errors and losses [12].

Differential Relay
In Figure 2b, the restraining coils A and B are also called biasing coils. As the current through protected equipment increases, for example in case of through fault, spill current increases proportionally. The relay may operate during through fault due to spill current since the I di f f pickup was the only setting of the differential relay, which is highly undesirable. To mitigate this issue, restraining or biasing is provided based on the loading condition of the protected object through restraining coils, and their setting results in percentage bias characteristics (slope characteristics) of the relay, which essentially results in restraining the operation of the relay [13]. The restraint (biasing) characteristics provide stability to the differential relay during normal and through fault scenarios; therefore, the differential relays are called percentage biased differential relays.

Transformers
A transformer is a static electric machine and works on electromagnetic induction principles. It is used to transfer power from one voltage level to another one while maintaining electrical isolation between different voltage levels and can be controlled by varying the number of turns of each winding. However, the voltage per turn ratio remains constant across its windings. The nominal current of each winding can be calculated by using Equation (1) [4].
The transformers occupy less geographical area that makes them well suited to be protected through differential protection. The differential protection has a very crisp and well-defined zone of protection. The zone of protection is between the CTs that are feeding the differential relay. Some important considerations regarding transformers must be considered before further delving into application of differential relay for the protection of transformers. In a nutshell, the transformer differential relay must cater for the following characteristics of a transformer.

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Differential relay should cater Vector Group of Transformer [14,15], Zero Sequence Current Flows [16], On Load Tap Changers [17], and must not initiate tripping during normal operation of transformer including energization of transformer (Inrush Current [18,19]), over fluxing [20], and tap changer operation. • Differential relay should remain stable during through fault even if the CT saturation of one or more CTs occur [21,22]. • Differential relay should only initiate tripping during in-zone fault (fault inside protection zone of differential relay [23]).

Matching Current Transformers of Interposing Transformers
When no fault occurs in the differential protection zone during normal operation of a transformer, the current in differential coils of the differential relay should be equal in magnitude but with 180-degree phase shift. However, secondary currents from CTs mostly differ in magnitude and phase angle; therefore, the secondary currents cannot be directly applied to the differential coils of the relay and are conditioned and modified before applying to them so that the relay remains stable (ideally I di f f = 0) during the transformer's normal operation. The conditioning and matching of CT secondary currents are performed through Matching Current Transformers (MCT) or Interposing CT [4]. The matching CTs also performs zero-sequence filtering whenever required in the secondary circuit.  Figure 3a shows the connection diagram of the differential relay with two windings of the transformer. The transformer under consideration is 220/132/11 kV, 160/160/30 MVA auto transformer with vector group Yna0 + d11. High voltage side (primary winding) terminals are marked as A, B, and C while the secondary winding terminals (132 kV side) are marked as Am, Bm, and Cm. The neutral terminal is grounded and marked as O. Tertiary winding terminals (11 kV side) are marked as a, b, x, and c. Tertiary delta is unloaded, kept close through external jumper between terminal x and terminal c and is not wired to the differential relay. The external jumper between terminals x and c is connected to ground.
The secondary side of both main CTs is star connected and the star point is towards the auto transformer and is grounded at one point only. The secondary CT circuit from 220 and 132 kV side terminates into the current elements of the differential relay as shown in Figure 3a. The dotted box marked as "D" inside differential relay contains MCTs, restraining coils, differential coils, and harmonic restraining coils. In modern differential relays, all such coils are implemented through an algorithm. Matching CT's configuration and vector group depends on transformer under protection and may vary from manufacturer to manufacturer as per their protection design. Figure 3b shows the inside architecture of the dotted box D from Figure 3a [24]. The red (R), yellow (Y), blue (B), and neutral (N) currents from HV CT secondary side is shown as I HV sec−R , I HV sec−Y , I HV sec−B , and I HV sec−N , respectively. Similarly, for the LV CT secondary side they are shown as I LV sec−R , I LV sec−Y , I LV sec−B , and I LV sec−N , respectively. Both HV and LV side MCT is in star-deltastar configuration. The delta winding traps the zero-sequence current. In this particular case, both HV and LV MCT are used for magnitude compensation and phase introduced by them will be 0. MCT configurations for relay type P642 under different vector groups of transformers are as follows. . Differential relay circuit [24]: (a) connection diagram with two windings of transformer, and (b) matching CTs, restraining coils, and differential coils implemented in differential relay through algorithm.

HV MCT
Transformer HV side matching CTs, irrespective of transformer's vector group under protection are of either star-delta-star or star-star configuration. Star-delta-star configuration is used for magnitude compensation and zero sequence filtering whereas star-star configuration performs magnitude compensation only.

LV MCT
If the main transformer has a vector group of YyX or DdX (where X is any even integer from 0 to 11 indicating phase shift between HV and LV windings), then LV MCT will be star-star Z (when zero sequence current filtering is disabled) or star-delta-star Z (when zero sequence current filtering is enabled). The Z is the phase shift introduced by LV MCT for the compensation of phase shift introduced by the vector group of the main transformer. The delta is only introduced when zero sequence current filtering is required. Similarly, if the main transformer has vector group of YdX or DyX (where X is any odd integer from 1 to 11 showing phase shift between primary and secondary winding), then LV MCT will be star-delta Z. LV MCT provides necessary phase compensation in addition to the magnitude compensation and zero-sequence filtering (if required). Table 1 shows different vector groups of transformer and corresponding LV MCT configuration with required phase shift when the vector group of transformers under protection is YyX, DdX, YdX, or DyX.

Settings Implemented in Differential Relay
The S1 Agile software is used for implementation of settings in differential relay P642 (Make: Alstom [24]) [25]. The CT ratio data, transformer data, and differential relay settings implemented in the differential relay are shown in Tables 2-4, respectively. In Table 4, the setting 'T1 CT' with address '0A.10 corresponds to HV side CT and setting of HV CT ratio is 1200:1. The setting 'Polarity' is set to 'standard' that shows the star point of HV CT is towards transformer. Moreover, the setting 'T2 CT' with address '0A.14 corresponds to LV side CT and setting of LV CT Ratio is also 1200:1. The setting 'Polarity' is set to 'standard' that shows the star point of the LV CT is towards the transformer. Table 2. CT data implementation in differential relay on 220 kV GS KSK 160 MVA transformer T2.000.

CT and VT Ratios
Value   Table 3 corresponds to auto transformer data implemented in the differential relay. Power rating of both HV and LV winding is set to 160 MVA. The HV and LV connection of the auto transformer are in 'Y'. The HV nominal voltage rating and LV nominal voltage rating are 220 and 132 kV, respectively. The neutral of HV and LV winding is considered as 'grounded'. Figure 4 shows the graphical differential characteristics or bias characteristics implemented for the testing. The setting 'Trans Diff' is set to 'enabled', which means that the differential protection function is enabled in the relay. In Table 4 and Figure 4, the current I S1 is pick-up setting of the differential relay. Setting 'K1 in Table 4 and Figure 4 is the percentage slope for the slope 2 of differential characteristics. The slope provides restraining of differential protection operation in case of spill current occurrence due to the tap changing operation, CT errors, and through faults. The differential relay must remain stable and must not initiate tripping during through faults. However, the CT errors may result in larger mismatched current or spill current or differential current as defined in Figure 2b, which depends on fault intensity. In such cases, the restraining to differential operation is provided through slope setting 'K1 = 30%'. Slope is the ratio of change in differential current to the change in bias current.  In Table 4, the setting I S2 marks the start of slope 3, as shown in Figure 4. The slope 3 provides restraining of differential protection, during through fault, even if the main CT is saturated. The setting 'K2 in Table 4 and Figure 4 defines the percentage slope setting for slope 3. The setting 'I S − H S1 ' in Table 4 and Figure 4 monitors the operational peak of the differential current. Beyond setting 'I S − H S1 ', the 2nd harmonic restrain cannot restrain differential relay operation. Therefore, the setting should be kept higher than expected peak magnetizing current. Setting 'I S − H S1 ' only results in tripping if the peak value of the differential current exceeds 'I S − H S1 ' setting and operating point lies in trip region of the bias characteristics. If differential current exceeds the setting 'I S − H S2 ', as shown in Table 4 and Figure 4, the differential relay causes tripping regardless of biasing characteristics and harmonic components. The differential relay continuously calculates I di f f and I bias current through HV and LV secondary currents at its terminals. If the calculated I di f f and I bias currents end up in the tripping region, the differential relay will initiate tripping as per the defined algorithm. Setting 'Zero sequence filtering, HV' and 'Zero sequence filtering LV' set to 'Enabled' will result in the elimination of zero sequence current components through HV and LV MCTs. The 2nd, 5th harmonic blocking are set at 15% and 40%, respectively.

Test Apparatus
Testing of the differential relay is conducted through a six current source secondary injection universal relay test set connected to the relay, as shown in Figure 5a,b. The settings and configuration of the relay is performed through S1 Agile Software, and the computer is used for reference setting and result monitoring. The relay trip contact is used as stop contact for the test set.

Measurement Test
A measurement test is performed to ascertain that the relay is reading the current at its terminals accurately. Through the measurement test, the correctness of CT ratios and measurement of differential and restraining current is determined (in pu). The nominal current or full load current at primary and secondary side of the transformer is calculated using Equation (1) as I nom.pri = 420 A and I nom. sec = 700 A. The CT ratio at primary and secondary side of the transformer is computed as [4]: Referring to Figure 2b, the differential current is computed as vector sum of currents flowing through it as [4]: where I 1 and I 2 are the secondary current of HV MCT and LV MCT, respectively, that are shown as I A and I B in Figure 2b. The → I 1 and → I 2 are vector quantity currents flowing in the differential coil. Restraining current or bias current provides restrain to the differential relay operation [26]. The bias current is based on the loading of the transformer and hampers the operation of the relay. However, the bias current computation in differential relay differs in different makes and models, and even the same manufacturer may have different mathematical equation for its computations. Bias current is computed in Equation (6) as follows [4]: Both the differential and bias currents are measured as per unit quantities, where per unit value is the ratio of actual and base values. The base value is the rated secondary current of the main CTs that in our case is taken as 1A. Whereas, the HV MCT ratio and LV MCT ratio are automatically calculated by differential relay as 2.858 and 1.715, respectively, using Equation (7) [4].
HV MCT Ratio or LV MCT Ratio = a = I sec ondary I primary (7) Referring to Figure 6a and using HV MCT Ratio, we can illustrate that upon the injection of balanced three phase nominal HV secondary current (0.35A) into corresponding relay current elements with no current injection into LV side relay current elements, current equal to 1A flows in secondary of HV MCT, resulting in flow of I di f f = 1 pu using Equation (5) and I bias = 0.5 pu using Equation (6). In Figure 6a, the phase shift of three phases is shown through clock convention, where 0 corresponds to 0 • , 4 corresponds to −120 • , and 8 corresponds to −240 • . Therefore, in order to thoroughly verify the HV side relay elements measurement, HV secondary current corresponding to the different loading conditions is simulated and then by computing HV primary current values. Moreover, the differential current and bias current are compared with observed values. Tables 5 and 6 record the measurement results of the HV side relay current elements. Referring to Figure 6b and LV MCT Ratio, the injection of balanced three phase nominal LV secondary current (0.58A) into corresponding relay current elements with no current injection into HV side relay current elements, the current equal to 1A flows in secondary of the LV MCT, resulting in flow of I diff = 1 pu using Equation (5) and I bias = 0.5 pu using Equation (6). In Figure 6b, the clockwise phase shift of three phases is shown, where 6, 10, and 2 correspond to −180 • , −300 • , and 60 • . Tables 5 and 6 record the measurement results of the LV side relay current elements.

Pickup Test
A pickup test is performed to check the setting I S1 in differential relay and conducted separately from HV side and LV side relay elements. From Figure 6a, the pickup computes the minimum differential current that initiate relay tripping. For pickup test, Equations (8) and (9) compute the 3-phase HV side and LV side secondary currents related the pickup setting Is1 [5]. By injecting the secondary current (Equation (8)) to the HV side while keeping LV side to zero, the relay should pick up and trip as per setting. Similarly, if the current (Equation (9)) is injected to the LV side relay elements, the relay should pick up and tripping as per setting while keeping HV side to zero. The HV nom sec and LV nom sec are the nominal secondary CT currents for HV and LV sides.
3 − Phase Pickup current f or HV side = I S1 × HV nom sec 3 − Phase Pickup current f or LV side = I S1 × LV nom sec During testing, the gradual current increase is observed till relay pick up threshold and compared with the calculated value. Moreover, the respective current is gradually decreased until the relay drops off. Equations (10) and (11) are used for single phase pickup current injection calculation for HV and LV sides, respectively, while Equations (12) and (13) are used for two phase pickup current injection calculation for HV and LV sides, respectively [5].
1 Ph. Pickup current for HV side = I S1 × HV nom sec × MF 1 Ph. Pickup current for LV side = I S1 × LV nom sec × MF 2 Ph. Pickup current for HV side = I S1 × HV nom sec (12) 2 Ph. Pickup current for LV side = I S1 × LV nom sec × MF where MF is the multiplying factor where applicable that depends on the MCT configuration and zero sequence current filtering (enabled or disabled) status. For Equations (10)-(13), the MF is computed using sequence current (I 0 , I 1 , and I 2 ) given in Ref. [5]. Using [5], it is apparent that MF value in Equations (10) and (11) is 3 2 , while in Equation (13) the MF is 1. Table 7 shows the single, double, and three phase testing results where the acceptable range for pick-up observed is computed using the following range formula given in [24] as 0.9 × Pickup Calc. − 1.1 × Pickup Calc, and for drop-off observed, the range I defined as 0.9 × Pickup Calc. to 1.0 × Pickup Calc. Table 7 illustrates that for both HV and LV sides, all the pickup observed, and drop-off observed values for single, double, and three phase pickup tests are within the aforementioned ranges.

Trip Time Test
The trip time test is performed to measure the time from inception of fault till relay trips. The recommendation is to test trip time at 5.0 × HV Pickup Calc. [24]. The results of trip time test are recorded using three-phase current injection into HV side relay current elements 5.0 × HV Pickup Calc., which is 0.2625 A. The acceptable range is 30-35 ms, while observed is 27 ms. The simulation and analysis performed in Section 6.9 explicitly discuss the trip time test of numerical differential relay.

Stability Test
During through fault, the relay must remain stable and must not initiate tripping. Ideally, the bias current increases but the differential current remains low (near to zero). Practically, some differential current may be observed (due to CT saturation); however, the relay remains stable due to bias characteristics. The stability test is performed by simulating the condition for through fault. The condition can be simulated by simultaneously applying nominal HV and LV secondary currents at respective relay current elements. Table 8 presents the differential and bias currents measurements by the relay when 5 times of balanced HV and LV nominal secondary currents are applied at relay terminals.

Bias Test
Referring to the bias characteristics shown in Figure 4, testing of bias characteristics includes testing all three slopes. For each slope, two points are considered on the graph, near to the boundary of trip and restrain region. The current injections that correspond to the selected points are injected in the relay and its behavior is recorded. Figure 8 shows the points selected on Figure 4. Using Equations (5) and (6), the currents I 1 and I 2 shown in Figure 6a,b, respectively, are calculated for each point selected on Figure 8. Moreover, the I HV sec and I LV sec corresponding to I 1 and I 2 , respectively, are calculated in amperes. The 3phase I HV sec and I LV sec with angles shown in the stability test are applied simultaneously to the corresponding relay elements. The behavior of relay (Trip/No Trip) is recorded, and I di f f and I bias measured by relay is compared with the computed value of selected point. To illustrate this phenomenon, recorded results are shown in Table 9. Figure 9a shows the waveform of currents corresponding to Point 'B' mentioned in Table 9. Before the injection of currents corresponding to Point 'B', transformer rated currents are applied as pre-fault to differential relay. The pre-fault current values read by relay are 414.9 A (RMS) for primary side and 698.6 A (RMS) for secondary side. The injected three phase HV and LV fault currents into relay result into I di f f = 0.18 pu and I bias = 0.40 pu. The observed I di f f and I bias from relay are in accordance with the I di f f and I bias of Point 'B' as apparent from Figure 8. Figure 9b shows the waveform of currents corresponding to Point 'F' mentioned in Table 9. The injected three phase HV and LV fault currents into relay result into I di f f = 1.26 pu and I bias = 3.0 pu. The observed I di f f and I bias from relay are in accordance with the I di f f and I bias of Point 'F' as apparent from Figure 8. jected three phase HV and LV fault currents into relay result into = 0.18 pu and = 0.40 pu. The observed and from relay are in accordance with the and of Point 'B' as apparent from Figure 8. Figure 9b shows the waveform of currents corresponding to Point 'F' mentioned in Table 9. The injected three phase HV and LV fault currents into relay result into

The 2nd and 5th Harmonic Restraint Test
In-rush current and over fluxing of transformers results in increased 2nd harmonic and 5th harmonic current components, respectively. Once the harmonic contents are detected as per threshold setting, the relay's operation is restrained. The restraining of relay operation is tested by simultaneously injecting fundamental component of current (must be higher than and kept constant during test), and 2nd or 5th harmonic component into relay current element. By increasing the 2nd or 5th harmonic component, the percentage setting is verified from Table 4 at address 31.29 and 31.34, respectively. Results are given in Table 10.

High Stage 1 and High Stage 2 Test
To verify high stage 1 tripping, the differential protection must remain unblocked once the condition > − is fulfilled. The testing is performed per phase for HV side relay elements only. The results of high stage 1 test for setting given in Table 4 are recorded in Table 11. Moreover, the settings ' − ' and ' − ' are tested by testing points G, H and I, J, respectively, as shown in Figure 8. Table 12 records the test results for points G, H, I, and J. Figure 10a shows the waveform of currents corresponding to Point 'H' mentioned in Table 12. The injected three phase HV and LV fault currents into relay result into  Figure 9b shows the waveform of currents corresponding to Point 'F' mentioned in Table 9. The injected three phase HV and LV fault currents into relay result into = 1.26 pu and = 3.0 pu. The observed and from relay are in accordance with the and of Point 'F' as apparent from Figure 8.

The 2nd and 5th Harmonic Restraint Test
In-rush current and over fluxing of transformers results in increased 2nd harmonic and 5th harmonic current components, respectively. Once the harmonic contents are detected as per threshold setting, the relay's operation is restrained. The restraining of relay operation is tested by simultaneously injecting fundamental component of current (must be higher than and kept constant during test), and 2nd or 5th harmonic component into relay current element. By increasing the 2nd or 5th harmonic component, the percentage setting is verified from Table 4 at address 31.29 and 31.34, respectively. Results are given in Table 10.

High Stage 1 and High Stage 2 Test
To verify high stage 1 tripping, the differential protection must remain unblocked once the condition > − is fulfilled. The testing is performed per phase for HV side relay elements only. The results of high stage 1 test for setting given in Table 4 are recorded in Table 11. Moreover, the settings ' − ' and ' − ' are tested by testing points G, H and I, J, respectively, as shown in Figure 8. Table 12 records the test results for points G, H, I, and J. Figure 10a shows the waveform of currents corresponding to Point 'H' mentioned in Table 12. The injected three phase HV and LV fault currents into relay result into = 180 • 1.75 relay are 414.9 A ( ) for primary side and 698.6 A ( ) for secondary side. The injected three phase HV and LV fault currents into relay result into = 0.18 pu and = 0.40 pu. The observed and from relay are in accordance with the and of Point 'B' as apparent from Figure 8. Figure 9b shows the waveform of currents corresponding to Point 'F' mentioned in Table 9. The injected three phase HV and LV fault currents into relay result into

The 2nd and 5th Harmonic Restraint Test
In-rush current and over fluxing of transformers results in increased 2nd harmonic and 5th harmonic current components, respectively. Once the harmonic contents are de-tected as per threshold setting, the relay's operation is restrained. The restraining of relay operation is tested by simultaneously injecting fundamental component of current (must be higher than and kept constant during test), and 2nd or 5th harmonic component into relay current element. By increasing the 2nd or 5th harmonic component, the percent-age setting is verified from Table 4 at address 31.29 and 31.34, respectively. Results are given in Table 10.

High Stage 1 and High Stage 2 Test
To verify high stage 1 tripping, the differential protection must remain unblocked once the condition > − is fulfilled. The testing is performed per phase for HV side relay elements only. The results of high stage 1 test for setting given in Table 4 are recorded in Table 11. Moreover, the settings ' − ' and ' − ' are tested by testing points G, H and I, J, respectively, as shown in Figure 8. Table 12 records the test results for points G, H, I, and J. Figure 10a shows the waveform of currents corresponding to Point 'H' mentioned in   Figure 9b shows the waveform of currents corresponding to Point 'F' mentioned in Table 9. The injected three phase HV and LV fault currents into relay result into

The 2nd and 5th Harmonic Restraint Test
In-rush current and over fluxing of transformers results in increased 2nd harmonic and 5th harmonic current components, respectively. Once the harmonic contents are de-tected as per threshold setting, the relay's operation is restrained. The restraining of relay operation is tested by simultaneously injecting fundamental component of current (must be higher than and kept constant during test), and 2nd or 5th harmonic component into relay current element. By increasing the 2nd or 5th harmonic component, the percent-age setting is verified from Table 4 at address 31.29 and 31.34, respectively. Results are given in Table 10.

High Stage 1 and High Stage 2 Test
To verify high stage 1 tripping, the differential protection must remain unblocked once the condition > − is fulfilled. The testing is performed per phase for HV side relay elements only. The results of high stage 1 test for setting given in Table 4 are recorded in Table 11. Moreover, the settings ' − ' and ' − ' are tested by testing points G, H and I, J, respectively, as shown in Figure 8. Table 12 records the test results for points G, H, I, and J. Figure 10a shows the waveform of currents corresponding to Point 'H' mentioned in   Figure 9b shows the waveform of currents corresponding to Point 'F' mentioned in Table 9. The injected three phase HV and LV fault currents into relay result into

The 2nd and 5th Harmonic Restraint Test
In-rush current and over fluxing of transformers results in increased 2nd harmonic and 5th harmonic current components, respectively. Once the harmonic contents are de-tected as per threshold setting, the relay's operation is restrained. The restraining of relay operation is tested by simultaneously injecting fundamental component of current (must be higher than and kept constant during test), and 2nd or 5th harmonic component into relay current element. By increasing the 2nd or 5th harmonic component, the percent-age setting is verified from Table 4 at address 31.29 and 31.34, respectively. Results are given in Table 10.

High Stage 1 and High Stage 2 Test
To verify high stage 1 tripping, the differential protection must remain unblocked once the condition > − is fulfilled. The testing is performed per phase for HV side relay elements only. The results of high stage 1 test for setting given in Table 4 are recorded in Table 11. Moreover, the settings ' − ' and ' − ' are tested by testing points G, H and I, J, respectively, as shown in Figure 8. Table 12 records the test results for points G, H, I, and J. Figure 10a shows the waveform of currents corresponding to Point 'H' mentioned in    Table 9. The injected three phase HV and LV fault currents into relay result into

The 2nd and 5th Harmonic Restraint Test
In-rush current and over fluxing of transformers results in increased 2nd harmonic and 5th harmonic current components, respectively. Once the harmonic contents are de-tected as per threshold setting, the relay's operation is restrained. The restraining of relay operation is tested by simultaneously injecting fundamental component of current (must be higher than and kept constant during test), and 2nd or 5th harmonic component into relay current element. By increasing the 2nd or 5th harmonic component, the percent-age setting is verified from Table 4 at address 31.29 and 31.34, respectively. Results are given in Table 10.

High Stage 1 and High Stage 2 Test
To verify high stage 1 tripping, the differential protection must remain unblocked once the condition > − is fulfilled. The testing is performed per phase for HV side relay elements only. The results of high stage 1 test for setting given in Table 4 are recorded in Table 11. Moreover, the settings ' − ' and ' − ' are tested by testing points G, H and I, J, respectively, as shown in Figure 8. Table 12 records the test results for points G, H, I, and J. Figure 10a shows the waveform of currents corresponding to Point 'H' mentioned in  Figure 8. Differential characteristics or bias characteristics with selected points.

The 2nd and 5th Harmonic Restraint Test
In-rush current and over fluxing of transformers results in increased 2nd harmonic and 5th harmonic current components, respectively. Once the harmonic contents are detected as per threshold setting, the relay's operation is restrained. The restraining of relay operation is tested by simultaneously injecting fundamental component of current (must be higher than I di f f and kept constant during test), and 2nd or 5th harmonic component into relay current element. By increasing the 2nd or 5th harmonic component, the percentage setting is verified from Table 4 at address 31.29 and 31.34, respectively. Results are given in Table 10.

High Stage 1 and High Stage 2 Test
To verify high stage 1 tripping, the differential protection must remain unblocked once the condition I di f f > I S − H S1 is fulfilled. The testing is performed per phase for HV side relay elements only. The results of high stage 1 test for setting given in Table 4 are recorded in Table 11. Moreover, the settings 'I S − H S1 ' and 'I S − H S2 ' are tested by testing points G, H and I, J, respectively, as shown in Figure 8. Table 12 records the test results for points G, H, I, and J. Figure 10a shows the waveform of currents corresponding to Point 'H' mentioned in Table 12. The injected three phase HV and LV fault currents into relay result into I di f f = 5.6 pu & I bias = 10.0 pu. The observed I di f f and I bias from relay are in accordance with the I di f f and I bias of Point 'H' as apparent from Figure 8. Figure 10b shows the waveform of currents corresponding to Point 'I' mentioned in Table 12. The injected three phase HV and LV fault currents into relay result into I di f f = 6.4 pu & I bias = 12.0 pu. The observed I di f f and I bias from relay are in accordance with the I di f f and I bias of Point 'I' as apparent from Figure 8. Table 9. Test results of bias characteristics for points selected in Figure 11a.

Simulation Results and Discussion
In addition to testing, the numerical relays also generate time stamped waveforms and measurements as standard format COMTRADE [27]. Such waveform can provide important insight into pre-fault conditions, fault inception, post-fault conditions, and behavior of relay under real-time fault situations. Few current waveforms from COMTRADE files generated by relay for trip time test and bias characteristics test (point D) are displayed for discussion. Current waveforms for trip time test (fault current applied for extended time regardless of relay trip) and bias characteristic test at point D (fault current applied with nominal currents as pre-fault) in Figure 8 are presented in Figures 8a and 11b, respectively. The waveforms are plotted through SEL SynchroWAVE Event [28]. Figure 11a shows relay reads Red Phase Primary Current (IA_1_1.sec) as 307A (RMS), which is approximately equal to 315A, as per discussed calculations. Similarly, Red Phase Differential Current (IA_DIFF) is observed as I di f f = 0.7540 pu and Red Phase Bias Current (IA_BIAS) is observed as I bias = 0.3783 pu. Observed values of Red Phase Differential Current (IA_DIFF) and Red Phase Bias Current (IA_BIAS) are as per calculations discussed. The calculated values of Red Phase Differential Current and Red Phase Bias Current being I di f f = 0.75 pu and I bias = 0.375 pu, respectively. Figure 11b shows transformer red phase currents calculated by relay (IA_1_1.sec corresponds to HV side red phase current, IA_2_1.sec corresponds to LV side red phase current, IA_DIFF corresponds to red phase differential current, and IA_BIAS corresponds to red phase bias current) when point D in Figure 8

Conclusions and Future Work
In this paper, a complete procedural guideline for the practical implementation of numerical differential relay testing procedures was prepared and composed for insight analysis of relay settings for the protection of an EHV 220/132 kV auto transformer. Moreover, based on the experimental results, a detailed technical and theoretical analysis including connection details, operating principle, and biasing characteristics was also performed. A secondary injection relay test set was used for the detailed testing of numerical differential relay. For this purpose, a "six current source secondary injection universal relay test set" was connected to the relay. Keeping in view of the prepared formal procedural guideline, the real-time implementation of relay was performed, which gives a detailed insight study that can be helpful for the research community and power system protection experts in understanding the basic principles, operation, and testing of numerical differential relays.
The tests used to monitor a relay's health include measurement test, pickup test, trip-time test, stability test, bias characteristics test, 2nd and 5th harmonic restraints test, and high stage 1 and high stage 2 test. The testing results were then critically analyzed from theoretical and practical perspectives to insure the relay's satisfactory performance. Table 13 tabulates the summarized results of relay testing with the final remarks presented against each test. The testing results of the differential relay under consideration are satisfactory and indicate the sound health and appropriate functionality of relay.  Figure 8 are as per respective region (trip/restrain). Additionally, the obs. I di f f and I bias currents of relay are comparable to calc. I di f f and I bias shown in Figure 8. If the behavior of relay deviates from the applied settings in such a way that the deviation is greater than the allowed tolerance by manufacturer and it is made sure again that the testing procedure followed is proper and comprehensive and the relay settings under test are properly understood by testing engineer, then proceedings can be made to declare the relay unhealthy. Moreover, diagnosis can also be made through testing to determine whether any analogue, input/output module, CPU module, or power supply module is faulty. After identification and replacing the faulty module with the healthy one, the relay is to be tested again to ensure its healthiness.
In future, a detailed manual will be prepared which will include comprehensive testing procedural guidelines for understanding the complex design, features, and working of the numerical distance protection relay used for the protection of EHV transmission lines.  Informed Consent Statement: Not applicable.

Data Availability Statement:
As all the hardware testing were performed on differential relay installed for protection of 160 MVA, 220/132 kV Auto Transformer located at 220 kV Grid Station NTDC Kala Shah Kaku, Lahore, Pakistan. Due to the privacy policy of the national grid, the data cannot be shared openly.