Line Differential Relays

Line Differential Relays in the

Computer-Aided Protection Engineering System (CAPE)

Prepared for

CAPE Users’ Group

June 24-25, 2008

Electrocon International, Inc.

Ann Arbor, Michigan

This document is the sole property of Electrocon International, Inc. and is provided to the CAPE Users Group for its own use only. It may not be supplied to any third party, or copied or reproduced in any form, without the express written permission of Electrocon International, Inc. All copies and reproductions shall be the property of Electrocon International, Inc. and must bear this ownership statement in its entirety.

Line Differential Relays 2008 Users’ Group Meeting

Line Differential Relays

I. Introduction This Application Note explains how CAPE models line current differential relays. A differential relay [1-4] measures the difference between the input and output currents of the protected equipment. This difference current, IOP in Figure 1, is proportional to the fault current for internal faults and is well below pickup for other operating conditions. A bus, machine, or transformer can be protected by a single differential relay in a unit protection scheme, but a line needs at least two relays: one per terminal, and a communication channel to transmit remote currents and possibly remote settings.

Figure 1: Two-Circuit Current-Differential Scheme, Showing One of the Two Line Relays.

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The line differential relay has one three-phase operating CT per winding and operates as a "segregated ABC-Phase" relay. A single three-phase element in CAPE represents three identical relay elements, one per phase. Each compares one local current from (Ia, Ib, Ic) with the corresponding phase current at the other terminals, using the fundamental frequency component. If only one phase causes operation, and the actual relay allows single-pole tripping, the element can trip only the faulted phase. Some relays also have separate ground or negative-sequence differential elements. The CAPE model predicts definite operation or non-operation for solid or low-resistance faults. Because some practical limitations are ignored, the region of marginal operation near the operating characteristic is not accurate: detection of high-resistance faults, for example. CAPE uses the following approximations, which are appropriate in a phasor analysis of line relays:

• Currents and voltages are steady-state phasors. Transient effects such as DC offset in the fault current are ignored.

• Communication-signal phase delay is ignored: the local and remote current phasors

are added directly and treated as synchronized.

• CAPE assumes that the CTs are ideal transformers, with no saturation limit. Difference currents due to CT saturation are ignored, under the assumption that the sloped characteristic can be set to avoid them. CT saturation detectors (such as in the ABB REL561) are not modeled.

• Some line differential relays (e.g. Siemens 7SA6) integrate the transient current for

1/4 cycle to find the total charge at the line ends. This supplementary function provides subcycle tripping, ahead of CT saturation. It is outside the scope of the phasor model. The CAPE model uses only the standard operate-restraint characteristic; timing cannot be resolved below about 1 cycle.

• CAPE does not compute inrush currents from a power transformer in the protected

region, so second-harmonic inrush restraint is ignored. Appendix A lists all the differential relays now modeled in CAPE. II. Model of a Line Current Differential Relay A. CT Connections and Current Balance A Main CT on the terminal measures currents from the bus into the protected equipment (for positive CT polarity). The CT on the terminal is always on the bus side of the circuit breaker, as in Figure 1. In the CAPE model, each relay is connected to all the CTs at the protected terminals as in Figure 1. This arrangement lets the CAPE user set and model one relay at a time for any

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type of equipment (line or unit protection). You do not need to supply a CT summation point, because CAPE adds the currents internally using special code for a CDIFF element. However, you do have to connect the same CTs to the relays at both terminals. If the database has more than one possible CT, you must make sure that you choose the same CTs for all the relays. The difference or operating current, IOP, is the total rms phasor into the relay element:

current into equipmentOperating current = Sum over CTs of tap setting

⎛ ⎞⎜ ⎟⎝ ⎠

The tap settings Tj = (T1, T2) compensate for differing CT ratios and allow for a transformer in the protected zone. In electromechanical relays, the taps must be set by hand. The CAPE models of microprocessor relays have default settings that balance the local and remote currents in case the ratios are different. B. Characteristic Slope Percentage differential relays operate when the difference current exceeds a percentage of a restraint current. The restraint current is a combination of the terminal currents; its definition depends on the relay. A generic percentage differential characteristic has a three-step shape (two slopes and one pickup level) as in Figure 2. This is an adequate approximation for most curve shapes, since the other approximations already limit the accuracy for operating currents near the curve. For solid faults, the operating current is either well above the restraint (internal fault) or well below it (external fault).

RESTRAINT CURRENT

OPERATING CURRENT IOP

PICKUP (MIN. TRIP)

HIGH-SET OVERCURRENT

START OF SLOPE 1

START OF SLOPE 2

Figure 2: Percentage Differential Operating Characteristic.

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The relay operates when its (Operating Amps/Tap) exceeds either the Restraint (slope * restraint expression) or the high-set overcurrent pickup, on one or more phases. C. Alpha Plane (Schweitzer SEL311L) With the "alpha-plane" method [1, 2] the relay evaluates a ratio of phasors:

Alpha = (Total remote current /T2 ) / (Local current/T1) A single value of Alpha is found at the terminal where the local current is largest. This terminal makes the trip/restrain decision, and the remaining terminals make the same decision [1]. The relay trips when the magnitude and angle of Alpha are outside a specified segment of its complex plane (the restraint region). This rule applies to two-terminal or three-terminal lines. D. Line-Charging Compensation Capacitive current appears as an internal fault and reduces the sensitivity available in cables and long lines. Some relays correct for this and subtract part of the capacitive current at every terminal:

Differential current in phase A = Sum over N terminals of ( Ia - jB * Va / N ) Here: B = total line-charging susceptance (provided as relay taps); N = number of line terminals in use (2 or 3); Va is the postfault phase-A-to-neutral voltage measured by the relay VT; Ia is the total postfault phase A current measured by the relay CT. A similar expression corrects the neutral current (3I0) in the earth relay using the measured zero-sequence voltage V0. You have to connect an operating VT and set the appropriate taps. Details of the implementation are explained with the reference for each relay. E. AUX Element to Model Communication Channel (ABB REL561) The differential relay sums multiples of local and remote current. These currents are computed as (Primary Current/CT ratio) In a transformer or bus differential relay, all the taps are based on settings of the same relay, so no settings need be transmitted. However, line differential relays must scale the current correctly before transmitting it to the relays at the other terminals, in case the CT ratios are unequal. In the CAPE model the local relay must apply the correct remote scaling factor (the tap Tj) before it sums the local and remote secondary currents.

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At present, CAPE supplies default factors (Tj = Primary Base Amps / CTR) for balanced perunit currents when the CT ratios are different. The defaults are adequate for most applications, when operating current is either well above or well below pickup. If the factors are different from the defaults, the local relay in CAPE must look up the relay settings at the other terminals. The CAPE model of the ABB REL56 relay implements this option on an experimental basis, allowing CAPE to read the remote setting from the CAPE database. The user has to specify, in the database, which relay to designate as the remote relay. The library REL561 model contains an AUX element "REMOTE_1.” This AUX element represents the communication channel from the remote relay and does not have any tripping logic. You specify the remote-end relay as its external supervisor. Figure 3 shows this relationship.

Arrow shows transmission direction

Local CDIFF Remote CDIFF

AUX_REMOTE element

AUX_REMOTE element

Contact logic for remote breaker Contact logic for local breaker

Figure 3: External Supervisor for AUX_REMOTE Element, to Transmit Settings from a Relay at Another Terminal. III. Setting the Differential Element To add a differential relay to the system in the CAPE database, you use the Database Editor as follows: A. Specify a Local Zone of Protection, either LINE, XFMR, or MISC For a relay that is to trip the local (logical) breaker only, or the bus ties on one detailed double/triple bus structure, use a LINE LZOP. Otherwise specify one or more breakers in the Trip Data of a MISCELLANEOUS LZOP. The Protect Data consists of the branches for which the relay provides primary protection. Choose a relay name and add the relay to the LZOP.

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B. Place the CTs Place the CTs on the line branches or on a protected bus. For a line on a detailed breaker-and-a-half or ring bus structure, you need a CT summation point with two bus-tie CTs as parents. The Database Editor lets you begin to place the CT near the line end and then offers a special form that will create a pair of CTs and their summation point in one step. Connect each CT or summation point to the relay by specifying a CT Input. For CT INPUT 1, choose a CT at the local end of the line. For CT INPUT 2 or CT INPUT 3, choose a CT on a remote branch. The database library associates CT taps T1, T2, and T3, with inputs 1, 2, and 3 respectively. C. Set the Common Taps Set the relay common taps associated with each CT (such as rated MVA, base kV, or current scaling, depending on the relay). Also set the common taps that are needed for other relay elements. By default these local elements use the CT connected to CT INPUT 1. D. Check the Operation of the CDIFF Element: see the example below. E. Supply a Contact Logic Code and include it in the logic expression for the Local Zone of Protection. IV. Checking the Operation of a CDIFF Element Apply a close-in fault on one terminal, or a bus fault for a bus relay. Then use the System Simulator and view the text output. Enter the command "List_One_Element" or "ELE" and choose the element on the Protective Device Element Help Form. Alternatively, enter "ELE CSE,” which will report the currently selected element. The relay should operate for this internal fault. The screen report (Figure 4) and the plot in Figure 5 show the total operating and restraint currents in each phase, and the characteristic slope. *************************************************** *** Relay Element Report for 1148 CDIFF "Phase" *** *************************************************** Name GRL_100 TOSHIBA Type GRL100 Model GRL100 Style GRL100_5A Substation GAINESVILLE NO.2 Branch Main CT: 153-150 Ckt 1 (115.0 kV) CT quantity ABC Rated current 5.00 A LZOP 37 LINE Gainesville #1 White 115 Line Contact logic code: GRL100_CDIFF_3PH System MVA 100.0 Reference phase lead at bus 150 from 153 = 0 deg; primary connection is YY Operating Mode PERCENTAGE CT Qty ABC Restraint Expression: SUM * restraint factor 1.00

2008 Users’ Group Meeting

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Relay: 1148 CDIFF "Phase" Original Present CT tap CT_TAP1 1.0 1.0 CT tap CT_TAP2 1.0 1.0 Low current pickup/tap 0.5 0.5 Start of slope 1 (derived) 0.0 0.0 Percent slope 1 16.667 16.667 Start of slope 2 240.6 240.6 Percent slope 2 100.0 100.0 High current pickup/tap 999.0 999.0 No separate supervisor elements Operating Time: 1 CYCLES ************************************************* Operation report for 1148 CDIFF "Phase" ************************************************* Midline node on "150 GNSVL2+115 1" to "153 GANSVLE1 115" Ckt 1 "999001 GNSVL2+115 1" (NEWBUS1) distant 0.500 from "150 GNSVL2+115 1" SINGLE_LINE_GROUND at temporary bus "999001 GNSVL2+115 1" (NEWBUS1) *** Element operation: 1148 CDIFF "Phase" *** LZOP: 37 Gainesville #1 White 115 Line at GAINESVILLE NO.2 Relay Name: GRL_100 Model: GRL100 Style: GRL100_5A Tag: 1148 Element: CDIFF Designation: "Phase" CT branch Sec Amps Tap Setting 0-seq BaseA/ Op Amps/Tap Restraint/ Slope% Slope*Rstrnt Op/ (first parent) total (+ Seq) (Y/N) CTR Tap or Min Pickup A-G 150 153 1 32.14 @ -84 CT_TAP1 1.00 @ 0 Y 3.14 32.14 @ -84 (Ia) A-G 153 150 1 22.15 @ -78 CT_TAP2 1.00 @ 0 Y 3.14 22.15 @ -78 (Ia) A-G Total 54.235 @ -81 deg SUM 54.29 16.67 9.55 Op 5.68 B-G 150 153 1 1.58 @ -72 CT_TAP1 1.00 @ 0 Y 3.14 1.58 @ -72 (Ib) B-G 153 150 1 1.58 @ 108 CT_TAP2 1.00 @ 0 Y 3.14 1.58 @ 108 (Ib) B-G Total 0.000 @ 0 deg SUM 3.16 16.67 1.03 No Op 0.00 C-G 150 153 1 1.58 @ -69 CT_TAP1 1.00 @ 0 Y 3.14 1.58 @ -69 (Ic) C-G 153 150 1 1.58 @ 111 CT_TAP2 1.00 @ 0 Y 3.14 1.58 @ 111 (Ic) C-G Total 0.000 @ 0 deg SUM 3.16 16.67 1.03 No Op 0.00

Figure 4: GRL100 Operation for a Midline Fault on Phase A.

Line Differential Relays

1148 CDIFF "Phase" operates in 1.0 cyc; 0.02 sec; A-phase No separate supervisor elements


Figure 5: Operate/Restraint Characteristic for Toshiba GRL100 Current Differential Element.

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If the relay fails to operate:

• Make sure that enabling tap settings are ON for this relay.

• Check that the correct CTs are connected to both ends.

• Check that the reported CT taps are approximately proportional to (BASE Amps/CT ratio). If they are not, the CT ratios may be different; consult the Relay Quick Reference for the correct compensation settings.

Next, apply an external fault on one of the line-end buses. The element should not operate. In this example the currents cancel exactly (Figure 6).

SINGLE_LINE_GROUND at bus "153 GANSVLE1 115" LZOP: 37 Gainesville #1 White 115 Line at GAINESVILLE NO.2 Relay Name: GRL_100 Model: GRL100 Style: GRL100_5A Tag: 1148 Element: CDIFF Designation: "Phase" CT branch Sec Amps Tap Setting 0-seq BaseA/ Op Amps/Tap Restraint/ Slope% Slope*Rstrnt Op/ (first parent) total (+ Seq) (Y/N) CTR Tap or Min Pickup A-G 150 153 1 12.42 @ -83 CT_TAP1 1.00 @ 0 Y 3.14 12.42 @ -83 (Ia) A-G 153 150 1 12.42 @ 97 CT_TAP2 1.00 @ 0 Y 3.14 12.42 @ 97 (Ia) A-G Total 0.000 @ 0 deg SUM 24.85 16.67 4.64 No Op 0.00 B-G 150 153 1 2.17 @ 95 CT_TAP1 1.00 @ 0 Y 3.14 2.17 @ 95 (Ib) B-G 153 150 1 2.17 @ -85 CT_TAP2 1.00 @ 0 Y 3.14 2.17 @ -85 (Ib) B-G Total 0.000 @ 0 deg SUM 4.34 16.67 1.22 No Op 0.00 C-G 150 153 1 2.19 @ 93 CT_TAP1 1.00 @ 0 Y 3.14 2.19 @ 93 (Ic) C-G 153 150 1 2.19 @ -87 CT_TAP2 1.00 @ 0 Y 3.14 2.19 @ -87 (Ic) C-G Total 0.000 @ 0 deg SUM 4.37 16.67 1.23 No Op 0.00 1148 CDIFF "Phase" does not operate No separate supervisor elements

Figure 6: Non-operation for an External Bus Fault.

If the element misoperates for the external fault:

• Check that the correct CTs are connected to both ends.

• Check that the CT taps reported are approximately proportional to (BASE Amps/CT ratio).

• If you have delta-connected CTs on line terminals, make sure that the primary

phase lead angles are the same at all ends (e.g. 30 degrees).

• Look for load taps that supply infeed currents between the line ends.

• If mutual coupling or line charging is suspected, rebuild the network with "Use Mutuals" or "Use Line Charging" unchecked on the Session Setup form and test the relay again.

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Appendix A - Models of Differential Relays in CAPE (June 2008) The following differential relay models are in the library database "cape_starter.gdb.” For details, please refer to the online Relay Quick Reference. MANUFACTURER MODEL ==================== ================ ABB HCB ABB HCB-1 ABB REG216 ABB REG316 ABB REL561_V2 ABB RET316 ALSTOM P632 ALSTOM P633 ALSTOM P634 ASEA RADSB ASEA RADSE ASEA RADSG ASEA RADSS_6LINE ASEA RYDSA20-2 ASEA RYDSA20-3 BASLER ELECTRIC BE1-87T BASLER ELECTRIC BE1-CDS220 BBC DIX109 BBC DIX110 BBC DIX111 GEC ALSTHOM MBCH-12 GEC ALSTHOM MBCH-13 GEC ALSTHOM MBCH-16 GEC Measurements DTH31 GEC Measurements DTH32 GENERAL ELECTRIC B30 GENERAL ELECTRIC BDD15B GENERAL ELECTRIC BDD16B GENERAL ELECTRIC IJD53 GENERAL ELECTRIC L90 GENERAL ELECTRIC STD15 GENERAL ELECTRIC STD16 GENERAL ELECTRIC STD18 GENERAL ELECTRIC T35 GENERAL ELECTRIC T60 SCHWEITZER SEL-311L SCHWEITZER SEL-387 SCHWEITZER SEL-587 SIEMENS 7SD24 SIEMENS 7SD511_V3.0 SIEMENS 7SD52_V4.6 SIEMENS 7SD61 SIEMENS 7UT512-V3.0 SIEMENS 7UT513-V3.0 TOSHIBA GRL100 WESTINGHOUSE CA WESTINGHOUSE CA-16 WESTINGHOUSE CA-26 WESTINGHOUSE CA-6 WESTINGHOUSE HU WESTINGHOUSE HU-1 WESTINGHOUSE HU-4

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References 1. “Transformer Differential Relays in the Computer-Aided Protection Engineering

System (CAPE),” Prepared for CAPE Users’ Group by Electrocon International, Inc.; June 25-26, 2002

2. J. Lewis Blackburn, Protective Relaying Principles and Applications, 2nd Edition,

Marcel Dekker, Inc., New York, NY; 1998. 3. IEEE Guide for Protective Relay Applications to Transmission Lines, IEEE Std C37.113-

1999; Institute of Electrical and Electronic Engineers, Inc.; February 2000. 4. “Modeling Current Differential Relays in the Computer-Aided Protection Engineering

System (CAPE),” Prepared for CAPE Users’ Group by Electrocon International, Inc.; June 19-20, 2001.

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Line Differential Relays