Transformer Protection Application Guide
About the Author George Rockefeller is President of Rockefeller Associates, Inc. He has a BS in EE from Lehigh University; a MS from New Jersey Institute of Technology and a MBA from Fairleigh Dickinson University. Mr. Rockefeller is a Fellow of IEEE and Past Chairman of IEEE Power Systems Relaying Committee. He holds nine U.S. Patents and is co-author of Applied Protective Relaying (1st Edition). Mr. Rockefeller worked for Westinghouse Electric Corporation for twenty-one years in application and system design of protective relaying systems. He worked for Consolidated Edison Company for ten years as a System Engineer. He has also served as a private consultant since 1982.
This Guide contains a summary of information for the protection of various types of electrical equipment. Neither Basler Electric Company nor anyone acting on its behalf makes any warranty or representation, express or implied, as to the accuracy or completeness of the information contained herein, nor assumes any responsibility or liability for the use or consequences of use of any of this information. Revised 8/03
Transformer Protection Application Guide This guide focuses primarily on electrically actuated relays for the more prevalent applications. Principles are emphasized. The references provide a source for additional information. Reference 1 includes extensive references and bibliographies. References 2 & 3 contain a chapter on transformer protection.
Setting procedures are not included; refer to specific instruction manuals. Fuse protection is only briefly addressed. Grounding transformers and 3 phase banks of single-phase transformers are not considered here, but are treated in Reference 1. Table I (page 18) provides Basler model, function, description and style number. It also references the figures where the relays are indicated by their ANSI numbers.
This guide was prepared to assist in the selection of relays to protect power transformers. The purpose of each relay is described and related to one or more power system examples.
1. Failure Statistics The engineer must balance the expense of applying a particular relay against the consequences of relying on other protection or sacrificing the transformer. Allowing a protracted fault would increase the damage to the transformer and the possibility of tank rupture with a consequent oil fire. An increase in damage would not necessarily have significant economic impact, depending upon whether the initial damage can be repaired on site. For example, a tap changer flashover can ordinarily be repaired in the field, but if this fault is allowed to evolve into a winding fault, the economic impact can be substantial. Transformers used in a unit-connected generator unit are particularly critical, since the unavailability of the transformer can create large generation-replacement costs. Similar economic impacts may also exist at industrial sites. This explains why the MVA rating of the transformer may not be the pivotal aspect in choosing the appropriate protection.
Table II (page 3) lists failures for six categories of faults (Reference 1). Winding and tap changers account for 70% of failures. Loose connections are included as the initiating event, as well as insulation failures. The miscellaneous category includes CT failure, external faults, overloads and damage in shipment. An undisclosed number of failures start as incipient problems. These failures can be detected by sophisticated on-line monitoring devices (e.g. gas-in-oil analyzer) before a serious event occurs. Such devices will probably see increasing use on larger transformers, to supplement more conventional relays (Reference 8). 2. Fuses Fuses are economical, require little maintenance and do not need an external power source to clear a fault. However, they introduce singlephasing conditions when just one or two
1
FIGURE 1. (See Legend, next page).
LEGEND FOR FIGURES. Device 49 50 / 51 51 51N-1 51N51N-2 2 51N-3 63 67 67N 67N 86 87T 87T 87 N
resistance grounded on the 13 kV side. A detailed discussion of this application is premature, but the following is an introductory treatment. The phase differential (87), ground differential (87N) and sudden pressure relay (63) provide the primary transformer fault protection. Note that the 51N-2 relay serves primarily as back-up rather than as transformer protection. The 51 and 51N-3 relays function as partial differential relays to protect the bus and back up the downstream relays and breakers. The 67N relay offers an alternative to the 87N function. The 50/51 phase overcurrent relays provide transformer backup. Also note the redundant lockout relays (86), with the trip connections arranged such that complete protection is available even with a failure of one 86 relay or its dc feed.
Description Le g e n d Thermal CS Circuit Switcher Instantaneous & Time Rg Grounding Resistor Overcurrent Time Overcurrent Transformer Ground Time Overcurrent Bushing Neutr eutra al Time Time Ove Overc rcur urre rent nt N.C. .C. Norm ormally ally Clo Close sed d Groun d T im ime Ov Overcurr en ent OP Operatin g Co ilil Sudden Pressure Pol Polarizing Coil Directional O ve vercurrent Dire Direct ctio iona nall Grou Ground nd Over Overcu curr rren entt Lockout Auxiliary Pha Phase Diffe iffere rent ntia ial, l, 3 Phas Phase e Ground Di Differential
Table II (Ref. 1) Failure Statistics for
Two Time Periods
1955 - 1965 Description
1
1
Winding failures
2
Number
1975-1982 Typical Settings & Remarks
% of Total
Number
% of Total
134
51
615
51
Tap changer failures
49
19
231
19
3
Bushing failures
41
15
114
9
4
Terminal board failures
19
7
71
6
5
Core failures
7
3
24
2
6
Miscellaneous failures
12
5
72
13
262
100
1217
100
If such an installation involves local generation, frequency and voltage relays might also sense the islanding of the station. The 67 directional overcurrent relays respond to circulating load current through the 13 kV busses if the 115 kV breaker A opens. The 67 relays also provide backup for the 115 kV line relays, as well as backup for transformer-zone faults. This is in addition to the backup provided by the 50/51 relays. This example will be revisited after presenting some principles and concepts.
fuses blow, which can cause overheating of 3 phase motors. Also, fuses have a somewhat limited interrupting capability and provide less sensitive protection than that of a differential or ground relay. Fuses should not be employed on resistance-grounded systems, since they must carry the maximum load current and, therefore, cannot blow for low-current ground faults. Fuses are probably the predominant choice for transformers below 10 MVA.
4. Differential Relaying Differential relays sense the unbalance in the flow of currents in various apparatus or busses. In the absence of a fault in the protected zone, this unbalance tends to be small because the
Where a fused transformer uses a low-side circuit breaker, the breaker should be equipped with phase and ground overcurrent relays as backup of downstream devices. However, these relays will not respond to a transformer fault. 3. Protection Example Fig. 1 shows extensive use of relays representative of a large industrial load. There are two 115 kV feeds to 30 MVA transformers that are
FIGURE 2.
3
FIGURE 3.
flows into the zone are cancelled by the flows leaving. Accordingly, such relays can be more sensitive than phase overcurrent relays and need not be delayed to coordinate with other relays during external faults. The simplest implementation of differential protection merely parallels the CTs on all the connections to the zone, per Fig. 2. However, more sophisticated means are usually employed to provide faster, more sensitive and reliable schemes.
istic can be set from 15 to 60%. The relay becomes desensitized at the higher currents in order to remain secure in the presence of dissimilar CT performance. This creates false operating current. In contrast, the characteristic of the relay in Fig. 2 is a horizontal line. The restraint current can be derived in a number of ways. In the BE1-87T, the maximum of the input currents provides the restraint, yielding a consistent method regardless of the number of inputs. Up to 5 inputs per phase can be separately measured, depending upon the relay style. Transformers present differential relays with distinctive problems, which affect their design and application. These are: • Unequ Unequal al sec second ondary ary curr current ents, s, becau because se of the different turns ratios of the power transformer windings and the cts. • Phas Phase e shi shift ft of wyewye-de delt lta a ban banks ks.. • Tap Tap cha chang ngin ing g und under er load load.. • Magn agnetiz etizin ing g inr inrus ush h. • Unmea Unmeasu sured red groun grounded ded neu neutr tral al curre current nt..
Transformer differential relays utilize a restraint current in addition to the operating current of Fig. 2. This produces a percentage differential characteristic, by separately measuring the input currents, per Fig. 3. Fig. 4 shows such a characteristic for the BE1-87T phase-differential relay, where operating (or “differential”) current is plotted against the maximum (or larger) restraint current. The scaling is in “multiples of tap”. The ratio matching taps will be explained in the next section. The slope of the character-
4.1 Current Matching
FIGURE 4.
FIGURE 5.
The matching of unequal currents requires either auxiliary CTs or a means of scaling within the relay. Fig. 5 shows the use of taps on the relay windings to match a 2-to-1 difference in the levels of the CT secondary currents under nonfault conditions. For this difference the 10A current flows through just half the number of turns in restraint winding R1 as does the 5A current in restraint winding R2, so that the ampere-turns of the two windings are equal.
This tap position also connects to the midpoint of the operating winding, so that the net operating ampere-turns is zero. Thus, by ratio matching, the input currents are normalized and the operating signal is reduced to zero. Fig. 5 applies generally to electromechanical relays.
FIGURE 7.
FIGURE 6.
Fig. 6 shows the BE1-87T’s matching taps on the secondary of the relay’s input CTs. Rather than use an operating CT, this relay develops the operating signal electronically. The BE1-87T has a matching range of 2 to 8.9A in 0.1A steps. The taps are selected to be in proportion to the currents to be matched. Matching of three winding transformer applications must in effect be done two windings at a time, rather than assuming some arbitrary current distribution among the three windings. The procedure can be streamlined by assuming identical power in all three windings. While this is a physical impossibility, it allows proper current matching for all current distributions.
FIGURE 8.
need to connect the main CTs in delta. With wye CTs a ground relay also can be connected. A wye connection also reduces lead burden for a phase fault. The worst case is for a 3-phase fault with delta cts, per Fig. 8; the lead burden voltage is magnified to three times the 3 phasefault value with wye cts.
4.2 Phase Shift Compensation The phase shift developed in a wye-delta power transformer can be handled by connecting the CTs in wye on one side and in delta on the other side, per Fig. 7. The relay current input from the delta CTs is the phasor difference of two phase currents. The BE1-87T can perform this differencing electronically, preventing the
Note in Fig. 7 that the delta CTs are on the wyegrounded side of the transformer. The phase shift can be accommodated with the delta CTs on either side. However, it is essential to put the
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wye-side CTs is caused by zero-sequence current, the delta CTs filter out this unbalance in Fig. 10. There are two ways to form the CT delta. The connections must mirror those of the power transformer to provide the proper balance. 4.3 Tap Changing Under Load
FIGURE 9.
FIGURE 11.
FIGURE 10.
delta CTs on the wye side in order to prevent incorrect tripping for an external ground fault, shown in Fig. 9. Here, the delta CTs are on the wrong side. The three units of current flow entering from the grounded wye are not measured, so they produce an unbalance. (The delta-CT ratio is assumed to be 3/1 to provide balancing for phase faults.) In contrast, in Fig. 10 delta CTs on the wye side produce a balance. Since the unbalance on the primary of the
Current matching should occur for the condition where the load tap changer is in its neutral position. Then, the relay must accomodate the unbalance with the taps at the full boost or buck position. The percentage differential characteristic provides this accomodation, per Fig. 11. The “total mismatch” line represents the sum of the imperfect relay-tap match plus the power transformer tap contribution. The slope of this line is approximately the total % mismatch. The mismatch line is offset by the transformer exciting current, which produces its own unbalance. In the BE1-87T, available taps limit the maximum mismatch to 2.5%. Fig. 11 also shows the BE187T characteristics at the two extremes of slope setting (15 and 60%), as well as the related safety margins at the critical points. The relay characteristic contains the flat section in order to maintain good sensitivity for low-current faults where the load current is nonnegligible. The total current flowing is the pre-fault current plus the current produced by the fault. Accordingly, for small fault currents the load current introduces a significant restraint bias. 4.4 Magnetizing Inrush Inrush is the transient exciting current resulting from a sudden change in the exciting voltage.
This occurs at the instant of energization, the clearing of an external fault (recovery inrush) or during the inrush period of another transformer (sympathetic inrush). (Reference 4)
The unrestrained element responds to the operating or differential current and must be set to override the largest expected inrush pulses. It must also override similar pulses caused by dissimilar dc saturation of the CTs during high current external faults. For these reasons this element is set two orders of magnitude higher than the restrained element pickup.
Since inrush current appears as operating current to a differential relay, the relay must have sufficient delay and insensitivity to the distorted wave or take advantage of the inrush’s distinctive waveform by using harmonic restraint or some other form of pattern recognition. The second harmonic predominates in inrush currents (Reference 4) and is used in most transformer differential relays, either alone or in combination with other non-fundamental components. The relays restrain if the harmonic(s) exceed(s) a percentage of the fundamental component. Historically, this percentage has been fixed by design. Some newer designs provide for a user setting.
4.4.1 Energizing Inrush This transient results from remanence (residual flux) in the core. If the instantaneous voltage at energization calls for flux of the same polarity
Current transformer saturation also generates harmonics. Under symmetrical conditions, CT distortion produces only odd harmonics. Under assymetrical conditions CT distortion produces both even and odd harmonics. CT saturation under assymetrical conditions can delay a harmonically restrained element. Accordingly, an unrestrained element, set above the maximum inrush level complements the restrained unit. It is important to provide CTs with sufficient quality to provide good waveform long enough to allow either the restrained or unrestrained element operation.
FIGURE 13.
as the remanence, the core is driven into saturation, creating peak exciting currents that can exceed ten times rated peak. This compares with a normal steady-state exciting current of 0.01 to 0.02 times rated. Inrush current appears as relay operating current.
Reference 5 provides means to evaluate CT adequacy. Appendix I (page 19) of this guide provides an example of such an evaluation.
In Fig. 12 the steady-state flux at the instant of energization matches the residual flux, so no transient current flows. In contrast, in Fig. 13 the steady-state flux at energization is at its negative peak. Combined with a positive remanence, this condition produces the maximum level of transient current. The inrush current is actually much larger in relation to steady-state current ie than indicated by Fig. 13. Fig. 14 shows a typical inrush waveform. Note the “dead spot”, where almost no current is flowing as the core exits the saturated region.
FIGURE 12.
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4.5 Overexcitation
FIGURE 14.
However, this “dead spot” disappears on subsequent cycles because of CT saturation (Reference 5). In extreme cases the CT can saturate during the first cycle, eliminating the “dead spot”. The decay rate of successive primary-current peaks depends upon the amount of resistance in the source and the non-linear inductance of the transformer. In Fig. 14, the negative peaks are reduced further by CT saturation. The primary current peaks will not decay as fast as indicated by the CT output of Fig. 14. 4.4.2 Recovery Inrush A recovery inrush occurs at the clearing of an external fault as a result of the sudden increase in voltage from the depressed level during the fault. This voltage transient causes a flux transient, with accompanying abnormally high exciting current. The current level will be less than that of an energizing case. 4.4.3 Sympathetic Inrush Current Ip in Fig. 15 shows sympathetic inrush current in transformer T1, resulting from the energization of an adjacent transformer T2. The decaying dc component of current Ie flowing in T2 develops a drop in the source resistance Rs, producing pulses of inrush current Ip on the alternate half cycles. Note the delayed buildup of Ip. The severity of the sympathetic inrush is a function of the level of dc voltage drop across the source resistance. A common set of differential relays should not be used to protect both T1 and T2 transformers in Fig. 15 if they can be switched separately. The sum of the two transformer currents, Is, may not contain sufficient harmonics to restrain the relays once transformer T1 saturates severely.
FIGURE 15.
Overexcitation results from excessive voltage or below-normal frequency or a combination of the two such that the volts/Hz exceed rated. Fig. 16 shows three situations where overexcitation can occur: a unit-connected generator isolated from the system or a transformer connected on the open end of a long line. In addition, an interconnected system can experience a dynamic overvoltage following a protracted fault as a result of generator fields at ceiling or following load shedding. All of these scenarios involve essentially balanced conditions. Substantial phase-to-ground overvoltages can also occur on sound phases during a ground fault on impedance-grounded systems. In these cases delta windings or wye-ungrounded windings will not be overexcited, since the line-line voltages will not increase. The dashed curve in Fig. 17 illustrates the increase in transformer exciting current with increased excitation, resulting in thermal stress. This exciting current produces operating current in the differential relay, but an operation of this relay is not desirable, since immediate response is not necessary. For a dynamic overvoltage condition, the power system should be allowed time to correct itself. Also, a differential operation indicates a transformer failure, requiring unnecessary investigation and delayed restoration of the transformer. Accordingly, where sustained overexcitation is a concern, a separate volts/Hz relay should be applied (24).
104 to 138% of rated excitation. If the transformer is unloaded, as per Fig. 16(a) and (b), the relay operating current will be the exciting current less its third harmonic component; then, based on Fig. 17, the fifth harmonic content exceeds 35% over the range of about 104 to 138% of rated excitation. Should the transformer become faulted, the relay will operate if the fault current is sufficient to reduce the fifth harmonic component below the relay’s restraint level. Such a reduction occurs both because of the reduced excitation level and due to the fundamental-frequency fault current. FIGURE 16.
If the transformer is loaded (e.g. Fig. 16(c)), any mismatch current will reduce the fifth harmonic level of the operating current; the relay may not be restrained by the fifth harmonic. However, the transformer loading will reduce the overexcitation to a level where the operating current will be below pickup. For example, if the transformer is at 115% excitation, Fig. 17 indicates a magnetizing current of 3% (including 3rd harmonic); this plus mismatch current should be insufficient to operate a relay.
The solid curves of Fig. 17 illustrate the variation in harmonic content with voltage changes as a percentage of the fundamental value for a balanced excitation. The presence of a third harmonic component indicates that the wyegrounded winding was energized. When a delta winding is energized all triplen frequency currents (i.e. third, ninth, etc.) are blocked, because they are in phase on a fundamental basis. With a wye-delta bank, the CTs are connected in delta on the wye side (or the wye currents are electronically differenced). Thus, third harmonic component in the relay currents is cancelled. Accordingly, the lowest harmonic available to the relay for restraint is the fifth. The BE1-87T restrains if the fifth harmonic exceeds 35% of the fundamental. In Fig. 17, this relay will restrain over the voltage range of
With normal system connections the power system could be operated at 105% continuously and dynamically as high as about 115% during a severe disturbance. Under these conditions the third harmonic may be sufficient to restrain the relay; should the transformer become faulted, the fault current will swamp out the exciting current to allow the relay to trip. Voltages in excess of 138% can follow full-load rejection of hydro units. However, generator speed will be correspondingly high, so the volts/ Hz value will not significantly exceed normal. 4.6 Connection Examples Fig. 18 provides application examples for two-, three- and five-restraint cases. The relay derives restraint signals separately from each set of CT inputs. In Fig. 18(a) the relay protects a delta-wye transformer, with the CTs connected in delta on the wye-winding side. These CTs could be connected in wye when using a 3 phase style BE1-87T by selecting the electronic differencing option. This differencing option
FIGURE 17.
9
CTs must be connected in delta (or equivalent electronic differencing with a 3 phase relay), since the autotransformer is a zero-sequence current source. Otherwise, any current flowing in the transformer ground connection will unbalance the differential relay. This current is not measured and inputted to the relay. The relay Fig. 18(c) protects the combination of a bus and transformer. A transformer differential relay can be applied for bus or combination bus/transformer protection. CTs can be paralleled and connected to a common restraint input. Radial feeder CTs can be paralleled as long as the continuous rating of the relay winding is not exceeded. Source circuit CTs can also be paralleled, but it must be done judiciously. Fig. 19 shows the use of a tworestraint relay for the bus/transformer combination. Here four sets of source CTs are paralleled and connected to a common restraint winding R1. Such paralleling might produce a current in excess of the continuous rating of the restraint winding. Also, incorrect operation may occur during an external fault as illustrated in Fig. 19(a) and (b), where the faulted-circuit CT saturates severely. The secondary current on circuit 2 should be 70A, but is only 50A due to CT saturation. The CT deficiency of 20A causes the flow in restraint winding R1 and in the operating circuit. Since no current flows in R2, the relay is operating along the “single-feed line” in Fig. 19(b). This is an operating condition, even though the fault is external to the relay zone of protection. Paralleling of CTs on non-source circuits can be safe, within the thermal limitations of the relay. In this case there is no loss of restraint for external faults, since these circuits contribute no fault current. Again, source CTs can also be paralleled, but it must be done judiciously. For example, in Fig. 19(a), if CTs 1 and 2 were paralleled on R1 and CTs 3 and 4 on a third input R3, the 40A flow in R3 would be sufficient to prevent incorrect tripping if the relay is set with a 60% slope.
FIGURE 18.
duplicates the effect of a delta-CT connection. The operating signal is obtained by connecting the operating coil to measure the sum of the relay input currents or electronically as is the case in the BE1-87T. A three-input relay protects the autotransformer in Fig. 18(b). All
4.7 Phasing Example Fig. 20 shows a procedure for phasing the CT connections for a wye-delta transformer. There
10
A)
B)
FIGURE 20.
wye CTs (on the delta side) and to one side of the delta-connected CTs, as shown in Fig. 20(a). Step 2 is to show the currents flowing to the wye power transformer winding: Ia, Ib, Ic. Step 3 develops the currents flowing out of the delta power transformer winding—these depend upon the actual transformer delta connections. Step 4 shows the relay currents resulting from the wye CT primary currents which are determined from the polarities of the CTs. Step 5 duplicates the currents from step 4 and dictates
FIGURE 19.
are two ways to make the delta connection of the power transformer for either a 30 degree lead or lag. The delta CTs (or relay differencing) must compensate for this power transformer phase shift. The circled numbers in Fig. 20(a) represent the steps in the phasing process. The first step completes the relay connections to the
11
how the CT delta windings must be completed as shown in step 6 of Fig. 20(b). For example, in order to produce IA-IC in the direction shown, the non-polarity side of the phase “C” CT must connect to the phase “A” polarity side. With the delta CT connection, the relay currents on each phase are in phase. Any difference in magnitude is handled by selecting current taps approximately in proportion to the current input proportion. The delta CT connection also serves to filter any zero-sequence component from the relay. This component circulates in the CT delta, but does not appear in the relay.
overcurrent relay, shown as 87N-1 in Fig. 21. However, such protection must use a delay (e.g. 25 cycles) to ride through the false residual current resulting from the dissimilar performance of the phase CTs during a phase fault. The phase fault current can be 100 times the maximum level of current during a ground fault. Thus, it does not take much difference in the performance of the phase CTs to create a large false residual current. For the same reason, a percentage differential relay for the ground differential function can be insecure during external phase faults, since the neutral current contributes negligible restraint during phase faults.
4.8 Ground Differential With the 13.8kV bus tie normally closed in Fig. 1, either a ground differential or directional ground relay is needed. Otherwise, the neutral overcurrent relays on both both transformers transformers will operate for a 13.8kV winding or lead fault, resulting in an unnecessary interruption of the station.
FIGURE 21.
Where impedance grounding limits the ground fault current to levels below the sensitivity of the phase differential, this relay can be complemented with a separate ground differential relay. This can be a differentially-connected
The amount of current for a ground fault in the wye winding tends to be a function of the fault location in relation to the winding neutral. A good objective is to provide sufficient sensitivity to detect a fault 10% from the neutral end, where the current will be about 10% of the maximum current. In Fig. 21, the 20 ohm resistor limits the transformer ground current to about (13,800/1.73)/20= 400A for a lead or transformer terminal fault. A 10% fault, then, yields 40A primary and 0.67A in the secondary of the 300/5 neutral CT. This current is matched by the residual current from the 2000/5 CTs by the auxiliary CTs (ACT) with a step-up current ratio of 1 to 6.7A. The secondary burden on the ACT will be magnified by the square of the current ratio or 44 times. However, while the ohmic burden can be very high, the ground current level is limited by the grounding impedance. For example, a 0.5 ohm secondary burden reflects to a 22 ohm primary burden, but the maximum current is just 400/400= 1A for an external lineground fault, yielding a burden voltage on the 2000/5 CTs of 1*22= 22V. The 87N-1 relay pickup in Fig. 21 is set for 0.5A based on a neutral current contribution of 0.67A relay current for a ground fault 10% from the
neutral end of the wye winding. By comparison, the 87T phase differential relay sees the transformer contribution for a phase fault as 0.05A compared to a pickup of 0.7A. The 87T pick-up current is based on a high side tap setting of 2 and a relay pickup of 35% of tap. Other 13.8 kV ground sources, where available, will increase the level of relay current for an internal fault. However, the protection must cover the case with no added current contribution.
A wye connection for the 2000/5 CTs on the low side facilitates the auxiliary ct (ACT) connection. With the conventional delta connection of these CTs for a 3-phase 87T relay, 3 ACTs must be placed inside the delta, requiring the running of all six CT leads to the relay location. In Fig. 21, the BE1-87T relay (3 phase model) allows a wye connection with electronic differencing duplicating the phase shift otherwise provided by the delta CT connection. The 4.3A tap of the 87T on the low-side is selected as if the CTs were connected in delta. This tap matches the currents within 1%. Fig. 22 shows the development of false residual current by the phase CTs during an external “AB” fault due to dissimilar CT performance. The phase A CT performs well, but the phase B CT current of 28A is deficient by 2A. This deficiency appears as residual current and develops 13.3A in the 87N relay, producing 27 times pickup. Fig. 23 shows the application of a current polarized directional ground-overcurrent relay for the 87N-2 ground differential relay function. The polarizing winding of the directional element measures the neutral current, while the differential current supplies the directional element operating signal and the overcurrent signals. Fig. 23 shows that the auxiliary CT in the residual circuit over-mismatches the neutral current. For a 400A line-ground fault the differential current is 1.3A of the polarity to provide a bias in the non-trip direction, providing added security.
FIGURE 22.
The directional element provides security during multi-phase external faults, where dissimilar phase CT performance develops false residual current, as shown in Figure 22. Because the residual current is highly distorted and the wave form varies from cycle to cycle, directional operation is intermittent. Each time the directional element resets, it resets the timeovercurrent element. Accordingly, the overcurrent element delay can be set for a fraction of the fault duration.
FIGURE 23.
In Fig. 21 the transformation of the 40A low-side current to the high-side requires multiplication by the transformer turns ratio, rather than by the line-line voltage ratio. The per unit current on the delta side is 57.7% of the per unit current on the wye side for a line-ground fault on the wye side.
13
5. Turn-to-Turn Faults Phase differential relays may not detect a turnto-turn fault and ground differential relays do not respond to such faults. A neutral overcurrent relay will see fault current if an external ground source exists. However, for an impedance grounded system most of the fault current probably will be contributed by the delta-side source. A single turn fault may produce a total less than rated current (Reference 6). Accordingly, a sudden pressure relay (SPR) should be applied to complement the differential protection. The SPR will detect any abnormality that generates a sudden increase in pressure due to gas generation (e.g. arcing due to a loose connection). 6. Sudden-Pressure Relays (63)
A)
1. sudden gas pressure relay 2. transformer tank 3. insulating oil level 4. main port 5. bellows 6. gas cushion 7. snap switch 8. equalizer port
B)
FIGURE 24.
Fig. 24(a) shows a SPR that detects an increase in gas pressure, applied on gas-cushioned transformers of about 5 MVA and up. The gas pressure is generated by an arc under the oil, producing decomposition of the oil into gas products. The change in pressure actuates
bellows 5 closing microswitch contact 7. Equalizer port 8, much smaller than the main port 4, prevents bellows movement for slow changes in gas pressure due to ambient temperature changes and load cycling. Fig. 24(b) shows use of the break contact of the microswitch (63) in conjunction with auxiliary relay 63X. This circuit prevents tripping for a flashover of the make contact of 63. A design similar to that of Fig. 24(a) is mounted within the oil either in gas-cushioned or in conservator-type transformers. The SPR will respond only to arcs within the oil. While more sensitive than a differential relay, the SPR is not as fast as the electrical relay, so both relays should be applied. Because these relays have experienced a substantial number of undesired operations, many users connect them only to alarm. Their reliabililty has improved by installing them on stiffer sections of the tank and by blocking tripping for high current faults. During highcurrent external faults, winding movement generates an oil pressure wave which has a tendency to cause relay operation. In fact, there have been cases where a relay operation has been a precursor to transformer failure due to excessive winding movement. Conservator-type power transformers do not have a gas cushion within the main tank. Instead, the cushion resides in a separate auxiliary tank. A gas accumulator relay (“Bucholz”) can be installed in the pipe connecting the main and auxiliary tank to detect the generation of gas. This relay has two elements, an accumulator alarm and a trip function. The accumulator, which stores a portion of the gas, provides an alarm for slowly developing conditions. A baffle in the pipe actuates the trip element for relatively fast gas flow to the auxiliary tank.
7. Monitoring for Incipient Problems A number of on-line devices have been developed in recent years to detect incipient conditions which threaten serious consequences.
These include: gas-in-oil analysis, acoustic partial-discharge detection, moisture sensor, tap-changer-operation supervision and pump/fan supervision (Reference 8).
also should prevent operation during transformer energization. This element provides important fast backup of 87T for high-side faults. Because of its high pickup and slow operation, the time element provides poor protection for transformer winding and tap changer faults. Accordingly, this relay (and the ground overcurrent protection) is not a substitute for differential and gas relays except for transformers smaller than about 3 MVA. The consequences of a slow cleared fault include the threat of an oil fire due to a ruptured tank or bushing explosion and the necessity of having to remove the transformer for repair. Removal is generally necessary for even a fast cleared winding fault. This is not the case for a tapchanger flashover that is cleared before winding damage.
8. Overcurrent Relays Fig. 1 shows a number of overcurrent relays: 50/51, 51, 51N-1, 51N-2, 51N-3, 67 and 67N. With the possible exception of the 51 and 51N-3 relays, the overcurrent relays serve as back-up functions. 8.1 50/51 Relay The 50/51 phase relay time element in Fig. 1 (Page 2) must be set to carry the maximum expected load current. Since a transformer is capable of carrying considerable overload for a short period, a high pickup is normally called for (e.g. twice the forced-cooled rating). The time unit should coordinate with the 51 partialdifferential relay; otherwise, both transformers would be tripped for a fault faul t downstream from the 51 relay. In the absence of a low-side transformer or bus-tie overcurrent relay the high-side relay should be coordinated with the feeder or line protection. The use of partial-differential relays introduces an added coordination step. An alternative is to utilize bus-differential protection, although a failure of this type of protection will result in the loss of all feeders to the station. This is a low-probability scenario, particularly with metalclad switchgear.
8.2 51 Relay The partial differential relay 51 in Fig. 1 measures the sum of the transformer and bus-tie breaker currents. Such a connection is appropriate with a normally-closed bus-tie breaker, to avoid unwanted transformer breaker tripping for an adjacent bus fault. This relay serves as primary bus protection or backs up the bus differential protection. It also backs up for line or feeder faults. This relay must be set to coordinate with the feeder or line protection. It trips the transformer and bus-tie breakers. If the transformer and bus-tie breakers are interlocked to prevent both from being closed, a single set of overcurrent relays on the bus-tie breaker will suffice, rather than a set of partial differential relays on both busses.
The 50/51 operating time needs to be faster than the through-fault (external fault) withstand capability of the transformer (Reference 1, Appendix). Limits have been established for 4 MVA ranges, based on thermal and mechanical stresses. Fig. 25 illustrates both “frequent” and “infrequent” limits and recognizes the cumulative effect of these stresses. Feeder or line relay times should fall under the frequent curves, while the 50/51 times should fall under the infrequent curve. This is based upon the relative probability of these two classes of faults.
8.3 51N-1 Relay The 51N-1 relay in Fig. 1 provides sensitive back-up of 63 and 87T for high-side ground faults, but no response to turn-turn faults. The high-side ground overcurrent unit in the Fig. 1 application has no coordination requirement because the delta winding blocks ground current flow for a low-side fault. However, it must be delayed to ride through false residual current that can be developed during low-side phase faults (see Fig. 22).
The 50/51 instantaneous element should be set for about 160% of the current for a low-side 3 phase fault. This setting not only prevents incorrect operation for a low-side bus fault, but
15
8.4 51N-2 Relay The neutral overcurrent relay in Fig. 1 primarily backs up the 51N-3 partial differential protection for bus faults and it backs up 87N as well. In the absence of the 87N application, 51N-1 provides the primary ground fault protection for the transformer low-side zone. It also backs up 87T, depending upon the sensitivity of the 87T. The 51N-2 relay must coordinate with 51N-3 to allow the latter to clear a bus fault without tripping both transformers. If the 13.8kV bus tie can be closed with both transformers in service, as shown in Fig. 1, the 51N-2 relays on both transformers will operate for a 13.8kV winding or lead fault, unless a 67N or 87N relay is provided for faster clearing.
67N provides just marginal value, since 51N-2 backs up 87N. Because ground fault current is limited, the need for fast backup is less impelling. Relays 67N and 51N-2 offer an alternative to 87N. However, the advantage of the 87N 8 7N application is that it provides fast response with the low-side breaker open or with no external ground source. 9.0 49 Thermal Protection Conventional thermal relays measure the oil temperature and transformer current to estimate the hot-spot temperature. They provide an indication and means for controlling pumps and fans. Typically these devices provide two temperature sensing levels for control, and a third, higher temperature sensing for alarm or tripping.
8.5 51N-3 Relay Section 8.2 also applies to the 51N-3 relay except that this relay provides the ground fault coverage. 8.6 67 Relay The 67 relay operates for power flow from the transformer low side toward the high side. Such flow could occur with the 115 kV tie breaker open, either for a 115 kV fault or under load conditions. Reversed flow can also occur with the 115 kV tie breaker closed, with local generation. This relay will respond to high-side ground faults, because of the phase current flow (positive- and negative-sequence). This is valid only as long as a remote high-side ground source remains connected. 50/51 is the only other relay in Fig. 1 responsive to a high-side ground fault beyond the transformer high-side bushings. Because normal load flow is toward the low side, 67 can be set more sensitively than 50/51 and may also be faster. Relays associated with the 115kV breaker "A" will trip the high side circuit switcher. However, if the circuit switcher fails to open, the 67 relay tripping the circuit switches and the 13.8kV breaker "B" functions as backup to de-energize the circuit. 8.7 67N Relay The 67N relay serves as fast back-up protection for the 87N relay. Unless 87N is not applied,
Recently developed fiber-optic sensors, incorporated in the transformer winding, provide a direct method of measuring the hot-spot temperature. About four of these sensors would provide good coverage. References 1. ANSI/I ANSI/IEEE EEE C37. C37.91-1 91-1985, 985, IEEE Guide Guide for Protective Relay Applications to Power Transformers 2. Lewis Lewis Blackbu Blackburn, rn, “Pro “Protect tective ive Relay Relaying: ing: Principles and Applications”, Marcel Dekker, Inc. 1987 3. S. Horow Horowitz itz and and A. Phadke, Phadke, “Powe “Powerr System System Relaying”, John Wiley & Sons, Inc., 1992 4. W. K. K. Sonnem Sonnemann, ann, C.L. C.L. Wagner Wagner and and G.D. G.D. Rockefeller, “Magnetizing Inrush Phenomena in Transformer Banks”, AIEE Transactions, Vol. 77, pt. III, pp 884-892, Oct. 1958 5. IEEE IEEE Commit Committee tee Repor Report, t, “Trans “Transient ient ReResponse of Current Transformers”, IEEE Special Publication, 76CH1130-4PWR 6. Klingsho Klingshorn, rn, H.R. H.R. Moore, Moore, E.C. E.C. Wentz Wentz,, “Detection of Faults in Power Transformers”, AIEE Transactions, Vol. 76, pt. III, Apr. 1957, pp 87-98 7. ANSI/I ANSI/IEEE EEE C37.9 C37.95-1 5-1989 989 “IEEE “IEEE Guide Guide for Protective Relaying of Utility-Consumer Interconnections” 8. “On-Lin “On-Line e Transfor Transformer mer Monitor Monitoring, ing,”” Electrica Electricall World, Oct. 1995, pp. 19-26.
FIGURE 25.
17
Table I Relays and Typical Settings for 60 Hz Models ANSI No .
Qty. Basler Model/ De sc rip t io n Function
Ba sle r St yle No .
Figure No .
In v e rse :2.05 V / Hz Hz (107%), TD=2, Reset: 2s/ 2s/ % FS; Ala rm: rm : 2.26 V/ Hz(118% Hz(118%))
--
24
1
BE1-24 1-3.99 V / Hz Hz Overexcitation
49
1
Th e rm a l
50/ 5
3
BE1-50/ 51B 1 pha se overcurrent
0.5-15.9A., 0.5-15.9A., 1 ph . 1-99A inst.
50/ 50/ 51B 51B-1X -1XX
P.U. .U.: 9A; 9A; TD:2 D:2 (VI (VI); ); Instantaneous reset; 60A 60A insta insta ntane ous
51
3
BE1-50/ 51B partial differential
0.5-15.9A , 1 p h. h.
50/ 51 51B-1XX
P.U.: 9A ; TD: 1 ( VI); 1 Instantaneous reset; Dis Disc onne c t instanta instanta neo us
51N-1
1
BE1-50/ 51 51B ground overcurrent
0.1-3.18A , 1 p h. h.
50/ 51 51B-1XX
P.U.: 0.25A ; TD: 4 (VI); 1 Instantaneous reset; Dis Disc onne c t instanta instanta neo us
51N-2
1
BE1-50/ 51 51B Neutral overcurrent
0.1-3.18A , 1 p h. h.
50/ 51 51B-1XX
P.U.: 0.5A ; TD: 5 (V I); 1 Instantaneous reset; Dis Disc onne c t instanta instanta neo us
51N-3
1
BE1-50/ 51 51B 0.1-3.18A , 1 p h. h. Ground Ground pa rtial tial differential
50/ 51 51B-1XX
P.U.: 0.1A ; TD: 2 (V I) 1 Instantaneous reset; Dis Disc onne c t instanta instanta neo us
63
A C XF1XX0SXX
Typ ic a l Se tting tt ing s & Remarks
1
Su d d e n p re ssu re o r Buc holz Ga s Ac c um.
1
1,23
67
1
BE1-67 Ph a se Directional overcurrent
0.5-12A; inst. 1-40 1-40 time s; 3 p h.
B1XZ 1XZ2XX 2XX3C6X
TOC : 1A, 1A, 02 TD, B6 B6 (VI) (VI) Inst.: 15A
1
67 N
1
BE1-67N Directional overcurrent
0.25 0.25-6 -6A; A; d irec irec tiona l instant, 2-100A
A1XZ A1XZ2XX 2XX3CXX 3CXX
Inst. nst.:: Not c onnec ted TOC:1 0.25A, 01 TD, TD, B3 (De f.)
86-1/ 86-2
2
Lo c ko u t A u x.
87N-1
1
BE1-50/ 51 51M
0.1-3.18A TO C 0.2-19.8A inst.
BE1-50/ 51M-2 M-2
Inst. nst.:: not not c onnected TOC: 0.5A, 2 TD, D (Def.)
20
87N-2
1
BE-67N Ground differential
0.25-6A TO TO C ; 2-100A dir. inst.
A1XZ A1XZ2XX 2XX3CXX 3CXX
Inst: nst: 2A, 2A, p olar. p.u.: p.u.: 2A; TOC: 0.25A, 07 TD, B1(Short)
1,22
87T
3
BE-87T Tran sfo rme r differential
2-8.9A , 3 p ha ha se se
E1EA 1X 1XX1XXX
Se e Se tt tt in g se se c ti tio n o f IM
1,17,2
1
Appendix I: Time to Ct Saturation For the application in Fig. 1, assume a high-side, wye-connected, multiratio 600/5 CT on the 300/5 tap and an ANSI accuracy class of C200. The unrestrained element pickup is 22A on the secondary of the 300/5 CTs. The maximum time constant of the fault current is 0.02s. Two way lead burden (for ground fault) and CT winding resistance is 0.4 ohms. Assume an internal fault producing 33A, which is 150% of pickup. Ks = (ct knee pt. voltage)/(burden voltage) = (0.6*Effective Accuracy Class)/(22*1.5*0.4) = (0.6*200*300/600)/13.2 = 60/13.2 = 4.5
FIGURE I-1.
[The effective accuracy class voltage is 100V, since only half the total CT turns are in use. The knee point is at about 0.6 times the effective accuracy class. Checking at 1.5 times the unrestrained unit pickup.] FIGURE I-2.
From Fig. I-1 (Reference 5), the time to saturation is 13ms (3/4 cycle). This applies for a fully offset current of 33A rms symmetrical and assumes the CT saturates at the knee point, a somewhat conservative assumption. This result indicates marginally acceptable CT performance. Fig. I-2 shows CT waveform similar to that expected for the above example, although the dc time constant is much longer in Fig. I-2 than the assumed 0.02s. Note that the CT delivers considerable energy even after onset of severe saturation, including the negative excursions. At higher levels of current the CT will saturate sooner; however, the negative excursions, during which interval the CT recovers from saturation, produce increased energy. Fast response depends upon the relay’s reaction to this distorted waveform. Use of a higher CT ratio will improve ct performance, but the reduced current levels will result in desensitizing the unrestrained element unless the relay taps are lowered in proportion to the drop in secondary current level.
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Appendix II: Harmonics During Ct Saturation CTs experience both “ac” and “dc” saturation. Ac saturation results under symmetrical current conditions. Dc saturation occurs when the current contains a “dc” component, during a fault, magnetizing inrush, motor starting or generator synchronizing. CTs that produce negligible distortion under symmetrical conditions can become severely distorted when a dc component exists (Reference 5). While faults generally produce the most current, other conditions such as a motor starting produce much slower dc decay than occurs for a fault. A smaller dc current that persists longer can also produce dc saturation. For these external disturbances, unequal times to saturation in various CTs results in false operating current. Either the harmonic-restraint or the percentage differential restraint (fundamental frequency characteristic) prevents unwanted tripping for this condition. Under symmetrical current conditions, CT distortion generates odd harmonics, but no even harmonics. A CT experiencing dc saturation during an assymetrical fault develops both even and odd harmonics. Relays that restrain on odd harmonics may fail to operate if the harmonic content exceeds the relays’ threshold for restraint. Relays that restrain on just even harmonics may be temporarily restrained until the CTs recover from the effects of the dc transient. High-set unrestrained elements (instantaneous) supplement the restrained elements, so that high current faults, where CT saturtion can be severe, can be cleared independent of any harmonic restraint. These elements must be set above the maximum inrush level and above the maximum false operating current produced by dissimilar ct performance during external faults. For satisfactory protection, harmonic generation by the cts should not exceed the restraint level for a current below the unrestrained element pickup. Poor CT quality can materially detract from the reliability of the differential relay. A good objective is Ks=8 or higher for a current at
the unrestrained pickup level (see Appendix I). Ks is the ratio of the CT knee-point voltage to the burden voltage. The higher the Ks value, the better the CT performance.
Revised 8/03 If you have any questions or need additional information, please contact Basler Electric Company. Our web site is located at: http://www.basler.com e-mail:
[email protected]
Basler Electric Headquarters Route 143, Box 269, Highland Illinois USA 62249 Phone 618/654-2341 Fax 618-654-2351
Basler Electric International P.A.E. Les Pins, 67319 Wasselonne Cedex FRANCE Phone (33-3-88) 87-1010 Fax (33-3-88) 87-0808
