REDUCING TRIPPING TIMES IN MEDIUM VOLTAGE SWITCHGEAR

Abstract Traditional coordination time intervals (CTI) between successive levels of protection in a main-tie-main (MTM) configuration have been about 0.25 to 0.3 seconds. When several layers of coordination must be accommodated, the backup clearing times can be excessively long. However, a variety of approaches may be used to reduce overall backup coordination times. When coordination time improves, there may also be significant impacts on total clearing time, arc flash incident energy, voltage regulation, motor dropouts and system integrity. This paper compares three approaches to reducing the maximum total clearing time in a typical MTM configuration including:

Setting group change(s) with feedback from the tie breaker position

Use of high-speed relay-to-relay communications to quickly isolate fault locations

Use of an electronically triggered fault current limiter (ET-FCL) to limit available fault current

Index Terms - fault current limiter (FCL), main-tie-main

(MTM), short circuit capacity (SCC), coordination time interval (CTI), Generic Object Oriented Substation Event (GOOSE)

I. INTRODUCTION

Three methods of improving backup coordination times are discussed in this paper. For comparison purposes, each method is based on the simple MTM layout shown in Figure 1.

A

B

C C

A

Utility A Utility B

Bus A Bus B

Fig. 1 Base MTM layout

Even if this layout is operated with the tie breaker normally open, a failure of either transformer will require that tie breaker be closed so that the loads served by each feeder breaker may be served from the remaining transformer. Therefore, as a general case, the coordination path is A-B-C. In other words, the main breaker relay C must be coordinated with the tie breaker relay B which in turn must be coordinated with the feeder breaker relay A. The minimum time difference between curves is referred to as the CTI (coordination time interval) and is typically in the range of 0.25 to 0.3 seconds. The sketch in Figure 2 shows these time-current coordination curve relationships.

Fig. 2 Typical MTM time-current coordination

For purposes of comparison, a CTI interval of 0.3 seconds will be assumed throughout the remainder of this paper. It is also assumed that there are no significant sources of fault current downstream from the main buses. In other words, fault current cannot flow upstream. Assuming the fastest operating time of Relay A is 2 cycles or about 0.033 seconds, the CTI interval dictates a minimum operating time for Relay B at 0.33 seconds and a minimum operating time for Relay C at 0.63 seconds.

Robert A. Wilson, P.E. Raymond E. Catlett, P.E. Senior Member, IEEE Senior Member, IEEE ABB Inc. ABB Inc. 123 Capri St. 8 Driftwood St. Sugar Land, TX 77478 Collinsville, IL 62234 bob.a.wilson@us.abb.com ray.catlett@us.abb.com

II. TIE BREAKER POSITION FEEDBACK

Improving overall relay operating times is most easily accomplished with the aid of relay-to-relay communications. Such communication may be accomplished via hardwire connections between critical devices or via a common communication protocol. One of the simplest ways to improve coordination times in a MTM layout is to communicate the position of the tie breaker to the relays at C as illustrated in Figure 3.

Fig. 3 Tie breaker position feedback to relays at C In the base example (Figure 1), when the tie breaker is closed, relay C must be coordinated with relay B which in turn must be coordinated with relay A. On a typical log-log coordination plot, the curves would be stacked as C-B-A top to bottom as in Figure 2. If the tie breaker is open, there is no need for relay C to be coordinated with relay B (tie breaker). It is only necessary to coordinate relay C with relay A. The coordination plot curves become C-A as illustrated in Figure 4.

Fig. 4 Coordination time curves for open tie breaker layout

Modern microprocessor relays typically have multiple setting groups available. With knowledge of the tie breaker position at relay C, the settings can be easily changed by changing the active setting group. This information can be passed using hardwire connections from the tie breaker 52b auxiliary contact to initiate the setting group change. When the tie breaker is open, the 52b contact applies a voltage to an input on relay C to initiate a switch from active group #1 to active group #2. This change moves the time-current curve to the position previously occupied by relay B as shown in Figure 4. Alternatively, for relays that are IEC61850 compliant, the breaker position information may be passed from relay B to relays C via GOOSE messaging to accomplish the same goal. IEC61850 GOOSE messaging offers additional advantages including being able to transfer signal quality without extra connections. For example, suppose both 52a and 52b contacts are connected to relay B. One could confidently determine the position of the tie breaker if 52a is closed and 52b is open or visa versa. However, if both 52a and 52b are in the same position, the actual position of the tie breaker is indeterminate. This could easily happen if one of the auxiliary contacts is dirty and does not make a good electrical connection when closed. In this case, the quality of the data being sent is declared to be bad. The GOOSE message quality attribute may be passed along with the signal itself. In order to switch setting groups, the data point indicating the tie breaker position should indicate open and the quality of the data point should be good. If both conditions are not met, the switch to the faster setting group #2 should not be made. Another advantage of GOOSE messaging is accomplished via constant monitoring of communications from the sending relay B to the receiving relays C. If communications is interrupted, a communications timeout error is generated and a GOOSE error is issued at relays C. The communication timeout will also cause the validity of the data to be declared bad. Although speed of signal transfer is not particularly critical in this example, GOOSE messaging has also been shown to be faster than hardwire connections due primarily to the filtering time and processing time associated with signals over hard wire. Binary GOOSE message transfer times can be as little as 3ms which is less than one quarter of a cycle. Figure 5 shows the logic of a GOOSE logic implementation on one manufacturers relay C. Setting group 2 is activated only if all of the following conditions are met:

Tie breaker is open (POS_OP signal asserted) Validity output is asserted (52a and 52b are

consistent with each other and GOOSE communication has not timed out)

GOOSE communications status is good

Fig. 5 Setting group 2 activation logic

Advantages of this approach include:

Simple, can be implemented with hardwires Disadvantages include:

Coordination improvement is limited to operation under open-tie conditions

III. FAULT LOCATION FEEDBACK

The previous example shows how communication may be used to change setting groups and thereby reduce tripping times at relay C. Reduced tripping times at all relays can be achieved when additional information is transferred. This scheme uses a separate set of phase and ground 50D (definite time) elements at relays B and C operating in parallel with the existing conventional time-overcurrent (TOC) elements. The 50D elements are set at the lowest pickup value of the feeder relays and at a time delay setting of 0.1 seconds or perhaps a bit shorter (discussed later). With these settings, the phase and ground 50D elements will be much faster than their corresponding TOC elements. They can be allowed to operate only if the fault is known to be in their primary protection zone. The 50D elements must be blocked when any downstream relay senses the fault since that implies a fault within a downstream zone. Consequently, the pickup (aka start) status of downstream relays must be communicated upstream to block any upstream 50D elements that would otherwise trip. For example, consider the MTM example in Figure 6. If any overcurrent element picks up (starts timing), that information is sent to each upstream relay as a blocking signal. If relay B or relay C receives a blocking signal, its 50D elements are blocked from operating because the fault is beyond its protection zone. As long as one or more downstream relays are in pickup mode, all upstream 50D elements in each of the upstream relays are blocked. If any 50D element times out without receiving a blocking signal, it is allowed to trip.

Fig. 6 Pickup signal communication using hardwires

The time delay in the 50D elements must be set no less than the maximum time required to receive blocking signals from the downstream relays. If this scheme is implemented with hardwire connections between relays, a delay time of 10 - 15 cycles is probably appropriate. If implemented with GOOSE messaging, a delay time of 15 - 30 milliseconds is possible depending on the manufacturers GOOSE implementation. The base MTM layout used in these examples is quite simple and is intended only to compare the three approaches described in this paper. Typical MTM layouts have several feeders on each bus. Implementing this scheme with several feeders quickly becomes impractical if a hardwire implementation is used. The number of wire pairs is equal to the number of relay combinations in the layout. Even for this simple MTM layout, the number of wire pairs would be cumbersome. Moreover, each wire and wire connection represents an additional failure point that is not normally monitored for integrity, impacting the overall reliability of scheme. GOOSE messaging accomplishes the same goal but with far fewer physical connections. GOOSE messages are based on a publisher-subscriber basis where the publisher is the sender of data and the subscriber is the receiver of the data. Figure 7 shows the equivalent GOOSE based layout.

Fig. 7 Pickup signal communication using GOOSE messages

GOOSE communication requires a single Ethernet connection between each relay and a common Ethernet switch. Signals are routed from the publisher through the Ethernet Switch to the subscriber. Per IEC 61850-5 Standards, Class P1 (distribution) point-to-point communication time for high speed applications is 10ms [1]. Consequently, a delay time of 1 cycle should be sufficient to allow receipt of a blocking signal from the downstream relay(s). Some relay manufacturers even meet the Class P2/3 (transmission) requirement of

The operating times for the IEC61850 GOOSE based scheme are constant. The GOOSE based scheme has an estimated tripping time of 2.5 cycles or 0.04 seconds. Overall tripping times are only slightly slower than dedicated differential protection zones. This example is based on the simplest of MTM schemes. Additional protection layers above level C could be added without affecting the overall operating times within the GOOSE network. Advantages of the GOOSE messaging implementation include:

Communications are typically faster than hardwire[1] Communications channels are continuously

monitored[2] For practical numbers of relays and communications

signals, the effects on point-to-point delay times are small [2]

Most applications require fewer relay-to-relay connections

GOOSE messages are repeated automatically to improve reliability of signal transfer

Disadvantages of GOOSE messaging include:

Some additional relay programming required to configure the GOOSE messages (virtual relay-to-relay wiring

Communications between different manufacturers, while possible, adds complexity

Adding feeders requires downloading new GOOSE configurations to all receiving relays in the network

IV. LIMITING FAULT CURRENT

An Electronically Triggered Fault Current Limiter (ET-FCL) operates much like a sub-cycle switch. It consists of electronics that initiate a pyrotechnic device that literally blows the current carrying conductor apart within an explosion proof canister once the threshold current setting is exceeded [4]. The electronics determine the rate-of-rise characteristics of the fault and predict whether the root-mean-square (rms) value of the threshold setting will be exceeded. If so, the electronics triggers the pyrotechnic device, opening the circuit. The ET-FCL detection and peak fault wave limitation time is about 0.6ms, much faster than most relays can detect that a fault has occurred. Consider the simple MTM layout again. Assume that each transformer has similar impedances and the available three-phase bolted fault current on the load side is 25kA as shown in Figure 9. Then, due to the symmetrical layout of the system, the total fault current will be divided approximately evenly between the two transformers.

Fig. 9 Using an ET-FCL to limit fault current If the ET-FCL with a threshold setting of 12kA is inserted in series with the tie breaker, the two buses will be separated when the ET-FCL senses current above 12kA. Complete separation occurs within 1ms, too fast for the other relays to detect a problem. Consequently, Relay C only needs to be coordinated with relay B up to the ET-FCL setting of 12kA, not the previous 25kA. Above 12kA, the two halves are isolated and relay C only needs to coordinate A. The curve C shape may be adjusted (lower time dial) because the CTI spacing between C and B is no longer relevant above this threshold value of current. Figure 10 shows how this improvement is realized.

CURRENT

TIME

CTICTI

12kA

B

A

C

CTI

C

Relay C characteristics move from C to C

Fig. 10 Coordination improvements with a Fault Current Limiter Advantages of this approach include:

No communication between relays is required Fault current is truly limited with no appreciable effect

on regulation Switchgear upgrades may be postponed if additional

loads are installed As ET-FCL threshold settings are lowered, faster

time dials may be applied to upstream relays

Arc flash incident energy reduction Inter-bus immunity during faults

Disadvantages include:

ET-FCL cost and the cost of consumables Inability to fully test the ET- FCL (partial test only)

V. CONCLUSIONS

Three different methods for reducing coordination time in a simple MTM scheme have been discussed. The simplest uses feedback from the tie breaker position to dynamically change setting groups. The second uses high-speed Ethernet communications to determine fault location, thereby eliminating the normal time coordination of relays. The third approach uses a fault current limiter to separate the buses during heavy faults. Each has advantages and disadvantages. The best improvements come from sharing information between relays. The additional information makes it possible to locate the faulted segment within a few milliseconds, eliminating the need for conventional time coordination. An IEC61850 based protection scheme that shares overcurrent pickup status with upstream relays provides results in the fastest clearing times with minimal additional investment in hardware.

VI. REFERENCES

1. International Standard IEC 61850-5, First edition 2003-07

2. Hakala-Ranta, Antii, et al.,Utilizing Possibilities of IEC 61850 and GOOSE, CIRED 2009, Paper 0741

3. Feeder Protection and Control, REF620 ANSI, Product Guide, ABB 1MAC506635, PG Rev. A, October 2012

4. Catlett, Ray, et al.,Improving Relay Protection Levels in Medium Voltage Switchgear, 2012 IEEE PCIC Conference

VII. BIOGRAPHIES

Robert Wilson received his BSEE degree from Purdue University and his MSEE degree from Carnegie Mellon University where his focus was on power engineering. He is currently employed by ABB Inc. as a Regional Technical Manager in Sugar Land, Texas for ABBs Substation Automation and Protection Division covering the South Central United States. He has authored several technical papers on the subject of optical arc flash protection. He is a senior member of IEEE and a registered professional engineer in the states of Pennsylvania and Texas. Ray Catlett received his BSEE degree from University of Missouri-Rolla and a Masters Engineering Management from Washington University where his focus was technology assessment and innovation. He has been employed with ABB since 2000 in many roles, presently a

Senior Technical Consultant. He has more than 30 years of design, analysis and consulting experience in power systems and has co-authored previous PCIC papers. He is a senior member of IEEE and a registered professional engineer in the states of Missouri and Texas.

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