Shifting Transformers Damage Curves for Through-Fault Current Protection
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The purpose of this guide is to establish the rationale for shifting equipment damage curves based on winding connection when evaluating transformer through-fault current protection.
ANSI Ø Shifts and Winding Connections
The ANSI standards specify that transformers connected Δ-Δ or Y-Y shall have a phase shift of 0º. Transformers connected Δ-Y or Y-Δ shall have a phase shift of 30º, and the low-voltage winding shall always lag the high-voltage winding.
Table 1 summarizes the winding connections covered in this guide. The last connection covers the neutral ground resistor (NGR) case common to industrial plants with MV distribution systems serving rotating equipment.
|Through-Fault Current Protection
Engineers must consider all possible fault scenarios on the secondary-side of the transformer in order to evaluate the level of through-fault current protection provided by a primary-side fuse, relay or circuit breaker. On a three-phase power system this would include; three-phase fault, single-line-to-ground fault, line-to-line fault and line-to-line-to-ground fault. It is common practice to view current distributions in per unit on the three-phase fault current base seen by the primary-side protective device.
Three-Phase (3Ø) Secondary Fault
The primary-side relays would each see 1.0 A p.u. fault current on a 3-Ø primary fault current base, figure 1.
|Single-Line-to-Ground (SLG) Secondary Fault
The primary-side phase A and C relays would see 0.58 A p.u. fault current on a 3-Ø primary fault current base, figure 2.
|Line-to-Line (LL) Secondary Fault
The primary-side phase A and C relays would see 0.50 A p.u. fault current and the phase B relay would see 1.0 A p.u. fault current on a 3-Ø primary fault current base, figure 3.
|Line-to-Line-Ground (LLG) Secondary Fault
The primary-side phase A and C relays would see 0.58 A p.u. fault current and the phase B relay would see 1.0 A p.u. fault current on a 3-Ø primary fault current base, figure 4.
|Transformer secondaries were faulted and primary currents were calculated for each fault type and summarized in Table 2 for winding configurations listed in Table 1.|
|Table 2 Fault Current Summary Table|
|1. Shifting of the damage curve is dependent upon the amp rating of the NGR relative to the transformer primary-side FLA. Shifting is To Be Determined by the engineer on a case by case basis. For a sample case study see Example 3.
Plot the damage curve and set a primary-side 50/51 relay to protect a 1000kVA, 65ºC, 4160-480/277V, Δ-YG, oil-filled, substation transformer with an impedance of 6.0%.
Consider secondary 3-Ø faults only when setting the primary-side 50/51 relay to protect the transformer during through-faults.
The protection is met based on the criteria given, see Figure 5.
Now examine the protection provided by the 50/51 relay shown in figure 1 for faults of all types using Table 1. For a secondary LL fault the primary relays in phases A and C would only see 50% of the fault current they would otherwise see for a 3-Ø fault. This is not a problem though because the B-phase relay would see 100% current, and the transformer would be protected.
The LLG fault is similar to the LL fault accept that the relays in phases A and C would see 58% current. But again the B-phase relay would see 100% current, so the transformer would be protected.
However for the SLG fault case, the A and C-phase relays would see 58% current with no current flowing in the B-phase! In order to evaluate the through-fault current protection afforded by the relays for a secondary SLG fault, the damage curve of Figure 5 would have to be shifted 58% to the left. It is common practice to show both damage curves on the TCC. After shifting it becomes apparent that the original relay settings are inadequate, see Figure 6.
Repeat Example 1 but now consider secondary faults of all types when setting the primary-side 50/51 relay to protect the transformer during through-faults.
The protection is met based on the criteria given, see Figure 7.
|Fig. 5 Example 1 Though-Fault Current Protection (3-Ø Fault Only)|
|Fig. 6 Example 1 Though-Fault Current Protection (All Faults)|
|Fig. 7 Example 2 Though-Fault Current Protection (All Faults)|
Consider the case of a 5000kVA, 65ºC, 13800-4160/2400V, Δ-YG, oil-filled, substation transformer with an impedance of 6.0%. The secondary neutral terminal is grounded through a 400A NGR.
Step 1 – Determine the primary FLA
FLA PRI = 5000kVA / (1.732 x 13.8kV) = 209A
Step 2 – Determine the primary-side current distribution for a secondary-side SLG fault
I SLG SEC = 400 amps
I FAULT PRI = 0.58 x 400 amps (4160V / 13800V) = 69 amps
Step 3 – Determine the relationship between I FAULT PRI and FLA PRI
I FAULT PRI = 69 < FLA PRI = 209A
|• No shifting is required, see Figure 8.
• The relay is not capable of distinguishing between a secondary-side SLG fault and an increase in load
• In this case it is common practice to protect the transformer using a 51G relay fed from a current transformer mounted in the secondary neutral bushing.
• If the transformer protection system includes a 51G relay there is no need to perform this calculation.
|Fig. 8 Example 3 Though-Fault Current Protection (Δ-YRG)|
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The latest revision of:
• EEE Std C57.12.00, IEEE Standard General Requirements for Liquid-Immersed Distribution, Power and Regulating Transformers
• IEEE Std C57.12.01, IEEE Standard General Requirements for Dry-Type Distribution and Power Transformers Including Those with Solid-Cast and/or Resin-Encapsulated Windings
• IEEE Std C37.91, IEEE Guide for Protective Relay Applications to Power Transformers
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