Fundamentals of MV Transformer Protection Using Relays
Currently a Masters Student at Washington State University, author has worked on multiple protection-coordination projects in his career.
Transformers are at the heart of the electricity distribution infrastructure and their protection is critical to its safe and reliable operation.
This article serves as a first hand application reference for implementing reliable protection on medium-voltage distribution transformers (11 kV - 33 kV) through commonly available microprocessor MV relays (Siemens, Schneider and GE).
The protection philosophy incorporates three broad steps:
- Take an understanding of the protection functions required for transformer protection.
- Plot a Time Current Characteristic (TCC) curve for those functions.
- Set the relay parameters to follow the plotted TCC curves.
MiCom relays protecting dry-type transformers in a typical building substation
Protection Functions Required for MV Transformers
The eight essential protection functions required for transformer protection are listed in the table below. The 50G/P and 51G/P functions are required on both the HV and LV sides. The LV side protection may utilize a low voltage power circuit breaker (LVPCB) instead of a relay fed from the secondary side CTs.
| Protection Function | Description |
|---|---|
50P | Phase Instantaneous Overcurrent |
51P | Phase Time Overcurrent |
50G | Ground Instantaneous Overcurrent |
51G | Ground Time Overcurrent |
49 | Thermal Overload |
87 | Differential Protection (for transformers >10 MVA) |
Second Harmonic Resraint | Restrains relay operation when second harmonic content is detected in current. |
Event Recorder | Fault event recorder |
The protection schematics demonstrate these essential protection functions as they are conventionally used for transformer protection. The 87 - differential protection is conveniently not used for transformers rated less then 10 MVA to reduce system costs and avoid adding extra complexity.
Protection schematic for a typical 11 kV / 400 V transformer rated less then 10 MVA.
Protection schematic for a typical transformer rated above 10 MVA.
Plotting the TCC Curve for Transformer Protection
To begin applying the aforementioned protection functions on a typical transformer, we first need to plot the TCC curve. To begin plotting the TCC curve of the transformer, understanding of the following cornerstones is required.
Transformer Full Load Amperes (FLA): Rated continuous current carrying capacity of a transformer at a referenced ambient
temperature.Transformer Inrush Current: The magnetizing inrush current a transformer draws when it is energized.
Transformer Damage Curve: The thermal and mechanical limit of operation of the transformer. Beyond this limit the transformer suffers permanent damage.
Next, a calculation of the above three is required.
Transformer Full Load Amperes (FLA): This is the Rated MVA divided by the product of voltage and sqrt(3). e.g for a transformer rated 3.5 MVA @ 11 kV pri, FLA = 3.5 MVA / 11 kV x 1.732 = 183 Amps
Transformer Inrush Current: This is usually taken as 8 or 12 times the FLA and is plotted at 0.12 seconds (06 AC cycles) on the TCC plot. e.g for a transformer rated 3.5 MVA @ 11 kV pri, Inrush = 8 x 183 = 1,464 Amps.
Transformer Damage Curve: Plotted according to the standard guidelines of IEEE C57.109-1993 for liquid-immersed transformers and IEEE C57.12.59-2001 for dry-type transformers.
A transformer operating zone is to defined thereafter.
- Right side of the transformer damage curve is the equipment damage area.
- Left side of the FLA and Inrush Point is the equipment operating area.
- The TCC is placed in between these two areas as follows.
Operating and Damage areas for a typical dry type transformer rated 3.5 MVA @ 11kV.
The actual TCC curve is then placed in between the operating and damage areas, above the FLA and inrush points and below the transformer damage curve. The exact position and characteristic of the curve is dependent on coordination with other upstream and downstream devices which is beyond the scope of this article.
Transformer TCC curve for 50P and 51P functions.
Configuring Relays for Transformer Protection
Once you know the protection functions and have plotted the TCC curve, this curve now needs to be programmed into the microprocessor relay for the protection functions to work as desired.
Microprocessor relays require certain parameters to be fed into their registers via proprietary software that are unique to the manufacturer of the relay, so that they can accurately mimic the plotted TCC curves.
From an assessment of typical relays of market leading manufactures, such as Siemens Siprotec® 7SJ602 series, Schneider Electric's Sepam® series and GE Multilin® series, we have picked out the parameters that you should know, along with their calculation guidelines, in order to precisely mimic the TCC plot of your choice into the relay.
You should note that the exact determination of protection parameters to be fed into relays requires a protection-coordination study from a licensed consultant, that can evaluate relay coordination with upstream and downstream devices. Without a study, these parameters are based on estimates and thumb rules.
Relay Parameters for 50P/51P - Instantaneous and Time Overcurrent Function
We will now show you how you can mimic our example TCC curve shown above in a microprocessor relay.
| Relay Parameter | Calculation Guideline |
|---|---|
Characterstic Curve | May be selected from Very Inverse, Extremely Inverse and Standard Inverse characterstics. |
Pick Up Value | Usually 80 - 120 % of the transformer FLA (183 A), for the example case, it is 232 Amps. This is the vertical asymptote of the TCC. |
Time Delay | A suitable time delay is required to establish coordination with other devices. Some relays require a value of time that corresponds to 10 x Pickup Value on TCC curve to be inserted as this parameter. 0.12 s for the eample TCC. |
Instantaneous Pick-Up Value | This is the verticle asymptote of the definite-time curve, usually represents the lower right portion of the TCC plot. Its value is set below the single phase fault current. For example TCC, it is 3120 A. |
Instantaneous Time Delay | The horizontal asymptote of the definite-time curve. A suitable delay is required for coordination with other devices. In our example TCC, it is 0.5 s. |
Parameters required for 50P/51P fault function configuration by the GE's Multilin® relays. Pickup, Time delay and Choice of Characteristic Curve are highlighted.
Relay Parameters for 50G/51G - Instantaneous and Time Ground Overcurrent Function
The required parameters for 50G/51G functions follow the same recommendations as 50P/51P functions with the exception that the pickup value is set at approximately half of the value set for Phase Over-current and the instantaneous pickup value is set below the phase to ground fault levels.
Parameters required for 50G/51G fault function configuration by the Siemens' Siprotec® relays. Pickup, Time delay and Choice of Characteristic Curve are highlighted for both the definite-time (50G) and Inverse-time (51G) functions.
Harmonic Restraint
The harmonic restraint function prevents the relay from tripping when transformers are energized.
At the energization of the transformers a large magnitude of magnetizing inrush current flows, which contains a significant second harmonic content. The relay can mistakenly take this zero sequence current from harmonics as a fault current and trip on earth fault, if harmonic restraint is not enabled, however when enabled, the relay can correctly recognize this second harmonic current as an energization event and restrain the relay from tripping.
The harmonic restraint function should be 'enabled' whenever the relay is used for transformer protection.
Parameters required for 50G/51G fault function configuration by the Schneider Electric's Sepam® relays. The Harmonic Restraint parameter is highlighted.
Relay Configuration for 49 - Thermal Overload Function
The 49 - thermal overload function is utilized as a temperature trip for the transformer. A resistor temperature detector or thermistor may be inserted in each of the three phase winding coils of the transformer (dry type transformers are usually manufactured with temperature trips) and the output of those thermistors may be monitored by an external temperature control unit or may be dropped at the digital inputs of the relays. Digital I/Os can then be configured to give a logical trip command to the relay. Most modern numerical relays have multiple digital inputs and outputs to implement logic functions.
Typical temperature control units will operate the cooling fans at a fixed set-point and then trip the relay if winding temperature rises further. The set-point is usually programmed during commissioning.
Typical temperature control unit for a dry-type transformer.
Event Recorder
Event recorders record the fault events as they occur, they should also be enabled for all protection functions.
References
- IEEE Std C37.91 - 2000, Guide for Protective Relaying of Power Transformers.
- IEEE Buff Book, Std 242 - 2001, Protection and Coordination of Industrial and Commercial Power Systems.
- J. L. Blackburn, T. J. Domin, Protective Relay and Principles and Applications. CRC Press.
- Thomas P. Smith P.E, The ABC's of Overcurrent Coordination.
This article is accurate and true to the best of the author’s knowledge. Content is for informational or entertainment purposes only and does not substitute for personal counsel or professional advice in business, financial, legal, or technical matters.
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