Transformer Protection Basics

Summary

This webinar offers an in-depth look at transformer protection, focusing on differential protection elements, their necessity, and setting configurations. Christine Kreitz, a technical application engineer, discusses various transformer types, fault categories, and the importance of proper protective relaying to prevent catastrophic failures. She outlines the function of current differential protection, its challenges, and how to program relay settings in GE devices. The presentation also covers external and internal fault handling, the impact of transformer inrush, and the significance of correct CT polarity for reliable operation.

Takeaways

• 📈 Transformers are critical and expensive assets in the power system, and their failure can significantly impact the downstream equipment and operations.
• 🛡️ Proper protective relaying can detect abnormal conditions early and limit damage, reducing repair costs and downtime.
• 💡 Different types of transformers, such as Generator Step-Up Transformers (GSU), step-down transformers, and auto transformers, require specific protection schemes.
• 🚨 Transformer protection focuses on internal faults like overheating, overfluxing, and winding faults, which can be catastrophic if left undetected.
• 🔍 Current differential protection is a key element in transformer protection, which works by comparing the current entering and exiting the transformer to detect internal faults.
• ⚙️ The percent slope differential (87T) is typically used over the unrestrained differential (50/80) for better security and to account for normal measurement errors.
• 🤖 GE's relays, such as the 845 and T60, offer advanced features for transformer protection, including current differential protection and the ability to interface with dissolved gas analyzers.
• 🧠 Understanding and correctly setting the key parameters for differential protection, like pickup value, slopes, and breakpoints, is crucial for effective protection.
• 🔩 Correct CT (current transformer) polarity and wiring are essential for accurate differential protection operation.
• 🌀 Transformer inrush current, which can be many times higher than the rated current, must be managed by the relay to prevent false tripping during energization.
• ⚖️ Magnitude compensation and phase compensation are necessary adjustments for differential protection to account for the transformer's voltage and current changes.

Q & A

What is the main purpose of the webinar on transformer protection?

The main purpose of the webinar is to provide an overview of the basics of transformer protection, focusing on fundamental transformer differential protection elements, why they are needed, and how relay settings are determined.

Why are transformers considered critical and expensive assets in substations?

Transformers are considered critical and expensive assets because they are often the most significant and costly components in a substation. If a transformer fails, everything downstream of it is affected, leading to extensive downtime and repair costs.

What are some common types of power transformers mentioned in the webinar?

The webinar mentions generator step-up transformers (GSU), step-down transformers used in substations and industrial plants, medium to low voltage transformers within plants, and auto transformers as some common types of power transformers.

What is the primary function of a transformer current differential protection element?

The primary function of a transformer current differential protection element is to detect most internal faults within the transformer. It works by comparing the current going into and out of the transformer and tripping if a non-zero differential current is detected, indicating a fault within the transformer zone.

How does a transformer inrush affect the differential protection element?

Transformer inrush, which occurs during energization and can be as high as 10 times the rated full-load current, can cause a high differential current that might falsely trigger the differential protection element. To prevent this, relays can detect the presence of second harmonic in the winding current during inrush and block the differential element from operating until the transformer is fully energized.

What is the recommended approach for dealing with phase compensation in transformer differential protection?

The recommended approach for dealing with phase compensation is to let the relay handle it automatically, provided that the winding configurations are properly identified in the settings. This method is preferred over external wiring adjustments, which could potentially lead to issues with metering.

What are some of the key settings needed to configure the dual slope characteristic for a transformer differential protection element?

The key settings needed to configure the dual slope characteristic include the pickup value, slope one, breakpoint one, breakpoint two, and slope two. These settings help in creating a sensitive yet secure operating curve for the differential protection element.

Why is correct CT polarity important in transformer differential protection?

Correct CT polarity is crucial because it ensures that the currents from different windings are 180 degrees apart in phase when they are brought to the relay. If the polarities are incorrect, the relay will add the currents instead of cancelling them out, resulting in a high differential current that could falsely trigger the protection element.

What is the purpose of the IEEE CT saturation tool mentioned in the webinar?

The IEEE CT saturation tool is used to determine the breakpoint settings for transformer differential protection elements. It helps in identifying the current levels at which the CTs start to saturate, ensuring that the protection settings are correctly configured to account for CT saturation conditions.

How can one confirm if the differential protection element is operating properly during testing?

To confirm if the differential protection element is operating properly, one can manually calculate the expected differential and restraint currents using the relay settings and test currents, then compare these values to the dual slope characteristic. Alternatively, using a differential element simulator or a test set with plotting capabilities can automate this process and directly indicate whether the relay passed or failed the test.

What are the implications of having one winding grounded and not the other in a transformer?

If one winding is grounded and the other is not, a ground fault would cause the grounded winding to see zero sequence current while the other would not. This discrepancy needs to be accounted for in the relay settings to prevent false differential currents from triggering the protection element. The relay should perform zero sequence removal for the grounded winding if the settings are configured correctly.