- Transmission Line Protection Definition: Transmission line protection is a set of strategies used to detect and isolate faults on power lines, ensuring system stability and reducing damage.
- Selective Tripping: This method ensures that only the breaker nearest to the fault trips, preserving system integrity and limiting the impact of faults.
- Time-Graded Overcurrent Protection: In this approach, relays are set to trip at staggered times, based on their proximity to the power source, to coordinate fault isolation.
- Inverse Time Relay Advantage: These relays offer a dynamic response, with tripping times that decrease as fault severity increases, allowing quicker isolation of severe faults.
- Differential Protection: This technique uses a comparison of conditions between two points on a line to detect discrepancies caused by faults, swiftly isolating the affected section.
An electrical power transmission line covers a large physical area and is exposed to weather, vegetation, pollution and external contact. Its protection must therefore account for more fault locations and changing system conditions than protection for individual electrical power transformers or alternators. A transmission line protection scheme also has to distinguish internal faults from load and faults beyond the line. The same general goals apply to a transformer or alternator, but the measurements and operating zones differ.
Protection of line should provide the following features:
- For a fault inside a primary protection zone, the designated circuit breaker or breakers should trip selectively.
- If a primary relay or breaker fails, coordinated local or remote backup protection should clear the fault after an intentional delay.
- The scheme should clear damaging faults quickly while remaining secure for load, external faults and permitted system swings.
These requirements make protection of transmission line different from protection of transformer and other power-system equipment. Common transmission line protection functions include:
- Time-graded overcurrent protection.
- Differential protection.
- Distance protection.
Time Graded Over Current Protection
Time-graded overcurrent protection coordinates relay pickup and delay settings so the device nearest the fault operates first. The following sections describe definite-time and inverse-time applications.
Protection of Radial Feeder
In a radial feeder, normal power flows from one source towards the loads. Definite-time or inverse-time overcurrent relays can be graded along the feeder if minimum and maximum fault-current studies show adequate sensitivity and coordination.
Line Protection by Definite Time Relay
In a definite-time scheme, each successive upstream relay has a longer intentional delay. The relay nearest the remote end has the shortest delay, while upstream relays provide delayed backup.
The following example uses a source at point A.
At point D, circuit breaker CB-3 has a definite operating time of 0.5 seconds. CB-2 at point C operates in 1 second, and CB-1 at point B operates in 1.5 seconds.
If a fault occurs at point F, fault current passes through the current transformers or CTs at the upstream locations. CB-3 should trip first because its relay has the shortest delay. If CB-3 or its relay fails, CB-2 provides delayed backup. CB-1 provides the next backup stage if CB-2 also fails.
Advantages of Definite Time Line Protection
The scheme is simple to understand and coordinate on a radial feeder. For a fault within a section, the first upstream breaker normally isolates the smallest practical part of the feeder.
Disadvantage of Definite Time Line Protection
Each upstream grading step adds delay. A fault near the source can therefore have the highest available fault current but the longest operating time, increasing equipment stress and the effect on the wider system.
Over Current Line Protection by Inverse Relay
An inverse-time relay operates faster as current rises above its pickup setting. Its time follows a selected standard or manufacturer curve and a time-setting multiplier; it is not simply proportional to 1 divided by fault current.
In the figure, the relay at point D has the fastest coordinated setting. Relays towards source A have successively longer settings so they can provide backup.
For a fault at F, CB-3 at D should trip first. If CB-3 fails, the delayed relay at C should trip CB-2.
A high-current fault near the source can still make an upstream inverse-time relay operate quickly. Engineers must check the full curve, pickup, breaker time and coordination margin for the minimum and maximum fault currents.
Over Current Protection of Parallel Feeders
Parallel feeders can maintain supply if one circuit is isolated, but a fault may receive current from both ends or through the healthy feeder. Nondirectional overcurrent alone may not identify the faulted circuit. Directional overcurrent elements use polarising quantities to determine whether fault current is forward or reverse, and their time settings must be coordinated for each operating configuration.
In this simplified example, both feeders have an inverse-time, nondirectional over current relay at the source end. Directional elements at the load end are set to detect reverse fault current. Modern schemes distinguish directional overcurrent from directional power and may use communications-assisted logic for faster, more secure isolation.
If a fault occurs at F with total current If, the source feeds it through two paths. One path passes through circuit breaker A. The other passes through CB-B, feeder 2, CB-Q, the load bus and CB-P. In the figure below, IA and IB are the contributions through feeders 1 and 2.
Using Kirchoff’s current law, IA + IB = If.
IA flows through CB-A and IB flows through CB-P towards the fault. The directional element at CB-P detects reverse fault current and trips CB-P, while the element at CB-Q sees the opposite direction and restrains. Opening CB-P removes the IB contribution. IA continues through CB-A, which then clears the remaining IA contribution and isolates the faulted feeder. This sequence is illustrative; actual settings must also cover breaker failure, current reversal, weak infeed and changes in network topology.
Differential Pilot Wire Protection
Line differential protection compares current entering and leaving a defined feeder zone. Merz-Price voltage-balance and Translay schemes are historical pilot-wire implementations. Modern numerical relays usually exchange sampled current data over supervised communications channels and add percentage restraint, CT-saturation security and backup elements.
Merz Price Balance System
In the illustrated Merz-Price circulating-current scheme, matched CTs are installed at both ends of the protected line. Their secondary circuits and the relay operating coils are connected by pilot wires with polarities chosen so through-current circulates between the CTs rather than through the operating coils.
During normal load or an external fault, the end currents are ideally equal for the protected zone, so the differential operating current is near zero. Practical schemes allow for CT error, ratio mismatch and saturation.
For an internal fault between the CTs, the end-current comparison produces differential current. If it exceeds the pickup and restraint characteristic, the scheme operates.
Relays at both ends then trip their associated circuit breaker, isolating the protected line. Channel supervision and independent backup protection are required because a failed pilot circuit or communications channel can otherwise reduce dependability.
