Sunday, March 21, 2021


Author: BSEE Hugo E Reyes


A three-phase power system is subjected to PHASE FAULTS as well as GROUND FAULTS. Faults involving just one of the phase conductor and ground are called GROUND FAULTS. Faults involving two or more phase conductors, with or without ground, are called PHASE FAULTS

On the other hand, it may be pointed here that fault current for a single line-to-ground fault (SLG), depends on the system grounding and the distance to the fault, but also on the level of generation in the power system. Other factor is the arc resistance that is nothing but the arc that is formed due to flashover of insulator string.

It may occurs that the fault current for a single line-to-ground fault, may be less than the load current. The lowest current fault magnitude corresponds to a SLG located at the end of the backed-up line section under minimum generation conditions. Under these scenarios, the ground overcurrent element must have maximum sensitivity in order to detect high-resistance faults.



The term residual in common usage is normally reserved for three-phase system connections and seldom applied to single-phase or multiple-signal mixing.

The Figure 1 depicts the basic residual connection scheme.

Figure 1 Residually Connected Ground Relay

In this scheme, the phase overcurrent elements (50P/51P) are connected to the phases of the Wye-connected current transformers (CTs) and the ground overcurrent element (50N/51N) is connected to the Wye Neutral. Thus, the residual connection allows the ground fault relay to measure the sum of the phase currents, which is equivalent to the residual current (3.I0). With electromechanical relays this scheme needs four relays; nowadays, with digital relays this scheme needs just one relay.

The pickup current of the phase overcurrent relay (51P) needs to be set above the maximum load current. On the other hand, the ground fault element (51N) needs to be set above the maximum zero-sequence unbalance current, which is typically no more than 10 to 15 % of the phase current.

Unequal performance of current transformers during heavy phase faults or initial asymmetrical motor starting currents may produce false residual currents causing ground fault relay (GFR) operation, an instantaneous GFR with a higher pickup should be substituted, or the time overcurrent relay should have a larger time dial or pickup setting.


A ground fault relay (GFR or 50N) that is connected to a current transformer located in the grounded neutral of a Power Transformer or AC Generator, provides a convenient, low-cost method to detecting ground fault currents. This scheme is widely applied on 5 kV up to 15 kV systems where low-resistor grounding is frequently used, and the ground fault current is as low as 200 Amperes. The GFR can be set to minimum values of current pickup and time delay to be selective with load-side feeder GFRs. This method is also applied on solidly grounded systems, 480 Volts, 3 phase/ 3 Wire or 3 phase /4 wire systems. One advantage that this scheme provides is the fact that false residual currents do not occurs and do not cause relay operations.

The Figure 2 is a typical scheme of a neutral connected GFR.

Figure 2 One CT in the Grounded Neutral


This scheme is also known as Flux-Summing CT, as well as the neutral connected scheme, it can provides higher sensitivity by using lower-ratio CTs. This method is widely applied on medium voltage systems, but is also used on low-voltage systems for improved protection.

The Figure 3 depicts a typical zero-sequence ground fault relay scheme.

Figure 3 Zero-sequence Ground Fault Relay

One advantage of this scheme is that the CT Ratio (CTR) is not dictated by the load current, it avoid the possible difficulties of unequal individual CTs saturation. The disadvantage is the limitation of the size of conductors that can be passed through the window of the toroidal CT. The standard ratio for toroidal CTs are: 50/5 and 100/5.

The zero-sequence CT is commonly used with a 0.25 Amperes instantaneous ground overcurrent element (50G). The combination provides a primary pickup of 5 Amperes, rather than 2.5 Amperes.

In normal operation, the zero-sequence current unbalance (3.I0) could be very low, usually less than 10% of the Maximum Possible Load (IML) or the Short Time Maximum Load (ISTML). The pickup current of delayed ground overcurrent relays (51N or 51G) must be set larger than the maximum zero-sequence current unbalance (3.I0) that may be tolerated by the power system, and lower than the minimum single-line-to-ground fault (SLG).

                                    Imax-unbalance (IMU) < IPKP-51G < IF-1Ø

The lowest fault current (IF-1Ø), returning through the Earth to the Substation Neutral, corresponds to a single-line-to-ground fault located downstream of the backed-up power line section under minimum generation conditions.

The choice of a relay time characteristics, in the case of line protection, is usually limited to the Inverse and Very Inverse Curves. Typically, the Very Inverse Curve is the more often used. On the other hand, when coordination with fuses and/or series trip reclosers is required, an Extremely Inverse characteristic would be preferable. 

The next Figure 4 shows a single line diagram (SLD) of a radial system, there is a ground overcurrent relay 2 (51G-2) providing primary protection to the power line, between Bus 1 and Bus 2, and also a backup protection to a ground overcurrent relay 1 (51G-1). The element 51G-2 must detects SLG faults beyond the downstream element 51G-1, the backup protection is executed if the element 51G-1 fails to operate in its primary zone. Hence, the goal is to select the pickup current of the element 51G-2.

With the application of a ground relay set on the 0.5 Amperes - TAP, on a basis of a ground relay designed to carry 5.0 Amperes, the single-line-to-ground fault should not be less than two times the pickup current or 1.0 Amperes. 

To be able to detect a ground fault of 10% of the current produced by a bolted line-to-ground fault (IG) is a recognized criterion. The maximum load of any circuit off a bus dictates the critical CT Ratio (CTR). With a primary current of 10% x IG, a ratio of K= 5 and minimum secondary current of 1.0 A, produce the following:

IG ≥ 2 x K

If the use of this criterion produces an excessively high ground fault current, a lower current value can be chosen by using a higher neutral resistor value.

Ground fault currents on distribution circuits are generally higher at the substation than phase-fault currents, but they decrease at a much greater rate with the distance from the substation due to X0 (zero-sequence reactance) is larger than X1 (positive-sequence reactance) for the feeder circuits. As well as phase overcurrent relays, instantaneous ground unit (50N or 50G) can be used to improve relaying, specifically for close-in ground faults. Therefore, instantaneous ground units operate with no intentional time delay, generally in the order of 1 to 3 cycles.

On the other hand, ground fault currents are not transferred through power transformers that are connected Delta-Wye or Delta-Delta, in these cases the ground fault protection for each voltage level is independent of the protection at other voltage levels.


Typically, in a solidly grounded system fault currents returns to the near substation neutral along the Equipment-Grounding Conductors (EGC). When the ground return impedance is as low as that of the phase conductors, ground fault currents could be high, and the normal phase overcurrent protection would clear them as fast as possible. However, the impedance of the ground return path is usually high. Thus, the ground fault itself is usually arcing, so the impedance of the arc further reduces the fault current. Under this scenario, the ground fault current is below the trip setting of the phase overcurrent devices and it does not trip at all until the fault escalates and extensive damage is done. For these reasons, low-level ground protection relays with minimum time-delay settings are provided to rapidly clear ground faults. 

The NEC requirements for ground fault protection of equipment are outlined in the articles 230.95, 210.17, 215.10, 240.13, 517.17, 695.6(G), 700.31, 701.26 and 708.52.

Some NEC's requirements are:

- Ground fault protection (50G/51G) shall be provided for 1000 Amperes or greater in service disconnecting means in 480/277 Volts, solidly grounded Wye (Star) systems.
- When a ground fault protection is applied on the main or feeder of a healthcare facility, then ground fault protection must be on the next level of feeders according with 517.17 (B) and 708.52 respectively.
- Ground fault protection is not required for the alternate source of emergency systems (700.31) and legally required standby systems per 701.26.
- Ground fault protection is not allowed on the circuit paths for fire pumps per 695.6(G).
- For health care essential electrical systems, additional level of ground fault protection cannot be located on the load-side of certain transfer switches, per 517.17(B).

The Art. 230.95 of the NATIONAL ELECTRICAL CODE (NEC-NFPA 70) requires that:

“Ground fault protection of equipment shall be provided for solidly grounded wye electric services of more than 150 volts to ground but not exceeding 600 volts phase-to-phase for each service disconnect rated 1,000 Amperes or more. The grounded conductor for the solidly grounded wye system shall be connected directly to ground through a grounding electrode system, as specified in 250.50, without any resistor or impedance device”.

This requirement does not apply to electrical systems where the ground conductor is not solidly grounded, as is the case with high-impedance grounded neutral systems covered in article 250.36. Ground fault protection of services does not protect the conductors on the supply side of the service disconnecting means, but it is designed to provide protection for line-to-ground faults that occurs on the load sides of the service disconnecting means. An alternative to installing ground fault protection may be to provide multiple disconnects rated less than 1,000 Amperes. For instance, up to six 800 Amperes disconnecting means may be used, and in that case ground fault protection would not be required.

Note: according to the Art. 100 the definition of disconnecting means is: “A device, or group of devices, or other means by which the conductors of a circuit can be disconnected from their source of supply”. For example: circuit breakers and fuses.

Additionally, the Art. 230.95 (A) requires:

 “The ground-fault protection system shall operate to cause the service disconnect to open all ungrounded conductors of the faulted circuit. THE MAXIMUM SETTING OF THE GROUND-FAULT PROTECTION SHALL BE 1200 AMPERES, and the maximum time delay shall be one second for ground fault currents equal or greater than 3000 Amperes”.

Also, there is no minimum setting, but setting at low levels can increase the probability of unwanted shutdowns. The article 230.95 (A) also place a restriction on fault currents greater than 3,000 Amperes and limit the duration fault to more than one second.

The following examples has been taken from “EATON – BUSSMANN SERIES SPD ELECTRICAL PROTECTION HANDBOOK” based on 2017 NEC.

Example 1:

The figure 5 shows a Time-Current Curve (TCC) for a line-to-ground fault with a 1600 Amperes circuit breaker in combination with a GFR (50G) that is set at 1,200 Amperes and 12-cycle delay (0.2 seconds). For a ground fault currents between 1,200 and 14,000 Amperes, the GFR will trip the circuit breaker opening the circuit. On the other hand, for ground fault current greater than 14,000 Amperes the circuit breaker phase overcurrent element (50P) will respond faster than the ground fault relay (50G).

Figure 5 TCC for Line-to-Ground Fault

Example 2

The figure 6 shows a One-Line Diagram and the Figure 7 shows the Time-Current Curve (TCC) for a power system where the main supply service and feeders are selectively coordinated for low-level ground fault currents.

Figure 6 One-Line Diagram (OLD) Example 2

We can see in Figure 7 that this power system is selectively coordinated for all ground fault currents. The instantaneous ground fault relay in the feeder (50G-2) is set to trip starting at any ground fault between 100 Amperes up to around 2000 A in 100 milliseconds, also the relay 50G-2 is coordinated with the main ground relay 51G-1. For ground fault currents in the feeder between 2,000 A and 4,000 A, the fuse LPS-RK-200S will clear the ground fault faster than the ground fault element 51G-2. If the feeder fuse fails to clear the ground fault then the backup protection 51G-1 (in the main) will clear the fault. By the way, we can see that at ground fault of 3,000 A the ground fault relay 51G-1 will clear the fault in 1 seconds, according with the article 230.95 (A).


ü  Normally, load current does not affect the ground relay operation.

ü  Ground overcurrent relays have more sensitivity than phase overcurrent relays, because they are usually set at 10% to 20% of the sensitivity of phase relays.

ü  Ground overcurrent relays (50G or 50N) usually can be set and coordinated independently of the phase overcurrent relays (50P/51P). 

ü  The application and coordination of ground overcurrent relays are the same as for phase relays.

ü  As with instantaneous phase overcurrent relays (50P), instantaneous ground trip (50G or 50N) can be used to improve relaying, particularly for close-in ground faults.

ü  Ground relays are not affected by out-of-step conditions.

ü  The higher zero-sequence line impedance Z0L, as compared with the positive-sequence line impedance Z1L, may allow to use a high-set ground overcurrent element and make coordination easier than for phase faults.

ü  The zero-sequence isolated system may make coordination easier.

ü  The NEC Art. 230.95 requires the implementation of a ground overcurrent relay at least at the supply end of a low-voltage systems if the neutral is solidly grounded, and voltages in range of more than 150 volts to ground but not exceeding 600 volts phase-to-phase for each service disconnect rated 1,000 Amperes or more.

ü  THE MAXIMUM SETTING OF THE GROUND-FAULT PROTECTION SHALL BE 1,200 AMPERES, and the maximum time delay shall be one (1) second for ground fault currents equal or greater than 3,000 Amperes.

ü  There is no minimum setting for ground overcurrent relays. Even though, for neutral connection schemes a range of 200 A to 400 A is widely used.. On the other hand, for zero-sequence ground fault schemes a range of 30 mA to 50 A is frequently used.


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