A Ground Fault Protection Method

for Ungrounded Systems

Louis V. Dusang, Jr.

Abstract—This paper presents a novel approach to

simultaneous ground fault isolation for ungrounded power

systems. The concept capitalizes on current differential and

directional overcurrent designs by considering the second ground

fault on the system to prevent a phase-to-phase-to-ground fault.

Supplying uninterrupted power to consumers is important.

Ungrounded power systems have an advantage of ride-through

capability during single phase-to-ground faults. It is desirable

and important, to trip only the appropriate breakers during

faults. While an ungrounded power system can remain

operational with a single phase-to-ground fault there are

circumstances when a major portion of the distribution system

shuts down upon a second ground fault on another phase

resulting in a phase-to-phase-to-ground fault. A patent pending

concept exploits prior art designs universally regardless of the

various relay manufacturers’ implementation methods.

Combining prior art differential protection and ground fault

detection the invention minimizes breaker tripping by addressing

multiple ground faults.

Index Terms—Differential protection, ground fault protection,

ungrounded power system

I. INTRODUCTION

For many commercial, industrial, and even residential

environments, power system reliability is of utmost

importance. In some manufacturing or textile environments, a

power outage can result in the loss of product in the

production process when outage occurred. Further, power

outages can result in down time for a facility, not only during

the outage, but also due to production restarting undertaken

subsequent to an outage. Losses of product and down time

may also lead to substantial monetary losses for a facility as a

result of the power outage. As such, facilities often take

measures to improve or maximize power system reliability to

avoid such losses.

Utilization of an ungrounded power system is a means of

improving power system reliability; hence, some textile and

industrial facilities, as well as US Navy ships operate on an

ungrounded distribution system. This paper presents a

technique of determining two unique single phase-to-ground

faults on different line section phases associated with

ungrounded power systems, causing a double line-to-ground

fault, and isolating one of the faults.

_____________________________

Louis Dusang is with Northrop Grumman Shipbuilding, Pascagoula, MS

39567 USA (phone: 228-935-2451; email: louis.dusang@ngc.com)

There are two types of distribution systems, grounded or

ungrounded. These systems are typically derived from a wye-

connection or delta-connection. A wye-connected may or

may not utilize the neutral for grounding. A delta-connected

has no neutral. Since the delta-connected system does not

have a neutral it is an ungrounded system. To ground an

ungrounded system one generally employs a resistance to

ground apparatus.

High resistance to ground systems like ungrounded systems

permit continued power system operation under single-line-to-

ground (SLG) fault conditions. It requires another SLG fault

on a phase other than the one faulted to trip the circuit

protecting device. This provides an opportunity to clear the

SLG fault without shutting down the system such that the end

user may never no there was a problem The purpose of the

high impedance grounding system is to lower the fault current

and limit overvoltage transients.

There are no intentional ground paths for ungrounded

systems. Ungrounded systems do have a stray capacitance to

ground path for current to flow. The impedance for such a

system should be equal to or slightly less than capacitive

reactance to ground. The reason for this is to increase the

amperage slightly to a value that can be read.

II. UNGROUNDED OR ISOLATED NEUTRAL POWER SYSTEM

BACKGROUND

System grounding minimizes voltage and thermal stresses,

provides personnel safety, and assists in rapid detection and

removal of ground faults [1]. Operating a power system

ungrounded limits ground fault current, but does not minimize

voltage stress. Additionally, locating ground faults on an

ungrounded power system is difficult.

The advantage of a solidly or low grounded systems, like

most in the U.S., over ungrounded power systems is that they

reduce overvoltage, but not to the extent of permitting un-

interrupted service. Phase-to-ground faults on solidly or low

impedance grounded systems must be cleared immediately to

avoid thermal stress and human safety hazards.

Ungrounded systems (see Fig. 1) have no intentional

ground connections. The system is connected to ground

through parasitic capacitance, the line-to-ground capacitance

(CAG, CBG, and CCG). Additionally, there is distributed

capacitance to ground for the transformers and feeder

conductors, and phase-to-phase capacitances which are not

represented. In both delta- and wye-configurations, loads are

connected ungrounded phase-to-phase; therefore, the

distributed capacitance to ground forms the unintentional

2008 IEEE Electrical Power & Energy Conference

978-1-4244-2895-3/08/$25.00 ©2008 IEEE

ground. The advantage of an ungrounded power system is

that for a single-phase-to-ground (closing Switch S of Fig. 1)

fault, the voltage triangle (see Fig 2) remains intact and

therefore loads can remain in service. When a SLG fault

occurs, the faulted phase potential decreases to near zero and

the healthy phases increase by a factor of 1.73. At the same

time, the zero-sequence voltage increases to three times the

normal phase-to-ground voltage. Fig 2 demonstrates these

two conditions. Fig 2a shows an unfaulted, ungrounded

system. Fig 2b shows how the voltage triangle shifts relative

to ground for an A-phase-to-ground fault.

A

B

C

G

CB

CCCA

R

R

R

S

a) Delta-configuration

A

B

C

G

CB

CCCA

R

R

R

N

S

b) Wye-configuration

Fig. 1. Three-Phase Ungrounded Systems

Fig 2. Voltage Triangle (a) Unfaulted System. (b) Faulted System (Solid A-Phase Fault, RF = 0)

The major factors in determining the magnitude of ground

fault current in ungrounded power systems are the ground

return impedance (zero-sequence line-to-ground impedance)

and fault resistance [2], [3]. Since loads are connected phase-

to-phase and there is no return to ground they do not generate

any zero-sequence current.

Ground faults in ungrounded systems utilize zero-sequence

current or three-phase voltage measurements [4]. While this

method, detects a fault it does not locate the fault [5], [6]. The

traditional method for locating single-phase-to-ground faults

was to disconnect a bus-tie feeder and determine if the zero-

sequence voltage decreased to its prefault value. Since fault

current can flow in either direction, forward or reverse,

modern relays incorporate a directional element to isolate the

detected ground fault.

III. TWO-TERMINAL UNIT PROTECTION OF UNGROUNDED

POWER LINES

Pilot channel relaying for two-terminal lines requires a

relay at each line end and a communication circuit connected

between the relays (see Fig. 3) [1], [7]. The five common

types of communication channels for pilot relaying are audio

tones over leased circuits, microwave or power-line carrier

(SSB), power-line carrier by itself, metallic wire pairs, RS-232

or n x 64 kb digital and fiber optics. Securely transferring a

trip, block or trip permission signal to the opposite end of the

protected line is the premise of pilot channel relaying [8].

Pilot wire usage provides high-speed differential and

directional signal capabilities.

Fig. 3. Schematic Diagram of Modern Differential and Directional

Comparison System

Differential relays operate on a current summing principle

that is the current flowing into a protected circuit zone equals

the current flowing out yielding no differential current on a

per-phase basis. When a fault occurs within the protected

circuit zone, part of the current flows into the fault such that

the current flowing in no longer equals the current flowing out

the circuit zone. While a differential current flows in the

relay, it does not assert unless the current is above a preset

value.

Directional overcurrent relay consist of a non-directional

overcurrent element in conjunction with a directional function.

Directional overcurrent relays provide sensitive tripping for

fault currents in forward direction, but not in the reverse

direction. Directional elements compare the current flow at

the terminals. Current flows into the line at the terminals for

internal faults in which the relay sends a trip signal to the

circuit breaker. Current flows outward at the terminals for an

external fault and utilizing a blocking signal inhibits the

sending of an assert signal to the breakers.

A relay may contain backup fault detection to the

differential fault detection. If the differential element or fiber

optic is damaged, the associated relay will not receive remote

current information; therefore, a blocking scheme,

incorporated into each relay takes appropriate action. While

differential relay action is without intentional delay, the

blocking scheme does include a short coordination time delay.

The backup fault detection is typically based on the phase

directional elements (67). The 67P only detects multi-phase

faults while the 67N element detects phase-ground faults.

Both elements are necessary to detect all fault types because

of the difference in pickup and sensitivity levels. The 67P

elements operate from phase currents and the 67N elements

operate from the current delivered by the core-flux summing

current transformers. A core flux summing transformer or

zero sequence CT encircles all phase conductors and senses

phase current imbalances. Core flux summing transformers

consist of a secondary winding isolated from the core without

a primary winding.

5 4

6

3 1

APS1

2

APS2DG1

DG3DG5

DG4 DG2

DG6

7HB 5HB

5SG

4SG

2SG

3SG

4HB 1HB

1SG6SG

6HA 5HA 4HA 2HA

SHORE

POWER

SHORE

POWER

F1

GROUNDING BANK 4.16kV/460 BANKDIESEL GENERATOR ON-LINE CIRCUIT BREAKER (CLOSED)

CIRCUIT BREAKER (OPEN)DIESEL GENERATOR OFF-LINE

Fig. 4. Example Power System Single-Line Diagram

For the 3-phase fault shown in Fig. 4 (F1 in the Figure), the

desired result is that only Breakers 1 and 2 open. The arrows

shown near Breakers 1, 3 – 6 indicate the direction of fault

current flow. If we were to consider time-overcurrent

protection, we would need to review instantaneous (ANSI 50)

and inverse-time elements (ANSI 51).

The arrows in Fig. 4 for Breakers 1, 3 – 6 indicate the

direction of fault current flow for Fault F1. For those breakers

where the arrow direct is away from the bus, a phase

directional element would declare a forward direction fault.

Conversely, if the arrow direction were into the local bus, the

phase directional element would declare a reverse direction

fault. What would happen if we required forward direction

declaration by a directional element before allowing the 51

element at that same breaker to begin operating? Breakers 1 –

6 would then include directional protection, and, only

Breakers 1, 2, 4 and 6 would declare a forward direction fault.

(Again note that Breakers 1 and 2 are protecting the faulted

line and both declare a forward fault. For all other line

sections, only one line terminal directional element declares

the fault direction as forward.) To achieve selectivity between

the protective relays at Breakers 1, 4 and 6, these relays must

sense different magnitudes of fault current.

The system configuration shown in Fig. 4 is such that

Breakers 1, 3, 4, 5 and 6 all sense the same magnitude of fault

current. The phase current waveforms flow through Breakers

1, 3 – 6 for Fault F1. It should be noted that the load and fault

current waveforms are 180° out-of-phase for Breakers 3 and 4,

and Breakers 5 and 6. This is a strong indicator that a line

current differential element scheme applied to these lines

would properly restrain.

IV. SIMULTANEOUS GROUND FAULT LOGIC DESCRIPTION

The zero-sequence component is the primary means to

detect and clear phase-to-ground faults. Ungrounded systems

produce very little phase-to-ground fault current.

Continued service is possible in ungrounded power systems

under SLG fault conditions. An A-phase-to ground fault

alone on 1HA-2HA line as seen in Fig. 5a and Fig. 5b will not

result in tripping of circuit breakers for the ungrounded power

system. The same is true of a single B-phase-to ground fault.

However, if the B-phase-to-ground occurs before clearing the

A-phase ground fault the zero-sequence component cannot

detect the resulting phase-to-phase fault. For the radial

configuration shown in Fig. 5a, the relays associated with

busses 1HA-2HA, 2HA-3HA, and 3HA-4HA will send an

assert signal to their respective breakers resulting in

differential element trip for the phase-to-phase fault. In this

case the power transformers 2HA and 3HA will have no

power source. Fig. 5b is similar, but a relay “racing”

condition exists as to which breakers will trip since connected

in a ring bus configuration. In the ring bus configuration case,

it is possible that more of the system is shutdown.

Protection against second ground faults is possible when

utilizing a zero-sequence current sensor at both cable ends of

each bus-tie. In general, time delays are inefficient in that it

delays the differential current trip thereby defeating the high-

speed pilot function and may cause excessive damage during

phase-to-phase fault and short circuit conditions. The

proposed concept essentially blocks the differential elements

from asserting under ground fault conditions. Utilizing a

Supervisory Control And Data Acquisition (SCADA) system

one bus-tie can be isolated in either case minimizing

transformer loss. In the case of Fig. 5, bus-tie 2HA-3HA can

open without removing a fault while maintaining power to all

power transformers.

a) Radial System

X

A-Phase Fault

X

B-Phase Fault

1G

1HA 2HA 3HA 4HA

2G

1HB 2HB 3HB 4HB

b) Ring Bus System

Fig. 5. Power Distribution System

Relay manufacturers have various ways of implementing

differential and directional protection. Although the methods

differ between relay manufacturers the principles are similar.

Fig. 6a depicts an oversimplified rendition of present day

differential protection (analyzing each phase for a difference

in current via OR logic) and Fig. 6b depicts an oversimplified

version of directional overcurrent protection. For current

differential protection if B-phase and C-phase have no

differential current flow, but current flows through the

differential relay in A-phase the differential relay will assert if

the value exceeds the pickup setting. Operation of the ground

relay is based on detection of a ground fault without isolating

the fault condition.

a) Differential Scheme

b) Ground Directional Overcurrent Scheme

Fig. 6. Simplified Fault Protection Logic

V. SIMULTANEOUS GROUND FAULT PROTECTION

Present day differential protection typically operates on a

per phase basis. This design is suitable for both grounded and

ungrounded power systems. However, for ungrounded

systems a single phase fault will not result in a trip unless the

relay setting is set such that it results in a signal to trip the

breaker. Employing a phase-to-phase design (see Fig. 7) such

as in the patent pending approach provides for single phase

fault isolation.

Fig. 7. Simplified Patent Pending Protection

The patent does not modify the primary differential,

directional or ground fault detection schemes developed by the

various manufacturers in which CT saturation and other

factors are considered by the relay manufacturer’s design.

The patent enhances each of these schemes by including

additional logic to address the second ground fault. Utilizing

existing ground fault detection technology we block the

differential elements when a ground fault is present on the

power system to prevent tripping when the second ground

fault occurs.

To examine the relationship of zero-sequence voltage and

current and differential protection the system was modeled as

a simple two line ungrounded system connected to two buses

with a source connected to each bus as shown in Fig. 8.

Fig. 8. Power System Configuration

As stated earlier, each manufacturer’s relay can apply the

patent pending simultaneous ground fault protection.

Evaluating the new concept consisted of running scenarios on

power system configuration of Fig. 8 and comparing the

results with present day differential and ground fault

protection with simultaneous ground fault protection, see

Table I.

TABLE I

FAULT PROTECTION TEST CASES

Test

Case

Scenario Non-Simultaneous Ground

Fault Protection

Simultaneous Ground

Fault Protection

1 SLG fault on Line 1 Relay 1 and Relay 2 fault

detection via zero-sequence

Same

2 Phase-to-phase-to-ground fault,

Line 1

Relay 1 and Relay 2 isolate fault

via differential protection

Same

3 Phase-to-phase fault on Line 1 Relay 1 and Relay 2 isolate fault

via differential protection

Same

4 Three-phase-to-ground fault on

Line 1

Relay 1 and Relay 2 isolate fault

via differential protection

Same

5 SLG fault (Aφ), Line 1

SLG fault (Cφ) w/ delay, Line 1

Relay 1 and Relay 2 isolate fault

via differential protection

Relay 1 and Relay 2

isolate fault via new

concept

6 SLG fault (Aφ), Line 1

SLG fault (Cφ) w/ delay, Line 2

All relays assert isolating both

faults via differential protection

Selectively isolate either

Line 1 or Line 2

Cases 1-5 deal with one line in which fault isolation is

similar regardless of protection scheme applied. The

difference lies in Case 5. If the SLG fault occurs on a bus and

evolves into a double line-to-ground fault, the same relays

assert similar to a differential trip except with a delay. This

time delay acts as a differential element block while

permitting fault isolation via SCADA system corresponding to

the simultaneous ground fault protection scheme.

Case 6 affects both lines. Here is where the real benefit of

the concept becomes apparent. The per phase differential

protection approach results in each relay sending a trip signal

to open all breakers. However, when implementing a two-

phase scheme, blocking differential elements provides time to

isolate one of the SLG faults. In other words, with the

differential phase components blocked, the second ground

fault utilizing a SCADA signal isolates one SLG fault.

Obviously, only two breakers trip versus four. In the event no

SLG fault is cleared a timer will time out tripping the

applicable busses, which operates as a backup.

The advantage in both Case 5 and Case 6 is it provides

time to address the ground fault with continued differential

protection.

For larger power systems as in Figure 4 when the second

ground fault occurs on a different bus (Case 6), the differential

current while remaining internal between the two outermost

relays covers more lines. In Figure 4a, we have three, two

terminal, busses: 1HA-2HA, 2HA-3HA and 3HA-4HA.

Implementing a timer in the scheme addresses multiple bus

situations.

Personnel may be addressing the first ground fault

occurrence when the second ground fault occurs. Under these

conditions it may be unsafe to trip the breakers. Depending

on whether the power system configuration is ring bus or

radial depends on how the two faults will be isolated. In

either case the option may be to isolate the second fault

occurrence. This option can be safe for personnel and

maximize power system reliability.

VI. CONCLUSIONS

Power system reliability is important for many commercial,

industrial, and even residential environments. As such, this

paper introduces a technique of determining two unique

single-phase-to-ground faults, creating a double-line-to-

ground fault, and isolating one of the faults. The concept is

applicable to ungrounded and high impedance grounded

systems. Additionally, the new scheme capitalizes on current

differential, directional overcurrent and ground fault

protection.

High-speed fault clearing is maintained for phase-to-phase,

phase-to-phase-to-ground and three-phase faults. Although a

delay is added when a second SLG fault occurs on the system,

it is insignificant in that it is similar to protection without

communications. Additionally, it enhances power system

performance and reliability.

VII. ACKNOWLEDGEMENT

The author acknowledges the co-inventor, Jeff Roberts, for

his contributions.

VIII. REFERENCES

[1] IEEE Recommended Practice for Protection and Coordination of

Industrial and Commercial Power Systems, IEEE Std 242-2001

[2] Cooper Bussmann Inc, “Overcurrent protection and the 2002 National

Electrical Code questions & answers to help you comply,” On-line

Training, March 2002, [Online]. Available:

http://www.bussmann.com/library/docs/NE02.pdf

[3] J. Roberts, H.J. Altuve and D. Hou, "Review of ground fault protection

methods for grounded, ungrounded and compensated distribution

systems," presented at the 28th Annual Western Protective Relay Conf.,

Spokane, Washington, October 23-25, 2001. [Online]. Available:

http://www.selinc.com/techpprs/6123.pdf

[4] A. A. Regotti and H. W. Wargo, “Ground-fault protection and detection

for industrial and commercial distribution systems,” Westinghouse

Engineer, pp. 80-83, July 1974.

[5] D. J. Love and N. Hashemi, “Considerations for ground fault protection

in medium voltage industrial and cogeneration systems,” IEEE Trans.

Ind. Applications., Vol. 24, pp 548-553, July/Aug. 1988.

[6] T. Baldwin, F. Renovich, and L. F. Saunders “Directional ground-fault

indicator for high-resistance grounded systems,” IEEE Trans. Ind.

Application, Vol. 39, No. 2, pp. 325-332, March/April 2003

[7] J. Roberts, D. Tziouvaras, G. Benmouyal, and H. J. Altuve, “The Effect

of multiprinciple line protection on dependability and security,”

presented at the 28th Annual Western Protective Relay Conf., Spokane,

Washington, October 23-25, 2001. [Online]. Available:

http://www.selinc.com/techpprs/6109-Paper-WPRC.pdf

[8] J. Benckenstein, “System reliability improvements through fiber optic

systems,” Pulsar Technical Publication FD45–VER01, March 2001,

[Online]. Available: http://www.pulsartech.com/pulsartech/docs/FD45-

VER01.pdf

IX. BIBLIOGRAPHY

Louis Dusang received a Bachelor of Science in Electrical Engineering

degree from Mississippi State University in 1988 and is pursuing his MSEE at

the University of Idaho. He is a Registered Engineer in South Carolina. He

has been an electrical engineer with Northrop Grumman Shipbuilding since

November 2001. He is the lead project engineer for LDA Power Systems.

Prior to joining NGSB, Mr. Dusang worked as both an electrical engineer and

controls engineer for Jacobs.