Ground Fault Protection for Bus-Connected Generators in an Interconnected 13.8-KV System

IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS, VOL. 43, NO. 2, MARCH/APRIL 2007 453

Ground Fault Protection for Bus-ConnectedGenerators in an Interconnected 13.8-kV System

J. C. Das, Senior Member, IEEE

Abstract—This paper is based on modifications implemented inthe protection and grounding systems of a large paper mill anddescribes selective ground fault protection for a 13.8-kV systemwith multiple bus-connected generators, synchronous bus ties, andutility interconnections. The ground fault current in the system isreduced from the existing 3400 A to 500 A, and a hybrid groundingsystem is implemented for each of the generators. As the groundfault currents are reduced to limit the fault damage, the sensitivityand selectivity of the ground fault protection become important.Directional ground fault relays with coordinating pickup settingsare applied to achieve this objective. The new platform for di-rectional elements (numerical relays) drives its performance fromsequence impedance measurements.

Index Terms—Directional ground fault relays, ground faultdirectional elements, hybrid generator grounding, sequence im-pedance measurements.

I. INTRODUCTION

THE system configuration and ground fault protection ofthe 13.8-kV distributions are shown in Fig. 1. The over-

lapping zones of the phase fault protection are also shown.Other protective relaying functions are not shown for clarity.The emphasis is on the ground fault protective devices. Eachgenerator is hybrid grounded and has a neutral breaker.

Before the aspect of selective ground fault protection isdiscussed, some explanation of the grounding system is relevantto this paper. Until the recent modifications to the groundingsystem, as shown in Fig. 1, the mill has operated for 35 yearswith the following:

• generators grounded through 2000-A/1000-A resistors;• one or two of the generators operated ungrounded (neutral

breakers open) to limit the ground fault current. Yet, at anyoperating time, the system ground fault current could be3400 A.

The original system may have been designed with highground fault currents so that the phase differential protectionsoperate positively on ground faults. During the last 35 years ofoperation, luckily, no stator ground fault damage or insulationfailures of generator windings have occurred.

Paper PID-06-29, presented at the 2006 IEEE Pulp and Paper IndustryConference, Jacksonville, FL, June 19–23, and approved for publicationin the IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS by the Pulpand Paper Industry Committee of the IEEE Industry Applications Society.Manuscript submitted for review June 18, 2006 and released for publicationOctober 30, 2006.

The author is with AMEC E&C Services, Inc., Tucker, GA 30084 USA(e-mail: [email protected]).

Digital Object Identifier 10.1109/TIA.2006.889899

The ground fault damage to stator windings of industrialgenerators has been examined in [1]. Powell considers no gen-erator neutral breaker and assumes that source-side and gen-erator neutral currents are both 400 A. Considering that thegenerator breaker is opened in six cycles by instantaneousground relaying in response to a generator zone ground fault,greater fault energy (approximately four times) is releasedinto the fault from the ground fault current of 400 A fromthe generator neutral circuit than the system with 400-A cur-rent. This is because generator current decays slowly in about0.8–1.0 s depending on the generator single-line-to-groundfault time constant. This paper then suggests high-resistancegrounding of the generator, with ground current limited to10 A. This concept is enlarged in [2]–[5]. The following com-ments are of interest.

1) A single bus with generation and utility tie interconnec-tion is considered in [2]–[5]. Practically, the generation isdispersed throughout the system in a variety of configu-rations, for example, Fig. 1.

2) Wu et al. [6] show that when a neutral breaker is pro-vided and trips simultaneously with generator breaker, thesource- and neutral-side fault currents are simultaneouslyinterrupted, and the fault energy release is equivalent tothat with hybrid grounding system with high-resistancegrounding through 10 A.

3) It is shown in [7] (see Fig. 2) that for high-resistancegrounded systems, the current through the groundingresistor should be equal to the stray capacitance currentto prevent overvoltages, i.e.,

Rn =Vln

3Ic(1)

where Vln is the line-to-neutral voltage, Rn is the re-sistance introduced in the neutral circuit, and Ic is thestray capacitance current of each line conductor. The straycapacitance currents are displaced by 120◦, and under noground fault condition, these currents sum to zero, andthe neutral does not carry any stray capacitance currents.Under a ground fault condition, the stray capacitanceof the faulted phase is grounded, and the neutral againdoes not carry any stray capacitance current and flowsstraight to ground. Practically, some currents flow due toasymmetry associated with the three phases.In large distribution systems, the stray capacitance currentcan be high (i.e., of the order of tens of amperes), and thehigh-resistance grounding is not practical.

0093-9994/$25.00 © 2007 IEEE

454 IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS, VOL. 43, NO. 2, MARCH/APRIL 2007

Fig. 1. Distribution system (13.8 kV) for selective ground fault protection. Only ground fault relays and overlapping zones of phase differential relays are shown.The generators have phase differential protection (not shown) and ground differential relays 87GN.

For the system under discussion, the stray capacitancecurrent was calculated to be close to 80 A [8]. The13.8-kV distribution has 60 000 ft of shielded cableand approximately 200 load centers. A high-resistancegrounded system is adopted when the stray capacitancecurrent can be limited to approximately 10–15 A.

4) In general, the plant generation is considered more reli-able than the utility source, and coordination is requiredfor external faults so that no nuisance trip of the plantgenerators occurs.

Although there are a total of five grounded sources in thedistribution system, i.e., three generators and two utility trans-formers, the entire plant load can be served with two sourcesin service, i.e., one utility tie transformer and generator G2(Fig. 1). Grounding of each source through 100-A resistorswas decided, and this choice is further discussed in this paper.Thus, the maximum fault current in the system is limited to500 A. Although the generators are provided with a neutralbreaker, a hybrid grounding system is chosen to prevent thepossibility of overvoltages when the neutral breaker openssimultaneously with the line breaker; however, no rigorousstudy is conducted. The high-resistance portion of the hybridgrounding system remains permanently connected to the neu-tral and is not disconnected when the neutral breaker trips. It isdesigned to limit the current to 8 A, considering the capacitance

of generator windings, surge capacitor, and bus connections,when the generator line breaker is opened (Fig. 1).

II. PHASE FAULT DIFFERENTIAL RELAYS

The phase differential protection shown in Fig. 1 in variouszones may not pickup on ground fault currents as the sensitivityis low, and hence, low-level ground fault currents cannot bedetected. Consider the high-impedance-type differential pro-tection shown in Fig. 1. The minimum pickup current can becalculated from the following expression:

Imin =

[x=n∑x=1

Ix + IR + I1

]N (2)

whereImin minimum fault current to trip the relay;n number of breakers;Ix secondary excitation current of the current transform-

ers (CTs) at a voltage equal to the pickup value of thedifferential relay;

IR current in differential relay at pickup voltage;I1 current in the Thyrite unit of differential relay at

pickup voltage;N CT ratio.

DAS: GROUND FAULT PROTECTION FOR BUS-CONNECTED GENERATORS IN AN INTERCONNECTED 13.8-kV SYSTEM 455

Fig. 2. Optimum grounding resistor for high-resistance grounded systems toprevent overvoltages.

This calculation shows that the differential relay will not pickup at currents below 300–400 A.

The phase differential protection zones shown for cableprotection in Fig. 1 have microprocessor-based multifunctionprotective relays (MMPRs) with fiber-optic interface and inter-tripping. The pickup sensitivity for ground faults of these relaysis 0.5-A secondary current, and considering the CT ratios, itvaries from 300 to 200 A.

Thus, phase fault differential relays are not adequate for theground fault protection.

III. GENERATOR GROUND DIFFERENTIAL RELAYS

The generators have MMPRs, which have ground faultdifferential function, i.e., 87GN. The lowest setting on theserelays is 16 A. As the generator is grounded through a 100-Aresistor, approximately 84% (considering zero tolerances on theset pickup values) of the stator winding from the line end isprotected, assuming a linear variation of voltage from the line-to-neutral terminals of the winding. For a ground fault towardthe neutral end of the windings, neither 87GN nor 51G will beoperated. Although the probability of a fault decreases as thevoltage toward the neutral is reduced and the generator insula-tion system is not graded, i.e., the neutral is fully insulated, it isnot desirable to leave 16% of the windings unprotected.

The common practice of grounding the generators througha 400-A resistor protected a larger percentage of the statorwindings; i.e., it will protect 96% of the windings with the same16-A pickup setting. Thus, reducing the grounding currentcompromises some protection. If a fault occurs toward theneutral end, it will remain undetected, will persist for a longtime, and can cause core damage [9]. The Appendix describeshow protection of a greater portion of the stator windings

Fig. 3. Generator differential ground fault protection (87GN) using a producttype of electromagnetic relay. The figure shows stability on external single-line-to-ground fault.

toward the neutral can be implemented for low-resistancegrounded generators.

The 51G, i.e., the standby generator ground fault function,must coordinate with downstream ground fault protection andshould not trip the generator unless the fault is on the generatorbus. Thus, it will be less sensitive compared to 87GN functiondepending on downstream coordination for selective tripping.

A common practice in the industry has been to use anelectromechanical relay for generator differential ground faultprotection, which is commonly called the product type ofrelay. Fig. 3 shows such a scheme, with stability on external200-A single-line-to-ground fault. The CT ratios are externallymatched through an auxiliary transformer, i.e., 1/15 in Fig. 3.The relaying class accuracy on these auxiliary transformers israrely greater than C20 (C30 with special design), and these aresubjected to saturation. The CT burden on the high current sidewill be reflected as the square of turns ratio on the primary side,i.e., multiplied by a factor of 225 in Fig. 3. With the auxiliaryCT connections, as shown in Fig. 3, for an external fault, theoperating coil carries 0.33-A current in the opposite directionto the operating current, giving certain margin of stability. Thetime of operation depends on multiple of tap products and timedial settings. It can be of the order of several seconds evenwith sensitive settings. These product types of relays are notsuitable because of: 1) unacceptable operating times at lowcurrent levels and 2) sensitivity of pickup settings. Nuisancetrips have occurred in many installations, with misappliedauxiliary transformers.

There is no auxiliary current matching CT for 87GN functionin the MMPRs, as shown in Fig. 1. The protective relaysinternally make corrections for the mismatch. The accuracieswith internal correction of the mismatch are ±5% on pickup


TABLE IRELAY OPERATION FOR SELECTIVE GROUND FAULT TRIPPING

TABLE IIAREA OF SHUTDOWN FOR FAULT LOCATIONS SHOWN IN FIG. 1

settings, inclusive of internal relay algorithms. The time delaysetting of one cycle [1] on 87GN function even with MMPRs istoo optimistic, and nuisance trips have occurred. A prominentmanufacturer of these relays recommends six-cycle time delayon 87GN function to account for CT saturation on externalfaults.

IV. SELECTIVE GROUND FAULT COORDINATION

Table I shows the tripping matrix for selective ground faultclearance, and Table II shows the area of shutdown for therespective fault locations in Fig. 1. It can be seen that withoutthe provision of directional ground fault relays, as shown inFig. 1, selective tripping cannot be obtained.

Fig. 4 shows that coordination is achieved throughout thedistribution system including the utility ground fault relays. Thelow pickups of the protective devices are of interest, namely:

• 50G, all 13.8-kV feeder breakers: 5 A, instantaneous(all transformers in the downstream distribution systemhave delta-connected 13.8-kV windings, permitting thesesettings);

• 67N, breakers UT2 and UT4: 10 A;• 67N, breakers ST1, ST2, and ST4: 16 A;

Fig. 4. Selective coordination of ground fault relays in 13.8-kV distributionsystem, as shown in Fig. 1.

• 51G, generator 3, breakers ST1, ST2, and ST4: 20 A;• 51G, generators 1 and 2, breakers UT2 and UT4: 25 A.

These low pickup settings require a reliable directionalground fault relay.

V. DIRECTIONAL GROUND RELAYS

Selection and application of the directional ground protectionis therefore the key issue in coordinated ground fault protection.

Single-phase-to-ground and double-phase-to-ground faultsare unsymmetrical faults. All the sequence component cur-rents and sequence voltages, i.e., positive, negative, and zerosequence, are produced. Fig. 5(a) and (b) shows the intercon-nections of sequence networks and sequence current flows fora single-line-to-ground fault, i.e.,

I0 = I1 = I2 =13Ia (3)

Ia = 3I0 =3Va

(Z1 + Z2 + Z0) + 3Zf + 3Rn(4)

where I0, I1, I2, and Ia are the zero-sequence, positive-sequence, negative-sequence, and phase-to-ground fault cur-rents; Z1, Z2, and Z0 are the sequence impedances; and Zf

is the fault impedance. Va is the prefault voltage to neutral atthe fault location, Ia is the single-line-to-ground fault current,and Rn is the neutral resistor.

Fig. 6 shows the zero-sequence network of Fig. 1 for a single-line-to-ground fault at F1. When the neutrals are grounded


Fig. 5. (a) Sequence current flows for a single-line-to-ground fault.(b) Interconnections of sequence impedances.

through resistances, these impedances predominate, and allother sequence impedances can be ignored in the calculations.Thus, the ground fault current anywhere in the 13.8-kV systemis 500 A, and a rigorous computer calculation with all thesequence impedances modeled shows only a minor difference;i.e., a fault at bus 1 gives 499-A ground fault current, andthe sequence impedances in per unit at 100-MVA base are asfollows:

Z0 =2.5116 + j0.0290

Z1 =0.0005 + j0.0233

Z2 =0.0008 + j0.0221. (5)

Directional elements use a reference against which thequantities are compared; this reference is also known as thepolarizing quantity. These references are either zero-sequenceor negative-sequence quantities. With mutual inductance prob-lems between transmission lines, use of negative-sequencequantities provides further security.

Classic relays used current or voltage polarization or both,which are derived from external sources. Fig. 7 shows anopen-delta-connected potential transformer (PT) for voltagepolarization of the directional element.

A proper source for the external current polarization isrequired. While a CT in the neutral circuit of a delta–wyetransformer provides a suitable polarization source, a CT inthe wye–wye-connected grounded or ungrounded transformers

Fig. 6. Zero-sequence network for a single-line-to-ground fault at F1 in Fig. 1.

and in zigzag transformers is not a proper current polarizationsource [10].

This is obvious when the zero-sequence impedance connec-tions of these transformers are examined. With these classicrelays, the sequence quantity for each application must beselected for the application.

Modern ground directional relays (GDRs) consist of a com-bination of three directional elements, namely:

1) zero-sequence current polarized;2) negative-sequence voltage polarized;3) zero-sequence voltage polarized.

The selection logic makes it possible to select one or two orthe best choice logic for the application.

The zero-sequence voltage polarization does not requireexternal PTs in modern GDRs. This voltage can be internallygenerated from wye–wye PT inputs (but not from open-delta-connected PT inputs).

External zero-sequence current source is not necessarilyrequired. The relay algorithm calculates the sequence compo-nents from the line current inputs.

Fig. 8 shows a much simplified logic diagram for the grounddirectional element of the relay for low-resistance groundedgenerators. Inputs from zero-sequence and negative-sequencevoltages are shown at NAND gate 3. The low-resistance logicoperating from neutral channel current is also shown. Thelogic for the negative-sequence voltage-polarized and current-polarized elements are similar and not shown in Fig. 8. Notethat although the positive-sequence, negative-sequence, andzero-sequence currents are equal in magnitude on a single-line-to-ground fault, the sequence voltages will be much different,as the sequence impedances have large variations (5).

In Fig. 8, Z0 is measured by the relay based on

Z0 =Re [3V0(IN < θ0)∗]

|IN |2 . (6)

Similarly, in the negative-sequence logic, Z2 is calculated by

Z2 =Re [V2(I2 < θ1)∗]

|I2|2 (7)

where θ0 and θ1 are the zero-sequence and positive-sequenceline angles, respectively; i.e., from (5), θ0 ≈ 1◦ (the resistance


Fig. 7. Zero-sequence voltage source for polarization of ground fault directional relay and phase vectors on single-line-to-ground fault.

Fig. 8. Partial logic diagram of a modern MMPR.

predominates). The asterisk shows the conjugate of thecurrent.

Fig. 8 shows that IN should be greater than the positive-sequence current multiplied by a settable factor a0N and itssettings 50NFP or 50NRP, which are the set currents for thedirectional logic to operate. The setting of a0N = IN/I1 in-creases the security of directional element and prevents nui-sance tripping for zero-sequence currents of system unbalance,CT saturation, etc. For industrial systems, the unbalance cur-rents will be small, and the setting should be lower than theintended pickup of zero-sequence current settings.

For an output F32N or R32N to assert, the measured Z0 inthe forward or reverse direction must overcome the set forwardor reverse thresholds (Fig. 9). These are controlled by thefollowing equations:

Z0F setting ≤ 0, forward threshold

0.75 · Z0F − 0.25∣∣∣∣3V0

IN

∣∣∣∣ (8)


Fig. 9. Directional element characteristics of MMPR in Fig. 8.

TABLE IIISEQUENCE CURRENTS SEEN BY THE DIRECTIONAL GROUND RELAYS FOR

SINGLE-LINE-TO-GROUND FAULT IN FIG. 1 (IN THE DIRECTION

OF THE OPERATION OF THE RELAY)

Z0F setting > 0, forward threshold

1.25 · Z0F − 0.25∣∣∣∣3V0

IN

∣∣∣∣ (9)

Z0R setting ≥ 0, reverse threshold

0.75 · Z0R + 0.25∣∣∣∣3V0

IN

∣∣∣∣ (10)

Z0R setting < 0, reverse threshold

1.25 · Z0F + 0.25∣∣∣∣3V0

IN

∣∣∣∣ . (11)

VI. DIRECTIONAL GROUND ELEMENT

OPERATING LOGIC SELECTION

A. Single-Line-to-Ground Fault

Table III shows the sequence currents seen by each relayat its location. For a zero resistance fault in the resistancegrounded system, i.e., Zf = 0, the zero-sequence and positive-sequence voltages are approximately equal to line voltage (fulldisplacement of neutral-to-ground potential), and the negative-sequence voltage is approximately zero. With some resistanceto the fault, the positive-sequence and zero-sequence voltageswill be reduced, and the negative-sequence voltage will be 180◦

out-of-phase with the positive-sequence voltage. The sequencecurrents are used for setting zero-sequence voltage logic (notshown in Fig. 8).

As the relay is totally blocked in one direction of opera-tion, only one threshold setting, i.e., forward or reverse, needsbe made.

B. Double-Line-to-Ground Fault

A double-line-to-ground fault gives high positive-sequenceand negative-sequence currents, i.e., of the order of 5–8 kA.The positive-sequence and negative-sequence currents are equaland at a phase difference of 180◦. The zero-sequence current issmall, i.e., 66 A. The voltages of faulted phases are zero, andthose of the unfaulted phase rise to 20.7 kV. Thus, the positive-sequence, negative-sequence, and zero-sequence voltages areall equal in magnitude, i.e., approximately 7 kV. The zero-sequence voltage-polarized algorithm of the relay will notoperate, and the negative-sequence polarization will operatepositively.

As the fault currents in phases are high, the directional phasefunction in the same GDR (not discussed in this paper) and alsoother discrete differential relays are operative. Yet, negative-sequence option in directional ground fault function can bemade operative as a further backup.

C. Bench Testing

The relays were bench tested and had a pickup accuracy bet-ter than 99% to 101% of the set values even at low directionalcurrent setting of 10 A. CT errors must be considered. The ratiocorrection of class C accuracy CTs is limited to 10% at anycurrent from 1 to 20 times the rated secondary current at thestandard specified burden or any lower standard burden usedfor specific accuracy.

VII. CONCLUSION

1) The stray capacitance current in the distribution sys-tem should be carefully calculated. A high-resistancegrounded system can be implemented only when the straycapacitance currents are generally not more than 10 A.In most distribution systems, this limit will be exceeded,and high-impedance grounding of the generators will beimpractical.

2) When considering low-resistance grounding, the groundfault current should be examined with respect to thesensitivity of the protection schemes. A section of thestator windings toward the neutral is left unprotected, andif a fault occurs in this section, severe damage can occur,as persistent fault currents of the order of 4–5 A can causecore damage.

3) A greater percentage of the stator winding can beprotected using protective schemes, as given in theAppendix.

4) The selectivity of the ground fault protection shouldbe carefully considered when the ground currents arelowered in a distribution system. Approximately 70% ofall the faults start as ground faults, and it is imperativethat nuisance trips do not occur. Directional/differentialground fault relays become imperative to achieve thisobjective.

5) Settings of modern GDRs operating on sequence quan-tities will provide effective protection. Proper settingsrequire a study to calculate the sequence quantities as


Fig. 10. Distribution of third-harmonic voltage. (a) Normal operation, noground fault. (b) Ground fault at the neutral terminal. (c) Ground fault closeto the neutral.

Fig. 11. High-resistance grounded generator directly connected through astep-up transformer.

seen by the relays. This paper demonstrates how theseevaluations have been made in an operating mill andproven on bench testing.

Fig. 12. (a) Low pickup stator winding ground fault protection in a 100-Aresistance grounded generator using a special FFAC device. (b) Low pickupstator winding ground fault protection in a 100-A resistance grounded generatorusing an auxiliary CT and overcurrent relay.

APPENDIX

A 100% generator stator winding protection for high-resistance grounded systems is based on the distribution ofthird-harmonic voltages under normal operating and fault con-ditions. Third-harmonic voltages vary with the generator de-sign, as well as with real and reactive power outputs. Fig. 10shows such a distribution. A differential relay sensing thedifference between the generator neutral and generator lineterminals is more effective as compared to a simple voltagerelay at the neutral terminal [12]. The protection systems basedon third-harmonic voltage work well with generators connectedthrough a step-up transformer (Fig. 11). The delta windings ofthe generator step-up transformer and unit auxiliary transformer


confine third harmonics to a limited zone. Also, the straycapacitance currents from the utility source or auxiliary distri-bution do not contribute to the high-resistance grounding straycurrent calculations. The utilities’ high resistance ground theirgenerators, and 100% stator winding protection is provided.

In low-resistance grounded multiple bus-connected genera-tors with intervening impedance, the distribution of the third-harmonic voltages under normal operation and ground faultconditions cannot be precisely defined, and this system ofprotection cannot be effectively applied.

This paper shows that 16% of the stator winding (dis-counting the relay tolerances) toward the neutral end remainsunprotected.

Although no protective device is commercially available toextend the winding protection toward the neutral, a simplesystem, as shown in Fig. 12, can be used.

Fig. 12(a) shows an analog fundamental frequency alarmdevice with an input filter, contact closing at 0.03-A set-pointoutput, in terms of primary ground current. The fundamentalfrequency alarm control (FFAC) is a nonstandard device ofspecial manufacture.

An on-delay timer is introduced and gated with neutralbreaker status contacts. The auxiliary relay 94 trips the neutralbreaker. The timer is set to coordinate with 51G and 87GNsettings. This will protect 97.5% of the stator windings, and thetolerances on the pickup of the alarm unit are ±0.2%.

Fig. 12(b) shows an overcurrent relay, with digital signalprocessing, permitting selection of fundamental frequency,root mean square, and average sensing. The low pickup isobtained by selecting a relay of 1-A rating, although the aux-iliary CT secondary current is 6 A at maximum ground faultcurrent of 100 A. This requires that the overcurrent relay shouldhave adequate overload capability. At minimum setting of0.1-A pickup, 98.4% of the stator winding is protected. Theauxiliary CT has a maximum input of 1.2 A and output of 6 A;therefore, it can be a revenue metering class 0.3 accuracy tolimit ratio error.

In Fig. 1, a setting of 10 V on 59N function connected in thesecondary of the grounding transformer in the high-resistancegrounding system will detect a low-level fault of approximately4 A. Some voltage will be developed under normal operatingconditions due to third-harmonic currents, and this voltage wasmeasured to be 3–4 V. The voltage setting on 59N shouldoverride it. A time delay of 8–10 s can be provided, so thathigher level currents picked up by 87GN are first cleared.

These schemes will achieve the desirable objective of reduc-ing the generator ground current as well as protecting more than95% of the generator winding from the generator line end.

REFERENCES

[1] L. J. Powell, “The impact of system grounding practices on generatorfault damage,” IEEE Trans. Ind. Appl., vol. 34, no. 5, pp. 923–927,Sep./Oct. 1998.

[2] IEEE/IAS Working Group Report, “Grounding and ground fault protec-tion of multiple generator installations on medium voltage industrial andcommercial power systems: Part 1,” IEEE Trans. Ind. Appl.,vol. 40, no. 1,pp. 11-16, Jan./Feb. 2004.

[3] ——, “Grounding and ground fault protection of multiple generator in-stallations on medium voltage industrial and commercial power systems:Part 2,” IEEE Trans. Ind. Appl., vol. 40, no. 1, pp. 17–23, Jan./Feb. 2004.



[6] A. Wu, Y. Tang, and D. Finney, “MV generator low resistance groundingand stator ground fault damage,” IEEE Trans. Ind. Appl., vol. 40, no. 2,pp. 672–679, Mar./Apr. 2004.

[7] Electrical Transmission and Distribution Reference Book, WestinghouseElectric Corporation, East Pittsburg, PA, 1964.

[8] D. S. Baker, “Charging current data for guesswork-free design ofhigh resistance grounded systems,” IEEE Trans. Ind. Appl., vol. IA-15,no. 2, pp. 136–140, Mar./Apr. 1979.

[9] J. R. Dunki-Jacobs, “The reality of high resistance grounding,” IEEETrans. Ind. Appl., vol. IA-13, no. 5, pp. 469–475, Sep./Oct. 1977.

[10] Applied Protective Relaying, Westinghouse Electric Corporation, CoralSprings, FL, 1982.

[11] A. Guzman, J. Roberts, and D. Hou, “New ground directional elementsoperate reliably for changing system conditions,” in Proc. 51st Annu.Georgia Tech. Prot. Relay Conf., Atlanta, GA, 1997.

[12] J. Pilleteri and J. R. Clemson, “Generator stator ground protection,”in Silent Sentinels, RPL 81-3. Coral Springs, FL: Westinghouse,Aug. 1981.

J. C. Das (SM’80) received the B.A. degree inmathematics and the B.E.E. degree from Panjab Uni-versity, Chandigarh, India, in 1953 and 1956, respec-tively, and the M.S.E.E degree from Tulsa University,Tulsa, OK, in 1982.

He is currently a Staff Consultant with ElectricalPower Systems, AMEC E&C Services, Inc., Tucker,GA. He is responsible for power system studies, in-cluding short circuit, load flow, harmonics, stability,arc flash hazard, grounding, and protective relaying.He conducts courses for continuing education in

power systems. He has authored or coauthored more than 40 technical publica-tions. He is the author of Power System Analysis (Marcel Dekker, 2002). Hisinterests include power system transients, harmonics, power quality, protection,and relaying.

Mr. Das is a member of the IEEE Industry Applications Society and the IEEEPower Engineering Society. He is a member of the Technical Association ofthe Pulp and Paper Industry (TAPPI) and the International Council on LargeElectric Power Systems (CIGRE), a Fellow of the Institution of ElectricalEngineers, U.K., a Life Fellow of the Institution of Engineers (India), and amember of the Federation of European Engineers (France). He is a RegisteredProfessional Engineer in the States of Georgia and Oklahoma, a CharteredEngineer in the U.K., and a European Engineer. He is a member of the PowerDistribution Subcommittee of the Pulp and Paper Industry Committee of theIEEE Industry Applications Society. He received the IEEE Pulp and PaperIndustry Committee Meritorious Engineering Award in 2005.

Ground Fault Protection for Bus-Connected Generators in an Interconnected 13.8-KV System

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