Presented at the 2003 IEEE IAS Pulp and Paper Industry Conference in Charleston, SC: © IEEE 2003 - Personal use of this material is permitted.

APPLICATION OF A HYBRID GROUNDING SCHEMETO A PAPER MILL 13.8 KV GENERATOR

Doug Moody Vernon Beachum Tom Natali William Vilcheck, P.E. David D. Shipp, P.E.Senior Member, IEEE Member, IEEE Senior Member, IEEE Fellow, IEEE

MeadWestvaco Eaton / Cutler-HammerLuke, MD 21540 Warrendale, PA 15086

Abstract – Many paper mills and other industries useturbine generators to supply critical process steam andelectrical generation needs within the plant. The loss of agenerating unit for an extended period would result in verycostly replacement power and repair costs for any papermill. As machine insulation systems age over decades,aging mechanisms progress to increase the risk of apossible ground fault internal to the generator. AnIEEE/IAS Working Group Report [1,2,3,4] submitted in2002 discusses grounding and ground fault protection formedium voltage generator stators, highlighting their meritsand drawbacks. The report is intended as a guide forengineers installing new or upgrading existing generatorsystems to minimize industrial bus connected generatordamage from stator ground faults. This paper discusses amost recent 13.8kV generator upgrade at a paper millemploying the hybrid grounding scheme and ground faultprotection evaluated favorably by the IEEE/IAS WorkingGroup. Project tasks are described in detail. Issues anddifficulties encountered during the course of the generatorgrounding upgrade which were not mentioned in theWorking Group Report are presented for reference.

Index Terms – hybrid generator grounding, statorground fault, core damage, ground differential

I. INTRODUCTION

An IEEE/IAS Working Group Report presentingmethods of protecting medium-voltage industrialgenerators against extensive damage from internal groundfaults was presented at the 2002 IEEE/IAS AnnualMeeting. The report is comprised of four technicalpapers.� Part 1 describes the grounding problem, lists user

examples of stator ground failure, and provides atheoretical explanation for the problem and resultinggenerator damage.

� Part 2 discusses various grounding methods used inindustrial applications and offers a novel groundingapproach which maintains continuity of service,controls transient overvoltages, and effectively limitsdamage to stator iron occurring from internal groundfaults.

� Part 3 explains various ground protection schemes forthe generator grounding and system groundingconfigurations of Part 2.

� Part 4 provides a conclusion and a list of additionalresource material.

A. Working Group Findings

The conclusions and recommendations of the IEEE/IASWorking Group are repeated here because they are thebasis for the Luke Paper Mill generator upgrade. Theworking group report has shown that the extensivedamage due to core burning of faulted generator stators isbased upon two factors:1. As paper mill electrical distribution system complexity

increased, the number of source resistor groundswithin the system increased, and the total availableground fault current increased. A circuit breakerclearing time of 6 cycles and the increasingmagnitude of ground fault current creates significantburning energy within the stator.

2. Ground fault current which rises through the neutral ofthe generator will not be interrupted by tripping thegenerator circuit breaker, but will persist for severalseconds (after the field breaker trips) until the fielddemagnetizes. Recent failures have shown thatconsiderable burning damage will be done if thegenerator is low resistance grounded [1][5]. The timedecay of generator ground fault current after initialsystem clearing is shown in figure 1.

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Fig. 1 Generator Ground Fault Current

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B. Working Group Solutions Summarized

The working group advises that the solutions to thisproblem should involve several elements. They are brieflysummarized below:1. The number and ratings of low-resistance grounding

resistors should be kept to a minimum, to minimizethe system source contribution.

2. The generators should be high-resistance grounded,especially during the time after the generator circuitbreaker opens and the field excitation is decaying.

3. Hybrid High Resistance Grounding System (HHRG).Employ high-resistance grounding of the generatorand low-resistance grounding of the external powersource(s).

4. An option to item 3 is to high-resistance ground boththe generators and the external sources with the busbeing low-resistance grounded via a groundingtransformer supplied through a circuit breaker. Thisoption is effective only if adequate high-resistancegrounding can be achieved, but allows systemoperation during an uncleared high-resistance groundfault.

II. APPLICATION TO MOST CRITICAL OR AT-RISKUNITS

A hybrid grounding scheme as applied to a direct busconnected generator typical of many paper mills is shownin Fig. 2 [2],[5]. The low resistance ground interruptingdevice is opened as part of the generator tripping

sequence for a ground fault within the generator zone(See section VI for controls description). This scheme isespecially beneficial to older critical mill turbine generatorsand/or those generators with known insulation integrityproblems.

The Luke #12 generator, (13.8 kV, 40 MVA hydrogencooled) built in 1979, is such a unit. On-line partialdischarge testing conducted since 1999 has revealedhigher than normal partial discharge (PD) levels for unit#12 which indicate voids in the ground wall insulationsystem. The PD on-line activity is sensed by highfrequency capacitors (80 pf) connected at the 13.8 kVmachine terminals. Unit #12 is an asphalt- mica insulatedmachine with two turns per coil design. Present paper milleconomics favor delaying a planned rewind hopefully untilsome years into the future. The risk of delaying the rewindis managed by continued use of on-line PD monitoringtogether with the added protection of the HHRG protectionsystem. Typical mill economics show that applying theHHRG to units such as #12 yield very good value whencompared to the very high combined costs of rewindingthe stator, purchasing replacement power and steamsystem consequences, especially for the extended repairoutage periods involved in core damage repair.

A. Description of Mill 13.8 kV System

So that the new HHRG system project can be seen froma total mill system standpoint, the Luke Mill simplified 13.8kV one-line diagram is shown in Fig. 3. Both the utility tiesand both mill generators are normally in operation tosupply a total mill load of about 70 MW. The bus tiereactor is in service with all sources energized to limit thetotal system available fault current to within theinterrupting rating of the 1000 MVA switchgear. Thereactor is bypassed (by closing breaker 1-20A) wheneverany one source is out of service to prevent excessivereactor voltage drop to mill loads should the loss of thesecond source occur on the same side of the reactor.Total 13.8 kV system ground fault levels prior to theHHRG project were very high, at 3200 amps total. Thiswas comprised of 800 amps from each utility transformer,400 amps from #11 generator and 1200 amps from #12generator. In light of the noted IAS Working Group findingsand after completing a ground fault study for the Luke Mill,it was planned to reduce the total mill available groundfault current to 800A. This is further noted in section VI ofthis paper.

In summary, the goal to protect the critical mill (#12)generator required that the generator be hybrid groundedand that the system ground fault levels be reduced asnoted. This translated to various involved project tasks asnoted below:

1. Hybrid Grounding for #12 Generator - Size resistorand transformer based on system charging current,select high speed switching device and packaging ofall components in suitable enclosure.

2. Interface new #12 unit HHRG to existing millgenerator relaying and tripping schemes, withoperating indications for alarms and status.

3. Install and commission the generator HHRG system.4. Mill Ground Fault Study to reduce system level and

adjust ground relaying accordingly throughout the millsystem.

5. Implement reductions in other source resistors andnew relay settings.

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These tasks were accomplished with close teamworkbetween the outside equipment manufacturer and milllocal engineering efforts. Presently items 1-4 are completeand item 5 should be completed by June 2003.

III. DESCRIPTION OF HHRG CABINET AND DEVICES

Part of the design process was how best to retrofit theHHRG physically into the system. This had to also involvethe cabinet controls, sizing, packaging, etc. Thereessentially was no room adjacent to the switchgear itself.Also the switchgear was somewhat removed from themezzanine location where the generator wye point andexisting 200 amp (LRG) resistor were located. It wasdecided to locate the HHRG as close to the wye point aspossible. The chosen location had width and heightconstraints and was somewhat of a wet area. Since theassembly was to be built to metal-enclosed standards,proper internal clearances (internal separation for L.V. andM.V.) were also factors.

The final design provided a modular approach consistingof:1. Separate lockable M.V. cabinet.2. NEMA 3R / 4 design for the wet environment.3. Separate control cabinet mounted on the side, for

safety and at eye level.4. H.R resistor to be mounted externally on top. This

installation elected to mount it remotely.5. One foot high legs, to get cabinet above any water

ingress.6. Local/remote switch and local/remote lights.

IV. HYBRID GROUNDING SYSTEM CONTROLSINTERFACE

The crucial value and protection of the HHRG systemmust be insured by a practical and usable controlsinterface. Controls design must operate the new groundingsystem in harmony with normal generator operations andwithout a need for the operator to do additional switching.For all normal conditions the control system must providethe noted protection together with minimal monitoring toverify the system is active. In the case of a ground faultwithin the generator zone, the system must instantly applyhigh resistance grounding, provide positive indication ofthe event and lockout against any hasty and dangerousrestarting of the unit. For faults out on the mill system, theHHRG must not operate to jeopardize mill loads andsteam supply. For ease in retrofitting to existing unitcontrols, and cost constraints, the necessary wiring andcomplexity should be kept to a minimum.

A. Unit #12 Protection Overview

The new HHRG retrofit controls must be carefullyinterfaced with the existing generator protection system.For background, an overview of the existing Luke #12protection system is given to put the new HHRG controlschanges in perspective. In 2001, the #12 systemprotection was upgraded from 1979 vintageelectromechanical relays to digital microprocessor basedprotection. For a functional one-line diagram and otherdetails of this upgrade, see [5]. The new system includedtwo digital multifunction relays installed in a redundant

Fig. 3 Luke Mill Ground Fault Protective Relay One-Line Diagram

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protection scheme, with a dedicated (86) lockout devicefor each relay. At this time a new 200 amp groundingresistor was installed for unit #12. (Original was 1200amps)

The HHRG project required a review of existinggenerator tripping schemes to determine how to involvethe new vacuum switch. Initially it was planned tocontinue LRG operation of the generator and switch to (10A) HRG only for a fault in the generator zone. However totake advantage of the existing lockouts and using theflexibility of the digital relays, the HHRG switch was simplyadded to existing simultaneous tripping scheme. That is,either generator relay tripping will operate its lockout (86)device to open the low resistance (200 amp) groundingpath, per table 1. This method also provides some minimalexercising of the HHRG vacuum switch while providinghigh resistance grounding during coast-down after anysystem trip. Basically, in coming off-line, the only time theHHRG does not operate is on a normal operationsshutdown. On a turbine trip and for all electrical tripfunctions the unit is switched to high resistance groundingduring coast-down. A tripping logic diagram is presented inTable 1, which shows the addition of the new HHRGvacuum switch action.

Luke Mill Generator #12 Trip Table with HHRGSystem Additions

Trip Mode/ Gen. Field Steam HHRG AuxRelay

Device Function

MainBKR BKR Turb. Switch

CR- 87G

Simult. Trip: 24,40,46, 51N,51V, X X X X

87G, 87 X X X X X Sequential Trip* X X X X 32-1,2 Normal Operator X X X Shutdown

Alarm Only 27,59,59N

Shaded areas note when the HHRG Vacuum Switchis tripped open.

Table 1 Tripping Logic Table

All trips are processed simultaneously except for turbinetrips, which are done sequentially (main stop valve limitswitch supervised by the reverse power relay) as shown inthe trip logic table in Table 1. The HHRG Vacuum switchis tripped open as part of all relay based trippingsequences. In the table, “Simultaneous” refers to trippingeach item marked “X” at the same time, using the existinglockout relays. Note that for a ground fault in thegenerator zone, a dedicated output from either generatorrelay picks up CR-87G which seals in to hold its lockout

relay tripped against restart of unit. For other details ontripping functions see reference [5].

It should be noted that operating with the generator(s)LRG resistors open, that is leaving only the utility sourceresistors on the system, has definite merits. Total groundfault exposure is reduced but total system relaying mustbe evaluated. At islanding of the generator or for twosource operation below 400 amps, the controls mustautomatically switch the LRG resistor back in. At Luke, thisoption is being revisited as the grounding study is nowcompleted, and a PLC is available to do the logic. TheHHRG system hardware is flexible to allow this change.

B. HHRG Switching Device

Vacuum Switch Device and Operation: The new singlepole vacuum switch was available only in AC operatingsolenoid design so that an interface relay was required forthe main breaker (DC) control circuit. The HHRG vacuumswitch operation is momentary pulsed to open and pulsedto close.

C. Generator Breaker Control Circuit Interface

To eliminate the need for any new or separateswitching operation by the operator, it was decided toclose the HHRG vacuum switch on startup along with themain generator breaker. To accomplish this, a (DC)interposing relay was added to the existing breaker controlclosing circuit. At the Luke Mill, generators aresynchronized by manual operator control. With allpermissives met to synchronize the unit to the system, theoperator closes the main breaker and the new HHRGvacuum switch will close also. A simplified schematicdiagram with controls interface is shown in Figure 4.

D. Description of Operations

The system will operate as noted below without anychange in existing operator procedures. The Luke #12HHRG related controls sequence with monitoring andalarming features is described below:

1. On closing the generator main breaker at startup, thenew vacuum switch automatically closes also to placethe HRG/LRG parallel resistors in service with lowresistance grounding dominating. Indication of thenew HHRG vacuum switch position is provided at theoperator panel and at the generator main breaker.New alarms alert the operator if the HHRG system isdisabled or if the vacuum contactor does not closewith the main breaker.

2. Trip with Restart Allowed: (Turbine trips or Generatortrips except for internal ground fault.) One or bothlockout relays will trip and trip open the vacuumswitch to apply the high resistance grounding duringcoast-down. With conditions permitting, resetting thelockout relay(s) will allow restart of the unit just asbefore. The new vacuum switch stays open until thegenerator main breaker is closed at the subsequentrestart of unit, except as noted below.

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3. Trip for ground fault within the generator zone. Thedifferential ground (87G) function of the digital relaysshould operate to trip the unit (per Table 1) and latchup auxiliary relay (CR87G) to prevent the operatorfrom being able to reset either lockout relay andrestart the turbine. At the operator panel and at thegenerator breaker, special (red) indications noting“#12 Gen Ground Fault Trip” will be on. Thisindication is also latched in and supplements the“87G” flag indication on the relay, which could behastily reset and lost. Operations procedures for thisevent must clearly forbid any attempts to reset thegenerator lockout relays or any attempt to restart theunit, with instructions to contact the shift foreman andthe department superintendent immediately. Toemphasize the seriousness of the event, a bold sign(below the Ground Fault Trip indication) at thebreaker notes: “Make absolutely no attempt to restartthe turbine generator! Irreparable damage will result!Training should emphasize that the generatorwindings have failed at some point, and the unit willneed to be kept out of service for testing and probableextensive repairs. A hasty restart at this point wouldbe very dangerous, compounding damage to thegenerator.

E. Indications at Switchgear Main Breaker

At lower right on door, red and green lamps areprovided to show the position of the new HHRG VacuumSwitch. A third, amber lamp verifies that the HHRGProtection is enabled. See Picture 1. The enabled lampshould normally be “on” to prove power to the HHRGcabinet in the basement and that control switch is in the“Remote” position. These indications are also provided tothe operator via the PLC interface as noted below.

Picture 1 - At Main Breaker

F. Indications at HHRG Cabinet

Field cabinet indications are provided for control power,vacuum switch position and ground fault lamp status. Notethat no operator involvement at this panel is necessary.

G. Operator Panel Alarms and Indications

Outputs from the new system to the existing powerhouse Loadshed PLC are sent to (lampbox) alarmslocated above #12 Generator controls at the TurbineOperator Panel. They include HHRG System Enabledand Vacuum Switch Position indications and the alarm –“#12 Generator Ground Fault Trip”. This alarm will flash toindicate seriousness of the event.

H. Controls Devices Locations Summary

A summary of new hardware installed to augment thenew HHRG cabinet is as follows:

Fig. 4 Simplified HHRG Schematic Diagram with Controls Interface

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Devices at the Generator Breaker Cubicle1. HHRG Vacuum Switch Open/closed position

indications (LED’s).2. HHRG System Enabled LED.3. Generator Ground Fault Trip LED.4. Interposing relay (CR-152) to breaker close

circuit.5. CR-87G Seal-in Relay and Reset Push Button.

New Alarms/Indications at the Operator Panel1. HHRG Contactor Position Tripped open.2. Generator Ground Fault Trip.3. HHRG System Disabled.

I. Relay Diagnostics

Where digital relays are used, an auxiliary contact fromthe HHRG vacuum switch could be wired to an input of thegenerator relay for time-stamping the switching operation.This was done in the Luke system and aids in checkingHHRG vacuum switch action, the interpretation ofoscillograph tripping, and sequence of events data for anytrip incidents.

V. GROUND FAULT PROTECTION

Referring to the Tripping Logic in Table 1, one newdedicated output from each digital relay was programmedto operate for ground differential or phase differential(87G, 87) functions. This new output operates bothlockouts and also picks up a new relay, CR87G, whichseals in and prevents operators or maintenance personnelfrom resetting the 86 devices. Breaking the seal of CR87Gis accomplished with special effort by opening the door ofthe main breaker and operating a reset switch, which isboldly marked to obtain supervisory permission to do so.

A. Ground (Zero Sequence) Differential ProtectionImproves Sensitivity

Since quick sensing and clearing of internal groundfaults is critical to limit system iron damage, it is of interestto add or upgrade to ground differential (87G) protection.This protection can provide significant improvement inground fault sensitivity over conventional phase differentialrelaying. The increased sensitivity also translates to asignificant increase in extent of coverage of the statorwindings. The basic 87G protection detail is shown in Fig.2 (See ref. [5][6] for 87G function description). In the Lukescheme, the 87G function was already provided in thenoted digital relays, so only a change of neutral CT ratiowas needed. With 2000/5 phase CT’s, a neutral CT ratioof 300/5 was selected to stay within the prescribed (phaseto neutral) CT matching ratio limits of the relay. Toevaluate the 87G sensitivity, directional element becomesinoperative below a minimum neutral CT current (0.2amps) to prevent miss-operation on heavy through faults.For the 300/5 neutral CT used, the 0.2 amp cutofftranslates to 12 amps primary current. Ratioed against the200 amps for a ground fault at winding high side and sincethe fault driving voltage along the winding to neutral isproportional, this shows that only 12/200 or 6% of windingis below the 87G sensing threshold. Consequently, withthe noted CT ratios, the 87G function will protect 94% ofthe winding. By comparison, conventional phase

differential relaying with 2000/5 CT’s, and a pickup of 0.2amps (80 amps primary) protects only 60% of the winding.The advantage of the 87G function is clearly significant,particularly where the resistor rated current is smallcompared to phase CT ratio. This is especially importantin the case of generator single source operation whereavailable ground current is limited to 200 amps.

B. Neutral Overvoltage (59G) Protection

Directly sensed off the HHRG secondary resistor at the240 volt level and wired to inputs of both the digital relays,this function provides backup to the differential protection.It also provides generator ground fault protection in theevent that the generator LRG is inadvertently left open.Although pickup of the relay is sensitive, with setting of 5volts, the response must be delayed to coordinate withsystem ground fault tripping of both feeder and tie circuits,so delays of one second or more are typical. After finalconsiderations, the Luke settings for this function waschanged to "Alarm Only".

VI. LOW RESISTANCE GROUNDING RE-DESIGN ANDGROUND FAULT PROTECTION CONSIDERATIONS

The low resistance grounding (LRG) and ground faultprotection system at the mill are key factors in controllingground fault damage. As concluded by the IEEE/IASWorking Group, the increase in available fault current andthe clearing time of the ground fault protection is one ofthe two factors that impact the extent of generator damagedue to core burning of faulted generator stators. Up to thispoint, this paper has concentrated on the internal groundfault component of the generator ground fault. However,the total external ground fault in-feed must also becontrolled. For example, extrapolating the arc energyreleased as determined in [1][10], the energy from theinternal 400A resistor is approximately equal to 1400A’ssystem in-feed for 6 cycles. It is therefore important toevaluate the LRG and ground fault protection systems andlook for ways to improve them. In addition to limitinggenerator damage, this exercise can also improve overallsystem protection and damage limitation.

After evaluating the existing LRG system at the mill, itwas determined that the total available ground faultcurrent was at an unacceptably high level. This sectiondiscusses the resulting LRG re-design, which has beenproposed for the paper mill and ground fault protectionissues associated with it.

A. Purpose

The main purpose of the LRG re-design is to limit theavailable ground fault current to 1000A or less whilemaintaining adequate system protection. Presently, theground fault current of the 13.8kV system is limited to2200A. Limiting the ground fault current to a value under1000A will greatly reduce equipment damage that wouldnormally result during a ground fault. In order to preventcable shield damage during ground faults, 1000A isconsidered a safe maximum ground fault current level forLRG systems [9]. Since ground faults are the mostcommon type of fault that occurs in electrical distributionsystems, reducing the amount of equipment damage

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during a ground fault will result in significant economicalsavings.

The result of the LRG analysis was to limit the groundfault current to 800A. This will be achieved by installing200A grounding resistors at all four system sources. Insome cases the existing LRG grounding resistors can bereconfigured to achieve the desired current. In this case,however, they could not be reconfigured, and newgrounding resistors will have to be installed.

B. Fault Energy And Equipment Damage Considerations

The amount of equipment damage that occurs during aground fault can be gauged by looking at the amount ofenergy released during the fault. The amount of energyreleased during a fault is proportional to the Ikt of the fault,where I is the fault current and t is the fault duration inseconds. K is between 1 and 2 with k=2 being a purelyresistive arc [1][10]. Table 2 illustrates the Ikt for differentfault values of I, and t (k=1.5 and 2 are shown in Table 2).Limiting the ground fault current to 800A will reduce Iktfault energy to between 13% and 22% of what is availablewith the present system configuration. A design-goal of

800A maximum ground fault current was selected for thissystem for the following reasons:

� It is below the approximate 1400A damage thresholdfor 6 cycle system clearing noted in section VI, andlow enough to keep over-all equipment damage to aminimum and not compromise cable shield integrity(provided that proper ground fault protection isapplied).

� It is high enough for most of the existing protectiverelays to sense and properly operate during a groundfault.

C. Relay Sensitivity Requirements

The overall system configuration is shown in Figure 3.Typically, the system is operated with all four sources inservice and all breakers closed (except breaker 1-20A).When three (or less) sources are in service, the reactor isbypassed by closing breaker 1-20A and opening breaker1-20.

Normally, all four 13.8 kV sources are in service(exceptions are listed below). The ground fault protectionscheme must, however, be able to reasonably handle allthe following contingency operation scenarios:

1. Generator outages: No.11 Generator is taken downfor one week, approximately twice a year. No.12Generator is taken down approximately once everytwo years. Major Turbine-Generator outages arescheduled once every seven years, for about threeweeks duration (This is the longest scheduled unitoutage).

2. Total Mill scheduled outages: scheduledapproximately once every 30 months, mostly forcleaning mill 13.8 kV switchgear and field distributionequipment.

3. Planned utility outages: One tie line only - substationmaintenance is typically scheduled about once everytwo years for either transformer/ breaker supply.

4. Island Operation (generators only, no utility service):Very infrequently, only with major substation problemsinvolving the total station or from an unexpected utilitytransfer trip to both paper mill substation breakers.This may occur about once every three years.

Based on these contingency operating conditions,implementing the grounding re-design will result in thefollowing:

a) The maximum available ground current under normaloperation will be 800A.

b) The practical minimum available will be 400A with twosources in service.

c) The absolute minimum available ground fault currentwill be 200A with one source in service (occurredonce in 15 years for 30 minutes).

d) HRG normal operation (versus LRG) of bothgenerators would result just over 400A total and isbeing considered as noted at end of section IV.

Therefore, the ground fault protection scheme mustoperate adequately for the 400A to 800 A available groundfault conditions. For the rare case of the 200A condition,the ground fault protection will be expected to operate at atolerably reduced performance level.

D. Adequacy of Ground Fault Protection:

For the ideal situation, all ground fault protective deviceswould be able to detect 10% of the available ground faultcurrent. However, because of the complexity / size of thissystem, the existing protective relay types, and existingCT ratios, (some at 3000/5) it is not practical (both from aneconomic and systems reliability perspective) to meet the10% criterion everywhere. As is with all fault protectionschemes, some compromises must be made. Based onthe fact that most ground faults are expected to be in therange of 60% to 70% of the maximum available, a morerealistic (yet adequate) design criteria was developed forthis system. Therefore, in order to provide adequateground fault protection, the following protective relaysensitivity criterion was established for the paper mill. All

cycles 2200A 800A%

energy 2200A 800A%

energy

0.5 40.2 5.3 13% 0.9 0.2 22%1.0 80.8 10.7 13% 1.7 0.4 22%5.0 403.2 53.3 13% 8.6 1.9 22%6.0 484.0 64.0 13% 10.3 2.3 22%

30.0 2,420.0 320.0 13% 51.6 11.3 22%60.0 4,840.0 640.0 13% 103.2 22.6 22%

Fault Time:

Table 2RELATIVE FAULT ENERGY

I2T x 103 for fault current of:

I1.5T x 103 for fault current of:

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were readily accomplished with existing relaying except asnoted.

1. Primary ground fault protection on feeders (50Gdevices using zero-sequence CT's) must be able todetect at least 10% of the minimum available groundfault current. This covers high impedance faults inload transformer windings.

2. Primary bus and inter-tie protection relays (87B and87R) must be able to detect at least 50% (preferably10% to 40%) of the available ground fault current withtwo sources in service (i.e. must be able to detect atleast 200A). This will require changing the Bus 1(87B) relays.

3. Secondary ground fault protection (51G devices onutility transformer source neutrals) must be able todetect at least 50% (preferably 10% to 40%) ofminimum available. These will actually be set about25% per the utility engineers.

4. 67N devices must be able to detect at least 50%(preferably 10% to 40%) of available ground faultcurrent when two sources are available. This meansthat the 67N applied at the source breakers will haveto detect at least 100A, and the 67N at the bus tiebreakers will have to detect at least 100A.

5. 51N devices at source breakers and bus tie breakersshould be able to detect at least 50% (preferably 10%to 40%) of available ground fault current when onlytwo sources are available. This means that the 51Napplied at the sources should detect at least 200A,and the 51N at the bus tie breakers should detect atleast 100A.

6. The 87PW relays (pilot wire differential on 3000/5CT’s) on the incoming utility lines are not sensitiveenough to adequately detect ground fault currents forany of the contingencies. Due to the high cost ofreplacing these relays, it is instead planned that the67N trip output at breakers 1-30 and 2-02, be tied intothe associated 87PW relays as an external transfertrip. The 87PW at the paper mill bus should thensend a trip signal to the utility end; thereby givingrelatively faster tripping than waiting for the fault toburn into a major phase-to-phase or 3-phase faultbefore the 87PW would otherwise trip.

In summary, low-level ground faults in the utility tiecircuits will be taken care of by using the control aspectsof the 87PW relay. The effect will be rather fast clearing(within 0.32 seconds). Since the utility service cables areaerial on messenger, they are easily accessible. Groundfaults here would be easily fixed at minimal costscompared to the damage that might occur to thegenerators if the LRG system is left "as is".

In order to achieve the above listed sensitivityrequirements, some relay changes will be necessary. AtLuke, relaying upgrades [5] in 2000 provided digital relayssensitive enough to meet most of the requirements. Asummary of changes required are listed below:

� Change ground settings, most relays� Replace one set of bus differentials� Commission Zero Sequence feeder protection� Add 87G relays for utility transformers� Install new CT’s for sensitive generator 87G� Change utility grounding resistors/CT’s

� Add 67N transfer trip from mill to pilot wire relayson utility lines

VII. THINGS TO REMEMBER

Since this is the first known installation using this designconcept, a very thorough evaluation on all design aspectshad to be considered. Since some were almostoverlooked, a review list is noted for reference:

A. Checklist of Significant Items to Address

1. Vacuum Switch: It has to be rated for the dutycomplete with clearing time comparable to thebreaker clearing time (< 7 cycles).

2. Vacuum Switch Control Power: Most come with 120VAC. The switchgear has 125 VDC.

3. Wye Point Surge Protection: Applying a LightningArrester at the wye point assures that any vacuumswitch induced switching transients do notcompromise generator insulation.

4. Cabinet packaging: This had to match confinedspace, environment, maintain clearances for BIL,cable bending radius within cabinet.

5. Out of Sight / Out of Mind: Designed remote switchposition indication such that operators would notforget the HHRG.

6. Harmonics: A 3rd harmonic filter was installed to keep3rd harmonic voltage out of the controls and protectiverelaying.

7. Generator Protective Relaying: Must simultaneouslytrip vacuum switch with main breaker. Decide if onlygenerator ground protection or all the generatorprotection trips the switch.

8. Generator breaker: As the main breaker closes, thevacuum switch must close - including with thegenerator breaker in the test position.

9. Control power: Feed only critical control from UPS(e.g. not the cooling fans).

10. 59G Relay: Decide to locate the 59G relay at HHRGor at the generator protection location.

11. Maintenance: Develop a schedule for HHRG systemin line with other switchgear / relay testing schedules.

VIII. HHRG INSTALLATION

The HHRG equipment is well designed and comes wellpackaged in three component enclosures: mediumvoltage, control, and the HRG ground resistor (set for 6.4amps). The control enclosure typically comes from thefactory mounted on the side of the M.V. enclosures, butcould be off mounted if required. The ground resistor forthe system is also normally designed to be mounted onthe top of the M.V. enclosure. This too, can be offmounted to fit the user's needs. (In the Luke system, thesecondary resistor was off mounted next to the original200 amp resistor below the generator.). Assembled as athree component unit, the HHRG equipment is compact.The assembly is 49 inches wide, 24 inches deep and 92inches high (with the resistor mounted on top) and 72inches without the resistor. A separate surge arrester isoff mounted and was installed as close as possible to theneutral summing point (applied Y point to ground) of thegenerator.

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The external wiring requirements for the system areusually going to be small. The HHRG cabinet requires a120 VAC source for its controls, and heater/fan units. Inthe Luke Mill project, an existing Uninterruptible PowerSupply (UPS) feed was used for HHRG critical controlssupply. Other cabinet interconnections are required to thenormal low resistance ground resistor and a trip signal toand/or from the generator breaker for the vacuum switch.A 59G relay is included in the control section of the HHRGunit and terminals are provided to supply voltage to anexternal protection quality relay with a 59G function.Installing the surge arrester and properly tying thegrounding together is the final step. The installation at theLuke mill required approximately five (12-hour) shifts tocomplete and was completed during the scheduledOctober 2002 Total Turbine-Generator Internal Outage.The Luke installation also duplicated the local HHRGcabinet indication lights at the generator breaker asdescribed in the Controls section. Though optional, this isrecommended because it provides valuable monitoring ofthe HHRG system from the remote main breaker. Thisfeature required a seven-conductor cable between themain breaker and the HHRG unit. A second similar cablewas installed from the HHRG system cabinet to the mill’sexisting Load Shedding PLC cabinet for routing HHRGstatus/alarms to the Turbine Control Room.

A final word on the installation: The three things, in theinstallation of this system that require the most attentionare: GROUNDING - GROUNDING - GROUNDING! Thenew HHRG installation provided the incentive andopportunity to completely inspect and upgrade the groundwiring for this machine. All connections were opened,cleaned and remade. Where necessary, new cable wasinstalled. (For example a new and shorter cable from thenew phase surge arrester, to machine frame.) Newgrounding conductors were added for the HHRGcomponents resulting in a reconfiguration of some parts ofthe original grounding. The main thing to remember is thatthe generator frame ground, the low resistance resistorground and the high resistance ground resistor ground areall grounded to the same point. On older units it is typicalto find corroded, loose grounding joints or poorly groundedarresters, etc., so these remedial efforts are important forthe grounding integrity of the new HHRG system and alsoto insure effective transient protection for the generator.

IX. CONCLUSIONS

The HHRG system was installed and operational afterthe October 2002 total internal outage on the Luke #12Turbine Generator unit. Startup of the system went well ,and the design has been well received by Operations andMaintenance. To date the HHRG system has performedas per design over several months of operation. Thisperiod included one turbine trip incident where reversepower relaying operated to activate the HHRG transitionon coast-down (as per Table 1) As for status of thegenerator, no immediate plans exist to rewind the unit, butcontinued on-line PD monitoring data will be trended toassess the insulation integrity. This monitoring, togetherwith the protection afforded by the new Hybrid Grounding,has significantly delayed concerns for a rewind of thegenerator and hopefully some years of additional servicefor this critical unit can be realized. The option of normalHRG operation of generator(s) is seriously being

considered pending logic and wiring needed for automaticswitching to LRG as needed to handle islanding and twosource contingencies.

X. REFERENCES

[1] IEEE Working Group on Generator Grounding, P.Pillai, chair, A. Pierce, B. Bailey, B. Douglas, CMozina, C. Normand, D. Love, D Baker, D.Shipp, G Dalke, J. Jones, J. Fischer, J Bowen, L.Padden, N. Nichols, R. Young, N.T. Stringer.“Grounding and Ground Fault Protection ofMultiple Generator Installations on MediumVoltage Industrial and Commercial Systems, Part1: The Problem Defined”. IEEE IAS Conferencerecord, October, 2002.

[2] IEEE Working Group on Generator Grounding, P.Pillai, chair, A. Pierce, B. Bailey, B. Douglas, CMozina, C. Normand, D. Love, D Baker, D.Shipp, G Dalke, J. Jones, J. Fischer, J Bowen, L.Padden, N. Nichols, R. Young, N.T. Stringer.“Grounding and Ground Fault Protection ofMultiple Generator Installations on MediumVoltage Industrial and Commercial Systems, Part2: Grounding Methods”. IEEE IAS Conferencerecord, October, 2002.

[3] IEEE Working Group on Generator Grounding, P.Pillai, chair, A. Pierce, B. Bailey, B. Douglas, CMozina, C. Normand, D. Love, D Baker, D.Shipp, G Dalke, J. Jones, J. Fischer, J Bowen, L.Padden, N. Nichols, R. Young, N.T. Stringer.“Grounding and Ground Fault Protection ofMultiple Generator Installations on MediumVoltage Industrial and Commercial Systems, Part3: Protection Methods”. IEEE IAS Conferencerecord, October, 2002.

[4] IEEE Working Group on Generator Grounding, P.Pillai, chair, A. Pierce, B. Bailey, B. Douglas, CMozina, C. Normand, D. Love, D Baker, D.Shipp, G Dalke, J. Jones, J. Fischer, J Bowen, L.Padden, N. Nichols, R. Young, N.T. Stringer.“Grounding and Ground Fault Protection ofMultiple Generator Installations on MediumVoltage Industrial and Commercial Systems, Part4: Conclusions and Bibliography”. IEEE IASConference record, October, 2002.

[5] C.J. Mozina, D.C. Moody. ”Mill Benefits fromUpgrading Generator Protective Relaying”.Conference Record of 2002 Annual Pulp andPaper Industry Technical Conference, Toronto,Canada, pp. 16-30.

[6] “IEEE Tutorial on the Protection of SynchronousGenerators”, IEEE Power Engineering SocietyTutorial 95TP10.

[7] D. D. Shipp and F. J. Angelini, "Characteristics ofDifferent Power System Neutral GroundingTechniques", Society of Petroleum Engineers,Electrical Submergible Pump Workshop Record,1994. and IEEE Industry Applications SocietyTechnical Conference Record, October, 1988.

[8] Donald Beeman, Industrial Power SystemsHandbook, McGraw Hill for General ElectricCompany, 1955.

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[9] P. Hamer and B. Wood., “Are Cable ShieldsDamaged under Ground Faults” IEEETransactions on Industry Applications, Vol.1A-22,No. 6, November/December 1986, pp. 1149-1155.

[10] L. J. Powell, “The Impact of System GroundingPractices on Generator Fault Damage,” IEEETransactions on Industry Applications, vol. IA-34,No. 5, Sept./Oct. 1998, pp. 923-927