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Generator excitation system considerationswhen installing a used turbine generator unit

B Y R O B E R T S . J O R D A N , R I C H A R D C . S C H A E F E R ,

J O H N A . E S T E S , J R . , & M I C H A E L R . D U B E

E Y E R -

H A E U S E R

Company owns

a market soft-

wood pulp manufacturing

facility at Port Wentworth,

Georgia, and the company was

looking for a way to reduce

manufacturing costs. It was

determined that installing a

used steam turbine generator at

the plant would be a viable way

to reduce manufacturing costs.

The unit would displace purchased electrical energy with “in-

house” generation during times that the plant could produce

the energy for less than it would be charged by the electric

utility. During these times, the unit would be operated in a

mode such that the electrical energy flowing into the plant

through the utility intertie would be kept to a minimum (tie

line control mode). During other times of the year, providing

that it was economical, the

plant could sell electrical ener-

gy to the utility. Once the

unit was purchased, and the

degree of reconditioning and

repairs to the turbine and the

generator had been deter-

mined, the next major deci-

sion was which of the auxiliary

systems could be reused.

This article covers the

process involved in evaluating

whether or not to reuse the

generator’s original compound excitation system and, if

replaced, the type of excitation system that should be installed:

compound or potential bus-fed type. We discuss the issues

encountered during the evaluation process, the expectations

desired, the decisions made, and the outcome achieved as a

result of the final decision to replace the existing compound

excitation system with a potential bus-fed excitation system.

© EYEWIRE

W

1077-2618/05/$20.00©2005 IEEE

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Project ScopeWeyerhaeuser Company’s Port Wentworth facility manu-factures softwood market pulp. The heart of the plant’sutility system is the Recovery and Utility Complex, con-sisting of two large 600 psig, 750 °F boilers and a radial-ly configured, 13.8-kV electrical power-distributionsystem (PDS). The PDS consists of 1,000-MVA, 15-kVswitchgear; a 30-MVA, 46/13.8-kV utility tie, and a 56-MVA, 13.8-kV single-extraction, back-pressure turbinegenerator (#4 TG). One boiler is a base-loaded 450,000lb/hr recovery boiler. The other boiler, which is a combi-nation unit, is rated 500,000 lb/hr (on gas oroil)/400,000 lb/hr (on just bark) and operates as theswing unit. The plant’s electrical load is approximately30 MVA. In recent years, the plant has shut down alinerboard machine, as well as the complete pulp milland parts of the wood-handling facility that supplied it.While this left the plant with an excess of steam capaci-ty, the plant must still regularly buy around 6–8 MVA ofelectrical energy. This occurs because the output of the#4 TG is a function of the connected process steamdemand flowing through its turbine. Since a large por-tion of this steam load “disappeared” with the above-mentioned shut downs, the #4 TG is not able to producethe plant’s entire electrical requirement. By adding acondensing turbine generator unit to the plant, the gen-erator could supply the “shortage” as well as take care ofelectrical load swings and even regulate the plant’s volt-age should it ever become disconnected from the utility.

It was determined that if a usedcondensing steam turbine genera-tor in good condition [hereafterreferred to as the new turbine gen-erator, new unit, or TG#5 (Figure1)] could be located, tested, pur-chased, and installed, it would be aviable way to help cut manufactur-ing costs at the Port Wentworthfacility. The new generator, whichwould supply the plant’s additionalelectrical demand, would be oper-ated in a tie line control mode witha set point of 0 MW. This mode ofoperation would keep the incom-ing electrical energy flowingthrough the utility tie at or nearzero. At just how close to “zeroflow” the tie would remain woulddepend on the dead band and thetime constant of the new turbine’soverall speed control system. Thenew unit would operate in thismode during the parts of the yearwhen “in house” electrical energycosts were less than those chargedby the electrical utility. Duringthe balance of the year, should itprove to be profitable, the plant’scontract with the utility wouldallow it to sell excess electricalenergy to the utility.

A project scope was defined, and funds were approved.The major components of the project to be installed atthe plant consisted of the turbine, the generator, and theinfrastructure to support and connect the new equipmentto the Recovery and Utility Complex. In addition, therewere many auxiliary systems required to support the tur-bine and the generator such as the following:

1) turbine stop valve and its controls2) turbine control valve and its actuator3) turbine condenser, including large condensate recir-

culation pumps4) turbine drain and leak off system5) turbine governor6) turbine control panel7) turbine supervisory instrumentation system8) two-cell cooling tower with variable-speed fans9) generator excitation system

10) generator grounding system11) generator protective relaying system12) generator supervisory instrumentation system13) generator control panels—both local and remote14) generator’s hydrogen cooling system, including its

control panel15) combination lubrication, bearing sealing, and

hydraulic control oil system16) turning gear assembly and its controls.

Although the generator met or exceeded acceptableelectrical test criteria, the unit was approximately 35years old. The project scope did not include funds for a

generator stator rewind. Howev-er, funds were available for therotor rewind, if necessary.

Discussions were conductedwith the plant’s major loss carrierand several generator specialists inorder to determine a “course oftreatment” for both the stator andthe rotor. All agreed that the gen-erator stator windings had exceed-ed their “design life” (30 years),but in view of the test resultsobtained prior to purchasing theunit, the unit should still have“some” useful life left.

It was decided that a mini-mum “clean up” was all thatwould be done to the stator wind-ing before reenergizing the gener-ator. It was a calculated risk, butthe project team felt that condi-tions were favorable, althoughthere was no guarantee that theunit would continue to operatewith its present windings longenough to obtain the project’santicipated return on investment.

Similarly, the generator rotormet or exceeded acceptable elec-trical test criteria. Hence, it wasdecided to send the generator’srotor out to a machine shop to

New turbine generator and reactor installed at

the recovery and utility complex. The Quon-

set-type “building” on the ground behind the

TG building gets lifted into place over the TG

for weather protection.

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have its collector rings resurfaced, itswedges retightened and the completerotor rebalanced. Similar refurbish-ment was done to the turbine rotor,the turbine stop valve, and the con-trol valves, along with the controlvalve’s actuator.

Once the above decisions weremade with respect to the turbine gen-erator proper, the major remainingconsideration was whether or not tojust reuse, recondition and reuse, orreplace all the various auxiliary sys-tems. These decisions were made on asystem-by-system basis.

The Turbine Generator SystemThe turbine generator (unit) that wasobtained for the project was manufac-tured circa 1967. It has a condensingturbine with four uncontrolled extrac-tion ports and was originally rated22,000 kW. Its synchronous generator is a hydrogen-cooled unit originally rated 29.4 MVA, with a power fac-tor (PF) of 0.85 and a nominal stator voltage of 13.8 kV.The generator’s rotating field is rated 409 A at 250 Vdc(102 kW) and originally supplied, via collector rings,from a compound excitation system.

The purchased system also included all auxiliary sys-tems for both the turbine and the generator. Since itsinstallation in 1968, the unit had been operated as a base-loaded unit for a utility located in the Great Lakes region.The unit operated nearly continuously until 1993, whenit was shut down for a modernization and a major rerateof the turbine. Its turbine was mechanically rebuilt andrerated to 29,000 kW, thus allowing the generator todevelop and deliver its full range of capabilities. At thesame time, the original hydraulic governor was replacedwith an electronic governor, and both the turbine and thegenerator were extensively instrumented with tempera-ture and vibration probes, all of which reported to a newsupervisory control system and data logger. The generatorrating remained the same.

The unit was recommissioned again as a base-loadedunit and ran until 1997, at which time the entire plantwas decommissioned and shut down. The three turbinegenerator units at the plant were mothballed by havingthe turbine generators enclosed, on the operating level,in electrically heated enclosures of closed cell foam. Theunits had desiccant strategically placed within theenclosures to keep the units dry. At some time subse-quent to the decommissioning of the plant, all power tothe plant was shut off and subsequent changes of thedesiccant were suspended, resulting in the turbine gen-erator units lying fallow.

During the month of October 2002, the owner wascontacted. With certain preconditions having been met,the unit was torn down, inspected, and tested with theaid of a temporary electrical generator (and a constantvoltage transformer to run the test equipment), a dcwelder to dry out the windings prior to testing, and

kerosene heaters to remove moisturefrom the immediate area of the genera-tor windings (Figure 2). This was doneas the temperature outside (and, subse-quently, inside) the plant began todrop in preparation for greeting theupcoming Great Lakes winter.

Subsequent to satisfactorily passingboth mechanical and electrical inspec-tion and testing, the unit was pur-chased in early November. Thecollecting of the engineering and man-ufacturer’s drawings, the tagging of theequipment, the disassembly, and pack-ing the parts and pieces into shippingcontainers began in earnest duringNovember and continued into mid-December of 2002. The containerswere shipped to site at Port Went-worth and arrived during the month ofJanuary 2003.

Design ConsiderationsAlthough the design work on the project began inNovember, immediately after the unit had been pur-chased, the design process and all the associated decisionswere exacerbated by several factors.

1) The aggressive schedule did not allow time for thor-ough investigation or documentation of the controlinterconnections prior to dismantling the originalinstallation.

2) The existing documentation and spare parts werefound in a state of “disarray.”

3) Once the existing engineering and manufacturer’sdocumentation was reviewed, sorted, and labeledwith project equipment numbering, it needed to beentered into a project database.

The project team faced an extremely aggressive pro-ject timetable, since the most expensive electrical energythat the plant purchased was the energy delivered dur-ing the warm months of the year, i.e., from June through

Turbine generator undergoing inspection and test in situ at

the decommissioned utility plant prior to purchase.

2

INSTALLING AUSED STEAM

TURBINEGENERATOR AT

THE PLANTWOULD BE AVIABLE WAYTO REDUCE

MANUFACTURINGCOSTS.

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September. The plant wanted the unit operational as soonas possible after 1 June 2003. While this commissioningdate was considered unachievable, it was incumbent uponthe project team to make decisions in a very timely man-ner in order to achieve the unit’s commissioning at theearliest practical opportunity to maximize the company’sreturn on its investment.

Evaluation Process for type of Excitation SystemAs mentioned previously, the first consideration withregard to the unit’s excitation system was whether toreuse, recondition and reuse, or replace the compoundexcitation system. The decision process included evaluat-ing the pros and cons of reusing the existing excitationsystem. The pros and cons are listed in Table 1.

After evaluating the pros and cons, it was decided thatthe existing compound voltage regulating system shouldbe replaced. The next decision was to decide which type ofvoltage excitation system to employ: a compound type or apotential bus-fed excitation system.

The Excitation SystemThe compound-type excitation system combines an out-put from a power potential transformer (PPT) connectedto the generator high voltage terminals combined with

the output from power current transformers one in eachphase of the generator. The combined output of the PPTwith the power current transformers provides a vectoraddition of voltage that is rectified via a silicon-con-trolled rectifier (SCR) bridge and applied to the field ofthe generator. An automatic voltage regulator monitorsthe terminal voltage and determines the amount ofpower to be applied to the field of the generator tomaintain constant output at the generator. Should afault occur in the PSD, the compound excitation systemis designed to provide current support, typically for 10s, depending upon the design characteristics of themachine, in order to provide enough time for the gener-ator protection to clear the fault. See ANSI C50.13.

During a fault, the generator terminal voltage will dip,depending upon the impedance between the generator andthe location of the fault (Figure 3). With a compound exci-tation system, the fault current produced by the generatorwill supply power to the excitation system via the power-current transformers to supply power to the field of thegenerator, thus maintaining the fault current for enoughtime to provide relay coordination for breaker tripping.

Where nearby generation provides adequate fault cur-rent support to achieve disired protection coordination, acompound excitation may not be required.

TABLE 1. ITEMS CONSIDERED IN THE EVALUATIONOF WHETHER OR NOT TO REUSE THE EXISTING EXCITATION SYSTEM.

Pros Cons

1) In all probability, reusing 1) The equipment was on the manufacturer’s “Obsolete Equipment List” the equipment would result resulting in parts not being readily available from the manufacturerin the least capital cost. and, more than likely, technical service would not be available in a

timely manner

2) Parts were available from 2) The equipment contained parts that had very long lead times, namelyafter market suppliers. namely power saturable current transformers, which would require 17

weeks to replace if they failed.

3) The existing regulator was an analog regulator subject to the normal component value drifting due to both temperature variations and aging.

4) The MVA capabilities of the generator could be extended via better protection and limiter circuitry.

5) Overexcitation limiting used to prevent rotor overheating is not available with the existing system, while the generator protection is limited to generator field overvoltage or volts/hertz.

6) Manual control does not track the voltage regulator, hence transfer to manual control could cause a system upset if not continuously monitored by the operator.

7) Increased automatic control via distributive control system or PLC cannot be supported by the existing hardware.

8) Systems now require better operating performance and better response time for improved transient stability.

9) Cleaning existing equipment to determine if it were still operational would take a great deal of engineering time and construction effort, which translated to a substantial cost with the possibility of little or no return.

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Compound excitation systemswere very popular in the early 1970sand before, prior to the utility net-work interconnected systems wherefault current could not be derived byother sources.

A potential bus-fed excitation sys-tem is unlike a compound type staticexciter because it utilizes only a PPTconnected to the generator terminals toprovide excitation power (Figure 4).The output of the power transformer isconnected to a six-thyristor powerbridge that is controlled via a firingcircuit and voltage regulator.

The bus-fed excitation system isdesigned to provide a level of field forcing that exceedsthe nominal requirements of the field during steady-stateloading at rated kilovoltamperes and rated PF. Typically,the field-forcing level is a minimum of 150% of thenominal full load requirements [7]. During a fault, thevoltage to the power bridge will drop by the percentageof the voltage drop at the generator terminals. Hence, ifthe terminal voltage drops by 30%, the bus-fed excita-tion system would still be able to deliver 105% fieldexcitation based upon 150% field forcing.

For the new Port Wentworth generator, the full loadfield amperes are 409 A with a hot-field resistance of0.485 �. This results in a field voltage of 185 Vdc for a320 Vac nominal PPT secondary. The 6-SCR bridge hasa nominal 250 Vdc rating with a maximum field forc-ing voltage of 275 Vdc or 2.02 p.u. from nominal full-load voltage. The high fieldforcing will result in extremelyfast voltage response. Additional-ly, should the terminal voltagedrop to 70%, the exciter systemwould still be able to provide140% field forcing.

Another important considera-tion of one type excitation systemversus the other is cost. Thepotential bus-fed excitation sys-tem is approximately half thecost of the compound excitationsystem, and with field forcing ofthe magnitude discussed above,the risk of insufficient fault cur-rent support for the system isminimized.

It was decided that since theoriginal plant generator (G4), wasrated 56 MVA with a brushlessexciter and a permanent magnetgenerator (PMG), fault currentcould be provided from thismachine if it became an issue ofconcern. It was felt a compoundsystem was not required, and apotential bus-fed excitationwould be suitable.

Although not specified, the newexcitation system would be digital,based upon a microprocessor designand taking advantage of enhancedfeatures that would allow maximumuse of the machine capability andunit field protection. These featureswould include under and over excita-tion limiters, volts/hertz limiter, andauto tracking between voltage regula-tor and manual control for bumplesstransfer. Protection included fieldover current and field over voltage,loss of field, and automatic transfer tomanual control in the event of loss ofvoltage sensing.

The new static exciter was specified to require 1/4%voltage regulation and a field current regulator for com-missioning. Other control modes found to be advanta-geous were Var and PF control. The Var/PF control actsas supplementary loop controller that allows the voltageregulator to respond quickly after a fault, but as a sup-plemental control, it will slowly integrate the Var or PFsetpoint back to normal after the system recovers fromthe disturbance. The use of Var/PF control would enablethe operator to maintain constant vars without constantmonitoring (Figure 5).

Figure 5 shows the contact inputs or RS 485 serialcommunication port for connection to a plant controlsystem for operation of the excitation/generator system.For startup and shutdown, the excitation systemincluded an ac field breaker to interrupt the power

THE CHECKOUT OF THEEXCITATION

SYSTEM WENTEXTREMELYSMOOTHLY

AND RAPIDLY.

Simplified potential bus-fed excitation system.

Generator Field

Static Exciter

AVR

GEN.Breaker

Power Potential

Transformer

52

Generator Transformer

Line ImpedanceInfinite

Bus

4

Simplified compound excitation system.

Generator Field

Static Exciter

GEN.

AVRPower

Potential Transformer

Power Current

Transformer 52

Breaker

Line Impedance

Infinite Bus

3

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input to the 6-SCR rectifier bridge. A field flash con-tactor with a series resistor is used to initiate and auto-matically build generator voltage initially duringstarting. An automatic disconnect opens the field flashcontactor when the generator voltage reaches a presetvoltage level. A field discharge resistor combined withtwo power SCRs connected antiparallel is used to dis-charge the field energy when the ac field contactor isopened at shutdown.

The new excitation system included voltage match-ing to eliminate the need for the operator to adjust thegenerator voltage raise/lower controls to match the busvoltage. The use of the voltage matching feature wouldspeed the process of having the generator synchronize tothe bus and ensure the generator voltage is higher thanthe bus voltage to ensure vars would be exported at timeof synchronization.

With future requirements imminent by the NorthAmerican Electric Reliability Council (NERC), animportant feature noted was oscil lography andsequence of events capture with the new excitation sys-tem. With the new equipment, events, such as distur-bances, could be logged automatically for any systemabnormality, including terminal voltage, line current,field voltage and field current, vars, kilowatts, etc., in

a comtrade file for download into a viewing softwareprogram. Sequence of events recording could providecontinuous monitoring of the excitation system for anychange with a date-and-time stamp to help diagnosisproblems in the system.

Design EffortFor this project, Weyerhaeuser Company would contractout the design interface of the excitation system. Thecontractor would provide a detailed bill of material,including cabling, routing, and terminations; designinterface drawings; system elementaries; excitationequipment; checkout; and commissioning of the excita-tion system, plus training to plant operators.

Weyerhaeuser decided that it would provide all labornecessary to install the new equipment and provide projectsupervision at installation.

Rather than being shutdown driven, all of the tasksneeded to be defined to fit into a project timeline deter-mined by the time allotted for engineering and construc-tion. This includes such tasks as equipmentmanufacturing and delivery, interface design, ordering ofinstallation materials, equipment delivery, installation,system testing, system startup and commissioning, train-ing, and documentation. For this project, a schedule out-

Block diagram of the static exciter system.

SCR Gate Drive

Interface Firing Circuit

Chassis

Analog Output ±10 Vdc

Watchdog Timer

Contact to Cause trip

On/Off Status

Power Input

125 Vdc 120 Vac

Control Power

Local Indicators:. AVR Mode. Manual Mode. Droop. Autotracking. R/L Limit Indicator. Under/ Overexcitation Limit. AC Overvoltage. AC Undervoltage. Underfrequency. Null. Oscillography. Sequence of Events

(4) Field Configurable Output Contacts

LCD Screen

Keypad SwitchesControl:

Protection:

. Contactor Cumulation

. Setpoint-R/L Serial Link

. Mode Transfer-Serial Link

. Preposition-52b Contact

. Field Overvoltage

. Field Overcurrent

. Gen.Undervoltage

. Gen.Overvoltage

. By Contact or Communication

Digital Controller

Aux. Input

Functions:

Communications -RS485

. Voltage Regulation

. Generator Softstart

. Volts/Hertz

. Reactive Droop

. Min/Max Current Limit

. Voltage Matching

. Var/P.F. Control

. Field Current Regulator

. Control

. Calibration

. Monitoring

. Exciter Input/Output Status. Set Up

AC Field Contactor

Isolation Transducer

Field Flashing Contactor and Current Limit Resistor

Generator Field

Generator

Paralleling CT

PT PT

Three-Phase Power PPT

Voltage Sensing

Start/StopRaise/Lower

Auto/Manual

Voltage Matching

Serial Link Communication

to SCADA System (ModbusTM Protocol)

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line of how the job would be performedwas provided.

An initial meeting between Weyer-haeuser and the consultant was scheduledto convey the needs of both parties tomake sure a complete understanding of theproject and all expectations were under-stood. Items that were discussed included:

1) schedules to establish new equip-ment availability, demolition, andremoval of the old equipment andinstallation of the new systems

2) establish project responsibilities andcontacts

3) functional review of operation of thenew upgraded excitation system

4) review of construction proceduresand site safety issues

5) review location of the new equipment6) review all drawings (system elementaries, connec-

tions, and interconnections) of the existing sys-tem

7) review generator design data and curves8) discuss conduit runs or to find the optimum direc-

tion for new cabling, conduit, and wire tray9) review operator interface to the new upgraded exci-

tation system, type of control, digital interface orcontacts, alarms, and interface.

Installation ConsiderationsThere were several major installation considerationsinvolving the generator’s excitation system that neededto be resolved prior to starting the detailed design. Theywere the location of the primary components, the loca-tion of the operator interface controls, and the methodol-ogy of interconnection wiring.

It was decided to mount all the major components ina new air-conditioned electrical equipment room (EER)that had its make-up air charcoal filtered. This served adual purpose: first, it kept the major components (thePPT and the exciter control/rectifier cabinet) close tothe generator, thus minimizing the length of both thePPT and CT sensing leads, and second, it supplied adecent environment for the electronics present in thecontrol/rectifier cabinet.

While the state of the art in the control of today’sexcitation systems is typically a digital display panelwhere both alpha numerics and graphics are easily dis-

played, it was felt that certain functions,such as voltage adjustment and synchro-nizing, were better accomplished usingtraditional operator interface controls,such as rheostats and control switches.Likewise, it was felt that the operatorswould be much more comfortable withtraditional analog metering for the criti-cal generator parameters, such as ac volts,ac amps, dc volts, dc amps, ac kilowatts,and kilovars, even though these parame-ters would be displayed on a digital dis-play. It was decided to mount both theoperator interface controls, the redundantanalog metering, and the controls for theexciter in a new cabinet (Figure 6),designed as part of the project, which

would be located in the control room in a space betweenthe existing synchronizing panel and the control cabinetfor the existing # 4 TG. This cabinet would also containan operator interface for the new turbine’s governor aswell as additional turbine controls and status indication.

The quantity and type of interconnecting exciterwiring was specified by the engineering company whoprovided the design interface. The constructionmethodology chosen was one that the Weyerhaeuserdesign team had used successfully on numerous pro-jects. The ac and dc power wiring was armor sheathedcable in aluminum cable tray. The 120-Vac control and5-A current transformer secondary wiring wereinstalled as singles in aluminum conduit, and the ana-log wiring was individually twisted, shielded triads inrigid galvanized steel conduit. The conduits and cabletrays exited the EER walls through an aluminum bulk-head that allowed proper sealing of the EER withregards to the HVAC system.

CommissioningUpon verification of all ac and dc control circuits,checkout and calibrating of the excitation systembegan. Interface operating software provided by themanufacturer was used to calibrate the new excitationsystem. The operating software included means to setboth the maximum and minimum limits for the upperand lower voltage raise and lower stops, current levelsfor over- and under-excitation current limits, as well asthe volts/hertz value (limit). Absolute values for read-ing generator voltage and current were accomplished byidentifying the generator voltage transformer and CTratios and entering them into the manufacturer’s oper-ating interface software.

Testing to check the new excitation system voltageresponse was accomplished by using an analysis test soft-ware program and the oscillography recording capabilityprovided with the excitation system. As shown in Figure7, data logging would capture information of the excita-tion system performance, such as the field voltage andgenerator voltage at startup. Figure 7 illustrates the gen-erator voltage buildup characteristic programmed for a30-s voltage buildup time. No voltage overshoot occursusing the softstart characteristic.Voltage softstart buildup characteristic.

#1 Vave (1.0 p.u.)

7

Excitation cabinet installed in

the new generator EER.

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Performance of the generator and excitation system is afunction of the gains that are applied to the digital con-troller and the available field forcing provided by thepower rectifier bridge and the PPT. To measure perfor-mance, voltage step changes are performed to record gen-erator voltage response. Figure 8 illustrates the results of a5% voltage step change performed when the generator isopen circuited. The voltage time recovery is less than 0.8 swith no voltage overshoot.

Among other tests performed were verification of boththe over- and under-excitation limits. The over-excitationlimit was set to allow maximum field forcing forimproved transient stability yet still provide protection ofthe generator rotor to by preventing excessive heating dueto excessive field overload. The under excitation limit wasset based upon the generator’s reactive capability. It wasset to prevent too few vars from being absorbed by thegenerator for a given number of kilowatts going out of thegenerator. Too little vars being absorbed for a given kilo-watt output would result in the generator slipping poles.The volts/hertz limit was calibrated to coordinate with thevolts/hertz relay, device 24.

One specific test requested by the mill was to dynami-cally demonstrate that the automatic voltage regulatorwould transfer to manual control (field current regulator)in the event of loss of voltage sensing to the automatic volt-age regulator. Here, all three sensed voltages were removedby pulling the fuse block to the voltage regulator. Timedelay to transfer to manual control was set for 0.2 s duringthe interim, voltage rose to 125%, and upon transfer tomanual, settled back to the prefault condition of 13.8 kV.The test demonstrated anticipated performance.

ConclusionWhile, at this writing, the #5 TG has only been runningfor approximately one week, the check out of the excita-tion system went extremely smoothly and rapidly.

Both the digital regulator and the power electronicsappear to be “rock solid” and have operated as expected.The communications between the main cabinet and thedisplays located in the control room have been adequate.A possible area of improvement in the equipment is thatthe operator panel, while having good functionality, islaid out such that its operation is somewhat less intu-itive than it might otherwise have been. The built-inoscillography enabled a record to be made of the base-line tests for future reference.

Where future testing maybe required to comply withNERC future regulations, internal testing capability with-in the digital controller, such as oscillography andsequence of events recording, will help position the mill toperformed any future testing as may be required by NERCat minimum cost.

In summary, the experience was a very satisfactory andrewarding one with both the engineering consultant’s and

the manufacturer’s representatives performing as expectedto make the job of retrofitting the excitation system on analmost 40 year old generator a lot less daunting than itmight have otherwise been.

References[1] A. Godhwani, M.J. Basler, and T.W. Eberly, “Commissioning and

operational experience with a modern digital excitation system accept-ed for publication,” IEEE Trans. Energy Conversion, vol. 13, pp.183–187, June 1998.

[2] R.C. Schaefer, “Application of static excitation systems for rotatingexciter replacement,” in Proc. IEEE Pulp and Paper Industry TechnicalConf., 1997, pp. 199–208.

[3] R.C. Schaefer, “Steam turbine generator excitation system moderniza-tion,” in Conf. Rec. IEEE/IAS Annu. Meeting, 1995, pp. 194–204.

[4] IEEE Guide for Identification, Testing, and Evaluation of the Dynamic Per-formance of Excitation Control Systems, IEEE 421.2-1990.

[5] R.C. Schaefer, “Voltage regulator influence on generator stability,” pre-sented at Waterpower, 1991.

[6] R.C. Schaefer, “Voltage versus var/power factor regulation on hydrogenerators, presented at IEEE/PSRC, 1993.

[7] IEEE Guide for Specification for Excitation Systems, IEEE 421.4 1990.[8] T.W. Eberly and R.C. Schaefer, “Minimum/maximum excitation lim-

iter performance goals for small generation,” IEEE Trans. Energy Con-versation, vol. 10, pp. 714–721, Dec. 1995.

[9] IEEE Recommended Practice for Excitation System Models for Power SystemStability Studies, IEEE 421.5-1992.

[10] IEEE Guide for the Preparation of Excitation System Specifications, IEEE421.4-1990.

[11] D. Kral and R. Schaefer, “NERC policies affecting the powerindustry,” in Conf. Rec. IEEE/IAS Annu. Meeting, 2003, pp. 214–222.

[12] R.C. Schaefer and K. Kim, “Digital excitation system providesenhanced tuning over analog systems, in Conf. Rec. IEEE/IAS Annu.Meeting, 2000, pp. 84–91.

Robert S. Jordan (Bob.Jordan2@weyerhaeuser.com) is with Wey-erhaeuser Engineering Services in Charlotte, North Carolina.Richard C. Schaefer (richschaefer@basler.com) is with BaslerElectric in Highland, Illinois. John A. Estes, Jr.(jestes@e2psi.com) and Michael R. Dube (mdube@e2psi.com) arewith E Squared Power Systems, Inc., in Littleton, Colorado. Jor-dan and Schaefer are Members of the IEEE. This article firstappeared in its original form at the 2004 IEEE Pulp and PaperIndustry Technical Committee Conference.

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