..COMMON SENSE'' PERFORMANCE TESTING FOR COMBINED CYCLE PLANTSIN A COMPETITIVE INDUSTRY

James KochPower Plant Performance Specialist

130 Lansdowne Court, Lansdowne, PA 19050

Ghristopher J. HaynesResults Engineer, New England Power Company

Brayton Point Road, P.O. Box 440, Somerset, MA 02726

ABSTRACTAn approach to testing for perforrnance improvement is described

which is cost effective, and has provided proven results in combinedcycle units. The method makes optimum use of existing plantinstrumentation, and through innovative analysis of the data, allowsoperators to identiS the causes for all losses in expected output.Examples are cited from one 250 MW combined cycle unit in whichall causes for a 12 MW shortfall in capacity were found, after which 3

MW was immediately recovered with low cost maintenance.Instrumentation considerations are discussed, and how they differ

from those commonly associated with performance testing.Establishing a reliable baseline for comparison, and the repeatabilityof instrumentation, is of prime importance, with lesser emphasis beingplaced on absolute accuracy. Although the paper uses a combinedcycle plant as the focus of the discussion, the concepts described areequally applicable for cost effective testing of any type of electricgenerating unit.

INTRODUCTIONThe past two decades have seen considerable attention paid to

heat rate monitoring and improvement in fossil generating units(Sloboda, l98l). In 1985, the authors published a paper whichdescribed a coherent system for monitoring heat rate losses inconventional steam units. In the method, the total difference betweenactual and expected unit heat rate is allocated to various plantparameters, each being related to either the physical condition of theunit, or to selection of an operator control set point. This approachcan also be applied to gas turbine combined cycle units. A set of suchparameters for a combined cycle is shown in Figure l. With newchallenges such as the advent of competition, the growth of the IPP

industry, uncertainty in future energy prices, and the emergence ofcombined cycle as a dominant generation technology, the incentive forheat rate improvement remains strong. Also, with gas turbine havinga somewhat "fixed" fuel input, improvements in combined cycle heatrate translate directly to increased output, increasing plant revenue andprofit.

For example, consider a 250 MW combined cycle with a 5

clkWh power purchase agreement. If we assume a capacity factor ofabout 90 percent, then a I percent improvement in heat rate willincrease output by 2,500 kW, increasing annual revenue by nearly$1,000,000. While a I percent gain may or may not be feasible, evena portion of this improvement is justification for such a testingprogram.

DESCRIPTION OF THE APPROACHThe approach used by the authors identifies a set of parameters,

called heat rate determinants, which describe the physical condition ofthe cycle equipment is a simple and concise way. By quantiffingexpected and actual values for all such parameters, an accountingsystem reconciles the lost generation for the unit. Previous examplesof heat rate determinants focused on conventional fossil steam units.However, a similar set of parameters can be developed for gas turbinecombined cycle units.

Table I describes a typical combined cycle unit that has noted asteady decrease in generation (after correcting for ambient conditions)during the four years since commercial operation. This loss iscompared to the test performed at initial acceptance, which establishedthe baseline for future comparison. While the loss is certainly real, theexact physical cause of this deterioration is not at all apparent fromthis data.

INJECTION WATER FLOI'VFIRING TEMPERATURETUREINE EFFICIENCY

HRSG SURFACE TOSSESGT EX}iAUST D|rcT SURFACE LOSS

\AAD HP STEAM PRESSURECROSSO\ER STEAM PRESSURE

HP STEAM ruRBINE EFFICIENCYLP STEAM TURBINE EFFICIENCY

INLET PRESSURE OROP

COi'PRESSOR EFFICENCYINLET AIR FLO^'

EXI{AUST PRESSURE DROP

WATER FLOWTO}IER APPROACH

CONOENSER CLEANLINESS

HRSG SECTION CLEANLINESS

AUXILIARY POI'UER

Flgure 1

Performance Parameterc for Comblned Gycle Unlt

Table IErample of Comblned Cycle Performance History

Initial Acceptance2 Years Later4 Years Later

Deviation 11,243 kW 11,864 kW

Allcr correcting for ambient conditions, this unit has lost | 1,E64kW in capacity over four ycars. An analysis which identifics andquantifies all of the causes of this loss is shown on Table 2. Note howthe sum of thc individual parameters very nearly reconcilcs the cntiredcviation bctwcen the expcctcd and as-tcsted gencralion. Thisagreement in thc overall rcconciliation is callcd "closure," and is usedas a mcans to validatc thc rcsults of thc calculation. In this case, the

analysis identified all of thc causcn of lost gcneration to within 40 kw, or0.3Yo, of thc overall dcviation.

The accounting of losr pcrformancc in this cxamptc shows thu thcmajor contributors to lost gcncration arc thc two gas turbincq thc twoHRSG's, the stearn turbine, and the condcnser. A dcuilcd analysis ofeach piece of equipment can then bc done in order to pinpoint thc oractphysical causes for each loss. Correctivc action can be planncd bascd onthis information, and the lost gencration rccovercd in thc most costeffective fashion.

This tabulation also indicatcs thu there are currcntry no problcmswith the cooling tower, and that auxiliary power is about 300 kw bclowits expected level. Thesc arc also vduablc rcsults, and with thcm, plantmanagement can direct opcrstor awarencss and maintenanqc planningtoward those items which will bcncfit thc most, and delay aclion onareas which are not causing the loss.

Examplcs of dctailcd equipment analysis for each arca in thccombined cycle plant are describcd latcr in more dctail. ln each casc,the analysis uses inlbrmation rcadily available from cxisting plantinstrumentation and information systcms, and minimizcs intrusion onnormal plant opcration.

As Tested Correcied

248,325 kW 251,336 kW247,178 kW 244,764 kW237.082 kW 239,472 kW

Gas Turbine 1

Gas Turbine 2HRSG 1

HRSG 2Miscellaneous Surface LossesSteam TurbineCondenserCooling TowerAuxiliary Power

Sum of Individual Parameters

"Closure"

CALCULATION AND ANALYTICAL METHODThe method for determining the kilowatt losses from each

component in combined cycles is based on a technique developed bythe authors over many years for conventional steam units. Althoughthe ASME PTC codes are used for guidance, their purpose iscommercial acceptance of equipment, not periodic diagnosticmonitoring or detailed cycle analysis. Rather, it is the experience andknowledge of the analyst that is crucial for meaningful test results.

The process involves the following seven steps:

Develop Design Heat BalanceA design heat balance determines the expected generation for the

unit, and defines references for "imposed" conditions such as ambienttemperature and fuel constituents. It will also incorporate the effect ofany changes to the design of the unit since initial operation.ldentify Heat Rate Determinants

A set of parameters is defined which will relate performancelosses to the physical condition of equipment. These will be then usedto plan corrective action. For example, rather than simply track backpressure, poor condenser performance is attributed to circulating waterflow, cleanliness factor, plugged tubes, and cooling tower approach.Calculate Test Heat Balance

A heat and mass balance for the as-tested combined cycle unit iscalculated. In this step one of the various flow measurements (e.g.,fuel flow, water flow, steam flow, pump head, etc.) is selected as thebasis for the steam side heat balance, based on an overall level ofagreement with all other available data points.Normalize to Reference Conditions

The as-found performance for each component must be correctedfor the conditions "imposed" on it, so that a comparison to design is

Table 2Example of Heat Rate Determinant Analysis

Expected Generation, CorrectedAs-Tested Generation, Corrected

Deviation

Summary of Effects for lndividual Components:

251,336 kW239,472kW

11,864 kW

3,083 kW2,7921,8881,140(426)

3,009716

0(2e8)

11,904 kW

40 kw (0.3%)

true and meaningful. For example, heat transfer capability (UA) foreach section in the HRSG must be corrected for flow before acomparison to design UA can be made.

Determine Kilowatt LossesThe design heat balance is recalculated, varying each parameter

one at a time, so that the impact of each parameter on unit output isfound, until the total deviation in actual-to-expected generation isaccounted for.Check for "Closure"

When done correctly, the sum of the individual losses will addexactly to the overall deviation between expected and as-testedgeneration. This provides for an intermediate check of the validity ofthe results.

Perform Uncertainty AnalysisThe effects of each individual instrument on the performance of

the equipment is determined, in order to find the overall confidence inthe results. This step will also take into account redundantmeasurements (where available), and the impact of any assumptionsmade.

It has been the authors' experience that results can be availablewithin one month of the test. Any short-term improvements can beidentified quickly, and the benefits taken as soon as possible. Thefinal analysis can also indicate data which produced conflictingresults, identifring instruments in need of calibration or repair prior tothe next test.

WHY THE APPROACH WORKSThis proven method differs from other approaches to

performance analysis, such as on-line monitoring and artificial

intelligence, in that it places the emphasis on the mechanical andthermodynamic problem, rather than on computer applications. Sinceall results are directly related to equipment condition, performanceproblems are clearly identified so that corrective action can be taken.

The concept of "closure," and use of redundant measurements,assures meaningful conclusions. Also, the method is low cost,achieving useful results with existing instruments, and with minimalintrusion on normal plant operation.

It is also important to note that the sole purpose of this approachis to correctly identify performance problems, so that lost generation

can be recovered. There is no interest in providing a tool, or inapplying a new technology or research result, as is often the case inperformance monitoring "packages." Unfortunately, it has becomecommon to include some alternate, and often expensive, agenda withperformance improvement, rather than to concentrate on the true goal,which is to increase output in the most cost effective manner possible.

TEST DESCRIPTIONA simple input-output test is performed with all bypasses, vents,

drains, blowdowns, and any GT extraction air fully isolated. The testis best conducted with the gas turbines at base load, the steam turbineat VWO, and with auxiliaries such as duct burners out of service. It isalso useful to fill and isolate the condensate make-up tank, which thenprovides an overall check on water side isolation.

Nearly all modern power plants have sufficient instrumentationexisting to undertake this type of test. If available, a modern DCSsystem is capable of monitoring and recording nearly all of the datapoints in the plant. Operator involvement during the test is thenlimited to taking fuel gas samples, performing a survey of GT andHRSG surface temperatures, and making a set of clipboard readingsfrom local indicating gauges.

ln one case, contract requirements for periodic O&MPerformance Tests provided the initial opportunity for this effort.However, the value of the information obtained, the relatively lowcost of the test, and the quick turn-around of test results demonstratedthat this effort would have easily been justified in any event.

DISCUSSION OF RESULTS FOR SAMPLE CASEThis method has been used successfully on several combined

cycle units, with one 500 MW facility being able to identiff all causesfor 17 MW in reduced output since initial operation. Of that loss, 3

MW has been recovered thus far, and planning is underway forrecovery of another 3 MW. The remaining 1l MW, though notimmediately recoverable, has been identified, and is the focus offollow on testing, and planning for future outages.

The sample case described below is indicative the authors' actualexperience in testing of several combined cycle units. However, thisexample is not intended to represent any one particular unit. Thesample case is based on a 250 MW STAG 2078A configuration, withtriple pressure HRSG's, a dual admission steam turbine, and amechanical draft cooling tower. A heat balance diagram for thesample unit is attached as Figure 2

Gas Turbine AnalysisThe summary in Table 2 shows that the two gas turbines together

account for 5.9 MW, or half, of the lost generation for this unit. Table3 is a summary of the performance of one of the two gas turbines. Itwas developed by calculating a heat balance around the unit usingdata available from both the plant DCS, and from the gas turbine'scontrol system print-out.

The results, also shown on Figure 3, provide a more detailedaccount of the machine's performance and condition than simplycorrecting to ambient temperature using the manufacturer's curves. Inthis case, they show that the primary cause for lost performance is a

decrease in water flow, presumably a control change made by plantmanagement.

As for the physical condition of the gas turbine, only thecompressor efficiency, which is down I point from design, causing aloss of 891 kW, shows a major in generation. This result, along withthose from other equipment and systems, will be trended in futuresuch tests.

A significant difficulty in this approach is that there is nopractical method, of which the authors are aware, for measuring the

Compressor Efficie ncy, o/o

Turbine Efficiency, %Inlet Air Flow, CuFUMinCompressor Discharge Pressure, psiFiring Temperature, deg FWater Injection Flow, lb/hrInlet Pressure Drop, inWCExhaust Pressure Drop, inWC

Corrected GenerationCorrected Heat Rate

Table 3Performance Results for Gas Turbine (1 of 2l

Actual

90.488.0496,300163.02,03828,0003.912.0

80,85911,017

Expected

91.388.0499,1 00166.32,03837,1503.912.0

83,94210,798

kW Loss

891

563247

1,392

3,083

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Firing Temperature 2038 deg F(based on 11 .7o/o Coding Air Flow)

Inlet Air Flow 496,300 CFM

Compressor Efficiency gO.4 o/o Turbine Efficiency 88.0 %

Water Injection Flow 28,000 lb/hr

Compressor Discharge Pressure 163 psig

Figure 3Cross Section of Gas Turbine with Performance Parametert

intcrnal cooling air flow in thc gas turbinc. Cooling air flow must beknown to accurate ly dclerminc the valuc for firing tempcrature, and tocorrectly interprct the results for compressor discharg,c pressure. Forcxample, a decreasc in comprcssor discharge pressurc, olherwiscuncxpliained by a changc in inlct air flow or unrrccompanicd by

degradation in turbinc scction cfficicncy, cut sug,gest an incrcasc incooling air flow as a percent of total air flow.

Fortunatcly, cooling air flow is not nccdcd to dctcrminc thc orhcrparatnetcrs, most nolably compressor scction clTiciency, and turbincssction cfficiency.

Table 4Effective Area (UA, Btu/sqft-hrdeg) for HRSG ( of 2l

Normalized for Gas Turbine Exhaust Flow

HP SuperheaterHP EvaporatorlP SuperheaterHP Economizer - 3lP EvaporatorHP Economizer - 2lP EconomizerHP Economizer - 1

LP EvaporatorLP Feedwater Heater

TOTAL

As-Tested

556,7991,494,614

u,249681,600832,359

77,49269,112

194,930252,2091 19,213

4,302,563

Design

573,7041,798,143

27,9051,082,2221,322,U3

154,308141,401407,6y348,950177,891

6,035,011

Cleanliness"percenr

97.183.1

122.763.062.9s0.248.945.472.367.0

71.3

HRSG AnalysisBy calcularing a hcat balance around the lIRSG, thc heat transfcr

capability (uA), or effective area for heat transfcr, of each section isdctermined. The calculatcd result must be normalized for flow, andthc result then correctcd to lSo beforc a meaningful comparison todcsign is made. The resulting comparison is a "creanriness factor" forcach section in rhe HRSG. Shown in Table 4 is such an analysis forone of the two IIRSG's on rhc sample combined cycle unit:

The test results show that, on average, the entire HRSGcleanliness is about 30 percent lower than design. This causes adecrease in HP steam production of about 14,000 lb/hr, or about 5percent, which is causing a loss in steam turbinc gcneration of almost2 Mw attributable this one tIRSG alone. The cleanliness results arealso shown on a cross scction diagram in Figure 4. Thc loss in steamgenerating capubility can also be seen in the differcnce betweenexpcctcd and actuul cvup()rator pinch point lbr cach ol' thc thrccpressure lcve ls.

This mcthrd is usclul in that it clcarly idcntifics thosc arcasrequiring attcntir-rn. 'l'hc ninc scctions with lbuling atl have linncd-tubes, with thc lbuling matcrial lodging betwecn rhe fins. Thc two"clcan" supcrhcalcrs arc both unfinncd, and no clcaning is requircd.This result allr.rws thc plant to conccnlratc thc clcalring clfort to thosesections which rvill rccovcr rhc most kilowatts during the limited timewindow of thc ne xt outagc. A similar result to this was arso seen by

Table 5HRSG Evaporator Pinch Point (deg F)

Design HRSG 1

HP Evaporator 18.1lP Evaporator 13.5LP Evaporator 40.0

29.735.466.4

HRSG 2

20.225.255.3

the authors on another combined cycle unit, and led to a dry-ice blastcleaning of the gas side. A pre- and post-cleaning analysis vcrifiedthat approximately I MW had been recovered on one HRSG, asdemonstratcd by increased steam production. with the economicsstated earlicr, a I MW gain on each of two FIRSG's represents anincrcasc in rcvcnur: ol'ncarly $800,000 pcr year, with no additionalfuel cost (i.e., "frce energy").

Sincc the cost of the cleaning was minimal ($10,000), the valueof the inlbrmation obtaincd as a result of performing the analysis isclear. ll'thc cost bcnefit analysis had addressed only thc dccrease ingas sidc prcssure drop, and not the heat transl'cr improvemcnt, thepcrceived bcnelir of the cleaning would have been grosslyunderstatcd. Furthermore, tbllow-up cleanings would not beperformed as frequently as would be actually justified.

HP Superheater 97 o/o

HP Evaporator 83 o/of P Superheater 123lP Evaporator 63

o/o

%HP Economizer (2) 50 %lP Economizer 49 %HP Economizer (1) 45 o/o

LP Evaporator 72 %LP Economizer 6T %

HP Economizer (3) 63 %

Figure 4schematic Diagram for HRSG with section ,,cleanliness" Factors

Steam Turbine AnalysisThe slcam turbinc manufacturer's expccted pcrformance

(Spencer, Cotton and Cannon, 1974\ was used in conjunction with theas-found inlet stcam flows from a heat and mass balance using the testdatan generator output, and the actual back prcssure. If performing atdesign, the steam turbine should have produced over 87,774 kW withthe measured steam conditions (Figure 5). Inslead, the measuredsteam turbine g,cneration was only 84,765 kW (Figure 6).

Steam temperatures and pressures takcn at the throttle and at theHP/LP crossovcr showed that the HP section of the stcam turbine wasexactly at its valves wide open (VWO) design efficiency of 87percent. Horvcvcr, a mass and energy balance around the LP turbinerevealed that thc LP section efficiency was only 82 percent, which is

lower-than its expected design cfficiency by 6 poins. In pcrformingthis calculation, corrections for cxhaust loss were propcrly takcn intoaccount, so that these effects were not mistakenly attributed to thephysical condition of thc machinc.

Both the HP and LP turbinc results wcre substantiatcd by anuncertainty analysis, and by consideration of several alternatc datasets, available from both the DCS and manual clipboard rcadings. Theconclusion was also validated by thc tcchnique of multiple flow mcteranalysis, as will be described latcr.

While this situation cannot be corrected in the near term, findingthis large amount of lost generation is valuable information for plantmanagemcnt. lt will be taken into account for future inspcctions andmaintenance planning, as well as in subsequent performance testing.

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Figure 5Heat Balance for Steam Turbine, Expected Pedormance at Design Efficiency

Figure 6Heat Balance for Steam Turbine, As-Tested Condition

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Cooling System AnalysisExpected condenser performance was determined from heat rejectionduty and circulating water inlet temperature. The as-tested backpressure of 2.4 in Hg was high by nearly 0.7 in Hg, and the heattransfer capability of the condenser was found to be only two-thirds ofits expected design value, according to HEI condenser criteria (1978).

With no tubes plugged, and the water side of the tubes verified tobe clean in an inspection, air binding was suspected as the problem.This is caused by either excess air in-leakage, or malfunction of the airremoval equipment.

Investigation showed that a vacuum regulator valve on the inletto the vacuum pumps had been set to be open during normaloperation. Intended to be open only in the event of insufficientcooling, protecting the pumps from cavitation, this situation preventedeffective condenser air removal. The valve was reset, and backpressure decreased by over 0.5 in Hg. In addition to avoiding theexpense of a costly air in-leakage detection survey, the correspondingincrease in generation of 700 kW will increase annual plant revenueby over $275,000. Again, this approach proves to be a cost effectivemethod to performance improvement.

Conversely, the cooling tower approach temperature, adjusted forambient conditions and flow, was found to be within a fraction of adegree of design (Dickey, 1978). Analysis also showed that thecirculating water pumps were operating very near their expectedperformance. Information of this type is also valuable to plantoperators, in that attention can be focused on areas of knowndegradation, and not spent on equipment which is in satisfactorycondition.

The authors recognize that the HEI method is not rigorous, andwas developed as a sizing criteria for design and selection of steamsurface condensers. The authors have found, however, that it allowsfor accurate comparisons to a known baseline when variations inambient conditions and load are modest.

Further, the HEI method's gravest deficiencies occur whencirculating water temperatures and condenser back pressures are low(due to effects of air removal, cold water viscosity on heat transfer,and pressure drop due to increased steam velocity). However, duringcold weather months, when back pressure is low, changes tocondenser performance have little effect on overall plant perfoffnance.Indeed, the authors have found that it is generally not cost effective toclean condensers during the winter, even when their heat transfercapability is seriously degraded by fouling. On the other hand, thereis significant economic incentive to clean condensers frequently(sometimes weekly) during the summer to correct only moderatesamounts of fouling.

INSTRUMENTATION REQUIREMENTSTo effectively monitor performance, good instrumentation is

essential, but "good" and "expensive" are not necessarily the samething. There is often reference to the ASME PTC codes whendiscussing performance testing. However, when the purpose fortesting is monitoring for degradation, these must be taken with a grainof salt, because the interest in is changes relative to a baseline, not inabsolute performance, as in the case of contract acceptance testing.Thus, much of the philosophy of the ASME PTC's is inappropriate inthis application.

The instrumentation requirements for effective performancemonitoring differ strongly from those of contract acceptance testing.First, although absolute accuracy is not required, relative accuracy isessential. Because absolute accuracy is not required, the installationrequirements for instrumentation can be relaxed somewhat. What isimportant, however, is that the condition of the baseline test be

matched in subsequent performance diagnostic tests. Thus, if theinstallation of instrumentation is unchanged, and sensors are proven tobe accurate, then the measurement of flow rates, temperatures,pressures, and power output should be comparable, even if thein strument instal I ation i s somewhat off-code.

The two sections below summarize the authors' experience withtwo specific instrument concerns, and recommend a level ofinstrumentation appropriate for combined cycle performance testing.The overall conclusions, however, are equally applicable for any typeof generating unit.

Flow Meter AnalysisThe ASME PTC codes, most notably PTC-6, are built around the

use of one main flow meter of impeccable accuracy. Extremelydemanding standards in its construction, installation, and inspectionmust be met (e.9., upstream and downstream diameters, flowstraighteners, etc.). It requires calibration at a certified facility tofundamental, internationally agreed upon standards. Then, laboratoryconditions (such as flow profile, Reynolds Number, and condition ofthe flow element) must be duplicated in the field, along with use offull NBS tracability in taking readings. All of this is needed becauseof the contractual nature of acceptance testing.

A major concern is Reynolds Number extrapolation. Forconventional steam units, it is not possible to calibrate a flow meter atits expected operating Reynolds Number. Thus, the code mandatesthe use of a precision throat-tap flow nozzle, for which extrapolationto higher Reynolds Numbers is well documented. For combined cycleunits, though, the requirements of a throat-tap nozzle are notnecessary. This is because the lower condensate temperatures ofcombined cycle units can be matched in the laboratory, making anASME throat-tap nozzle unnecessary. Flow meters which are lessexpensive, and have a lower pressure drop, such as Venturi flowtubes, should be acceptable, and it is unclear to the authors why theywould not be favored for combined cycle application.

It is evident, however, that there is some need to assurerepeatability in flow measurement. For instance, the ASME PTC 6.1states that a piece of weld rod lodged across a flow nozzle can changeits coefficient by as much as l0 percent. This makes inspectiondesirable, although in may cases it is not practical.

One possible substitute for inspection involves the use ofmultiple flow meters. This approach would be similar to that cited inDIN 1943, which calls for using the readings from several flow meters(e.g., main steam, feedwater, condensate, and pump suctions), withweighting factors assigned to each reading based on the uncertainty ofeach, to arrive at a weighted average primary flow. Then, the DINcode calls for calculating the results of the test based on this one"weighted average" primary flow, which includes the uncertainty ofall of its constituent readings. It is the view of the authors, however,that for contract acceptance testing, this method is a weak substitutefor the high levels of accuracy that the ASME PTC approach offers.

INJECTION WATER FLOTfY

HP STEATT FLOYI,|P STEAr| FLOW

FUEL FLOW \,}IO HP STEATI PRESSURE CROSSOVER STEAr| PRESSURE

HP ECONOMIZER FLO'VIP ECOilOMIZER FLO'V coNo€xslrt puup ctn\G

BOILER FEEO PUMP SIJCTION FLOWSOILER FEEO PUIP CURVE

Flgure 7Available Flow Heterr In a Combined Cycle Unlt

However, multiplc flow mcters can be used cffectivcly inperformance monitoring in another way. While the example fromPTC 6. I refers to damage to onc flow meter (say, the feedwater flownozz)e). it is improbable that thc same change would occur in allflow meters (such as steam, condcnsate, and fuel flow meters). lf therelative readings of all of thc available flow meters show the sameoffscts as lhcy did in thc baseline test, then it is reasonable to foregoinspection. A necessary clement of this approach is that at least oneof thc flow meters was inspcctcd (but not necessarily calibrated)during thc basclinc tcst.

Allowing for futurc disagrccmcnts bctwccn flow meterq thcrcmurt bc a known refcrcncc point. For cxample, assume that since thebascline tcst" an unexpectcd divcrgence ariscs between the fecdwaterflow and condensate flow mercrs. Neithcr flow meter had bccninspectcd beforc. The condcnsatc flow mcter is now inspectcd, andfound to bc damagcd. Thc feedwater flow metcr is inspected and isfound to bc in good condition. It is reasonablc to assume that thcfccdwatcr flow mctcr was also in good condition at the timc of thcbascline tesl, and that its rcadings have remaincd consistent, but thereis no physical proof of this.

lf, however, either of thc two mctcns had bccn inspccted prior tothc baseline test, the readings of thc undamaged fcedwatcr flowmeter could now be accepted with morc confidence.

Figurc 7 shows all of the flow melcrs available on a rypicalcombined cycle plant. An cxample of thc usc of mulriplc flow mereranalysis as shown in Tablc 6. Herc, thc measured condcnsate flowdiffers from a condensatc flow which is calculated whcn using cachof the other available flow mclers in a heat balancc calculuion:

Teble 6Comparison of Available Flow Meters

(lb/hr)

Measured Condensate FlowCalc'd by GT/HRSG Heat BalanceCalc'd by HP & lP Feedwater FlowCalc'd from \ ruO HP Stm PressCalc'd from Crossover Stm Press

677,000709,20071 0,000712,300707,200

l0

If the measured condensate flow had been used as the primaryflow, it would have been perceived that the HRSG performance waspoor (with low steam flow), and the steam turbine performance wasacceptable. However, reviewing other available flow indicators datareveals that the condensate flow measurement is indicating about 5

percent too low, and that the true condensate flow is closer to71 0,000 lb/hr. Use of multiple flow meters not only provides a morereliable measure of equipment condition, but also, in this case,indicates that condensate flow instrumentation needs to be checked.

Gas Turbine Exhaust TemperatureSimilarly, it is apparent that a high level of repeatability is

essential, but that only a general level ofaccuracy is required ofotherinstruments (pressures, temperatures, generation, etc.) used forperformance monitoring. As in the case of the flow meter inspection,these instruments also need to be calibrated in the baseline test, yetdo not require rigorous follow-on calibration as long as theirrepeatability is not in question.

Of particular interest is gas turbine exhaust gas temperaturemeasurement. This parameter is used for controlling the firingtemperature on unit, as well as in determining the performance ofboth the gas turbine and the HRSG. The uncertainty of measuringthe temperature of any single point in the GT exhaust gas stream can

be reduced to less than 1 deg F, as per the ASME "Guidelines forEvaluation of Measurement Uncertainty." However, in measuringthe overall GT exhaust gas temperature, there are additionaluncertainties introduced because of the severe stratification of thisflow stream.

Since stratification makes uncertainty in exhaust gas

temperature measurement very high, owners who are serious aboutmonitoring equipment condition are well advised to examine theirinstallations carefully. In one instance, the authors noted that a gas

turbine included 18 thermocouples mounted around the exhaustannulus. It is possible to calibrate these so that the uncertainty ofeach is only I deg F, as per the code. Superficially, the uncertaintyin the overall measurement of exhaust temperature (with all 18

thermocouples) would be somewhat better than I deg F.However, it was observed that the 18 individual readings varied

by as much as 50 deg F from each other, by 30 deg F from theaverage, and had a standard deviation of l0 deg F. Even worse, theoffsets between thermocouples changed substantially with changes inambient conditions and NOx injection flows.

The true uncertainty was found by applying the principles in thefamiliar "Student's t" test. The uncertainty for a sample populationof l8 with the statistics described above, compared to a much largerpopulation (which would be indicative of an infinite number ofthermocouples) was found to be 6 deg F.

In a different unit of different manufacture, only 6 exhaustthermocouples were provided. In this case, there was a maximumvariation of one-to-another of 100 deg F, a maximum variation fromthe average of 70 deg F, and a standard deviation of 50 deg F. In thiscase, Student's t test suggested an uncertainty from the "true"average exhaust temperature of 22 deg F.

If the differences between thermocouples were repeatable, onecould have reasonable confidence in relative changes in exhausttemperature measurement, as is needed in performance testing fordegradation, even though there would be little confidence forabsolute performance. Unfortunately, this is not the case. Changes

in ambient conditions, inlet guide vane position, NOx injectionflows, significantly skewed the readings relative to each other.

Owners of gas turbines are well advised to assess this aspect ofthe existing instrumentation on their equipment. It is the view of theauthors that the measurement of exhaust temperature, particularlywith respect to the number of exhaust thermocouples, is the singleweakest element in performance monitoring in combined cycles, andis the one area for which investment in improved instrumentation isjustified.

CONCLUSIONA coherent system for identif ing losses in combined cycles has

been described. This method requires a simple test which usesexisting instrumentation common to nearly all modern power plants.The resulting analysis quantifies the performance of each piece ofequipment in the cycle, and compares as-found physical condition todesign. All losses in generation are identified, so that correctiveaction can be taken, and lost revenue recovered.. Redundantmeasurements, such as multiple flow meters are used to verifrresults.

The example cited is based on actual experience with a 250 MWcombined cycle plant which had lost 12 MW since commercialoperation. Testing and analysis identified the causes for the entireloss. Recovery of 2 MW was achieved within four months of thefirst test, with recovery of an additional 1 MW shortly thereafter.The remaining 9 MW, though not immediately recoverable, will be

the focus for follow up testing and inspections until the next majoroverhaul.

Experience with two specific instrument concerns (steam cycleflow measurement and GT exhaust temperature measurement) wasdiscussed, and an appropriate level of instrumentation recommendedfor combined cycle performance testing. The overall conclusions,however, are equally applicable for any type of generating unit.

REFERENCESSloboda, Alan, T., "Thermal Performance Assurance,"

presented at the EPRI Heat Rate Improvement Conference,Charlotte, NC, December, 1981.

Koch, James, and Haynes, Christopher J., "Power PlantPerformance Monitoring," presented at the EPRI Heat RateImprovement Conference, San Francisco, CA, October, 1985

Spencer, R. C., Cotton, K. C., and Cannon, C. N., "AMethod for Predicting the Performance of Steam TurbineGenerators, 16,500 kW and Larger," General Electric PublicationNo. GER-2007 C, July, 197 4.

Heat Exchange Institute, "Standards for Steam SurfaceCondensers", Cleveland, OH, 1978.

Dickey, Joe Ben, Jr., "Managing Waste Heat with the WaterCooling Tower," 3rd Edition, Marley Cooling Tower CompanyPublication, Mission, KS, May, 1978.

American Society of Mechanical Engineers, "Appendix A toTest Code for Steam Turbines," ASME PTC 6.1-82, New York,NY, 1982.

DIN Code 1943, "Thermal Acceptance Tests of SteamTurbines," German Standards Institute, Cologne, 1975.

American Society of Mechanical Engineers, "Guidance forEvaluation of Measurement Uncertainty in Performance Tests ofSteam Turbines," ASME PTC-6 Report, New York, NY, 1974.

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