Steam Turbin Thermal Evaluation

GE Power Systems

Steam TurbineThermal Evaluationand Assessment

Paul AlbertGE Power SystemsSchenectady, NY

GER-4190

g

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Baseline and Periodic Performance Testing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

ASME PTC 6S Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Capacity Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Enthalpy Drop Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Evaluation of Performance Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Assessment of Turbine Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Turbine Steam Path Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Advanced Method for Assessing Stage Efficiency Losses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Loss Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Leakage Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Friction Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Aerodynamic Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Losses Due to Changes in Flow Passage Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Steam Path Audit Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Advancements in the Evaluation and Assessment of Data . . . . . . . . . . . . . . . . . . . . . . . . . . 14Performance Monitoring. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Plant Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Steam Turbine Thermal Evaluation and Assessment

GE Power Systems ■ GER-4190 ■ (10/00) i


GE Power Systems ■ GER-4190 ■ (10/00) ii

IntroductionFor a steam turbine-generator to operate at itsoptimum level of thermal performance, it mustachieve a high initial level of performance andmust be able to sustain thermal performanceover time. This is best achieved by an ongoingprogram of evaluation and assessment of ther-mal performance data. This program has athree-fold purpose. The first is to detect deteri-oration in the thermal performance by trend-ing changes in various performance parame-ters. The second is to identify the cause of per-formance degradation by proper data evalua-tion and interpretation. The third is to developcost-effective solutions to correct operationaland equipment problems, which are contribut-ing to the degradation in thermal performance.To meet these objectives, a thermal perform-ance program should include the followingessential factors:

■ Obtain baseline performance data onindividual turbines and cyclecomponents during initial operationand after a maintenance outage toestablish a base for identifying specificareas of performance losses

■ Periodic acquisition of repeatableperformance data

■ Proper evaluation and assessment ofperformance data so thatdeterioration can be detected, located,trended, and corrected in a cost-effective manner

■ Detailed inspection of andquantification of the expectedperformance recovery fromrestoration of turbine steam path

This paper identifies testing procedures andmonitoring activities that are effective forobtaining and evaluating performance data.

This data, with its associated results, will estab-lish accurate trends of various performancecharacteristics. The basic theory of the turbinesteam path flow, pressure, and temperaturerelationships is reviewed to improve under-standing of how these trends can be interpretedand used to locate and identify the cause of theturbine deterioration. Some common causes ofturbine deterioration include deposits, solidparticle erosion, increased clearances in pack-ings and tip spill strips, and foreign object dam-age.

This paper also reviews the value of conductinga turbine steam path evaluation to identify thespecific components contributing to the loss inthermal performance. In addition, this inspec-tion can be used to verify the predictions of tur-bine conditions from the monitoring program.Technological advancements of GE’sPerformance Evaluation Services is also dis-cussed.

Baseline and Periodic PerformanceTesting A performance test conducted in accordancewith the ANSI/ASME PTC 6-1996 “SteamTurbine” Code (Reference 1) is an accuratemethod of establishing the performance of aturbine-generator unit. The test requires theuse of highly accurate calibrated instrumenta-tion and highly controlled measurement proce-dures. When this code is used to conductAcceptance tests, the uncertainty of the testresult is very small. Although this code test pro-vides excellent baseline performance, it gener-ally is not economically justifiable for periodictesting as part of monitoring performance.However, the test code is useful in developing abasic understanding of the required measure-ments and procedures for determining the per-formance of a turbine-generator unit.


GE Power Systems ■ GER-4190 ■ (10/00) 1

The value of the analysis of performance testdata greatly depends on the quality of the data.The use of “Acceptance” test procedures toobtain periodic performance results yields themost accurate test data for analysis and evalua-tion. Fortunately, performance monitoringdoes not necessarily require absolute accuracy,but it demands repeatable data for establishingaccurate trends of various performance charac-teristics so simplified procedures can be used.

ASME PTC 6S Report The ANSI/ASME PTC 6S Report “SimplifiedProcedures for Routine Performance Tests ofSteam Turbines” (Reference 2) provides guidancein developing procedures to monitor perform-ance. This procedure provides the necessarydata to determine turbine cycle heat rate, kilo-watt capacity, HP and IP section efficiencies,and turbine stage pressures and flow capacities.

The essential measurements for ASME PTC 6SReport tests are shown in Figure 1. For this test,like other heat rate tests, the most importantmeasurements are electrical load and primaryflow, which is usually measured in the feedwaterline. To assure repeatability, the differential

pressure transducer on the primary flow ele-ment should be calibrated prior to the test. Inaddition, mechanical station watthour metersusually have to be read by counting disk revolu-tions to obtain a precise reading of kilowatt out-put. Temperatures and pressures at the inletand outlet of the HP and IP sections should bemade with instruments capable of producinghigh repeatability.

The repeatable determination of the turbinecycle heat rate also depends on cycle isolation.Since primary flow is measured in the feedwaterline, any leakage between the flow measure-ment and the turbine stop valve must be elimi-nated or the test results adjusted accordingly.Otherwise, an erroneous measurement of heatrate will be obtained. Steam and water leakageswithin the turbine cycle do not affect the meas-urement of heat rate, but these leakages cancause a significant loss in the actual heat rateand kilowatt capacity.

Capacity Test When a repeatable measurement of primaryflow cannot be obtained, another practical,effective method of trending the performance



From Reheater

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Figure 1. Test instrumentation location for a PTC 6S Test - fossil unit

GT25647

of the turbine-generator unit is to make period-ic measurements with the turbine control valveswide open (VWO). This test, usually referred toas a Capacity Test, determines the generatoroutput capacity, HP and IP enthalpy drop effi-ciency, and turbine stage pressures.

In rare cases, when steam generator capacitymay be inadequate to drive the unit to a VWOposition at rated pressure, one alternative is toreduce pressure to permit opening all inlet con-trol valves. This procedure is preferred over themore demanding method of accurately repro-ducing positions of partially opened controlvalves or for correcting results for valve posi-tion.

The Capacity Test, like the simplified heat ratetest, depends on repeatable measurements ofelectrical output and the pressures and temper-atures at the inlet and outlet of the HP and IPturbine sections. Isolation of the turbine cycle isalso important because it can significantly affectthe electrical output of the unit.

Enthalpy Drop Test The Enthalpy Drop Test is used frequently formonitoring steam turbines. This test involves aminimum number of instruments, but estab-lishes the efficiency of those turbine sectionsmost susceptible to deterioration. An EnthalpyDrop Test can be conducted on any turbine sec-tion operating entirely in the superheat region,such as the HP and IP sections of fossil reheatunits and the HP section of automatic extrac-tion units. The pressure and temperature aheadof and at the exhaust of the section being testedmust be measured. The efficiency of the sectioncan then be calculated from the ratio of actualto isentropic enthalpy drop. The turbine expan-sion line in Figure 2 illustrates this relationship.

The measurements required to determine theHP and IP turbine section efficiencies areshown in Figure 3. Pressure taps and thermo-

couple wells should be located ahead of the tur-bine stop valve, ahead of the intercept valve, ineach cold reheat pipe, and in the crossover orlow-pressure section bowl. In the cold reheatpipes, the pressure taps should be near the HPsection exhaust connection, and the thermo-couple wells should be in the horizontal pipeafter the first elbow to ensure good mixingbefore measuring the temperature.

Duplicate temperature instrumentation shouldbe used to conduct an Enthalpy Drop Test. Thiswill not only improve the accuracy of the data,but will also detect a faulty temperature meas-urement. When there are two separate steamleads from the boiler to the turbine, duplicateinstrumentation is recommended in each lead.

Evaluation of Performance DataThe effort of obtaining good repeatable testdata will be lost unless that data is properly eval-uated. The generator output and turbine cycleheat rate depends on the operating conditionsof the turbine cycle and the performance of the



ENTROPYEN

THA

LPY

Saturation Line

AE

UEEfficiency =

P Throttle

P Hot Reh

eat

AE UE

HP Section

P=3”Hg

P Bowl IP Section

LP Section

P Cold Rehea

t

Figure 2. Enthalpy Drop Test

many individual equipment components. If thetest results indicate that heat rate has deterio-rated or the maximum electrical capacity of theunit has changed, any of the following condi-tions could be contributing factors:

■ Turbine steam flow

■ Efficiency of the turbine steam path

■ Available energy of the turbine (i.e.,steam conditions)

■ Performance and operation of thebalance of plant components

To assess the turbine condition and its contri-bution to any deterioration in thermal per-formance, output and heat rate must be cor-rected for the influence of two non-turbinerelated factors: (1) the available energy of theturbine and (2) the performance and opera-tion of the balance of plant components.

The available energy of the turbine is affectedby variations in the following operating condi-tions:

■ Throttle pressure

■ Throttle temperature

■ Reheat temperature

■ Reheater pressure drop

■ Condenser vacuum

Heat rate and generator electrical output mustbe corrected for these operating conditionsusing correction factor curves normally provid-ed in the unit's thermal kit. Figure 4 is a sampleof a correction curve. Variations in throttlepressure and temperature also change massflow due to their effect on the specific volumeof steam. This effect is typically combined withthe available energy effect in the relevant cor-rection factors. Keep in mind that these correc-tions also represent an accounting of perform-ance losses due to operating conditions.

When assessing the turbine condition, it is nec-essary to account for variations in the perform-ance and operation of balance of plant compo-nents, such as feedwater heaters and auxiliaryprocess flows. Every effort should be made toeliminate or minimize flows which might varydue to seasonal changes or other causes. Athermal model program or valid correctioncurves can be used to correct for cycle or bal-ance of plant changes.



TT

PTT PP

P

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T T

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Cold ReheatSteam

ExtractionSteam

ExtractionSteam

LP Turbine

IntermediatePressureTurbine

High PressureTurbine

Stop & InterceptValvesStop Valves

Control Valve Chest

Figure 3. HP & IP efficiency measurement locations

The generic correction curves from the ASMEPTC 6S Report test code for the more signifi-cant cycle changes are listed below:

■ Final feedwater temperature

■ Auxiliary extractions

■ Main steam attemperation

■ Reheat steam attemperation

■ Condensate sub-cooling

■ Condenser make-up

A sample correction curve is presented in Figure 5.

Occasionally, it may be necessary to make cor-rections for out-of-service feedwater heaters orfor cycle leakages. These effects can best be cal-culated by heat balance calculations, but oftencan be adequately estimated by simplified cal-culations which consider first order effects. Arigorous program should be in place to identify,quantify, and eliminate cycle leakages becausethey typically affect the thermal performance ofthe plant by more than one percent during nor-mal operation.

Once these corrections have been made the

trend in heat rate and/or generator output canbe used to assess the turbine condition. Steamflow and steam turbine efficiency are the tworelevant factors which must now be considered.If the efficiencies of the superheated turbine

% decrease

% increase% change in heat rate

% change in pressure+1 +2 +3 +4 +5

-5 -4 +3 -2 -1

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Method of Using Correction Curves

These correction factors assumeconstant control valve opening andare to be applied to heat rates andkilowatt load at specified steamconditions.

(1) The heat rate at the specifiedcondition can be found by dividingthe heat rate at test condition by thefollowing:

1 +% change in gross heat rate

100

(2) The kilowatt load at the specifiedcondition can be found by dividingthe kilowatt load at test conditions bythe following:

1 +% change in kW load

100

Figure 4. Throttle pressure correction for single reheat units



Load Correction

Reheat Steam Desuperheat

Load Correction Main Steam Desuperheat

Heat Rate CorrectionReheat Steam Desuperheat

Heat Rate Correction Main Steam Desuperheat

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Desuperheating flow supply is from BFP

Apply corrections at constant main steam & reheat temperatures

Corrected HR = Test HR/D

Corrected Load = Test Load/D

where D = 1+ %Corr

100X % Desuperheating Flow( )

Figure 5. Correction for main steam and reheatsteam desuperheating flow

GT 25649

sections have been established, a change in effi-ciency can be expressed in terms of a change inheat rate and generator output. Some typicalvalues for the percent change in heat rate for aone-percent change in section efficiencies for asingle reheat unit are:

HP turbine = 0.17

IP turbine = 0.12 to 0.25

IP and LP turbine = 0.72

For non-reheat and industrial turbines withmore than one turbine section, the effect onoverall performance due to a change in the effi-ciency of one section can be estimated by mul-tiplying that change by the proportion of totalunit power produced in that section.

The turbine efficiency characteristics must beunderstood in order to compare test results todesign or to previous test results. For example,Figure 6 illustrates the efficiency characteristicsof an HP turbine section in a fossil unit applica-tion.

An HP turbine achieves its best efficiency withall control valves wide open (VWO) and, as thecontrol valves are closed (or throttled), the effi-ciency decreases. The parameters usually usedto represent valve position are a percent of valve

wide-open flow (at rated throttle pressure andtemperature) or a pressure ratio, such as firststage pressure divided by throttle pressure. Theupper curve represents a partial arc or partial-admission unit with the first stage nozzles divid-ed into four separate nozzle arcs, each beingsupplied with steam from its own control valve.The lower curve represents full arc or singleadmission with all control valves connected intoa common chamber ahead of the first stage noz-zles. Both curves demonstrate the significanteffect of valve position on HP efficiency and theneed for testing at valve positions, which can beset repeatedly and held constant for the test.

Assessment of Turbine Conditions The proper interpretation of test results canlead to an assessment of the internal conditionof the turbine which can assist in prioritizingmaintenance activities. There may be indica-tions of mechanical damage in a turbine sec-tion, deposits or solid particle erosion.Knowledge of the turbine characteristics is nec-essary to understand why the performance haschanged.

Maximum generator output is directly affectedby changes in the efficiencies of the various tur-bine sections and changes in the flow capacityof the first three or four stages of the high-pres-sure turbine. Changes in the flow capacity of fol-lowing stages may indicate a physical change inthe steam path and consequential effects onlocal steam path efficiency. A change in the flowcapacity of the turbine or the flow capacity of aparticular turbine stage is reflected in the stagepressure, temperature, and flow relationship.Section 6 of the ASME PTC 6S Report containsa detailed discussion of these turbine character-istics. For all turbine stages except the first andlast stage, the stage pressure ratios are essential-ly constant and the basic flow equation simpli-fies to:



HP TurbineEfficiency

Locus of ValveBest Points

PartialArc Full Arc

VWO

100Percent Flow

P1ST/PT

Figure 6. HP turbine efficiency

W = KACq √ P / v (1)

where:

W = Flow to the following stage

K = A constant

A = Nozzle area

Cq = Coefficient of discharge

P = Inlet stage pressure

v = Specific volume at stage inlet

The equation can be rearranged as:

W / √ P / v = KACq (2)

From the equation of state of an ideal gas (Pv = RT) the equation can be arranged as:

W / P √ 1/R * T = KACq (3)

where:

R = Universal gas constant

T = Inlet stage temperature

This equation states that the flow function (W / √ P/v) is related to the flow passage areaof the stage (A) and the design and conditionof the stage passage (Cq). In more generalterms, the flow function relates to the steampath condition. If a particular stage flow func-tion has changed, then the downstream condi-tion of the turbine steam path must havechanged. This is a powerful diagnostic tool inidentifying damage, deposits, erosion or otherproblems which have affected a group of stageswithin the turbine steam path. If the effectiveflow area of a stage increases due to erosion orother problems, the flow function will alsoincrease. Some problems, such as deposits,cause a reduction in the effective area of stageand a corresponding decrease in the flow func-tion.

The flow function can be used to recognize thata change has occurred in the effective area of

the stage. However, the flow function is not pro-portional to the area change as implied in theequation. It is important to note that the deri-vation of the flow function equation is based ona constant pressure ratio across the stage. Whenthe effective flow area of a stage changes, thestage pressure ratio also changes. Thus the rela-tionship of the flow capacity to nozzle area issomewhat more complex. Figure 7 shows theflow capacity change that can be expected for achange in nozzle area of an impulse-type tur-bine. For example, a 10% reduction in the noz-zle area of the first stage would reduce the max-imum capacity of the unit by about 3%.

Since the Capacity Test does not provide arepeatable measure of the primary steam flow,the flow function cannot be calculated. Anoption is to trend turbine stage pressures. Asshown by equation 1, the steam flow divided bythe absolute pressure ahead of a stage is pro-portional to the effective area of the followingstage, provided that the temperature remainsconstant. For a constant valve position and con-stant inlet steam conditions, a change in a tur-bine stage pressure indicates either a change inthe effective area downstream of the stage or achange in the flow capacity of the unit.

To use the trend of turbine stage pressures topredict the internal condition of the turbine,the stage pressures during the test must be cor-rected to reference steam conditions. The firststage pressure observed during a test on the HPsection of a reheat turbine, or the pressure forany stage on a non-reheat turbine, should becorrected to reference conditions by the follow-ing equation:

Pc = Po * Pd / Pt (4)

where:

Pc = Corrected pressure for plotting

Po = Measured stage or shell pressure



Pt = Test throttle pressure

Pd = Design, or reference, throttle pressure

When an extraction for feedwater heating istaken from an intermediate stage in the HP tur-bine section, the measured stage or shell pres-sure should also be corrected using the sameequation. Although not theoretically accurate,this correction is a very close approximation.

For stage or shell test pressures at or followingthe inlet to the reheat section of the turbine,and for the exit from the last stage of the HPsection, additional corrections must be madefor variations in throttle temperature, reheattemperature, and reheat spray flow to the boil-er. The correction equation to be used is:

Pc = Po * (Throttle pressure and temperature correction)

* (Reheat temp. correction)

* (Reheat spray correction)

Pc = Po * √ ((Pd * vt) / (Pt * v d))

* √(vdr/vtr) * (1 - (Wrhs/Wrhb)) (5)

where:

vd = Design, or reference throttle specific volume

vt = Test throttle specific volume

vtr = Specific volume at test temperature and test pressure at inlet to intercept valves

vdr = Specific volume at design reheat temperature and test pressure at inlet to intercept valves

Wrhs = Reheat spray flow to the boiler

Wrhb = Reheat bowl flow

Once the turbine stage pressures are standard-ized, the percent difference from a reference ordesign value should be calculated. Then thevalues can be plotted vs. chronological testdates as shown in Figure 8. The percent changein other performance parameters such as heatrate, generator output, section efficiencies, flowfunction, etc., can all be plotted on similargraphs.



CHANGE IN NOZZLE AREA (PERCENT)

CHANGE IN CAPACITY (PERCENT)

STG 1

STG2

STG3

STG4

2 4 6 8 10

-2-4-6-8-10

2

1

-2

-3

-1

STG 1

STG 2

STG 3

STG 4

Figure 7. Effect of change in nozzle area on flow capacity for impulse-type turbines

GT 25687

Turbine Steam Path EvaluationThe interpretation of the results of perform-ance monitoring activities can be used to iden-tify turbine internal problems causing a deteri-oration in performance, and assist in planningmaintenance required to address the problems.However, to restore performance during a tur-bine maintenance outage, the turbine compo-nents contributing to the performance lossneed to be identified. This can best be done byconducting a turbine steam path evaluation.

A steam path evaluation should include adetailed visual inspection of the steam pathcomponents and clearance measurements ofthe packings; and tip spill strips. The visualinspection should evaluate and quantify theperformance impact of degradation effectssuch as erosion, deposits, damage, peening, etc.Clearance measurements at multiple circumfer-ential positions of the diaphragm packings, tipradial spill strips, and end shaft packings shouldbe used to quantify the effect of increased clear-ances. With this information, decisions can bemade based on the economics associated withthe repair and replacement of turbine compo-nents, and the priority of necessary repair work.

The steam path evaluation should categorizethe identified stage performance losses into sixcomponents: excess diaphragm packing leak-age loss, excess radial tip spill strip leakage loss,nozzle recoverable and unrecoverable losses,and bucket recoverable and unrecoverable loss-es. Recoverable losses are defined as those thatcan be recovered by cleaning, dressing, repairof the components, or replacement of clear-ance controls. The unrecoverable loss is thatpart of the performance loss that can only berecovered by replacement with new compo-nents, such as new diaphragms or buckets.

Advanced Method for Assessing StageEfficiency Losses Most steam path audit thermodynamic evalua-tions performed in the past were based on con-sideration of steam path components and tur-bine sections as discrete entities. The complexinterplay of the effect of observed losses on agiven stage upon another stage was more diffi-cult to discern. With the capability of a PC it isnow possible to employ the capabilities of moresophisticated analysis programs that were, inthe past, only available on a mainframe com-puter. Advanced methods being used consider



Test Dates

Initial Test Date

% D

epar

ture

from

Ref

eren

ce

Min

us0

Plu

s

Figure 8. Pressure or capability curve vs. chronological test dates

GT 25688

not only the effect of the observed componentlosses on the steam path efficiency, but also theinteraction between these complex loss mecha-nisms. In other words, the feedback effect of theobserved losses can now be calculated ingreater detail and with greater accuracy.

GE has introduced a new tool for assessing theloss mechanisms that are evaluated during aSteam Path Audit. This new tool is called SPA2000, and is a PC-based program that uses astage-by-stage calculation to analyze the per-formance of a turbine section. This program,which is a user-friendly version of the sameanalysis program used by GE design engineers,is calibrated based on many years of field testdata and GE lab test data. It is the most accuratetool available to the auditor for the predictionof turbine section performance and flow capac-ity. SPA 2000 is used for obtaining input ofdesign data and inspection data, as well as forreporting stage and turbine performance out-put data. Additional input parameters havebeen added to allow the auditor to input specif-ic component losses observed on the nozzleand bucket profiles.

SPA 2000 is a FORTRAN-based program thatuses a closed system for making comprehensiveperformance calculations, including the follow-ing:

■ Nozzle and bucket efficiency

■ Flow passing capability

■ Leakage flow calculations

■ Rotation losses

■ Carryover loss between stages

■ Supercritical and wet expansions

■ Partial arc stages

■ Moisture loss

■ Idle bucket loss

■ Non-uniform discharge pressure

■ Governing stage calculation

Loss Mechanisms Stage efficiency losses may be caused by a num-ber of reasons, such as deposits, solid particleerosion (SPE); foreign object damage (FOD),rubbed or damaged packings, or rubbed ordamaged spill strips. Regardless of the causesleading to losses, stage efficiency losses may bequantified by sorting the losses into one of thefollowing four categories:

■ Leakage loss

■ Friction loss

■ Aerodynamic loss

■ Loss caused by changes in flow passageareas

These losses prevent the efficient transfer of theenergy into shaft work as the steam is expandedthrough a turbine stage.

Leakage Losses In order for a turbine to produce shaft power,steam must pass through both the nozzle andbucket flow passages. Steam bypassing eitherthe nozzles and/or buckets due to diaphragminterstage packing leakage, bucket root leakageor bucket tip radial spill strip leakage, will notproduce kilowatts. It may also disrupt the flowthrough the nozzles and buckets in such a wayas to further decrease turbine shaft output.Leakage losses are caused by increased clear-ances between the rotating and stationary com-ponents. These increased clearances are causedby rubbing between components, solid particleerosion or foreign object damage. The amountof the loss will be a function of the amount ofthe leakage flow. The amount of leakage flow isa function of the clearance (leakage) area, thegeometry of the leakage path, and the pressuredrop (pressure ratio) across the componentthat the leaking steam is bypassing. Equationscan be used for the discrete calculation of leak-age flow through an interstage diaphragm pack-ing, or a tip or root spill strip. However, this



does not account for the effect of the increasedleakage on the energy distribution on the stageor the consequence of it on the downstreamstage. For example, if there is excess root clear-ance on a diaphragm spill strip, there will be anincrease in the flow entering or leaving thesteam path, which, in turn, affects the root reac-tion of the stage and the amount of flow whichpasses through the bucket dovetail hole or thewheel hole. Similarly, if additional leakage flowis calculated over the tip spill strip of a bucket,the tip reaction of the stage will also be affected,which affects the energy distribution on thestage as well as on the stage immediately down-stream. The stage-by-stage analysis program uti-lized by SPA 2000 calculates the various leakageflows in the steam path based on all of the meas-ured clearances during the audit. Furthermore,the complex interplay of the increase ordecrease in any of these flows relative to thedesign case for each stage is determined.

Friction Losses Stage efficiency losses due to an increase in themeasurable roughness of a nozzle partition orbucket vane surface will be a function of theratio of the height of the projections to thethickness of the boundary layer, and whetherthis flow is laminar or turbulent (ReynoldsNumber). The thinner the boundary layer(higher Reynolds Number), the more signifi-cant the friction loss becomes, even for smallprojections. Projections are caused by contami-nates in the steam which deposit on the surfaceof the partitions. Projections are also causedwhen foreign particles collide against partitionsurfaces, leaving behind small indentations inthese surfaces. Quantifying friction losses insteam turbine airfoils is a complex topic, whichis further explained in Reference 3. Many factorscontribute to the amount of this loss. Such fac-tors include the location (suction vs. pressure

side), the orientation, the size, and the geome-try of the projections on the airfoil surface. It iscustomary when evaluating friction losses todivide the airfoil into three regions: leadingedge, suction side trailing edge, and pressureside trailing edge. Nozzle suction side rough-ness affects stage efficiency approximately threetimes more than pressure side roughness. Theleading edge roughness will have the greatestcontribution to stage efficiency loss occurringon the bucket. Bucket leading edge suction sideroughness affects stage efficiency approximate-ly two times more than pressure side roughness.Also, because of the higher-pressure dropthrough the nozzles relative to the buckets onan impulse design stage, approximately 75% ofa stage efficiency loss caused by surface rough-ness is attributed to the nozzles. Figure 9 showsthe approximate loss in stage efficiency as afunction of surface finish for GE steam tur-bines. This information is separated by turbinesection. Since higher Reynolds Numbers arefound in the High-Pressure section (smallerboundary layer), the smaller the projectionshave to be in order to avoid an increase in fric-tion loss. This plot assumes a 63 micro-inch fin-ish for the as-built surface finish of the parti-tions. Common causes for friction lossesinclude deposits and foreign object damage.Although the Steam Path Audit inspectionrequires an evaluation of the surface roughnesson each of the turbine components, as well asthe location of particular grades of roughness,the SPA 2000 program only requires the auditorto assess the roughness on the particular com-ponent, and not to evaluate the roughness on astage based on an assumed level of reaction forthe stage. Because other loss mechanisms mayaffect the stage reaction and the energy distri-bution on the stage, the effect of increasedroughness on a component may have a more orless severe effect on the stage efficiency than if



the roughness is applied as discrete loss in stageefficiency relative to the stage in a new andclean condition with all other geometricalparameters equivalent to their design values.

Aerodynamic Losses As previously mentioned, turbine nozzle andbucket profiles and geometry are designed sothat steam accelerating through nozzle passagescan be redirected onto the buckets at optimumentrance angles and velocities. Any changes tonozzle and/or bucket profiles will change theentrance and/or exit steam angles, increasingthe aerodynamic losses within a stage. Thesefactors are critical considerations when repairsare made to these components.

Three critical parameters which should be rou-tinely inspected during the Steam Path Audit toquantify these “off-angle” steam losses includenozzle trailing edge thickness, nozzle throatwidths, and bucket leading edge profiles. Figure10 shows a plot of stage efficiency loss as a func-tion of trailing edge thickness for different noz-

zle throat widths. HP and IP turbine sectiondiaphragms are designed with nozzle trailingedge thickness in the range of 15 to 25 mils,depending on the stage. The most commoncauses of off-angle losses are due to erosion ofnozzle trailing edges and poor quality repairs.When nozzle trailing edges become eroded, thenozzle trailing edges decrease until, whenenough material is lost, pieces of trailing edgesbegin to break off. When this occurs the trailingedge thickness will increase and the off-anglelosses will increase. Diaphragm repairs whichincrease nozzle trailing edge thickness abovethe design thickness will also increase theamount of off-angle losses. The SPA 2000 pro-gram uses the loss curves presented in Figure 10,but it is only necessary for the auditor to inputthe design and measured trailing edge thick-ness for each diaphragm and the program willautomatically calculate the loss (or gain) in effi-ciency on the turbine stage, and its associatedaffect on the inlet conditions to the down-stream stage.



L.P. Turbine

I.P. Turbine

H.P. Turbine500 Mw Unit

200 Mw Unit

8 16 32 63 125 250 500

16 32 63 125 250 500 1000Surface Finish, Micro-Inches C.L.A. (Flow Across Cut)

Surface Finish, Micro-Inches C.L.A. (Flow With Cut)900 600 400 240

Emery Grade

Equivalent Sand Grain Size (Mils)

Loss

in S

tage

Effi

cien

cy (P

erce

nt)

4.0 6.0 8.0 10.02.04.0 6.0 8.0 10.0

0.4 0.6 0.8 1.00.20.10.050.01

0

2

4

6

8

10

Figure 9. Approximate loss in stage efficiency as a function of surface roughness

Losses Due to Changes in Flow Passage Areas If the flow passage area of a stage changes, theinitial pressure into that stage must change inorder to pass a constant steam flow. This changein the initial pressure will change the amount ofavailable energy to the stage, which in turn willaffect the efficiency of the stage. Changes toflow passage areas are commonly caused bydeposits (area reduction), erosion (areaincrease), or mechanical damage (area reduc-tion or increase). An approximate rule ofthumb for an impulse-type stage is a 10%increase in nozzle throat area will result in a 3%stage efficiency loss for a stage other than a con-trol stage.

In addition to the effects on stage efficiency,changes in stage areas will also affect the flowpassing capability of the turbine. This will inturn have an additional effect on the kilowattgenerating capability of the turbine for a con-

stant valve position. Deposits in the nozzlethroat area will decrease the efficiency as well asthe flow passing capability (and therefore kilo-watt capability) of the unit, while erosion of noz-zle flow passages will decrease the efficiency butincrease the turbine's flow passing capability.

However, with the introduction of the SPA 2000program, the geometry specific to the steampath is used to calculate the flow passagethrough the turbine stages and a more accurateprediction of the flow capacity of the unit canbe determined. This analysis also includes theeffect of the change in the stage flow coeffi-cients due to the presence of the observed lossmechanisms, such as steam path erosion ordeposits on the turbine stages.

SPE damage to the turbine steam path can alsoresult in secondary cycle losses caused bychanges in section efficiencies and stage pres-sures. For example, higher-than-design coldreheat temperatures (caused by erosion in theHP section) may necessitate the need for reheatattemperation. First reheat stage erosion willreduce cold reheat pressure, resulting in alower pressure to the final feedwater heater andthus a reduced final feedwater temperaturewhen the turbine extraction to the top heater isat the reheat point. First reheat stage erosionwill also reduce the reheat bowl pressure, thusincreasing the velocity through the reheaterand the reheater pressure drop.

Steam Path Audit Reporting Immediately following the conclusion of thesteam path audit, a preliminary report is pre-pared which contains the thermodynamic andstructural evaluations of the audit so that thefindings and recommendations can be incorpo-rated and implemented in a timely fashion dur-ing the outage period. The performance orthermodynamic evaluation portion of a Steam



0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Nozzle Throat - Inches

0.015

0.25

0.035

0.045

Percent Nozzle Efficiency Loss10

9

8

7

6

5

4

3

2

1

0

Nozzle Trailing Edge Thickness LossPercent of Nozzle Efficiency

Figure 10. Estimated loss in stage efficiency fordifferent trailing edge thickness

Path Audit report, using SPA 2000, will includethe following information:

■ Background information on unitinspected

■ Efficiency appraisal evaluationsummary

■ Tabular breakdown of losses

1. End shaft packings and snout rings.

2. Recoverable losses for each sectionshowing losses by component (on each stage inspected).

3. Unrecoverable losses for eachsection showing losses bycomponent (on each stageinspected). (See Figure 11.)

■ Graphical presentation of results

1. Recovered losses for each turbinesection inspected (pie charts).

2. Summary of losses by stage and type(bar charts).

3. Summary of losses by stage for eachmajor component, i.e., bucket,nozzle, tip leakage, root leakage(bar charts).

■ Color photographs of steam path

Photos of the major components and each stagewhich is inspected are made using either tradi-tional photography or employing the latest indigital camera technology. Digital photography(see Figure 12) allows the auditor to make a quickreview of the quality of the photographs. Thisformat makes the photos easily available via e-mail to GE turbine experts who are not presentat the site. This enhances the comprehensiveanalysis that is presented to the customer in areport-out at the conclusion of the audit.

Advancements in the Evaluation andAssessment of DataThe prior section explained the value of anAdvanced Steam Path Audit (SPA 2000) duringa steam turbine maintenance outage.Advancements are also ongoing for acquiring,evaluating, and assessing thermal performanceof operating power plants. To deliver more cus-tomer value, the focus of advancement is onautomation, remote access for timely diagnosticassistance, and expansion of expertise to coverthe entire power plant.



Figure 11. Overall summary of losses

Performance Monitoring

Performance Monitoring is an ongoing diag-nostic activity coupled with software tools thatallow the collection and presentation of data.Preliminary interpretation of the data can beperformed automatically. A detailed review anddetermination of data requires periodic reviewby an engineer and/or plant operator. GE nowoffers performance monitoring products forsteam turbines / gas turbines / combined cycleplants which have a suite of related modulesthat provide on-line plant performance moni-toring. The performance monitor powered byGE Enter Software’s EfficiencyMap and GateCycle software provide real-time guidance toplant owners and operators with four modules.

The On-line Heat Balance Module validates andreconciles measured data from the plant toallow operators to conserve mass and energyaround each of the major components.

The Performance Module calculates plant andcomponent efficiencies, and resulting equip-ment degradation.

The Optimizer Module recommends the opti-mum plant equipment configuration to maxi-

mize overall plant profitability at any given timeand operating conditions. The On-LineOptimizer uses real time data, allowing opera-tors to determine how best to adjust control-lable parameters to maximize profit. The Off-Line Module simulates the plant performancebased upon specific user inputs to the heat bal-ance model.

The Data Module consists of an embeddedPlant Information (PI™) System by OSISoftware, Inc., which communicates measuredtag values from the plant DCS and serves asEfficiencyMaps’ historian.

Plant diagnostic assistance, remote softwaresupport and consulting services are providedupon request by experienced GE EnterSoftware engineers and experienced GE ther-mal performance engineers. With the cus-tomer’s permission, data and results can easilybe communicated to GE’s Monitoring andDiagnostic center in Atlanta, GA.

Plant Evaluations GE is now positioned to leverage EER's* fossilboiler thermal and emission expertise alongwith GE's steam turbine cycle thermal perform-



Figure 12. Digital photography

ance expertise to deliver a Total PlantEvaluation Service. This service enables the cus-tomer to make cost-effective business decisionsto improve plant efficiency or increase plantelectrical output capacity. This service begins bygathering plant design data to understand theexpected performance and operating con-straints of a plant. Next, performance engineersvisit the plant to gather performance data andto gain a first-hand understanding of the oper-ating requirements and limitations. A detailedassessment is completed to identify loss per-formance and recommend about operationalchanges or maintenance actions to recover per-formance. The study can also include a thermalmodel study of equipment uprates/upgrades orcycle modifications for improving plant effi-ciency or kilowatt capacity.

* EER Energy and Environmental ResearchCorporation, a wholly owned subsidiary ofGeneral Electric Company

SummaryOver the next few years, becoming the “low-cost” power producer will be increasinglyimportant. Power plant owners can make a sig-nificant contribution toward achieving this goalby implementing a well-organized perform-ance-diagnostic program, which will reduce fuelcosts and facilitate cost-effective maintenance.

This paper has presented some of the latestadvancements used for evaluating and assessingthe performance of your steam turbine, includ-

ing methods for periodic data acquisition, inter-pretation of performance data, inspection ofthe turbine steam path, monitoring the per-formance of your steam turbine and evaluatingthe total plant. These programs are essential inorder to achieve and maintain the highest levelof thermal performance of a turbine-generatorunit.

GE continues to look for better ways to servicecustomers by improving the thermal efficiencyand kilowatt capacity of power plants. Today’sinternet and e-Business technology is underdevelopment to better compare unit perform-ance with fleet data and quickly assess pertinentinformation.

References1. ANSI/ASME PTC 6-1996, “Steam Turbines”.

2. ANSI/ASME PTC 6S Report - 1974,“Simplified Procedures for RoutinePerformance Tests of Steam Turbines”.

3. Forster, V.T., “Performance Loss of ModernSteam Turbine Plant Due to SurfaceRoughness”, The Institution of MechanicalEngineers Proceedings, 1966-67, vol. 181,Part I, Number 17, England.

AcknowledgementsMarriner, Brian W., “Advanced Method forAnalyzing Steam Path Audit Data”. Presented atPower-Gen International Conference 1999.



List of FiguresFigure 1. Test instrumentation location for a PTC 6S Test - fossil unit

Figure 2. Enthalpy Drop Test

Figure 3. HP & IP efficiency measurement locations

Figure 4. Throttle pressure correction for single reheat units

Figure 5. Correction for main steam and reheat steam desuperheating flow

Figure 6. HP turbine efficiency

Figure 7. Effect of change in nozzle area on flow capacity for impulse-type turbines

Figure 8. Pressure or capability curve vs. chronological test dates

Figure 9. Approximate loss in stage efficiency as a function of surface roughness

Figure 10. Estimated loss in stage efficiency for different trailing edge thickness

Figure 11. Overall summary of losses

Figure 12. Digital photography





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Steam Turbin Thermal Evaluation

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