GE Gas Turbine Performance Characteristics

GE Power Systems

GE Gas TurbinePerformanceCharacteristics

Frank J. BrooksGE Power SystemsSchenectady, NY

GER-3567H

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Thermodynamic Principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2The Brayton Cycle. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Thermodynamic Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Combined Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Factors Affecting Gas Turbine Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Air Temperature and Site Elevation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Humidity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Inlet and Exhaust Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Fuels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Fuel Heating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Diluent Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Air Extraction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Performance Enhancements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Inlet Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Steam and Water Injection for Power Augmentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Peak Rating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Performance Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Verifying Gas Turbine Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

List of Figures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

GE Gas Turbine Performance Characteristics

GE Power Systems ■ GER-3567H ■ (10/00) i


GE Power Systems ■ GER-3567H ■ (10/00) ii

IntroductionGE offers both heavy-duty and aircraft-derivativegas turbines for power generation and industri-al applications. The heavy-duty product line con-sists of five different model series: MS3002,MS5000, MS6001, MS7001 and MS9001.

The MS5000 is designed in both single- andtwo-shaft configurations for both generatorand mechanical-drive applications. TheMS5000 and MS6001 are gear-driven units thatcan be applied in 50 Hz and 60 Hz markets.

All units larger than the Frame 6 are direct-drive units. The MS7000 series units that areused for 60 Hz applications have rotationalspeeds of 3600 rpm. The MS9000 series unitsused for 50 Hz applications have a rotationalspeed of 3000 rpm. In generator-drive applica-

tions the product line covers a range fromapproximately 35,800 hp to 345,600 hp (26,000kW to 255,600 kW).

Table 1 provides a complete listing of the avail-able outputs and heat rates of the GE heavy-dutygas turbines. Table 2 lists the ratings of mechani-cal-drive units, which range from 14,520 hp to108,990 hp (10,828 kW to 80,685 kW).

The complete model number designation foreach heavy-duty product line machine is pro-vided in both Tables 1 and 2. An explanation of

the model number is given in Figure 1.

This paper reviews some of the basic thermo-dynamic principles of gas turbine operationand explains some of the factors that affect itsperformance.


GE Power Systems ■ GER-3567H ■ (10/00) 1

Table 1. GE gas turbine performance characteristics - Generator drive gas turbine ratings

GE Generator Drive Product LineModel Fuel ISO Base Heat Heat Exhaust Exhaust Exhaust Exhaust Pressure

Rating Rate Rate Flow Flow Temp Temp Ratio(kW) (Btu/kWh) (kJ/kWh) (lb/hr) (kg/hr) (degrees F) (degrees C)

x10-3 x10-3

PG5371 (PA) Gas 26,070. 12,060. 12,721 985. 446 905. 485 10.6Dist. 25,570. 12,180. 12,847 998. 448 906. 486 10.6

PG6581 (B) Gas 42,100. 10,640. 11,223 1158. 525 1010. 543 12.2Dist. 41,160. 10,730. 11,318 1161. 526 1011. 544 12.1

PG6101 (FA) Gas 69,430. 10,040. 10,526 1638. 742 1101. 594 14.6Dist. 74,090. 10,680. 10,527 1704. 772 1079. 582 15.0

PG7121 (EA) Gas 84,360. 10,480. 11,054 2361. 1070 998. 536 12.7Dist. 87,220. 10,950. 11,550 2413. 1093 993. 537 12.9

PG7241 (FA) Gas 171,700. 9,360. 9,873 3543. 1605 1119. 604 15.7Dist. 183,800. 9,965. 10,511 3691. 1672 1095. 591 16.2

PG7251 (FB) Gas 184,400. 9,245. 9,752 3561. 1613 1154. 623 18.4Dist. 177,700. 9,975. 10,522 3703. 1677 1057. 569 18.7

PG9171 (E) Gas 122,500. 10,140. 10,696 3275. 1484 1009. 543 12.6Dist. 127,300. 10,620. 11,202 3355. 1520 1003. 539 12.9

PG9231 (EC) Gas 169,200. 9,770. 10,305 4131. 1871 1034. 557 14.4Dist. 179,800. 10,360. 10,928 4291. 1944 1017. 547 14.8

PG9351 (FA) Gas 255,600. 9,250. 9,757 5118. 2318 1127. 608 15.3Dist. 268,000. 9,920. 10,464 5337. 2418 1106. 597 15.8

GT22043E

Thermodynamic PrinciplesA schematic diagram for a simple-cycle, single-shaft gas turbine is shown in Figure 2. Air entersthe axial flow compressor at point 1 at ambientconditions. Since these conditions vary fromday to day and from location to location, it isconvenient to consider some standard condi-tions for comparative purposes. The standardconditions used by the gas turbine industry are59 F/15 C, 14.7 psia/1.013 bar and 60% relativehumidity, which are established by theInternational Standards Organization (ISO)and frequently referred to as ISO conditions.

Air entering the compressor at point 1 is com-pressed to some higher pressure. No heat isadded; however, compression raises the airtemperature so that the air at the discharge ofthe compressor is at a higher temperature andpressure.

Upon leaving the compressor, air enters thecombustion system at point 2, where fuel isinjected and combustion occurs. The combus-tion process occurs at essentially constant pres-sure. Although high local temperatures arereached within the primary combustion zone(approaching stoichiometric conditions), the



Mechanical Drive Gas Turbine Ratings

Model Year ISO Rating ISO Rating Heat Heat Mass Mass Exhaust Exhaust

Continuous Continuous Rate Rate Flow Flow Temp Temp

(kW) (hp) (Btu/shp-hr) (kJ/kWh) (lb/sec) (kg/sec) (degrees F) (degrees C)

M3142 (J) 1952 11,290 15,140 9,500 13,440 117 53 1,008 542

M3142R (J) 1952 10,830 14,520 7,390 10,450 117 53 698 370

M5261 (RA) 1958 19,690 26,400 9,380 13,270 205 92 988 531

M5322R (B) 1972 23,870 32,000 7,070 10,000 253 114 666 352

M5352 (B) 1972 26,110 35,000 8,830 12,490 273 123 915 491

M5352R (C) 1987 26,550 35,600 6,990 9,890 267 121 693 367

M5382 (C) 1987 28,340 38,000 8,700 12,310 278 126 960 515

M6581 (B) 1978 38,290 51,340 7,820 11,060 295 134 1,013 545

Table 2. GE gas turbine performance characteristics - Mechanical drive gas turbine ratings

MS7000

(EA)12PG

ModelNumberof

Shafts

PowerSeriesApplication

ApproxOutputPower inHundreds,Thousands, or10 Thousandsof Horsepower

R - RegenBlank - SC

1 or 2Frame3,5,76,9

MechDrivePkgdGen

M -

PG -

17

Figure 1. Heavy-duty gas turbine model designation

GT25385A

GT23054A

combustion system is designed to provide mix-ing, burning, dilution and cooling. Thus, by thetime the combustion mixture leaves the com-bustion system and enters the turbine at point3, it is at a mixed average temperature.

In the turbine section of the gas turbine, theenergy of the hot gases is converted into work.This conversion actually takes place in twosteps. In the nozzle section of the turbine, thehot gases are expanded and a portion of thethermal energy is converted into kinetic energy.In the subsequent bucket section of the turbine,a portion of the kinetic energy is transferred tothe rotating buckets and converted to work.

Some of the work developed by the turbine isused to drive the compressor, and the remain-der is available for useful work at the outputflange of the gas turbine. Typically, more than50% of the work developed by the turbine sec-tions is used to power the axial flow compressor.

As shown in Figure 2, single-shaft gas turbinesare configured in one continuous shaft and,therefore, all stages operate at the same speed.These units are typically used for generator-drive applications where significant speed varia-tion is not required.

A schematic diagram for a simple-cycle, two-shaft gas turbine is shown in Figure 3. The low-pressure or power turbine rotor is mechani-cally separate from the high-pressure turbineand compressor rotor. The low pressure rotoris said to be aerodynamically coupled. Thisunique feature allows the power turbine to beoperated at a range of speeds and makes two-shaft gas turbines ideally suited for variable-speed applications.

All of the work developed by the power turbineis available to drive the load equipment sincethe work developed by the high-pressure tur-bine supplies all the necessary energy to drivethe compressor. On two-shaft machines thestarting requirements for the gas turbine loadtrain are reduced because the load equipmentis mechanically separate from the high-pressureturbine.

The Brayton CycleThe thermodynamic cycle upon which all gasturbines operate is called the Brayton cycle.Figure 4 shows the classical pressure-volume(PV) and temperature-entropy (TS) diagramsfor this cycle. The numbers on this diagram cor-



Compressor

Inlet Air

1

CombustorFuel

2

4

Exhaust

3

Turbine

Generator

Figure 2. Simple-cycle, single-shaft gas turbine

GT08922A

respond to the numbers also used in Figure 2.Path 1 to 2 represents the compression occur-ring in the compressor, path 2 to 3 representsthe constant-pressure addition of heat in thecombustion systems, and path 3 to 4 representsthe expansion occurring in the turbine.

The path from 4 back to 1 on the Brayton cyclediagrams indicates a constant-pressure coolingprocess. In the gas turbine, this cooling is doneby the atmosphere, which provides fresh, cool

air at point 1 on a continuous basis in exchangefor the hot gases exhausted to the atmosphereat point 4. The actual cycle is an “open” ratherthan “closed” cycle, as indicated.

Every Brayton cycle can be characterized by twosignificant parameters: pressure ratio and firingtemperature. The pressure ratio of the cycle isthe pressure at point 2 (compressor dischargepressure) divided by the pressure at point 1(compressor inlet pressure). In an ideal cycle,



Exhaust

LoadLP

Compressor

Inlet Air

CombustorFuel

HP

Turbine

Figure 3. Simple-cycle, two-shaft gas turbine

1

2

1

2

1

2

3

4

4

4

3

3

FuelP

T

S

V

Figure 4. Brayton cycle

GT08923C

GT23055A

this pressure ratio is also equal to the pressureat point 3 divided by the pressure at point 4.However, in an actual cycle there is some slightpressure loss in the combustion system and,hence, the pressure at point 3 is slightly lessthan at point 2.

The other significant parameter, firing temper-ature, is thought to be the highest temperaturereached in the cycle. GE defines firing temper-ature as the mass-flow mean total temperature

at the stage 1 nozzle trailing edge plane.Currently all first stage nozzles are cooled tokeep the temperatures within the operating lim-its of the materials being used. The two types ofcooling currently employed by GE are air andsteam.

Air cooling has been used for more than 30years and has been extensively developed in air-craft engine technology, as well as the latest fam-ily of large power generation machines. Airused for cooling the first stage nozzle enters thehot gas stream after cooling down the nozzleand reduces the total temperature immediatelydownstream. GE uses this temperature since it ismore indicative of the cycle temperature repre-

sented as firing temperature by point 3 in Figure4.

Steam-cooled first stage nozzles do not reducethe temperature of the gas directly throughmixing because the steam is in a closed loop.As shown in Figure 5, the firing temperature ona turbine with steam-cooled nozzles (GE’s cur-rent “H” design) has an increase of 200degrees without increasing the combustionexit temperature.

An alternate method of determining firing tem-perature is defined in ISO document 2314, “GasTurbines – Acceptance Tests.” The firing tem-perature here is a reference turbine inlet tem-perature and is not generally a temperature thatexists in a gas turbine cycle; it is calculated froma heat balance on the combustion system, usingparameters obtained in a field test. This ISOreference temperature will always be less thanthe true firing temperature as defined by GE, inmany cases by 100 F/38 C or more for machinesusing air extracted from the compressor forinternal cooling, which bypasses the combustor.Figure 6 shows how these various temperaturesare defined.



Figure 5. Comparison of air-cooled vs. steam-cooled first stage nozzle

OPEN LOOPAIR-COOLED NOZZLE

ADVANCED CLOSED LOOPSTEAM-COOLED NOZZLE

200F More Firing Temp. at Same NOx Production Possible GT25134

Thermodynamic Analysis

Classical thermodynamics permit evaluation ofthe Brayton cycle using such parameters as pres-sure, temperature, specific heat, efficiency fac-tors and the adiabatic compression exponent. Ifsuch an analysis is applied to the Brayton cycle,the results can be displayed as a plot of cycleefficiency vs. specific output of the cycle.

Figure 7 shows such a plot of output and

efficiency for different firing temperatures andvarious pressure ratios. Output per pound of airflow is important since the higher this value,the smaller the gas turbine required for the sameoutput power. Thermal efficiency is importantbecause it directly affects the operating fuel costs.

Figure 7 illustrates a number of significantpoints. In simple-cycle applications (the topcurve), pressure ratio increases translate intoefficiency gains at a given firing temperature.



Turbine Inlet Temperature - Average Gas Temp in Plane A. (TA)

ISO Firing Temperature - Calculated Temp in Plane C. TC = f(Ma , Mf)

GE Uses Firing Temperature TB

• Highest Temperature at Which Work Is Extracted

Firing Temperature - Average Gas Temp in Plane B. (TB)

CL

Figure 6. Definition of firing temperature

Figure 7. Gas turbine thermodynamics

GT23056

GT17983A

The pressure ratio resulting in maximum out-put and maximum efficiency change with firingtemperature, and the higher the pressure ratio,the greater the benefits from increased firingtemperature. Increases in firing temperatureprovide power increases at a given pressureratio, although there is a sacrifice of efficiencydue to the increase in cooling air lossesrequired to maintain parts lives.

In combined-cycle applications (as shown in thebottom graph in Figure 7), pressure ratioincreases have a less pronounced effect on effi-ciency. Note also that as pressure ratio increas-es, specific power decreases. Increases in firingtemperature result in increased thermal effi-ciency. The significant differences in the slopeof the two curves indicate that the optimumcycle parameters are not the same for simpleand combined cycles.

Simple-cycle efficiency is achieved with highpressure ratios. Combined-cycle efficiency isobtained with more modest pressure ratios andgreater firing temperatures. For example, theMS7001FA design parameters are 2420 F/1316 Cfiring temperature and 15.7:1 pressure ratio;

while simple-cycle efficiency is not maximized,combined-cycle efficiency is at its peak.Combined cycle is the expected application forthe MS7001FA.

Combined CycleA typical simple-cycle gas turbine will convert30% to 40% of the fuel input into shaft output.All but 1% to 2% of the remainder is in theform of exhaust heat. The combined cycle isgenerally defined as one or more gas turbineswith heat-recovery steam generators in theexhaust, producing steam for a steam turbinegenerator, heat-to-process, or a combinationthereof.

Figure 8 shows a combined cycle in its simplestform. High utilization of the fuel input to thegas turbine can be achieved with some of themore complex heat-recovery cycles, involvingmultiple-pressure boilers, extraction or toppingsteam turbines, and avoidance of steam flow toa condenser to preserve the latent heat content.Attaining more than 80% utilization of the fuelinput by a combination of electrical power gen-eration and process heat is not unusual.



Exhaust

Fuel

Gas TurbineAir

Comp Turb Gen

Gen

Comb

HRSGST

Turb

Figure 8. Combined cycle

GT05363C

Gen

Combined cycles producing only electricalpower are in the 50% to 60% thermal efficien-cy range using the more advanced gas turbines.

Papers dealing with combined-cycle applica-tions in the GE Reference Library include:GER-3574F, “GE Combined-Cycle Product Lineand Performance”; GER-3767, “Single-ShaftCombined-Cycle Power Generation Systems”;and GER-3430F, “Cogeneration ApplicationConsiderations.”

Factors Affecting Gas TurbinePerformance

Air Temperature and Site ElevationSince the gas turbine is an air-breathing engine,its performance is changed by anything thataffects the density and/or mass flow of the airintake to the compressor. Ambient weatherconditions are the most obvious changes fromthe reference conditions of 59 F/15 C and 14.7psia/1.013 bar. Figure 9 shows how ambient tem-perature affects the output, heat rate, heat con-sumption, and exhaust flow of a single-shaftMS7001. Each turbine model has its own tem-perature-effect curve, as it depends on the cycle

parameters and component efficiencies as wellas air mass flow.

Correction for altitude or barometric pressureis more straightforward. The air density reducesas the site elevation increases. While the result-ing airflow and output decrease proportionate-ly, the heat rate and other cycle parameters arenot affected. A standard altitude correctioncurve is presented in Figure 10.

HumiditySimilarly, humid air, which is less dense thandry air, also affects output and heat rate, asshown in Figure 11. In the past, this effect wasthought to be too small to be considered.However, with the increasing size of gas turbinesand the utilization of humidity to bias water andsteam injection for NOx control, this effect hasgreater significance.

It should be noted that this humidity effect is aresult of the control system approximation offiring temperature used on GE heavy-duty gasturbines. Single-shaft turbines that use turbineexhaust temperature biased by the compressorpressure ratio to the approximate firing tem-perature will reduce power as a result of



-7

0

130

Output

CompressorInlet

Temperature

PercentDesign

Heat Rate

Exhaust FlowHeat Cons.

120

49

100

38

80

27

60

16

40

4

20

-18

°F

°C

70

80

90

100

110

120

Figure 9. Effect of ambient temperature

GT22045D

increased ambient humidity. This occursbecause the density loss to the air from humidi-ty is less than the density loss due to tempera-ture. The control system is set to follow the inletair temperature function.

By contrast, the control system on aeroderiva-tives uses unbiased gas generator discharge tem-perature to approximate firing temperature.The gas generator can operate at differentspeeds from the power turbine, and the powerwill actually increase as fuel is added to raise the

moist air (due to humidity) to the allowabletemperature. This fuel increase will increase thegas generator speed and compensate for theloss in air density.

Inlet and Exhaust LossesInserting air filtration, silencing, evaporativecoolers or chillers into the inlet or heat recov-ery devices in the exhaust causes pressure lossesin the system. The effects of these pressure loss-es are unique to each design. Figure 12 shows



Figure 10. Altitude correction curve

Figure 11. Humidity effect curve

GT18848B

GT22046B

the effects on the MS7001EA, which are typicalfor the E technology family of scaled machines(MS6001B, 7001EA, 9001E).

FuelsWork from a gas turbine can be defined as theproduct of mass flow, heat energy in the com-busted gas (Cp), and temperature differentialacross the turbine. The mass flow in thisequation is the sum of compressor airflowand fuel flow. The heat energy is a functionof the elements in the fuel and the productsof combustion.

Tables 1 and 2 show that natural gas (methane)produces nearly 2% more output than does dis-tillate oil. This is due to the higher specific heatin the combustion products of natural gas,resulting from the higher water vapor contentproduced by the higher hydrogen/carbon ratioof methane. This effect is noted even thoughthe mass flow (lb/h) of methane is lower thanthe mass flow of distillate fuel. Here the effectsof specific heat were greater than and in oppo-sition to the effects of mass flow.

Figure 13 shows the total effect of various fuelson turbine output. This curve uses methane asthe base fuel.

Although there is no clear relationship betweenfuel lower heating value (LHV) and output, it is

possible to make some general assumptions. Ifthe fuel consists only of hydrocarbons with noinert gases and no oxygen atoms, outputincreases as LHV increases. Here the effects ofCp are greater than the effects of mass flow.Also, as the amount of inert gases is increased,the decrease in LHV will provide an increase inoutput. This is the major impact of IGCC typefuels that have large amounts of inert gas in thefuel. This mass flow addition, which is not com-pressed by the gas turbine’s compressor,increases the turbine output. Compressorpower is essentially unchanged. Several sideeffects must be considered when burning thiskind of lower heating value fuels:

■ Increased turbine mass flow drives upcompressor pressure ratio, whicheventually encroaches on thecompressor surge limit

■ The higher turbine power may exceedfault torque limits. In many cases, alarger generator and other accessoryequipment may be needed

■ High fuel volumes increase fuel pipingand valve sizes (and costs). Low- ormedium-Btu coal gases are frequentlysupplied at high temperatures, whichfurther increases their volume flow



Figure 12. Pressure drop effects (MS7001EA)

4 Inches (10 mbar) H2O Inlet Drop Produces:

1.42% Power Output Loss

0.45% Heat Rate Increase

1.9 F (1.1 C) Exhaust Temperature Increase

4 Inches (10 mbar) H2O Exhaust Drop Produces:

0.42% Power Output Loss

0.42% Heat Rate Increase

1.9 F (1.1 C) Exhaust Temperature IncreaseGT18238C

■ Lower-Btu gases are frequentlysaturated with water prior to deliveryto the turbine. This increases thecombustion products heat transfercoefficients and raises the metaltemperatures in the turbine sectionwhich may require lower operatingfiring temperature to preserve partslives

■ As the Btu value drops, more air isrequired to burn the fuel. Machineswith high firing temperatures may notbe able to burn low Btu gases

■ Most air-blown gasifiers use airsupplied from the gas turbinecompressor discharge

■ The ability to extract air must beevaluated and factored into the overallheat and material balances

As a result of these influences, each turbinemodel will have some application guidelines onflows, temperatures and shaft output to preserve

its design life. In most cases of operation withlower heating value fuels, it can be assumed thatoutput and efficiency will be equal to or higherthan that obtained on natural gas. In the case ofhigher heating value fuels, such as refinerygases, output and efficiency may be equal to orlower than that obtained on natural gas.

Fuel HeatingMost of the combined cycle turbine installationsare designed for maximum efficiency. Theseplants often utilize integrated fuel gas heaters.Heated fuel results in higher turbine efficiencydue to the reduced fuel flow required to raisethe total gas temperature to firing temperature.Fuel heating will result in slightly lower gas tur-bine output because of the incremental volumeflow decrease. The source of heat for the fueltypically is the IP feedwater. Since use of thisenergy in the gas turbine fuel heating system isthermodynamically advantageous, the com-bined cycle efficiency is improved by approxi-mately 0.6%.



100%H2

4020

100%CH4

Output - Percent

Kca

l/kg

(Tho

usan

ds)

LHV

-Btu

/lb (

Tho

usan

ds)

105

100% CO75% N2 - 25% CH4

75% CO2 - 25% CH4

100%CH4H10

60

50

30

20

10

10

30

0100 110 115 120 125 130

Figure 13. Effect of fuel heating value on output

GT25842

Diluent InjectionSince the early 1970s, GE has used water orsteam injection for NOx control to meet appli-cable state and federal regulations. This isaccomplished by admitting water or steam inthe cap area or “head-end” of the combustionliner. Each machine and combustor configura-tion has limits on water or steam injection levelsto protect the combustion system and turbinesection. Depending on the amount of water orsteam injection needed to achieve the desiredNOx level, output will increase because of the

additional mass flow. Figure 14 shows the effectof steam injection on output and heat rate foran MS7001EA. These curves assume that steamis free to the gas turbine cycle, therefore heatrate improves. Since it takes more fuel to raisewater to combustor conditions than steam,water injection does not provide an improve-ment in heat rate.

Air ExtractionIn some gas turbine applications, it may bedesirable to extract air from the compressor.

Generally, up to 5% of the compressor airflowcan be extracted from the compressor dis-charge casing without modification to casingsor on-base piping. Pressure and air temperaturewill depend on the type of machine and siteconditions. Air extraction between 6% and 20%may be possible, depending on the machineand combustor configuration, with some modi-fications to the casings, piping and controls.Such applications need to be reviewed on acase-by-case basis. Air extractions above 20%will require extensive modification to the tur-bine casing and unit configuration. Figure 15

shows the effect of air extraction on output andheat rate. As a “rule of thumb,” every 1% in airextraction results in a 2% loss in power.

Performance EnhancementsGenerally, controlling some of the factors thataffect gas turbine performance is not possible.The planned site location and the plant config-uration (such as simple- or combined-cycle)determine most of these factors. In the eventadditional output is needed, several possibilitiesto enhance performance may be considered.



130

120

110

100

90

80

70

Output%

Compressor Inlet Temperature

40 60 80 100 120ºF

4 16 27 38 49ºC

1%

3%

No SteamInjection

With 5%Steam

Injection

Figure 14. Effect of steam injection on output andheat rate

Figure 15. Effect of air extraction on output and heatrate

GT18851A GT22048-1C

Inlet CoolingThe ambient effect curve (see Figure 9) clearlyshows that turbine output and heat rate areimproved as compressor inlet temperaturedecreases. Lowering the compressor inlet tem-perature can be accomplished by installing anevaporative cooler or inlet chiller in the inletducting downstream of the inlet filters. Carefulapplication of these systems is necessary, as con-densation or carryover of water can exacerbatecompressor fouling and degrade performance.These systems generally are followed by mois-ture separators or coalescing pads to reduce thepossibility of moisture carryover.

As Figure 16 shows, the biggest gains from evap-orative cooling are realized in hot, low-humid-ity climates. It should be noted that evapora-tive cooling is limited to ambient temperaturesof 59 F/15 C and above (compressor inlet tem-perature >45 F/7.2 C) because of the potentialfor icing the compressor. Information con-tained in Figure 16 is based on an 85% effectiveevaporative cooler. Effectiveness is a measureof how close the cooler exit temperatureapproaches the ambient wet bulb tempera-

ture. For most applications, coolers having aneffectiveness of 85% or 90% provide the mosteconomic benefit.

Chillers, unlike evaporative coolers, are not lim-ited by the ambient wet bulb temperature. Theachievable temperature is limited only by thecapacity of the chilling device to producecoolant and the ability of the coils to transferheat. Cooling initially follows a line of constant



Figure 16. Effect of evaporative cooling on outputand heat rate

49

120°F

°C

Dry BulbTemperature

20

25

30

35

40100% RH

15.005

.020

SpecificHumidity

EvaporativeCooling Process

Btu Per Poundof Dry Air

(Simplified)

PsychrometricChart

.000

.010

.015

40 60 80 100

4 16 27 38

10% RH

Inlet ChillingProcess

20% RH

40% RH

60% RH

Figure 17. Inlet chilling process

GT22419-1D

GT21141D

specific humidity, as shown in Figure 17. As satu-ration is approached, water begins to condensefrom the air, and mist eliminators are used.Further heat transfer cools the condensate andair, and causes more condensation. Because ofthe relatively high heat of vaporization of water,most of the cooling energy in this regime goesto condensation and little to temperaturereduction.

Steam and Water Injection for PowerAugmentationInjecting steam or water into the head end ofthe combustor for NOx abatement increasesmass flow and, therefore, output. Generally, theamount of water is limited to the amountrequired to meet the NOx requirement in orderto minimize operating cost and impact oninspection intervals.

Steam injection for power augmentation hasbeen an available option on GE gas turbines forover 30 years. When steam is injected for poweraugmentation, it can be introduced into thecompressor discharge casing of the gas turbineas well as the combustor. The effect on outputand heat rate is the same as that shown in Figure14. GE gas turbines are designed to allow up to5% of the compressor airflow for steam injec-tion to the combustor and compressor dis-charge. Steam must contain 50 F/28 C super-heat and be at pressures comparable to fuel gaspressures.

When either steam or water is used for poweraugmentation, the control system is normallydesigned to allow only the amount needed forNOx abatement until the machine reaches base(full) load. At that point, additional steam orwater can be admitted via the governor control.

Peak RatingThe performance values listed in Table 1 arebase load ratings. ANSI B133.6 Ratings and

Performance defines base load as operation at8,000 hours per year with 800 hours per start. Italso defines peak load as operation at 1250hours per year with five hours per start.

In recognition of shorter operating hours, it ispossible to increase firing temperature to gen-erate more output. The penalty for this type ofoperation is shorter inspection intervals.Despite this, running an MS5001, MS6001 orMS7001 at peak may be a cost-effective way toobtain more kilowatts without the need foradditional peripheral equipment.

Generators used with gas turbines likewise havepeak ratings that are obtained by operating athigher power factors or temperature rises. Peakcycle ratings are ratings that are customized tothe mission of the turbine considering bothstarts and hours of operation. Firing tempera-tures between base and peak can be selected tomaximize the power capabilities of the turbinewhile staying within the starts limit envelope ofthe turbine hot section repair interval. Forinstance, the 7EA can operate for 24,000 hourson gas fuel at base load, as defined. The startslimit to hot section repair interval is 800 starts.

For peaking cycle of five hours per start, the hotsection repair interval would occur at 4,000hours, which corresponds to operation at peakfiring temperatures. Turbine missions betweenfive hours per start and 800 hours per start mayallow firing temperatures to increase above basebut below peak without sacrificing hours to hotsection repair. Water injection for power aug-mentation may be factored into the peak cyclerating to further maximize output.

Performance DegradationAll turbomachinery experiences losses in per-formance with time. Gas turbine performancedegradation can be classified as recoverable ornon-recoverable loss. Recoverable loss is usually



associated with compressor fouling and can bepartially rectified by water washing or, morethoroughly, by mechanically cleaning the com-pressor blades and vanes after opening the unit.Non-recoverable loss is due primarily toincreased turbine and compressor clearancesand changes in surface finish and airfoil con-tour. Because this loss is caused by reduction incomponent efficiencies, it cannot be recoveredby operational procedures, external mainte-nance or compressor cleaning, but onlythrough replacement of affected parts at rec-ommended inspection intervals.

Quantifying performance degradation is diffi-cult because consistent, valid field data is hardto obtain. Correlation between various sites isimpacted by variables such as mode of opera-tion, contaminants in the air, humidity, fuel anddilutent injection levels for NOx. Another prob-lem is that test instruments and procedures varywidely, often with large tolerances.

Typically, performance degradation during thefirst 24,000 hours of operation (the normallyrecommended interval for a hot gas pathinspection) is 2% to 6% from the performancetest measurements when corrected to guaran-teed conditions. This assumes degraded partsare not replaced. If replaced, the expected per-formance degradation is 1% to 1.5%. Recentfield experience indicates that frequent off-linewater washing is not only effective in reducingrecoverable loss, but also reduces the rate ofnon-recoverable loss.

One generalization that can be made from thedata is that machines located in dry, hot cli-mates typically degrade less than those inhumid climates.

Verifying Gas Turbine PerformanceOnce the gas turbine is installed, a perform-ance test is usually conducted to determine

power plant performance. Power, fuel, heatconsumption and sufficient supporting datashould be recorded to enable as-tested per-formance to be corrected to the condition ofthe guarantee. Preferably, this test should bedone as soon as practical, with the unit in newand clean condition. In general, a machine isconsidered to be in new and clean condition ifit has less than 200 fired hours of operation.

Testing procedures and calculation methods arepatterned after those described in the ASMEPerformance Test Code PTC-22-1997, “GasTurbine Power Plants.” Prior to testing, all sta-tion instruments used for primary data collec-tion must be inspected and calibrated. The testshould consist of sufficient test points to ensurevalidity of the test set-up. Each test point shouldconsist of a minimum of four complete sets ofreadings taken over a 30-minute time periodwhen operating at base load. Per ASME PTC-22-1997, the methodology of correcting test resultsto guarantee conditions and measurementuncertainties (approximately 1% on output andheat rate when testing on gas fuel) shall beagreed upon by the parties prior to the test.

SummaryThis paper reviewed the thermodynamic princi-ples of both one- and two-shaft gas turbines anddiscussed cycle characteristics of the severalmodels of gas turbines offered by GE. Ratings ofthe product line were presented, and factorsaffecting performance were discussed alongwith methods to enhance gas turbine output.

GE heavy-duty gas turbines serving industrial,utility and cogeneration users have a provenhistory of sustained performance and reliabili-ty. GE is committed to providing its customerswith the latest in equipment designs andadvancements to meet power needs at highthermal efficiency.



List of FiguresFigure 1. Heavy-duty gas turbine model designation

Figure 2. Simple-cycle, single-shaft gas turbine

Figure 3. Simple-cycle, two-shaft gas turbine

Figure 4. Brayton cycle

Figure 5. Comparison of air-cooled vs. steam-cooled first stage nozzle

Figure 6. Definition of firing temperature

Figure 7. Gas turbine thermodynamics

Figure 8. Combined cycle

Figure 9. Effect of ambient temperature

Figure 10. Altitude correction curve

Figure 11. Humidity effect curve

Figure 12. Pressure drop effects (MS7001EA)

Figure 13. Effect of fuel heating value on output

Figure 14. Effect of steam injection on output and heat rate

Figure 15. Effect of air extraction on output and heat rate

Figure 16. Effect of evaporative cooling on output and heat rate

Figure 17. Inlet chilling process

List of TablesTable 1. GE gas turbine performance characteristics - Generator drive gas turbine ratings

Table 2. GE gas turbine performance characteristics - Mechanical drive gas turbine ratings



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GE Gas Turbine Performance Characteristics