ger-4200 - economic and technical considerations for ......opposed to the bottoming cycle...

GE Power Systems

Economic and TechnicalConsiderations forCombined-CyclePerformance-EnhancementOptions

Chuck JonesJohn A. Jacobs IIIGE Power SystemsSchenectady, NY

GER-4200

g

ContentsAbstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Economic Evaluation Technique . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Output Enhancement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Gas Turbine Inlet Air Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Evaporative Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Evaporative Cooling Methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Evaporative Cooling Theory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Wetted-Honeycomb Evaporative Coolers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Water Requirements for Evaporative Coolers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Foggers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Evaporative Media and Inlet Fogging Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Evaporative Media . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Inlet Fogging. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Evaporative Intercooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Inlet Chilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Inlet Chilling Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Off-Peak Thermal Energy Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Comparison of Direct Chilling and Thermal Energy Storage . . . . . . . . . . . . . . . . . . . . . . . . . . 13LNG/LPG Gas Vaporizers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Power Augmentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Gas Turbine Steam/Water Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Supplementary Fired HRSG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Peak Firing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Output Enhancement Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Efficiency Enhancement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Fuel Heating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Performance-Enhancement Case Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Assumptions/Base Plant Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Description of Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

HRSG Duct Firing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Gas Turbine Inlet Fogging/Evaporative Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Gas Turbine Inlet Chilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Economic and Technical Considerations for Combined-Cycle Performance-Enhancement Options

GE Power Systems ■ GER-4200 ■ (10/00) i

HRSG Duct Firing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Gas Turbine Inlet Air Fogging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Gas Turbine Evaporative Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Gas Turbine Inlet Air Chilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Economic Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Other Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30List of Exhibits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30


GE Power Systems ■ GER-4200 ■ (10/00) ii

AbstractOver the past several years tumultuous, revolu-tionary and widespread changes have occurredwithin the U.S. power generation industry.Deregulation, linked with declining reservemargins and climatic temperature extremes hasresulted in new economic plant-operation con-siderations for owners of existing power plantsand developers of new power plants.

A sustained increase in summer peak periodpower demands and peak pe-riod durationcombined with escalation of peak energy rates(¢/kWh) have encouraged owners and opera-tors of existing plants and developers of com-bined-cycle power plants to seek power-enhanc-ing alternatives for optimizing plant perform-ance and revenue streams.

Various methods are available for improving theperformance of combined-cycle power plantsduring initial plant design or as uprate oppor-tunities. Improvements can be made in plantoutput or efficiency beyond those achievablethrough higher steam temperatures, multiplesteam-pressure levels or reheat cycles. Forexample, it has become commonplace to installgas fuel heating on new combined-cycle powerplants to improve plant efficiency. Additionally,gas turbine inlet air cooling is sometimes con-sidered for increasing gas turbine and com-bined-cycle output.

A variety of options available for enhancingcombined-cycle performance (primarily plantoutput) exists; this paper presents a technicaldescription of each alternative, outlines the rel-ative performance benefits of each enhance-ment alternative and discusses the potentialeconomic valuation of the alternatives and com-bination of alternatives.

Given the large volume of GE, 7FA (PG7241FA)gas turbine sales over the last several years and

sales commitments for the next several years,coupled with an expectation that many of thesewill be configured as STAG 207FA (two gas tur-bines and one steam turbine) combined-cycleplants, the economic assessment of perform-ance-enhancement alternatives is presented inthe form of a case study for a STAG 207FA com-bined-cycle plant configuration.

IntroductionPlant output and efficiency are carefully consid-ered during the initial plant design becausethey impact the cost of electricity in combina-tion with fuel costs, plant capital cost, cost ofcapital and electricity sales. These fac-tors willdrive the gas turbine selection as well as the bot-toming cycle design in combined-cycle opera-tion. As fuel costs increase, cycle selections typi-cally include higher steam pressures, multiplesteam pressure levels, reheat cycles and highersteam temperatures. Once these selections havebeen made, other factors are addressed. Is therea need for peak power production with premi-ums paid for the resulting power? If so, gas tur-bine power augmentation by way of water orsteam injection or a supplementary fired heatrecovery steam generator (HRSG) may be thesolution. Do peak power demands occur on ahot day (summer peaking)? This may suggest apotential benefit from some form of gas turbineinlet evaporative cooling or chilling.

For existing plants, some performance-enhancement options can also be economicallyretrofitted to boost power output and efficiency.Although this paper’s primary focus is onoptions that enhance output, a brief discussionof fuel gas heating, which is a technique used toenhance combined-cycle plant efficiency, is pro-vided.

The ability of utilities and independent powerproducers (IPPs) to generate additional power


GE Power Systems ■ GER-4200 ■ (10/00) 1

beyond a plant’s base capacity during summerpeak power demand periods has become animportant consideration in the design of com-bined-cycle plant configurations. In recentyears, utilities and IPPs within the United Stateshave received premiums for power generationcapacity during summer peak power demandperiods. Figure 1 depicts one plausible scenariofor the price of electricity (¢/kWh) as a func-tion of annual operating hours. It should benoted that curves like this one are highlyregional dependent. With price-duration curvessuch as this, the majority of a plant’s profitabili-ty could be driven by the high peak energy ratesthat can be achieved over a relatively short peri-od of time. Thus, a plant that can economicallydispatch a large quantity of additional powercould realize the largest profits.

While current market trends such as the onedepicted in Figure 1 should be considered dur-ing the design and development phase of acombined-cycle facility, forecasts of future mar-ket trends and expectations are equally impor-tant and warrant design considerations.

One of the primary challenges facing develop-ers of new combined-cycle plants, as well asowner/operators of existing plants, is the opti-mization of plant revenue streams. As a result ofescalating peak energy rates and peak demand

duration, significant emphasis has been placedon developing plant designs that maximizepeak power generation capacity while allowingfor cost-effective, efficient operation of theplant during non-peak power demand periods.In addition to maximizing plant profitability inthe face of today’s marketplace, expectations offuture market trends must be considered.

Economic Evaluation TechniqueFrom an economics perspective this paper willqualitatively explore the potential revenuestream trade-off between a combined-cycleplant without performance enhancements tothe same plant if it were to include a perform-ance-enhancement option or a combination ofoptions. Our goal is to determine which per-formance-enhancement options or combina-tion of options can be applied to a new or exist-ing combined-cycle plant to maximize totalplant profits on a plant life-cycle basis. A glos-sary of economic terms referenced in this textappears at the end of this paper.

With very few exceptions, the addition ofpower-enhancement techniques to a base plantconfiguration will impact baseload perform-ance negatively and, hence, affect a plant’s netrevenue generating capability adversely duringnonpeak periods. Figure 2 is an exaggerated



Estimated Electricity Price Duration Curve

0

10

20

30

40

50

60

70

80

0 1000 2000 3000 4000 5000 6000 7000 8000

Annual Operating Hours (hrs)

Pea

k E

nerg

y R

ate

(¢/k

WH

)

Figure 1. Potential peak energy rate variation as afunction of operating hours

Power Enhancement Performance Consideration

m b

Pea

Bas

Benefit

Penalty

Figure 2. Plant performance trends

graphic representation of this concept. In gen-eral, efficiency is the predominate economicdriver during non-peak generating periods,while capacity dominates the economic evalua-tion during peak power demand periods. Thus,it is extremely important to develop an eco-nomic model that considers both the cost ofelectricity (COE) during non-peak periodswhile taking into consideration expectations ofpeak energy rates.

After having established baseline peak and non-peak period performance levels for the variouspower-enhancement alternatives, a COE analy-sis technique is applied to determine alterna-tives that would afford the best overall life-cyclebenefit. In addition to including both peak andnon-peak performance levels, the COE modelincludes the split between annual peak andnon-peak operating hours, the premium paidfor peak power generation capacity, the cost offuel, plant capital cost, the incremental capitalcost of the enhancements and the cost to oper-ate and maintain the plant. This COE model isthen used to determine the sensitivity of a givenpower-enhancement alternative with respect tothe economic parameters included within it.

Most peak power enhancement opportunitiesexist in the topping cycle (gas turbine) asopposed to the bottoming cycle (HRSG/steamturbine). In general, with the exception of ductfiring within the HRSG, there are few in-dependent design enhancements that can bemade to a bottoming cycle that has alreadybeen fully optimized to achieve maximum plantperformance. However, in general, perform-ance enhancements to the gas turbines willcarry with them an increase in bottoming cycleperformance due to an associated increase ingas turbine exhaust energy.

Output EnhancementPlant output enhancements can be categorized

further into two major categories: gas turbineinlet cooling and power augmentation.

Gas Turbine Inlet Air Cooling For applications where significant powerdemand and highest electricity prices occurduring the warm months, a gas turbine air inletcooling system is a useful option for increasingoutput. Inlet air cooling increases output by tak-ing advantage of the gas turbine’s characteristicof higher mass flow rate and, thus, output as thecompressor inlet temperature decreases.

Industrial gas turbines that run at constantspeed are constant-volume-flow machines. Thespecific volume of air is directly proportional tothe temperature. Because the cooled air isdenser, it gives the machine a higher air massflow rate and pressure ratio, resulting in anincrease in output. In combined-cycle applica-tions there is also a small improvement in ther-mal efficiency.

Figure 3 shows that a 10°F (5.6°C) reduction ingas turbine inlet dry-bulb temperature forheavy-duty gas turbines improves combined-cycle output by about 2.7%. The actual changeis somewhat dependent on the method of steamturbine condenser cooling being used. Simple-



100

110

90

80

120

90

100

102

Rated Point

Ambient Air Temperature

-10 0 10 20 30 4012010080604020 F

C0

Heat Rate(Percentof Rated)

Power Output(Percentof Rated)

Figure 3. Combined-cycle system performance variationwith ambient air temperature

cycle output is improved by a similar percent-age. Several methods are available for reducinggas turbine inlet temperature. There are twobasic systems currently available for inlet cool-ing. The first and perhaps the most widelyaccepted system is evaporative cooling.Evaporative coolers make use of the evapora-tion of water to reduce the gas turbine’s inlet airtemperature. The second system employs vari-ous ways to chill the inlet air. In this system, thecooling medium (usually chilled water) flowsthrough a heat exchanger located in the inletduct to remove heat from the inlet air.Evaporative cooling is limited by wet-bulb tem-perature. Chilling, however, can cool the inletair to temperatures that are lower than the wet-bulb temperature, thus providing additionaloutput albeit at a significantly higher cost.Depending on the combustion and control sys-tem, evaporative cooling may reduce NOx emis-sions; however, there is very little benefit to begained from current dry low NOx technology.

In the case of uprates and new unit designs,even though the compressor inlet temperatureis reduced, the temperature of the cooling airto the generator, transformer, cooling air cool-er (if applicable) and lubricating oil cooler isnot reduced. Calculations must be performedto determine if these components can handlethe increased power and loads at the elevatedtemperatures.

Evaporative Cooling Evaporative cooling is a cost-effective way to addmachine capacity during warm weather whenpeaking power periods are usually encounteredon electric utility systems, provided the relativehumidity is not too high.

Evaporative Cooling Methods There are two basic systems for achieving evap-orative cooling. The first uses a wetted-honey-

comb type of medium and is typically referredto as an evaporative cooler. The second systemis known as an inlet fogger.

Evaporative Cooling Theory Evaporative cooling works on the principle ofreducing the temperature of an air streamthrough water evaporation. The process of con-verting the water from a liquid to a vapor staterequires energy. This energy is drawn from theair stream. The result is cooler, more humid air.A psychrometric chart (Figure 4) is useful inexploring the theoretical and practical limita-tions of evaporative cooling.

Theoretically, the minimum temperature thatcan be achieved by adding water to the air isequal to the ambient wet-bulb temperature.Practically, this level of cooling is difficult toachieve. The actual temperature drop realizedis a function of both the equipment design andatmospheric conditions. Other factors beingconstant, the effectiveness of an evaporativecooling system depends on the surface area ofwater exposed to the air stream and the resi-dence time. The effectiveness of the cooler is afunction of its design and is defined as follows:

Cooler effectiveness = T 1DB – T2T1DB – T2WB

■ 1 refers to entering conditions.

■ 2 refers to exit conditions.

■ DB equals dry-bulb temperature.

■ WB equals wet-bulb temperature.

Typical effectiveness levels are 85 to 95%.

Assuming the effectiveness is 85%, the tem-perature drop can be calculated by:

Temperature drop = 0.85 (T1DB – T2WB)

As an example, assume that the ambient tem-perature is 100°F (37.8°C) and the relativehumidity is 32%. Referring to Figure 4, which isa simplified psychrometric chart, the corre-



sponding wet-bulb temperature is 75°F(23.9°C). The air temperature drop throughthe cooler is then 0.85 (100–75), or 21°F(11.7°C) (equals a compressor inlet tempera-ture of 79°F [26°C]). The cooling process fol-lows a line of constant enthalpy as sensible heatis traded for latent heat by evaporation.

The effectiveness of evaporative coolers is typi-cally 85% and of foggers somewhat higher at 90to 95%.

The exact increase in power available from aparticular gas turbine as a result of air coolingdepends upon the machine model and site alti-tude, as well as on the ambient temperature and

humidity. However, the information shown inFigure 5 can be used to make an estimate of thisbenefit for evaporative coolers. As would beanticipated, the improvement is greatest in hot,dry weather.

Wetted-Honeycomb—Evaporative Coolers Conventional media types of evaporative cool-ers use a wetted honeycomb-like medium tomaximize evaporative surface area and coolingpotential. For gas turbines, the medium is typi-cally 12 or more inches thick and covers theentire cross-section of the inlet air duct or filterhouse. The media and drift eliminator result ina pressure drop in the inlet air duct. Typical val-ues are approximately one inch of water col-umn. This increase in inlet pressure dropdecreases the plant output and efficiency for allambient temperatures and loads even when thesystem is off. The result is a 0.35% reduction ingas turbine baseload output and a 0.3% reduc-tion in combined-cycle output. The combined-cycle output effect is less because the reducedgas turbine airflow is somewhat counteracted bya small increase in gas turbine exhaust temper-ature. Heat rate increases are modest at 0.12%and 0.04% for gas turbine and combined cycle,respectively. Retrofit installation often requiressubstantial ducting modifications. The effec-tiveness of the system is fixed by the mediaselection and condition so the inlet air temper-ature can not be controlled—the system iseither on or off. This is not typically an issuebecause the operator desires the maximum pos-sible increase in plant output. A typical self-cleaning filter/evaporative cooler design isshown in Figure 6. Water is pumped from a tankat the bottom of the module to a header, whichdistributes it over the media blocks. These aremade of corrugated layers of fibrous materialwith internal channels formed between layers.There are two alternating sets of channels, one



120

Dry Bulb Temperature - ºF

20

25

30

35

40Cooling Process

15.005

.020

Pounds Moisture Per Pound of Dry Air

Btu Per Poundof Dry Air

.000

.015

40 60 80 100

10% RH

WaterEvaporated

20% RH40% RH

60% RH

100% RH

DegreesCooled

Figure 4. Psychrometric chart, simplified

Temperature - ºF

15

12

9

6

3

060 70 80 90 100 110 120

Increase in Output - %10% RH

20%

30%

40%

50%

60%

Figure 5. Effect of evaporative cooler on availableoutput – 85% effective

for water and one for air. This separation offlows is the key to reducing carryover. Drifteliminators are installed downstream of themedia to protect against the possibility of watercarryover. The water flows down by way of grav-ity through the water channels and diffusesthroughout the media through wicking action.Any excess returns to the tank. The level ofwater in the tank is maintained by a float valve,which admits makeup water.

A controller is provided that regulates the oper-ation to a minimum ambient dry-bulb tempera-ture. The minimum temperature must be 60°F(15.6°C) or higher. If evaporation were permit-ted at too low a temperature, this could causeicing. When there is a possibility that the dry-bulb temperature will fall below freezing, thewhole system must be deactivated and drainedto avoid damage to the tank and piping and thepossibility that the porous media would plugwith ice.

Water Requirements for EvaporativeCoolers Evaporative coolers are most efficient in aridregions where the water may have a significant

percentage of dissolved solids. If makeup wateris added in sufficient quantity to replace onlythe water that has been evaporated, the water inthe tank (which is also the water pumped to themedia for evaporation) will gradually becomeladen with more minerals. In time, these min-erals would precipitate out on the media andreduce evaporation efficiency. This wouldincrease the hazard of some minerals becomingentrained in the air and entering the gas tur-bine. In order to minimize this hazard, watertypically is bled continuously from the tank tokeep the mineral content diluted. This istermed blowdown.

The amount of makeup water, which must beprovided, is the sum of evaporation and blow-down. The rate at which water evaporates froma cooler depends upon the ambient tempera-ture and humidity, the altitude, cooler effective-ness and the airflow requirement of the gas tur-bine. Figure 7 shows the evaporative waterrequirement of an 85% effective MS6001(B)gas turbine cooler at sea level. The correspon-ding value for an MS7001 or MS9001 machinecan be estimated by respectively doubling ortripling the quantity shown.

One of the main concerns in determining theacceptability of water quality is its propensity to



DistributionManifold

DistributionPad Water Discharge

Holes Spray WaterUp Into Deflector

Bracket

FacingPlateAir

Flow

DriftElimination

Media

OutletInlet

Upward Airflow.Water Carryover From MediaIs Removed and Drains Into Sump.

Sump

Figure 6. Media pack cooler design

Evaporation - GPM

Temperature - ºF

20

15

10

5

050 60 70 80 90 100 120

10% RH

20%

30%

40%

50%

60%

110

Figure 7. Evaporation rate for MS6001(B) – 85%effective

deposit scale. Scaling is influenced by the inter-action of the water’s total hardness, total alka-linity (ALK), total dissolved solids (TDS), pHand water temperature. To assist in determiningwhether the water is suitable for use in evapora-tive coolers, a saturation index (SI) is typicallyused.

A standard laboratory analysis of the water candetermine the total hardness (ppm as CaCO3),total alkalinity (ppm as CaCO3), total dissolvedsolids (ppm) and pH. The levels of the firstthree components are first modified by anadjustment factor W:

W = (1/B +1)(1/F + 1),

where

F = flood factor = (water drain rate from mediato tank)/(water evaporation rate)

and

B = blowdown factor = (water bleed rate fromtank)/(water evaporation rate).

Water evaporation rate can be estimated byusing the information in Figure 7.

In most cases, F and B are adjusted duringinstallation to be approximately uniform on atypical hot day so that W equals 4. However, tomake low-quality water more suitable, anincreased blowdown rate may be used to lowerthe adjustment factor. Flood factor should notbe adjusted to compensate for water qualitybecause this could result in liquid water carry-over.

The ppm of TDS, ALK and hardness are mul-tiplied by the adjustment factor to obtain ppm(adjusted). To evaluate the suitability of waterfor evaporative coolers, a modified Langlier sat-uration index chart is used (see Figure 8). Theadjusted total alkalinity (ppm as CaCO3) is con-verted to PALK, and the adjusted total hardness(ppm as CaCO3) is converted to PCA by enter-

ing the chart on the right-hand ordinate andreading the appropriate quantity from theright-hand abscissa. The adjusted total dissolvedsolids are converted to PTDS by entering theleft ordinate, selecting the appropriate watertemperature (which may be taken to be the wet-bulb temperature) and reading the upper-leftabscissa.

Saturation index (SI) = pH - PCA – PALK-PTDS

SI < 1.0 indicates no water treatment isrequired.

Water treatment may be used to control anyproperty or combination of properties toreduce SI to 1.0 or less. Initially, the blowdownrate is adjusted to be approximately the same asthe evaporation rate on a typical hot day; thismay later be adjusted based on operationalexperience and local water quality.

Even though care may be taken with water qual-ity, the media eventually will have to be replacedas material precipitates out in sufficient quanti-ty to impair its effectiveness. However, experi-ence indicates that this may take quite a longtime. At one site there has been operation forsix seasons under adverse conditions withinsignificant performance degradation. It isexpected that the media will continue to beused for at least two more years. While this is

Steam Turbines for Industrial Applications


pTDS Scale

pCs & pALK Scale

10,000

45 40 35 30 25 15 10

5,000

3,000

1,000

500

300

100

5030

1020

10,000

5,000

3,000

1,000

500

300

100

5030

10

PPM(Adjusted)

PPM(Adjusted)

27 26 25 24 23 22 21 20 19 18

pCa

pALK

70º 80º 90º50º 60º

Figure 8. Langelier saturation index chart

believed typical, the estimate may change asmore experience is gained.

Tests indicate that the feedwater may have highlevels of sodium and potassium without signifi-cant carryover of these metals into the gas tur-bine. However, very careful attention to detail isnecessary in order to realize this level of per-formance. This includes proper orientation ofthe media packs, correct flows of air and water,uniform distribution of water over the mediasurface and proper drainage back to the tank.Any deficiencies in these areas may make it pos-sible for water to become entrained in the air,with potentially serious results. Consequently,installation and maintenance of evaporativecooling equipment is very important. In areaswhere the water exceeds 133 ppm sodium andpotassium, it is good practice to periodicallycheck the rate at which these elements enterthe gas turbine by means of a mass balance cal-culation. Any discrepancies between the rate atwhich sodium and potassium enter in the feed-water and the rate at which they leave in theblowdown can be attributed to carryover.Concentration of these elements in the inlet airshould typically be held to 0.005 ppm or less.For example, this is equivalent to an ingestionrate of 0.01 lb/h for an MS7001 gas turbine.

When media types of coolers were first placed inservice, some units exhibited unacceptable car-ryover. It was found that this problem had threepossible causes: damaged or improperlyinstalled media, entrainment of water from thedistribution manifold or local areas of excessive-ly high velocity through the media. The firstcause was removed by new procedures for ship-ping and installing the media blocks. Carryoverfrom the manifold was eliminated by installingblanking plates downstream of the spray ele-ments. The third problem, high-flow velocitythrough portions of the media, was the most dif-ficult to solve. After considerable effort, two

solutions were developed. The first incorporat-ed features in the design to force more uniformflow so that velocities everywhere were withinthe acceptable range. The second solutioninvolved a new design that accepted some carry-over from the media but that eliminated carry-over into the gas turbine by use of eliminatorblades, similar to the vanes of a moisture separa-tor, immediately downstream of the evaporativemedia. Both approaches have proven successfulin the field and both approaches are now takentogether to ensure no water carryover.

Foggers Foggers were first applied to gas turbine inletair cooling in the mid-1980s. Nearly 100 fog sys-tems are installed on turbines in NorthAmerica, from aeroderivatives to large-framemachines. Fog systems create a large evapora-tive surface area by atomizing the supply ofwater into billions of super-small sphericaldroplets. Droplet diameter plays an importantrole with respect to the surface area of waterexposed to the airstream and, therefore, to thespeed of evaporation. For instance, water atom-ized into 10-micron droplets yields 10 timesmore surface area than the same volume atom-ized into 100-micron droplets.

For evaporative cooling or humidification withatomized water, it is important to make a truefog, not a mist. To a meteorologist, waterdroplets of less than 40 microns in diametermake up a fog. When droplet sizes are largerthan this, they are called a mist. True fogs tendto remain airborne due to Brownian move-ment—the random collision of air moleculesthat slows the descent of the droplets—whilemists tend to descend relatively quickly. In stillair, for example, a 10-micron droplet falls at arate of about one meter in five minutes, while a100-micron droplet falls at the rate of about onemeter in three seconds.



Fogger nozzles (Figure 9) should be installeddownstream of the inlet air filters. The determi-nation of whether or not the nozzles should beinstalled upstream or downstream of thesilencers depends upon the time available forthe water to fully evaporate before the moist airencounters the next fixed object in the system(silencers, trash screen or inlet bellmouth).Retrofit installation times of one to two outagedays have been quoted by manufacturers forsome high-pressure water systems and requireonly minor modifications to the turbine inletstructures. Some water will condense or coa-lesce out as it travels down the inlet duct. Toprevent this water from collecting in the inletduct, a drain line needs to be installed down-stream of the fog nozzles.

When considering a particular fog systemdesign, give special attention to the fog nozzlesand nozzle manifolds to avoid the possibility ofsmall parts breaking off and becoming ingestedby the turbine. Vibration caused by airflowacross the manifolds should be considered, aswell. If the manifolds are not properly designedor if they are improperly supported, vibrationcould eventually lead to structural failure of themanifolds or mounting brackets.

To minimize the potential of compressor foul-ing or nozzle plugging, demineralized water isused in high-pressure fog installations. Thewater requirements are the same as those for

gas turbine water-injection systems. Reports offouling or plugging came only from plantswhere demineralized water was not in use orwhere the water supply systems were improper-ly maintained. Demineralized water makes itnecessary to use high-grade stainless steels forall wetted parts. The usual nozzle manifold con-sists of half-inch-diameter tubes, spaced 8 to 12inches apart. Because such an open latticeworkof small pipes does not impede the flow of air,the fog nozzle pressure drop is negligible.

There are several different methods of wateratomization that can be employed. Some sys-tems use gas turbine compressor air in nozzlesto atomize the water. Other systems pressurizethe water using high-pressure pumps that forcethe water through a small orifice. Air-atomizednozzles require less water pressure but sufferfrom lower generator output because of the airextraction from the gas turbine and inlet heat-ing from the warm compressor air. Typical air-to-water ratios are 0.6 to 1 by mass (500 to 1 byvolume). Some of the high-pressure pumpedsystems force the water to swirl, which causes itto break up into small droplets. Others forcethe water to impact on a pin, causing the sameeffect. For pressurized water systems, dropletsize is inversely proportional to the square rootof the pressure ratio. Doubling the operatingpressure results in a droplet that is about 30%smaller. Typical operating pressures for high-pressure pumped-fog systems range from 1,000to 3,000 psi.

A typical pressurized water fog system consistsof a series of high-pressure pumps, a control sys-tem and an array of tubes containing the fognozzles. The pump skid normally consists of sev-eral high-pressure pumps, each connected to afixed number of fog nozzles. With this arrange-ment, each pump and its associated nozzles rep-resent one discrete stage of fog cooling. The



Compressor

Silencers

Fog Pump

AirFlow

Filters Fog Nozzles

Figure 9. Fogger system

pumps can then be turned on sequentially asthe demand for cooling increases. For example,with four stages, a temperature drop of 20ºF(11.2°C) is managed in 5°F (2.8°C) increments.If a finer increment of temperature reduction isdesired, more stages can be included. It isimportant to distribute the fog nozzles for eachstage evenly over the cross-section of the duct sothat temperature gradients are minimized.Careful control of foggers is required to avoidexcessive water carryover to the compressor.

The capacity of existing plant facilities for dem-ineralizing and storing water needs to be evalu-ated when this system is retrofitted on existingplants to ensure that sufficient water will beavailable to meet the projected demand

Evaporative Media and Inlet FoggingComparison The following list highlights some of the impor-tant advantages and disadvantages of the twomain types if inlet cooling.

Evaporative Media Advantages

■ Water quality requirements are lesssevere than fogger system.

■ Simple and reliable

■ More operating experience

Disadvantages

■ Uprates frequently require substantialduct modifications.

■ Higher gas turbine inlet pressure dropthan fogger system degrades outputand efficiency when not in use

■ Lower cooling effectiveness

Inlet Fogging Advantages

■ Gas turbine inlet pressure drop islower than that of evaporative mediaand provides increased output.

■ Potential for higher effectiveness thanevaporative media

■ Potential for lower uprate costs andfaster installation time due to reducedduct modifications compared toevaporative media

Disadvantages

■ Requires demineralized water.

■ Higher parasitic load than evaporativemedia for high-pressure pumpedsystems

■ Lower power increase for air-atomizedsystems

■ Controls are more complex.

Evaporative IntercoolingEvaporative intercooling, also called oversprayor overcooling, can be accomplished by pur-posefully injecting more fog into the inletairstream than can be evaporated with the givenambient climate conditions. The airstream car-ries unevaporated fog droplets into the com-pressor section. Higher temperatures in thecompressor increase the moisture-holdingcapacity of air, so the fog droplets that did notevaporate in the inlet air duct do so in the com-pressor. When the fog evaporates, it cools, mak-ing the air denser. This increases the total massflow of air through the gas turbine and reducesthe relative work of compression, giving anadditional power boost. Fog intercooling allowsturbine operators to get power boosts that aregreater than would be possible with a conven-tional evaporative cooling system.

The limits of fog intercooling have not beenfully investigated, but the benefits claimed aresubstantial. Theoretically, it is possible to injectenough fog to cause a power boost that is ashigh as that obtained by inlet air chilling belowthe wet-bulb temperature and at a fraction ofthe cost. This remains to be seen. There is one



possible drawback to intercooling: if waterdroplets are too large, there is a potential forliquid-impaction erosion of the compressorblading. Bombardment of a metal surface withwater droplets can lead to the development ofmicrofractures in the metal’s surface and cancause surface pitting.

Intercooling can also be accomplished by fogspraying atomized water between compressorsections in gas turbines, which have high- andlow-pressure compressors. The GE LM6000SPRINT™ system is one example of such a sys-tem. Water is injected through 24 spray nozzleslocated between the high-pressure and low-pres-sure compressors on the two-shaft LM6000(Figure 10). Water is atomized to a droplet diam-eter of less than 20 microns using high-pressureair taken from the eighth-stage bleed. Injectingwater significantly reduces the compressor out-let temperature, and this allows the turbine tooperate at the natural control limit associatedwith firing temperature rather than the com-pressor outlet temperature limitation. Theresult is higher output and better efficiency.Output increases of more than 20% and effi-ciency increases of 3.9% are possible on 90°F(32°C) days

The LM6000, when compared to some framemachines, has a steeper lapse rate—the rate at

which output decreases with increased air tem-perature—so the LM6000 has typically beenapplied with chiller technology. The SPRINT™technology allows the operator to recover mostof the power lost on hot days without incurringthe capital and operating costs of chillers.SPRINT™ retrofit kits are available for existingLM6000 machines. Investigations are under wayto find a way to utilize spray intercooling for theLM6000’s low-pressure compressor section.

Before evaporative intercooling can be applied,the gas turbine component maximum load lim-itations and control algorithms must be careful-ly reviewed to ensure that design limitations arenot exceeded. The same review must be con-ducted for the generator, steam turbine andauxiliary systems.

Inlet Chilling The two basic categories of inlet chilling systemsare direct chillers and thermal storage.Liquefied natural gas (LNG) systems takeadvantage of the fuel supply, utilizing the cool-ing effect associated with the vaporization of liq-uefied gas. Thermal storage systems take advan-tage of off-peak power periods to store thermalenergy in the form of ice to perform inlet chill-ing during periods of peak power demand.Direct chilling systems use mechanical orabsorption chilling. All are candidates for newplants or plant retrofits.

As with evaporative cooling, the actual tempera-ture reduction from a cooling coil is a functionof equipment design and ambient conditions.Unlike evaporative coolers, however, coolingcoils are able to lower the inlet dry-bulb tem-perature below the ambient wet-bulb tempera-ture. The actual temperature reduction is limit-ed only by the capacity of the chilling device,the effectiveness of the coils and the compres-sor’s acceptable temperature/humidity limits.



Blank-off/spacer

Water Manifold

AirManifold

24 ea. SprayNozzles

FeederTubes

8th-StageBleed Air Piping

Water-Metering

ValveAir-atomized spray - Engine-supplied air- Spray droplet diameter less than 20 microns

From Off-engine Pump

Skid

LPC FrontFrame

HPC

Figure 10. Diagram of LM6000PC SPRINT™ system

Figure 11 shows a typical cooling cycle based onan ambient dry-bulb temperature of 100°F(37.8°C) and 20% relative humidity. Initial cool-ing follows a line of constant humidity ratio. Asthe air approaches saturation, moisture beginsto condense out of the air. If the air is cooledfurther, more moisture condenses. Once thetemperature reaches this regime, more andmore of the heat removed from the air is usedto condense the water. This leaves less capacityfor temperature reduction. Because of thepotential for water condensation, drift elimina-tors should be installed downstream of the coilsto prevent excessive water ingestion by the gasturbine. The exact point at which further cool-ing is no longer feasible depends upon thedesired gas turbine output and the chilling sys-tem’s capacity.

It is readily apparent from the graph in Figure 11that the air can be cooled below the ambientwet-bulb temperature. Therein lies one of themajor benefits of the cooling coil system. Itmust be pointed out, though, that the lowerlimit of cooler operation is a compressor inlettemperature of 45°F (7.2°C) with a relativehumidity of 95%. At temperatures below 45°F(7.2°C) with such high relative humidity, icingof the compressor and the resulting risk ofequipment damage is probable.

Inlet Chilling Methods

Direct Cooling

Direct cooling provides almost instantaneouscooling for capacity enhancement around theclock. Some of the increase in power output isused to drive the system. Direct cooling systemsoperate on the same principles, which havecooled industrial processes as well as HVAC sys-tems in large buildings for many years. Largemechanical chillers powered by electricity maybe used with heat exchangers (chiller coils) inthe gas turbine inlet. These heat exchangersadd approximately one inch of water to theinlet pressure drop. Absorption chillers usingheat as the energy source are an option if wasteheat is available. These typically cost more thanmechanical chillers of like capacity but carrylower parasitic loads while operating. The gasturbine inlet air temperature can be reduced aslow as 45 to 50°F (7.2 to 10°C), depending onthe ambient air dew point, waste heat availableand chiller size. Mechanical chillers consume asignificant amount of power, so the net gainsare less than the absorption system.

The chiller refrigerant requires cooling. Water-cooled chillers require a cooling tower.Mechanical chillers can also be air cooled; how-ever, absorption chillers are available only aswater-cooled models.

There are several ways to accomplish directcooling. These can be divided into two basictypes: direct-expansion and chilled-water sys-tems. Direct-expansion systems utilize a refrig-erant directly in the cooling coil mounted inthe inlet air duct. Chilled-water systems utilize asecondary heating fluid between the refrigerantand the turbine inlet air. This fluid is typicallywater or a water-glycol mixture.

For example, cooling the inlet air on a GE 7FAunit from 95ºF (35°C) dry-bulb, 77°F (25°C)



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 11. Inlet cooling process

wet-bulb to 45ºF (7.2°C) requires approximate-ly 7.4 T/hr of cooling, providing net increase of24.1-megawatt gas turbine electrical output at aprice of about $240 per kilowatt. However, itmust be considered that this system providesthe full performance benefit only on hotterdays and the benefit is reduced as ambient tem-perature decreases. Also, the system reducespower output capacity on cold days below 45°F(7.2°C) due to the increase in gas turbine inletpressure drop.

Off-Peak Thermal Energy Storage Where premium prices are paid for power dur-ing daytime peak power consumption periods,off-peak thermal energy storage may be theanswer. Ice or cold water is produced usingmechanical chillers during off-peak hours andweekends and stored in large storage tanks.Capacity enhancement is possible only for a fewhours each day. During periods of peak powerdemand, the cold water or cold water producedfrom melted ice is used to chill the gas turbineinlet air. This system is capable of reducing gasturbine inlet air temperature to temperatures ofbetween 50 and 60°F. However, significant spaceis required for the ice or cold water storage.

Comparison of Direct Chilling andThermal Energy Storage Direct Chilling

Advantages

■ Provides chilled air 24 hours a day

■ Simple and reliable

■ No off-peak parasitic power required

■ Very efficient

Disadvantages

■ Requires higher on-peak parasiticpower

■ Increased capital cost becauserefrigeration equipment is sized forpeak load

Thermal Energy Storage

Advantages

■ Low on-peak parasitic power required

■ Lower capital cost than direct chillingfor peaks lasting less than eight hours

Disadvantages

■ Requires more off-peak power

■ Higher capital cost than direct chillingfor peaks lasting more than 8 hours

■ More complex system than directchilling

■ Chilled air available for only part ofthe day.

LNG/LPG Gas Vaporizers Where LNG or liquefied petroleum gases(LPG) are used, these fuels need to be vapor-ized before use in the gas turbine. They are typ-ically delivered to the gas turbine fuel system attemperatures around 50°F (10°C). Gas turbineinlet air can be used to accomplish much of thefuel vaporization and heating. An intermediatefluid such as glycol is used. The gas turbine inletair heats the glycol and is cooled in this process.The glycol heats the fuel. A 10°F (5.6°C) reduc-tion in inlet air temperature is typical for thissystem. Because the fuel needs to be vaporizedanyway, chilling the inlet air provides a way ofturning a large portion of the energy into use-able power.

Power AugmentationThree basic methods are available for poweraugmentation: water or steam injection, HRSGsupplementary firing and peak firing.

Gas Turbine Steam/Water Injection Injecting 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 amount



required to meet the NOx requirement in or-der to minimize operating cost and impact oninspection intervals. Steam injection for poweraugmentation has been an available option 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. In combined-cycleoperation, the cycle heat rate increases withsteam or water injection. In the case of waterinjection, this is primarily due to the use ofhigh-grade fuel energy to vaporize and heat thewater. In the case of steam injection, this is pri-marily due to the use of bottoming cycle energyto generate the steam for the gas turbine thatcould otherwise be used in the steam turbine. Asecondary factor is that typical control systemsreduce firing temperature when injecting steamor water. This counteracts the effect of higherheat transfer due to the extra water vapor onthe gas side to maintain hot gas path part life.

GE gas turbines are designed to allow typicallyup to 5% of the compressor airflow for steaminjection to the combustor and compressor dis-charge. The amount of steam injection is afunction of gas turbine and gas turbine com-bustion system. Steam must contain at least50°F (28°C) superheat and be at pressures com-parable to fuel gas pressures. When eithersteam or water is used for power augmentation,the control system is normally designed to al-low only the amount needed for NOx abate-ment until the machine reaches base (full)load. At that point, additional steam or watercan be admitted through the governor control.

Supplementary Fired HRSG Because gas turbines generally consume a smallfraction of the available oxygen within the gasturbine air flow, the oxygen content of the gasturbine exhaust generally permits supplemen-tary fuel firing ahead of (or within) the HRSG

to increase steam production rates relative to anunfired unit. A supplementary fired unit isdefined as an HRSG fired to an average tem-perature not exceeding about 1800°F (982°C).

Because the turbine exhaust gas is essentiallypreheated combustion air, the supplementaryfired HRSG fuel consumption is less than thatrequired for a power boiler, providing the sameincremental increase in steam generation.Incremental plant heat rate for supplementaryfiring is typically in the range of a simple-cyclegas turbine.

An unfired HRSG with higher steam conditionsis often designed with multiple pressure levelsto recover as much energy as possible from thegas turbine exhaust. This adds cost to theunfired HRSG, but the economics are oftenenhanced for the cycle. In the case of the sup-plementary fired HRSG, if the HRSG is to befired during most of its operating hours to the1400-to-1800°F (760–982°C) range, then a suit-ably low stack temperature can usually beachieved with a single-pressure-level unit. This isthe result of increased economizer duty as com-pared to the unfired HRSG.

A supplementary fired HRSG has a design quitesimilar to that of an un-fired HRSG. However,the firing capability provides the ability to con-trol the HRSG steam production within thecapability of the burner system and independ-ent of the normal gas turbine operating mode.Supplementary fired HRSGs are applicable tonew units or combined-cycle add-ons. Retrofitinstallations on existing HRSGs are not practi-cal due to the need for duct burner space andsignificant material changes.

There is a small performance penalty whenoperating unfired compared to operating a unitdesigned without supplementary firing, and themagnitude of this performance penalty isdirectly proportional to the amount of supple-



mentary firing built into the combined-cycleplant. The performance penalty is due to twofactors: unfired operation results in lower steamflows and pressures and, thus, lower steam tur-bine efficiency; also, the pumps, auxiliaryequipment and generator are sized for higherloads. Operating unfired results in compara-tively higher parasitic loads compared to a unitdesigned solely for unfired operation.

Peak Firing Users of some gas turbine models have the abil-ity to increase their firing temperature abovethe base rating. This is known as peak firing,where both simple-cycle and combined-cycleoutput will increase. The penalty for this type ofoperation is shorter inspection cycles andincreased maintenance. Despite this, runningat elevated peak firing temperatures for shortperiods may be a cost-effective way to add kilo-watts without the need for additional peripher-al equipment.

Output Enhancement SummarySeveral output enhancement techniques andsystems have been discussed. A comparison ofthe potential performance impacts for eachtechnique based on a 90°F (32.2°C), 30% RHday are shown in Table 1.

Before any of these enhancements are appliedto an existing plant, the steam turbine, balance

of plant and generator capability need to bereviewed to ensure operating limits will not beexceeded. For example, generator output maybe limited on hot days due to reduced coolingcapability.

Efficiency Enhancement

Fuel HeatingIf low-grade heat energy is available, this can beused to increase the temperature of gaseousfuels, which increases cycle efficiency by reduc-ing the amount of fuel energy used to raise thefuel temperature to the combustion tempera-ture. There is a very small (almost negligible)reduction in gas turbine output compared tothe no-fuel heating case, primarily due to thelower gas turbine mass flow as a result of thereduction in fuel consumption. The reductionin combined-cycle output is typically greaterthan simple-cycle output primarily becauseenergy that would otherwise be used to makesteam is often used to heat the fuel. Actual com-bined-cycle output and efficiency changes aredependent on fuel temperature rise and cycledesign. Provided the fuel constituents areacceptable, fuel temperatures can potentially beincreased up to approximately 700°F (370°C)before carbon deposits begin to form on heattransfer surfaces and the remainder of the fueldelivery system. For combined-cycle applica-tions, fuel temperatures on the order of 300 to450°F (150–230°C) are generally economicallyoptimal.

A combined-cycle plant has plenty of low-gradeheat energy available. Typical F-class three-pres-sure reheat systems use water from the interme-diate pressure economizer to heat the fuel toapproximately 365°F (185°C). Under these con-ditions, efficiency gains of approximately 0.3points can be expected for units with no stacktemperature limitations.



Power Enhancement Option

Base Configuration

Evaporative Cooling GT InletAir (85% Effective Cooler)

Chill GT Inlet Air to 45ºF

GT Peak Load

GT Steam Injection (5% of GTAir Flow)

GT Water Injection

HRSG Supplementary Firing

DD Output

Base

+5.2%

+10.7%

+5.2%

+3.4%

+5.9%

+28%

DDHeat Rate

Base

-

+1.6%

+1/0%

+4.2%

+4.8%

+9.0%

Power Performance Impact

Table 1. STAG system power-enhancement options

It is important to ensure that the fuel does notenter the steam system because maximumsteam system temperatures are typically abovethe auto ignition temperature for gas fuels. Thiscan be accomplished in several ways. For a sys-tem utilizing a direct water-to-fuel heatexchanger, the water pressure is maintainedabove the fuel pressure so that any leakage takesplace in the fuel system. Additional systemdesign and operation requirements ensure thatthe fuel does not enter the steam system duringperiods when the water system is not pressur-ized. Figures 12 and 13 show the details of such a

system. Other systems use an intermediate heattransfer fluid so that any fuel heat exchangerleakage cannot directly enter the steam system.

For uprate opportunities, it must be consideredthat additional water flow may be required.Calculations must be performed to ensure theexisting pump capabilities are not exceededand that pressures are sufficient to deliver waterto the HRSG drums under worst-case condi-tions. Other components that may seeincreased water flows (such as HRSG economiz-ers) must be evaluated to ensure the design isacceptable.

Performance-Enhancement Case StudyThe economic analysis of performance-enhancement alternatives is highly dependentupon plant configuration, capacity factor,expected electricity price duration curves andfuel cost. As such, each plant needs to be evalu-ated on a case-by-case basis. As an example, aneconomic evaluation for a typical GE STAG207FA three-pressure reheat plant is presented.The economic evaluation presented hereassumes that power-enhancement options areused only during annual summer peak powerdemand periods and that for the remainder ofthe year the plant is operated at baseload (atannual average ambient conditions). In otherwords, there are two levels of plant perform-ance considered when evaluating the net eco-nomic benefit of any given plant power-enhancement arrangement. These are baseloadplant performance at (baseload) annual aver-age ambient conditions and peak-load per-formance at (peak-load) maximum ambientconditions.

Utilization of power-enhancement alternativesat ambient conditions other than peak-loadambient conditions may add to the economicevaluation benefit of that alternative. For exam-



kW

ToCOND

kW

Steam

FuelGas

HRSG

COND

GT

ST

ExhaustGas

StackGas

C.W.

FUELHX

Air

Figure 12. Fuel heating functional block diagram

IP FEEDWATER SYSTEM

LSH4223

LSH4222

LSHH4222A

LSHH4222B

LSHH4222C

Standard Gas Fuel Heating System

GAS FUEL HEATER

PI4210

TI4210

UNIT TRIP

COLLECTING TANK

FV-4211

FV4212

FV

FV

CONDENSER HOTWELL

SLOPE FEEDWATERVENT TANK

LTLIC

H HH

HS

SLOPE

GAS FUEL

SCRUBBER

LSH4224

STAINLESSSTEEL

FV4224

GAS FUEL MODULE

GAS CONTROL VALVES

SLOPE

FV4222

FV4223

TCV4233

PT4213

PI

4213DPI

4213ZIC

4233

TIC

4233

H HH

I

TE4214

TIC

4214

TY

4214

HS

4224

GAS SUPPLY

PT4200

TE4200A/B

TI

4200

PI

4200

TI4214

HS

HS

HS

4211

HS

4212

I

LAH

4224

LAH

4223

HS

4223

LAH

4222

HS

4222

LCV

VENT TO

SAFE AREA

VENT TOSAFE AREA

PDT-4240B

PDT4240A

PT4240

TE4240A/B

TI

4240

HEATER INLETGAS FUELSCRUBBER

(MAY BE IN GAS

SUPPLIER'S SCOPE)

Figure 13. Standard gas fuel heating system

ple, it is common practice to design gas turbineinlet chilling systems so that it is possible tomaintain a constant gas turbine compressorinlet air temperature across the ambient tem-perature range (to a minimum temperature ofapproximately 45°F). By operating a chiller inthis fashion, combined-cycle output would beimproved even at annual average ambient orbaseload ambient conditions. Provided thedemand for electricity exists, this may afford anadditional economic evaluation benefit (thisconsideration has not been evaluated in thecase study presented).

Assumptions/Base Plant Description

Assumptions Fixed

Annual average ambient conditions:59°F, 60% RH, 14.7

Peak period ambient conditions:95°F, 45% RH, 14.7 psia

Fuel—natural gas (LHV): 21,515 Btu/lbm

Evaluation term: 20 years

Escalation rate: 3% per year

Discount rate: 10%

Fixed-charged rate: 16%

Annual capacity factor: 85% (7446 hrs/year)

Variable

Fuel cost: $1.50–$3.50 /MMBtu

Peak energy rate: 4.5–18 ¢/kWh

Peak energy period: 100–3000 hrs/year

Base Plant Configuration The baseline plant configuration, to which allpeak power-enhancement alternatives are com-pared, is a GE STAG 207FA combined-cycleplant. This plant consists of two PG7241(FA)gas turbines with a nine-ppmvd (15% O2) gas-only DLN combustion system; two unfired,three pressure-level HRSGs with 15°F to 10°F

pinch and subcooling for all pressure levels;and a GE-type D11 reheat steam turbine withrated throttle conditions of 1800 psia/1050°F/1050°F and a rated exhaust pressure of1.5 in Hga. The cooling system is a combinationof a wet cooling tower and condenser. The base-line plant configuration does not include anypower enhancement equipment.

Estimated Baseline Plant Performance:

@ annual average ambient (59°F)

Net plant output (kW): 514,550

Net plant heat rate (Btu/kWh): 6197

@ peak period ambient (95°F)

Net plant output (kW): 456,320

Net plant heat rate (Btu/kWh): 6323

For the purpose of this study, the capital costassociated with the baseline plant configurationon a turnkey basis was estimated to be $420 perkilowatt (referenced to the annual average per-formance level). The annual operation andmaintenance (O&M) cost associated with thebase configuration was estimated to be $14.45million on a first-year annual basis.

Description of MethodsStarting with the baseline plant configurationdefined above, a variety of power-enhancementalternatives and combinations of alternativeswere added to the base configuration. Exhibit 1contains a complete listing of the power-enhancement alternatives considered in thisstudy. It is necessary to note that the HRSG,condenser and cooling tower designs were opti-mized for the base-line plant configuration andthat this same hardware was used in conjunc-tion with each of the power-enhancement alter-natives to calculate the (off-design) perform-ance associated with each of the alternatives.Further, it has been assumed that there are no



limitations with respect to the availability ofwater and that the only penalty associated withadditional water consumption beyond thatrequired for the base case is the incrementalcapital cost associated with the water treatmentsystems.

For each of the enhancement alternatives con-sidered, plant performance (output and heatrate) was developed at both the annual averageambient conditions without the performanceenhancement operating and at the peak powerperiod ambient conditions with the enhance-ment in operation. Incremental plant capitalcost and incremental O&M costs were estab-lished and fed into a COE model along with theperformance at the annual average ambientconditions and the peak period ambient condi-tions.

The COE model (including all performanceenhancement alternatives) was run across a

range of fuel costs, peak power energy rates andpeak versus non-peak annual operating hours.The results from this parametric COE analysisare summarized in Exhibits 1a and 1b. Exhibit 1asummarizes the key economic evaluationparameters associated with individual perform-ance-enhancement technology (excluding com-binations of technologies), while Exhibit 1b pro-vides a 20-year NPV economic ranking of all theenhancement alternatives and combination ofalternatives as a function of peak energy rate,peak period duration and fuel cost.

All enhancement alternatives were evaluatedrelative to the base case. Positive numbers forvalue vs. base in this table represent a net (lifecycle, NPV evaluation) benefit, while negativevalues represent a deficit relative to the base.

The optimal power-enhancement alternativeshould be a low-risk alternative with highestpeak power revenue-generating capacity (low



Exhibit 1. List of Performance Enhancements

Case No. Description: Peak Power Enhancement MethodCase 1 GT Peak Firing (35°F)Case 2 GT Steam Injection (3.5% of Compressor Inlet Air flow, CIA)Case 3 GT Steam Injection (5.0% of Compressor Inlet Air flow, CIA)Case 4 GT Peak Firing (35°F) + Steam Injection to 3.5% CIACase 5 GT Peak Firing (35°F) + Steam Injection to 5.0% CIACase 6 GT Evaporative Cooling (Ambient Relative Humidity-45%)Case 7 GT Evaporative Cooling (Ambient Relative Humidity-60%)-SensitivityCase 8 GT Inlet Fogging (Ambient Relative Humidity-45%)Case 9 GT Inlet Fogging (Ambient Relative Humidity-60%)SensitivityCase 10 GT Inlet Chilling to 45°F (Ambient RH-45%), Chiller with External Heat Sink.Case 11 GT Inlet Chilling to 45°F (Ambient RH-45%), Chiller with Cooling Tower SinkCase 12 GT Inlet Chilling to 45°F (Ambient RH-60%), Chiller with External Heat Sink.Case 13 GT Inlet Chilling to 45°F (Ambient RH-60%), Chiller with Cooling Tower SinkCase 14 HRSG Duct Firing-Steam turbine sliding pressure mode of operation. Fired to approximately

45% increase in HP steam production.Case 15 HRSG Duct Firing-Steam turbine fixed-pressure mode of operation with HP throttle bypass

to cold reheat. Fired to output achieved in Case 14.Case 16 HRSG Incremental Duct Firing-Firing from nominal throttle pressure to max HP inlet throttle

pressure limit.Case 17 GT Steam Injection (5.0% CIA) + Incremental HRSG Duct FiringCase 18 GT Steam Injection (3.5% CIA) + Incremental HRSG Duct FiringCase 19 GT Peak Firing + Steam Injection (5.0% CIA) + Incremental HRSG Duct FiringCase 20 GT Steam Injection (3.5% CIA) + Evaporative Cooling (Amb. RH-45%)Case 21 GT Steam Injection (3.5% CIA) + Evaporative Cooling (Amb. RH-45%) + Incremental HRSG

Duct Firing.Case 22 GT Inlet Chilling + GT Steam Injection (3.5% CIA)Case 23 GT Inlet Chilling + GT Steam Injection (3.5% CIA) + Incremental HRSG FiringCase 24 GT Inlet Chilling + GT Steam Injection (5.0% CIA)Case 25 GT Inlet Fogging + GT Steam Injection (3.5% CIA)Case 26 GT Water InjectionCase 27 GT Water Injection + Incremental HRSG Duct FiringCase 28 GT Inlet Fogging-to saturationCase 29 GT Steam Injection (3.5% CIA) with steam supply taken from the HP superheat discharge.

(Note: All other steam injection cases assume steam taken from IP superheater with the balance made up from the HP superheater.)

Case 30 Addition of a PG7121(EA) Peaking Gas Turbine Generator Set

Notes1. Steam injection beyond 3.5% of the gas turbine compressor air flow is not an available option for the cur-

rent PG7241FA gas turbine with a DLN combustor. 5.0% steam-injection cases are used for theoreticalpurposes only.

2. Water injection is not an available alternative to application with a PG7241FA. The case is presented toexamine theoretical results.

3. GT inlet fogging to saturation is presented for theoretical evaluation purposes only.

Exhibit 1. List of performance enhancements

risk being defined as an alternative that has arelatively low initial capital cost and a minimumdetrimental impact on performance at theannual average ambient operating point).

From the perspective of economic risk it is alsonecessary to consider that the power generationmarket is not stagnant. In other words, asidefrom viewing the economic evaluation benefitfrom the perspective of today’s market, oneshould give a fair amount of consideration tofuture market expectations. In the future onecould expect that as the installed capacity baseof power generation equipment in the domesticmarket increases, there will be a potential forerosion of peak energy rates and peak powercapacity demand, coupled with escalating fuelprices. As peak energy rates approach the baseprice of electricity, it is expected that efficiencyrather than capacity will once again be the pri-mary economic driver in the selection of per-

formance-enhancement equipment options. Insuch a market environment, one might expectthat plants with the highest efficiencies wouldbe more profitable and would be dispatchedbefore high-capacity, lower-efficiency plants.

To further illustrate this point, Figures 14 and 15show potential market trends associated withconsumer electricity rates and fuel prices. (Bothfigures were extracted from the DOE EnergyInformation Administration Web site.)

Figure 14 represents a combined forecast of elec-tricity rates and fuel prices as a function of time.The y-axis of the graph represents the ratio ofprojected fuel prices and electricity rates tothose that existed in 1990. It is also noteworthythat the declining trend in the electricity rate isa direct result of competition among electricitysuppliers as a result of deregulation within thepower generation industry.



Annual Peak Operating Hours: 500

Peak Energy Rate (¢/kWH): 9.00

Fuel Cost ($/MMBTU) - HHV: $2.50

Reference Case Case 1 Case 2 Case 6 Case 8 Case 10 Case 14

Base GT Peak LoadSteam Injection

(3.5% CIA)Evap. Cooling

(45% RH)Inlet Fogging

(45% RH)GT Inlet Chilling

(45% RH)Duct Firing

(Sliding Press.)

Average Base Load Performance(Ambient Conditions : 59°F, 60% RH)

Net Plant Output (kW) 521,939 521,939 521,939 520,371 521,405 520,371 519,022

Net Plant Heat Rate (Btu/kW-hr) 6,110 6,110 6,110 6,109 6,109 6,109 6,144

Average Peak Load Performance(Ambient Conditions : 95°F, 45% RH)



Capital Investment of Enhancement +Associated B.O.P ($MM) -NA- 0.4 4.1 1.4 1.1 11.5 3.7

First-Year COE (¢/kWH) 2.96 2.97 3.00 2.97 2.96 3.01 2.99

20-Year Levelized COE (¢/kWH) 3.63 3.64 3.68 3.64 3.63 3.69 3.66

Potential Risk:NPV Evaluation Relative to Base @ UniformPrice of Electricity ($MM) Base (1.72) (9.83) (1.32) (0.30) (11.24) (6.19)

Potential Net Benefit (Reward - Risk)

Total Levelized Net Benefit From PeakingCapacity Relative to Base ($MM) Base $1.07 ($6.95) $3.63 $5.48 ($0.33) $10.33









(45% RH)Duct Firing

(Sliding Press.)










Potential Risk:NPV Evaluation Relative to Base @ UniformPrice of Electricity ($MM) Base (1.16) (10.14) (0.41) 0.74 (10.08) (4.68)


Total Levelized Net Benefit From PeakingCapacity Relative to Base ($MM) Base $4.39 ($4.41) $9.49 $12.29 $11.70 $28.29









(45% RH)Duct Firing

(Sliding Press.)




Average Peak Load Performance(Ambient Conditions: 95°F, 45% RH)






Potential Risk:NPV Evaluation Relative to Base @ UniformPrice of Electricity ($MM) Base (1.72) (9.83) (1.32) (0.30) (11.24) (6.19)











(45% RH)Duct Firing

(Sliding Press.)









20-Year Levelized COE (¢/ kWH) 3.65 3.65 3.70 3.65 3.64 3.70 3.67

Potential Risk:NPV Evaluation Relative to Base @ UniformPrice of Electricity ($MM) Base (1.16) (10.14) (0.41) 0.74 (10.08) (4.68)



Exhibit 1a. COE summary across multiple economic scenarios



Fuel Cost = $3.50 per MBtu - HHV

500 hrs @ 6.0¢ 1000 hrs @ 6.0¢

Case #Value vs. Base($ MM - NPV) Rank Case #

Value vs. Base($ MM - NPV) Rank

28 $3.14 1 28 $7.53 18 $2.00 2 15 $6.90 2

15 $0.81 3 14 $6.14 36 $0.64 4 8 $5.30 49 $0.63 5 6 $3.48 5

16 $0.60 6 9 $2.38 67 ($0.28) 7 16 $2.21 71 ($0.59) 8 7 $1.53 8

14 ($1.19) 9 19 $1.49 919 ($4.61) 10 1 $1.07 1011 ($5.44) 11 11 $0.15 1129 ($5.82) 12 21 ($1.74) 1218 ($6.48) 13 29 ($1.97) 1326 ($6.56) 14 10 ($2.17) 1417 ($6.62) 15 17 ($2.65) 1525 ($7.08) 16 18 ($3.40) 1621 ($7.13) 17 25 ($3.43) 1710 ($7.26) 18 26 ($4.15) 184 ($7.38) 19 13 ($4.48) 19

20 ($8.44) 20 4 ($5.14) 205 ($8.64) 21 20 ($5.23) 21

13 ($8.97) 22 5 ($6.63) 222 ($9.03) 23 12 ($6.86) 233 ($10.39) 24 2 ($8.56) 24

12 ($10.96) 25 3 ($10.23) 2523 ($16.57) 26 23 ($10.41) 2622 ($17.95) 27 22 ($14.00) 2724 ($20.17) 28 24 ($17.45) 2830 ($28.32) 29 30 ($23.07) 2927 ($34.96) 30 27 ($29.38) 30


500 hrs @ 9.0¢ 1000 hrs @ 9.0¢



15 $8.85 1 15 $22.98 114 $7.02 2 14 $22.55 228 $6.92 3 28 $15.10 38 $4.88 4 19 $15.00 46 $3.10 5 11 $11.55 5

16 $2.42 6 8 $11.05 69 $2.34 7 21 $10.36 7

19 $2.14 8 29 $8.83 87 $1.32 9 17 $8.70 91 $0.79 10 10 $8.67 10

11 $0.26 11 6 $8.40 1129 ($0.42) 12 16 $5.84 1217 ($0.94) 13 9 $5.80 1321 ($1.08) 14 13 $5.69 1410 ($1.84) 15 23 $5.07 1518 ($2.33) 16 25 $5.02 1626 ($2.47) 17 18 $4.89 1725 ($2.86) 18 7 $4.73 1813 ($3.89) 19 26 $4.02 194 ($4.50) 20 1 $3.83 20

20 ($4.64) 21 12 $2.86 215 ($5.42) 22 20 $2.37 22

12 ($6.09) 23 4 $0.62 232 ($7.60) 24 5 ($0.20) 243 ($8.65) 25 22 ($2.83) 25

23 ($8.83) 26 2 ($5.70) 2622 ($12.37) 27 30 ($6.42) 2724 ($14.95) 28 3 ($6.77) 2830 ($20.00) 29 24 ($7.00) 2927 ($29.68) 30 27 ($18.81) 30


500 hrs @ 12.0¢ 1000 hrs @ 12.0¢



15 $16.89 1 15 $39.07 114 $15.22 2 14 $38.96 228 $10.71 3 19 $28.51 319 $8.89 4 11 $22.95 48 $7.75 5 28 $22.68 5

11 $5.95 6 21 $22.45 66 $5.56 7 23 $20.56 7

29 $4.98 8 17 $20.06 821 $4.97 9 29 $19.63 917 $4.74 10 10 $19.51 1016 $4.23 11 8 $16.79 119 $4.05 12 13 $15.85 12

10 $3.57 13 25 $13.48 137 $2.92 14 6 $13.32 141 $2.17 15 18 $13.18 15

18 $1.81 16 12 $12.58 1626 $1.61 17 26 $12.19 1725 $1.37 18 30 $10.22 1813 $1.19 19 20 $9.98 1920 ($0.84) 20 16 $9.47 2023 ($1.08) 21 9 $9.22 2112 ($1.23) 22 22 $8.34 224 ($1.62) 23 7 $7.94 235 ($2.21) 24 1 $6.59 242 ($6.17) 25 4 $6.38 25

22 ($6.79) 26 5 $6.24 263 ($6.92) 27 24 $3.44 27

24 ($9.73) 28 2 ($2.85) 2830 ($11.68) 29 3 ($3.31) 2927 ($24.39) 30 27 ($8.23) 30

Exhibit 1b. COE rankings across multiple economic scenarios


500 hrs @ 6.0¢ 1000 hrs @ 6.0¢


Value vs. Base($MM - NPV) Rank

28 $3.93 1 15 $12.21 115 $3.46 2 14 $11.88 28 $2.61 3 28 $9.14 314 $2.13 4 8 $6.54 46 $1.17 5 19 $5.39 516 $1.13 6 6 $4.56 69 $1.04 7 16 $3.27 77 $0.08 8 9 $3.23 81 ($0.31) 9 11 $3.21 919 ($2.67) 10 7 $2.27 1011 ($3.92) 11 21 $1.81 1129 ($3.98) 12 29 $1.73 1217 ($4.65) 13 1 $1.63 1326 ($5.01) 14 17 $1.29 1418 ($5.09) 15 10 $0.86 1521 ($5.36) 16 18 ($0.62) 1610 ($5.75) 17 25 ($0.91) 1725 ($5.84) 18 26 ($1.06) 184 ($6.44) 19 13 ($1.47) 1920 ($7.27) 20 20 ($2.89) 205 ($7.45) 21 4 ($3.27) 2113 ($7.47) 22 12 ($3.86) 222 ($8.38) 23 5 ($4.26) 2312 ($9.46) 24 23 ($5.45) 243 ($9.48) 25 2 ($7.26) 2523 ($14.10) 26 3 ($8.42) 2622 ($16.03) 27 22 ($10.13) 2724 ($18.09) 28 24 ($13.27) 2830 ($25.29) 29 30 ($16.99) 2927 ($28.74) 30 27 ($21.61) 30


500 hrs @ 9.0¢ 1000 hrs @ 9.0¢


Value vs. Base($MM - NPV) Rank

15 $11.50 1 15 $28.29 114 $10.33 2 14 $28.29 228 $7.72 3 19 $18.89 38 $5.48 4 28 $16.72 419 $4.09 5 11 $14.60 56 $3.63 6 21 $13.91 616 $2.95 7 17 $12.65 79 $2.75 8 29 $12.53 811 $1.78 9 8 $12.29 97 $1.68 10 10 $11.70 1029 $1.42 11 23 $10.04 111 $1.07 12 6 $9.49 1217 $1.03 13 13 $8.70 1321 $0.69 14 18 $7.67 1410 ($0.33) 15 25 $7.54 1526 ($0.93) 16 26 $7.11 1618 ($0.94) 17 16 $6.90 1725 ($1.61) 18 9 $6.65 1813 ($2.39) 19 12 $5.86 1920 ($3.47) 20 7 $5.47 204 ($3.56) 21 20 $4.72 215 ($4.24) 22 1 $4.39 2212 ($4.60) 23 4 $2.49 2323 ($6.35) 24 5 $2.17 242 ($6.95) 25 22 $1.03 253 ($7.75) 26 30 ($0.35) 2622 ($10.44) 27 24 ($2.83) 2724 ($12.87) 28 2 ($4.41) 2830 ($16.97) 29 3 ($4.96) 2927 ($23.45) 30 27 ($11.04) 30


500 hrs @ 12.0¢ 1000 hrs @ 12.0¢



15 $19.54 1 14 $44.69 114 $18.54 2 15 $44.37 228 $11.50 3 19 $32.40 319 $10.84 4 21 $26.00 48 $8.35 5 11 $26.00 511 $7.47 6 23 $25.52 629 $6.82 7 28 $24.29 721 $6.74 8 17 $24.00 817 $6.71 9 29 $23.33 96 $6.10 10 10 $22.54 1010 $5.08 11 13 $18.86 1116 $4.76 12 8 $18.03 129 $4.46 13 30 $16.30 137 $3.28 14 25 $15.99 1418 $3.20 15 18 $15.96 1526 $3.15 16 12 $15.58 1613 $2.69 17 26 $15.28 1725 $2.61 18 6 $14.41 181 $2.45 19 20 $12.32 1923 $1.39 20 22 $12.20 2020 $0.33 21 16 $10.53 2112 $0.26 22 9 $10.07 224 ($0.68) 23 7 $8.67 235 ($1.02) 24 5 $8.61 2422 ($4.86) 25 4 $8.25 252 ($5.53) 26 24 $7.61 263 ($6.01) 27 1 $7.15 2724 ($7.65) 28 27 ($0.47) 2830 ($8.65) 29 3 ($1.50) 2927 ($18.17) 30 2 ($1.55) 30

Figure 15 represents a projection of fuel pricetrends for a wide variety of fuels. The valuesdepicted as the y-axis on the graph representsfuel price in $/1000 ft3.

DiscussionGiven the number of alternatives investigated, itis impractical to describe and discuss the resultsof the parametric COE study for each alterna-tive in any significant detail. As such, this dis-cussion is limited to general categories of peakpower alternatives that were evaluated bestunder almost all the economic scenarios exam-ined. These alternatives have been divided into

general categories of HRSG duct firing, gas tur-bine inlet air fogging, gas turbine inlet air chill-ing and gas turbine evaporative cooling.

HRSG Duct FiringTwo methods of HRSG duct firing were exam-ined for the purpose of this study. The first isGE’s traditional method, which is based uponsliding-pressure operation of the steam turbine.This configuration is designed such that thethrottle pressure in an unfired mode of opera-tion at the annual average ambient conditions issignificantly less than the throttle pressure ofthe base case at the same ambient conditions.The throttle pressure in the unfired mode ofoperation was intentionally lowered by increas-ing the HP bowl inlet area such that the steamturbine could accommodate the additionalsteam flow produced when the HRSG is firedwithout exceeding a maximum throttle pres-sure limit of approximately 1900 psia. The levelof firing considered in this study is such that thefired HP steam production is roughly equiva-lent to 1.45 times the HP steam production ofthe base plant at the annual average ambientconditions. While this method of HRSG ductfiring allows for a significant gain (approxi-mately 15% net plant output or approximately41% in gross steam turbine-generator output)in peak period power production over the baseconfiguration, there is a small reduction inpower and an associated increase in heat raterelative to the base case in an unfired mode ofoperation. This reduction was found to beroughly 3 megawatts in net plant output.

The second method of duct firing is a fixed-pressure mode of operation. The rated throttlepressure for this case is equal to that of the basecase at the annual average ambient conditions.In this case the maximum throttle pressure islimited to approximately 1900 psia through the



Figure 14. Projected fuel/electricity prices

Figure 15. Projection of fuel prices

bypassing of HP steam into the cold reheat.Thus, a maximum steam turbine generator out-put equivalent to the sliding pressure case canbe achieved without sacrificing any significantunfired performance relative to the base con-figuration. The disadvantages to this configura-tion is that it has a slightly higher capital costthan that associated with the sliding pressureconfiguration, and there is a higher duct burn-er fuel consumption when firing to a steam tur-bine generator output equal to that obtainedwith the sliding pressure configuration. Thesteam turbine generator output obtained repre-sents a gain in gross steam turbine generatoroutput of approximately 41%, correlating to again in net plant output of approximately14.5% relative to the base plant configurationperformance at peak period ambient condi-tions.

Gas Turbine Inlet Fogging/EvaporativeCoolingSince the performance benefits gained throughthe application of either evaporative cooling oran inlet fogging system are sensitive to variationin ambient relative humidity (see Figure 5), it islogical to assume that the economic evaluationbenefit of both systems is also sensitive to varia-tions in ambient relative humidity. This casestudy attempts to address this phenomenon byexamining the evaluation benefit of each sys-tem at both nominal “peak-load” ambient con-ditions 95°F, 45% RH, as well as at 95°F and60% RH (cases 6, 7, 8 and 9).

The benefit of fogging over traditional evapora-tive coolers appears to be threefold: lower cap-ital cost, more effective cooling (ability toachieve lower gas turbine compressor inlet tem-peratures) and a much lower gas turbine inletpressure drop through the application of thefogging hardware. Given that the inlet air-cool-

ing potential is higher with the fogging systemthan the evaporative cooling system, the resultis a higher peak period power improvement. Inaddition, during nonpeak periods (when thepower-enhancement devices are not in service),the plant configured with an inlet fogging sys-tem has a higher plant output than a plant con-figured with a traditional evaporative coolingsystem. This is a direct result of the lower inletpressure drop associated with inlet fogging asopposed to that associated with a traditionalevaporative cooling system.

One potential drawback to the fogging system isthe potential for water droplet carryover intothe gas turbine compressor inlet. The potentialproblems associated with water carryover intothe compressor and impact of water carryoveron DLN combustion system operation are cur-rently under investigation.

Gas Turbine Inlet Chilling For the purpose of this study, a mechanicalchilling system with chilling to a gas turbinecompressor inlet temperature of 45°F was stud-ied as a potential means of producing addition-al peak period power. As in the case of evapora-tive cooling, chilling systems sizing and effec-tiveness is impacted by the ambient relativehumidity. Thus, this study includes inlet airchilling to 45°F at ambient conditions of 95°F,45% RH, and 95°F, 60% RH, to determine thesensitivity of the COE for chilling with respectto ambient relative humidity.

The effect of a chilling system utilizing the maincooling tower as a heat sink compared with asystem with a dedicated cooling system was alsotaken into consideration. The chilling systemwith a dedicated cooling system results in aslightly higher performance level than the sys-tem using the main cooling tower because itdoes not have an impact on the steam turbine



back pressure; however, its performance benefitis more than offset by the additional capital costof the dedicated cooling system.

This study does not address alternative inlet chill-ing arrangements such as thermal storage andabsorption chilling cycles, described previously.

ResultsUnder almost every economic scenario consid-ered in this study, HRSG duct firing (both in slid-ing- and fixed-pressure modes of operation)appears to be a clear winner in terms of a 20-yearCOE evaluation relative to the base case (casewithout any power enhancement equipment).Duct firing is followed by inlet fogging, evapora-tive cooling and inlet air chilling that, in general,also have favorable evaluations relative to thebase. A general exception to this is inlet air chill-ing at peak power rates less than 9 cents per kilo-watt hour (refer to Exhibit 1).

Graphical representation of incremental peakpower revenue as a function of peak energy rateversus peak operating hours has been providedfor each of these alternatives (Exhibit 2). Thisdata illustrates each alternative’s sensitivity tooperating hours, fuel cost and peak energy rateand establishes categories of risk vs. reward asso-ciated with the alternatives.

The four alternatives described above have beendivided into three categories based upon thepotential risk and reward associated with each ofthe alternatives. These categories are low risk-moderate reward, moderate risk-high reward andhigh risk-high reward. Graphical representationsof risk vs. reward on a net present value (NPV)basis for these four alternatives are at-tached(Exhibit 3). The risk associated with a given alter-native is the capital investment for that alterna-tive combined with the value of the lost perform-ance during nonpeak operating hours. The eco-

nomic penalty resulting from lost performance isevaluated assuming a uniform price of electricity.In other words the economic penalty accountsfor any incremental increase in the COE of agiven alternative relative to the base case and isindependent of peak energy rate and peak loadduration. For this study, the NPV of this lost per-formance is referred to as a nonpeak perform-ance burden. The reward has been defined asthe NPV of the incremental revenue associatedwith a given alternative during peak operationalperiods relative to the base over an evaluationterm of 20 years. Referring to Exhibit 3, the opti-mal peak performance plant alternative for anygiven economic scenario will be the one that isfarthest from the y-axis in conjunction with beingclosest to the x-axis. The solid line on thesecurves represents parity between the potentialrisk and reward. In other words, a point on thisline represents a scenario in which the potentialreward is equivalent to potential risk. It should benoted that for some alternatives, under certaineconomic scenarios it is possible to achieve a neg-ative value for risk, which represents the benefitthat could be achieved by that alternative, assum-ing uniform price of electricity annually.

The incremental installed capital investmentassociated with a given power-enhancementalternative is an integral part of the overall eco-nomic analysis model. Although it is believedthat the best possible estimates were utilized with-in the COE model used throughout the course ofthis study, it is worthwhile to consider themodel’s sensitivity to this parameter. In general,the capital investment associated with each of thealternatives is a very small percentage of the totalcapital investment. Thus, a small deviationbetween the estimated investment capital relativeto an actual, as-procured/installed capital invest-ment should not compromise the integrity of theconclusions drawn from the results of the study.



Although the relative ranking of the various peakpower-enhancement alternatives will not be sig-nificantly altered, the evaluation of an alternative

relative to the base plant configuration will beslightly influenced. In an effort to address anypotential concerns associated with this point, the



In crem en ta l P eak R even u e vs . P eak O p era tin g H o u rs

-$100

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Peak Operation (hrs /year)

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Method: HRSG Duct Firing - (Case 15)

Fuel Cos t: $1.50 per MMBtu - HHV

Annual Operating Hours : 7446

20 Year COE - NPV Bas is


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Method: HRSG Duct Firing - (Case 15)

Fuel Cost: $3.50 per MMBtu - HHV

Total Annual Operating Hours: 7446

20 Year COE - NPV Basis

In c rem en ta l P eak R even u e vs . P eak O p era tin g H o u rs

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Method: Gas Turbine Inlet Fogging - (Case 8)


Total Annual Operating Hours : 7446



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Method: Gas Turbine Inlet Fogging - (Case 8)





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Method: GT Mechanical Inlet Air Chiller - (Case 11)




In cre me n tal Pe ak Re v e n u e v s. Pe ak Op e ratin g Ho u rs

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Method: GT Mechanical Inlet Air Chiller - (Case 11)




Exhibit 2. Incremental peak power revenue vs. peak operating hours (by peak power alternative)

COE model was run assuming a ±10% change ineach alternative’s capital investment require-ment to make an assessment of the sensitivity of

the relative evaluation to this change (see Table 2).Table 2 can be used in conjunction with Exhibits1a and 1b to assess the relative ranking of these




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Method: Gas Turbine Evaporative Cooling - (Case 6)





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15.00

18.00

Method: Gas Turbine Evaporative Cooling - (Case 6)




Exhibit 2 (cont). Incremental peak power revenue vs. peak operating hours (by peak power alternative)

N P V R ew ard vs R isk

Case 14

Case 28

Case 15

Case 8

Case 6

Case 1

Case 11Case 2

($2 .0 )

$0 .0

$2 .0

$4 .0

$6 .0

$8 .0

$10 .0

$12 .0

$0 .0 $1 .0 $2 .0 $3 .0 $4 .0 $5 .0 $6 .0 $7 .0 $8 .0 $9 .0

In c rem en ta l N e t R even u e - R ew ard ($M M )

Ne

t In

ve

stm

en

t

+ N

on

-Pe

ak

Pe

rfo

rma

nc

e B

urd

en

- R

isk

($

MM

)

Fuel Cost = $2.50 per MMBTU - HHV

Total Annual Operating Hours = 7446

Peak Annual Operating Hours = 500

Peak Energy Rate = 6.00 ¢/kWH

HRSG Duct Firing

GT Inlet ChillingSteam Injection

Evap. Cooling/Fogging

GT Peak Firing


Case 2

Case 11

Case 1

Case 6

Case 8

Case 15

Case 28

Case 14

($4 .0 )

($2 .0 )

$0 .0

$2 .0

$4 .0

$6 .0

$8 .0

$10 .0

$12 .0

$14 .0

$16 .0

$18 .0

$0 .0 $2 .0 $4 .0 $6 .0 $8 .0 $10 .0 $12 .0 $14 .0 $16 .0 $18 .0


Ne

t In

ve

stm

en

t

+ N

on

-Pe

ak

Pe

rfo

rma

nc

e B

urd

en

- R

isk

($

MM

)

Fuel Cost = $2.50 per MMBTU - HHV

Total Annual Operating Hours = 7446

Peak Annual Operating Hours = 1000


HRSG Duct Firing

GT Inlet Chilling

Steam Injection


GT Peak Firing


Case 2 Case 11

Case 1

Case 6

Case 8

Case 15

Case 28

Case 14

($2 .0 )

$0 .0

$2 .0

$4 .0

$6 .0

$8 .0

$10 .0

$12 .0

$14 .0

$16 .0

$18 .0

$0 .0 $2 .0 $4 .0 $6 .0 $8 .0 $10 .0 $12 .0 $14 .0 $16 .0 $18 .0


Ne

t In

ve

stm

en

t

+ N

on

-Pe

ak

Pe

rfo

rma

nc

e B

urd

en

- R

isk

($

MM

)

Fuel Cost = $2.50 per MMBTU - HHVTotal Annual Operating Hours = 7446Peak Annual Operating Hours = 500


HRSG Duct Firing



GT Peak Firing


Case 2Case 11

Case 1

Case 6

Case 8

Case 15

Case 28

Case 14

($6 .0 )

($1 .0 )

$4 .0

$9 .0

$14 .0

$19 .0

$24 .0

$29 .0

$34 .0

$0 .0 $5 .0 $10 .0 $15 .0 $20 .0 $25 .0 $30 .0 $35 .0


Ne

t In

ve

stm

en

t

+ N

on

-Pe

ak

Pe

rfo

rma

nc

e B

urd

en

- R

isk

($

MM

)

Fuel Cost = $2.50 per MMBTU - HHVTotal Annual Operating Hours = 7446Peak Annual Operating Hours = 1000


HRSG Duct Firing



GT Peak Firing

Exhibit 3. Risk vs. reward trade-off plots (NPV basis)

alternatives as well as the change in evaluationrelative to the base plant configuration.

HRSG Duct FiringOf all the peak power enhancement optionsexamined, HRSG duct firing represents one of

the largest gains in incremental peak power pro-duction (approximately 15% in net plant outputrelative to the base case) and evaluates favorablyrelative to the base case under all economic sce-narios considered in this study. As such, theapplication of HRSG duct firing appears to havea moderate risk, with the potential for a highreward (relative to the other three alternativesdiscussed here) across a 20-year COE evaluationperiod. The risk has been defined as being mod-erate due the relatively high up-front capitalinvestment combined with its high sensitivity tooperating hours, fuel cost and peak period powerrates. In this study it was determined that the cap-ital investment for duct firing was the thirdlargest of all the alternatives. (The application ofa PG7121[EA] required the largest capital invest-ment and was followed by gas turbine inlet airchilling.)

It should be noted that the duct-firing rate con-sidered in this study is a modest one in terms ofthe incremental increase in both STG and net

plant output. Although it is possible to achieveplant capacities above and beyond those consid-ered here, thus achieving larger peak revenuestreams, additional economic risk will beincurred. In general, as more and more peak fir-ing capacity is designed into the plant arrange-ment, the unfired “baseload” plant performanceis shifted further away from the optimal unfiredplant performance (base case). Thus, when andif the current power generation market shiftsfrom one that is driven primarily by capacity toone that is driven by efficiency, a plant economi-cally optimized around a capacity-driven marketwould be economically disadvantaged relative toone optimized around base load efficiency.

Of the two HRSG duct-firing alternativesdescribed above, duct firing in a fixed-pressuremode of operations tends to favor low-peak oper-ation hours, while duct firing in a sliding-pres-sure mode tends to favor high-peak operationhours. This trend exists because fixed-pressurearrangement is more efficient (with highersteam turbine generator output in an unfiredmode of operation) during nonpeak power peri-ods, while the sliding-pressure arrangement ismore efficient during peak operational periods(because it requires less duct burner fuel con-sumption to achieve a fixed steam turbine gener-ator output).

Gas Turbine Inlet Air FoggingGas turbine inlet air fogging falls into the low-risk, moderate-reward category. Of all the alter-natives discussed, inlet fogging requires the low-est up-front capital investment. Inlet fogging hadthe lowest incremental peak power-generatingcapacity (approximately 5.5 to 7% on a net plantoutput basis), second only to evaporative cool-ing. Of all the alternatives, inlet fogging is theleast sensitive to the variations in the economicparameters considered because of its insignifi-



Power- Change in Relative Change inEnhancement Capital Evaluation ($MM) –

Technology Investment NPV

GT Peak Firing ±10% -0.04/+0.04Evaporative Cooling ±10% -0.13/+0.13Inlet Fogging ±10% -0.11/+0.11Inlet Chilling ±10% -1.01/+1.01Steam Injection ±10% -0.41/+0.41HRSG Duct Firing ±10% -0.37/+0.37

Table 2. Effect of capital investment change oneconomic evaluation

cant impact on nonpeak period plant perform-ance, coupled with its low initial investment andmodest gain in incremental peak-period powergeneration.

Gas Turbine Evaporative CoolingTraditional gas turbine evaporative cooling alsofalls into the low-risk, moderate-reward category.Evaporative cooling requires a somewhat largercapital cost investment than is required for inletfogging, has a slightly larger negative impact onplant performance than inlet fogging and hasthe lowest incremental peak power-generatingcapacity (approximately 3 to 4.7% on a net plantoutput basis) of all the alternatives describedhere. The economic trends associated with theevaporative cooling system are similar to thosethat exist for inlet air fogging; however, evapora-tive cooling requires a slightly higher incremen-tal peak power energy rate to achieve parity withthe base plant arrangement than what isrequired for inlet air fogging.

Both inlet fogging and evaporative cooling aresensitive to ambient relative humidity. The lessmoisture in the inlet air entering the gas turbineinlet, the more effective are fogging and evapo-rative cooling, resulting in a larger increase inpeak power-generating capacity. The converse ofthis is also true.

Gas Turbine Inlet Air Chilling Gas turbine inlet air chilling for the sole purposeof capturing additional peak-period power rev-enues falls into a high-risk, high-reward category.Of the alternatives discussed, inlet chillingrequires the largest up-front capital cost invest-ment with an incremental peak-period power-generating capacity second only to HRSG ductfiring (approximately 9 to 10.8% on a net plantoutput basis). Inlet air chilling has the highestsensitivity to peak-period operating hours and is

second only to HRSG duct firing in terms of sen-sitivity to fuel cost.

The purpose of this study has been to determinethe most economical peak power-enhancementalternative and as such does not account for anyincremental power benefit that could beachieved at the annual average conditions by wayof the application of an inlet chilling system.Provided that a load demand exists, inlet air chill-ing could be utilized to maintain a constant com-pressor inlet air temperature of 45°F for ambienttemperatures greater than 45°F. This would pro-vide an additional economic evaluation benefitof approximately $3.25 million and would allowinlet air chilling to be reclassi-fied as a moderate-risk, high-reward peak power-enhancement alter-native because it would compare favorably withrespect to the base overall economic scenariosconsidered.

ConclusionSeveral means are available to enhance com-bined-cycle performance beyond larger gas tur-bine sizes and increased cycle complexity.Output enhancements range from those thatprovide hot-day output improvements (i.e., evap-orative cooling, spray intercooling and inlet chill-ing) to those that can provide higher outputs atall ambient conditions (water injection and sup-plementary firing). Efficiency enhancements canbe achieved through fuel heating and sprayintercooling. The final choice requires carefulevaluation of many factors, including water avail-ability, maintenance factors, capital cost, operat-ing cost, operating duration and plant dispatchcharacteristics.

The focal point of this case study is centered onthe economic drivers and opportunities thatexist in today’s market environment. While theeconomics in today’s market are primarily capac-ity driven as a result of premiums paid for power



generation during relatively short peak-powerdemand periods, longer-term market predic-tions should be carefully considered to ensurelong-term profitability. As the installed capacitybase increases throughout the country, fuelprices escalate and deregulation in the powergeneration industry becomes more prevalent, itis expected that a renewed emphasis will beplaced upon plant efficiency. Thus, the plantdesigned with moderate increases in capacitytoday, bearing in mind that efficiency will sig-nificantly impact a plant’s profitability in thefuture, could be the overall winner in terms oflife-cycle profitability.

References1. Chin, D, Hermanson, J. C., and Spadaccini,

L. J., “Thermal Stability and Heat TransferCharacteristics of Methane and Natural GasFuels,” Transactions of the ASME Paper 94-GT-390, 1994.

2. Loud, R. L., and Slaterpryce, A.A., “GasTurbine Inlet Air Treatment,” GER 3419A,1991.

3. Mee, T. R., “Inlet Fogging Augments PowerProduction,” Power Engineering, February1999.

4. Fisk, R. W., and VanHousen, R. L.,“Cogeneration ApplicationConsiderations,” GER 3430F, 1996.

5. Brooks, F. J., “GE Heavy-Duty Gas TurbinePerformance Characteristics,” GER3567G,1996.

6. McNeely, M., “Intercooling for LM6000 GasTurbines,” Diesel and Gas TurbineWorldwide, July-August 1998.

7. Lukas, H., “Power Augmentation throughInlet Cooling,” Global Gas Turbine News,Vol. 37, No. 3, 1997.

Glossary

Economic Terms

cost of electricity (COE). Total cost of produc-ing electricity, including fuel, operation andmaintenance (O&M), as well as capital returnand recovery and other miscellaneous operat-ing expenses.

variable expenses. Costs in producing electrici-ty that are a function of how many hours theplant is operated (fuel, maintenance that isfired hours dependent and consumables).

fixed expenses. Costs in producing electricitythat are not functions of how many hours theplant is operated (capital charges, operatingstaff, administration and property taxes).

energy revenue. Revenues paid for the deliveryof energy (kWh or MW hours) to the grid. Notethat two energy revenue streams are consideredwithin the economic analysis presented here;one that is a function of the cost of electricityduring base load operation and a second that isa function of assumed peak energy rates. Eachis a function of the split between base load andpeak-load operating hours.

turnkey cost. Price of plant by supplier, ready tooperate (typically expressed in either millionsof dollars or $/kW).

total capitalization. Turnkey cost plus owner’scost. Examples include interest during con-struction (IDC), permitting, land, intercon-nects and startup costs.

fixed-charge rate (FCR). A simplified represen-tation of the annual cost of borrowed andinvested capital. Comparable to a loan repay-ment rate in that its value (expressed as a per-centage of total invested capital), if receivedeach year over the economic life of the project,assures the owner the return of the invested



capital (equity and debt) and a stipulatedreturn on capital. (The typical IPP rate in theUnited States is 16% for 20 years.)

levilization. Conversion of a series of changingcash flows to an equivalent constant cash flowwith an identical net present value (NPV).Extremely use-ful for comparing two or moreprojects or plant design concepts with differentenergy and capital cost structures.

Other Termsrisk. The economic risk of any given power-enhancement option taking into account the

performance penalty at base load relative to anoptimized plant without enhancement, the cap-ital cost associated with the enhancement op-tion, as well as any additional fuel and O&Mcosts. Do not confuse economic risk with tech-nology risk.

reward. Potential incremental revenues associ-ated with peak power production. For the pur-pose of this paper, it equals the net plant poweroutput (at peak load conditions) times (the dif-ference between the cost of electricity and peakenergy rate) times (the peak operating hours).



List of FiguresFigure 1. Potential peak energy rate variation as a function of annual operating hours

Figure 2. Plant performance trends

Figure 3. Combined-cycle system performance variation with ambient air temperature

Figure 4. Psychrometric chart, simplified

Figure 5. Effect of evaporative cooler on available output – 85% effective

Figure 6. Media pack cooler design

Figure 7. Evaporation rate for MS6001(B) – 85% effective

Figure 8. Langelier saturation index chart

Figure 9. Fogger system

Figure 10. Diagram of LM6000 PC SPRINT™ system

Figure 11. Inlet cooling process

Figure 12. Fuel heating functional block diagram

Figure 13. Standard gas fuel heating system

Figure 14. Projected fuel/electricity prices

Figure 15. Projection of fuel prices

List of TablesTable 1. STAG system power-enhancement options

Table 2. Effect of capital investment change on economic evaluation

List of ExhibitsExhibit 1. List of performance enhancements

Exhibit 1a. COE summary across multiple economic scenarios

Exhibit 1b. COE rankings across multiple economic scenarios

Exhibit 2. Incremental peak power revenue vs. peak operating hours (by peak power alternatives)

Exhibit 3. Risk vs. reward trade-off plots [NPV basis]



ger-4200 - economic and technical considerations for ......opposed to the bottoming cycle...

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