GER-4211 - Gas Turbine Emissions And Control
gGER-4211GE Power SystemsGas Turbine Emissionsand ControlRoointon PavriGerald D. MooreGE Energy ServicesAtlanta, GA
Gas Turbine Emissions and ControlContentsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Emissions Characteristics of Conventional Combustion Systems . . . . . . . . . . . . . . . . . . . . . 1Nitrogen Oxides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Carbon Monoxide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Unburned Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Sulfur Oxides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Particulates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Smoke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Dry Emissions Estimates at Base Load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Dry Emissions Estimates at Part Load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Simple-Cycle Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Exhaust Heat Recovery Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Other NOx Influences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Emission Reduction Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Nitrogen Oxides Abatement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Lean Head End (LHE) Combustion Liners. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Water/Steam Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Carbon Monoxide Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Unburned Hydrocarbons Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Particulate and Smoke Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Water/Steam Injection Hardware. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Minimum NOx Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Maintenance Effects. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29Performance Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32GE Power Systems GER-4211 (03/01) i
Gas Turbine Emissions and ControlGE Power Systems GER-4211 (03/01) ii
Gas Turbine Emissions and ControlIntroductionWorldwide interest in gas turbine emissions andthe enactment of Federal and State regulationsin the United States have resulted in numerousrequests for information on gas turbine exhaustemission estimates and the effect of exhaustemission control methods on gas turbine performance. This paper provides nominal estimates of existing gas turbine exhaust emissionsas well as emissions estimates for numerous gasturbine modifications and uprates. (For sitespecific emissions values, customers should contact GE.) Additionally, the effects of emissioncontrol methods are provided for gas turbinecycle performance and recommended turbineinspection intervals. Emission control methodsvary with both internal turbine and externalexhaust system emission control. Only the internal gas turbine emission control methods —lean head end liners and water/steam injection— will be covered in this paper.In the early 1970s when emission controls wereoriginally introduced, the primary regulatedgas turbine emission was NOx. For the relatively low levels of NOx reduction required in the1970s, it was found that injection of water orsteam into the combustion zone would producethe desired NOx level reduction with minimaldetrimental impact to the gas turbine cycle performance or parts lives. Additionally, at thelower NOx reductions the other exhaust emissions generally were not adversely affected.Therefore GE has supplied NOx water andsteam injection systems for this applicationsince 1973.With the greater NOx reduction requirementsimposed during the 1980s, further reductionsin NOx by increased water or steam injectionbegan to cause detrimental effects to the gasturbine cycle performance, parts lives andinspection criteria. Also, other exhaust emis-GE Power Systems GER-4211 (03/01) sions began to rise to measurable levels of concern. Based on these factors, alternative methods of emission controls have been developed: Internal gas turbine—Multiple nozzle quiet combustorsintroduced in 1988—Dry Low NOx combustorsintroduced in 1990 External—Exhaust catalystsThis paper will summarize the current estimated emissions for existing gas turbines and theeffects of available emission control techniques(liner design and water/steam injection) on gasturbine emissions, cycle performance, andmaintenance inspection intervals. The latesttechnology includes Dry Low NOx and catalyticcombustion. These topics are covered in otherGERs.Emissions Characteristics ofConventional Combustion SystemsTypical exhaust emissions from a stationary gasturbine are listed in Table 1. There are two distinct categories. The major species (CO2, N2,H2O, and O2) are present in percent concentrations. The minor species (or pollutants)such as CO, UHC, NOx, SOx, and particulatesare present in parts per million concentrations.In general, given the fuel composition andmachine operating conditions, the majorspecies compositions can be calculated. Theminor species, with the exception of total sulfuroxides, cannot. Characterization of the pollutants requires careful measurement and semitheoretical analysis.The pollutants shown in Table 1 are a functionof gas turbine operating conditions and fuelcomposition. In the following sections, eachpollutant will be considered as a function of1
Gas Turbine Emissions and ControlMajor SpeciesTypical Concentration(% Volume)SourceNitrogen (N2)66 - 72Inlet AirOxygen (O2)12 - 18Inlet AirCarbon Dioxide (CO2)1-5Oxidation of Fuel CarbonWater Vapor (H2O)1-5Oxidation of Fuel HydrogenMinor SpeciesPollutantsTypical Concentration(PPMV)SourceNitric Oxide (NO)20 - 220Oxidation of Atmosphere NitrogenOxidation of Fuel-Bound Organic NitrogenNitrogen Dioxide (NO2)2 - 20Carbon Monoxide (CO)5 - 330Incomplete Oxidation of Fuel CarbonSulfur Dioxide (SO2)Trace - 100Oxidation of Fuel-Bound Organic SulfurSulfur Trioxide (SO3)Trace - 4Oxidation of Fuel-Bound Organic SulfurUnburned Hydrocarbons (UHC)5 - 300Incomplete Oxidation of Fuel or IntermediatesParticulate Matter SmokeTrace - 25Inlet Ingestion, Fuel Ash, Hot-Gas-PathAttrition, Incomplete Oxidation of Fuel orIntermediatesTable 1. Gas turbine exhaust emissions burning conventional fuelsoperating conditions under the broad divisionsof gaseous and liquid fuels. NOx increases with the square root ofthe combustor inlet pressureNitrogen Oxides NOx increases with increasingresidence time in the flame zoneNitrogen oxides (NOx NO NO2) must bedivided into two classes according to theirmechanism of formation. Nitrogen oxidesformed from the oxidation of the free nitrogenin the combustion air or fuel are called “thermal NOx.” They are mainly a function of thestoichiometric adiabatic flame temperature ofthe fuel, which is the temperature reached byburning a theoretically correct mixture of fueland air in an insulated vessel.The following is the relationship between combustor operating conditions and thermal NOxproduction: NOx increases strongly with fuel-to-airratio or with firing temperature NOx increases exponentially withcombustor inlet air temperatureGE Power Systems GER-4211 (03/01) NOx decreases exponentially withincreasing water or steam injection orincreasing specific humidityEmissions which are due to oxidation of organically bound nitrogen in the fuel—fuel-boundnitrogen (FBN)—are called “organic NOx.”Only a few parts per million of the available freenitrogen (almost all from air) are oxidized toform nitrogen oxide, but the oxidation of FBNto NOx is very efficient. For conventional GEcombustion systems, the efficiency of conversion of FBN into nitrogen oxide is 100% at lowFBN contents. At higher levels of FBN, the conversion efficiency decreases.Organic NOx formation is less well understoodthan thermal NOx formation. It is important tonote that the reduction of flame temperatures2
Gas Turbine Emissions and Controlto abate thermal NOx has little effect on organic NOx. For liquid fuels, water and steam injection actually increases organic NOx yields.Organic NOx formation is also affected by turbine firing temperature. The contribution oforganic NOx is important only for fuels thatcontain significant amounts of FBN such ascrude or residual oils. Emissions from thesefuels are handled on a case-by-case basis.burning natural gas fuel and No. 2 distillate isshown in Figures 1–4 respectively as a function offiring temperature. The levels of emissions forNo. 2 distillate oil are a very nearly constantfraction of those for natural gas over the operating range of turbine inlet temperatures. Forany given model of GE heavy-duty gas turbine,NOx correlates very well with firing temperature.Gaseous fuels are generally classified accordingto their volumetric heating value. This value isuseful in computing flow rates needed for agiven heat input, as well as sizing fuel nozzles,combustion chambers, and the like. However,the stoichiometric adiabatic flame temperatureis a more important parameter for characterizing NOx emission. Table 2 shows relative thermal NOx production for the same combustorburning different types of fuel. This table showsthe NOx relative to the methane NOx based onadiabatic stoichiometric flame temperature.The gas turbine is controlled to approximateconstant firing temperature and the products ofcombustion for different fuels affect the reported NOx correction factors. Therefore, Table 2also shows columns for relative NOx values calculated for different fuels for the same combustor and constant firing temperature relative tothe NOx for methane.Low-Btu gases generally have flame temperatures below 3500 F/1927 C and correspondingly lower thermal NOx production. However,depending upon the fuel-gas clean-up train,these gases may contain significant quantities ofammonia. This ammonia acts as FBN and willbe oxidized to NOx in a conventional diffusioncombustion system. NOx control measures suchas water injection or steam injection will havelittle or no effect on these organic NOxemissions.Typical NOx performance of the MS7001EA,MS6001B, MS5001P, and MS5001R gas turbinesFuelStoichiometricFlame Temp.Carbon MonoxideCarbon monoxide (CO) emissions from a conventional GE gas turbine combustion system areless than 10 ppmvd (parts per million by volume dry) at all but very low loads for steadystate operation. During ignition and acceleration, there may be transient emission levelshigher than those presented here. Because ofthe very short loading sequence of gas turbines,these levels make a negligible contribution tothe integrated emissions. Figure 5 shows typicalNOx (ppmvd/ppmvw-Methane)1765 F/963 C – 2020 F/1104 CFiring TimeNOx (ppmvd/ppmvw-Methane) @15% O2, 1765 F/963 C – 2020 F/1104 CFiring 1.686Hydrogen2.0673.966/4.0295.237/5.299Carbon .6170.489/0.5010.516/0.529No. 2 Oil1.6671.567/1.6471.524/1.614Table 2. Relative thermal NOx emissionsGE Power Systems GER-4211 (03/01) 3
Gas Turbine Emissions and Control280ISO Conditions2003/4 Load160No. 2 Oil1/2 Load120Full Load1/4 Load80400Natural GasGT25056NOX (ppmvw)240100012001400160018002000( F)5406507608709801090( C)Firing TemperatureFigure 1. MS7001EA NOx emissions320280ISO ConditionsNOX (ppmvw)2403/4 Load200No. 2 Oil1601/2 Load1201/4 LoadFull LoadNatural Gas400GT2505780100012001400160018002000( F)5406507608709801090( C)Firing TemperatureFigure 2. MS6001B NOx emissionsCO emissions from a MS7001EA, plotted versusfiring temperature. As firing temperature isreduced below about 1500 F/816 C the carbonGE Power Systems GER-4211 (03/01) monoxide emissions increase quickly. Thischaracteristic curve is typical of all heavy-dutymachine series.4
Gas Turbine Emissions and ControlGT25058200ISO ConditionsNOX (ppmvw)1603/4 LoadNo. 2 Oil1/2 Load1201/4 LoadFull Load8040Natural Gas1/4 Load010001200140016001800 ( F)540650760870980 ( C)Firing TemperatureFigure 3. MS5001P A/T NOx emissionsGT25059160ISO Conditions3/4 LoadNOX (ppmvw)120No. 2 Oil1/2 Load801/4 LoadFull Load40Natural Gas010001200140016001800( F)540650760870980( C)Firing TemperatureFigure 4. MS5001R A/T NOx emissionsUnburned HydrocarbonsUnburned hydrocarbons (UHC), like carbonmonoxide, are associated with combustion inefficiency. When plotted versus firing temperature, the emissions from heavy-duty gas turbineGE Power Systems GER-4211 (03/01) combustors show the same type of hyperboliccurve as carbon monoxide. (See Figure 6.) At allbut very low loads, the UHC emission levels forNo. 2 distillate and natural gas are less than7 ppmvw (parts per million by volume wet).5
Gas Turbine Emissions and ControlGas Turbine Machine ExhaustCO (ppmvd)GT25060200160Natural Gas1201/4 Load80401/2 LoadDistillateOil3/4 LoadFull Load08001000120014001600180020002200 ( F)43054065076087098010901200 ( C)Firing TemperatureFigure 5. CO emissions for MS7001EAGas Turbine Machine ExhaustUHC (ppmvw)GT2506112010080Natural Gas601/4 Load401/2 Load3/4 LoadFull 2200 ( F)32043054065076087098010901200 ( C)Firing TemperatureFigure 6. UHC emissions for MS7001EASulfur OxidesThe gas turbine itself does not generate sulfur,which leads to sulfur oxides emissions. All sulfuremissions in the gas turbine exhaust are causedGE Power Systems GER-4211 (03/01) by the combustion of sulfur introduced into theturbine by the fuel, air, or injected steam orwater. However, since most ambient air andinjected water or steam has little or no sulfur,the most common source of sulfur in the gas6
Gas Turbine Emissions and Controlturbine is through the fuel. Due to the latest hotgas path coatings, the gas turbine will readilyburn sulfur contained in the fuel with little orno adverse effects as long as there are no alkalimetals present in the hot gas.using the relationships above, the various sulfuroxide emissions can be easily calculated fromthe fuel flow rate and the fuel sulfur content asshown in Figure 7.There is currently no internal gas turbine technique available to prevent or control the sulfuroxides emissions from the gas turbine. Controlof sulfur oxides emissions has typically requiredlimiting the sulfur content of the fuel, either bylower sulfur fuel selection or fuel blending withlow sulfur fuel.GE experience has shown that the sulfur in thefuel is completely converted to sulfur oxides. Anominal estimate of the sulfur oxides emissionsis calculated by assuming that all fuel sulfur isconverted to SO2. However, sulfur oxide emissions are in the form of both SO2 and SO3.Measurements show that the ratio of SO3 toSO2 varies. For emissions reporting, GE reportsthat 95% of the sulfur into the turbine is converted to SO2 in the exhaust. The remainingsulfur is converted into SO3. SO3 combines withwater vapor in the exhaust to form sulfuric acid.This is of concern in most heat recovery applications where the stack exhaust temperaturemay be reduced to the acid dew point temperature. Additionally, it is estimated that 10% byweight of the SOx generated is sulfur mist. ByParticulatesGas turbine exhaust particulate emission ratesare influenced by the design of the combustionsystem, fuel properties and combustor operating conditions. The principal components ofthe particulates are smoke, ash, ambient noncombustibles, and erosion and corrosion products. Two additional components that could beconsidered particulate matter in some localitiesare sulfuric acid and unburned hydrocarbonsthat are liquid at standard conditions.16001200800% Sulfur by Weight0.60.44006040SO3 (lb/hr)4208121620Total Fuel Flow Rate (lb/sec)4080120GT250620.2160Sulfur Mist EmissionRate (lb/hr)801001.00.8SO2 (lb/hr)SO3 /SO20.0658 by WeightTYPICAL BASE LOADFUEL FLOW:51P61B71EA91E4.7 lb/sec6.2 lb/sec13.0 lb/sec18.5 lb/secFigure 7. Calculated sulfur oxide and sulfur emissionsGE Power Systems GER-4211 (03/01) 7
Gas Turbine Emissions and Controllates are also reported as PM-10. Therefore PM10 is not shown in the tables. The nominal fullrated firing temperature for each gas turbinemodel is also shown in Table 3.SmokeSmoke is the visible portion of filterable particulate material. The GE combustor design coupled with air atomization of liquid fuels hasresulted in a nonvisible plume over the gas turbine load range for a wide variety of fuels. TheGE smoke-measuring unit is the Von BrandReflective Smoke Number (GEVBRSN). If thisnumber is greater than 93 to 95 for theMS7001E, then the plume will not be visible.For liquid fuels, the GEVBRSN is a function ofthe hydrogen content of the fuel. For naturalgas fuel, the smoke number is essentially 99 to100 over the load range and visible smoke is notpresent.As can be easily seen in the table, at base loadwithout NOx abatement, the emissions of CO,UHC, VOC, and particulates are quite low. Theestimated values of NOx vary between gas turbine designs and generally increase with theframe size firing temperature.Dry Emissions Estimates at Part LoadSimple-Cycle TurbinesAt turbine outputs below base load the emissions change from the values given in Table 3.These changes are affected by the turbine configuration and application and in some cases bythe turbine controls.Dry Emissions Estimates at Base LoadThe ISO non-abated full load emissions estimates for the various GE heavy-duty gas turbinemodels are provided in Table 3. The natural gasand #2 distillate fuel emission estimates shownare for thermal NOx, CO, UHC, VOC, and particulates. For reporting purposes, all particu-Single-shaft gas turbines with non-modulatinginlet guide vanes operating at constant shaftspeed have part load emissions characteristicswhich are easily estimated. For these turbinesH2O/Steam Inj.GasGas(FG1A/FG1B)(FG1C/FG1F)Firing S7001BMS7001B Option 3MS7001B Option 41321601651912052452525252542424242MS9001BMS9001B Option 3MS9001B Option 65656565656FA7FA7FA
of gas turbine operating conditions and fuel composition. In the following sections, each pollutant will be considered as a function of Gas Turbine Emissions and Control GE Power Systems GER-4211 (03/01) 1
control methods are provided for gas turbine cycle performance and recommended turbine inspection intervals. Emission control methods vary with both internal turbine and external exhaust system emission control. Only the inter-nal gas turbine emission control methods — lean head end liners and water/steam injection — will be covered in this paper.
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“Technology Characterization: Gas Turbines”, Energy and Environmental Analysis, Prepared for: Environmental Protection Agency, 2008 Solar turbines performance specifications: Taurus 60, 5.74 MW turbine R. Pravi, G. Moore, “Gas Turbine Emissions and Control”, GE Power Systems, March, 2001, GER -4211 Air intake Exhaust:
A gas turbine is an extension of the same concept. In a gas turbine, a pressurized gas spins the turbine. In all modern gas turbine engines, the engine produces its own pressurized gas, and it does this by burning something like propane, natural gas, kerosene or jet fuel.
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