dry low nox combustion for gas turbines

GE Power Systems

Dry Low NOx CombustionSystems for GE Heavy-DutyGas Turbines

L.B. DavisS.H. BlackGE Power SystemsSchenectady, NY

GER-3568G

g

Contents

Abstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Dry Low NOx Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Dry Low NOx Product Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1DLN-1 System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3DLN-1 Combustor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Mode/Operating Range . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4DLN-1 Controls and Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6DLN-1 Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6DLN-1 Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7DLN-2 System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8DLN-2 Combustion System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Primary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Lean-Lean. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Premix Transfer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Piloted Premix. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Premix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Tertiary Full Speed No Load (FSNL). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

DLN-2 Controls and Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11DLN-2 Emissions Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11DLN-2 Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11DLN-2.6 Evolution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12DLN-2+ Evolution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Gas Turbine Combustion Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Equivalence Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Flame Stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Operational Stability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Gas Turbine Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Emissions Control Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Dry Low NOx Combustion Systems for GE Heavy-Duty Gas Turbines

GE Power Systems ■ GER-3568G ■ (10/00) i


GE Power Systems ■ GER-3568G ■ (10/00) ii

AbstractState-of-the-art emissions control technology forheavy-duty gas turbines is reviewed with empha-sis on the operating characteristics and fieldexperience of Dry Low NOx (DLN) combustorsfor E and F technology machines. The lean pre-mixed DLN systems for gas fuel have demon-strated their ability to meet the ever-lower emis-sion levels required today. Lean premixed tech-nology has also been demonstrated on oil fueland is also discussed.

IntroductionThe regulatory requirements for low emissionsfrom gas turbine power plants have increasedduring the past 10 years. Environmental agen-cies throughout the world are now requiringeven lower rates of emissions of NOx and otherpollutants from both new and existing gas tur-bines. Traditional methods of reducing NOx

emissions from combustion turbines (water andsteam injection) are limited in their ability toreach the extremely low levels required in manylocalities. GE’s involvement in the developmentof both the traditional methods (References 1through 6) and the newer Dry Low NOx (DLN)technology (References 7 and 8) has been welldocumented. This paper focuses on DLN.

Since the commercial introduction of GE’sDLN combustion systems for natural-gas-firedheavy-duty gas turbines in 1991, systems havebeen installed in more than 222 machines, fromthe most modern FA+e technology (firing tem-perature class of 2420 F/1326 C) to field retro-fits of older machines. As of May 1999, thesemachines have operated more than 4.8 millionhours with DLN; and more than 1.4 millionhours have been in the F technology. To meetmarketplace demands, GE has developed DLNproducts broadly classified as either DLN-1,which was developed for E-technology

(2000°F/1093°C firing temperature class)machines, or DLN-2, which was developedspecifically for the F technology machines andis also being applied to the EC and H machines.

Development of these products has required anintensive engineering effort involving both GEPower Systems and GE Corporate Research andDevelopment. This collaboration will continueas DLN is applied to the H machines and com-bustor development for Dry Low NOx on oil(“dry oil”) continues.

This paper presents the current status of DLN-1technology and experience, including dry oil,and of DLN-2 technology and experience.Background information about gas turbineemissions and emissions control is contained inthe Appendix.

Dry Low NOx Systems

Dry Low NOx Product Plan Figure 1 shows GE’s Dry Low NOx product of-ferings for its new and existing machines inthree major groupings. The first group includesthe MS3002J, MS5001/2 and MS6001B prod-ucts. The 6B DLN-1 is the technology flagshipproduct for this group and, as can be noted, isavailable to meet 9 ppm NOx requirements.Such low NOx emissions are generally notattainable on lower firing temperaturemachines such as the MS3002s and MS5001/2sbecause carbon monoxide (CO) would beexcessive.

The second major group includes theMS7001B/E, MS7001EA and MS9001Emachines with the 9 ppm 7EA DLN-1 as theflagship product.

The dry oil program focuses initially on thisgroup.

The third group combines all of the DLN-2products and includes the FA, EC, and H


GE Power Systems ■ GER-3568G ■ (10/00) 1

machines, with the 7FA product as the flagship.

As shown in Figures 2 and 3, most of these prod-ucts are capable of power augmentation and ofpeak firing with increased NOx emissions. With

gas fuel, power augmentation with steam is inthe premixed mode for both DLN-1 and DLN-2systems.

The GE DLN systems integrate a staged pre-mixed combustor, the gas turbine’sSPEEDTRONIC™ controls and the fuel andassociated systems. There are two principalmeasures of performance. The first is meetingthe emission levels required at baseload on bothgas and oil fuel and controlling the variation ofthese levels across the load range of the gas tur-bine.

The second measure is system operability, withemphasis placed on the smoothness and relia-bility of combustor mode changes, ability toload and unload the machine without restric-tion, capability to switch from one fuel to anoth-er and back again, and system response to rapidtransients (e.g., generator breaker open eventsor rapid swings in load). GE’s design goal is tomake the DLN system operate so the gas tur-bine operator does not know whether a DLN orconventional combustion system has beeninstalled (i.e., its operation is “transparent tothe user”). A significant portion of the DLNdesign and development effort has focused onsystem operability. As operational experience



9 25

Turbine Model

MS6001(B)

MS7001(EA)

MS7001(FA) 9

25

9

25

9

NOx@15% O2(ppmvd)

OperatingMode Diluent

NOx atMax D/F(ppmvd)

MaximumDiluent/Fuel

COMax D/F(ppmvd)

Premix

Premix

Premix

Premix

Premix Steam

Steam

Steam

Steam

Steam 2.5/1

2.5/1

2.5/1

2.5/1

GT24556B.ppt

2.1/1 12

25 15

15

9 25

25 15

Figure 2. DLN power augmentation summary

MS6001(B)

MS7001(EA)

MS7001(FA)

MS9001(E)

9

25

18

50

25

15

6

4

9

25

25

25

25

15

18

50

35 15

40 15

6

4

6

6

NOx-Base(ppmvd)

NOx-Peak(ppmvd)

CO-Base(ppmvd)

CO-Peak(ppmvd)

GT24557A . ppt

Figure 3. DLN peak firing emissions - natural gasfuel

Gas Distillate

Turbine Model NOx (ppmvd) CO (ppmvd) Diluent NOx (ppmvd) CO (ppmd) Diluent

MS3002(J)-RC 33 25 Dry N/A N/A N/A

MS3002(J)-SC 42 50 Dry N/A N/A N/A

MS5001P 25 50 Dry 65 20 W ater

MS5001R 42 50 Dry 65 20 W ater

MS5002C 42 50 Dry 65 20 W ater

MS6001B 9 25 Dry 42 30 W ater

MS7001B/E Conv. 25 25 Dry 42 30 W ater

MS7001EA 9 25 Dry 42 30 W ater

MS9001E 15 25 Dry 42 20 W ater

25 25 Dry 90 20 Dry

MS6001FA 25 15 Dry 42/65 20 W ater/Steam

MS7001FA 25 15 Dry 42/65 20 W ater/Steam

9 9 Dry 42/65 30 W ater/Steam

MS7001FB 25 15 Dry 42 20 W ater

MS7001H 9 9 Dry 42/65 30 W ater/Steam

MS9001EC 25 15 Dry 42/65 20 W ater/Steam

MS9001FA 25 15 Dry 42/65 20 W ater

MS9001FB 25 15 Dry 42 20 W ater

MS9001H 25 15 Dry 42 20 W ater

Figure 1. Dry Low NOx product plan

has increased, design and development effortshave moved towards hardware durability andextending combustor inspection intervals.

Design of a successful DLN combustor for aheavy-duty gas turbine also requires the design-er to develop hardware features and opera-tional methods that simultaneously allow theequivalence ratio and residence time in theflame zone to be low enough to achieve lowNOx, but with acceptable levels of combustionnoise (dynamics), stability at part-load opera-tion and sufficient residence time for CO burn-out, hence the designation of DLN combustiondesign as a “four-sided box” (See Figure 4).

A scientific and engineering development pro-gram by GE’s Corporate Research andDevelopment, Power Systems business andAircraft Engine business has focused on under-standing and controlling dynamics in lean pre-mixed flows. The objectives have been to:

■ Gather and analyze machine and labo-ratory data to create a comprehensivedynamics data base

■ Create analytical models of gas turbinecombustion systems that can be used tounderstand dynamics behavior

■ Use the analytical models and experi-mental methods to develop methods tocontrol dynamics

These efforts have resulted in a large number ofhardware and control features that limit dynam-ics, plus analytical tools that are used to predictsystem behavior. The latter are particularly use-ful in correlating laboratory test data from fullscale combustors with actual gas turbine data.

DLN-1 SystemDLN-1 development began in the 1970s withthe goal of producing a dry oil system to meetthe United States Environmental ProtectionAgency’s New Source Performance Standardsof 75 ppmvd NOx at 15% O2. As noted inReference 7, this system was tested on both oiland gas fuel at Houston Lighting & Power in1980 and met its emission goals. Subsequent tothis, DLN program goals changed in responseto stricter environmental regulations and thepace of the program accelerated in the late1980s.

DLN-1 CombustorThe GE DLN-1 combustor (shown in cross sec-tion in Figure 5 and described in Reference 8) is atwo-stage premixed combustor designed for usewith natural gas fuel and capable of operationon liquid fuel. As shown, the combustion systemincludes four major components: fuel injectionsystem, liner, venturi and cap/centerbodyassembly.



GT23812B

NOx

CO

Turndown

Dynamics

Figure 4. DLN technology - a four sided box Figure 5. Dry Low NOx combustor

The GE DLN-1 combustion system operates infour distinct modes, illustrated in Figure 6, dur-ing premixed natural gas or oil fuel operation:

These components form two stages in the com-bustor. In the premixed mode, the first stagethoroughly mixes the fuel and air and delivers auniform, lean, unburned fuel-air mixture to thesecond stage.

Mode/Operating Range■ Primary – Fuel to the primary nozzles

only. Flame is in the primary stageonly. This mode of operation is usedto ignite, accelerate and operate themachine over low- to mid-loads, up toa pre-selected combustion referencetemperature.

■ Lean-Lean – Fuel to both the primaryand secondary nozzles. Flame is inboth the primary and secondarystages. This mode of operation is usedfor intermediate loads between twopre-selected combustion referencetemperatures.

■ Secondary – Fuel to the secondarynozzle only. Flame is in the secondaryzone only. This mode is a transitionstate between lean-lean and premix

modes. This mode is necessary toextinguish the flame in the primaryzone, before fuel is reintroduced intowhat becomes the primary premixingzone.

■ Premix – Fuel to both primary andsecondary nozzles. Flame is in thesecondary stage only. This mode ofoperation is achieved at and near thecombustion reference temperaturedesign point. Optimum emissions aregenerated in premix mode.

The load range associated with these modes var-ies with the degree of inlet guide vane modula-tion and, to a smaller extent, with the ambienttemperature. At ISO ambient, the premix oper-ating range is 50% to 100% load with IGV mod-ulation down to 42°, and 75% to 100% loadwith IGV modulation down to 57°. The 42° IGVminimum requires an inlet bleed heat system.

If required, both the primary and secondaryfuel nozzles can be dual-fuel nozzles, thus allow-ing automatic transfer from gas to oil through-out the load range. When burning either natu-ral gas or distillate oil, the system can operate tofull load in the lean-lean mode (Figure 6). Thisallows wet abatement of NOx on oil fuel andpower augmentation with water on gas.



Primary Operation• Ignition to 20% Load

GT20885B. ppt

Lean-Lean Operation• 20 to 50% Load

Second-Stage Burning• Transient During Transfer to Premixed

Premixed Operation• 50 to 100% Load

Fuel100%

Fuel100%

Fuel70%

Fuel83%

17%

30%

Figure 6. Fuel-staged Dry Low NOx operating modes

The spark plug and flame detector arrange-ments in a DLN-1 combustor are different fromthose used in a conventional combustor. Sincethe first stage must be re-ignited at high load inorder to transfer from the premixed mode backto lean-lean operation, the spark plugs do notretract. One plug is mounted near a primaryzone cup in each of two combustors. The systemuses flame detectors to view the primary stage ofselected chambers (similar to conventional sys-tems), and secondary flame detectors that lookthrough the centerbody and into the secondstage.

The primary fuel injection system is used dur-ing ignition and part load operation. The sys-tem also injects most of the fuel during pre-mixed operation and must be capable of stabi-lizing the flame. For this reason, the DLN-1 pri-mary fuel nozzle is similar to GE’s MS7001EAmulti-nozzle combustor with multiple swirl-sta-bilized fuel injectors. The GE DLN-1 systemuses five primary fuel nozzles for the MS6001Band smaller machines and six primary fuel noz-zles for the larger machines. This design is capa-ble of providing a well-stabilized diffusion flamethat burns efficiently at ignition and duringpart load operation.

In addition, the multi-nozzle fuel injection sys-tem provides a satisfactory spatial distributionof fuel flow entering the first-stage mixer. Theprimary fuel-air mixing section is bound by thecombustor first-stage wall, the cap/centerbodyand the forward cone of the venturi. This vol-ume serves as a combustion zone when thecombustor operates in the primary and lean-lean modes. Since ignition occurs in this stage,crossfire tubes are installed to propagate flameand to balance pressures between adjacentchambers. Film slots on the liner walls providecooling, as they do in a standard combustor.

In order to achieve good emissions perform-

ance in premixed operation, the fuel-air equiv-alence ratio of the mixture exiting the first-stagemixer must be very lean. Efficient and stableburning in the second stage is achieved by pro-viding continuous ignition sources at both theinner and outer surfaces of this flow. The threeelements of this stage comprise a piloting flame,an associated aerodynamic device to force inter-action between the pilot flame and the innersurface of the main stage flow, and an aerody-namic device to create a stable flame zone onthe outer surface of the main stage flow exitingthe first stage.

The piloting flame is generated by the second-ary fuel nozzle, which premixes a portion of thenatural gas fuel and air (nominally, 17% at full-load operation) and injects the mixturethrough a swirler into a cup where it is burned.Burning an even smaller amount of fuel (lessthan 2% of the total fuel flow) stabilizes thisflame as a diffusion flame in the cup. The sec-ondary nozzle, which is mounted in the capcenterbody, is simple and highly effective forcreating a stable flame.

A swirler mounted on the downstream end ofthe cap/centerbody surrounds the secondarynozzle. This creates a swirling flow that stirs theinterface region between the piloting flame andthe main-stage flow and ensures that the flameis continuously propagated from the pilot to theinner surface of the fuel-air mixture exiting thefirst stage. Operation on oil fuel is similarexcept that all of the secondary oil is burned ina diffusion flame in the current dry oil design.

The sudden expansion at the throat of the ven-turi creates a toroidal re-circulation zone overthe downstream conical surface of the venturi.This zone, which entrains a portion of the ven-turi cooling air, is a stable burning zone thatacts as an ignition source for the main stagefuel-air mixture. The cone angle and axial loca-



tion of the venturi cooling air dump have sig-nificant effects on the efficacy of this ignitionsource. Finally, the dilution zone (the region ofthe combustor immediately downstream fromthe flame zone in the secondary) provides aregion for CO burnout and for shaping the gastemperature profile exiting the combustion sys-tem.

DLN-1 Controls and Accessories The gas turbine accessories and control systemsare configured so that operation on a DLN-equipped turbine is essentially identical to thatof a turbine equipped with a conventional com-bustor. This is accomplished by controlling theturbines in identical fashions, with the exhausttemperature, speed and compressor dischargepressure establishing the fuel flow and com-pressor inlet-guide-vane position.

A turbine with a conventional diffusion com-bustor that uses diluent injection for NOx con-trol will use an underlying algorithm to controlsteam or water injection. This algorithm will usetop level control variables (exhaust tempera-ture, speed, etc.) to establish a steam-to-fuel orwater-to-fuel ratio to control NOx.

In a similar fashion, the same variables are usedto divide the total turbine fuel flow between theprimary and secondary stages of a DLN com-bustor. The fuel division is accomplished bycommanding a calibrated splitter valve to moveto a set position based on the calculated com-bustion reference temperature (Figure 7). Figure8 shows a schematic of the gas fuel system for aDLN-equipped turbine.

The only special control sequences required arefor protection of the turbine during a generatorbreaker open trip, or for a Primary ZoneIgnition or Primary Re-Ignition (PRI) (i.e.,flame is established in first stage during pre-mixed operation). When either the breaker

opens at load or a PRI is sensed by ultravioletflame detectors looking into the first stage, thesplitter valve is commanded to move to a pre-determined position. For the breaker openevent the combustor returns to normal opera-tion in primary mode at full speed no load(FSNL). In the case of a PRI there is no hard-ware damage and the combustor maintains loadbut operates in extended lean-lean mode withhigh emissions.

DLN-1 EmissionsThe emissions performance of the GE DLN sys-tem can be illustrated as a function of load for agiven ambient temperature and turbine config-uration. Figures 9 and 10 show the NOx and COemissions from typical MS7001EA andMS6001B DLN systems designed for 9 ppmvdNOx and 25 ppm CO when operated on natural



Lean-Lean

Secondary Mode

Premix Mode

202019501600 º F

11041066871 º C

CombustionReference

Temperature

100

90

0

10

20

30

40

50

60

70

80

% P

rim

ary

Fu

el S

plit

GT20327D

Primary Mode

Figure 7. Typical DLN-1 fuel gas split schedule

Figure 8. Dry Low NOx gas fuel system

gas fuel. Note that in premixed operation, NOx

is generally highest at higher loads and CO onlyapproaches 25 ppm at lower premixed loads.The MS9001E DLN system has very similarbehavior but with somewhat higher NOx emis-sions (See Figure 1). Figures 11 and 12 show NOx

and CO emissions for the same systems operat-ed on oil fuel with water injection for NOx con-trol, rather than premixed oil. These figures arefor units equipped with inlet bleed heat andextended IGV modulation.

At loads less than 20% of baseload, NOx andCO emissions from the DLN are similar to thosefrom standard combustion systems. This resultis expected because both systems are operatingas diffusion flame combustors in this range.Between 20% and 50% load, the DLN system isoperated in the lean-lean mode. On gas fuel theflow split between the primary fuel nozzles and

secondary nozzle may be varied to optimizeemissions, while on oil fuel the flow split isfixed.

From 50% to 100% load, the DLN system oper-ates as a lean premixed combustor when operat-ed on gas fuel, and as a diffusion flame combus-tor with water injection when operated on oilfuel. As shown in Figures 9–12, NOx emissionsare significantly reduced, while CO emissionsare comparable to those from the standard sys-tem.

DLN-1 ExperienceGE’s first DLN-1 system was tested at HoustonLighting and Power in 1980 (Reference 7). A pro-totype DLN system using the combustor designdiscussed above was tested on an MS9001E atthe Electricity Supply Board’s (ESB) NorthwallStation in Dublin, Ireland, between October



Figure 10. MS6001B emissions - natural gas

Figure 12. MS6001B emissions distillate oil fuel

Figure 11. MS7001EA Dry Low NOx combustionsystem performance on distillate oil

Figure 9. MS7001EA/MS9001E emissions - natural gas fuel

1989 and July 1990. A comprehensive engineer-ing test of the prototype DLN combustor, con-trols and associated systems was conducted withNOx levels of 32 ppmvd (at 15% O2) obtainedat baseload. The results were incorporated intothe design of prototype systems for theMS7001E and MS6001B.

The 7E DLN-1 prototype was tested atAnchorage Municipal Light and Power (AMLP)in early 1991 and entered commercial serviceshortly afterward. Since then, development ofadvanced combustor configurations have beencarried out at AMLP. These results have beenincorporated into production hardware.

The MS6001B prototype system was first oper-ated at Jersey Central Power & Light’s ForkedRiver Station in early 1991. A series of addition-al tests culminated in the demonstration of a 9ppm combustor at Jersey Central in November1993.

As of May 1999, 44 MS6001B machines areequipped with DLN-1 systems. In total, theyhave accumulated more than 1.4 million hoursof operation. There are, in addition, 4MS7001E, 8 MS7001B/E, 39 MS7001EA, 27MS9001E, 2 MS5001P and 4 MS3002J DLN-1machines that have collectively operated formore than 2 million hours. Excellent emissionresults have been obtained in all cases, with sin-gle-digit NOx and CO achieved on manyMS7001EAs. Several MS7001E/EA machineshave the capability to power augment withsteam injection in premixed mode.

Starting in early 1992, eight MS7001F machinesequipped with GE DLN systems were placed inservice at Korea Electric Power Company’sSeoinchon site. These F technology machineshave achieved better than 55% (gross) efficien-cy in combined-cycle operation, and the DLNsystems are currently operating between 30 and40 ppmvd NOx on gas fuel (the guarantee level

is 50 ppmvd). These units have operated formore than 250,000 hours. Four additional Ftechnology DLN-1 systems were commissionedat Scottish Hydro’s Keadby site and at NationalPower’s Little Barford site. These 9F machineshave operated more than 80,000 hours at lessthan 60 ppm NOx.

The combustion laboratory’s testing and fieldoperation have shown that the DLN-1 systemcan achieve single digit NOx and CO levels on Etechnology machines operating on gas fuel.Current DLN-1 development activity focuseson:

■ Application of single-digit technologyto the MS6001B and MS7001EAuprates.

■ Application of DLN-1 technology forretrofitting existing field machines(including MS3002s and MS5000s,some of which will require upgradebefore DLN retrofit)

■ Completing the development of steampower augmentation as needed by themarket

■ Completing the development of leanpremixed oil fuel DLN-1 products.

■ Increasing combustion inspection intervals.

■ Improving overall system reliabilityand operability for operation on oilfuel.

DLN-2 SystemAs F-technology gas turbines became availablein the late 1980s, studies were conducted toestablish what type of DLN combustor would beneeded for these new higher firing temperaturemachines. Studies concluded that that air usagein the combustor (e.g., for cooling) other thanfor mixing with fuel would have to be strictly



limited. A team of engineers from GE PowerSystems, GE Corporate Research andDevelopment and GE Aircraft Engines pro-posed a design that repackaged DLN-1 premix-ing technology but eliminated the venturi andcenterbody assemblies that require cooling air.

The resulting combustor is called DLN-2, whichis the standard system for the 6FA, 7FA, and 9FAmachines. Fourteen combustors are installed inthe 7FA, 18 in the 9FA, and six in the 6FA. Twoadditional variants of the DLN-2 system havebeen developed to meet the additional designrequirements imposed by either new machinecycles or reduced emissions levels. These com-bustors, the DLN-2.6 and the DLN-2+, will bedescribed briefly in later sections.

DLN-2 Combustion System The DLN-2 combustion system shown in Figure13 is a single-stage dual-mode combustor thatcan operate on both gaseous and liquid fuel.On gas, the combustor operates in a diffusionmode at low loads (< 50% load), and a pre-mixed mode at high loads (> 50% load). Whilethe combustor can operate in the diffusionmode across the load range, diluent injectionwould be required for NOx abatement. Oiloperation on this combustor is in the diffusionmode across the entire load range, with diluentinjection used for NOx control.

Each DLN-2 combustor system has a singleburning zone formed by the combustor linerand the face of the cap. In low emissions opera-tion, 90% of the gas fuel is injected throughradial gas injection spokes in the premixer, andcombustion air is mixed with the fuel in tubessurrounding each of the five fuel nozzles. Thepremixer tubes are part of the cap assembly.The fuel and air are thoroughly mixed, flow outof the five tubes at high velocity and enter theburning zone where lean, low-NOx combustionoccurs. The vortex breakdown from the swirlingflow exiting the premixers, along with the sud-den expansion in the liner, are mechanisms forflame stabilization. The DLN-2 fuel nozzle/pre-mixer tube arrangement is similar in designand technology to the secondary nozzle/cen-terbody of a DLN-1. Five nozzle/premixer tubeassemblies are located on the head end of thecombustor. A quaternary fuel manifold is locat-ed on the circumference of the combustion cas-ing to bring the remaining fuel flow to casinginjection pegs located radially around the cas-ing.

Figure 14 shows a cross-section of a DLN-2 fuelnozzle. As noted, the nozzle has passages for dif-fusion gas, premixed gas, oil and water. Whenmounted on the end cover, as shown in Figure15, the diffusion passages of four of the fuelnozzles are fed from a common manifold,called the primary, that is built into the endcover. The premixed passages of the same fournozzles are fed from another internal manifoldcalled the secondary. The pre-mixed passages ofthe remaining nozzle are supplied by the terti-ary fuel system; the diffusion passage of thatnozzle is always purged with compressor dis-charge air and passes no fuel.

Figure 15 shows the fuel nozzles installed on thecombustion chamber end cover and the con-nections for the primary, secondary and tertiaryfuel systems. DLN-2 fuel streams are:



Figure 13. DLN-2 combustion system

■ Primary fuel – fuel gas enteringthrough the diffusion gas holes in theswirler assembly of each of theoutboard four fuel nozzles

■ Secondary fuel – premix fuel gasentering through the gas meteringholes in the fuel gas injector spokes ofeach of the outboard four fuel nozzles

■ Tertiary fuel – premix fuel gas deliveredby the metering holes in the fuel gasinjector spokes of the inboard fuelnozzle

■ The quaternary system – injects a smallamount of fuel into the airstream justup-stream from the fuel nozzle swirlers

The DLN-2 combustion system can operate inseveral different modes.

Primary Fuel only to the primary side of the four fuelnozzles; diffusion flame. Primary mode is usedfrom ignition to 81% corrected speed.

Lean-Lean Fuel to the primary (diffusion) fuel nozzles andsingle tertiary (premixing) fuel nozzle. Thismode is used from 81% corrected speed to apre-selected combustion reference tempera-ture. The percentage of primary fuel flow ismodulated throughout the range of operationas a function of combustion reference tempera-ture. If necessary, lean-lean mode can be oper-ated throughout the entire load range of theturbine. Selecting “lean-lean base on” locks outpremix operation and enables the machine tobe taken to base load in lean-lean.

Premix Transfer Transition state between lean-lean and premixmodes. Throughout this mode, the primaryand secondary gas control valves modulate totheir final position for the next mode. The pre-mix splitter valve is also modulated to hold aconstant tertiary flow split.

Piloted Premix Fuel is directed to the primary, secondary andtertiary fuel nozzles. This mode exists whileoperating with temperature control off as anintermediate mode between lean-lean and pre-mix mode. This mode also exists as a defaultmode out of premix mode and, in the eventthat premix operating is not desired, pilotedpremix can be selected and operated to base-load. Primary, secondary and tertiary fuel splitare constant during this mode of operation.

Premix Fuel is directed to the secondary, tertiary andquaternary fuel passages and premixed flameexists in the combustor. The minimum load for



Figure 14. Cross-section of a DLN-2 fuel nozzle

Figure 15. External view of DLN-2 fuel nozzlesmounted

premixed operation is set by the combustionreference temperature and IGV position. It typ-ically ranges from 50% with inlet bleed heat onto 65% with inlet bleed heat off. Mode transi-tion from premix to piloted premix or pilotedpremix to premix, can occur whenever the com-bustion reference temperature is greater than2200 F/1204 C. Optimum emissions are gener-ated in premix mode.

Tertiary Full Speed No Load (FSNL) Initiated upon a breaker open event from anyload > 12.5%. Fuel is directed to the tertiarynozzle only and the unit operates in secondaryFSNL mode for a minimum of 20 seconds, thentransfers to lean-lean mode.

Figure 16 illustrates the fuel flow scheduling as-sociated with DLN-2 operation. Fuel staging de-pends on combustion reference temperatureand IGV temperature control operation mode.

DLN-2 Controls and Accessories The DLN-2 control system regulates the fuel dis-tribution to the primary, secondary, tertiary andquaternary fuel system. The fuel flow distribu-tion to each combustion fuel system is a func-tion of combustion reference temperature andIGV temperature control mode. Diffusion,piloted premix and premix flame are estab-lished by changing the distribution of fuel flowin the combustor. The gas fuel system (Figure

17) consists of the gas fuel stop-ratio valve, pri-mary gas control valve, secondary gas controlvalve premix splitter valve and quaternary gascontrol valve. The stop-ratio valve is designed tomaintain a predetermined pressure at the con-trol-valve inlet.

The primary, secondary and quaternary gascontrol valves regulate the desired gas fuel flowdelivered to the turbine in response to the fuelcommand from the SPEEDTRONIC™ controls.

The premix splitter valve controls the fuel flowsplit between the secondary and tertiary fuelsystem.

DLN-2 Emissions PerformanceFigures 18 and 19 show the emissions perform-ance for a DLN-2-equipped 7FA/9FA for gasfuel and for oil fuel with water injection.

DLN-2 ExperienceThe first DLN-2 systems were placed in serviceat Florida Power and Light’s Martin Station withcommissioning beginning in September 1993,and the first two (of four) 7FA units enteredcommercial service in February 1994. Duringcommissioning, quaternary fuel was added andother combustor modifications were made tocontrol dynamic pressure oscillations in thecombustor.



GT24671

Primary

Secondary

Tertiary

Quaternary

Premix ModeLean-LeanMode

PrimaryMode

235022002135

Combustion Reference Temperature

100

70

60

50

40

30

20

10

0

% o

f Bas

e Lo

ad F

uel F

low

16% Speed 1000 20 40 60 80 100

% Load Typical

Figure 16. Typical DLN-2 gas fuel split schedule

Figure 17. DLN-2 gas fuel system

After the 7FA DLN-2 entered commercial serv-ice the 9FA DLN-2 was introduced. Subsequentfleet experience indicated that to achieve ade-quate operational robustness against the entirerange of site specific events, an improvement inpremixer flashback resistance was needed.Under certain transient conditions flashbackcan occur where flame “holds” or is supportedin the recirculation zone downstream of thepremixed gas pegs. This region is not designedto withstand the abnormally high temperaturesresulting from the presence of a flame. In theevent of a flashback, the metal temperaturesincrease to unacceptable levels and hardware

damage occurs. In some cases, these eventshave caused forced outages and adverselyimpacted availability. The solution chosen wasto install full “fairings” on the downstream sideof the cylindrical fuel injection pegs.Laboratory testing and subsequent fleet experi-ence has demonstrated that full fairings arehighly effective in reducing the probability offuel nozzle flash-back. The fairings improve thepeg aerodynamics in order to reduce the size ofthe recirculation zone downstream of the pegs.The result is to significantly reduce the proba-bility of flame holding or attachment to the pre-mixed pegs. Figure 20 shows the original DLN-2fuel nozzle while Figure 21 illustrates the samenozzle with the addition of the fuel-peg fairings.

As of May 1999 there were 8 6FA, 26 7FA and 389FA units equipped with DLN-2 in commercialservice. They have accumulated more than 1.1million hours of operation.

DLN-2.6 EvolutionRegulatory pressures in the U.S. market in theearly 1990s led to the need to develop a 9 ppmcombustion system for the Frame 7FA. Theresult of this development is the DLN-2.6, whichwas first placed into service in March 1996 atPublic Service of Colorado.

Reduction of NOx levels from the DLN-2 at 25ppm to 9 ppm required that approximately 6%



Figure 20. Un-faired DLN-2 fuel nozzle

Figure 19. Distillate oil emissions with waterinjection above 50% load

Figure 18. Gas fuel emissions in diffusion andpremixed

additional air was needed to pass through thepremixers in the combustor (see Appendix fordescription of the NOx and temperature rela-tionship). This change in air splits was accom-plished through reductions in cap and linercooling air flows, requiring increased coolingeffectiveness. However, without changes in theoperation of the DLN-2 system, certain penal-ties would have been incurred for achieving 9ppm baseload performance. The turndown of aDLN-2 combustor tuned to 9/9 operation wasestimated to be about 70% load, compared to40% load for the 25/15 system. A new combus-tor configuration was conceived based on theDLN-2 burner, but overcoming these difficul-ties. The DLN-2 burner was carried forward asthe basis of the new combustor because of itsexcellent flame stabilization characteristics andthe large database of knowledge, which hadbeen accumulated on the parameters affectingcombustion dynamics.

The key feature of the new configuration is theaddition of a sixth burner located in the centerof the five existing DLN-2 burners. The pres-ence of the center nozzle enables the DLN-2.6to extend its 9/9 turndown well beyond the fivenozzle DLN-2. By fueling the center nozzle sep-arately from the outer nozzles, the fuel-air ratiocan be modulated relative to the outer nozzlesleading to approximately 200°F of turndownfrom baseload with 9 ppm NOx. Turning the

fuel down in the center burner does not resultin any additional CO generation.

Absent any other changes in the DLN-2 otherthan the addition of the center nozzle, theDLN-2.6 combustor would have required fivefuel manifolds, compared to four on the DLN-2. An alternative scheme was proposed to oper-ate the machine at startup and low load, whicheliminated diffusion mode. The result was apremixed-only combustor with 4 manifolds: 3premixed manifolds staging fuel to the sixburners, and a fourth premixed manifold forinjecting quaternary fuel for dynamics abate-ment, (See Figure 22). The first three premixedmanifolds, designated PM1, PM2, and PM3, areconfigured such that any number (1 to 6) ofburners can be operated at any time. The PM1manifold fuels the center nozzle, the PM2 man-ifold fuels the two outer nozzles located at thecross-fire tubes, and the PM3 manifold fuels theremaining three outer nozzles. The five outernozzles are identical to those used for the DLN-2, while the center nozzle is similar but with sim-plified geometry to fit within the availablespace.

With the elimination of the diffusion mode theDLN-2.6 loads and unloads very differently thanthe DLN-2. The loading and unloading strate-gies are shown in Figures 23 and 24. The addi-tional mode changes are necessary to maintainthe premixed flames within their burnablezones and so prevent combustor blowout. The



PM3

PM2

PM3

PM2

PM3

PM1

q

q

q

q

q

q

qq

qq

q

q

PM2 (2 nozzles)located at crossfire tubes PM3

(3 nozzles)

PM1(1 nozzle)

Quaternary (15 pegs)

6 Premix Burners - Five identical outerburners, one smaller center nozzle.

During different machine cycle conditions,PM1, PM2, PM3 are flowed in varyingcombinations to give low F/A.

Quaternary Pegs are locatedcircumferentially around the combustioncasing.

q

q

q

Figure 22. DLN-2.6 fuel nozzle arrangement

Fairing

~Fused Tip

Figure 21. Fully faired (flashback resistant) fuelnozzle

gas fuel control system is also changed relativeto the DLN-2. Control is accomplished with onestop ratio valve and four individual gas controlvalves, (See Figure 25). The splitter valve utilizedin both the DLN-1 and DLN-2 combustion sys-tems is eliminated.

Emissions performance of the DLN-2.6depends on the operational mode (See Figures26 and 27). As can be seen, the emissions goal

of 9 ppm NOx and CO over a 50% load rangewas met. Since its introduction in 1996 theDLN-2.6 has been installed on 8 machines andaccumulated approximately 17,000 hours ofoperation.

DLN-2+ EvolutionIn late 1996 an uprated version of the Frame9FA was introduced. Called the 9FA+e, the cyclefor this machine increased the air and fuel flowto the combustion system by approximately10%. In addition, the machine was intended foruse with gas fuels ranging in heat content from



BREAKEROPENEVENT

UNIT FLAM E-OUT

DLN-2.6TYPICALUN-LOADINGSEQUENCE

STOP

PM1+PM3

PM1+PM2

PM2+PM3+Q

PM1+PM2+PM3+Q

PM1

PM1+PM2

(FSNL operating mode)

Figure 24. DLN-2.6 unloading and fired shutdownsequence

Mode 1

Mode 3

Mode 4

Mode 5Q

Mode 6Q

1

10

100

1000

0% 50% 100%

Load (MW)

CO

(p

pm

)

Figure 27. CO level vs. percent load

GCV3 GAS CONTROL PM3

SRV SPEED/RATIO VALVE



GAS SKID

SRV

GCV4

GCV2

GCV1

GCV3

PM3 - 3 NOZ. PRE-MIX ONLY



Q - QUAT MANIFOLD, CASING, PRE-MIX ONLY

PM2

Q

6 BURNERS

TURBINE COMPARTMENT

BURNINGSINGLE

ZONE

PM1

PM3

GCV4 GAS CONTROL Quaternary

Figure 25. DLN-2.6 fuel distribution and controlssystem

Mode 1Mode 3

Mode 4

Mode 5QMode 6Q

0

20

40

60

80

0% 50% 100%% Baseload

ISO NOx

(ppm)

Figure 26. NOx at 15% O2 vs. percent load

PM1+PM2

PM1

DLN-2.6TYPICALLOADINGSEQUENCE

START

PM1+PM3

PM1+PM2

PM2+PM3+Q

PM1+PM2+PM3+Q

(firing and initial crossfire)

PM2+PM3

PM2 (Complete crossfire to 95 % speed)

(95 % speed to TTRF1 switch #1 at 10 percent load)

(TTRF1 switch #1 to #2 at 25 percent load

(TTRF1 switch #2 to #3 at 40 percent load

(TTRF1 switch #3, brief duration)

(TTRF1 switch #3 + a time delay to #4 at 45 percent load)

(Above TTRF1 switch #4 to base load)

Figure 23. DLN-2.6 ignition, crossfire, accelera-tion, and loading strategy

approximately 70–100% of natural gas whilestill maintaining low emissions.

To meet these requirements an updated versionof the DLN-2, called the DLN-2+, was devel-oped. The DLN-2+ retains the basic architec-ture of the DLN-2 with adaptations for both thenew requirements and to improve the operabil-ity and robustness of the existing system. Incomparison to the DLN-2, the major changesare concentrated in the fuel nozzle and end-cover arrangement (See Figure 28). Both theendcover and fuel nozzle have substantiallyenlarged fuel passages for the increased volu-metric flow of fuel. In addition the fuel nozzle(See Figure 29), was redesigned for furtherimprovements in flame holding margin,reduced pressure drop, and improved diffu-sion-flame stability.

flow entering the premixer, while downstreaman integral outer shroud eliminates any poten-

tial flow disturbances after the point of fuelinjection. The improvement in aerodynamicsalso reduces the overall system pressure drop tothe level required by the new cycle.

The nozzle-tip geometry and the improvementsin diffusion flame stability allow the use of a dif-fusion flame on every nozzle. This eliminatesthe lean-lean mode of the DLN-2 and results inthe simplified staging methodology shown inFigure 30.

A further simplification illustrated in Figure 30 isthe elimination of the DLN-2 Quaternary fuelsystem. This is achieved through the use of bi-radial fuel staging in each swirler vane. In thisdesign the radial fuel injection balance can beadjusted via fixed orifices on the endcover aspart of the system setup procedure.

Overall, the fuel nozzle and endcover arrange-ment of the DLN-2+ can accept fuels withWobbe Index ranging from 28 to 52. The fuel



Figure 28. Parts highly modified for DLN-2+ ascompared to DLN-2

Figure 29. DLN-2+ fuel nozzle

D5IGNITION to LOW LOAD

D5 + PM1 + PM4LOW LOAD toPREMIX TRANSFER

PM1 + PM4 PREMIX TRANSFER to BASE LOAD

D5 - Diffusion Flame on AllPM4 - Premixed Flame on “4”PM1 - Premixed Flame on “1”

PM4 PM1

D51

4

4

4

4

Load Reject to Underlined Mode

Premix Dynamics Control: PM4/PM1 Fuel Split

Figure 30. DLN-2+ staging methodology

The additional gains in flame-holding velocitymargin result from cleaner aerodynamics in thepremixers. This is achieved via a new swirlerdesign, which incorporates fuel injection direct-ly from the swirler surface. Each swirler vanecomprises a turning vane and an upstreamstraight section. The straight section is hollowand houses the fuel manifolds plus the discreteinjection holes. Upstream of the swirler an inletflow conditioner improves the character of the

delivery system is very similar to the one usedfor the DLN-2.6, with a stop ratio valve andindependent gas control valves for each of thethree gas fuel circuits.

The first installation and startup of a 9FA+e wasin early 1999 at the Sutton Bridge Power Stationin the UK. Emissions measured during thestartup were well within design goals (See Figures30 and 31). Additional machines will be com-missioned throughout 1999.

ConclusionGE’s Dry Low NOx Program continues to focuson the development of systems capable of theextremely low NOx levels required to meettoday’s regulations and to prepare for morestringent requirements in the future. New unit

production needs and the requirements ofexisting machines are being addressed. GEDLN systems are operating on more than 222machines and have accumulated more than 4.8million service hours. GE is the only manufac-turer with F technology machines operatingbelow 15 ppmvd.

Appendix

Gas Turbine Combustion Systems A gas turbine combustor mixes large quantitiesof fuel and air and burns the resulting mixture.In concept the combustor is comprised of a fuelinjector and a wall to contain the flame. Thereare three fundamental factors and practicalconcerns that complicate the design of the com-bustor: equivalence ratio, flame stability, andability to operate from ignition through fullload.

Equivalence Ratio A flame burns best when there is just enoughfuel to react with the available oxygen. With thisstoichiometric mixture (equivalence ratio of1.0) the flame temperature is the highest andthe chemical reactions are the fastest, com-pared to cases where there is either more oxy-gen (“fuel lean,” < 1.0) or less oxygen (“fuelrich,” > 1.0) for the amount of fuel present.

In a gas turbine, the maximum temperature ofthe hot gases exiting the combustor is limited bythe tolerance of the turbine nozzles and buck-ets. This temperature corresponds to an equiva-lence ratio of 0.4 to 0.5 (40% to 50% of the sto-ichiometric fuel flow). In the combustors usedon modern gas turbines, this fuel-air mixturewould be too lean for stable and efficient burn-ing. Therefore, only a portion of the compres-sor discharge air is introduced directly into thecombustor reaction zone (flame zone) to bemixed with the fuel and burned. The balance of



0

200

400

600

800

1000

1200

0 50 100 150 200 250 300

GT load (MW)

CO

(ra

w)

Figure 32. DLN-2+ combustion system NOx emissions

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

0 50 100 150 200 250 300

GT load (MW)

ISO

No

x @

15%


the airflow either quenches the flame prior tothe combustor discharge entering the turbineor cools the wall of the combustor.

Flame Stability Even with only part of the air being introducedinto the reaction zone, flow velocities in thezone are higher than the turbulent flame speedat which a flame propagates through the fuel-airmixture. Special mechanical or aerodynamicdevices must be used to stabilize the flame byproviding a low velocity region. Modern com-bustors employ a combination of swirlers andjets to achieve a good mix and to stabilize theflame.

Operational Stability The combustor must be able to ignite and tosupport acceleration and operation of the gasturbine over the entire load range of themachine. For a single-shaft generator-drivemachine, speed is constant under load and,therefore, so is the airflow for a fixed ambienttemperature. There will be a five-to-one or six-to-one turndown in fuel flow over the loadrange. A combustor whose reaction zone equiv-alence ratio is optimized for full-load operationwill be very lean at the lower loads.Nevertheless, the flame must be stable and thecombustion process must be efficient at allloads.

GE uses multiple-combustion chamber assem-blies in its heavy-duty gas turbines to achievereli-able and efficient turbine operation. Asshown in Figure A-1, each combustion chamberassembly comprises a cylindrical combustor, afuel-injection system and a transition piece thatguides the flow of the hot gas from the combus-tor to the inlet of the turbine. Figure A-2 illus-trates the multiple-combustor concept.

There are several reasons for using the multi-ple-chamber arrangement instead of large silo-type combustors:

■ The configuration permits the entireturbine to be factory assembled, testedand shipped without interimdisassembly

■ The turbine inlet temperature can bebetter controlled, thus providing forlonger turbine life with reducedturbine cooling air requirements

■ Smaller parts can be handled moreeasily during routine maintenance

■ Smaller transition pieces are lesssusceptible to damage from dynamicforces generated in the combustor;furthermore, the shorter combustionsystem length ensures that acousticnatural frequencies are higher and lesslikely to couple with the pressureoscillations in the flame



GT21897A .ppt

Figure A-1. MS7001E Dry Low NOx combustionsystem

GT18556

Figure A-2. Exploded view of combustion chamber

■ Smaller combustors generate less NOx

because of much better mixing andshorter residence time

■ As turbine inlet temperatures haveincreased to improve efficiency, thesize of the combustors has decreasedto minimize cooling requirements, asin aircraft gas turbine combustors

■ Small can-type combustors can becompletely developed in thelaboratory through a combination ofboth atmospheric and full-pressure,full-flow tests. Therefore, there is ahigher degree of confidence that acombustor will perform as designedacross all load ranges before it isinstalled and tested in a machine.

Gas Turbine EmissionsThe significant products of combustion in gasturbine emissions are:

■ Oxides of nitrogen (NO and NO2,collectively called NOx)

■ Carbon monoxide (CO)

■ Unburned hydrocarbons or UHCs(usually expressed as equivalentmethane [CH4] parti-cles and arisefrom incomplete combustion)

■ Oxides of sulfur (SO2 and SO3)particulates.

Unburned hydrocarbons include both volatileorganic compounds (VOCs), which contributeto the formation of atmospheric ozone, andcompounds, such as methane, that do not.

There are two sources of NOx emissions in theexhaust of a gas turbine. Most of the NOx is gen-erated by the fixation of atmospheric nitrogenin the flame, which is called thermal NOx.Nitrogen oxides are also generated by the con-

version of a fraction of any nitrogen chemicallybound in the fuel (called fuel-bound nitrogenor FBN). Lower-quality distillates and low-Btucoal gases from gasifiers with hot gas cleanupcarry various amounts of fuel-bound nitrogenthat must be taken into account when emissionscalculations are made. The methods describedbelow to control thermal NOx emissions areineffective in controlling the conversion of FBNto NOx.

Thermal NOx is generated by a chemical reac-tion sequence called the Zeldovich Mechanism(Reference 6). This set of well-verified chemicalreactions postulates that the generation of ther-mal NOx is an exponential function of the tem-perature of the flame and a linear function ofthe time which the hot gases are at flame tem-perature. Thus, temperature and residencetime determine thermal NOx emissions levelsand are the principal variables that a gas tur-bine designer can adjust to control emission lev-els.

For a given fuel, since the flame temperature isa unique function of the equivalence ratio, therate of NOx generation can be cast as a functionof the equivalence ratio. Figure A-3 shows thatthe highest rate of NOx production occurs at anequivalence ratio of 1.0, when the temperatureis equal to the stoichiometric, adiabatic flametemperature.

To the left of the maximum temperature point(Figure A-3), more oxygen is available (theequivalence ratio is < 1.0) and the resultingflame temperature is lower. This is a fuel-leanoperation. Since the rate of NOx formation is afunction of temperature and time, it followsthat some difference in NOx emissions can beexpected when different fuels are burned in agiven combustion system. Since distillate oil andnatural gas have approximately a 100°F/38°Cflame temperature difference, a significant dif-



ference in NOx emissions can be expected ifreaction zone equivalence ratio, water injectionrate are equal.

As shown in Figure A-3, the rate of NOx produc-tion dramatically decreases as flame tempera-ture decreases (i.e., the flame becomes fuellean). This is because of the exponential effectof temperature in the Zeldovich Mechanismand is the reason why diluent injection (usuallywater or steam) into a gas turbine combustorflame zone reduces NOx emissions. For thesame reason, very lean dry combustors can beused to control emissions. Lean, dry control isdesirable for reaching the lower NOx levels nowrequired in many applications, and also to avoidthe turbine efficiency penalty associated withdiluent injection.

There are two design challenges associated withvery lean combustors. First, care must be takento ensure that the flame is stable at the designoperating point. Second, a turndown capabilityis necessary since a gas turbine must ignite,accelerate, and operate over the load range.Both of these challenges are driven by the needto operate the combustor at low flame tempera-tures to achieve very low emissions. Thereforethe combustor operating point at full load isjust above the flame blowout point, which is thepoint at which a premixed fuel and air mixtureis unable to self sustain. At lower loads, as fuel

flow to the combustors decreases, the flametemperature will approach the blowout pointand at some point the flame will either becomeunstable or blow out. This behavior is in directcontrast to that of a diffusion flame combustor.In that type of combustor the fuel is injectedunmixed and burns at maximum flame temper-ature using only a portion of the available air.This results in high NOx emissions, but has thebenefit of very good stability because the flameburns at the same temperature independent offuel flow.

In response to these challenges, combustion sys-tem designers use staged combustors so a por-tion of the flame zone air can mix with the fuelat lower loads or during startup. The two typesof staged combustors are fuel-staged and air-staged (Figure A-4). In its simplest and mostcommon configuration, a fuel-staged combus-tor has two flame zones; each receives a con-stant fraction of the combustor airflow. Fuelflow is divided between the two zones so that ateach machine operating condition, the amountof fuel fed to a stage matches the amount of airavailable. An air-staged combustor uses a mech-anism for diverting a fraction of the airflowfrom the flame zone to the dilution zone at low



PrimaryStage

SecondaryStage

DilutionZone

DilutionZone

Primary Stage

Figure A-4. Staged combustors

Figure A-3. NOx production rate

load to increase turndown. These methods canbe combined, but both work to achieve thesame objective, to maintain a stable flame tem-perature just above the blowout point.

Emissions Control MethodsThere are three principal methods for control-ling gas turbine emissions:

■ Injection of a diluent such as water orsteam into the burning zone of aconventional (diffusion flame)combustor

■ Catalytic clean-up of NOx and COfrom the gas turbine exhaust (usuallyused in conjunction with the other twomethods)

■ Design of the combustor to limit theformation of pollutants in the burningzone by utilizing “lean-premixed”combustion technology

The last method includes both DLN combus-tors and catalytic combustors. GE has consider-able experience with each of these three meth-ods.

Since September 1979, when regulationsrequired that NOx emissions be limited to 75ppmvd (parts per million by volume, dry),more than 300 GE heavy-duty gas turbines haveaccumulated more than 2.5 million operatinghours using either steam or water-injection tomeet required NOx emissions levels, sometimesproducing levels even lower than required. Theamount of water required to accomplish this isapproximately one-half of the fuel flow.However, there is a 1.8% heat rate penalty asso-ciated with using water to control NOx emis-sions for oil-fired simple-cycle gas turbines.Output increases by approximately 3%, makingwater (or steam) injection for power augmenta-tion economically attractive in some circum-

stances (such as peaking applications).

Single-nozzle combustors that use water orsteam injection are limited in their ability toreduce NOx levels below 42 ppmvd on gas fueland 65 ppmvd on oil fuel. GE developed multi-nozzle quiet combustors (MNQC) for theMS7001EA and MS7001FA capable of achieving25 ppmvd on gas fuel and 42 ppmvd on oil,using either water or steam injection. SinceOctober 1987, more than 26 MNQC-equippedMS7001s that use water or steam injection havebeen placed in service. One unit that uses steaminjection has operated nearly 50,000 hours at 25ppmvd NOx (at 15% O2).

Frequent combustion inspections anddecreased hardware life are undesirable sideeffects that can result from the use of diluentinjection to reduce NOx emissions from com-bustion turbines. For applications that requireNOx emissions below 42 ppmvd (or 25 ppmvdin the case of the MS7001EA or MS7001FAMNQC), or to avoid the significant cycle effi-ciency penalties incurred when water or steaminjection is used for NOx control, one of theother two principal methods of NOx controlmentioned above must be used.

Selective catalytic reduction (SCR) converts NOand NO2 in the gas turbine exhaust stream tomolecular nitrogen and oxygen by reacting theNOx with ammonia in the presence of a catalyst.Conventional SCR technology requires that thetemperature of the exhaust stream remain in anarrow range (550°F to 750°F or 288°C to399°C) and is restricted to applications with aheat recovery system installed in the exhaust.The SCR is installed at a location in the boilerwhere the exhaust gas temperature hasdecreased to the above temperature range. Newhigh-temperature SCR technology is beingdeveloped that may allow SCRs to be used forapplications without heat recovery boilers.



For an MS7001EA gas turbine, an SCR designedto remove 90% of the NOx from the gas turbineexhaust stream has a volume of approximately175 cubic meters and weighs 111 tons. It is com-prised of segments stacked in the exhaust duct.Each segment has a honeycomb pattern withpassages that are aligned in the direction of theexhaust gas flow. A catalyst, such as vanadiumpentoxide, is deposited on the surface of thehoneycomb.

SCR systems are sensitive to fuels containingmore than 1,000 ppm of sulfur (light distillateoils may have up to 0.8% sulfur). There are tworeasons for this sensitivity.

First, sulfur poisons the catalyst being used inSCRs. Second, the ammonia will react with sul-fur in the presence of the catalyst to formammonium bisulfate, which is extremely corro-sive, particularly near the discharge of a heatrecovery boiler. Special catalyst materials thatare less sensitive to sulfur have been identified,and there are some theories as to how to inhib-it the formation of ammonium bisulfate. This,however, remains an open issue with SCRs.

More than 100 GE units have accumulatedmore than 100,000 operating hours with SCRsinstalled. Twenty of the units are in Japan; oth-ers are located in California, New Jersey, NewYork and several other eastern U.S. states. Unitsoperating with SCRs include MS9000s,MS7000s, MS6000s, LM2500s and LM5000s.

Lean premixed combustion is the basis forachieving low emissions from Dry Low NOx andcatalytic combustors. GE has participated in thedevelopment of catalytic combustors for manyyears. These systems use a catalytic reactor bedmounted within the combustor to burn a verylean fuel-air mixture. They have the potential toachieve extremely low emissions levels withoutresorting to exhaust gas cleanup. Technicalchallenges in the combustor and in the catalystand reactor bed materials must be overcome in

order to develop an operational catalytic com-bustor. GE has development programs in placewith both ceramic and catalyst manufacturers toaddress these challenges.

References1. Washam, R. M., “Dry Low NOx

Combustion System for Utility GasTurbine,” ASME Paper 83-JPGC-GT-13,Sept. 1983.

2. Davis, L. B. and Washam, R. M., “Develop-ment of a Dry Low NOx Combustor,”ASME Paper No. 89-GT-255, June 1989.

3. Dibelius, N.R., Hilt, M.B., and Johnson,R.H., “Reduction of Nitrogen Oxides fromGas Turbines by Steam Injection,” ASMEPaper No. 71-GT-58, Dec. 1970.

4. Miller, H. E., “Development of the QuietCombustor and Other Design Changes toBenefit Air Quality,” AmericanCogeneration Association, San Francisco,March 1988.

5. Cutrone, M. B., Hilt, M. B., Goyal, A.,Ekstedt, E. E., and Notardonato, J.,“Evaluation of Advanced Combustor forDry NOx Suppression with NitrogenBearing Fuels in Utility and Industrial GasTurbines,” ASME Paper 81-GT-125, March1981.

6. Zeldovich, J., “The Oxidation of Nitrogenin Combustion and Explosions,” Acta Phys-icochimica USSR, Vol. 21, No. 4, 1946, pp577-628.

7. Washam, R. M., “Dry Low NOx

Combustion System for Utility GasTurbine,” ASME Paper 83-JPGC-GT-13,Sept. 1983.

8. Davis, L. B., and Washam, R. M., “Develop-ment of a Dry Low NOx Combustor,”ASME Paper No. 89-GT-255, June 1989.



List of FiguresFigure 1. Dry Low NOx product plan

Figure 2. DLN power augmentation summary

Figure 3. DLN peak firing emissions - natural gas fuel

Figure 4. DLN technology - a four sided box

Figure 5. Dry Low NOx combustor

Figure 6. Fuel-staged Dry Low NOx operating modes

Figure 7. Typical DLN-1 fuel gas split schedule

Figure 8. Dry low NOx gas fuel system

Figure 9. MS7001EA/MS9001E emissions - natural gas fuel

Figure 10. MS6001B emissions - natural gas

Figure 11. MS7001EA Dry Low NOx combustion system performance on distillate oil

Figure 12. MS6001B emissions distillate oil fuel

Figure 13. DLN-2 combustion system

Figure 14. Cross-section of a DLN-2 fuel nozzle

Figure 15. External view of DLN-2 fuel nozzles mounted

Figure 16. Typical DLN-2 gas fuel split schedule

Figure 17. DLN-2 gas fuel system

Figure 18. Gas fuel emissions in diffusion and premixed

Figure 19. Distillate oil emissions with water injection above 50% load

Figure 20. Un-faired fuel nozzle

Figure 21. Fully faired (flashback resistant) fuel nozzle

Figure 22. DLN-2.6 fuel nozzle arrangement

Figure 23. DLN-2.6 ignition, crossfire, acceleration, and loading strategy

Figure 24. DLN-2.6 unloading and fired shutdown sequence

Figure 25. DLN-2.6 fuel distribution and controls system

Figure 26. NOx at 15% O2 vs. percent load

Figure 27. CO level vs. percent load

Figure 28. Parts highly modified for DLN-2+ as compared to DLN-2

Figure 29. DLN-2+ fuel nozzle

Figure 30. DLN-2+ staging methodology



Figure A-1. MS7001E Dry Low NOx combustion system

Figure A-2. Exploded view of combustion chamber

Figure A-3. NOx production rate

Figure A-4. Staged combustors



dry low nox combustion for gas turbines

Documents