Nox emission control in gas turbines for combined cycle gas ...

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Nox emission control in gas turbines for combinedcycle gas turbine plant

M J MooreConsultant, Guildford, Surrey

Abstract: The increase, in recent years, in the size and efficiency of gas turbines burning natural gas in com-bined cycle has occurred against a background of tightening environmental legislation on the emission ofnitrogen oxides. The higher turbine entry temperatures required for efficiency improvement tend to increaseNOx production. First-generation emission control systems involved water injection and catalytic reductionand were relatively expensive to operate. Dry low-NOx combustion systems have therefore been developedbut demand more primary air for combustion. This gives added incentive to the reduction of air requirementsfor cooling the combustor and turbine blading. This paper reviews the various approaches adopted by themain gas turbine manufacturers which are achieving very low levels of NOx emission from natural gas com-bustion. Further developments, however, are necessary for liquid fuels.

Keywords: gas turbines, combustion, combined cycles, environment, nitrogen oxides, BATNEEC

1 INTRODUCTION

It was a fortunate coincidence for the United Kingdom thattightening European Community regulations on sulphuremissions from power plant coincided with the increasedavailability of natural gas at economic prices. Revised leg-islation allowing the use of gas for electricity generation andthe discouragement of oilfield exploitation without gasrecovery has led in the United Kingdom to the so-called‘dash for gas’. Natural gas contains very little sulphur andwhat is present can be relatively easily removed. Corrosivealkali metal salts are also absent, making natural gas anideal fuel for high-temperature gas turbines. Incorporatedin combined cycle—the so-called combined cycle gas tur-bine (CCGT) plant—this new breed of industrial gas turbinesenables cycle thermal efficiencies approaching 60 per cent(LCV) to be obtained, well in excess of open cycle gas tur-bine or Rankine-based steam plant. Similarly, gas turbineunit size has increased remarkably from 20 to 250MWover the past 20 years. However, higher turbine entrytemperature, a prime factor in increased efficiency, tendsto increase the rate of formation of oxides of nitrogen andspecial measures have been introduced by the gas turbinedesigners to counteract this effect. This paper presents abrief history of such developments and the approachescurrently being adopted by the main engine manufacturers.

2 ENVIRONMENTAL LEGISLATION

Complex interactions of nitrogen oxides with reactivehydrocarbons and sunlight produce low-level ozone, acidrain and smog and legislation reflects the view that anyemission of NOx is to be avoided or minimized. Emissionlimits imposed by power plant licensing authorities differin different countries but loosely reflect the current levelof abatement technology—although it could be arguedthat the legislation drives the technology where, for exam-ple, tough prescriptive limits are imposed. While some 95per cent of the NOx emitted is in the form of nitric oxide(NO), emission limits are defined as the quantity of nitrogendioxide equivalent, as the NO is ultimately converted toNO2 in the atmosphere. Monitoring instruments generallymeasure NO using chemiluminescent techniques and theequivalent NO2 is calculated. Emission is expressed in var-ious units (mg/m3, mg/MJ, ppm, ppmv) as the quantity ofNO2 in dry air at 1 atmosphere pressure (1.013 bar) and0 �C. It is also customary to refer the data to air containing15 per cent oxygen. In this review emission limits areexpressed as ppm, at 15 per cent dry O2.For new plant (or plant undergoing substantial upgrading)

permissible emissions of NOx have decreased significantlyin recent years. The current guidance in the United Kingdom(1) advises that emissions of NOx for gas turbines individu-ally of 50MW or more net rated thermal input should notat any time exceed:

Gaseous fuels: 60mg/m3 (50mg/MJ)—approximately 50 ppm

A00996 � IMechE 1997 Proc Instn Mech Engrs Vol 211 Part A

The MS was received on 4 April 1996 and was accepted for publication on27 August 1996.

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Liquid fuels: 125mg/m3 (105mg/MJ)—approximately 100 ppm

and emissions under steady conditions should be colourless.(If NO2 > 15 ppm in the exhaust gases, which can occur atlow exhaust gas temperatures, a yellow plume is produced.)Further examples of current limits [from reference (2)]

are listed in Table 1 for large plant (>100MWth). Themost severe limitations are in place in Southern Californiaand in certain areas of Germany and Japan.

3 NOx FORMATION IN GAS TURBINES

Combustion in gas turbines has traditionally employed adiffusion flame where fuel is sprayed into the centre of anair stream. Fuel mixes with the air by turbulent diffusionand the flame front can be considered the locus of thestoichiometric mixture where temperatures reach approxi-mately 2000 �C. The hot combustion products are cooledby dilution with excess air to temperatures acceptable tothe combustor walls and turbine blading.The combustion process consists of three phases, the

endothermic dissociation of the fuel molecules, followedby a fast, exothermic formation of CO and H2O, and finallythe slower, exothermic oxidation of CO to CO2. Some 80per cent of the energy is released in the second phase duringthe formation of CO. The slower burn-out to CO2 canrequire 75 per cent of the combustion zone length.Nitrogen oxides are formed at high temperature by the

dissociation of the O2 molecule and the action of the Oradical on molecules of nitrogen. Zeldovich (3) showedthat, at temperatures above 1500 �C, NOx was formedfrom nitrogen in the atmospheric air taking part in thecombustion process, the product being denoted ThermalNOx. This product is approximately 95 per cent NO, withNO2 making up the balance plus a small amount of N2O.The main reactions are

O2 → Oþ O

N2 þ O→ NOþ N

Nþ O2 → NOþ O

The rate of formation of NO has been determined

theoretically (4) and is described by

½NOÿ ¼ K1 expð¹K2=TÞ½N2ÿ½O2ÿ0:5t ð1Þ

The quantity of NO formed is an exponential function oftemperature and is proportional to the concentration of N2,the square root of O2 concentration and the residencetime, t, at the high temperature. The reduction in tempera-ture emerges as the main strategy for controlling thermalNOx emissions from gas turbines.The other NOx-producing mechanisms are so-called Fuel-

NOx and Prompt-NOx. The former results from reactionswith nitrogen present in the fuel—a significant componentin coal and, to a small extent, in liquid fuels but not presentin natural gas. Prompt-NOx (5) is formed very briefly duringthe combustion process by the interaction of CH radicals onN2, the quantity of NO produced in this manner being alsorelatively small.

4 HISTORICAL BACKGROUND

4.1 Combustor arrangement

The gas turbine was developed primarily for aircraft propul-sion where its light weight, inherent reliability and highthrust are distinct advantages. The jet engine burns distillatefuels, the potential pollutants being CO, SO2, NOx, UHCs(unburnt hydrocarbons) and even soot (as well as, of course,CO2).Diffusion flames are employed for stability and short

combustion chambers are incorporated to minimize engineweight and shaft length. Such engines tend to producerelatively large quantities of NOx and CO. Industrial gas tur-bines, relieved of weight restrictions, initially incorporatedlarge external (silo) combustors in order to ensure efficientburn-out (e.g. see Fig. 1). Typically emission levels of CO <

10 ppm were achieved and UHC emission was undetectable.The initial use of diffusion burners, however, did little tocontain NOx production. While satisfactory at turbine entrytemperatures of around 1000 �C, at the higher temperaturesof modern machines the large silo combustors tended torequire too much cooling air and at part-load the large areasof cool surface adversely affected burn-out. Long residencetimes also increased NOx production. For this and for otherstructural reasons the trend has therefore been to adoptsmaller multiple chambers in annular arrangement. (Onemanufacturer, GE (see Section 5.3), has always incorporatedthis arrangement.)

4.2 Water or steam injection

The first attempts to reduce NOx introduced a heat sink inthe flame by injecting water, with the aim of reducing aver-age combustion temperature and hence thermal NOx pro-duction. This had the added advantage of boosting gas

A00996 � IMechE 1997Proc Instn Mech Engrs Vol 211 Part A

Table 1 Some national NOx emission limits (ppm, 15 percent dry O2Þ

General

Gas Oil Local CO

Germany 50 75 <50 80Netherlands 37 37 — —United States 75 75 9 8Japan 73 73 9 8

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turbine output by increasing the mass flow of gas throughthe turbine, but gains were offset by the extra fuel requiredto heat the water to the temperature of the burning mixture.With water/fuel mass flow ratios in the range 1–2, the rateof NOx formation could be reduced by an order of magni-tude (Fig. 2). However, the process required large quantitiesof clean water—to at least boiler feedwater standard—toavoid corrosion of the turbine blading or deposition andblocking of cooling air holes by impurities. Particularlywith water injection, there was also an increase in levelsof pressure fluctuations associated with combustion. Suchdynamic pressures can excite acoustic resonance whichmay shorten combustor can life. Steam injection, whilelacking the cooling effect of water evaporation, can never-theless give better mixing and lower dynamic pressurelevels than water injection and can be incorporatedrelatively simply in a gas and steam combined cycle.Steam/water injection is still offered by manufacturers for

liquid fuel or dual-fuel firing and, at modern turbine entrytemperatures and pressures, can achieve typical NOx out-puts as shown in Table 2.

4.3 Selective catalytic reduction

Where local regulations required lower emission levels,selective catalytic reduction (SCR) systems were installed.Ammonium hydroxide solution sprayed over a mesh con-taining titanium and vanadium oxide catalysts reacts withthe NOx to form nitrogen and water. The reaction rate maxi-mizes at around 350 �C, necessitating the positioning of theSCR unit between the evaporator and economizer sectionsof the heat recovery steam generator (HRSG). Such systems


Fig. 1 Example of silo combustor on ABB GT13E. (Courtesy of ABB Power Generation)

Table 2 Approximate levels of NOx emission achieved bywater or steam injection—diffusion flame (NOxexpressed as ppm on 15 per cent O2, dry basis)

WithWithoutinjection Water Steam

Distillate fuels 200 40 50Natural gas 150 30 35

45NO�EMISSION CONTROL IN GAS TURBINES FOR CCGT PLANT



were relatively expensive to install and maintain but, com-bined with water injection, could reduce NOx emissions toless than 10 ppm.

4.4 The evolution of dry low-NOx systems

The high costs of the above systems provided the incentiveto explore the use of non-stoichiometric mixtures to reduceflame temperature in so-called dry low-NOx (DLN) systems.If fuel and air are mixed before combustion in a so-called

pre-mix flame, the combustion temperature, and thereforethe NOx formed, is a strong function of the fuel–air ratio,as shown diagrammatically in Fig. 3. By using a lean fuel/air mixture the rate of NOx formation can be significantlyreduced.In comparison, only at fuel-rich conditions does a diffu-

sion flame give low NOx. Fuel-rich combustion has atten-dant problems of cooling the combustor can withoutdiluting the fuel/air mixture and presents the possibility ofincomplete burn-out. Early attempts to reduce NOxemployed fuel or air staging in which, following an initial


Fig. 2 Effect of water/steam injection on the rate of NOx production [from reference (2)]

Fig. 3 NOx production from diffusion and pre-mix flames

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combustion, further air and/or fuel is added, followed bydilution air. Such systems could be rich/lean or lean/leanin sequence.For natural gas fuel the commonly adopted strategy is to

employ DLN burners incorporating lean, pre-mix flames.The main problems associated with lean pre-mix flamesare their stability, their fuel inflexibility and the limitedturn-down range. To minimize flame temperature and henceNOx production the fuel/air mixture is weakened to as nearthe extinction point as can safely be realized. Thoroughmixing is also essential to avoid unsteady combustion andeven flashback with subsequent burner damage. To stabilizethe flame, it is common practice to use a hybrid system inwhich the bulk of the fuel is burned in a pre-mix burner,the remainder being supplied to a small pilot diffusion flameembedded in the flow. Even so, operation is limited to anarrow range of fuel/air mixtures between the productionof excessive NOx and excessive CO (Fig. 4). Careful devel-opment of combustor geometry and control system is there-fore required.Stable turn-down is generally achieved by incorporating

multiple burners in the combustor which can be turned offsystematically, maintaining a uniform temperature profileinto the turbine. In CCGT plant the compressor air flowrateis reduced at part load using variable inlet guide vanes,enabling the gas temperature at entry to the HRSG to bemaintained down to typically 50 per cent load.The current development problem for DLN burners as

turbine entry temperatures increase is to provide the neces-sarily large quantity of air for lean pre-mix combustionwhile maintaining adequate cooling of engine hot partswithout reducing efficiency by extracting too much coolingair from the compressor. The next section summarizesbriefly the range of designs of the world’s main industrialGT (gas turbine) manufacturers and their claimedperformance.

In comparing gas turbine entry temperature (TET) it maybe noted that the manufacturers define TET in slightlydifferent ways. Japanese manufacturers tend to quote thetemperature at entry to the first fixed blades. US practiceis to use the temperature downstream of the first fixed bladesafter mixing with readmitted cooling air. Siemens, on theother hand, use the ISO 2314 value calculated from the com-bustion of full-load fuel flow with the total compressorflow. Thus, for the same engine, the above definitionsmay, for example, give TETs of 1280, 1230 and 1130 �Crespectively.

5 THE STATE OF THE ART

5.1 Mitsubishi Heavy Industries (MHI)

According to reference (6), MHI introduced the world’s firstoperational DLN combustor in their 1450K Class gas tur-bine at Tohoku Electric Company’s Higashi Niigata PowerStation in 1984. Denoted DLN1, the combustor used ahybrid burner with an air bypass arrangement for part load-ing. NOx levels at gas turbine exit were some 75 ppm, redu-cing to less than 10 ppm after the SCR system was installedin the HRSG.The DLN1 combustor incorporated a double chamber

for pilot and main burners in an annular arrangement. Thecombustor liner had a conventional film cooling system.However, for higher temperature engines, the air require-ment for lean pre-mix burners and film cooling is excessive.The next development, DLN2, in 1992, therefore employeda single chamber to reduce cooled surface area (Fig. 5). Italso incorporated advanced types of liner cooling, knownas PLATEFIN and MTFIN (Fig. 6). DLN2 also has a multi-nozzle system allowing dual-fuel operation. NOx levels of25 ppm have been achieved on the MHI 1600K Class ‘F’engine using DLN2 (Fig. 7).The incentive to reduce the quantity of cooling air has led

to the development of the DLN3 combustor incorporatingthe MTFIN liner cooling system. Target NOx levels are9 ppm for the F engine and 25 ppm for the 1750K G engine.Liner cooling is by air in the F engine but by steam in the Gengine. The latter acts as a superheater in the CCGT steambottoming cycle. DLN3 is at present undergoing laboratorytests.The next development, DLN4, has a target of 9 ppm for

the G engine. Areas receiving attention are the achievementof complete pre-mixing and minimization of boundary layersto reduce the potential flashback path and to minimizeunsteady combustion.

5.2 ABB Power Generation

Early ABB industrial gas turbines incorporated a single,diffusion burner in a silo combustor, suitable for oil orgas firing and using water injection where NOx limiting


Fig. 4 Operating range of pre-mix flames. (Courtesy ofSiemens AG)




legislation dictated. However, the perceived advantages ofDLN systems led to the development of a first-generation,lean, pre-mix burner which entered commercial operationin 1984 in a type GT13 machine. Burner design consistedof a long mixing tube in which air and gaseous fuel werepre-mixed, followed by a swirler and diffusion flame nozzleto stabilize the flame. By using multiple small burners,flame length—and hence residence time—was reducedand part-load performance achieved by burner staging. As

many as 36 burners were mounted in the single silo combus-tor and achieved NOx emissions of 40–60 ppm.To meet tighter emission standards, in 1987 ABB began

research on their second-generation system and producedthe environmental (EV) burner. The burner consists of anaxially split diffusing cone, the two halves offset to formtangential slots (see Fig. 8). Combustion air is fed throughthe slots forming a powerful vortex in the cone. Gas is injectedinto the vortex via small holes at the edges of the slots.


Fig. 5 MHI DLN2 combustor

Fig. 6 MHI combustor cooling systems

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(Liquid fuel can be sprayed into the burner via a nozzle atthe cone apex.) Pre-mixing in the cone is followed by com-bustion at exit where the vortex breaks down, allowingrecirculation and flame stabilization. As the flame is outsidethe burner, the burner structure remains relatively cool. Theburner is guaranteed by ABB to give less than 25 ppm NOxwith natural gas and 42 ppm with oil firing and water injec-tion (7). The EV burner was first used commercially in 1987in the Midlands power plant in the United States.As many as 54 EV burners were initially introduced into

each silo combustor. However, as with other GT manufac-turers, ABB have moved away from silo arrangementsand have developed an annular combustor, shown diagram-matically in Fig. 9. In the GT13E2, 72 EV burners arearranged in rings around the annulus, enabling the opera-tional load range to be achieved by burner group staging.In the latest GT design, the GT24/GT26, ABB have

introduced sequential combustion. The first combustion pro-cess is performed using multiple EV burners in an annulararrangement, the hot gases passing to the HP turbine stage.A further, spontaneous combustion downstream of thisstage is achieved by injecting fuel into a sequential EVburner also designed on the vortex breakdown principle.Vortices are produced by delta ‘wings’ on the sides of thecombustor segments and secondary air maintains a leanmixture. ABB claim that the uniformity of temperature ofthe lean mixture results in practically no NOx being pro-duced in the second combustion. The first GT24 wasfired-up in September 1995 at Gilbert Power Station, NewJersey.Also noted is the claim that the EV burner system enables

surrounding metalwork to be cooled by conventional con-vection cooling. The introduction of more sophisticatedfilm cooling systems is therefore avoided.


Fig. 8 ABB EV cone burner

Fig. 7 NOx emissions from MHI DLN2 combustor




5.3 GE power systems

The first DLN system developed by GE was tested at Hous-ton Lighting and Power in 1980 and met the EPA emissiongoals at that time of 75 ppmv NOx. Subsequent develop-ments have led to the present combustor designs, designatedDLN-1 and DLN-2. Both are based on the lean pre-mixprinciple but differ in detailed geometry.The DLN-1 design incorporates a complex fuel-staging

process to reach full load as shown in Fig. 10. At full loadthe primary nozzles provide a lean pre-mixed gas/air mix-ture to the flame burning at the outlet to the secondary noz-zle. Recirculation after a venturi stabilizes the flame anddilution air is added downstream. For low NOx productionthe primary fuel/air mixture is very lean so, for stable and

efficient combustion, a pilot flame and various geometricarrangements are employed to maintain ignition of themain mixture. The combustor can be dual fuelled but, forliquid fuel, a diffusion flame is employed with water injec-tion. On natural gas GE claim full-load emissions of as lowas 9 ppm NOx (at 25 ppm CO) for ‘E’ technology engines(TET ¼ 1100 �C) and for ‘F’ engines (TET ¼ 1316 �C)between 30 and 60 ppm NOx (8).At the higher temperatures of the ‘F’ engines and sub-

sequent technologies it was realized that a combustorrequiring less cooling air was required if engine efficiencywas not to be compromised. The new design, DLN-2(Fig. 11), was developed without the centre body andventuri of DLN-1, so saving the cooling air needed for thesecomponents. DLN-2 is a single-stage, dual-fuelled design


Fig. 9 Annular combustor of ABB GT 13E2

Fig. 10 GE DLN-1 combustor operating sequence

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incorporating five mixer nozzles. The lean mixture fromthe nozzles is swirled into the combustion chamber wherevortex breakdown and recirculation stabilizes the flame.The first DLN-2 combustor was operated commercially inFlorida P&L Martin Station in 1994 and achieved< 25 ppm NOx and 15 ppm CO.

5.4 Siemens AG

Multiple-burner systems have been employed by Siemensin their silo combustors and in the annular combustordesigns introduced in 1994. Typically six or eight burnersare fitted to silos for V84 and V94 engines and 24 to theV84 annular combustor. The burners are based on the‘hybrid’ arrangement developed in the mid-1980s andshown schematically in Fig. 12. Diffusion flames areused for start-up and low load, switching to lean, pre-mix flames at higher loads, giving the NOx emission per-formance shown in Fig. 13 for the V84.3A currently underfull-size testing in Berlin.Improvements have been made to the pre-mix swirler

and gas injection system to improve mixing. With the lat-est version of the hybrid burner, HR-3, Siemens guaranteeless than 25 ppm NOx at full load with natural gas (9).The combustors also burn liquid fuels by diffusion flame

with water injection, reducing NOx to 50 ppm. A dry pre-mix version for liquid fuels was tested in a V94.2 engineat Halmstad in 1993 and gave NOx < 90 ppm and CO < 10ppm at a TET of 1060 �C ISO.Cooling air requirements are claimed to be reduced by the

Siemens practice of lining the combustion chamber withceramic tiles.

5.5 Aero-derivatives

Aero-engine manufacturers have traditionally produced


Fig. 12 Siemens hybrid burner

Fig. 13 NOx emissions from Siemens V84.3A engine

Fig. 11 GE DLN-2 combustor




selected versions of jet enginesmodified for peak-power gen-eration. The longer operating life and higher temperaturesavailable from natural gas combustion has reawakened inter-est in this niche market, the large aero-derivatives even beingconsidered for combined cycle application. Notable exam-ples are the GE LM6000 and the Rolls-Royce RB211 andTrent gas turbines. Low NOx combustors for natural gashave been designed for these engines based on the pre-mixlean flame principle for reducing flame temperature.The LM6000 employs an annual combustor fed by three

rings of pre-mixing nozzles and an enlarged reaction cham-ber to increase residence time for improved burn-out. Ontest, emissions were less than 15 ppm NOx, 10 ppm COand 2 ppm UHC at a turbine entry temperature at 1288 �C.Guarantee figures are 25 ppm NOx with natural gas and42 ppm with liquid fuel plus water injection (10).The Trent DLN combustor consists of a series of ‘pots’

around the machine periphery. The emission guarantee is25 ppmv NOx, but development targets are 9 ppm NOx onnatural gas and 42 ppmv on liquid fuels using water injec-tion (11). These figures may be compared with the aero-engine version of the RB211 which produces some200 ppmv NOx and 80 ppmv CO.

6 FUTURE DEVELOPMENTS

The principle of application of best available techniques notentailing excessive costs (BATNEEC) adopted by EC envir-onmental control agencies suggests that the general require-ment for new plant may, in due course, reflect the low levelsof NOx emission (< 9 ppm), shown to be achievable usingDLN systems with natural gas fuels. Limits for liquid fuelswill also probably be revised downwards, particularly asdual fuelling is used to obviate difficulties arising frominterruptible gas supply contracts.For gas firing, manufacturers generally expect that further

attention to pre-mixing will enable future DLN systems tomeet the 9 ppm limits with improved stability and reducedCO emission. However, applying the same techniques toliquid fuels systems is inherently more difficult. Pre-mixingis compromised by the time taken for fuel droplets to evapo-rate and the tendency for pre-ignition and flashback to occur.Problems of incomplete burn-out and carbon residue depositshave also been experienced. Air blast fuel atomizers are a pos-sible option but represent additional energy consumption.Catalytic combustion is also being considered, but feasibilityhas yet to be established. DLN liquid fuel combustionremains, therefore, a challenge to gas turbine manufacturers.

7 CONCLUSIONS

Gas turbine manufacturers have successfully developed drylow NOx combustion systems for natural gas firing whichmeet current environmental requirements. Various combus-tor geometries and control strategies are employed but allare based on the principle of reducing flame temperature

to as near turbine entry temperature as possible by burninga pre-mixed lean mixture of gas and air. Refinement of DLNcombustor designs should enable NOx emissions of < 9 ppmto be achieved at the current TETs of 1260 �C.However, pre-mix flames require large quantities of

combustion air, making less air available for cooling ofcombustion chamber walls, turbine blading, etc. Manufac-turers are therefore developing alternative approachessuch as improved cooling heat transfer systems, steamcooling or sequential combustion to achieve increasedCCGT efficiency.Achievement of low NOx with liquid fuels has proved

more difficult and currently relies upon relatively expensivewater injection to achieve emissions of < 50 ppm. Dual fuel-ling is an important requirement for many operators and theDLN combustor for liquid fuels is a development goal forgas turbine designers.

REFERENCES

1 HMIP Chief Inspector’s Guidance to Inspectors, Process Gui-dance Note IPR1/2 (Revised 1994), Combustion Processes—Gas Turbines.

2 Schetter, B. Gas turbine combustion and emission control.VKI Lecture Series 1993–08 on Combined Cycles for PowerPlants, 5–9 July 1993.

3 Zeldovich, Ya. B. The oxidation of nitrogen in combustionand explosions. Acta Physicochimica USSR, 1946, 21, 577–628.

4 MacKinnon, D. J. Nitric oxide formation at high temperature.Air Pollution Control Ass. J., March 1974, 24(3), 237–239.

5 Fenimore, C. P. Formation of nitric oxide from fuel nitrogenin ethylene flames. Combustion and Flame, October 1972,19(2), 289–296.

6 Mandai, S. Methods of NOx reduction in MHI gas turbines. InIMechE Seminar on Best Technology for NOx EmissionControl, London, 27 September 1995.

7 Hellat, J. NOx control in CCGT plant. In IMechE Seminar onBest Technology for NOx Emission Control, London, 27September 1995.

8 Berkley Davis, L. Dry low NOx combustion systems for GEheavy-duty gas turbines. In IMechE Seminar on Best Tech-nology for NOx Emission Control, London, 27 September1995.

9 Huth, M., Hoffmann, S. and Scheffer, B. NOx emission con-trol with the Siemens dry low NOx hybrid burner. In IMechESeminar on Best Technology for NOx Emission Control,London, 27 September 1995.

10 Davidson, J. and Leonard, G. DLE combustor exceeds per-formance guarantees. Modern Power Systems, May 1995.

11 Toon, I. Dry low emissions technology for industrial aero-derivative gas turbines. In IMechE Seminar on Best Technologyfor NOx Emission Control, London, 27 September 1995.

BACKGROUND READING

Boyce, M. P. Gas Turbine Engineering Handbook, 1982 (Gulf).Lefebvre, A. H. Gas Turbine Combustion, 1983 (Taylor and

Francis, London).


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