Arnold Schwarzenegger 

Governor

HIGH-EFFICIENCY, ULTRA-LOW 

OXIDES OF NITROGEN 

SUPPLEMENTAL FIRING BURNER 

PIER FINAL PROJECT REPORT 

Prepared For: 

California Energy Commission 

Public Interest Energy Research Program 

Prepared By:

February 2011

CEC-500-2010-044

Prepared By: 

ALZETA Corporation 

John D. Sullivan, Project Manager 

Robert Nickeson, Project Engineer 

Jim Gotterba, Business Development Manager 

Santa Clara, CA 

Commission Contract No. 500-03-040 

Prepared For:

Public Interest Energy Research (PIER) 

California Energy Commission 

Michael Langley 

Contract Manager 

Avtar Bining, Ph.D. 

Program Area Lead 

Environmentally Preferred Advanced Generation 

Kenneth Koyama 

Office Manager 

Energy Generation Research Office 

Laurie ten Hope 

Deputy Director 

ENERGY RESEARCH AND DEVELOPMENT DIVISION 

Melissa Jones 

Executive Director 

DISCLAIMER 

This report was prepared as the result of work sponsored by the California Energy Commission. It does not necessarily represent the views of the 

Energy Commission, its employees or the State of California. The Energy Commission, the State of California, its employees, contractors and 

subcontractors make no warrant, express or implied, and assume no legal liability for the information in this report; nor does any party represent 

that the uses of this information will not infringe upon privately owned rights. This report has not been approved or disapproved by the California 

Energy Commission nor has the California Energy Commission passed upon the accuracy or adequacy of the information in this report. 

Acknowledgements 

ALZETA Corporation wishes to express its thanks to the following team members for their

contributions to this work:

Henry Mak, Sempra Energy / Southern California Gas (SCG)

Cenveo Anderson Lithograph, Commerce, California

Stelter & Brinck Ltd., Harrison, Ohio.

Please cite this report as follows:

Sullivan, John D. 2009. High‐Efficiency, Ultra‐Low Oxides of Nitrogen Supplemental Firing Burner.

California Energy Commission, Environmentally Preferred Advanced Power

Generation PIER Program. CEC‐500‐2010‐044.

i 
ii 
Preface 

The California Energy Commission’s Public Interest Energy Research (PIER) Program

supports public interest energy research and development that will help improve the quality

of life in California by bringing environmentally safe, affordable, and reliable energy services

and products to the marketplace.

The PIER Program conducts public interest research, development, and demonstration

(RD&D) projects to benefit California.

The PIER Program strives to conduct the most promising public interest energy research by

partnering with RD&D entities, including individuals, businesses, utilities, and public or

private research institutions.

PIER funding efforts are focused on the following RD&D program areas:

• Buildings End‐Use Energy Efficiency

• Energy Innovations Small Grants

• Energy‐Related Environmental Research

• Energy Systems Integration

• Environmentally Preferred Advanced Generation

• Industrial/Agricultural/Water End‐Use Energy Efficiency

• Renewable Energy Technologies

• Transportation

High Efficiency Ultra‐Low NOx Supplemental Firing Burner is the final report for the Combined

Heat and Power project (Contract Number 500‐03‐040) conducted by ALZETA Corporation.

The information from this project contributes to PIER’s Environmentally Preferred Advanced

Generation Program.

For more information about the PIER Program, please visit the Energy Commission’s website

at www.energy.ca.gov/research/ or contact the Energy Commission at 916‐654‐4878.

iii 
iv 
Table of Contents 

Executive Summary ...........................................................................................................................1

1.0 Introduction..........................................................................................................................5

1.1. Project Background..............................................................................................................5

1.1.1. Introduction of Technology................................................................................................6

1.1.2. Problem Statement...............................................................................................................9

1.2. Project Goals .........................................................................................................................11

1.2.1. Technical ...............................................................................................................................12

.

.

.

.

.

.

.

.

2.3. Full‐Scale Field Test.............................................................................................................34

2.3.1. Objective................................................................................................................................34

2.3.2. Geometry and Scale of Burner System .............................................................................34

2.3.3. Operating Conditions..........................................................................................................35

2.4. Results ...................................................................................................................................35

3.0 Project Outcomes .................................................................................................................37

3.1. Identification of Field Test Site ..........................................................................................37

3.1.1. Cenveo Facility Description ...............................................................................................38

1.2.2 Economics .............................................................................................................................16

1.3. Project Overview..................................................................................................................19

1.3.1. Project Phases .......................................................................................................................19

1.3.2. Problems Encountered........................................................................................................20

1.3.3 Project Accomplishments ...................................................................................................20

1.4. Report Organization............................................................................................................20

2.0 Project Approach .................................................................................................................21

2.1. Prototype Phase ...................................................................................................................21

2.1.1 Objective................................................................................................................................21

2.1.2 Geometry and Scale.............................................................................................................21

2.1.3 Operating Conditions..........................................................................................................21

2.1.4 Results ...................................................................................................................................22

2.2. Pilot Phase.............................................................................................................................27

2.2.1 Objective................................................................................................................................27

2.2.2 Geometry and Scale of Burner...........................................................................................28

2.2.3. Operating Conditions..........................................................................................................28

2.2.4. Results ...................................................................................................................................29

v 
3.1.2. Test Schedule and Requirem ........................................................39

3.2. Hardware Design.................................................................................................................40

3.3.1. Full Scale Duct Testing at ALZETA ..................................................................................44

3.4. 2007 Thanksgiving Weekend Burner Installation ...........................................................49

3.7. Project Rescope.....................................................................................................................56

4.2. Turbine Exhaust Gas Environment...................................................................................63

Glossary ...............................................................................................................................................65

ents for Field Access..

3.2.1. Control System.....................................................................................................................40

3.2.2. 10 Module Design................................................................................................................41

3.3. ALZETA In‐House Testing.................................................................................................42

3.3.2. Modifications........................................................................................................................46

3.5. Startup ...................................................................................................................................49

3.6. Post‐Test Analysis................................................................................................................54

3.6.1. ALZETA Testing of Welds .................................................................................................54

3.6.2. Review of Materials of Construction ................................................................................54

3.6.3. Liftech Analysis....................................................................................................................55

3.8. Design Modifications ..........................................................................................................56

3.9. Stelter & Brinck Duct Test Facility.....................................................................................58

3.10. Test Results ...........................................................................................................................59

4.0 Conclusions...........................................................................................................................63

4.1. Achievements .......................................................................................................................63

4.3. Industrial Hot Air Environment........................................................................................63

4.4. Sales Potential in the Industrial Hot Air Market.............................................................64

4.5. Sales Potential in the Gas Turbine Exhaust Market........................................................64

4.6. Recommendations ...............................................................................................................64

References............................................................................................................................................67

vi 
List of Figures 

Figure 1. Typical cogeneration system.................................................................................................1

3. burner

Figu

release rates. ................................................................................................................................... 14

10. Test matrix. ..........................................................................................................................29

Figure 11. Initial effect of adiabatic flame temperature (AFT) on emissions. ............................... 30

Figure 12. Accurate effect of adiabatic flame temperature (AFT) on emissions........................... 32

Figure 13. Test points for emissions data...........................................................................................32

Figure 14. Effect of dynamic pressure on pressure drop. ................................................................34

Figure 15. Gas injection design............................................................................................................41

Figure 16. Side view of the expansion section...................................................................................42

Figure 17. Front view of the expansion section.................................................................................43

Figure 18. Blower mounted on frame.................................................................................................43

Figure 19. Duct section with one burner bank installed. ................................................................. 44

Figure 20. Field demonstration burners installed in ALZETA test facility................................... 46

Figure 21. Schematic of extension box that was added to the burner modules to improve

mixing of fuel with turbine exhaust gas.....................................................................................47

Figure 22. Modified gas injectors for use in “H” design mixing arrangement............................. 48

Figure 23. Assembled modules, extension box, and gas injectors.................................................. 48

Figure 24.    ALZETA auxiliary panel for controlling of fuel valves for individual burner

modules........................................................................................................................................... 50

Figure 25.  Front view of completed assembly of burner modules................................................ 50

Figure 2.  Cogeneration system. ............................................................................................................7

Figure   Schematic of premixed surface stabilized supplemental firing   with HRSG. .. 13

re 4. ALZETA CSB NOx emissions plotted versus excess air over a range of burner heat

Figure 5. NOx versus total dilution for a range of excess air and FGR conditions....................... 15

Figure 6. Test matrix and test conditions for prototype tests.......................................................... 22

Figure 7. Effect of adiabatic flame temperature (AFT) on NOx emissions. ................................... 24

Figure 8. Effect of adiabatic flame temperature (AFT) on CO and NOx emissions..................... 24

Figure 9. Duct Burner............................................................................................................................28

Figure

vii 
Figure 26.  Final installation of perfora tom of burner modules. ................. 51

Figure 27.  View of gas manifold, control valves, burner mounting plates, and pilot plate. ..... 51

28.  View of far side of duct.....................................................................................................51

Figure 33.  Three branched injector tee. .............................................................................................57

Figure 34.  Test facility at Stelter & Brinck.........................................................................................58

ted steel plate at bot

Figure

Figure 29. Example of damaged burner module .............................................................................. 52

Figure 30. Photo of undamaged burner module taken at same time as photo in Figure 27.

Approximately half of the modules were undamaged............................................................ 53

Figure 31. View of rear of duct burner. ..............................................................................................53

Figure 32.  New burner box manifold with bracket for rear support rod pipe. ........................... 57

Figure 35.  Burner bank to be installed in duct. ................................................................................59

Figure 36.  Flames occurring in the gap between burners during testing..................................... 60

viii 
List of Tables 

Table 1.  Performance characteristics of 1‐5 MWe gas turbines........................................................6

Table 2. Comparison of heat recovery approaches including baseline and maximum heat

recovery (1.2 MWe engine).............................................................................................................8

Table 3. Current baseline for supplemental firing burners and boiler burners............................ 10

Table 4. Energy and environmental impacts .....................................................................................16

Table 5. Typical gas turbine / HRSG conditions relative to prototype burner test conditions... 26

Table 6. Comparison of site hardware at Cenveo and alternate field location............................. 38

Table 7. Comparison of Cenveo conditions and pilot‐scale test conditions ................................. 39

Table 8. Weight as a function of material gauge ...............................................................................54

Table 9.  Summary of test results ........................................................................................................61

ix 
x 
Abstract 

This project developed and tested a high‐efficiency, ultra‐low oxides of nitrogen (NOx)

supplemental firing burner system.  The target market is California, where ultra‐low NOx

regulations limit the use of conventional supplemental firing burners in combined heat and

power facilities.  Activities included a prototype phase, which provided baseline design data

and developed a method for predicting NOx emissions; a pilot phase, in which a burner

module that would be appropriate for industrial applications was developed and tested; and a

full‐scale testing phase, where a number of burner modules were installed in an operating

combined heat and power facility.  Results showed that fewer than 3 parts per million NOx

(corrected to 15 percent oxygen) could be achieved in the turbine exhaust gas environment

typical of many combined heat and power facilities.  However, an initial full‐scale test in a

turbine exhaust gas environment failed structurally, as the turbulence and flow variations

present in the exhaust stream were much greater than anticipated.  A second test with a more

rugged burner system design was structurally successful, but ultra‐low NOx emissions were

not achieved due to of the turbine exhaust gas turbulence.  This turbulence significantly

decreases gas flow uniformity, which is critical to optimizing performance and minimizing

emissions.  A commercial system will need to address the turbine exhaust gas turbulence and

flow variations to ensure ultra‐low NOx emissions.

Keywords: Combined heat and power, CHP, supplemental firing burner system, ultra‐low

NOx emissions

xi 
xii 
Executive Summary 

The primary goal of this project was the development of a supplemental firing burner system

(see Figure 1) to improve the efficiency of combined heat and power facilities while providing

the end user with ultra‐low emissions of oxides of nitrogen (NOx).  By reheating turbine

exhaust gas, overall plant efficiency is increased, and steam generation in the heat recovery

The

r

t

high velocity and highly turbulent stream confined in the duct

ent

e

s in

steam generator can match demand independently from the operation of the gas turbine.  

NOx emissions goal is 3 parts per million corrected to 15 percent oxygen, which is essential fo

the California market.  The burner and controls technology developed by this contract also

would have broader application, in that ultra‐low NOx technology is desired in process

industries where supplemental firing is used in providing hot air for numerous drying

applications in the food and plastic industries, among others.   

Turbine exhaust gas is the hot flow downstream of a turbine.  It typically is hot (between 700°F

and 1200°F) with reduced oxygen content relative to ambient air (15 percent oxygen to 18

percent oxygen in turbine exhaust gas versus 21 percent oxygen in air).  The turbine exhaus

gas flow is also a relatively

connecting the turbine exhaust to the inlet of the heat recovery steam generator.  The curr

state‐of‐the art supplemental firing burners, or “duct burners,” are modules that do not

provide any, or very limited, fuel and air premixing.  Essentially, fuel is injected into the

turbine exhaust gas stream, and the design of the duct burner “holds” the flame in one plac

with the flame extending 5 to 10 feet or more down the length of the duct.   This “diffusion

flame” combustion produces NOx emissions well in excess of the emissions requirement

many areas within California.     

Figure 1. Typical cogeneration system 

Source: http://www.eclipsenet.com/catalog/contents/Documents/01/165/165C%20Bulletin.pdf 

As an alternate approach, the high‐efficiency, ultra‐low NOx supplemental firing burner

technology fully premixes the fuel and air.  Combustion takes place on a metal mesh‐like

surface, with flames extending only inches off the surface.  A system is made up of modules,

each with a capacity of 1.2 million British thermal units per hour.  The module itself is a box

 1 
structure, open at one end, and having a wedge‐shaped mesh surface at the other.  Turbine

exhaust gas flows into the open end of the box where it is mixed with fuel at an optim

to‐fuel ratio to promote low NOx.  This premixed fuel and turbine exhaust gas continue

flow through the box and out through the wedge‐shaped mesh surface.  Combustion takes

place on the outermost surface of the mesh, and because turbine exhaust gas and fuel has bee

optimally mixed, NOx emissions are very low.

This project was divided into three technical phases.  In the prototype phase, the turbine

exhaust gas environment was simulated at laboratory scale (typically 800°F, and as low as 15

percent oxygen), premixed burners were tested in this environment, and NOx emissions were

measured.  It was demonstrated that NOx emissions can be correlated to adiabatic flame

temperature. The adiabatic flame temperature is the temperature that would be reached by

fuel‐oxidizer mixture if it could be completely combusted in an enviro

um air‐

s to

n

a

nment with no heat loss.  

to meet performance goals

s.  It

ip identified during the

phase would scale directly with the burner surface area.   

he ultra‐low supplemental firing burner technology was then subjected to a full‐scale field

st at an existing combined heat and power facility.  Conditions were similar to the pilot

in exhaust flow velocity and oxygen concentration, but the gas temperature was 1050°F

bout 250°F higher).  Only hours after installing the 10‐burner module system, a structural

ilure occurred, and testing in the actual turbine exhaust gas environment could not take

lace.  It is believed that the high turbulent environment and vibrations from equipment

ubjected the burner modules to excessive stresses.  

s a result of the structural failure, the module design was analyzed by a structural

company.  The engineers recommended several improvements, including

creasing the size of the burner support tube to minimize deflection and resist vibration,

adding additional supports at the rear of the module to reduce flutter, and altering the design

slightly to improve weld penetration at the joints.  A more robust, multimodule design was

then fabricated and tested, allowing combustion performance to be evaluated.  While the

redesign proved structurally sound, these results showed that uniform combustion is very

difficult to achieve in the turbine exhaust gas environment and, therefore, emissions goals

were not achieved.  Based on pilot phase results, the ultra‐low NOx supplemental firing

burner technology would be successful if the flow entering the burner module could be more

uniform.

Establishing this relationship between adiabatic flame temperature and NOx emissions means

performance can be predicted based on turbine exhaust gas conditions entering the

supplemental firing burner.  These results of the prototype tests justified proceeding to the

pilot scale phase.

In the pilot scale phase, a modular design was developed that achieved a better than 2:1

burner surface‐to‐duct cross sectional area ratio.  This ratio is necessary to match the typical

heat flux (the rate of heat energy transfer through a given surface) entering heat recovery

steam generators without expanding the duct size.  The ability

without requiring changes to existing plant hardware is essential for retrofit application

was also shown that the emissions and pressure drop relationsh

prototype

T

te

phase

(a

fa

p

s

A

engineering

in

 2 
In spite of the difficulties that were encountered during the project, the potential benefits of

this ultra‐low NOx technology are significant and merit further study.  For a current

generation combined heat and power system to be installed in the greater Los Angeles

metropolitan area, the San Joaquin Valley, or the Bay Area, the complete system (including the

power generating system and the duct burner) must meet NOx emissions levels that exceed

what can be achieved with current burners.  Stack treatment systems, such as selective

catalytic reduction, provide a solution, but the solution is much more expensive than a burner

solution.  The result is a higher cost for power and heat delivered by the combined heat and

power system, which makes the combined heat and power system less cost‐effective and

ultimately limits the use of combined heat and power in California.  The availability of a

viable ultra‐low NOx duct burner and gas turbine combustor would benefit California’s

ratepayers by reducing the overall cost of combined heat and power.

The following recommendations would address some of the problems that existed at the end

of this project.  First, a characterization of actual turbine exhaust gas environments is required,

including flow variations and turbulence.  With a better understanding of the turbine exhaust

gas environment, the hope is to identify ways of making the flow more uniform so that

combustion stability could be improved.  Second, an alternate approach should be evaluated

that withdraws turbine exhaust gas from the duct, premixes it with fuel, and then reintroduces

the premix to burners inside of the duct.  This approach could virtually eliminate the need to

deal with turbine exhaust gas flow variations and turbulence.  

The data in the figures and tables of this document was obtained by the author unless

otherwise noted in a source line beneath the table in question.

 3 
 4 
1.0 Introduction 

This project’s goal was to develop and demonstrate an ultra‐low oxides of nitrogen (NOx)

supplemental firing burner technology for impr

c

oving the efficiency of industrial scale

ombined heat and power (CHP) generating systems.  Improvements were to be achieved by:

a) providing very g to meet or

exceed the ate‐of‐the‐art s; b) i op

flexibility with respect to the balancing heat and power load atch process needs;

and c) havi Ox, carbon monox O), and hydrocarbons emissions, be

consiste e art industrial boiler burners.    

The desired also would le enough ign and op be

applicab CHP systems. the purpo pleting this , the

develop ed on a specific   After g several approaches,

a sup stem for re the exhaust   industrial e‐

generator the burn be installe n a turbine at

recover SG).  Although is a common application for supplemental

firing, the approach is also applicable to the st from recip g engines an fuel

cell t air ducts, o any process needing downstream exhaust

heatin

t Background 

ical” CHP customer with on site power requirements

ber of gas turbine

this class of

l gas turbine efficiencies are relatively low—in the 20‐30% range based on fuel

therefore generate a large amount of waste heat relative to the amount of

ly low temperature gas,

e can be 80% or more of the avoided

sts

wer to

a specific site.  However, in general the use of gas turbines to provide distributed

high overall thermal efficiency, with the efficiency target bein

efficiency of st industrial boiler mproving the

s to better m

erational

ng very low N ide (C also to

nt with the state‐of‐th

le e of

burner technology be flexib i s

s m

n its de eration to

to a wide rang   Yet, for

application.

e of co

reviewin

project

ment had to be focus

plemental firing burner sy

was selected, such that

heating from an gas turbin

er would d betwee and a he

y steam generator (HR this

exhau rocatin d some

technologies, recirculating ho

g.  

r

1.1. Projec

The specific application will target a “typ

in the capacity range of approximately 1 MWe to 5 MWe.  There are a num

manufacturers in this capacity range.  Two examples of manufacturers of

equipment are Solar Turbines of San Diego, California, and Kawasaki Gas Turbines –

Americas of Grand Rapids, Michigan.  A comparison of published performance data for

representative turbines from these manufacturers is presented in Table 1.

A review of Table 1 presents the following relevant information: 

• Industria

HHV – and

power produced.

• The waste heat that is produced is a high volume of relative

which limits the effectiveness of the heat recovery that can be achieved unless

supplemental firing is included.

• For a typical industrial user, the cost of fuel alon

cost of purchased electricity if there is no downstream heat recovery.  When other co

such as amortized capital costs and non‐fuel operating and maintenance costs are

included, generation of electricity without downstream heat recovery is rarely

economical.

• There can be reasons other than cost savings to produce power on site, such as

improved system reliability or to overcome the inability to get sufficient grid po

 5 
generation requires some form of waste heat recovery in order to be economically

feasible.  Improved cost‐effectiveness of waste heat recovery can dramatically im

the cost‐effectiveness of CHP systems.

Table 1. Performance characteristics of 1-5 MWe gas turbines 

Turbine Type Solar Saturn 20 Kawasaki 

GPB15DLE 

Solar Taurus 6

prove

0 

Output Power 

MWe @59oF, (15oC) 

1.21 1.42 5.20 

Heat Rate1 

Btu/kWe-hr (kJ/kWe-hr) 

15,500 

(16,400) 

16,200 

(17,100) 

12,500 

(13,200) 

Efficiency1, % 

(based on fuel HHV) 

22.0 21.1 27.3 

Exhaust /hr (k 51,240 

(23,220) 

63,300 

(28,710) 

174,800 

(79,280) 

 Flow, lb g/hr) 

Exhaust Temp, °F (°C) 960 

(516) 

995 

(535) 

906 

(486) 

Fuel Component of Power Cost, 

$/kWe-hr ($5/MMBtu fuel) $.078 $.081 $.063 

1. Heat input is based on fuel HHV. Turbine industry typically uses LHV, which results in lower calculated heat rate and higher 

calculated efficiency. 

1.1.1. Introduction of Technology 

Downstream Heat Recovery From Waste Heat Boilers and HRSGs 

In the 1‐5 MWe size range, turbine exhaust heat recovery is commonly achieved by using a

wa

no o the turbine exhaust.  These unfired systems have the

advantage of being very simple to operate and avoid the complexity of adding a second

e

mal efficiency, and an increased steam‐to‐power

ratio can all be obtained by installing supplemental duct burners between the turbine and the

xhaust gases, as shown in Figure 2.  These burners

can

very high.   

ste heat boiler or heat recovery steam generator (HRSG).  In the simplest systems, there is

supplemental fuel added t

pollution source from the burners of the supplemental firing system. But there are significant

disadvantages:  

• Compared to a similarly sized industrial boiler, the thermal efficiency of the unfired

HRSG is significantly lower.  Useful energy is being “lost.”

• The amount of steam that is produced is nearly constant for a given gas turbine size,

providing the facility operator with much less steam supply “turndown” than could b

realized with a conventional industrial boiler.   

Improved operating flexibility, higher ther

waste heat boiler or HRSG and heating the e

elevate the temperature of the turbine exhaust gas (TEG) to increase steam production and

provide more control over the amount of steam produced relative to the power produced by

the gas turbine. Marginal efficiency (conversion of fuel energy to steam) is

 6 
Examples of how duct burners and downstream heat recovery equipment would interface

with a gas turbine from an energy balance perspective are provided in Table 2.  These

calculations were done using a Solar Turbines Saturn 20 engine as the power generator.  Heat

recovery values and efficiencies were calculated assuming a stack temperature for the

combustion products of 300°F.  On the steam side, 150 pounds per square inch gauge (psig)

steam was assumed with an inlet water temperature of 227°F and exit conditions of 150 psig at

saturated conditions.  These inlet and exit steam conditions are considered to be typical for

industrial steam applications.  The stack temperature is considered to be achievable in systems

designed for high thermal efficiency.    

Figure 2. Cogenerati

recovery steam gener

on system. Supplementary re located between turbine a

ator. 

Source: Solar Turbines 

Alth ulations were done for the Saturn 20, similar heat recovery numbers could

ed.  For

low of

e

 burners a nd heat 

ough these calc

be calculated for other industrial turbines currently used for industrial power generation and

cogeneration systems without significantly changing the conclusions that will be reach

example, a 5 MWe turbine will have a TEG mass flow that is roughly 5 times the mass f

a 1 MWe engine and would generate roughly 5 times the amount of steam in a HRSG fired at a

similar temperature.  After correcting for the difference in capacity, there will be small

differences in mass flow and TEG  temperature due to differences in efficiency, but as stated

above, these differences are relatively small within the framework of this discussion of th

benefits provided by supplemental firing.

Table 2 presents the following information:

• The first column provides data for the case with no downstream heat recovery.  In

industrial applications this approach would rarely be cost‐effective but is included to

show the efficiency of the turbine by itself with no heat recovery.

Air Inlet 

Filter 

Generator 

Gas 

Turbine 

Exhaus

B

t

ypass

Silencer

H

R

Genera

(HRSG) 

eat 

ecovery 

Steam 

tor 

Diverter 

Valve 

Supplemen

Burne

tary

r

 7 
• Downstream heat recovery equipment adds backpressure to the turbine, which has a

slight negative impact on the turbine efficiency.  A power reduction of 0.25% pe

water column (w.c.) increase in back pressure is typical and is reflected in Table 2.  A

heat recovery boiler will add backpressure, and supplemental firing burner

r in.

s will add

e

12

Firing (1600°F); Supplemental 

additional pressure drop above what has been added by the boiler.  Therefore, in Tabl

2 approximately 6 in. w.c. was assumed and added in the unfired HRSG case; and

in. w.c. was added in the fired HRSG case.  The resultant power loss is tabulated.

Table 2. Comparison of heat recovery approaches including baseline and maximum heat 

recovery (1.2 MWe engine) 

Heat Recovery 

Approach No Heat 

Unfired Heat 

Recovery; 

Supplemental Optimum

Recovery 6 in. w.c. 

backpressure 

12 in. w.c. 

backpressure 

Firing 

(3% Stack O2) 

Power Generation (MWe) 1.21 1.19 1.17 1.17 

Turbine Heat Input 

(MMbtu/hr) 

18.8 18.8 18.8 18.8

Energy in Turbine 13.8 13.8 13.9 13.9 

Exhaust, MMbtu/hr 

Supplemental Fuel 

MMbtu/hr 

 11.3 43.3 

Cogeneration Heat 

Recovery MMbtu/hr 

 8.9 18.8 46.9 

Steam Generation (lb/hr) 8,900 18,800 46,900 

Power-Steam Ratio (%)1 45.6% 21.2% 8.5% 

Overall System 

Efficiency, HHV 

22.0% 69.2% 75.7% 82.0% 

1. Power-steam ratio is defined as the ratio of electric power to steam output in equivalent units of power (MWe/MWth for example).

• The second column “Unfired Heat Recovery” presents the case where there is

downstream heat recovery without supplemental firing.  The amount of steam

generated by this approach provides a power‐to‐steam ratio of 0.46 in this specifi

and would typically be between 0.4 and 0.5.  There is very limited flexibility in the

amount of steam that can be generated.  The peak steam supply is fixed at 8,900 lb/hr

Consequently, the only way to reduce the amount of steam generation at a fixed

turbine load is to vent the TEG to atmosphere, bypassing the steam generator

therefore “bypassing” any efficiency gain from the system.

c case

.  

and

am production would be approximately doubled, from the

00 lb/hr.  In addition, the system now

• The column “Supplemental Firing (1600°F)” presents the performance of a typical duct

burner using today’s baseline performance.  The temperature rise across the burner

would be 600‐650°F.  Ste

unfired value of 8,900lb/hr to a fired value of 18,8

 8 
provides a variable steam supply of between 8,900 lb/hr and 18,800 lb/hr as the duct

8,900

rmal efficiency of the CHP

strial boilers and

a condition that is

achie ial plications.  This lev l efficiency is

m fficie ould

cept in industrial steam licatio

• Also in the “Optimum Supplemental Firing” ca

when operating between the unfired mode an

fuel input between these two limits, the steam supply from the omes almost

as that from a standard industrial b

n ranges   to 10:1

1.1.2. Problem Statement 

Burners for Boilers Vers rners fo lemen

Today’s ultra‐low NOx burners (ULNBs) for boilers

than duct burners.  Sub‐9 ppm NOx emissions and sub‐50 ppm CO ected to 3%

2) can be achieved by a number of manufacturers of burners for boilers, and there are

fer between boilers and gas

x 2 3 ppm

burner heat input is varied.  Thermal efficiency would be lower at lower steam

generating rates, matching the efficiency of the unfired heat recovery case at the

lb/hr condition and increasing to 75.7% efficiency at maximum steam rate.

• The last column “Optimum Supplemental Firing” represents a reasonable maximum

thermal efficiency and maximum steam generation for a CHP system.  By adding

enough fuel to reduce the stack O2 level to 3%, the the

system is now similar to the best thermal efficiency achieved by indu

process heaters.  While this is the efficiency,” it is also

ved in industr

aximum e

“best thermal

boiler ap

ncy that c

routinely el of therma

the reasonable

burner con

be achieved with an advanced duct

ns.

se, there is now a 5:1 steam turndown

d the fully‐fired case.  By modulating the

HRSG bec

a pp

as flexible

turndow

oiler, where typical operational

from 5:1 .

us Bu r Supp tal Firing 

have much lower NOx and CO emissions

emissions (corr

O

hundreds of proven boiler applications in California.  Conversely, typical “low NOx” duct

burner emissions are on the order of 20‐25 ppm NOX corrected to 15% O2, or 60‐75 ppm NOx

when corrected to the same 3% stack O2 as for boiler applications.  The relatively high emissions

from duct burners limits the use of CHP systems in California, Texas, and several other industrialized

areas in the United States, and will continue to limit the economic viability of CHP systems if

this problem is not addressed.

Because the O2 levels used as emission correction factors dif

turbines (3% for boilers and furnaces, which is considered a typical stack O2 concentration; vs.

15% for turbines and ancillary components such as duct burners, which is also a typical stack

O2 concentration for these units), it may be simpler to reference emissions to lbs of NOx

generated per MMBtu heat input.  A lb‐per‐MMBtu comparison yields the same numerical

value for either technology.  The level that corresponds to 9 ppm NO at 3% O (and

NOx at 15% O2) is .01 lb per MMBtu.  Hence, the goal of the project was this .01 lb per MMBtu

level.  Table 3 presents representative baseline performance parameters for a current

generation duct burner.  This is compared to what is considered technically achievable.

The difference in the emissions of today’s best boiler burners versus today’s best duct burners

raises the following questions:

• How do boiler burners achieve ULN emissions?

 9 
• Why can’t duct burners reach the same emissions level?

In answering the first question, the generally accepted method for reducing NOx emissions in

is

boilers and most large industrial burners is to reduce the flame temperature by adding

additional air or flue gas.  Since NOx formation varies exponentially with flame temperature,

higher levels of dilution lead to more significant levels of NOx reduction.  The use of flue gas

preferred over the use of excess air for thermal efficiency reasons, even though more fan

power may be required to move flue gas through a burner.   

Table 3. Current baseline for supplemental firing burners and boiler burners 

Parameter Duct Burner 

Baseline 

Boiler 

Baseline Comments 

NOx Emissions 

(lb per MMbtu) .06 .01 

Boiler baseline corresponds to 9 ppm NOx at 

3% stack O2 which is widely regarded as 

boiler BACT. Duct burner emitting at .06 

lb/MMbtu requires stack treatment to meet 

BACT. 

CHP Thermal 

Efficiency 75.7% 82.0% 

Baseline duct burner efficiency limited by low

temperature rise across burner and h

residual oxygen in exhaust. 

igh 

Steam turndown Limited turndown from current baseline limits 

al 

2.1:1 5.3:1 operational flexibility. A minimum steam 

turndown of 5:1 is the expectation of industri

boiler operators. 

Currently, the most successful manufacturers of ULNBs all operate at similar levels of excess

combustion air and flue gas recirculation (FGR).  These manufacturers include ALZETA and

Todd Combustion and Coen (both John Zink Companies).  Since the fundamental principle

involved in reducing NOx is to lower flame temperature, it is not surprising that similar air

and FGR levels are required.  Nominal air and flue gas flows that are required are 20% excess

?)

rner

ould

combustion air and 35% FGR to achieve 9 ppm. ULNBs can run at FGR levels of 35‐40%,

resulting in O2 levels in the air‐flue gas mixture of 15‐16%.

The second question posed above (Why can’t duct burners achieve the same emissions levels

is more difficult to answer.  However, a review of available supplemental firing technologies

confirms that current duct burners do not meet the 9 ppm NOx emissions level corrected to

3% stack O2.  There are a number of reasons for this.  The most important ones are:

• To minimize pressure losses downstream of the turbine, conventional duct bu

technology is installed as an array (or grid) of burners that do not completely block the

cross‐section of the exhaust duct.  This approach has the advantage of keeping

pressure losses low, but it limits the amount of turbine exhaust that can interact with

supplemental fuel, since all of the added fuel can not immediately mix and burn with

all of the TEG.  Therefore, for a given heat input, the flame temperature in the

immediate vicinity of the fuel injection point is higher than the temperature that w

 10 
be reached in a premixed or rapidly mixed flame.  This higher temperature leads to

higher NOx emissions.

e

the low peak flame temperatures

that can be achieved in ULNBs designed specifically to operate in large furnaces.  

the primary motivation for installing the system, the

O2 level consistent with the air‐FGR mixture of a ULNB, the

typical ULNB oxidizer temperature of 200°F.  With the higher starting

the performance of supplemental firing technology.

  

n necessary.   

As discussed in a technical paper “Comparative Evaluation of Cogeneration Cycle

Alternatives” by R.C. Vetterick and P.G. Whitten (Reference 1), sizing of the electric and steam

components of a cogeneration system should be driven by plant thermal requirements during

normal operation.  Equipment sizing should not be driven by maximum steam demand or

maximum electric power usage due to inefficiencies that result from off‐design performance.  

A plant operator can typically buy electricity off of the power grid but has no secondary

source for steam.  Generating more power than can be used on site, with the intent to sell

• In designing duct burners, the performance goals of low pressure drop and short flam

length are in general not compatible with achieving

When power generation is

effectiveness of the heat recovery system may suffer.

• Although TEG has an

turbine exhaust is typically at a temperature of 950‐1000°F, which is significantly

higher than the

temperature for the combustion reaction, the resultant flame temperature is higher,

resulting in higher NOx emissions.

1.2. Project Goals 

One goal of this project was to close the technical gap that currently exists between duct

burners and boiler burners with respect to both thermal efficiency and pollutant emissions.  

The project would build on technology that has been proven to work in other industrial

applications and make a step change in

Another issue is operational flexibility.  Most industrial operators want boiler steam turndown

capability of 10:1, with 5:1 turndown being a minimum expectation.  An inability to achieve

this full level of turndown can result in excess steam being vented to the atmosphere, an

obvious loss of plant efficiency.  If the steam generator cannot match plant requirements to

steam supply, then either thermal efficiency suffers or operational complexity increases.  The

typical industrial gas turbine has a much more limited operating range with respect to mass

flow than does a boiler.  Therefore, it is difficult, if not impossible, to simultaneously meet

plant electricity and steam demand with conventional cogeneration systems without suffering

significant efficiency penalties during off‐design operation.

For this reason, many plant operators have found it necessary to keep a redundant source of

steam at the plant to provide steam when the cogeneration system is down and to increase

operational flexibility with respect to boiler turndown.  The cost of this redundancy is high.

Assuming a cogeneration plant with an electric capacity of 5 MWe and a maximum steam

requirement of 100,000 lbs/hr, the cost of a redundant steam supply can add 20 percent to the

cost of the plant.  Instead, these components could be replaced with a duct burner/HRSG,

which could be fired separately whe

 11 
power back to the grid, is marginally feasible at best for industrial facilities in today’s energy

market.3

In order for cogeneration to become a more attractive and cost‐effective option for industrial

plant operators, systems must be developed that provide:

• High thermal efficiency.

• Operational flexibility of 5:1 minimum steam turndown, regardless of turbine

operating condition.  

• NOx and CO emissions that meet BACT cost‐effectively and without stack treatment.

1.2.1. Technical 

The technical basis for this work was to take proven fully premixed surface stabilized burner

technology for boiler applications and extend this technology to operation in a turbine exhaust

gas stream.  A generic view of what the final product could look like is presented in Figure 3.  

As shown, the technology would be mounted in a duct to interface with both the upstream

turbine exhaust and the downstream HRSG.  Fuel is injected upstream of the burner surface.  

Note that the fuel is injected into discrete ports, with each gas injection port separately

premixed with a portion of the flow.

This type of mixing is necessary due to the limited flammability of the oxygen depleted TEG

stream.  There is a fairly narrow window of flame stability with respect to fuel air ratio.  Since

the mass flow of turbine exhaust is essentially constant and the fuel‐air operating range is

narrow, significant turndown can be achieved only by separately staging each burner’s

peration.  This same approach is used in current grid‐type burner layouts, with the primary

ifference being that a design based on ULNBs requires fully premixing upstream, prior to

on

e burner surface at the relatively high velocity that will exist in the surrounding duct due to

a

TEG.  

o

d

combustion.  One challenge in the duct burner application will be to stabilize combustion

th

both the limited duct cross‐sectional area and the high temperature of the TEG.  

While a larger duct would be preferred to allow a more planar burner arrangement, the CHP

industry typically operates at a higher energy density.  Therefore, a constraint is having to

operate in smaller ducts.  One potential approach is to install a burner geometry that has

surface area that is significantly larger than the projected area of the duct.  Other options

include cylindrical or conical burners mounted with their bases normal to the flow of the

This trade‐off of burner design complexity versus burner pressure drop and burner stability

will be investigated in the project.   

 12 
Burners 

Supplemental Fuel 

(3 places) 

 13 

Figure 3. Schematic of premixed surface stabilized supplemental firing burner with HRSG. 

The premixed surface stabilized technology that forms the basis of this duct burner closely

of the

elationship between excess air, flame temperature, and NOx emissions can be easily

ture that

minimizes the efficiency loss is to bring flue gas from the boiler stack back through the burner

to cool the flame.  This approach is known as flue gas recirculation (FGR).  The FGR approach

requires a similar level of “total dilution” of the flame to achieve the required NOx emissions

level.  In Figure 4, NOx emissions from a burner using different combinations of excess air and

FGR are plotted versus “total dilution.”  Total dilution is defined as the total mass flow of

is

related to ALZETA’s CSB commercial and industrial burner technology.  ALZETA has been

selling the CSBTM burner for 15+ years as a high excess air 9‐ppm ULNB.  The simplicity

r

demonstrated with this burner.  Figure 3 shows this relationship.  As excess combustion air is

increased, NOx emissions decrease.  Since NOx formation increases approximately as an

exponential function of temperature, the relationship between NOx and excess air is nearly

linear on a logarithmic plot of NOx emissions versus excess combustion air.

Operation at high excess air can reach sub‐9 ppm emissions levels but with the penalty of

lower thermal efficiency.  A similar approach for lowering the flame tempera

Advanced Supplemental 

Firing Burner 

O-Type 

HRSG 

2800°F 

3% O -4% 2

TEG: 

950°F, 

15% O2

300°F 

3%-4% 

O2

Flue 

gas 

Inlet 

Exhaust 
excess air and flue gas relative to the mass flow of air required for stoichiometric combustion.  

The excess air data from Figure 4 are presented as baseline data in Figure 5 for comparison.

FGR use in boilers is motivated by the desire to achieve low NOx without sacrificing thermal

efficiency.  The experience gained while operating with high levels of flue gas proved to be

beneficial in the early stages of this project.  At ULNB conditions, the O2 level of the air‐flue

gas mixture can be on the order of 16‐17%.  This approaches the 15‐17% O2 level considered to

be typical of a gas turbine.  Also, in addition to matching the burner O2 to TEG O2, the

chemical makeup of the two streams with respect to all of the major gas species (nitrogen,

water vapor, carbon dioxide, and oxygen) is similar.  In this important aspect of burner

design, the existing boiler burner and the proposed duct burner are nearly identical.

1

0% 10% 20% 30% 40% 50% 60% 70%

NOx ected to 3% O

10

100

Excess Air (%)

2)

1.0 - 1.3

0.8 - 1.0

0.4 - 0.8

 (ppm, corr

0.2 - 0.4

Surface Firing 

Rate 

(MMBtu/hr-ft2)

bustion with FGR and the proposed duct

n

g

Figure 4. ALZETA CSB NOx emissions plotted versus excess air over a range of burner heat 

release rates. Higher excess air corresponds to lower flame temperature and lower NOx. 

Despite the similarity between current ULNB com

burner, one important difference is that the TEG is a much higher temperature stream than

what is typical of a boiler air‐FGR mixture.  The typical TEG temperature is 950°F, while the

typical ULNB air‐FGR mixture temperature is on the order of 200°F.  Since there is a know

relationship between flame temperature and NOx, with a higher flame temperature causin

higher NOx, this higher gas temperature prior to combustion is a concern.    

 14 
100

1

10

NOx (ppm, dry, correcte

0% 10% 20% 30% 4 60% 70% 80%

Total 

3% O2)

<15% EA

15-20% EA

20-25% EA

25-35% EA

35-45% EA

d to 

>45% EA

Baseline

0% 50%

Dilution

Figure 2-10a. NOx versus Dilution, Cymric

Figure 5. NOx versus tota f excess air and FGR cond

 mass flow basis relative to stoichiometric air. “Baseline” is Figure 3 data. 

nges d in This Project

duct burner sy s developed base prem rface

burner technology that expanded on th base by optimizing

use in ct burner applicat departure from “grid”

designs used Significant

g burne sent k t

addressed inc

m High Premi eratures ‒ Max

for current generation boile ord A

lly tested and operated prem rs a

1000°F, but n any commercially av ipment.  Ad

required in the early stages of the project.

Performance When Optimized f p Operation ‒ Due to the

egative stem back , a

firing must to operate

conventional burners. be designed to

the pressure d

o burner can n ll

Mixing of fuel and air or fuel, air, es m

mi is especially importa ion

l dilution for a range o itions. Dilution is 

calculated on a

Technical Challe

A novel

Studie

stem wa d on existing fully ixed su

stabilized

burner design for

e current knowledge

the du ion.  This is a radical

that have been

application and existin

had to be

for decades.  

premixed surface

luding:

differences between

r applications pre

the duct burner

nowledge gaps tha

• Burner Perfor ance at Very x Temp imum premix

temperatures

has successfu

as

r ULNBs are on the

ixed surface burne

ailable equ

er of 200°F.  ALZET

t temperatures as high

ot in ditional R&D was

• Burner

critical n

burner designed

or Low Pressure Dro

pressure has on turbine

be optimized

impact that sy

for supplemental

performance

at a lower

pressure drop than

operate with no

the pressure dr

  The duct burner must

rop of current industri

egatively affect the fo

minally 1/2

p across the

al ULNBs.  Reducing

owing:  

o

good

and flue gas becom

nt in ULNB applicat

ore difficult, and

xing s.

 15 
o Flow uniformi mum performance.  Flow

uniformity typically achieving the desired

balance between uniformity and pressure.

and environmental impacts of r rk a ated

  The Innovative Energy Systems y Savings (Reference 3)

this estimate, and the inputs and outputs from that program are

DOE rogra the   

group was th dustr etho is

believed of industries of interest researchers.  The

P utilization Reference 4.

ty across the burner is critical to opti

involves a design trade‐off between

uniformity and minimizing pressure losses.  Improved designs can improve the

1.2.2. Economics 

The positive energy

section (see Table 4).

this p

(IES)

oject wo

Energ

re estim

Tool

in this

was used as the basis of

presented below.  The basis for this tool was a ‐sponsored p m with chemical

industry, and while the focus for this

to be applicable across the range

e chem

that

ical in

are

y, the m

to

dology

primary source for market data for CH was

Table 4. Energy and environmental impacts

User Inputs 

Sector: chemicals % Energy Savings 

N l atura Gas: 14.0%

% of Market 

ted: 50.0% % Energy Savings Impac Electricity: 0.0%

Annual Growth 

Rate: 5.0% % Energy Savings C o oal/C ke: 0.0%

Year of 2008 Introduction: % Energy Savings 

Fuel Oil: 0.0% 

Market Penetration 

Curve: 

20 Year Market 

Saturation 

S r

W

olid o r

astes

 Liquid 

: 

0 lbs pe

product

 tons of 

Technology Cro

Opportunity Area: Approach 

sscutting/Systems E y

A sy

nergy Opportunit Combine

rea: 

d heat and 

power stems 

Energy Recovery 

Quality: 

M e

Impacts: Petroleum refining; 

 p 

NA 

ultipl Industry Chemicals; 

Pulp & aper; Food

processing 

Capital Cost 

Conventional 

System: 

$7,500,000 

C l Cost New 

System: $7,600,000 

apita

Non-energy Annual 

Cost Conventional 

System ($): 

$750,000 

Non-energy Annual 

Cost New System ,000

($): 

$750

Technology 

Lifetime in Years 20 Non-Combustion Air Pollutants: 

0 lbs per ton of 

product 

 16 
Energy Impacts for chemicals 

(Based on the input provided above, this technology will have the following impacts :)

 2005 2010 2015 2020 

MARKET PENETRATION * N/A 1.9% 5.4% 14.7% 

MARKET (MW) N/A 24.25 87.96 305.60 

ENERGY SAVINGS 

Natural Gas Energy Savings (trillion Btu) N/A 4.46 16.18 56.22 

Electricity Savings (trillion Btu) ** N/A 0.00 0.00 0.00 

Coal Energy Savings (trillion Btu) N/A 0.00 0.00 0.00 

Fuel Oil Energy Savings (trillion Btu) N/A 0.00 0.00 0.00 

TOTAL ENERGY SAVINGS N/A 4.46 16.18 56.22 

Energy Cost Savings (million $)

Natural Gas N/A 18.06 77.99 274.92 

Electricity N/A 0.00 0.00 0.00 

Coal N/A 0.00 0.00 0.00 

Fuel Oil N/A 0.00 0.00 0.00 

TOTAL ENERGY COST SAVINGS N/A 18.06 77.99 274.92 

POLLUTANT REDUCTIONS (lbs) 

Carbon (MMTCE/yr) N/A 0.06691 0.24272 0.84328 

Nitrogen Oxides (NOX) N/A 1,048,314 3,802,577 13,211,377

Sulfur Oxides (SOX) N/A 4,461 16,181 56,219 

Carbon Monoxide (CO) N/A 281,037 1,019,414 3,541,773 

Volatile Organic Compounds (VOCS) N/A 26,765 97,087 337,312

Particulates N/A 0 0 0 

Other (million lbs) N/A 0 0 0 

Return on Investment 0% 

% Impact on Technology Opportunity 

Area N/A 0.70 2.55 8.87 

* % of possible market impacted as shown in user inputs, not the total market. 

** Includes electricity generation and transmission losses. 

User Explanations 

 17 
Technology Description: The High Efficiency Duct Burner will be used in industri

CHP syste

al 

ms to boost CHP efficiency to the efficiency 

currently achieved by state-of-the-art boilers (80% based 

on HHV). 

Market Percentage: Turbine and duct burners can be added upstream of 

conventional boiler, so boiler does not have to be 

replaced. 

Introduction Year: Field demonstration is planned for late 2007. First sale

will be the following year. 

Energy Impacts 

Percentages: 

Thermal efficiency will be increased for 70% current 

typical HHV efficiency to 80%. Electricity will be more 

effectively used by being generated on site, but this is 

not addressed. 

Other Wastes and 

Pollutants: 

None 

Summary of Inputs to IES Energy Tool 

Industrial CHP systems can be applied in a broad range of applications that include chemical

plants, refineries, paper mills, and any large industrial site that uses both electricity and heat.  

The current installed base of CHP systems in the United States is approximately 50 gigawatts

(GW) based on U.S. Combined Heat and Power Association estimates.  This includes some

very large sites and some sites that do not burn natural gas.  Hence, the market for CHP was

revised downward to 10 GW to provide a conservative estimate.  The market growth rate w

set at 5%, which is also conservative compared to some other estimates, with an estimated 20

year horizon for market saturation.  Capital cost was for the complete CHP system including

5 MW tu

as

‐

a

rbine, duct burners, and HRSG.  Cost was estimated based on $1,500 per kW installed

of the turbine alone would be on the order of $1,000 per kW.  

%

,

ergy by replacing low‐efficiency electric power generation and transmission

generation.  

The environmental benefits are very significant, with annual NOx emissions reduction by 2020

for the system.  The installed cost

The $1 00 ,5 amount includes the remaining system components.

Reduced Energy Usage for Equivalent Productivity 

For a given facility, the estimated fuel usage can be reduced by 11% relative to the current

typical CHP installation.  This was based on an estimated HHV thermal efficiency of 80

versus 72% for a typical current system.  When using the table, the comparison was for the

improved CHP system versus a current typical system.  This resulted in energy savings of 56

trillion Btu annually in 2020.  Another ALZETA assumption, not quantified in the IES

spreadsheet, is that improved duct burners would result in more widespread use of CHP

which will save en

with higher efficiency on‐site

Environmental Benefits 

being 13 million tons per year, CO reduction being 3.5 million tons per year.  Carbon

 18 
emissions are also reduced due to the more efficient conversion of fuel to heat and power,

resulting in less combustion of fossil fuel.

Public and Private Benefits of Reduced Peak Load on the Grid 

A more difficult impact to quantify is the private benefits that accrue as more large industrial

t

‐to‐quantify benefit of industrial CHP

burner system but with no

the proposed high‐efficiency system should

gas as

e total “system” allowed the

.  The power savings was not accounted for in the

rmance

characteristics were analyzed to establish design requirements for the subsequent phase.  This

elopment and helped ensure that each phase’s

ork was

lace

.3.1. Project Phases 

phases included:  

• Prototype phase, in which burner materials were evaluated and key parameters were

established for burners operating downstream of a turbine‐generator.

users generate a larger fraction of their own power.  This will either eliminate the need for

additional central power plants or will reduce the demand for power to be transmitted to end

users.  The net result will be lower demand on the existing power infrastructure.  The greatest

problems on the grid can be expected to occur at times of peak demand.  The addition of

cogeneration at industrial facilities can significantly reduce peak demand, which benefits no

only the industrial user; it also benefits other customers on the grid by relieving the required

transmission capacity.  This is a very real but difficult

systems.  

Economic Viability of the Proposed Product 

The duct burner technology developed under this project should have a capital cost that is

estimated to be $100,000 higher than that of a current duct

incremental operating cost increase.  However,

save the end user $500,000 per year in fuel, based on 150 MMBtu/hr heat input, natural

fuel at $8/MMBtu, and 50% utilization factor (using the system for half of its rated capacity).

Consequently payback for this system is estimated to be less than one year.  (Note that the IES

Tool did not calculate this.  Possible problems were the large cost of the total system compared

to the “incremental” cost of the duct burners; or the fact that th

end user to not purchase 5 MW of power

authors’ comparison of two CHP systems.)  Whatever the reason, the proposed product is

economically very viable with a payback of less than one year relative to the standard duct

burner.

1.3. Project Overview 

This project was divided into three development phases that progressed from the laboratory

to testing under actual field conditions.  During each phase, specific perfo

minimized the risks at each stage of dev

development activities represented significant steps toward a commercial product.  W

performed over a 4 1⁄2‐year period, starting June 2004.  Prototype and pilot‐scale activities were

performed at ALZETA Corporation in Santa Clara, California.  Full‐scale field tests took p

at Cenveo Anderson Lithograph in City of Commerce, California, and Stelter & Brinck,

Harrison, Ohio.   

1

Project

 19 
• Pilot phase, which focused on the design of an industrial‐sized module for the ultra‐

were tested under industrial

als and general operating concept of the prototype supplemental firing burner could

ultra‐low NOx and CO emissions, uniform and stable combustion,

when operating under TEG conditions, continuing to develop a design

ng a matrix

of modules and proceeding to the field testing phase.

  

ment typical of turbine exhaust gas.  The NOx emission levels that can be

nt air districts in the United States.  

In addition, it was shown that a strong correlation exists between NOx emissions and

le to predict emissions and set operating

y, a rugged and modular design was developed

overall

prototype and pilot scale phases are presented in

sults of field testing phase. And finally, Section 5 presents

low NOx supplemental firing burner and proving its operation.

• Full‐scale field test phase, where multiple burner modules

conditions.

The prototype phase was especially important in that if burner operating parameters could

not be determined for the high‐temperature, low‐O2 conditions that represent a typical TEG

environment, it would be difficult to continue.  However, if it could be demonstrated that the

materi

simultaneously achieve

and low pressure drop

for industrial scale would be highly justified.

Likewise, demonstrating that performance goals could be achieved when key operating

parameters were applied to an industrial‐scale module design was essential to successfully

completing the pilot‐scale phase.  Positive results at this scale would justify buildi

1.3.2. Problems Encountered 

Problems occurred during the field test phase when it became apparent that real TEG

conditions and the CHP environment were harsher and much more variable than anticipated.

This led to cyclic loading and vibrations that caused structural failure.  A redesign and second

field test were therefore necessary to prove the technology.   

1.3.3. Project Accomplishments 

Overall the project demonstrated that ultra‐low NOx can be achieved in the low‐O2, high‐

temperature environ

achieved will meet BACT requirements in the most stringe

adiabatic flame temperature, making it possib

conditions as TEG conditions vary.  And finall

to withstand the varying flow field and vibrations of TEG applications.   

1.4. Report Organization 

This report presents the key findings of each phase.  Section 1 presents the Executive

Summary, and Section 2 provides the Introduction and Project Background, Goals, and

project organization.  The results of the

Section 3.  Section 4 highlights the re

the Conclusion and Recommendations for the project, including several market opportunities.  

  

 20 
2.0 Project Approach 

The project was divided into three phases as described below.

2.1. Prototype Phase 

The prototype phase tested burner materials at laboratory scale to characterize emissions and

combustion performance on simulated turbine exhaust gas (TEG).  If successful and baseline

operating parameters could be established, the project would proceed to the next phase: pilot

scale.

2.1.1. Objective 

The objective of the prototype phase was to demonstrate that an ultra‐low NOx supplemental

firing burner based on ALZETA’s CSB ultra‐low NOx burners could operate predictability on

simulated TEG. The Phase investigated key performance parameters such as NOx and CO

emissions, pressure drop across the burner surface, and evaluated burner geometries

compatible with typical duct cross‐sections and burner surface flux constraints.   

2.1.2. Geometry and Scale 

Tests were performed with cylindrical, conical, and wedge‐shaped burner elements at a

nominal firing rate of 100‐200 MBtu/hr.  At this scale tests can be completed in the laboratory

in a rig that provided excellent visual access to the burner.  It also provided a suitable

environment for demonstrating burner flame stability and emissions over a range of operating

conditions that are representative of the turbine exhaust gas (TEG) environment.  Prior

experience has shown that prototype testing with materials based on ALZETA’s CSB ultra‐low

NOx burner are readily scaled‐up to larger systems.  Similar scale‐up results were expected for

TEG environments.

The key performance parameters to be investigated were:

• Ultra‐low emissions of NOx and CO.

• Low‐pressure drop across the burner.

and burner surface flux

of this application.

ing rate selected, the tests were approximately 1/40 of a full‐scale burner

ough the specific capacity of a full‐scale module was not defined until the

e

and O2 conditions is presented as Figure 6.

• Burner geometry compatible with the duct cross‐section

constraints

At the prototype fir

module, alth

completion of the pilot scale phase.   

2.1.3. Operating Conditions 

Test data were to be recorded at points that represented typical turbine outlet conditions.  The

initial test matrix was presented in Deliverable 6 and proposed varying the TEG gas

temperature between 700°F and 900°F and the oxygen concentration between 15% and 17%

dry O2.  Based on interest from a recuperated engine manufacturer, the test matrix was

expanded to lower temperature and slightly higher TEG O2 conditions to test at conditions

more representative of recuperated engine exhaust.  The targeted range of TEG temperatur

 21 
At specific TEG temperature and O2 conditions (the inlet conditions to the supplemental

burner), it was proposed in Deliverable 6 to operate the supplemental burner at exhaust

conditions of 4‐6% O2.  As a result of promising early test results, this operating range was

extended to include points between 2% and 6% O2.  During testing it was also determined that

achieve.

Figure 6. Test matrix and test conditions for prototype tests. 

2.1.4. Results 

Emissions 

NOx emissions have been previously shown to vary as a function of excess combustion air and

any other diluents in the premix stream, combustion air preheat, and other variables.  It has

also been demonstrated that NOx emissions do correlate well to a single parameter, adiabatic

flame temperature (AFT), which is a single variable that incorporates most of the other input

variables.  Therefore, for every test point, the AFT was calculated and used as the dependent

variable in all emissions plots.  The AFT calculations were performed using ALZETA’s in‐

house equilibrium code, CHEM.  CHEM requires gas composition, excess air, and temperature

as input values.  The input gas concentration and excess air are both calculated utilizing the

measured percentage O2 in the gas stream and assuming combustion of methane since the

controlling the test rig to all combinations of temperature and O2 was difficult to   

However, tests were conducted over a broad operating range, including some points outside

of the proposed test windows, and at all conditions that are of interest in this project.   

550

600

650

700

750

800

850

900

950

1000

Typical Industrial Gas Turbine 

Exhaust Conditions

14.0 14.5 15.0 15.5 16.0 16.5 17.0 17.5

%O2 in Duct

Gas T (F)

Recuperated Industrial Gas 

Turbine Exhaust Conditions

Data Points

 22 
exact composition of the natural gas used in testing was unknown.  The temperature was

measured with a thermocouple.  CHEM uses these input values and Joint Army Navy Air

Force (JANAF) thermochemical properties to calculate the heat of reaction and equilibrium

concentrations of 30 gas species that represent by‐products of the combustion reaction.  

The test results confirmed that for the prototype supplemental firing burner, NOx emissions

do correlate with the adiabatic flame temperature.  Figure 7 shows this relationship and that

the goals of reaching NOx emissions below 9 ppm at 3% O2 (3 ppm at 15% O2) were achieved.  

Keeping NOx emissions below 9 ppm requires an AFT below 2700°F.  Flame temperatures

below 3050°F resulted in NOx emissions of 27 ppm at 3% O2 (9 ppm at 15% O2), which is

considered to be excellent low‐NOx performance but does not meet the performance goals of

this project.  Test points meeting this emissions level include all test points with 4 to 6% O2 in

the stack, and test points with 2% O2 in the stack and 15% O2 in the duct.  Flame temperatures

below 2700°F include most test points with 6% O2 in the stack and test points with 4% O2 stack

and 15% O2 in the duct.   

For comparison, the test results are matched‐up to earlier gas turbine injector results that were

used to estimate supplemental burner performance as shown in Figure 8.  These data were

taken with preheated air at temperatures between 350 and 500°F and pressures between two

and eight atmospheres.  These conditions provided similar AFTs, and therefore the emissions

results are comparable.  Although the supplemental burner tests show higher NOx emissions

at a specific AFT, the differences are relatively small.  Of potentially greater interest the

upplemental burner had a much broader operating range at the low temperature end of the

s with stable burner

operation.  In addition, there was no evidence that CO emissions would be a problem

anywhere in the authors’ proposed range of operation.

s

range, which provides the potential for achieving lower emissions level

 23 
Supplemental Burner Emissions

25.00

y = 0.0006e0.0031x

15.00

20.00

 ppm)

0.00

5.00

10.00

2000 2200 2400 2600 2800 3000 3200

Emissions (15% O2,

NOx (15% O2)

CO (15% O2)

3 ppm

9 ppm

Expon. (NOx (15% O2))

3400

AFT (F)

Figure 7. Effect of adiabatic flame temperature (AFT) on NOx emissions. 

10

20

30

40

50

60

CO emissions (15% O2,

5

10

15

NOx emissions (15%

70

80

90

100

 ppm)

20

25

 O2, ppm)

CO (Prototype)

CO (Turbine Injector)

NOx (Prototype)

NOx (Turbine Injector)

0

2200 2400 2600 2800 3000 3200 3400

AFT (F)

0

Figure 8. Effect of adiabatic flame temperature (AFT) on CO and NOx emissions. 

 24 
Pressure Drop 

After achieving emissions requirements, the next most critical performance parameter was to

minimize pressure drop.  The pressure drop was shown to correlate with the dynamic

pressure, which is defined as 1⁄2 the density multiplied by the velocity squared.

Dynamic Pressure = (ρ*v2)/2gc

dynamic p the operating interest, and th f keep sure

drop below   was achieved over all conditions by keeping the dynam ure below

0.052 in. w.c.

Geometric Compatibility 

To keep the technology con rial pra the gener ign

approac w NOx w multip

modules, which could be m ement n the duct between

the turbine exit and the HRSG informa on HRSG i

and the authors’ prototype test results, d a maximum burner urface flux

that could be achieved withou , a burner ce‐to‐cros onal area

ratio of approximately 1.3:1 was were a num f ways to configure a

burner that has more surface are nal area.   

Two burne s we ility t to pilot imately to

full scale.   wedge d a half‐angl 0°.  This d vides a

burner surface area that is t ctiona .   

A second design was a truncated cone.  With a two‐foot diamete base and a six ch diameter

at the end, the truncated cone oss‐sectio ea ratio gr than 2,

specifically a surface area of 8.38 d in a 2’ x 2’ .  However void flame

interaction, the cones would nee ows with pace .  This

spacing will final su rea r 4:6.25

To verify t e and co have the s missions a essure

drop performance, the two owing if the two burner

geometries have the same veloc will have me pressu op.   An

arbitrary flow of 100 ft3/min was   For every 10% increment of travel

down the length of the burner, area that passed

calculated.  Then the amount of r as calculate uming flux

through the burner surface.  The calculated ing t g flow

by the inte the b at the ity is cons ithin

either geometry, and the two e.

Then to check that the pressure e same afte ing‐up to f ze,

alculations were performed with the exit conditions from three industrial gas turbines.  The

ree turbines chosen were the Kawasaki GPB‐15X, Solar Turbines Taurus 70, and General

Frame 7F.  Table 5 shows what typical exit conditions, duct sizes, and velocities would

Other tests showed that pressure drop through the surface burner scales linearly with

ressure over

3 in. w.c.

range of e goal o ing the pres

ic press

sistent with standard indust

g burner

ctice, al des

h for the ultra‐lo supplemental firin as to use le burner

ounted in a grid‐like arrang

i ing

withi work

nlet.  Based on exist

which demonstrate

tion nlet dimensions,

s

t loss of flame stability surfa s secti

calculated.  There ber o

a than cross sectio

r geometrie

The first is a

re analyzed to evaluate the ab o scale and ult

esign that included e of 3 esign pro

wo times the burner cross‐se l area

r ‐in

has a surface area to cr nal ar eater

8 ft2 when installe duct , to a

d to be placed in r six‐inch s s on all sides

yield a

hat the wedg

rface area to cross‐sectional a atio of 8. or 1.34:1.

ne geometry would ame e nd pr

concepts were compared, kn that

ity profile, then they the sa re dr

selected both cases.

the amount of surface

for

has been was

emaining flow w d s

by divid

by as a ant

he remainin

const

velocity was then

rior area of urner.  The conclusion was th veloc tant w

should be interchangeabl

drop will remain th r scal ull‐si

c

th

Electric

 25 
be for these three turbines if a series of duct burner modules were installed.  The table shows

use

l

the allowable 3 in. w.c. after scale‐up.

est conditions 

Duct Burner 

System 

Truncated 

Cone 

that all of the scaled‐up conditions are very similar to the prototype test conditions.  Beca

the conditions are similar, the dynamic pressure and therefore pressure drop is expected to fal

into the same range and stay below

Table 5. Typical gas turbine / HRSG conditions relative to prototype burner t

Property Wedge 

Prototype Rig 

TEG Mass Flow (lb/s) 0.129 0.129 

Temperature (F) 800 800 

Duct Dimensions 5” x 5” 5” x 5” 

Cross Sectional Area (sq ft) 0.17 0.17 

Duct Velocity (ft/s) 24.0 24.0 

Burner Surface Area (sq ft) 0.20 0.20 

Face Velocity (ft/s) 20.8 20.8 

 

TEG Mass Flow (lb/s) 17.6 17.6 

Temperature (F) 995 995

Kawasaki 

 GPB-15X 

Duct Dimensions 6’ x 5’ 5.5’ x 5.5’ 

Cross Sectional Area (sq ft) 30.0 30.25 

Duct Velocity (ft/s) 21.9 21.7 

Burner Surface Area (sq ft) 40.0 33.6 

Face Velocity (ft/s) 16.4 19.6 

 

Solar 

TEG Mass Flow (lb/s) 59.0 59.0 

Temperature (F) 913 913 

Duct Dimensions 10’ x 10’ 10.5’ x 10.5’ 

Cross Sectional Area (sq ft) 100 ft2

 110.25 ft2 

Taurus 70 Duct Velocity (ft/s) 20.8 18.8 

Burner Surface Area (sq ft) 120 134 

Face Velocity (ft/s) 17.3 15.4 

 

TEG Mass Flow (lb/s) 991 991 

Temperature (F) 1249 1249 

Duct Dimensions 40’ x 40’ 40.5’ x 40.5’ GE 

Frame 7F Cross Sectional Area (sq ft) 1600 1640 

Duct Velocity (ft/s) 27.1 26.5 

Burner Surface Area (sq ft) 2080 2147 

Face Velocity (ft/s) 20.9 20.2 

 26 
Conclusions 

Test results provided two correlations that can be used to model the NOx emissions and

pressure drop within the duct burner system.  The NOx emissions are shown to be accurately

006*e^(0.0031*AFT[°F])

ion of dynamic pressure by:  

t below

0.052 in. w.c. in pilot and full‐scale designs.  

Two geometries for scale‐up were considered, a wedge and a cone.  In order to verify that

emissions and pressure drop performance would remain the same, calculations were

performed.  It was determined that emissions performance would be unaffected because it is

controlled by the AFT, which is independent of geometry.  The pressure drop performance

will also remain the same because the velocity is constant inside either geometry.

Scale‐up calculations of a duct burner with two potential burner geometries were performed

under typical exhaust conditions and duct sizes of three industrial gas turbines.  These

calculations demonstrated that the prototype test rig conditions closely approximated those of

a typical industrial gas turbine exhaust duct.  The temperatures and gas velocities in the

industrial turbines and the test rig were all within a close range.  The prototype inlet

temperature was 700‐900°F, and the industrial turbines’ temperatures were between 914°F and

995°F.  Prototype inlet velocity was 20.8 ft/s, and the industrial turbine velocities were

between 15.4 and 20.9 ft/s.  Consequently, the same correlations for emissions and pressure

drop were expected to hold under scaled‐up conditions.

l

d and optimized under simulated

TEG conditions to demonstrate that the design could meet full‐scale performance goals.  If

sting had the following objectives:

2

modeled as a function of AFT by:  

NOx(15% O2)[ppm] = 0.0

The pressure drop can be modeled as a funct

Δp[in. wc]=58.129*(Dynamic Pressure[in. wc])

Both of these parameters can be scaled to larger burners and systems.  In order to keep the

authors’ goals of sub‐9 ppm NOx at 3% O2 (dry) and sub‐3 in. w.c. pressure drop, the flame

temperature had to be kept below 2700°F, and the dynamic pressure had to be kep

2.2. Pilot Phase 

Prototype testing defined modular design geometries for the ultra‐low NOx supplementa

firing burner.  In this phase, a larger scale design was teste

successful, multiple modules would be fabricated and tested at full scale under real TEG

conditions.   

2.2.1. Objective 

Pilot scale te

• Demonstrate stable burner performance when operating in a simulated gas turbine

exhaust stream with nominal conditions of 15% stack O and 800°F temperature.

 27 
• Demonstrate this stable operation with NOx emissions of 3 ppm or lower when

corrected to 15% O2 dry, and CO emissions of fewer than 16.5 ppm corrected to 15% O2

dry.

• Demonstrate the stable operation and low emissions with a burner pressure drop of 3

in. w.c. for the complete burner system

2.2.2. Geometry and Scale of Burner 

Since typical duct burner systems are made up of multiple modules, the pilot scale burner was

designed to be equivalent to a single module based on a version of the prototype geometries.  

Testing was done with a wedge‐shaped configuration instead of a conical burner as the wedge

shape yields a higher burner surface area to cross‐section area when flame interaction between

burners is considered.  The test burner configuration is shown in Figure 9 below:

Figure 9. Duct Burner 

2.2.3. Operating Conditions 

In these tests ALZETA used a gas turbine simulation rig to create typical TEG conditions

ng:  

varied between 0.75 and 1.25 times the design value of 925

upstream of the burner.  Testing involved the followi

• Burner inlet temperature was varied between the extremes of 700°F to 900°F, in

increments of 100°F.

• Burner inlet oxygen content was varied between 15% and 17% O2, in increments of 1%

O2.

• Stack O2 content was varied between 2% and 6% dry O2, in increments of 2%.

• Burner inlet flow rate was

scfm.

The conditions fit the test matrix shown in Figure 10.  For every inlet condition shown, data

were intended to be taken at 2%, 4%, and 6% O2 in the stack.

 28 
The gas turbine simulation rig consists of two burners fired in series. The first burner serves

the gas turbine combustor simulator, providing burner exhaust at conditions representa

a TEG stream.  An example of

as

tive of

these “simulated turbine exhaust” conditions would be a hot

tream with a temperature of nominally 800°F and 15 percent oxygen content.  The

define

vitiated air s

fired duty of the burner generating the simulated turbine exhaust ranged from 400 to 700

MBtu/hr, depending on operating conditions.  The exhaust conditions from this burner

the inlet conditions for the ultra‐low NOx supplemental firing burner pilot module or duct

burner.   

600

650

700

750

800

850

900

950

0.145 0.15 0.155 0.16 0.165 0.17 0.175

Dry O2

TEG Temperature (F)

Test Points

Figure 10. Test matrix. 

Prior to entering the duct burner, natural gas is injected into this stream, mixed, and

combusted by the duct burner at nominally 2 MMBtu/hr.  The exhaust from the duct burner

then flows into a small heat recovery steam generator where some gas is recycled back to the

system to optimize test conditions, and the remainder leaves the system.  

The key performance parameters investigated were:

stream with

• Stable operation with NOx emissions of 9 ppm or lower when corrected to 3% O2 dry,

2.2.4. Results 

• Burner stability when operating in a simulated gas turbine exhaust

nominal conditions of 15% O2 and 800°F.

and CO emissions of fewer than 50 ppm corrected to 3% O2 dry.

• Stable operation and low emissions with a burner pressure drop of 3 in. w.c. for the

complete burner system.

Previously it was shown that NOx emissions correlate well to a single parameter, adiabatic

flame temperature (AFT).  Therefore, for every test point the AFT was calculated and used as

 29 
the dependent variable in all emissions plots.  The AFT calculations were performed using

ALZETA’s in‐house equilibrium code, CHEM.  The procedure for calculating AFT was

described in Section 2.1.4.    

Emissions 

During an initial test sequence, the emissions data were not consistent with the earlier

prototype test data, such that NO and CO emissions were much higher than what was

expected based on

x

prototype test results.  In addition the pilot scale data had significantly

more scatter when plotted versus AFT.  Data were taken across the entire test matrix and are

presented in Figure 11.  It was also observed during this testing that the duct burner

consistently appeared to be running hot and eventually was damaged.

0.00

20.00

100.00

120.00

60.00

sions (ppm, 3%

40.00

80.00

2200 2400 2600 2800 3000 3200 3400

AFT (F)

Emis O2)

NOx

CO

Prototype

Figure 11. Initial effect of adiabatic flame temperature (AFT) on emissions. 

Due to these inconsistencies with the prototype test results, the burner and test rig were

inspected.  The cause of the unexpected performance was determined to be bypass air from

the simulated turbine exhaust stream that was not premixing with the duct burner fuel.  

Instead, it was passing though the boiler and biasing the stack oxygen reading upward.

As part of the initial pilot scale burner design, some of the simulated turbine exhaust gas was

to bypass along the top and bottom of the duct burner housing to cool the metal walls during

 30 
operation.  This flow intentionally would not mix with the fuel and, therefore, would not act

to dilute and cool the premix flame.  The bypass air was initially assumed to be a very small

portion of the flow.  But after review it was determined to be a much larger fraction of the

flow and therefore had a measurable impact on O2 as measured in the stack, making the NOx

emissions higher than they should have been.  These artificially high readings lead the

research team to run the burner too rich, which damaged the burner and yielded incorrect

AFT calculations.

Based on these unsatisfactory results, a new burner was built and the housing modified to

reduce the bypass flow.  In addition, the fuel‐air ratio in the duct burner was determined

based on a premix measurement instead of the stack measurement.  This burner was tested

across the entire test matrix with both stack and premix O2 measurements taken.  The premix

O2 measurement provides an accurate way to tell the true fuel‐air ratio of the burner and to

calculate the AFT without bypass air interference.  These tests showed that when the premix

measurement was used to calculate the AFT, the emissions data were consistent with what

was expected based on the prototype tests.  The calculations using the stack measurement

were all shifted toward lower AFTs.  The NOx emissions based on the premix reading

followed the exponential equation:

NOx = 0.0013*e0.0033*AFT

To meet the goal of 9 ppm NOx at 3% O , the AFT for the pilot scale needed to be kept below

.  For all test

oints the CO emissions were less than 1 ppm, which is the detection limit of the analyzer and

therefore are not shown on this graph.  Figure 12 shows the data for these tests.

Data were taken across the entire test matrix with the new burner.  The test matrixes with all

inlet condition test points are shown in Figure 13.  For each inlet condition, data were taken for

2%, 4%, and 6% O2 in the stack.    

2

2650°F.  This is similar to the 2700°F limit observed during the prototype tests

p

 31 
y = 0.0013e0.0033x

100.00

80.00

90.00

30.00

40.00

50.00

60.00

Emissions (ppm, 3% O2)

70.00

Premix

Prototype

Stack

9 ppm

Expon. (Premix)

0.00

10.00

20.00

2200 2400 2600 2800 3000 3200 3400

AFT (F)

Figure 12. Accurate effect of adiabatic flame temperature (AFT) on emissions. 

950

650

700

750

14 15 16

Temper800

850

ature (F

900

17 18

%O2

)

Test Points

Test Matrix

Figure 13. Test points for emissions data. 

 32 
Pressure Drop 

After meeting emissions requirements, the next most critical performance parameter was that

pressure drop across the burner be minimized.  The pressure drop has been shown to correlate

with the dynamic pressure, which is defined as:  

Dynamic Pressure = (ρ*v2)/2gc

In order to calculate the dynamic pressure, the density was calculated using the ideal gas law

at the measured temperature and pressure.  The velocity was calculated from the known

volumetric flowrate and burner surface area.  The volumetric flowrate was measured in

standard cubic feet per minute (scfm) and converted to actual cubic feet per minute (acfm) by

taking into consideration the inlet temperature and pressure drop. The velocity was obtained

by dividing the actual flowrate by the burner surface area, yielding a burner “face” velocity.

Figure 14 shows pressure drop data across the mixer and burner for both burners tested.  The

pressure drop data for these two burners was different due to differences in their construction.  

The first burner (Burner 1) consisted of a 66% open area backing plate with burner knit

material wrapped over the top of it.  The backing plate used with Burner 2 was only 8% open

area, and therefore the pressure drop was much higher.  Future plans call for the burner to

have a backing plate with 26% open area, so the pressure drop should fall between the two

sets of data.  Because the 8% open area backing plate was able to achieve a pressure drop

below the target of 3 in. w.c., there was high confidence that the 26% open area backing plate

would also reach the target.

Conclusion 

The test results provided a correlation to model the NOx emissions within a duct burner

  The pilot scale NOx emissions are modeled as a function of AFT by:

NOx [ppm, 3% O2] = 0.0013*e0.0033*AFT

3% O2 dry, the flame temperature must be kept below

50 ppm at 3% O2 dry was not an issue as CO

tests had less accurate measurements on the air flows and therefore this correlation was not as

data.  Pressure drop data were taken with two different burners.  One

system.

To meet the goal of sub‐9 ppm NOx at

2650°F.  The goal of keeping the CO below

emissions was zero across all test points.

Pressure drop was shown in the past to directly relate to dynamic pressure.  The pilot‐scale

obvious with the new

burner had 66% open area surface, and another had 8% open area surface. Although the 8%

open area burner pressure drops were much higher, both burners were able to achieve

pressure drops below the target of 3 in. w.c.   

 33 
0

1

6

7

5

3

4

sure Drop (in. wc)

Burner1

Bu

2

0 0.005 0.01 0.015 0.02 0.025

Dynamic Pressure (in. wc)

es Pr

rner 2

Figure 14. Effect of dynamic pressure on pressure drop. 

2.3. Full-Scale Field Test 

Based on the results of the pilot tests, a module design could be established that would allow

the design of a full scale ultra‐low NOx supplemental firing burner system.   This phase

prepared a design for a specific application with the goal of testing the system at that site.   

2.3.1. Objective 

The objective of this phase is to develop and fabricate a supplemental firing system for the

field demonstration site.  The new supplemental firing burner would increase overall plant

thermal efficiency, improve operational flexibility, and increase the reliability of steam and

electricity supplies, while reducing overall system operating costs.  

2.3.2. Geometry and Scale of Burner System 

The field demonstration hardware consisted of an array of burner modules essentially

identical to the single modules tested during the pilot scale phase.  Specifically, the orientation

and number of these modules was defined by the physical and operating conditions at the

Cenveo field demonstration site.  Cenveo (See section 4.1.2.) has a 3.75 MW Rolls Royce 501

 34 
gas turbine exhausting into a duct with internal dimensions of 4.5 ft by 7 ft.  When the turbine

is operating, supplemental firing burners need to add 12 MMBTU/hr of additional heat to the

exhaust stream in order for the HRSG and steam turbine to operate at full capacity.    It was

calculated that 10 modules would be required to meet Cenveo’s requirements.  With 10

modules, the Cenveo operating conditions for each module were similar to the ALZETA pilot‐

scale test conditions.  

2.3.3. Operating Conditions 

The Rolls Royce 501 gas turbine exhaust flow is 34.0 lb/s at 1050 ̊F.  Hence, velocity through

the duct where the ultra‐low NOx supplemental firing burner system would be installed is 21

ft/sec—essentially the same as during the pilot‐scale tests.  Temperature, however, is about

250°F hotter.  This would mean slightly lower dynamic pressure and, hence, somewhat lower

burner pressure drop.  Otherwise the environment was similar to the conditions used during

the pilot tests.   

2.4. Results 

Results are presented in the following section, Project Outcomes.

 35 
 36 
3.0 Project Outcomes 

This section summarizes the final outcomes of the project, in which the ultra‐low NOx

ld Test Site 

of six

t

gy required considerable effort.  

ns, the duct burner is typically specified and installed at the time of

ini

• Once a C is on‐line, the systems ty perate with alm n time.  

Finding to be shut down lo w installa g

proved

• Tim had to match th ject schedu

With nia Gas Com demonst

ident st AQMD and w customers e Gas

Company. s conduc the

• The target application was an industrial tur 3‐5 MW size r perated

for a sufficient number of hours to allow for significant life test data to be collected.

g

design

el supply pressure, and accessibility.

supplemental firing burner system was tested in the field.  The site selection, system design,

pre‐installation testing, installation and start‐up, test results, and rescoping for a final test are

discussed in this section.  

3.1. Identification of Fie

An important objective of this project was to demonstrate the performance of the high

efficiency ultra‐low NOx supplemental firing burner at a working field site for a period

months.  Although there are many duct burners in operation in California, finding a site tha

was interested in demonstrating a new duct burner technolo

Locating the site proved to be difficult for several reasons, with the most important being:

• For CHP applicatio

tial system installation.  Retrofit opportunities are very limited.

HP system pically o ost no dow

a site willing ng enough to allo tion and testin

to be difficult.

ing of site availability e authors’ pro

pa o field

le.

assistance from Southern Califor rati es were

ifie

ny, tw on sit

d; both were in the South Coa

  A review of both sites wa

ere industrial of th

ted to see if they met

bine in the

selection criteria.   

ange that o

• The site would have already been designed to operate with duct burners, and most

likely would currently have duct burners installed but would be interested in replacin

their current burners.

• The system layout would be compatible with the research team’s hardware

with respect to duct dimensions, fu

• The site would be interested in the efficiency and NOx benefits that could be provided

by the ALZETA supplemental burner relative to the performance of its current

hardware.

• The burner could be installed with minimal permitting modifications.  As a technology

demonstration, it would be desirable to install and operate without subjecting the

demonstration site to any permitting modifications that would extend beyond the

length of the research team’s demonstration.

Using these selection criteria as a guideline, Cenveo Anderson Lithograph in Commerce,

California, was selected as the demonstration site.  Reasons for selecting Cenveo included:

 37 
• The nge that

is of primary m erest to the auth opera e

custom

• The cu ct burners wanted to increas e heat input from

their duct b The HRSG stea put is used to dri a 1.2 MW steam

turbin l power, an ‐pressure steam m the system is

used to drive two illers.

• The duc e site is fl place in the d lowing for easy

removal s and insta of the ALZETA ers,

• Permitting be a problem denced by proactive work done by

Cenveo t e South Coas MD.

A comparison of by SCG aluated as pote

sites is shown in Table 6.

Tab ardware at Cenveo and alternate field location 

enveo Alternate 

ir 3.7 MW Allison 501 engine (now Rolls Royce) is in the industrial‐size ra

arket int ors and is ted year‐round by th

er.

stomer currently uses du and e th

urner system.   m out ve

e that generates additiona d low fro

ch

t burner assembly at th

of ner

anged in uct, al

the existing bur llation burn

did not appear to as evi

o coordinate with th t AQ

the two sites identified and ev ntial demonstration

le 6. Comparison of site h

Parameter C

Prime Mover Ro ce 501 lls Roy Solar Centaur 

Capacity (MW) 3.75 3.3 

Existin (Davis 

Engineering) 

orney (Davis 

Engineering) g Duct Burners Forney F

Duct Burner Capacity (MMbtu/hr) 16.0 25.0 

Fresh Air Operating Mode Yes No 

Primary Heat Recovery Device Heat Recovery Steam 

Generator 

Heat Recovery Steam 

Generator 

A site visit was scheduled and provided the opportunity for representatives from ALZETA,

eam

rs’

ons.  

the plant could not generate the remaining 550 kW of electricity that the steam

turbine was capable of generating unless the current system was repaired or a new duct

Cenveo, the Energy Commission, and Sempra to meet.  Sempra representatives attended the

meeting because they had facilitated the initial introduction between Cenveo and ALZETA

and because Sempra became a partner in the funding of the field demonstration.    

3.1.1. Cenveo Facility Description 

As stated above, the gas turbine generates 3.7 MW of electricity.  With no duct firing the st

turbine generates an additional 500 kW.  With duct burners at low fire, 150 kW of steam

turbine capacity is added bringing steam turbine output to 650 kW.  At the time of the autho

visit, the currently installed duct burner could operate only at low fire for emissions reas

This meant that

burner system was installed.   Hence, this site seemed ideal based on the selection criteria.

In addition, the operating data were used to perform an energy balance around the CHP

system components.  Cenveo dimensions and operating conditions are shown to compare

favorably to the ALZETA pilot scale test hardware in Table 7.   

 38 
Table 7. Comparison of Cenveo conditions and pilot-scale test conditions

Property Cenveo ALZETA Pilot-Scale 

Duct Internal Width (ft) 7 1 

Duct Internal Height (ft) 4.5 1 

Duct Area (ft2) 31.5 1 

Duct Section Length (ft) 2 1.2 

 

TEG Mass Flow (pph) 122,378 3,000 

TEG Temperature ( ̊F) 1053 800 

Vol. Flow (scfs) 459.4 18 

Vol. Flow (acfs) 1336.6 43.6 

Bulk Velocity (scfs) 14.6 18 

Bulk Velocity (acfs) 42.4 43.6 

 

Heat Input (MMBTU/hr) 12.5 1.2 – 2.0 

Burner Surface Area (ft2) 20 2 

Burner Projected Area (ft2) 10 1 

 

Duct Velocity (ft/s) 21.2 21.8 

Face Velocity (ft/s) 10.6 10.9 

3.1.2. Test Schedule and Requirements for Field Access 

Concerning the scheduling difficulties that are involved, Cenveo shuts down only two times

per year for scheduled service: Memorial Day weekend and Thanksgiving weekend.  At the

time of the first meetings with Cenveo, the opportunity to install over Memorial Day, 2007,

had already passed, so Thanksgiving of 2007 was chosen as the installation date.

so

l the new duct and, in a worst case scenario, impossible to reinstall the

al

e customer.  

However, if selecting to modify the existing duct and install burners in the field, the worst

A second necessary decision was whether to build a new duct section or modify the existing

duct.  The original plan called for building a new duct section to replace the existing section

that the burners could be preassembled.  However, after several visits to the demonstration

site, it was observed that the initial plan to remove the existing two‐foot duct section would

most likely be more difficult than expected.  The duct section at Cenveo has been in place for

more than 10 years, and it is likely that some metal deformation has occurred due to high

temperature cycling of the system.  It is also possible that this deformation is significant, and

the existing duct will become distorted when removed.  If this were to occur, it may not be

possible to instal

original duct.   

Since installation had to be completed in one weekend, the worst case scenario for replacing

the duct was that, at the end of the weekend, the turbine exhaust duct might still be open.  The

customer would then be unable to run the gas turbine, the steam turbine, or the supplement

burner system.  This would be unacceptable and too great of a financial risk for th

 39 
case scenario is that the supplemental burner system for some reason might not be

e

Discussions with the control panel designer determined that modifying the existing system

would be costly and complicated.  The existing panel is built around a programmable logic

controller (PLC), which in general would provide flexibility in design.  Unfortunately, due to

the age of the PLC in the panel (built in the mid‐1990s), a complete replacement of the PLC, IO

boards, and other electronic hardware would probably be required.  This would have been

unfortunate, since the existing controls worked well for the existing system.

By limiting the existing controls to system on‐off control, the flame safeguards, system

“permissives” functions, and the majority of the existing controls could be reused for the ultra‐

low NOx burner system.  The existing panel was left intact, but one function, the “heat input”

signal, which is the signal from the control room to the main gas valve of the existing duct

burner, was moved to a new panel.  With this approach, schedule and budget risks were both

reduced.

The existing system used a 4‐20 mA control signal to modulate an actuator that controlled the

main gas valve.  This control approach would not have worked with the ALZETA burner

concept.  As discussed previously, the ALZETA concept requires that each module in the

system operate in an on‐off mode.  A separate control panel was designed by ALZETA that

intercepted the 4‐20 mA gas valve control signal and ran it through a logic circuit that broke

iscrete on‐off commands for each of the 10 ALZETA modules.  

hese discrete on‐off commands then actuated an individual fuel solenoid valve for each of

the 10 ALZETA modules, thereby matching the heat input requirement to number of modules

ut signal.  

operational, but the gas turbine and steam turbine would both be running.   

3.2. Hardware Design 

Unlike the pilot scale tests, the system for Cenveo had additional constrains for interfacing

with the site—controls had to interface with the existing turbine and steam system, and th

burner system was to be designed for retrofit.  Work focused on interfacing with existing

controls and the existing duct section.

3.2.1. Control System 

During the initial visits to the Cenveo site, the existing duct burner control hardware was

inspected several times.  It was assumed that significant modifications would be required, and

possibly that the duct burner control panel would have to be replaced.   

the 4‐20 mA analog signal into d

T

being operated.

Choosing this controls approach simplified the interface requirements for the site.  The only

modification to the existing control panel was the redirection of the 4‐20 mA heat inp

In addition to being simpler and less expensive to implement at the Cenveo test site, this

design also demonstrated that minimal changes to what is considered to be “standard duct

burner controls” would be required in future ALZETA duct burner installations.

 40 
3.2.2. 10 Module Design 

The field system module design is very similar to that of the final pilot‐scale module design.  

However, at the field demonstration site the modules have to be supported by the gas pipe

and cannot be flanged in place as with the pilot‐scale tests.  Because the gas pipe needs to p

through the modules close to the burner face, it cannot be used for gas injection as there would

not be enough length for the gas and air to mix fully.  To overcome this issue, the burner

module was lengthened relative to the pilot‐scale design, and an extension pipe that projects

back to the entrance of the burner module was installed.  Attached to each of these pipes

ass

is an

“injection pipe” located in the center of the module and spanning across the horizontal length

of the module.  Figure 15 shows the gas injection design.  Modeling of the gas injection was

done using Lefebvre’s theory on mixing jets in cross flow, as it was with the pilot‐scale mixer

(Lefebvre, p.117‐126.)  The injection pipe has 14 holes, each 1/8” in diameter, that inject the gas

at a 90 ̊ angle into the air stream facing straight up and straight down.

Figure 15. Gas injection design. 

The next step in the duct burner design was the arrangement and support of the 10 modules.  

The final design had the duct burner modules arranged into two rows, or banks, that span five

modules across without any space between modules.  The modules were placed side by side

to ensure that each module would light the next.  The two rows were centered both

horizontally and vertically within the duct, leaving only a six‐inch space between the two

rows.  The six‐inch space was left to ensure that one row of burners could light the second

without the flames impinging upon one another.  The burner banks were centered within the

duct to ensure they receive enough air and to give the most even air distribution between the

two banks possible.   

 41 
3.3. ALZETA In-House Testing 

To test fire the newly designed burner system before installation at the Cenveo site, an existing

ALZETA high‐capacity air blower and burner control system were incorporated into a full‐

scale test facility.  The test facility consisted of a blower mounted to a frame, an expansion

duct section, and a duct burner section.  A variable‐frequency drive (VFD) was used to control

the blower motor speed to provide air flow up to 20,000 cfm.  The expansion section increased

the duct area from the 2 ft x 2 ft blower exit up to the 7 ft x 4.5 ft duct dimensions that match

the Cenveo site.  Photos of the test facility hardware follow in Figures 16 through 19.

Figure 16. Side view of the expansion section. 

 42 
Figure 17. Front view of the expansion section. 

 Figure 18. Blower mounted on frame. 

 43 
Figure 19. Duct section with one burner bank installed. 

The tests at ALZETA would accomplish the following:  

• Demonstrate reliable pilot ignition of the duct burners to ensure the pilot could light

the burners in a high cross‐flow velocity environment.  There was some concern that

the velocity in the duct may affect pilot performance.

• Demonstrate that the first burner bank could be used to ignite the second.  The baseline

.3.1. Full-Scale Duct Testing at ALZETA 

began with one completed burner row (five burner modules) installed on the duct

section. Of the five burners, the two on the side closest to the pilot lit and were operating with

uniform combustion, but the other three never had a steady flame.  The cause of this was

determined to be poor air flow distribution across the duct.  Using a hot‐wire anemometer, the

air velocity in the duct was tested for uniformity.  It was discovered that the velocity on the

right side of the duct, which did not light, was 50‐60 ft/s while the velocity on the left side of

the duct was only 5‐10 ft/s.  The extra air on the right side caused the premix to be too lean to

light.

design had the burners spaced six inches apart.  This test would determine whether

that distance was sufficiently close to have reliable ignition from the first bank of

burners, or if a second ignition pilot would need to be installed.  It also would

determine whether the burners were separated enough to avoid the flames from one

bank impinging on the other.

3

Testing

 44 
To make air distribution more uniform, the entire area around the burners was blocked with

51% open area perforated metal.  The velocity profile in the duct was measured again using an

anemometer, and the air distribution had the same pattern, but with less severe velocity

variation from point to point.  The right side of the duct had velocities in the 10‐13 ft/s range,

and the left side had velocities in the 1‐4 ft/s range.  The burners were lit again, but with the

same results as the first test.

Realizing that the air distribution across the duct could not be fixed with the current blower,

tests were done to even the air distribution through the burner modules.  To accomplish this,

the anemometer was used to measure the velocity on the face of each burner module.  Sheets

of perforated metal were placed at the entrance of each burner module to restrict the flow.  An

even distribution occurred when the first burner on the left had no restriction, the second was

covered with 65.5% open perforated metal, and the last three were all covered with 35.4%

open perforated metal.  The burners were lit again, and all remained operating with an even

flame distribution.   

A second burner bank was received and installed as shown in Figure 20.  Initial tests again

resulted in poor flow distribution and combustion.  A more thorough analysis of flow was

performed.  There were several points of concern:

• Single module tests completed earlier in the project met the research team’s emissions

and thermal performance goals.  The 10‐module 2‐bank system was designed as a

scale‐up of the single module hardware, with the 10 individual full‐scale modules

being nearly identical to the single‐module test hardware.  This represents the same

ity was not capable of

matching the temperature within the Cenveo duct, the mass flow at ambient

e same and would allow matching the burner surface firing rate.  It

e previous single‐module test results performed at temperature

e

geometric configuration needed at Cenveo.  While the pilot facil

temperature was th

was believed that th

would also allow scaling the cold flow results to TEG conditions, but this was not b

the case.

• It could be assumed that the poor flow uniformity and poor flame stability observed

during the full‐scale testing at ALZETA would also be a problem in the field

demonstration, as the actual localized flow conditions in the duct at the field site were

unknown.  There was no practical way of measuring how flow deviates spatially

across the Cenveo duct and how it fluctuates as a function of time.

 45 
igure 20. Field demonstration burners installed in ALZETA test facility. 

3.3.2. Modifications 

Test Duct Modifications 

Initial modification work was directed   improving flow conditions in the duct.  As

initially designed, the ALZETA test du ended immediately downstream of the burner

surfaces, while in the field installation the flow continues in a duct downstream to the HRSG.  

It was thought that flow disturbances a the duct exit could be caused by the rapid flow

expansion from the duct to open air or   wind, and that these disturbances could be causing

the flow non‐uniformity.  Neither of these flow conditions exists at the test site geometry, so

the research team’s test facility was modified to more closely simulate the field configuration.

‐section duct was built to simulate the duct section at the

b site.  This duct is 8 feet long, which provided adequate downstream flow uniformity.  Test

at

, although the flow in the duct is not steady or uniform,

proving flow conditions in the duct did not significantly improve burner performance.

F

toward

ct

t

by

First, a straight‐walled constant cross

jo

results were disappointing as the duct extension had minimal impact on improving burner

uniformity.  Next, honeycomb‐type flow baffles were added to the transition duct section th

exists between the blower and burners.  The baffles were added to remove large‐scale flow

disturbances from the blower wheel from propagating downstream.  Test results following

these modifications also showed minimal improvement in performance.  Based on these

results it was determined that

im

 46 
Burner Mixing Modifications 

Other work focused on improving mixing in the individual burner modules.  Changes were

made to the gas injection spuds, the modules were extended to allow for more mixing length

prior to the burner surface, and internal and external perforated metal baffles were added to

improve mixing.  Of all these modifications, the most significant were determined to be:

• Burner modules were increased in length by 10 inches by adding an “extension box” to

the upstream end of the burner modules, as shown in Figure 21.  This box is made

from 14 gauge stainless steel, which was similar to the material used for the burner

housings.  This modification added approximately 50% to the mixing length of the

burner modules. During development the extension box was bolted to the burner

modules.  In the field installation, the extension box was to be welded to the burner

modules after they were installed.

Figure 21. Schematic of extension box that was added to the burner modules to improve mixing 

of fuel with turbine exhaust gas. 

• The gas injector design was changed to incorporate more gas jets and less flow area

between banks of jets.  This modification approximately doubled the number of jets

ctor design are shown in

Figures 22 and 23.  The old spuds were similar in design but had fewer holes and

larger hole diameter.  

per module from 28 to 56.  The gas spuds for the new inje

 47 
Figure 22. Modified gas injectors for use in “H” design mixing arrangement. 

Figure 23. Assembled modules, extension box, and gas injectors. 

 48 
3.4. 2007 Thanksgiving Weekend Burner Installation 

Installation was scheduled for Thanksgiving weekend, 2007, when Cenveo would be

performing regular maintenance on the turbine system.  As part of the installation plan, work

in the duct had to be completed by Sunday morning so that the turbine could be restarted.  

Specific activities to be completed and the schedule for completing these activities were as

follows:

• Thursday Nov 22 ‒ ALZETA and subcontractor RECON (the onsite contractor) entered

the turbine exhaust duct, removed the existing duct burner, modified the duct walls to

accommodate new penetrations for the ALZETA burner, and began insulation and

sheathing repair as required.

• Friday Nov 23 ‒ The ALZETA auxiliary control panel for fuel flow control was

installed by Cenveo personnel, Figure 24. ALZETA and RECON completed insulation

and sheathing work.  ALZETA started installation of the 10 burner modules and the

pilot and scanner mounting plate as shown in Figures 25 and 26.  

• Saturday Nov 24 ‒ ALZETA completed installation of burner modules and supervised

the installation of the perforated steel baffles around the burners.  Pilots were installed.

by ALZETA had been completed the previous day.  During turbine startup, ALZETA

and RECON mounted the duct burner gas train.  ALZETA personnel completed the

fuel piping to the individual burner modules.  ALZETA gas train work was completed

Sunday afternoon, as shown in Figures 27 and 28.

The installation proceeded essentially on schedule, with no significant problems encountered.  

Photos of the installation are shown on the following pages.  

3.5. Startup 

The plant operators restarted the gas turbine as scheduled at 10 AM Sunday, Nov. 25.  As

stated earlier in this report, ALZETA had completed all in‐duct work that was scheduled.  

However, there remained approximately 8 hours of work to do outside of the duct including

piping the gas manifold, and installing the gas pilots, and the flame scanner mounting

hardware.  This work was completed during the day.

At about 5 p.m. on Sunday, a visual inspection of the burner modules via peepsites installed

on the duct revealed that one burner module (top row, 4th burner from wall) had suffered

some significant structural damage.  The top plate of the burner module had separated from

the rest of the box and had moved forward about 6 inches.  The burner surface material was

still attached to the burner, but since the premix enclosure that makes up the burner module

had been breached, this module could no longer be operated.  This first was observed

it was believed that only one

odule had failed, and the test would proceed with lightoff of the other modules later in the

week.

• Sunday Nov 25 ‒ Turbine was scheduled to go on‐line at 10 AM.  All “in duct” work

damage

approximately 7 hours after the turbine was started.  At the time,

m

 49 
Figure 24. ALZETA auxiliary panel for controlling of fuel valves for individual burner modules. 

Figure 25. Front view of completed assembly of burner modules. 

 50 
Figure 26. Final installation of perforated steel plate at bottom of burner modules. 

Figure 27. View of gas manifold, control 

valves, burner mounting plates, and pilot 

plate. 

Figure 28. View of far side of duct. The 

modifications required the addition of the 

two mounting posts at the center of the 

photo. 

 51 
The plant operators monitored the modules starting on Monday, and by Tuesday morning a

second module had failed.  Since visual access is limited, the condition of all the burner

modules was uncertain.  Since two modules had now failed, there was increasing concern over

the potential of causing damage to the exhaust duct or steam generator.  Hence, the plant

facility operators decided to shu t the turbine down on Tuesday evening and remove the duct

burner modules the next morning.   

ALZETA was at the jobsite for the removal of burner modules on Wednesday morning.  The

burner hardware was inspected inside of the duct prior to any removal activities.  But in order

to minimize downtime, all modules were removed by cutting with a torch.  Additional damage

was sustained beyond what occurred during startup and operation.  Before removal, it was

observed that damage had occurred to approximately half of the burner modules.  The decision

to shut down the turbine and remove modules was the correct decision.

Photos of the damaged burners are shown in Figures 29 through 31.  The most apparent

problem observed during removal was that a significant number of welds had completely

failed.  There was no evidence of metal fatigue nor was there any sign of distortion of the metal

parts around the welds.  This was particularly true for the extension boxes attached to the inlet

end of the burner modules.   

Figure 29. Example of damaged burner module. Damage was caused by top side of burner 

module breaking loose and tearing the burner face material. 

 52 
 
Figur aged burner m ame time as

Approx e modules were undam d. 

e 30. Photo of undam odule taken at s photo in Figure 27. 

imately half of th age

Figure 31. View of rear of duct burner. Note that the top of the right-hand module is missing an

the bottom of the left hand module has nearly se

d 

parated. Also note that the extension box is not 

in the photo because it is no longer attached to any of the burner modules. 

53 
The failure of the duct burner hardware after such a short time in the duct was a major

disappointment and a setback to the project.  Parts were shipped from the field site back to

Damaged hardware was returned to ALZETA and inspected.  The key defect was in welds

n

ure was optimized to

ge

e expense of system weight

odule weight would also require a redesign of the burner

ht 

ALZETA for evaluation.

3.6. Post-Test Analysis 

3.6.1. ALZETA Testing of Welds 

joining various sheet metal parts.  The fabrication procedures, weld processes, and installatio

processes were reviewed with the research team’s subcontractors.  The weld procedures were

insufficient for the duct burner service environment.  The weld proced

limit distortion of the parts rather than ensure structural stability.

A more rugged hardware design had to be developed.  Building everything with heavier gau

(thickness) material would allow for more substantial welds at th

and ease of installation.  Increasing m

support system.  The module and system weights as a function of thickness are summarized in

Table 8:

Table 8. Weight as a function of material gauge 

Material Thickness Module Weight Approx. System Weig

Gauge (inches) lbs lbs 

14 GA (0.0747) 33.1 500 

10 GA (0.1345) 59.6 900 

8 GA (0.1644) 72.8 1100 

3/16 plate (0.1875) 83.1 1300 

The existing design was reviewed, and several alternatives were developed.  Some further

development of the candidate designs is required to establish their impact on system

performance, installation interferences, and cost.

3.6.2. Review of Materials of Construction 

Also analyzed were the hardware design and method of fabrication.  Certain aspects of the

design must be maintained in order to achieve the research team’s performance objectives.  

Specifically:

s

n

• The design has to include a “premix section,” which requires that an enclosed duct with

sufficient mixing length be an integral part of the design.

• Within the premix section, a fuel injection system is required that efficiently distribute

and mixes the fuel and air.

• At the combustion end of the premix section, the design has to incorporate a porous

metal surface for the flame attachment.

Some design constraints are imposed by the need to meet these objectives.  The original desig

met these objectives, but was not sufficiently rugged.  Hence, future construction will include

54 
thicker gauge sheet metal parts and thicker and more penetrating welds.  Also, metal

e

n

rst demonstration can be used, but some modifications should be implemented.

along seam welds, an alternate method of burner

nded.  This method should provide more weld area

’s field demonstration.  

be

the flutter problem, it

to

and therefore stiffer, main support pipe for the modules be used.

e could occur over time.  This could lead to stress on the

a stiffer support pipe and the

addition of the space between individual modules in each row of burners.

• The distribution grid should be mounted to the duct walls and not to the individual

burner modules.  Space for thermal expansion should exist between the grid and the

modules.

reinforcement (such as gussets) may be added to critical areas.   

3.6.3. Liftech Analysis 

Liftech Consultants, Inc. of Oakland, California, a company with previous experience in the

structural analysis of duct burners, was hired to conduct a structural review of the design.  Two

initial areas for improvement were identified and evaluated:

1. The 7‐foot span of the main burner support is relatively long and could be subject to

significant deflection and vibration.  This suggests using intermediate beam supports

between the duct walls to support the burner assembly.

2. The duct baffles that were fabricated from perforated steel were attached to the duct

walls and to the burner modules.  It is preferable to support the baffles only from th

duct walls and to isolate them from the burner modules.

The Liftech analysis also concluded:  

• Stresses on the individual burner modules due to dead load and static TEG flow loads

were well within allowable limits.  The gauge of metal used and method of constructio

were most likely not the cause of the failure.  The general design approach used in the

fi

• Since localized failures were observed

module fabrication was recomme

and a reduction in stress at the weld.  This change was implemented and tested in the

research team

• Since dead load and static flow loads were well within allowable limits, failure could

have been caused by what Liftech referred to as “flutter.”  This refers to movement of

the boxes possibly due to unsteady loading caused by flow oscillations and could also

due to vibrations at resonant frequencies.  In order to deal with

was recommended that the back end of the burner boxes be separately supported

eliminate the cantilever that exists with the current design.  It was also recommended

that a larger diameter,

• It was recommended that the design be modified to include a space between each

module to allow for thermal expansion.  With no allowance for expansion, stresses can

be introduced to the modules.

• There was concern that high temperature creep (a permanent plastic deformation) of the

main burner support pip

individual burner boxes as the support pipe would sag due to creep.  The initial field

test did not last long enough for creep to occur.  However, it was recommended that this

problem be addressed in future demonstrations by using

55 
3.7. Project Rescope 

Following failure analysis and initiation of a redesign of the basic duct burner components,

ALZETA wanted to retest the new hardware at another field site prior to the end of the project.  

Cenveo was ruled out as a site for the retest.  The limited access to the burner hardware, except

during plant shutdowns over Thanksgiving and the Memorial Day weekends, made it difficult

for researchers to commit to a “one‐shot” redesign and retest of the hardware.

Other lower risk field test sites were identified and contacted.  Of these, most promising were

Stelter & Brinck and an HRSG manufacturer, both of which ALZETA had worked with in the

past.  Stelter & Brinck was the only company that could provide a location to test within the

authors’ project time constraints.  Hence an agreement between Stelter & Brinck and ALZETA

was prepared to allow immediate implementation and testing of the suggested redesigns.  

Testing was then performed at Stelter & Brinck at typical environmental conditions for an

industrial duct burner application.

Stelter & Brinck provided the additional advantage of also being interested in pursuing a

commercial agreement with ALZETA at the end of the demonstration.  It expressed an interest

in selling the burner into commercial hot air ducts as well as into gas turbines exhaust ducts.  

The design and testing of the modified duct burner hardware are discussed in the following

section.

.8. Design Modifications 

Based on Liftech analysis, a new burner module was designed and constructed to include the

following features:  

• Add support to the back end of the module to eliminate the “cantilever” and stabilize

the module vertically.  This would eliminate any “flutter” and unsteady loading due to

flow oscillations.  A bracket was added to the rear of each module for connecting to a

support pipe that installs in the duct, as shown in Figure 32.   

• The mounting arrangement between modules was modified to allow spacing for

thermal expansion.   

• Modules would be mounted on a stiffer and larger diameter support pipe.  In addition,

stress relief radiuses were included at the corners of the square feed‐through hole that

accommodates the support pipe.  These are also shown in Figure 32.  

• The flow distribution grid was mounded directly inside the duct and not supported by

the burner modules.   

• A new multiple injector pipe design (Figure 33) was developed to improve mixing and

eliminate the need for the extension box installed at the Cenveo site.  This eliminates

much of the mechanical loading experienced at Cenveo.

3

56 
Figure 32. New burner box manifold with bracket for rear support rod pipe. 

Figure 33. Three branched injector tee. 

57 
3.9. Stelter & Brinck Duct Test Facility 

A test duct at Stelter & Brinck in Cincinnati was used to fully simulate either a gas turbine or

industrial recirculation process heater.  The burner that provided the exhaust gas and heat to

the system, or turbine exhaust generator (TEG), was mounted upstream of the duct burners by

about 16 feet and provided up to 800°F of oxygen depleted air (down to about 16% O2) at

velocities typical of TEG applications.  A recirculation system, which brought flue gas back to

the first duct section, also allowed the O2 and duct velocity to be optimized for any given test.  

The facility is shown in Figure 34.

The facility included a burner section with removable wall to provide full access to the duct

burners so that any modifications could be easily implemented.  Also included were numerous

ports for measuring temperature, velocity, emissions, etc.  The open section, with the burner

modules ready for installation, is shown in Figure 35.   

Figure 34. Test facility at Stelter & Brinck. 

58 
59 

percent

Figure 35. Burner bank to be installed in duct. 

3.10. Test Results 

Commissioning activities were performed with inlet temperatures to the duct burners at 500°F.  

Both the upper and lower row of burners were easily lit by the ignition pilots.  The 500°F

temperature was chosen both as a moderate temperature condition to check out system

operation, as well as representative of a level that meets the low end of the air heater duct

burner operation requirements.

The first series of tests were also conducted at 500°F, with the TEG operating at about 15

excess air and 125 ppm NOx and 300 ppm CO.  Once both rows of burners were lit, a jet of

flame could be seen between the two rows of burners, as shown in Figure 36.   
Figure 36. Flames occurring in the gap between burners during testing. 

The burners were then taken out and inspected.  There was no evidence of damage, or a spot

te

fuel being entrained into the duct flow, which could result in flaming between

y formation.   

e system was restarted.  There appeared to be less of a jet

still a flame.  Some measurements wer at

te at he tem n °F tho in

measureme pres n

For e next s of te second open a erforat ate strip overlaid e

firs ne, als ached gap be the burners.  The le row “ yle” injec

which had b previously at enveo s installed.  For additional assurance

tha el wo be entrained or ted out e mixi anifold boxes, the placement of

the jector   mo owns 1⁄2” int burner   This ne nfigurat en

where the gas might be escaping from the mixing manifold boxes into the flow stream.  Despi

the fact that the 2.38 inch OD support pipe was blocking the 3.75 inch wide gap between the

burners, it was thought that this gap could be channeling and enhancing the duct gas flow

through this gap.  If so, a high‐velocity stream through this gap could entrain local gases at

higher static pressure, such as may reside at the entrance of the burner modules.  This could

result in some

the burners.  To address this possibility, and further block this gap to the duct flow, a strip of 30

percent open area perforated plate was inserted across this gap.  The injector jets on the top and

bottom rows of the three pronged injector “tree” were also turned 180 degrees so that the 0.10‐

inch diameter injection ports faced downstream, instead of upstream, into the flow.  Lastly, a

second, eddy‐dampening, 40 percent open area perforated plate was installed in the upstream

duct section, 20 inches in front of the burners, to damp any large‐scale edd

With the above changes made, th

between the burners,    but there was

n the sys

sure drop

e made

rough test

500°F inlet

mper ures, and t g including

nts of

was take

and emissio

up to 700

s.   

for more

th serie sts, a , 30% rea p ed pl was on th

t o o att at the tween doub H st tors,

een used the C ite, were

t fu uld not diver of th ng m

in tees was ved d tream o the box. w co ion th

60 
matched the configuration design in the previous installation, and no fuel bypassing was

expected.  However, upon restart, some flaming was still apparent between the rows of duct

burners.

In an attempt to both diagnose the problem as well as operate at different system conditions, the

research team decided to reduce the dilution air damper setting to reduce overall system flows.  

The system was stopped and restarted, such that a pilot measurement of velocity in the duct

was reduced to 0.45 inches w.c. from the original reading setting of 0.88 inches w.c.  When the

burners were relit, flaming between the burner modules was still present.  The flames were

different in that they appeared more yellow than before.  Out of concerns about possible

ystem was shut off before emission data measurements were taken.   

ular to

m, and none facing upstream.  The dilution air damper setting was

the

imulating burner and duct

flow

Table 9. Summary of test results 

Test 

# 

Preheat T 

(°F) 

Number 

of 

Burners 

Duct %O2

NOx ppm 

15% O2

CO ppm 

15% O2

Duct 

Burner dP 

in. w.c. 

Duct Burner 

SFR 

MMBtu/hr-f2

flashback, the s

The burner was once again removed, and a 3.5‐inch‐wide, solid plate was attached at the gap

between the burners, at the inlet plane of the burner boxes.  Also, the “H injector” tree

“branches” were turned 180 degrees so that all gas jet ports were facing either perpendic

the flow, or downstrea

returned to its original position for the final testing in the afternoon.  These final modifications

appeared to eliminate the flame in the gap, and testing proceeded.  At 500°F duct gas

temperature, a premix reading in the first burner module in the lower row was measured at 6%

O2 (wet) in the burner box.  This corresponds to about 45% excess air or dilution condition in

module upstream of the burner surface.

The inlet temperature to the duct burners was then taken up to 800°F.  Two data points were

taken, the first with 17.6% O2 in the upstream duct, and 14.2% O2 in the exit stream.  Another

premix measurement was taken at this point and indicated 7.5‐8% O2, wet, which corresponds

to approximately 65% dilution in the burner.  Measured input to the burners was 3.3 MMBtu/hr,

and the clocked gas flow was 8 MMbtu/hr total input to the TEG s

burners.

For the final test, the flue gas recirculation (FGR) damper on the dilution air line was opened to

allow some recirculation of flue gas products, and further reduce O2 levels in the duct.  Final

measurements, upstream of the burner, were 17.6% O2 in the duct, and 15.1% O2 in the exit.  The

measured first burner gas firing rate was 2.5 MMbtu/hr, and the measured duct burner gas

was about 2.3 MMbtu/hr.  A summary of test measurements is shown in  

Table 9.

1 500 Two 19.4 2.3 444 0.7 0.55 

2 700 Four 18.6 6.6 791 0.9 0.46 

3 500 Two 19.3 3.8 506 0.6 0.58 

4 500 Four 19.3 6.3 721 0.7 0.48 

5 800 Four 17.9 9.2 588 0.9 0.41 

6 800 Four 17.6 4.3 444 0.6 0.29 

61 
To reduce the NOx and CO data to their reported forms (ppm, dry, corrected to 15 percent O2),

  

Conclusions 

one row was operating, burner NOx emissions did not meet the

und with a fluctuating flame, the upstream

is lack of steady state conditions has

ion, making proper operation of the

e

locking and balancing flow between the burner modules.

stability and emissions, structural integrity

ting at Stelter & Brinck verified the

raw, uncorrected dry emissions data was taken for the first, or turbine exhaust gas generator

(TEG) burner, in the duct upstream of the burners.  These emissions were then corrected, on a

dry volume basis, to the new volume downstream of the burners after the duct burner fuel gas

had been injected.  These adjusted emission levels were then subtracted from the NOx and CO

emissions that were measured downstream of the burners.  This difference between the

adjusted upstream emissions and the downstream emissions was attributed to the duct burners.

Using the percentage O2 in the exit chamber, these emissions difference figures were corrected

to 15 percent O2.

Except for Test 1, in which only

sub‐3 ppm project goals.  Furthermore, in all tests, CO levels were very high.  The source of the

high CO production was not clear, and there was no time to investigate CO production

mitigation measures.

Operation of the burners appears to be sensitive to upstream pressure and flow conditions.  If

they are fluctuating, burner operation will be fluctuating, also.  This mode of operation can

produce high CO levels, related to both mixing and to the flame going on and off intermittently,

or attaching and unattaching, on the burner pad surface.  If the pressure field on the burner

surface is constantly changing or moving aro

pressures and flows will also be constantly changing.  Th

deleterious effects on both mixing and on flame stabilizat

burner a challenge. It is possible that forcing more flow through the burners would improv

operation, with the limit being all flow passes through the burners and there is no bypass flow.  

The options for this type of operation would need to be assessed.

Regarding the flames occurring outside the burners, the previous explanation of those

phenomena is the best explanation at this time.  Because this is not fully understood, a final

design would need provisions for b

In spite of difficulties encountered with combustion

of the redesigned hardware was demonstrated.  Tes

redesigned burner assemblies would withstand the duct environment with no structural issues.  

Ignition and combustion controls, which were never tested at Cenveo, did perform well.

62 
4.0 Conclusions 

This project developed and demonstrated an ultra‐low NOx supplemental firing burner system

for reheating turbine exhaust gas prior to a heat recovery steam generator.  Exhaust gas heating

is desired in cogeneration applications in that it permits more effective heat recovery from the

prime mover (turbine or engine) exhaust.  The higher gas temperature also provides greater

flexibility, as the amount of steam produced in the HRSG can be adjusted independently of the

gas turbine power demand.  This allows separate control of facility electric and steam (heat)

rs must also meet

ent was

cross‐section area, matching the typical incoming heat flux

eptually, the ultra‐low NOx supplemental firing duct

is project met the goals of emissions, heat output, and

nt

well as much more testing under actual conditions once

ot air heating applications can tolerate additional

pressure drop, using outside combustion air, or withdrawing process air from the duct and

externally premixing with fuel.  This would eliminate the issues with mixing with using

injectors installed in the turbulent duct environment, allowing banks of full‐scale burner

modules to operate much more like the conditions experienced in the pilot‐scale tests.  

Implementing external premixing would be straightforward using readily available equipment.

outputs.  However, as supplemental firing is applied in California, these burne

the strict NOx emissions standards being implemented throughout the state.

4.1. Achievements 

At both laboratory and pilot scale, in which a full‐scale supplemental firing burner elem

operated at typical TEG conditions, NOx and CO emissions of sub‐3 ppm (corrected to 15% O2)

were achieved.  In addition, the selected wedge‐shaped configuration offered greater than 2:1

burner surface area to duct

requirements for a HRSG.  Hence conc

burner technology developed under th

operating flexibility for plant operators seeking higher overall efficiency and more independe

control over steam (heat) and electric loads.

4.2. Turbine Exhaust Gas Environment 

Within simulated or actual turbine exhaust gas environments, however, performance was

disappointing.  Structural failure occurred at Cenveo where the full‐scale burner assembly was

subjected to actual turbine exhaust conditions.  In addition, under full‐scale simulated TEG

conditions, combustion stability on the burner surface was not always achieved, resulting in

high emissions and poor burner turndown.  A much greater understanding of the turbine

exhaust gas environment is needed, as

this environment is better defined.

4.3. Industrial Hot Air Environment 

This environment is similar to TEG in that the incoming stream is at elevated temperatures and

somewhat depleted of O2.  Again, at pilot scale, the supplemental firing burner module

demonstrated it could meet objectives when subjected to this environment.  However, at full‐

scale, the turbulent conditions resulted in poor combustion stability.  But in contrast to the gas

turbine environment, many industrial h

63 
4.4. Sales Potential in the Industrial Hot Air Market 

Stelter & Brinck reports a strong demand for ultra‐low NOx supplemental firing burners in the

NOx

also can affect the quality of products in the food industry and others.  With the structural

d en at Stelter & Brinck, and previous e d turndown performance proven

g pilot t roceed to the market assuming external premixing of

el and a

 Sale e Gas Turbine Exhaust Market 

ogenerat m efficiency and minimum pressure loss downstream of

rbine.  It premixing of the fuel and

additional as a more detailed

din and other pressure‐

g m ct flow, needs to be well understood before a product can be

zed for t

ugh the e redesigned modular burner system

ructura variations within the TEG environment

ed sta issions.  Providing a high‐efficiency ultra‐low NOx

r system quire the following, and these are the authors’

mendat tivities:

Develo onment and how to make flow more

unifor rch team attempted to minimize flow variations by

install increase flow resistance (a common means of

impro still too turbulent for

this ap e.   

Use sl air‐fuel premixing.  Pilot scale

demon en air and fuel flow rates were

stable. turbulent duct—the air flow inherently varies

widely. However, withdrawing TEG from the duct, externally mixing it with fuel, and

piping the premixed TEG and fuel back to the burner modules would be very similar to

the pilot scale test situation.  The authors developing a design for this approach

(which has not been done but should be straightforward) would lead to more rapid and

successful commercialization.   

process industries.  In addition to the need to meet more stringent emissions requirements,

esign prov missions an

durin esting, the product could p

the fu ir could be implemented.   

4.5. s Potential in th

The c ion market seeks maximu

the tu is, therefore, more difficult to justify adding external

air.  Hence,

understan

min

testing of in‐duct mixing techniques, as well

g of the performance tradeoffs associated with baffles

consu

ali

eans of stabilizing du

fin his market.   

4.6. Recommendations 

Altho testing at Stelter & Brinck verified that th

was st lly sound, the turbulence and flow

prevent ble combustion and low em

burne for CHP facilities will re

recom ions for future development ac

• p a greater understanding of the TEG envir

m within ductwork.  The resea

ing perforated metal plates to

ving flow distribution).  Yet, flow in a typical TEG duct was

proach to be effectiv

• ipstream combustion air and eliminate in‐duct

strated that ultra‐low NOx could be achieved wh

  This is not the case in a TEG

believe

64 
Glossary 

Specific terms and acronyms used throughout this work statement are defined as follows:

Acronym Definition 

acfm actual cubic feet per minute 

AFT Adiabatic flame temperature 

Btu British thermal unit 

cfm Cubic feet per minute 

CHP Combined heat and power 

CPR Critical project review 

CSB ALZETA commercial surface-stabilized burner product 

Dynamic 

Pressure 

Density multiplied by velocity squared divided by two gc

(ρ*v2

)/2gc

FGR Flue gas recirculation 

gc Gravitational constant. 32.2 (lbm-ft)/(lbf-s2) 

HRSG Heat recovery steam generator 

in. w.c. Inches of water column 

LNB Low-NOx burner (typically 20-30 ppm NOx) 

MBtu 1 thousand British thermal units 

MMBtu 1 million British thermal units 

MWe Megawatts electric power 

PIER Public Interest Energy Research 

ppm parts per million (usually on a volumetric basis) 

psig Pounds per square inch, gauge 

scfm standard cubic feet per minute 

SFR Surface firing rate of burner (Typical units are MMBtu/hr/ft2) 

TEG Turbine exhaust gas 

UCC.1 Uniform Commercial Code (Financing Statement) 

ULNB Ultra-low NOx burner (typically 15 ppm NOx or lower) 

VFD Variable-frequency drive 

65 
66 
67 

References 

1.  Vetterick, R.C. and Whitten, P.G., 1996. “Comparative Evaluation of Cogeneration Cycle

Alternatives.” EPRI Re‐powering Workshop, June 4‐5 1996. Washington, D.C.

2.  Resource Dynamics Corporation, Vienna, VA.  2003.  Cooling, Heating, and Power for Industry:

A Market Assessment.

3.  Chemical Industry Vision2020 Technology Partnership Challenge Technical Committee.

“Opportunities for Innovative Energy Systems in the U.S. Chemical Industry,” March 18, 2004.   

4.  ONSITE SYSCOM Energy Corporation, 2000. The Market and Technical Potential for Combined

Heat and Power in the Industrial Sector.”  Prepared for Energy Information Administration.