1

EPRI 2009 Heat Rate Conference 

Applying the Fundamentals for Best Heat Rate Performance of Pulverized Coal Fueled Boilers 

Dick Storm, Senior Consultant 

Storm Technologies, Inc. 

Abstract: 

Often overlooked are the factors that boiler combustion and performance play in the overall heat rate 

performance of pulverized coal plants. For example; a large utility boiler can be tested and found to be 

meeting the original design boiler efficiency by completing an ASME boiler heat loss method performance 

test. Yet the unit heat rate may be off design by over 300 Btu’s per kWh due to the non optimization of 

airflows, air in leakage, high desuperheating spray water flows to the reheater and superheater, auxiliary 

power consumption and/or non optimum steam temperatures (2, 3, 4, 5, 7, 23). In fact, there are at least twenty 

two operations and maintenance controllable heat rate factors that are controllable by excellence in O&M 

at the boiler (2). The top ten of these boiler operations and maintenance controllable variables (based on 

our experience) are: 

1. Air in-leakage into the boiler setting 

2. Pulverizer fineness, mechanical tolerances and tuning optimization 

3. Optimization of Primary, overfire air and secondary airflow measurement and control. 

4. Balanced fuel and air distribution into the burner belt 

5. Air heater leakage 

6. Reheater sprays 

7. Reheater steam temperature 

8. Superheat sprays 

9. Superheater Steam Temperature 

10. Carbon in Ash 

It has been the author’s experience that the average large coal fueled utility steam unit, on a given day, 

has about 300 to 500 Btu’s per kWh heat rate improvement potential (2, 3). 

This presentation will review some experiences and case studies of typical coal plants where the 

fundamentals of optimizing furnace performance have led to significant heat rate improvements. 

1.0 Introduction

Old coal fueled power plants are still the backbone of America’s base load power generation. The 

average age of the American coal fueled fleet is about 35 years. In 2007, coal fueled power plants 

produced about 49% of the total electric power generation of the United States. The plants are 

amongst the lowest cost of generation of electric power and are likely to be depended on for years to 

come. Reasonable cost electricity is an important factor for America’s economy and for industrial 

competitiveness. Therefore the efficiency of these old plants should be improved upon to be the best 

attainable. 

It has been the authors’ experience that many plants have significant opportunity for improvement in 

heat rate. This is illustrated by Figure 1, which has been taken from the July 23, 2008 report by the 
2

DOE/NETL, entitled “Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal-Fired 

Power Plant Fleet”. (24)

                     Source – NETL   

Figure 1 

This figure indicates a wide spread between the “Best” and the “Worst” performing plant heat rates. 

The purpose of this presentation is to show the opportunity to apply the fundamentals and achieve 

significant improvement in overall plant efficiency. 

Figure 2 on the next page is a figure that Storm Technologies, Inc. has used for years to illustrate the 

potential improvements by applying excellence in operations and maintenance.(3) This slide 

compares the design of the ASME historical power plant, Eddystone No. 1, which was designed for 

an overall thermal efficiency of about 41% to several periods from 1957 to present day. The world’s 

best most efficient plants even with extreme clean coal stack clean up auxiliaries are approaching 

41% again. Yet, we depend on an aging fleet of about 1400 old coal plants that could achieve heat 

rates of about 10,000 Btu/kWh or better, but often operate at about 10,500 Btu’s/KWh or about 32.5% 

thermal efficiency. 
3

There is Potential for Improvement 

Figure 2

With this background established of the potential improvement by applying the fundamentals, a few 

examples will be reviewed of the results that may be (and have been) attained by Applying the 

Fundamentals (2, 3, 5, 7, 10, 12, 15, 16, 18, 19, 20, 22, 23). 

Improved Heat Rate Results should begin with the optimization of the combustion process. 

2.0 Air In-Leakage – The Number 1 Stealth Heat Rate Penalty

Of course, this only applies to balanced draft systems. In our experiences, we occasionally are 

involved with pressurized furnaces, but I estimate that 90% plus of the pulverized coal boilers in 

operation, are balanced draft. 

Figure 3 – Combustion Airflow should be precisely measured and controlled. Any air that leaks into 

the setting after the furnace exit is of no value to combustion and is a loss in efficiency. The overall 

unit efficiency losses tend to compound one another and accumulate to very significant levels. 

Total equivalent leakages of air, from the furnace to the air heaters, has been documented to the 

range of 20% of the equivalent total air required for full load operation. See Figure 3 for typical 

locations of air in-leakage (3). 
4

Figure 3 – Typical Locations for Air In-Leakage 

This air in-leakage has resulted in significant heat rate penalties. Air in leakage and the resultant 

oxygen starved furnace further contributes to loss of capacity and reliability from the high furnace exit 

gas temperatures. Furnace oxygen starvation creates the reducing atmosphere which increases 

slagging, fouling and water wall metal wastage. 

In our experience, the heat rate penalty for excessive air in-leakage alone is often over 300 Btu/kWh. 
5

3.0 Combustion Airflow Optimization

Modern low NOX combustion systems typically have at least three air flow paths (excluding tramp air 

in-leakage). These are: Primary Airflow, Secondary Airflow and Overfire Airflow. The secondary 

airflow paths are often divided into at least two or more paths, of inner air or core air and peripheral 

air in a two air zone low NOX burner as shown in the figures below. 

All modern low NOX

burner designs internally 

stage combustion by 

deliberate separations of 

the air and fuel into 

zones. This separation 

of the airflow streams 

purposely reduces the 

flame intensity and 

lengthens the flames. 

Figure 3A

Some new generation low NOX burners have three or four secondary air zones, and some boilers 

utilize underfire air or boundary air for partial admission of portions of the combustion airflow to the 

burner belt. 

Forgiving

Sensitive

Unforgivin

g

Challenging !

70’s High 

Intensity Burner

First 

Generation 

Low NOX

Burner

2nd & 3rd Generation Low NOX

Burners w/ OFA / Staged 

Combustion 

20’ Flames

60’ Flames

Figure 3B 
6

The point attempted to be made here is the combustion airflow should be measured and controlled to 

each point of admission into the furnace. Or at least, know the total quantities of airflow being 

supplied to each major flow path; primary, secondary and overfire. The reason for knowing the exact 

airflow proportions is that there is limited time to complete combustion. Only one or two seconds. (1, 3, 

4, 5, 7, 8, 9, 11, 15, 19)

The residence time to combust pulverized coal fuel is only one to two seconds from the time a coal 

particle enters the furnace (from the uppermost burners), until the de-volatilized particles are 

quenched below the carbon char ignition temperature of 1,400° F as shown on Figure 4 below. 

Figure 4 

Because of this short time to completely combust the pulverized coal at a NOX compliant level, the 

airflow paths must be precisely measured and controlled. The schematic of typical airflow paths is 

shown on Figure 5. 
7

The fundamental fact of coal combustion, especially for bituminous coals is that the de-volatilized 

carbon char particles remaining after a pulverized coal particle enters the furnace will require a 

minimum of 1400°F and an oxidizing environment to complete combustion. Therefore, combustion 

must be completed before the burning carbon char particles enter the convective heat transfer section 

of the boiler. 

Figure 5 – Typical Air Flow Paths 

So what does airflow management have to do with heat rate? Plenty! Here are a few examples: 

• High primary airflow harms heat rate. This is especially true for bituminous fuels (total fuel 

moisture less than 10%) where significant tempering airflow is utilized as a component for 

primary air. 

• Why? Because the tempering airflow bypasses the air heater and in so doing, gives up the 

heat transfer of the exiting flue gas to exchange heat to that amount of combustion air in the 

primary airflow path. In essence, this is an increase in the stack dry gas loss, due to a 

slightly elevated flue gas exit temperature 

Even greater losses in efficiency from non-optimized primary airflow show up as high furnace exit gas 

temperatures which create heat rate penalties from a myriad of affects including: (1, 3, 4, 16, 19, 21, 22, 23)

3⁄4 High de-superheating spray water flows 

3⁄4 Increased slagging and fouling which requires more frequent sootblowing 

3⁄4 Increased ash cinder (popcorn) ash deposits to foul or plug the SCR or APH. 

These fouled surfaces then increase draft losses and increased fan power 
8

consumption, in addition to the increased frequency of soot blowing. Higher 

airheater differential also induces more airheater leakage. 

3⁄4 High primary airflow usually creates poor fuel fineness and poor fuel 

distribution which contribute to the above. Plus higher than optimum carbon 

in ash. 

3⁄4 The unit heat rate Performance deterioration tends to be compounded from 

the high furnace temperatures. The high temperatures promote slagging and 

fouling, which increases draft losses, which increase soot blowing, which 

create more SCR or ApH fouling which increases draft losses and thereby 

increases the air heater leakage and higher duct negative pressures create 

more in-leakage of tramp air. Fan power is increased, etc. Many factors do in 

fact, tend to multiply. 

Secondary airflows and overfire airflows are also important to be measured and controlled for best 

furnace performance. (4, 21, 23) Another subject is fuels flexibility. The more precise the airflow 

measurement and control is, the more tolerant a furnace is of fuels with lower fusion levels that 

accompany higher sulfur and iron levels. (5, 6)

The typical heat rate improvement opportunity for optimizing combustion airflow is in the magnitude of 

50-200 Btu’s/kWh. Not insignificant and at today’s fuel costs there is both financial and 

environmental incentives. 

4.0 What does Flyash Unburned Carbon Have to do with Heat Rate?

The heat rate penalty for Bituminous Flyash LOI (or Loss on Ignition) is roughly accepted to be about 

0.10% in efficiency for every 1.0% change in flyash LOI. In other words, if a boiler firing Central 

Appalachian coal with a 12,000 Btu/pound HHV and 10% ash has a 15% flyash LOI, the losses due 

to LOI when calculated by the ASME code will come out real close to 1.5 % in efficiency loss of the 

boiler for the heat loss component attributed to carbon in ash. If the steam plant is operating at a heat 

rate of 10,000 Btu’s/kWh, then the penalty could be expressed as 150 Btu’s per kWh. Seems simple 

enough. Now, if combustion optimization is applied to the pulverizers, mechanical tolerances and 

airflow, and the flyash LOI is reduced to about 5%, then the heat rate improvement would be roughly 

about 100 Btu’s right? Well maybe. 

 It has been our experience that when the flyash LOI is reduced significantly, as in this example, the 

heat rate improvement is often far better than the expected 100 Btu’s/kWh. Why? I have seen this 

many times and the explanation is this. When the pulverizer adjustments are made, the airflow 

proportions corrected, leakage repaired, and slagging reduced. Then there are a number of 

compounding factors that work in the favor of better heat rate. Among them: 

• Less soot blowing, so there is a reduction in steam consumption and steam cycle losses. 

• Less draft losses from cinders plugging the SCR or the Air Preheaters. So, there is less 

auxiliary horsepower required for the fans. 

• Less draft losses create less air heater differential between the entering air and leaving gas. 

This reduced delta of static pressures reduces airheater leakage rates. 
9

• As the fires are lowered in the furnace and active combustion is lowered down and out of the 

superheater and reheater, then there are less de-superheating water spray flows which are in 

themselves a large unit heat rate penalty. 

• Operations and maintenance personnel when working to reduce the flyash LOI become more 

aware of the other 21 O&M Controllable factors at the boiler and the overall heat rate 

improvement using flyash LOI as a precursor can yield improvements that exceed 

expectations from flyash carbon loss alone. 

5.0 Summary of Opportunities for Improvement

There are two lists that Storm uses as check lists to optimize combustion. They are the Thirteen 

Essentials and the 22 Heat Rate Factors Controllable by O & M. 

22 Heat Rate Variables 

1. Flyash Loss On Ignition (LOI) 

2. Bottom ash carbon content 

3. Boiler and ductwork air in-leakage 

4. More precise primary airflow 

measurement and control, by reducing 

tempering air 

5. Reducing pulverizer air in-leakage on 

suction fired mills 

6. Pulverizer throat size and geometry 

optimization to reduce coal rejects and 

compliment operation at lower primary 

airflows 

7. Secondary airflow measurement and 

control for more precise control of 

furnace stoichiometry, especially 

important for low NOX operation 

8. Reduction of extremely high upper 

furnace exit (FEGT) peak temperatures, 

which contribute to “Popcorn Ash” 

carryover to the SCR’s and ApH’s, High 

spray water flows, Boiler slagging and 

fouling, and high draft losses due to 

fouling. The high draft losses cause 

increased in-leakage, increased fan 

auxiliary power wastage and increased 

associated losses with the high spray 

water flows 

9. High de-superheating spray water flow 

to the superheater 

10. High de-superheating spray water flow 

to the reheater 

11. High air heater leakage (note: 

Ljungstrom regenerative airheaters 

should and can be less than 9% 

leakage) 

12. Auxiliary power 

consumption/optimization i.e., fan 

clearances, duct leakage, primary air 

system optimization, etc 

13. Superheater outlet temperature 

14. Reheater outlet temperature 

15. Airheater outlet temperature 

16. Airheater exit gas temperature, 

corrected to a “no leakage” basis, and 

brought to the optimum level 

17. Burner “inputs” tuning for lowest 

possible excess oxygen at the boiler 

outlet and satisfactory NOX and LOI. 

Applying the “Thirteen Essentials” 

18. Boiler exit (economizer exit) gas 

temperatures ideally between 650°F to 

750°F, with zero air in-leakage (no 

dilution!) 

19. Cycle losses due to valve leak through – 

i.e. spray water valves, reheater drains 

to the condenser, superheater and reheater drains and vents, and especially 

any low point drains to the condenser or 

to the hot well 

20. “Soot blowing” Optimization – or smart 

soot blowing based on excellence in 

power plant operation. (Remember, 

soot blowing medium is a heat rate 

cost, whether compressed air or 

steam) 

21. Feed water heater level controls and 

steam cycle attention to detail 

22. Steam purity and the costly impact of 

turbine deposits on heat rate and 

capacity 
10

Thirteen Essentials of Optimum 

Combustion for Low NOX Burners 

1. Furnace exit must be oxidizing 

preferably, 3%. 

2. Fuel lines balanced to each burner by 

“Clean Air” test ±2% or better. 

3. Fuel lines balanced by “Dirty Air” test, 

using a Dirty Air Velocity Probe, to ±5% 

or better. 

4. Fuel lines balanced in fuel flow to 

±10% or better. 

5. Fuel line fineness shall be 75% or more 

passing a 200 mesh screen. 50 mesh 

particles shall be less than 0.1%. 

6. Primary airflow shall be accurately 

measured & controlled to ±3% 

accuracy. 

7. Overfire air shall be accurately 

measured & controlled to ±3% 

accuracy. 

8. Primary air/fuel ratio shall be accurately 

controlled when above minimum. 

9. Fuel line minimum velocities shall be 

3,300 fpm. 

10. Mechanical tolerances of burners and 

dampers shall be ±1/4” or better. 

11. Secondary air distribution to burners 

should be within ±5% to ±10%. 

12. Fuel feed to the pulverizers should be 

smooth during load changes and 

measured and controlled as accurately 

as possible. Load cell equipped 

gravimetric feeders are preferred. 

13. Fuel feed quality and size should be 

consistent. Consistent raw coal sizing 

of feed to pulverizers is a good start. 

Myself and others in our company have presented numerous presentations, written articles for 

magazines and technical publications on the Storm approach to getting the “furnace inputs right” so I 

will not repeat the details here. The reference list at the end of this paper lists 23 publications or 

presentations on the subject “Optimizing Furnace Inputs”. Suffice it to say, we know they work and 

we have obtained good results by applying the fundamentals. 

A typical approach is shown on the Heat Rate Curve, Figure 6. 

Figure 6 
11

Figure 6 represents an actual case study of a 650MW, wall fired 2400 psi/1000°F/1,000°F unit. This 

was a coordinated effort by all of the O & M team, and Storm Technologies personnel using our 

testing and diagnostic techniques. Basically, the Heat Rate was improved overall by over 500 

Btu’s/kWh by a comprehensive approach to getting the boiler inputs optimized , feedwater cycle, 

condenser, cooling tower and balance of plant. By teamwork, the overall heat rate was improved 

significantly on two occasions. The high peaks were when attention was not applied to the boiler. 

I have been involved in many such successes as shown on Figure 6. Our approach works, when the 

O & M team all buys in and applies the fundamentals. 

How does a plant get started? 

Begin with a comprehensive diagnostic testing program that includes at least seven variables for 

measurement, then plan and execute the required maintenance operations to achieve results. See 

Figure 7a. 

Item Description Outage Provisions

1.0   Pulverizer & Fuel Line

Performance

Test Ports  Must be Installed  

1.1   Clean Airflow Balance  

1.2   Dirty Airflow Balance

1.3   Fuel Flow Balance  

1.4   Air‐Fuel Ratios  

1.5   Pulverized Coal Fineness

2.0   Primary Airflow Calibration

3.0   Secondary Airflow Distribution&

Control Accessibility & Testing Ports  are Required  

4.0   Excess O2 Probe Measurement

Accuracy Multi‐point test probes are Preferred  

5.0   Furnace Exit Gas Temperature &

Flue Gas Measurement  

Water & Air Supply Hoses & Fittingswill need to be  

prepared; Safe Test Platforms; TestPorts (test ports ‐ 

bent tube openings with observation / test door

assemblies)  

6.0  

Boiler Exit to Stack Flue Gas

Measurements; Air Heater

Performance; Boiler Efficiency &

Total SystemAir In‐leakage

Measurement  

Accessibility & Testing Ports  are Required  

7.0   Insitu Flyash Sampling & Analyses

for Sizing & unburned carbon  

Accessibility & Testing Ports  are required; Multi‐Point

Emission Sampling Systems by STORM TECHNOLOGIES

are suggested forease of testing/daily measurements  

Figure 7A 
12

PORT 6 PORT 1 PORT 2 PORT 3 PORT 5 PORT 4 PORT 6

NORTH DUCT SOUTH DUCT

PORT 1 PORT 2 PORT 3 PORT 4 PORT 5

PORT 1 PORT 2 PORT 3 PORT 4

PORT 1 PORT 2 PORT 4 PORT 3

PORT 6 PORT 6

PORT 1

PORT 2

PORT 1

PORT 2

PORT 4

PORT 3

PORT 5

PORT 3

PORT 4

PORT 5

NORTH DUCT

PORT 8

PORT 7

PORT 9

PORT 8

PORT 7

PORT 9

PORT 10 PORT 10

SOUTH DUCT

PORT 1 PORT 2 PORT 3 PORT 4 PORT 5 PORT 6 PORT 7 PORT 8

PORT 1

PORT 2

PORT 3

PORT 4

PORT 5

PORT 6

PORT 7

PORT 8

HVT

Over fire Air Compartments

Wind box 

Compartments

Coal Piping

Primary Air 

Venturis

Main Secondary Air Ducts

Economizer Outlet

PORT 1

PORT 2

PORT 3

PORT 1

PORT 2

PORT 3

PORT 4

PORT 5

PORT 6

Figure 7B Illustrations of Typical Boiler Performance Test Locations 

What are the rewards for Applying the Fundamentals? Well, if a 500 MW pulverized coal plant is 

operating at a heat rate of say 10,700 Btu/kWh and the heat rate can be reduced to 10,200 Btu/kWh 

the financial incentive is millions of dollars in fuel savings, plus the reduction in carbon dioxide. 

Typical opportunities are outlined on the table below. (2, 3, 4, 5, 7, 8, 21, 23)

Controllable

Variable

Qualities

Air In‐Leakage 200 Btu/kWh

Primary Airflow Optimization 50 Btu/kWh

Pulverizer Optimization and Improved Fuel Line

Balance 100 Btu/kWh

Reducing Air Heater Leakage 80 Btu/kWh

Reduced Coal "Pyrites" Rejects 40 Btu/kWh

Reduced Carbon in Ash 50 Btu/kWh

Reduction of de‐superheating spray water flows 50 Btu/kWh

Total: 570 Btu/kWh

Figure 8 
13

6.0 Summary

There are two observations that I have made over my 40+ years in this business. 1) During the 

60’s there was much attention to pulverizer coal fineness testing, air in-leakage testing, airheater 

tests and periodic unit heat rate tests. Plant Results Engineering staff focused on these tests and 

results. Back then, the boilers were often relatively new compared to the aging coal fleet we now 

depend upon. It has been my observation that there are less results engineering and test and 

results technicians employed in the plant staffs now, than there was 40 years ago. This would 

seem to be a missed opportunity for heat rate improvement, reduction of fuel costs and reduction 

of carbon emissions. 

2) The second point is that the boiler furnace duty has been increased since the 60’s and 70’s. 

There have been extreme measures to reduce NOX with the installation of low NOX burner 

systems. Fuels have been changed, many boilers designed for eastern bituminous fuels, now fire 

lower grade western fuels such as PRB. Exacerbating the challenge is the fact that often major 

plant overhauls have been changed from 6 months between boiler scheduled outages to 

sometimes more than 2 years. The overall reliability, considering the NOX changes, extended 

time between overhauls and fuel changes, are remarkable and noteworthy accomplishments. 

However, these accomplishments could, in the author’s opinion be made even better with more 

attention to applying the fundamentals to the furnace performance. 

As a third party observer experienced in the art of coal power generation, a fair question occurs to 

me: Is it now time to apply the fundamentals of getting the furnace inputs optimized and driving 

maintenance work orders from actual diagnostic tests? 
14

REFERENCES 

[1] “Getting the most from Boilers” Stephen K. Storm, 

Industrial Fuels & Power Magazine, December 2008 

[2] “The Fundamentals of Combustion & “The Apples 

Approach to Optimization”. Stephen Storm, Power Plant 

Summit, 2008 CII, Sponsored by the U.S. DOE, NETL and 

U.S. AID, New Delhi, India 

[3] “Large Electric Utility and Combustion Performance 

Improvements Short Course” – Storm Technologies, Inc., 

2008 

[4] “The Extreme Importance of Total Air & Fuel Flow 

Measurement on a 450MW B&W Wall Fired Unit firing high 

sulfur fuels”. Electric Power Conference 2008 May 7th, 2008, 

Baltimore, MD. 

[5] “Maximizing Plant Performance” - Stephen Storm. 

Presentation at Clyde Bergmann’s Boiler Cleaning 

Symposium, 2008 

[6] “Quality Counts – A look at different ways to measure 

coal quality” Stephen Storm, WORLD COAL MAGAZINE, 

March 2008 

[7] “A Review of the Importance of Measuring and 

Controlling the Furnace Inputs on a Typical PC Fired 

500MW boiler” R.F. Storm, Stephen Storm, POWER 

MAGAZINE, October 2007 

[8] “To Optimize Performance, Begin at the Pulverizer” R.F. 

Storm, POWER MAGAZINE, February 2007 

[9] “Apply the Fundamentals to Improve Emissions 

Performance” R.F. Storm, POWER MAGAZINE, October 2006 

[10] “Achieving Simultaneous NOX & Combustion 

Improvements on a 90 MW CE Unit by applying the 

fundamentals” Stephen Storm; Storm Technologies, Inc.; 

PWR2006-88157, Electric Power 2006 

[11] “Vertical Spindle Pulverizer Optimization” Stephen 

Storm; Storm Technologies, Inc.; PWR2006-88156, Electric 

Power 2006 

[12] “NOX Reduction without Low NOX Burners” Stephen 

Storm; Maureen Moss (Southern Company). (Electric Power 

2005) 

[13]”Testing Improves Results,” Stephen K.Storm, Daniel S. 

Storm, Sammy Tuzenew, Adam McClellan; Storm 

Technologies, U.S. Review of how testing can be utilized to 

optimize old PC fired boilers; World Coal Magazine, September 

2004 

[14]”Testing Improves Results,” Stephen K. Storm, Daniel S. 

Storm, Sammy Tuzenew, Adam McClellan; Storm 

Technologies, U.S. Review of how testing can be utilized to 

optimize old PC fired boilers; World Coal Magazine, September 

2004 

[15] “Practical Diagnostic Tests to Identify Opportunities to 

improve heat rate, reliability and capacity on large 

pulverized coal fired boilers,” R.F. Storm, Danny Storm, 

Adam McClellan, NTPC Thermal Power Generation 

Conference, 2003 New Delhi, India. 

[16] Opportunities for Improvement of Controllable Heat 

Rate Variables at the Boiler. Are these Really “Stealth” 

Losses or Simply Correctable by Applying the 

Fundamentals? R.F. Storm, EPRI Conference, 2005 

[17] “Conducting a Comprehensive Diagnostic Test on a 

Pulverized Coal Fueled Boiler; Richard F. Storm, Stephen K. 

Storm, Sammy Tuzenew; World Coal Magazine, September 

2003. 

[18] “Three Years Operating Experience at a Low NOX 

Limit of .33lbs/MMBTU with Flyash Carbon Content Less 

than 5%,”,” Richard F. Storm, Glenn Burney, Ervin Carden, 

3rd Annual Conference on Unburned Carbon on Utility Flyash - 

Sponsored by the U.S. Department of Energy. May 1997. 

Pittsburgh, PA. 

[19] “Performance Combustion and Reliability 

Optimization of a 360MW Unit, Firing 90% Pulverized Coal 

and 10% MSW,” Richard F. Storm, William Furman, Jay 

Chesser, T.J. Reilly, POWER-GEN, 1996. 

[20] “A Comprehensive Common Sense Approach to Low 

NOX Combustion in Pulverized Coal Fired Boilers,”

Richard F. Storm, IJPGC, ASME technical Paper, 1996. 

[21] “Performance Optimization of a Boiler Equipped with 

Low NOX Burners,” Richard F. Storm, Glen Burney, Mike 

Gallagher, Mark Lanseidel, POWER-GEN, 1995. 

[22] “Optimizing Combustion in Boiler with Low NOX 

Burners,” Richard F. Storm, POWER Magazine, October 

1993 

[23] “Optimizing Boiler Air & Fuel on a 450 MW Coal Fired 

Boiler,” Patrick McGowan, Barry Pulskamp, Richard Storm 

University of Kentucky Coal Conference, April 1991 

[24] “Reducing CO2 Emissions by improving the efficiency 

of the existing Coal-Fired Power Plant Fleet,” DOE-NETL, 

July 23, 2008.