Practical Considerations for Converting Boilers to Burn Natural Gas

Nathaniel S. Schindler

Allen Adriani

Combustion	Components	Associates,	Inc.	

ABSTRACT

Pulp and paper mill engineers and operations managers will benefit from the practical guidance provided to assess 

their facility to use low cost natural gas in their boilers. Basic principles of burning natural gas are discussed along 

with impacts on the current equipment. The differences associated with converting major power boiler types -- 

package boilers and field-erected wall and t-fired units – are reviewed. Other boilers – biomass and coal stokers, 

recovery boilers, and fluidized bed boilers -- can utilize natural gas as an auxiliary fuel for startup or load carrying 

capacity. The paper includes options and limitations related to keeping your current fuel for use during emergencies 

or in the event of market changes. Standards for safety and controls are reviewed. Emission control methods 

associated with natural gas are also discussed. Meeting NOx permit limitations can be a significant factor in the cost 

of converting a boiler to burn natural gas. Any calculation of the return on investment and determination of the 

feasibility of converting to natural gas must incorporate NOx emissions and associated control technologies to be 

accurate. 

1 INTRODUCTION:

Conversion to natural gas is an important opportunity in the pulp and paper industry today. Energy costs represent a 

significant portion of fixed costs for pulp and paper mills and the reduced cost and complexity of firing natural gas 

can add to the mills profit. Returns on investment of 1 year are not uncommon, making natural gas conversions 

attractive, even in these times of lean capital expenditures. But not all projects are equal. Mills have been seeking 

feasibility studies to determine the practicality and cost considerations of switching to natural gas. This paper 

presents some of the technical considerations of implementing a natural gas conversion. 

 Comparison of natural gas combustion properties; 

 Natural gas emissions fundamentals; 

 Common uses for natural gas at a pulp and paper mill; 

 Basic requirements of all natural gas conversion projects; 

 Special considerations with respect to boiler configurations; 

 Safety, controls, and NOx reduction techniques. 

2 NATURAL GAS PROPERTIES

This section of the paper will briefly touch on the general differences between burning natural gas and burning other 

fuels. Mechanisms of generating emissions by burning natural gas, particularly NOx, will be discussed. A general 

overview of the effectiveness of NOx reduction methods is also provided. 

2.1 Impacts to Existing Equipment

Converting from coal, oil, or biomass to natural gas changes stoichiometry, combustion air requirements, and the 

total combustion products. All of these impact the impact existing equipment, including FD and ID fans. The 

change in combustion product temperature, quantity, and composition affect the velocities and heat absorption 

within the boiler, superheater and economizer. 

During a feasibility study, the existing heat transfer surfaces must be evaluated to avoid high temperatures, to 

maintain adequate temperature differentials in the boiler walls, and to preserve proper boiler circulation. The 

differences between current operations and anticipated operation on natural gas should be thoroughly reviewed early 

in the project. Actual steam output firing natural gas can be reduced relative to other fuels in the same boiler. 

Natural gas flames produce lower radiational energy when compared to oil, coal and most other fuels. Therefore, 

radiant heat transfer in the lower furnace is lower for natural gas and convective heat transfer is increased through 

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the superheater. Boiler tube modifications may be required to maintain existing steaming capacity. Assess this 

early in the project so that capital costs of modifications and steam capacity limits can be accurately assessed. 

2.2 Fuels

Many different types of fuels can be burned inside a boiler. Biomass, coal, oil and gas are among the common fuels. 

Table 1 compares natural gas to these fuels. NFPA 85 defines natural gas as a gaseous fuel that is comprised of 

methane, propane, ethane and butane with a heating value of between 700஻்௎

ௌ஼ி

 and 1000஻்௎

ௌ஼ி. 

Table 1: Typical Fuel Combustion Properties 

Fuel 

Type 

HHV 

BTU/LBm 

Mass Air to 

Mass Fuel 

% Excess 

Air 

Typical 

Boiler 

Efficiency 

Natural 

Gas 

≈ 21,000 17.23 10-15 82-84% 

#6 Oil ≈ 18,100 10.63 10-15 85-88% 

Coal 11,000-13,000 10.7 25-30 84-86% 

Biomass 7,300-9,000 4.8 25-32 84-86% 

2.3 Emissions Formation Fundamentals

Boiler emissions have, during the last thirty years, come under the scrutiny of not only the U.S. EPA but also local 

and state governments. Solid and liquid fuels typically are highly regulated for a variety of emissions, including 

opacity, particulate, oxides of sulfur (SOx), mercury, nickel, carbon monoxide (CO), volatile organic compounds 

(VOCs), and NOx. Many of these pollutants are a result of components in the fuel or difficulties with combustion. 

Modern natural gas supplies have very few contaminants that cause pollution. Modern natural gas burners are well 

adapted to burn cleanly and completely. The primary pollutant of concern is NOx. CO and opacity are typically 

regulated because NOx reduction techniques, as discussed below, focus on reducing the flame temperature and can 

result in elevated CO or opacity. Opacity is typically not an issue with gas. When burning gas, VOC and particulate 

rates can often be higher at the FD fan inlet then at the boiler outlet. 

2.3.1 Thermal NOx.	 	 By reducing combustion temperature, the production of NOx can be reduced. NOx 

formation is a function of temperature. The higher the combustion temperature, the greater the NOx produced. 

During the combustion process, the majority of the NOx is formed after the flame front (Borman, 1998), termed 

thermal NOx. The Zeldovich mechanisms are the six mechanisms for thermal NOx production (Borman 1998):		

 O+N NO+N 2  (0.1) 

 N+O NO+O 2  (0.2) 

 N+OH NO+H  (0.3) 

The reactions are shown in the order in which they occur, with the first reaction dominating. The other reactions 

depend on completion of the first. When combustion temperature is lowered, the first equation will have a slower 

reaction rate. The rate of formation for the first reaction is given by the following equations (Heywood, 1988): 

 

          

        

1 21 2 2

23 3

d NO k O N k NO N k N O

dt

k NO O k N OH k NO H

 

 

 

  (0.4) 

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          

        

1 21 2 2

23 3

d N k O N k NO N k N O

dt

k NO O k N OH k NO H

 

 

 

 

 (0.5) 

The forward and reverse rate constants are denoted as kn. At lower temperatures there is less activation energy in 

the mixture and thereby the rate of NOx formation is reduced. Temperature, molecular surface area and 

concentration all influence the activation energy level (Kuo, 2005). Since the physical surface area of the molecule 

cannot be changed, temperature and concentration become the controlling factors to reduce NO and NO2. 

When the reaction rate is reduced by temperature, the first mechanism reduces the concentration of NO and N. This 

reduces the potential reactants in the second mechanism. Therefore, a reduction of temperature for the first reaction 

introduces a limiting factor for NOx emissions. For that reason, the objective of the technology to be applied is to 

reduce thermal NOx by lowering the reaction temperature. 

CO emission is effected by combustion temperature and excess air. When combustion temperature is too low, CO 

will not burnout reducing boiler efficiency. When excess air is insufficient, the CO emissions will increase because 

O2 is insufficient to complete the reaction of CO to CO2. There is a range of excess air that is optimal to minimize 

both CO and NOx emissions. 

2.3.2 Prompt NOx.		Ultra low NOx is not merely a name change from low NOx. Ultra low NOx is usually defined 

as less than 10 ppm NOx corrected to 3% O2. The important difference is that below 10 ppm, prompt NOx

mechanisms, not thermal NOx mechanisms, dominate the formation of NOx. Prompt NOx is formed by the reaction 

of nitrogen from the combustion air with combustion radicals formed at the outset of the combustion process in the 

fuel rich zones. Prompt NOx occurs almost instantaneously and cannot be controlled by reducing peak flame 

temperature, hence the apt name “prompt”. 

NOx emissions lower than 10 ppm are not achievable through the use of staged fuel and air low-NOx burner designs. 

A complete change in the burner concept is required to reduce or eliminate prompt NOx. Ultra low NOx burners that 

rely on high volumes of flue gas recirculation (FGR) (typically recirculating 30% of the flue gas mass or more) have 

been developed for single burner boilers or two burner unison fired boilers. Selective catalytic reduction (SCR) can 

be a cost-effective alternative to Ultra-Low NOx burners because of technical and control limitations on multi-burner 

boilers with pre-heated air. 

3 POWER BOILER MODIFICATIONS

3.1 Package Units

Package boilers are probably the easiest to convert to natural gas. Typically, package boilers at pulp and paper mills 

are backup or standby boilers available for use in the event of an emergency or boiler shutdown. Package boilers 

range in size from 10,000 pounds per hour steam to 250,000 pounds per hour steam. They are designed to be 

constructed completely in a factory and transported to the site in a package. Many industrial units are designed to 

generate 125 psig steam. Two package unit designs are prevalent in the United States -- firetube and watertube 

boilers. Firetube boilers usually generate less than 50,000 pounds per hour steam. Watertube package boilers are 

available up to 250,000 lbs/hr steam output. They are typically provided with one burner, but occasionally with two 

burners on a larger unit. 

The biggest distinction between a package watertube boiler and larger multi-burner units is that package units 

almost never utilize an air heater to preheat combustion air. This helps keep the size of the unit small, but comes at 

a cost. Using ambient combustion air lowers the overall efficiency of package units compared to preheated 

combustion air units, sometimes as an alternative to an air preheater a more expensive economizer can be added to 

improve efficiency. Ambient combustion air units have lower NOx than preheated combustion air units because the 

cold air lowers the peak flame temperature. This past spring, some mills utilized their gas-fired package units as 

baseload boilers because the low cost of natural gas justified their operation despite a lower efficiency than their 

field erected coal units. 

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Package units typically burn 

either natural gas or fuel oil. 

Other liquid and gaseous fuels 

can be burned in package 

burners as waste fuels or 

auxiliary fuels. Package boiler 

burners are relatively 

standardized in designs for fuel 

oil and natural gas. A new 

burner or burner modification 

can be relatively easily 

implemented. New fuel and air 

staged burners can be longer, so 

windbox modifications or new 

windboxes are often required for 

new burners. Most oil burners 

can be modified with a 

replacement fuel gas assembly in place of the oil burner. Low NOx burner modifications can include a low NOx gas 

manifold that also retains the capability to fire oil. (Figure 1.) 

Natural gas combustion is slightly less efficient than oil combustion because of the latent heat in the exhaust gas. 

However, the oil combustion air supply is often sufficient for gas firing because oil burners require a higher excess 

air level to complete combustion and reduce opacity than gas. 

If the package unit is designed to burn #6 fuel oil, consideration should be given to converting to #2 fuel oil as a 

backup fuel. A gallon of #2 fuel oil is more expensive than a gallon of #6 fuel oil; however, the overall costs of 

handling #2 fuel oil as a backup fuel can be lower. #2 fuel oil is easier to handle, burns better in the tight furnace of 

a package unit, and does not require heating. If the oil is expected to be burned only rarely, the high heat value 

components of #6 fuel oil can volatilize leaving a viscous slurry that is difficult to burn when needed. Low NOx #6 

fuel oil (~0.25 lb/mmBtu) and low NOx #2 fuel oil (~0.1 lb/mmBtu) atomizers are available. Because of the high 

sulfur content and other fuel components, #6 fuel oil is not compatible with ultra low NOx burners. 

3.2 Field Erected Units

Multi-burner field erected units are distinguished from package units by: 

 Preheated combustion air; 

 Capability to burn pulverized coal, and 

 Multiple, independently controlled burners. 

Preheating the combustion air with a flue gas air heater provides a significant performance benefit. It enhances 

efficiency because more energy is recovered from the unit so less fuel energy is needed to produce a unit of process 

heat. Coal can be efficiently burned in a field erected unit because the preheated air reduces the energy required to 

complete combustion. One disadvantage of pre-heated air is the relatively higher NOx emissions from heated air gas 

burners relative to cold air units. Therefore, the need to reduce NOx emissions may be a significant factor in your 

conversion of a multi-burner unit. 

Many paper mills considering conversion of existing coal-fired multi-burner units are also evaluating purchase of 

gas and oil fired package units. If a mill is willing to commit to natural gas for all its fired energy requirements, then 

purchasing new package units may be cost-effective. However, dual fuel gas and coal or even multi-fuel gas, coal, 

and oil burners are available and can be a solid investment for the mill’s future, providing flexibility amidst 

fluctuations in the energy market, maintaining high boiler efficiencies, and reducing capital costs of the conversion. 

The new environmental regulations calling for reduced CO emissions from coal fired boilers are a concern. An 

investment in gas burners can help provide flexible, low-cost energy, while meeting the strictest of regulations. 

Figure 1: Low NOx Gas Manifold

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Multi-burner boilers are typically arranged in two ways, wall-fired and tangent or corner-fired. Burners on wallfired units are arranged in rows and columns on one or more walls of the boiler. The burners are designed to create 

and maintain their own flame. Tangent fired units are designed with burners located in each of four corners on a 

single level. All four burners on a level are designed to fire together and create a swirl zone in the center of the 

furnace with a single stable flame. 

3.2.1 Wall‐fired field erected boilers. Wall-fired burners are typically round. They can be fired from a single 

wall or opposed fired. They can be arranged on a single level or multiple levels. Wall-fired burners have integrated 

registers or dampers to balance air to each burner and isolate burners that are not firing. These mechanisms help to 

ensure that each burner has a good fuel to air ratio under a 

variety of operating conditions. Typical natural gas 

pressures at the burner are 12 to 15 psig. The existing 

burners can often be modified to accept a low NOx natural 

gas burner manifold in the center. This permits reuse of 

dampers and actuators and reduces installation cost and time. 

Even when the register must be replaced, burner throat 

pressure parts are not usually required to convert a coal or oil 

burner to natural gas. Low-NOx gas burner retrofits capable 

of burning coal and oil are available. (Figure 2.) 

Low NOx natural gas burners rely on fuel and air staging to 

reduce peak flame temperature. Therefore, low NOx natural 

gas flames tend to be longer and wider than older coal or oil 

flames with the same heat input. Burner flame length can be 

reduced by increasing pressure drop through the burner. The 

FD fans on most coal boilers have sufficient capacity for a 

natural gas burner, even with a higher pressure loss. However, this should also be evaluated during the feasibility 

investigation. 

On the other hand, low NOx natural gas burners offer significantly higher turndowns than coal or oil burners. 

Natural gas burners are capable of 10:1 turndown, while oil burners are limited to approximately 6:1 and coal 

burners are limited to 3:1. Therefore, if the plant is eliminating coal, the total number of burners can sometimes be 

reduced. The cycling of burners in and out as load swings can also be reduced. Also, for two burner multi-burner 

units, unison firing should be considered. The safety system and controls become much less complicated, reducing 

overall project cost. 

3.2.2 Tangent fired field erected units. Tangent fired or corner fired units are multi-burner boilers with 4 

burners per level, one in each corner per level, and 

perhaps multiple levels. The burners are arranged to 

produce a single swirling flame. Unlike other burner 

arrangements in which each flame is independent, 

tangent fired burners are designed to have interacting 

flames supporting combustion across the furnace. Each 

corner has buckets providing combustion air and fuel 

into the furnace. Tangent fired burners often can tilt to 

move the fireball up or down to control steam 

temperature. Tangent fired burner designs also permit 

firing of coal, oil or gas. All three fuels can be readily 

integrated with burners in the same corners. (Figure 3.) 

Because of the relatively higher turndown of natural 

gas, adding and removing burners as load changes is 

minimized; in some cases all burners can be left in 

service all the time.

Modifying a tangent boiler to burn natural gas, 

especially if it is burning oil as a primary fuel, should be 

Figure 2: Wall Fired Multi Fuel Burner

Figure 3: Tangent Fired Multi‐Fuel Burner

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considered a priority because of the low cost of modifying the burners and the high cost of oil. Modifications to the 

circulation system to reach full load firing gas are not uncommon. However, incorporating natural gas buckets 

requires minimal modification to the existing corner buckets. The current coal buckets and oil burners can be 

retained often with no changes. On tangent fired coal units, oil igniters providing 10% of the heat input are typical. 

These igniters can be used to warm up the boiler and support combustion of the coal. Replacing these igniters with 

natural gas igniters can provide a significant return on investment. During low demand periods, low-cost natural gas 

igniters are often a cost-effective means of keeping the boiler warm. When firing natural gas alone, the mill can 

shut down the coal mills, feeders and other coal equipment, saving energy and operating costs. 

Low NOx gas and coal modifications are possible by incorporating current generation swirlers to stabilize a core 

flame and enhance fuel staging. We are not aware of any commercially available ultra low NOx burners for tangent 

fired units. 

3.3 Auxiliary Fuel Boilers

Paper mills often have hog fuel or coal stokers, fluidized bed boilers, and liquor recovery boilers. Many of these 

boilers have oil igniters or starting guns that can be modified to burn natural gas. These boilers also have the ability 

to supplement load capacity through upper level natural gas burners, maximizing the uptime of these units. When 

these boilers have existing auxiliary burners capable of oil firing, it is generally straightforward to convert and 

follow many of the same principles as multi-burner boilers, discussed above. 

3.3.1 Stoker units. Stoker units burn solid fuel on a grate. Typically, the solid fuel is hog fuel (a biomass 

product) or coal. As part of the combustion air system for the grate fire, over-fire air is incorporated above the grate 

to complete combustion and reduce CO emissions. The grate over-fire air is not to be confused with over-fire air for 

NOx emissions control. Auxiliary fuel burners capable of burning oil or gas can be installed above the grate. The 

burners can be arranged as tangent fired units or wall units. A significant difference between stoker units and multiburner units is that the grate must always be kept cool with undergrate air. When burning fuel in the auxiliary 

burners, the undergrate air impacts the fuel to air ratio and total excess air. Air to the grate must be controlled while 

firing natural gas to keep NOx emissions low while ensuring complete combustion. Emissions from auxiliary 

burners on stoker units tend to be higher than similar sized multi-burner units because of the higher excess air 

requirement to keep the grate cool. FGR can sometimes be used to cool the grate when firing natural gas. Natural 

gas burners on stoker units usually will not be able to supply the same steam output as the solid fuels due to the 

reduced radiant heat transfer in the lower furnace. Auxiliary heat input above approximately 50% of design heat 

input will likely require modifications of the superheater and circulation system, so a boiler study is necessary. If 

low emissions are critical, a CFD model can be a useful tool to identify the cost-effectiveness of various emission 

technologies.

3.3.2 Fluidized bed boilers.	 	 Fluidized bed boilers utilize oil or natural gas duct burners and lances for 

warming the bed and starting the coal or biomass main fuel. Duct burners are used to preheat the furnace to the 

auto-ignition temperature, which ignites the lance burners. The lance burners warm up the boiler and bed material 

and ignite the solid fuel. Once the solid fuel is fired, the duct and lance burners are shut off. Converting the duct 

burners from oil to natural gas is relatively straightforward. Converting the lances from oil to natural gas is more 

complicated. The auto-ignition temperature of natural gas is greater than the auto-ignition temperature of oil, so 

startup times may be increased to reach the solid fuel starting temperature.

3.3.3 Recovery boilers. Recovery boilers utilize liquor generated in the paper making process to generate 

steam. Auxiliary burners are utilized in recovery boilers for a couple of purposes. The primary purpose is as a 

startup gun, typically at the secondary air level above the bed. These burners are essential to the proper operation of 

the boiler. They are used for warm-up of the boiler and the furnace so that the liquor will burn. They are also used 

during shutdown to burn out the bed and reduce the liquor content. Furnace openings at the starting burner elevation 

are often small to limit leakage air through the burner openings when not in use. Starting burners also lack 

sophisticated fuel and air control and air enters the furnace through a variety of openings. Therefore, emissions from 

starting burners are often higher than from load burners.			

Load burners are typically located on the tertiary air level high in the furnace. They often have an independent 

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ambient air combustion supply. Load burners can be installed as wall burners or tangent burners. Most of the time, 

existing port openings and registers for oil burners can be reused. Recovery boilers without existing load burners 

usually have sufficient height to incorporate new load burners. These are often designed for about 50% of boiler 

design steam output. Heat transfer from the load burners to the lower furnace will be limited by the high elevation 

of the burner in the boiler and the limited luminosity of the gas flame reducing heat transfer to the lower furnace. 

Class I igniters are typical for startup and load burners, which scan the igniter only as more repeatable in the 

dynamic furnace environment of a recovery boiler. Flame detection of the igniter is also less susceptible to 

interference from slag from the liquor process. Class 1 igniters can also be utilized to verify combustion of waste 

gases in the auxiliary burners. 

4 SAFETY, CONTROLS, AND EMISSIONS

Natural gas safety systems are specialized to avoid boiler explosions by controlling when fuel can be let into the 

furnace. Controlling the fuel and air ratio properly is also essential to avoid boiler explosions, increase efficiency, 

and meet emission requirements. If your state has NOx limits of 0.1 lb/mmBtu or less, NOx control technologies will 

probably be required for preheated combustion air units to meet permit requirements. Implementing NOx control 

technologies are often similar in cost to modifying the burners. If NOx emission levels less than 0.04 lb/mmBtu is 

required, emission controls can double the cost of the project. 

4.1 Safety

Natural gas safety standards have been well developed of the years by the National Fire Protection Association 

(NFPA), Factory Mutual (FM) and BLRBAC. NFPA 85 is an industry standard for the burner management system 

of single burner and multi-burner gas and oil burners, duct burners, pulverized coal burners and fluidized bed 

burners. In many states, NFPA requirements have been adopted as regulatory or legal requirements. NFPA 85 was 

completely revamped around 2000 and has been updated a few times since then. Adding natural gas burners will 

require modifications to the existing burner management system to incorporate the necessary interlocks and startup 

sequence for gas firing. On older systems, a completely new burner management system may be required along with 

upgrades to the oil, biomass or coal safety systems. In addition, NFPA 54 provides standards for natural gas piping 

design. At some point in the project the insurance carrier must be involved to insure a smooth project and eliminate 

rework. 

FM has many standards and general requirements that apply to natural gas burner and piping systems for single and 

multi burner boilers. For the most part, these requirements are consistent with NFPA 85. FM also provides approval 

of certain products used in the natural gas firing system. These products include the safety shut-off valves, flame 

scanners, and pressure switches. BLRBAC has also produced some helpful recommendations for black liquor 

recovery boilers. Specific recommendations for auxiliary fuel firing and waste fuel firing provide useful information 

about the requirements of safely firing natural gas or waste fuel in a black liquor recovery boiler. 

Natural gas pipelines for paper mills are often brought in at pressures up to 600 psig to keep line size small. This 

pressure will need to be reduced and controlled to a pressure of 12 to 25 psig at the natural gas burner. Local 

building codes or insurance requirements may limit the pressure of the gas piping in the building. Safety control 

valves are limited to pressure ratings in accordance with FM test procedures. Pneumatic valves are typically rated 

for 130 psig. Motorized valves that don’t require instrument air to operate are rated to 40 to 60 psig. Pressure 

regulating valves and safety relief venting valves are a required part of most natural gas piping systems. Lead time 

on these devices is often around 16 weeks and is typically the critical path item for a conversion project. 

Due to the dangers associated with the explosive nature of natural gas, implementing operating and maintenance 

systems to verify the continued integrity of the natural gas piping, natural gas safety valves, and burner management 

system is critical. A periodic leak test of the natural gas safety valves is necessary to prevent boiler explosions. 

Periodic fugitive tests of threaded connections and valve stems are also important to prevent and detect leaks in the 

boiler room. NFPA 85 includes additional specific tests that must be performed on a regular basis to reduce the 

potential for explosions. When constructing new natural gas piping, an appropriate design standard such as NFPA 

54, ASME B31.1 or B31.3 and testing ensure that the system does not have leaks before natural gas is connected. If 

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pulverized coal is still expected to be used, then dust tight electrical enclosures may be required. 

4.2 Controls

Control systems for natural gas firing vary based on boiler type and emission control requirements. For most paper 

mills, air and fuel will be controlled independently through a fully metered control system driven by a DCS. 

Combustion air, FGR, and over-fire air flow rate, furnace exit oxygen, furnace exit CO, combustion air oxygen, and 

natural gas flow are common measurements, depending on the emissions control technology implemented. 

Implementing natural gas burners with the ability to co-fire with the biomass or other primary fuel require separate 

air measurement to the natural gas burners and the grate. Individual burner airflow measurement is also used for 

some co-firing applications. If cofiring more than one fuel in a burner is contemplated, the controls become much 

more complex. 

4.3 Emissions Controls

There are several technologies on the market today to control NOx formation in natural gas fired boilers. Low NOx

technologies include: FGR, overfire air (OFA), low NOx burners, burners out of service (BOOS), selective noncatalytic reduction (SNCR), and water injection. Typical NOx emissions from low NOx gas burners in a package 

unit firing natural gas are 0.1 lb/mmBtu without additional control technology. Typical uncontrolled NOx from low 

NOx field erected natural gas boilers range from 0.12 to 0.3 lb/mmBtu depending on boiler type and furnace design. 

Depending on the requirements of the project, these technologies can be layered to maximize NOx reductions and 

minimize costs. Emissions controls to meet permitting levels for natural gas burners can be a significant percentage 

of the conversion project cost. Early discussions with your state regulators on an adhoc basis can sometimes be 

fruitful for a smooth project. 

NOx control technologies can be added in various combinations to reduce NOx emissions from gas fired boilers to 

approximately 0.04 lb/mmBtu. Ultra low NOx burners and SCR are the only methods for reaching emissions of less 

than 0.01 lb/mmBtu. Table 2 lists emission reduction technologies considered. The table shows each technology 

individually and compares the potential decrease in NOx emissions on boilers between these technologies. 

Table 2: Comparison of NOx Technologies 

Reduction Method Decrease in NOx, % Compared to 

Conventional Gas Burners 

Annualize $/Ton 

NOx Removed 

FGR 25-75% $900 

OFA/BOOS 25% $400-600 

SOFA & FGR 50-80% $1,300-1,500 

Low NOx Burner 25% $70-100 

Low Excess Air (Air and 

Fuel Balance) 0-20% $30-50 

Ultra Low NOx Burners 90% $6,000-$8,000 

SCR 90% $6,000-8,000 

Water Injection 25-35% $400-600 

4.3.1 Low NOx burners.	 	Fuel staging, air staging, balancing, air/fuel ratios are all techniques that low NOx

burners use. The low NOx burner geometry produces a stable flame. It is important to have balanced airflow 

distribution and balanced fuel flow distribution between the burners as this is the foundation to achieving NOx

reduction. 

These same techniques can be applied to existing oil and coal burners. By incorporating air/fuel balancing to reduce 

overall excess air to the burners significant reductions in NOx and CO can be achieved. Fuel and air staging burner 

modifications provide further NOx reductions. 

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4.3.2 Flue gas recirculation.	 	 FGR is the recirculation of flue gases into the combustion air stream to the 

burner. FGR is a common emission control technology for gas and oil units. FGR reduces thermal NOx by 

increasing the specific heat of the combustion mixture to reduce the flame temperature (Agrawal, 2004). Adding 

FGR also lowers the concentration of O2 available in the combustion zone, slowing combustion and reducing the 

available oxygen for reaction with free nitrogen. 

FGR can be provided to the burners through a couple of methods. The easiest and least costly method is by 

inducing FGR into the existing FD fan. This method has several advantages: 

 Ducting runs from flue gas outlet to FD fan inlet are typically short; 

 Existing FD fan often provides sufficient pressure and flow characteristics to induce 10% FGR when 

converting from coal without upgrading the fan or motor; and 

 Tipping the fan, upgrading the motor, and increasing fan speeds are low cost options of increasing fan 

capacity. 

Induced FGR; however, typically cannot be used with #6 fuel oil or coal because sulfuric acid tends to condense in 

the FD fan when mixed with cold combustion air, causing major damage to the fan wheel and housing. In addition, 

SOFA, discussed below, is incompatible with induced FGR. 

FGR can also be provided through a separate FGR fan. This method is called boosted FGR. Boosted FGR is more 

expensive than induced FGR, in that an additional fan is required and the ductwork is typically longer and more 

complicated. The additional costs can be offset by corresponding benefits, including higher FGR levels, 

compatibility with #6 fuel oil and SOFA, discussed below, and reuse of the existing FD fan if its capacity is limited. 

FGR increases mass flow through the furnace and the boiler back pass. The increased velocity increases heat 

transfer to the superheater. In some boilers, particularly those constructed for coal only, boiler circulation and 

superheater attemperation capacity will be even more important at high FGR rates. 

4.3.3 Water injection.		Similar to adding FGR, injecting water into the flame is an effective means of reducing 

thermal NOx and is known as water injection. By targeting the hot spots in the flame, Combustion tempering can 

reduce NOx 25% with just 1 gal/min per 100 mmBtu/hr heat input. It is often used as a topping technology where 

NOx reduction is only required at full load and not used at lower loads. Unlike FGR, water injection has minimal 

impact on combustion air or flue gas flow. Fans are typically not impacted. Heat transfer in the superheater is only 

minimally impacted and the implementation costs can be very low. 

4.3.4 Overfire air. Overfire air (OFA) is a NOx reduction technique that removes a portion of the combustion 

air from the burner windbox. This air is introduced to OFA ports located above the burners. This technique 

provides an additional layer of air staging to the furnace zone. By decreasing the air/fuel ratio of the burner to run 

rich, flame temperature and thermal NOx is reduced. When the diverted air is introduced above the burners, the 

combustion is completed and the remaining CO is burned out.		

OFA has been incorporated in multi-burner units since the 1970’s. Older OFA port designs are not as effective as 

current generation of OFA ports. In some cases, original OFA ports have been removed because they were 

ineffective or caused boiler performance and maintenance issues. Using CFD modeling, current generation OFA 

systems are capable of 25% NOx reduction with minimal impact to the unit operation. 

An alternative to dedicated OFA ports is a tuning technique known as burners out of service (BOOS). BOOS is 

implemented by taking one burner or row of burners out of service. Out-of-service burners act as OFA ports by 

permitting the remaining burners to run lean. The remaining required combustion air is supplied through the BOOS 

to complete combustion. BOOS reduces boiler efficiency by increasing the excess O2 requirement by about 1%. 

4.3.5 Separated overfire air. Separated overfire air (SOFA) is similar to OFA with the exception that the OFA 

stream is separated from the burner combustion air prior to the introduction of FGR. OFA is then directed to the 

OFA ports without any combustion air and all of the FGR is directed to the burners. Providing OFA without FGR 

assists with burnout of CO at the OFA level, thereby decreasing CO and overall NOx. Segregating the OFA 

2012 PEERS Conference Page 2307
increases the percentage of FGR through the burner without increasing the total mass flow of FGR. This technique 

maximizes the benefits of FGR and OFA and provides combined emissions reductions of approximately 75% on 

natural gas. 

4.3.6 Ultra‐low NOx burners. Ultra-low NOx gas burners in package units are capable of achieving less than 

0.01 lb/mmBtu with 30% FGR. In contrast, low NOx burners in field erected units are typically 0.12 to 0.3 

lb/mmBtu without additional control technology. Ultra low NOx burners are not proven below 0.01 lb/mmBtu on 

preheated air units. Ultra-low NOx burners vary from low- NOx burners in several ways: 

 Ultra-low NOx burners are longer and have a larger throat diameter; 

 Ultra-low NOx burners require approximately 30% FGR; and 

 Ultra-low NOx burners require a high pressure drop (10-12 in w.c.); 

 Ultra-low NOx burners cannot be combined with #6 fuel oil or coal. 

These differences can double the cost of converting versus a low NOx burner retrofit. The windbox often will need 

to be replaced or extended to accommodate the longer burner. New burner pressure part openings may be required to 

accommodate the larger burner throats. The high FGR rate impacts both the FD and ID fans. An existing FD fan 

usually cannot accommodate a 30% increase in FGR flow. 30% FGR may raise the temperature at the FD fan inlet 

above its design temperature. Existing FD fans also cannot usually provide sufficient static pressure to overcome the 

increase in burner pressure drop from 5-6 in w.c. typical for standard burners to 10-12 in w.c. typical for utra-low 

NOx burners. A separate FGR fan or tipping the FD fan may be options to reuse the existing equipment. The FGR 

increases the flue gas exit temperature, which can exceed the design temperature of the ID fan. 

Ultra low NOx burners are not compatible with burning #6 fuel oil because of the high sulfur content and other 

contaminants in the flue gas, which can damage the burner. They are not compatible with burning coal. 

4.3.7 Post combustion treatment.		SNCR systems can be effective to reduce NOx while firing natural gas, but 

has not been shown to reduce emissions below approximately 0.05 lb/mmBtu. SNCR is worth considering if the 

unit has already implemented or is planning to implement SNCR for NOx control of coal or oil emissions. However, 

it is not generally as cost-effective as other comparable low NOx technologies. In addition, placement of the SNCR 

injection system at the proper temperature is critical for maximum NOx reduction with minimal ammonia slip. The 

existing SNCR injectors would need to be evaluated to determine if the injector location is appropriate for natural 

gas firing. Determining whether the existing SNCR system can be reused and predicting the performance often 

involves CFD modeling. 

Selective catalytic reduction (SCR) utilizes urea reagent injected in the flue gas ductwork upstream of a catalyst. 

Sufficient temperature in the flue gas must be available for the catalyst to convert the ammonia and NOx to N2. 

When the flue gas, including ammonia, passes through the catalyst, the NOx and ammonia react to produce nitrogen 

and water. Urea or ammonia based systems are available; urea has almost no siting concerns while ammonia is a 

hazardous chemical that must be sited and handled more carefully then urea. 

5 CONCLUSION

Natural gas can be readily incorporated in a mill’s overall energy plan. Existing capital equipment can often be 

repurposed or modified to take advantage of the low cost and ease of operation associated with firing natural gas. 

Investigation early on to determine the steaming rate of the unit firing natural gas, emission requirements, and 

impacts on other equipment will ease the transition and maximize the benefits associated with converting to natural 

gas. As part of the mills strategic planning, backup and alternate fuel strategies should be developed to reduce the 

impact of fluctuations in fuel price. Multi-fuel burner modifications are possible and can make sense for the longterm. 

6 REFERENCES

 Agrawal, A., Singh, S., and Shulka, M., Effect of EGR on The Exhaust Gas Temperature and Exhaust 

Opacity in Compression Ignition Engines, Volume 29, Part 3, Sadhan, June 2004. 

2012 PEERS Conference Page 2308
 Borman G., and Ragland K,. Combustion Engineering, McGraw-Hill Inc., 1998. 

 Heywood, J.B., Internal Combustion Engines, McGraw-Hill Inc., 1988. 

 Kou, K., Principles of Combustion, Second Edition, Wiley, 2005. 

2012 PEERS Conference Page 2309
COMBUSTION COMPONENTS ASSOCIATES, INC.

884 Main Street, Monroe, Connecticut 06468

Tel: (203) 268-3139 Fax: (203) 261-7697

www.cca-inc.net

Presented to 

TAPPI-PEERS 

October 2012 

Savannah, GA 

Presented by 

Nathan Schindler 

Practical Guide to Converting to Natural Gas

2012 PEERS Conference Page 2310
Introduction 

• Comparison of combustion properties; 

• Emission fundamentals; 

• Basic requirements of conversion projects; 

• Special considerations with respect to boiler 

configurations; 

• Safety, controls, and NOx reduction 

techniques. 

2012 PEERS Conference Page 2311
0 5 10 15 20 25 30

Fuel Flow Rate - gpm/burner

0.0

0.1

0.2

0.3

0.4

0.5

Atomizing Mass Ratio - Ms/Mf

 0 psid

10 psid

20 psid

30 psid

Atomizing Steam

 Differential

Map-aof

Atomizing Steam Mass Ratio with Fuel Flow and Atomizing Differential

Normalized Air/Fuel Ratio Spatial Distribution

140 psi fuel at 12.5 gpm

15 psi Differential 

10.5% Steam Mass ratio

5.0 inwc Windbox Differential

Measured 12 Inches Downstream of Atomizer

Natural Gas Properties

•Combustion Properties 

•Impacts to Existing Equipment 

•Formation of Emissions 

2012 PEERS Conference Page 2312
Fuel Type HHV

BTU/LBm

Mass Air to 

Mass Fuel

% Excess 

Air

Typical Boiler 

Efficiency

Natural Gas ≈ 21,000 17.23 10-15 82-84%

#6 Oil ≈ 18,100 10.63 10-15 85-88%

Coal 11,000-

13,000 10.7 25-30 84-86%

Biomass 7,300-

9,000 4.8 25-32 84-86%

Fuel Properties 

2012 PEERS Conference Page 2313
Impacts to Existing Equipment 

• FD and ID Fans 

– Stoichiometry 

– combustion air requirements 

– total combustion products 

• Boiler 

– Combustion product temperature, quantity, and 

composition affect the velocities and heat 

absorption within the boiler, superheater and 

economizer 

2012 PEERS Conference Page 2314
Thermal NOx 

• NOx formation is a function of temperature. 

• By reducing combustion temperature, the 

production of NOx can be reduced. 

• The higher the combustion temperature, the 

greater the NOx produced. 

• Dominant mechanism of NOx formation for 

low NOx gas burners. 

2012 PEERS Conference Page 2315
NOx (ppm) Production vs. Temperature (F) 

2012 PEERS Conference Page 2316
Prompt NOx 

• Dominant mechanism of NOx formation for 

ultra-low NOx 

• Formed by the reaction of nitrogen from air 

with combustion radicals formed in fuel rich 

zones 

• Occurs almost instantaneously and cannot 

be controlled by reducing peak flame 

temperature 

2012 PEERS Conference Page 2317
0 5 10 15 20 25 30

Fuel Flow Rate - gpm/burner

0.0

0.1

0.2

0.3

0.4

0.5

Atomizing Mass Ratio - Ms/Mf

 0 psid

10 psid

20 psid

30 psid

Atomizing Steam

 Differential

Map-aof

Atomizing Steam Mass Ratio with Fuel Flow and Atomizing Differential

Normalized Air/Fuel Ratio Spatial Distribution

140 psi fuel at 12.5 gpm

15 psi Differential 

10.5% Steam Mass ratio

5.0 inwc Windbox Differential

•Package Boilers Measured 12 Inches Downstream of Atomizer

•Field Erected Boilers 

•Auxiliary Fuel Boilers 

Boiler Type Specific Modifications 

2012 PEERS Conference Page 2318
Package Units 

• Ambient Combustion Air 

• Lower efficiency 

• Gas/oil 

• Relatively easy to convert 

• Lower NOx 

• Firetube/Watertube 

2012 PEERS Conference Page 2319
Low-NOx Gas Injectors 

Flame 

Stabilizer 

Gas Retrofit 

2012 PEERS Conference Page 2320
Field Erected Units 

• Multi-burner 

• Preheated Combustion Air 

• Higher Efficiency 

• Higher NOx 

• Gas/Oil/Coal/Biomass 

• Wall-Fired/T-Fired 

2012 PEERS Conference Page 2321
Gas Retrofit to Coal Circular Burners

Retain Coal Pipe - Retrofit Gas Manifold and Poker 

Assembly “Around” Coal Pipe

Gas Pokers 

Gas Manifold 

Coal Pipe 

(Existing 

2012 PEERS Conference Page 2322
Retrofit Low-NOx Gas Injectors Above & Below Coal 

Retrofit Gas 

Injectors 

Behind 

Bucket 

Flame 

Stabilizer 

Low-NOx Gas 

Injectors 

Gas Retrofit to Coal T-Fired Burners

2012 PEERS Conference Page 2323
Auxiliary Fuel Boilers 

• Stoker Units 

– Auxiliary Oil Burners 

• Fluidized Bed Boilers 

– Duct Burners 

– Startup Lances 

• Recovery Boilers 

– Startup Burners 

– Load Burners

2012 PEERS Conference Page 2324
0 5 10 15 20 25 30

Fuel Flow Rate - gpm/burner

0.0

0.1

0.2

0.3

0.4

0.5

Atomizing Mass Ratio - Ms/Mf

 0 psid

10 psid

20 psid

30 psid

Atomizing Steam

 Differential

Map-aof

Atomizing Steam Mass Ratio with Fuel Flow and Atomizing Differential

Normalized Air/Fuel Ratio Spatial Distribution

140 psi fuel at 12.5 gpm

15 psi Differential 

10.5% Steam Mass ratio

5.0 inwc Windbox Differential

Measured 12 Inches Downstream of Atomizer

Natural Gas Safety, Controls, & 

Emissions Reduction Technologies

2012 PEERS Conference Page 2325
Main Gas Valve Train 

2012 PEERS Conference Page 2326
Overview of Emission Technologies 

Typical Multi-Burner Boiler 

2012 PEERS Conference Page 2327
Comparison of NOx Technologies 

Reduction Method NOx, % Reduction

Annualized Cost

Factor

NOx Removal

Low NOx Burner 25% Low

OFA/BOOS 25% Low

Water Injection 25-35% Low

FGR 25-75% Moderate

SOFA & FGR 50-80% Moderate

Ultra Low NOx 

Burners

90% High

SCR 90% High

2012 PEERS Conference Page 2328
Low-NOx Circular Burner 

2012 PEERS Conference Page 2329
Gas Flame – High FGR 

21

2012 PEERS Conference Page 2330
Water Injection Skid 

2012 PEERS Conference Page 2331
SCR vs. SNCR 

SCR 

• Requires Catalyst 

• 90% or more NOx 

reduction for UltraLow NOx 

• Multi-fuel operation 

presents special 

problems for catalyst 

design 

SNCR 

• No Catalyst Required 

• 30-50% NOx reduction 

–Low NOx only 

• Multi-fuel operation 

possible but 

performance highly 

dependent on 

temperature profile at 

injection location 

2012 PEERS Conference Page 2332
Conclusions 

2012 PEERS Conference Page 2333
Questions 

Nathan Schindler 

203-268-3139 ext 137 

nschindler@cca-inc.net

www.cca-inc.net 

2012 PEERS Conference Page 2334