### 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 wi ll 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 difference s associated with convertin g 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 natu ral 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 NO x 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 NO x emissions and associated control technologies to be accurate.

1 INTRODUCTION:
Conversion to natural gas is an important opportunity in th e 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 consideratio ns 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 natu ral gas conversion projects;

 Special considerations with re spect to boiler configurations;

 Safety, controls, and NO x 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 NO x , will be discussed. A general overview of the effectiveness of NO x reduction methods is also provided.

2.1 Impacts to Existing Equipment
Converting from coal, oil, or biomass to natural gas ch anges stoichiometry, combustion air requirements, and the total combustion products. All of these impact the imp act 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, superh eater and economizer.
During a feasibility study, the existing heat transfer surf aces must be evaluated to avoid high temperatures, to maintain adequate temperature differentials in the boile r walls, and to preserve proper boiler circulation. The differences between current operations an d 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 conv ective heat transfer is increased throughthe superheater. Boiler tube modifications may be requir ed 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 defi nes 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 (SO x ), mercury, nickel, carbon monoxide (CO), volatile organic compounds (VOCs), and NO x . Many of these pollutants are a result of component s in the fuel or diffic ulties 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 NO x . CO and opacity are typically regulated because NO x reduction techniques, as discussed below, fo cus 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 NO x . By reducing combustion temperature, the production of NOx can be reduced. NOx formation is a function of temperature. The higher th e 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 mechanis ms are the six mechanisms for th ermal NOx production (Borman 1998):

2 

### O+N NO+N  (0.1)

2 

### N+O NO+O  (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 temper ature 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)

#                     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 NO x 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 an d concentration become the controlling factors to reduce NO and NO 2 . When the reaction rate is reduced by temperature, the firs t mechanism reduces the concentration of NO and N. This reduces the potential reactants in the second mechanism. Th erefore, a reduction of temp erature for the first reaction introduces a limiti ng factor for NO x emissions. For that reason, the objective of the technology to be applied is to reduce thermal NO x by lowering the reaction temperature.
CO emission is effected by combustion temperature and ex cess 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 O 2 is insufficient to comple te the reaction of CO to CO 2 . There is a range of excess ai r that is optimal to minimize both CO and NO x emissions.

2.3.2 Prompt NO x . Ultra low NO x is not merely a name change from low NO x . Ultra low NO x is usually defined as less than 10 ppm NO x corrected to 3% O2. The important difference is that below 10 ppm, prompt NO x mechanisms, not thermal NO x mechanisms, dominate the formation of NO x . Prompt NO x 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 NO x occurs almost instantaneously and cannot be controlled by reducing peak flame temperature, hence the apt name “prompt”.

NO x emissions lower than 10 ppm are not achievable through the use of staged fuel and air low-NO x burner designs. A complete change in the burner concept is required to reduce or eliminate prompt NO x . Ultra low NO x burners that rely on high volumes of flue gas recirculation (FGR) (typi cally recirculating 30% of the flue gas mass or more) have been developed for single burner boilers or two burner un ison fired boilers. Selective catalytic reduction (SCR) can be a cost-effective alternative to Ultra-Low NO x 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 th e 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 s ite 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 out put. They are typically pr ovided with one burner, but occasionally with two burners on a larger unit.
The biggest distinction between a pack age 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 ai r preheater a more expensive economizer can be added to improve efficiency. Ambient co mbustion air units have lower NO x than preheated combusti on air units because the cold air lowers the peak flame temperature. This past sp ring, 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.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 NO x burner modifications can include a low NO x 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 burn ers 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 ha ndle, burns better in the tight furnace of a package unit, and does not re quire heating. If the oil is expected to be burned only rarely, the high heat value components of #6 fuel oil can volatilize l eaving a viscous slurry that is diff icult to burn when needed. Low NO x #6 fuel oil (~0.25 lb/mmBtu) and low NO x #2 fuel oil (~0.1 lb/mmB tu) atomizers are availabl e. Because of the high sulfur content and other fuel components, #6 fuel oil is not compatible with ultra low NO x burners.

3.2 Field Erected Units

Multi-burner field erected units are di stinguished 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 pr ovides a significan t performance benefit. It enhances efficiency because more energy is reco vered 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 NO x emissions from heated air gas burners relative to cold air units. Therefore, the need to reduce NO x 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 un its 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 e fficiencies, and reducing capita l 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 ManifoldMulti-burner boilers are typically arranged in two ways, wall-fired and tangent or co rner-fired. Burners on wallfired units are arranged in rows and columns on one or more walls of the boiler. The bur ners are designed to create and maintain their own flame. Tangen t 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 fi re 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-NO x gas burner retrofits capable of burning coal and oil are available. (Figure 2.)

Low NO x natural gas burners rely on fuel and air staging to reduce peak flame temperature. Therefore, low NO x 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 NO x 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 sw ings can also be reduced. Also, for two burner multi-burner units, unison firing should be considered. The safety sy stem and controls become mu ch 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 o il as a primary fuel, should be Figure 2: Wall Fired Multi Fuel Burner

Figure 3: Tangent Fired Multi

‐ Fuel Burnerconsidered 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 in vestment. During low demand periods, low-cost natural gas igniters are often a cost-effective means of keeping the bo iler 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 NO x gas and coal modifications are possible by incorporating current generation swirlers to stabilize a core flame and enhance fuel staging. We are not aw are of any commercially available ultra low NO x 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 o il 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 fire d 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 impact s the fuel to air ratio and total excess air. Air to the grate must be controlled while firing natural gas to keep NO x emissions low while ensuring complete combustion. Emissions from auxiliary burners on stoker units tend to be higher than sim ilar sized multi-burner units becau se 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 ab ove approximately 50% of design heat input will likely require modifi cations of the superheater and circulation system, so a boiler st udy is necessary. If low emissions are critical, a CFD model can be a useful t ool 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 straightforwar d. Converting the lances from oil to natural gas is more complicated. The auto-ignition temperatur e of natural gas is greater than the auto-ignition temperature of oil, so startup times may be increased to reac h the solid fuel st arting 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 s econdary air level above the bed. These burners are essentia l 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 c ontent. 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 ai r enters the furnace through a variety of openings. Therefore, emissions from starting burners are often high er than from load burners.
Load burners are typically lo cated on the tertiary air level high in the furnace. They often have an independentambient 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 fr om 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 re ducing 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. Flam e detection of the igniter is also less susceptible to interference from slag from the liquor process. Class 1 ign iters 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 NO x limits of 0.1 lb/mmBtu or less, NO x control technologies will probably be required for preheated combustion air units to meet permit requirements. Implementing NO x control technologies are often similar in cost to modifying the burners. If NO x 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 be en 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 sy stem 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 ar e 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 pre ssure 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 requ ired 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 ga s 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. Ifpulverized coal is still expected to be used, then dust tight electrical encl osures 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, furn ace 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 burner s 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 NO x formation in natural gas fired boilers. Low NO x technologies include: FGR, overfire air (OFA), low NO x burners, burners out of se rvice (BOOS), selective noncatalytic reduction (SNCR), and water injection. Typical NO x emissions from low NO x gas burners in a package unit firing natural gas are 0.1 lb/mmBtu without additional control technology. Typical uncontrolled NO x from low NO x field erected natural gas boilers range from 0.12 to 0. 3 lb/mmBtu depending on boil er type and furnace design. Depending on the requirements of the project, these technologies can be layered to maximize NO x 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 NO x emissions from gas fired boilers to approximately 0.04 lb/mmBtu. Ultra low NO x burners and SCR are the only methods for reaching emissions of less than 0.01 lb/mmBtu. Table 2 lists emission reduction te chnologies considered. The table shows each technology individually and compares the potential decrease in NO x emissions on boilers between these technologies.
Table 2: Comparison of NO x Technologies

Reduction Method Decrease in NO x , % 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 NO x Burner 25% $70-100 Low Excess Air (Air and Fuel Balance) 0-20% $30-50

Ultra Low NO x Burners 90% $6,000-$8,000
SCR 90% $6,000-8,000 Water Injection 25-35% $400-600

4.3.1 Low NO x burners. Fuel staging, air staging, balancing, ai r/fuel ratios are all techniques that low NO x burners use. The low NO x 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 NO x 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 NO x and CO can be achieved. Fuel and air staging burner modifications provide further NO x reductions.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 NO x by increasing the specific heat of the co mbustion mixture to reduce the flame temperature (Agrawal, 2004). Adding FGR also lowers the concentration of O 2 available in the combustion zone, slowing combustion and reducing the available oxygen for reactio n 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 increasin g fan speeds are low cost options of increasing fan capacity.
Induced FGR; however, typically cannot be used with #6 fu el 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 inco mpatible 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 re use 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, particular ly 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 NO x and is known as water injection. By targeting the hot spots in the flame, Combustion tempering can reduce NO x 25% with just 1 gal/min per 100 mmBtu/hr heat input. It is often used as a topping technology where NO x 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 implemen tation costs can be very low.

4.3.4 Overfire air. Overfire air (OFA) is a NO x 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 z one. By decreasing the air/fuel ratio of the burner to run rich, flame temperature and thermal NO x 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% NO x 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 bo iler efficiency by increasing the excess O 2 requirement by about 1%.

4.3.5 Separated overfire air. Separated overfire air (SOFA) is simila r 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 OFAincreases the percentage of FG R 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 NO x burners. Ultra-low NO x gas burners in package units ar e capable of achieving less than 0.01 lb/mmBtu with 30% FGR. In contrast, low NO x burners in field erected units are typically 0.12 to 0.3 lb/mmBtu without additional control technology. Ultra low NO x burners are not proven below 0.01 lb/mmBtu on preheated air units. Ultra-low NO x burners vary from low- NO x burners in several ways:

 Ultra-low NO x burners are longer and have a larger throat diameter;

 Ultra-low NO x burners require approx imately 30% FGR; and

 Ultra-low NO x burners require a high pressure drop (10-12 in w.c.);

 Ultra-low NO x burners cannot be combined with #6 fuel oil or coal.

These differences can double the co st of converting versus a low NO x burner retrofit. The windbox often will need to be replaced or extended to accommodate the longer burner. New bu rner pressure part openings may be required to accommodate the larger burner throats. The high FGR rate impacts both th e FD and ID fans. An existing FD fan usually cannot accommodate a 30% increase in FGR flow. 30% FGR may raise the temperat ure at the FD fan inlet above its design temperature. Existing FD fans also cannot usually provide suffici ent 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 NO x 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 NO x 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 bur ner. They are not compatible with burning coal.

4.3.7 Post combustion treatment. SNCR systems can be effective to reduce NO x 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 NO x control of coal or oil emissions. However, it is not generally as cost-effective as other comparable low NO x technologies. In additio n, placement of the SNCR injection system at the proper te mperature is critical for maximum NO x reduction with minimal ammonia slip. The existing SNCR injectors would need to be evaluated to dete rmine 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 inject ed in the flue gas ductwork upstream of a catalyst. Sufficient temperature in the flue gas must be av ailable for the catalyst to convert the ammonia and NO x to N2. When the flue gas, including ammonia, passes through th e catalyst, the NO x 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 maximi ze 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 burnermodifications 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. Borman G., and Ragland K,. Combustion Engineering, McGr aw-Hill Inc., 1998.

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

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

# 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

# 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.

# Natural Gas Properties

• Combustion Properties

• Impacts to Existing Equipment

• Formation of Emissions

# 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

# 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

# Thermal NOx

• NO x 

# formation is a function of temperature.



# • By reducing combustion temperature, the production of NO x 

# can be reduced.



# • The higher the combustion temperature, the greater the NO x 

# produced.

• Dominant mechanism of NOx formation for low NOx gas burners.

# NOx (ppm) Production vs. Temperature (F)

# 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

# • Package Boilers

• Field Erected Boilers



# • Auxiliary Fuel Boilers 

# Boiler Type Specific Modifications

# Package Units

• Ambient Combustion Air



# • Lower efficiency

• Gas/oil



# • Relatively easy to convert

• Lower NOx



# • Firetube/Watertube

# Low -NOx Gas Injectors Flame 

# Stabilizer 

# Gas Retrofit

# Field Erected Units

• Multi-burner



# • Preheated Combustion Air

• Higher Efficiency

• Higher NOx

• Gas/Oil/Coal/Biomass

• Wall-Fired/T-Fired

# 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

# 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

# Auxiliary Fuel Boilers

• Stoker Units

– Auxiliary Oil Burners



# • Fluidized Bed Boilers

– Duct Burners

– Startup Lances



# • Recovery Boilers

– Startup Burners

– Load Burners

# Natural Gas Safety, Controls, & Emissions Reduction Technologies

# Main Gas Valve Train

# Overview of Emission Technologies

Typical Multi-Burner Boiler

# 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

# Low -NOx Circular Burner

# Gas Flame

–

High FGR

21

# Water Injection Skid

# 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

# Conclusions

# Questions

Nathan Schindler 

# 203

- 268 -3139 ext 137 nschindler@cca-inc.net www.cca-inc.net