Method of Co-Firing Coal or Oil with a Gaseous Fuel in a Furnace

Abstract

Methods for co-firing a fuel containing coal or oil that is injected into a burner in a furnace by injecting a gaseous fuel are disclosed. The gaseous fuel is injected in a manner so as not to consume air that would otherwise combine with the coal or oil in the primary flame. This can be accomplished by injecting the gaseous fuel at a higher or lower velocity than the coal or oil and combustion air are being injected. This can also be accomplished by directing the gaseous fuel being injected away from the primary flame created when the coal or oil burns.

Description

FIELD OF INVENTION

The present invention is directed toward controlling the operation of a furnace and in which coal or oil is burned in combination with a gaseous fuel.

BACKGROUND OF THE INVENTION

Coal and oil fired boilers are used to generate steam for many industrial purposes, chief among which is to drive electric generating, steam powered turbines for the electric utility industry. The coal or oil occur in a condensed solid or liquid state and must be ground or pulverized, in the case of coal, or atomized, in the case of oil, before being able to be combusted efficiently in the furnace section of the boiler.

Either of these finely ground or atomized, but still condensed phase, fuels then must be heated to an extent so as to volatilize a portion of the fuel into the gaseous phase before mixing with air and combustion begins. Once combustion and stable flames are established the furnace and burner throats become very hot and thus provide the required heating source for continuing volatilization and flame structure stability.

Natural gas occurs in the gaseous state and is easier to ignite and burn since there are no preparation or volatilization steps. Once ignited, the gas burns as it mixes with air, within its combustion limits of sufficient air but not too much air. Thus gas-fired igniters are often used to light-off or ignite, warm-up and stabilize the harder to burn coal or oil fuels. Coal or oil fuel is considered the main source of heat input to the utility boiler; with the gaseous ignition system supplying up to 10% or 15% fuel input for ignition and safety purposes. Often times the gaseous ignition system is augmented with a gas-fired warm-up system so as to allow initial steam generation in the range of 20 to 30% of full-load fuel input.

The igniter may have its own full or partial air supply, while the excess combustion air supply for the coal or oil fuel is usually 15% or slightly greater than that required for stoichiometric combustion. If the gaseous fuel input goes beyond the 10 or 15% required for ignition and flame stabilization, it would use combustion air meant for the condensed phase fuel. Most boilers have a master controller that controls the flow of coal or oil and air into the burners as well as the flow of any additional fuel and air into the igniters. This Boiler Master Controller must always assure safe operation by always controlling total air to each burner so that there is more air than fuel entering the boiler. The Boiler Master Control always assures adequate air supply by measuring both the actual air in-put and the cumulative fuel in-put.

Natural gas may also be co-fired as a portion of the main fuel. Depending on seasonal gas supply logistics, economics and pollution considerations the co-fired natural gas may be advantageously used in quantities of from 15% in the case of Fuel Lean Gas Reburn (FLGR) for NOx control, up to 100% when seasonally most economic. As gas prices vary over time the proportion of gas co-firing may depend on meeting certain operational benefits; such as, improved load turn-down as well as SO₃ and ash reduction for improved Selective Catalyst, Precipitator and Scrubber operation.

However, when natural gas is injected into the boiler in any amount greater than the 5 to 15% necessary for ignition, there is the possibility that the more easily burnt gaseous fuel will interfere with burner design by quickly using-up the air supply designed to mix and stabilize the condensed phase flame structure. Such interference can lead to problems of smoking, high carbon ash, furnace slagging and even boiler explosions.

Whenever solid or liquid fuels are co-fired with a gaseous fuel, care must be taken, so that the more easily combusted natural gas does not first steal the combustion air (Oxygen), necessary for flame stabilization of the condensed phase coal or oil flame in its primary flame structure. Detrimental results will cascade if the proper flame structure is not continually maintained. Those detrimental results are incomplete combustion, soot and carbon fouling, smoke and higher emissions, lower efficiency and other severe problems which include catastrophic explosion.

Consequently, there is a need for a method and injection apparatus that can inject natural gas into coal or oil fired large utility boilers while not interfering with condensed phase flame structure and safety. The essence of safe gas co-firing is that the more easily burnt gas must not steal the combustion air intended for the base of the flame of the condensed phase fuel.

The cost of natural gas has fluctuated widely during the past 25 years but the cost of coal remains competitive for the production of electricity. The use of safe co-firing of gas with coal provides flexibility in such a yearly or seasonal market. With new CO₂ reduction commitments, natural gas provides over 40% CO₂ reduction which can be proportioned over the percent gas co-fired with coal while maintaining coal supply, handling and firing capabilities. The clean burning natural gas allows many pollution control options; such as, reduced NO_x, SO₂, SO₃, ash and trace metals emissions.

Low gas price may provide actual fuel cost savings, but the co-firing of natural gas with coal offers advantages in flexibility and clean operation by not overloading the existing pollution control equipment. Even when the natural gas fuel cost is more than that of coal it is advantageous to burn the best co-fired combination which reduces operating and disposal costs while providing improved load turn-down and low load operation. These proportionate co-firing advantages can be considered in light of CO₂ and global warming while being compatible with the load following constraints imposed by changing daily and seasonal renewable energy dispatch. All these co-firing advantages depend on the safe operation of the condensed phase flames.

SUMMARY OF THE INVENTION

We provide a method by which a more easily burned fuel, such as natural gas, is introduced into a coal or oil burning furnace so that it will not disturb the primary flame structure of the solid or liquid fuel. We disclose methods to inject the gaseous (or more easily burned) fuel into the bulk volume of the furnace without disrupting the operation or safety of the coal or oil fired boiler and then the process by which both the solid or liquid and the gaseous fuel combustion are controlled to safely burn to completion.

In our method a gaseous fuel is co-fired ether through an existing or new burner or separately by itself, into an existing or new furnace without interfering with the condensed phase flame structure. At the same time, the process allows continued flame stabilization and safety of the condensed phase fuel combustion, furnace and boiler operation, and complete gaseous fuel combustion within the bulk furnace volume away from the primary flame structure.

Our method of safely combusting the gaseous fuel, without interfering with the safe operation of the condensed phase flame involves injector design, ancillary equipment design and control logic design of the gaseous fuel injection and safety permissives. Such designs, as disclosed here, allow the gaseous flame to have sufficient remaining air to combust in the bulk furnace volume and insure that the gaseous fuel can never be present under unsafe conditions.

Our method involves the safe injection of a gaseous fuel into a furnace volume without interfering with the originally designed operation of a condensed phase, coal or oil burner. This injection may be either through the existing burner, its peripheral openings or through separate furnace wall penetrations. The process is that combustion of the gaseous fuel is purposefully limited in the primary flame structure of the coal or oil burner; thus maintaining original equipment flame safety and stability. But, the subsequent mixing and combustion of gaseous fuel, actually improves the combustion and burn-out of the condensed phase fuel in the bulk volume of the furnace, because of the much higher water of combustion of methane (CH₄), with greatly increased free-radical hydrogen activity. This safe injection of the co-fired gaseous fuel must be accomplished, without stealing a significant amount of the necessary combustion air from the primary flame structure of the originally designed condensed phase burner.

Other objectives and advantages of our method and apparatus will become apparent form certain present preferred embodiments which are shown in the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagram of a typical swirl type burner with an igniter that is turned on.

FIG. 2 is a diagram of a swirl type burner configured in accordance with a first present preferred embodiment of our method.

FIG. 3 is a diagram of a swirl type burner configured in accordance with a second present preferred embodiment of our method.

FIG. 4 is a diagram of a swirl type burner configured in accordance with a third present preferred embodiment of our method.

FIG. 5 is a diagram of a swirl type burner configured in accordance with a fourth present preferred embodiment of our method.

FIG. 6 a is diagram of regions of a furnace without co-firing and FIG. 6b is a diagram of the same regions of a furnace with co-firing.

FIGS. 7 a, 7b and 7c are diagrams of other furnace/burner configurations in which our methods can be used.

FIG. 8 is a flow chart showing the control systems of a furnace that should be involved in using our co-firing methods.

FIG. 9 a is a perspective view and FIG. 9b is an exploded view of a present preferred injector that can be used for injecting a gaseous fuel using our methods.

FIG. 10 a is a graph of co-fire heat input during a test of our method.

FIG. 10 b is a graph of co-fire gas flow versus carbon monoxide levels in a furnace during a test of our method.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

A typical coal fired boiler has several burners into which pulverized coal in a stream of air is injected into a flame zone. Natural gas, i.e. methane, is separately injected into the burner. The gas injection may be accomplished through gas igniter tubes, or through separate higher velocity injector piping tips, spuds or nozzles. Normal igniter operation is shown in FIG. 1, where the igniter establishes its own stable flame structure, which then impinges on the main condensed phase fuel stream as it heats-up and mixes with its dedicated burner air supply. As can be seen in FIG. 1, a typical swirl type burner 1 is provided on the wall 2 of a boiler. The burner 1 has an opening 4 in which there is an injector tube 6 through which a stream of pulverized coal 5 is injected. Swirling combustion air 7 is injected through the opening 4 around the injector tube 6. Typically the combustion air is injected at a different velocity than the pulverized coal. An igniter tube 8 is positioned within the opening 4 adjacent the end of the coal injector 6. Natural gas and igniter air flows through the igniter to create an igniter flame 9 which impinges on the stream of pulverized coal 5 that then ignites creating a flame envelope 10.

We provide three methods which limit the mixing of the gaseous fuel within proximity of the condensed phase burner and its dedicated air supply. These different methods are necessary in order to allow retrofit to existing or new burner and igniter equipment having different designs with different co-firing gas usage applications.

Referring to FIG. 2 a swirl type burner has been modified so that the co-fire gas can be injected with a velocity significantly higher than the velocity of the coal combustion air and with a spatial direction so as to minimize mixing with the design burner air supply. The opening 4 in in the burner wall 2 and the injector tube 6 through which a stream of pulverized coal 5 is injected into the furnace are the same as in a conventional swirl type burner shown in FIG. 1. Swirling combustion air 7 is injected through the opening 4 around the injector tube 6. However, the igniter tube 18 that is positioned within the opening 4 has a tube within a tube configuration in which the centerline of both tubes is on a common axis. Gas and typically injector air is injected through the inner tube 15 while co-fire gas 13 is injected through the region between the inner tube 15 and the outer tube 17. The co-fire gas is injected around the standard igniter, but with velocity which is between ¼ greater and twenty times greater than the design burner air velocity and is spatially directed along the centerline of the burner throat as represented by the drawing of FIG. 2. The gaseous fuel injection co-firing tip provides a smooth, non-mixing jet of gaseous fuel. This co-firing fuel may be sized to burn between 10% and 75% of the original burner design sizing. This gaseous fuel injection may be either through a sub-sonic or a super-sonic nozzle but should have minimum turbulence within the injected stream and should cause minimum turbulence and mixing with the burner's dedicated air supply 7.

In another preferred embodiment of our method shown in FIG. 3 the injector 28 for the co-fire gas is configured to direct the co-fire gas 29 away from the burner air 7. In this embodiment the injector 28 may be configured to inject co-fire gas in separate penetrations in the furnace, separate from the burner throat penetration.

In the embodiment shown in FIG. 4 the injector 18 is similar to the injector in FIG. 2 but configured to inject the co-fire gas 29 away from the burner's dedicated air supply 7. The co-axial standard igniter flame 30 projects toward the pulverized coal stream while the co-fire gas 29 is directed away from the coal stream 5 and the burner flame envelope 10. In the method illustrated by FIG. 4 the co-fire gas may be injected through an igniter tube having a tube within a tube configuration with the tip configured to divert the co-fire gas away from the pulverized coal stream.

In these embodiments the gas may be injected circumferentially about the coal stream 5.

In yet another embodiment illustrated by FIG. 5 the co-fire gas 29 is injected at a low velocity which diverts the gas from the core flame 10 and creates separate flame fronts 31 and separate peripheral flames. We have found very little mixing as the low velocity co-fire gas stream separates on the periphery of the swirling coal burner combustion air core. The velocity of the combustion air and core flow can be 1.5 to 30 times that of the co-fire flame to cause distinct flame fronts.

Once the co-fire gas has been introduced into the bulk furnace volume without interfering with the coal flame structure, our process is such that the gaseous fuel does not combust until the gaseous fuel is in the bulk volume of the furnace, as shown by the different furnace regions of FIGS. 6a and 6b. The bulk furnace volume is away from the primary burner flame structure; that is, away from the initial mechanisms by which the condensed phase fuel flame is stabilized within the burner region as shown in FIG. 6a. Consequently, over half of the gas burns outside of the primary combustion zone.

The gaseous fuel is directed so that the injection jet or stream mixes into the core of the furnace volume flue-gas flow, shown in FIG. 6b. The co-fire gaseous fuel jet diameter and velocity are designed to penetrate to this core region and then mix as a result of the core turbulence, combustion activity and upward flow caused by the expansion of the hot combustion gases. This design is accomplished both by a-priori Computer Furnace Modeling and by actual operational multivariate analysis of combustion effectiveness.

Separate co-fire gas may be injected through separate furnace penetrations as is accomplished when injected gas for Fuel Lean Gas Reburn is injected in the upper furnace. In the case of Fuel Lean Gas Reburn when co-fire gas indicated by the “FLGR Gas” arrow and over-fire air indicated by the “OFA Input” arrow in FIG. 6b are injected into the upper one-third of the furnace, the co-fire gas also reduces nitric oxide in emissions due to the reaction of the nitric oxide with the gas at lowered temperatures of the flue gas leaving the furnace.

The hydrogen present in natural gas (CH₄) combustion generates water molecules; whereas coal is basically pure carbon (C) and any water present is mostly from moisture in the air or fuel. With natural gas combusting in this core region, twice the water content of coal combustion is generated and the flue-gas water content goes from nominally 6% to 12% in proximity of the co-fire gas mixing. In this fuel-rich core region where the gas is allowed to mix with the still burning coal particles; this water of combustion (or more exactly the free radical hydrogen specie) activates the carbon surface of the coal particles and greatly improves the combustibility of the coal particles.

Thus natural gas interferes with ignition mechanisms of coal by stealing the combustion air in the primary flame stabilization region of the burner; but, the water of natural gas combustion improves the combustion of carbon once stable flames establish in the combustion core.

Since the gaseous fuel burns most easily, the gaseous fuel should be proportionately the last to burn or burn separate from the coal flames. The implications of this are that the condensed phase burner is initially operating with proportionately higher excess air in its primary combustion and flame stabilization region and this leads to cleaner coal or oil combustion with less reducing slag or unburnt carbon effects.

The proportion of extra excess air available to the condensed phase primary zone is equal to the percentage of gaseous fuel that is later combusted by our delayed gaseous fuel combustion process. In our process of delayed combustion of the gaseous fuel, the final combustion air, when leaving the furnace volume still must be adequate to complete the combustion of the more easily burned gaseous fuel. This can be assured by monitoring the inputs and outputs of the furnace, and using that feedback to control inputs and burner operating conditions. This can be done with control logic in the boiler master controller always assuring that there is more air flow than cumulative fuel flow, thereby allowing safe and efficient gas co-firing.

With opposed-fired, turbo-fired or tangentially fired furnaces the flame region is generally defined as the center of the furnace flow volume, whereas with face-fired or other furnaces (such as roof-fired or stoker-fired) it is the higher velocity, high temperature flow which is often asymmetric in these different types of furnaces. Different types of furnace/burner/igniter combinations, but not all, are shown in FIGS. 7a, 7b and 7c.

In a turbo-type boiler shown in FIG. 7a there is one igniter 42 and associated co-fire gas spud 43 between two coal injector pipes 44 all of which are in an opening or openings 45 through which combustion air is injected into the burner. The configuration of a tangential type burner shown in FIG. 7b is similar to that of the turbo-type burner, but the igniters 42 may be aside each coal injector pipe 44 or between those pipes as shown in FIG. 7b. In other swirl type furnaces the igniter and co-fire gas injector may be adjacent the coal injector pipe as shown in FIG. 1 or the igniter 42 may be adjacent the coal injector pipe 44 with the co-fire gas 43 onside the tertiary air pipe on the centerline of the coal injector pipe 44 as shown in FIG. 7c.

In all cases, the bulk gas core flow allows the condensed phase combustion to continue. The combustion region may be predicted by computerized flow modeling (CFM) or measured by parametric gas injection and the testing of the condensed phase combustion completion. The furnace or boiler master controller controls the flow of the pulverized coal, combustion air, co-fire gas into each burner. As previously stated and shown in FIG. 8 control logic is provided under continual surveillance of the master controller to practice our method. The flow rates will be different for different types of burners and even for the same type of burners in different furnaces.

During co-firing the safe operation of the boiler is of paramount importance and the control logic of the gaseous fuel is designed so that the default operation is always that of the original design fuel, its Burner Management System and the Boiler Master Control. The control logic can also allow for the gaseous fuel to also be used as:

• • the igniter fuel for the main flame condensed-phase burner,
  • the warm-up and/or start-up fuel for the boiler,
  • the stabilizing fuel during transient operations, and
  • the variable input co-firing fuel with each burner, But each application must not compromise the bulk furnace volume combustion safety of the diverted co-fire fuel.

When class I gas igniters are available for each burner they are to be operated as originally designed when they are being used as burner igniters, and furthermore these igniters are always to be available for this dedicated use. However, once flames are proven and the igniters are allowed to be withdrawn from the flame safety and surveillance system, the method of our invention is that the control logic shown in FIG. 8, which we have developed and demonstrated, allows for the igniter tube itself or a separate gas tube to be activated to carry the gaseous fuel into the furnace in the manner predicated by our process of delayed combustion.

The overriding permissive to the introduction of co-fired gaseous fuel is that stable furnace operation has been achieved. Typically this will mean that:

• • The mid-furnace gas temperature is measured and it must be in excess of 1,700 F,
  • Combustion air must be in excess of that demanded by the boiler combustion master control accounting for all fuel input
  • Excess O₂ trim control must be above its minimum set point.
  • All of these permissives are only applicable after flame safety and its continuing surveillance is proven.

A typical embodiment of this control logic and safety system is shown in FIG. 8. The double block and bleed valves of the co-firing control system and its logic assures that gaseous co-firing fuel can only be introduced when our co-firing logic has confirmed all safety conditions as proven. During operation levels of CO, O₂, H₂O and NO as well as furnace temperature are measured at selected locations in the furnace. Measurements of coal flow and steam product may also be measured. In addition, emissions of NO, SO₃, CO, CO₂ and HCl may be monitored. This information can be used to control burner operation including adjusting coal flow and gas flow.

A present preferred embodiment of a co-fire tube which we have used is shown in FIG. 9a in assembled condition and an exploded view is shown in FIG. 9b. This co-fire tube 50 has an outer tube 51 with a housing 52 at one end that supports and air tube 53 that fits within the outer tube. A second housing 54 is attached to one end of the air tube 53 and to the first housing 54. An igniter tube 55 which carries the natural gas fits through housings 54 and 52 into the air tube 53. Housing 56 is attached to the end of the igniter tube. All of the housings have input ports. The igniter tube preferably has a diameter of 1.9 inches (4.826 cm.), the air tube 53 preferably has a diameter of 3.5 inches (8.89 cm.) and the outer tube preferably has a diameter of 4.5 inches (11.43 cm.). The co-firing tube 51 is co-axial to the igniter tube and carries 40 million BTU/hr. of natural gas whereas the inner igniter is capable of firing 20 million BTU/hr. Gas may be injected through a converging subsonic nozzle or through a divergent nozzle that produces a supersonic non-mixing core stream that later expands.

In a present preferred embodiment of a furnace that practices our method the gas supply is controlled by a piping and instrument valve system which supplies designed gas pressure and gas flow to the igniter tube or the separate gas injection tube. The gas supply header is fed through a gas block valve that assures that gas is not available at the boiler unless all permissives are proven while the bleed system relives all gas pressures and vents all gas lines away from the boiler.

To test our method an opposed fired 460MW Utility Boiler was fitted with three co-axial/co-firing tubes like those shown in FIGS. 9a and 9b inserted into three of 30 coal burners (capable of firing 140 million BTU/hr. each) arranged on 5 firing levels with three levels front and two rear; each level having 6 burners, 3 N-side and 3 S-side. The co-firing tubes were inserted into the air throats of the top level three burners N-side, each co-fire tube with capability of firing 40 million BTU/hr. or 28.6% of the total burner capacity. Thus the co-firing gas would be 5.7% of total N-side heat input and this is equivalent to a measurable decline of 1.1% or about 1% excess oxygen on N-side with an increase of about 1% excess O₂ on the S-side; except that flue gases from N-side obviously mix back and forth with S-side flue gases.

Data from a typical co-firing test run, starting at 13:55 on Oct. 1, 2014 is shown in FIG. 10a, with all 30 burner igniters on, the gas flow to the annular co-fire tube was increased from 330 to 450 for a total time of 45 minutes. The generation at about 450GMW remained constant, while the N-side O₂ dropped about 1% and the S-side initially remained the same, then increased as the boiler Master Controller accounted for the extra 120,000 cf/hr gas flow of fuel by reducing coal to the pulverizers.

Initially as the three N-side, top level co-fire tubes were sequentially brought into service over a period of 8 minutes, the excess O₂ dropped almost exactly 1%, due to this increased fuel input to the N-side. Due to this reduced excess O₂ in this N-side region shown in FIG. 10a, the CO increased from about 800 ppm to almost double at over 1,400 ppm. shown in FIG. 10b. The CO in all other quadrants of the furnace remained constant. However as the Boiler Master Controller sensed too much fuel input and cut back the coal flow to all 30 burners then more O₂ became available and the N-side O₂ increased after about 10 to 15 minutes with a subsequent decrease back to nominal CO of 800 ppm.

Because the N-side fuel was imbalanced by plus 6% due to the three co-fire tubes and the S-side coal flow was reduced, the O₂ imbalance of about 1% excess air, shown in FIG. 10a, between N-side and S-side now persisted through the remainder of the 45 minute test. The result of this imbalanced O₂ is that the CO on the N-side again goes high as the Boiler Master Controller reduces air flow to balance reduced coal flow. During this test the furnace exit temperature, reheat and superheat spays and dampers and the opacity showed no deviation from normal operation, thus demonstrating the ability to co-fire gas without interfering with coal flame safety or stable operation.

Although we have described our method as being used in a coal fired furnace the method could be used in oil fired furnaces as well as furnaces burning other fuels. Furthermore, the coal fired furnaces in which our method can be used are not limited to the types of furnaces that we have described and shown in the drawings.

While we have shown and described certain present preferred embodiments of our method for co-firing coal or oil with a gaseous fuel in a furnace it should be understood that our invention is not limited thereto and may be variously embodied within the scope of the following claims.

Claims

1. A method for co-firing a fuel containing coal or oil that is injected into a burner in a furnace, the burner being provided with combustion air and the fuel wherein the combustion air burns in a primary flame within a primary combustion zone in the furnace, comprising injecting a gaseous fuel into the burner in a manner so that the gaseous fuel does not consume air that would otherwise combine with the fuel in the primary flame.

2. The method of claim 1 wherein the combustion air is injected into the burner at a selected velocity and the gaseous fuel is injected at a gaseous fuel injection velocity that is higher than the selected velocity.

3. The method of claim 2 wherein the gaseous fuel is injected at a velocity that is between ¼ and 20 times greater than the selected velocity.

4. The method of claim 1 wherein the combustion air is injected into the burner at a selected velocity and the gaseous fuel is injected at a gaseous fuel injection velocity that is lower than the selected velocity.

5. The method of claim 4 wherein the selected velocity is from 1.5 to 30 times the gaseous fuel injection velocity.

6. The method of claim 1 wherein the gaseous fuel is injected axially along a centerline of the coal or oil being injected.

7. The method of claim 1 wherein the gaseous fuel is injected circumferentially with the fuel.

8. The method of claim 1 wherein the gaseous fuel is injected without adequate stoichiometric air in a direction away from the primary flame and at a velocity which is 1.25 to 20 times a velocity at which the combustion air is being injected into the furnace.

9. The method of claim 1 wherein the burner has an igniter and the gaseous fuel is injected coaxially around the igniter.

10. The method of claim 1 wherein the gaseous fuel is injected above the primary combustion zone of the furnace.

11. The method of claim 1 wherein the gaseous fuel is injected in a manner so that over half of the gaseous fuel burns outside of the primary combustion zone.

12. The method of claim 1 wherein the gaseous fuel is methane.

13. The method of claim 1 also comprising measuring at least one of loss on ignition, levels of CO, O2, H2O, and NO and temperatures in the furnace while the gaseous fuel is being injected and adjusting a flow rate of the gaseous fuel based upon such measuring.

14. The method of claim 13 wherein the adjusting is based upon a multivariate analysis.

15. The method of claim 1 also comprising measuring at least one of coal flow into at least one burner, steam production, furnace temperature in at least one location in the furnace, O2 levels in at least one location in the furnace, CO levels in at least one location in the furnace, and NOx levels in at least one location in the furnace before injecting the gaseous fuel.

16. The method of claim 1 also comprising measuring emissions of at least one of NO, SO3, CO, CO2 and HCl from the furnace.

17. The method of claim 1 wherein the gaseous fuel is injected through converging sub-sonic nozzle.

18. The method of claim 1 wherein the gaseous fuel is injected through a divergent nozzle that produces a supersonic non-mixing core stream that later expands.