Stories are often the best way to learn, especially when the topic is as complex as incomplete combustion.
D uring my 35 years specializing in the boiler-burner business I have discovered many ways to produce incomplete combustion, mostly by correcting the mistakes of others, but some through my own foolishness. By sharing these incidents, I hope to give you an understanding of what can produce incomplete combustion and how to detect it, correct it, and prevent it. Despite extensive experiences, I’m still discovering ways to do it wrong. I know I won’t live long enough to make enough mistakes so I can learn it all, and I trust you will take to heart this article because you won’t live long enough either.
Incomplete combustion of natural gas
Can you imagine operating a gas-fired furnace at 25 million Btu/hr and not knowing that another four or five million Btu/hr of natural gas was going up the chimney without burning? Can you imagine it going on for months?
One of the first trouble-shooting calls I received after hanging up my Merchant Marine License involved a vertically fired hot oil heater in North Carolina. The plant engineer called to describe the dilemma. ‘We had a thunderstorm last night and apparently lightning hit the stack of the vertical heater. Now we have this 40-ft. gas flame at the top of the stack. We were about to trip the safeties to shut it down but someone said that could make things worse. What do we do?’
Did the plant engineer hesitate to trip the heater because it might be more hazardous, or was he attempting to protect production? Shutting down the heater would require a process shut down and there was some indication that may have had more bearing on their decision to leave it running. Regardless of the rationale, the decision to keep the heater operational made a considerable difference in the outcome. You can appreciate the predicament the plant engineer found himself in. At that moment he had a hazardous situation on his hands. Subsequently, he would have to explain how he failed to detect thousands of dollars worth of gas wasted up that stack. Obviously, this is a case of incomplete combustion. At least it was incomplete until the lightning struck the stack. What would you have done?
Perhaps your first thought would be to trip the safeties-simply shut off the gas. But that’s not the best thing to do as long as the burners continue to fire, flame monitoring being an accepted condition on almost all gas fired equipment today. The furnace contained a considerable amount of unburned fuel. As long as the burners continued to fire and generate inert gas from the mixture of combustion air and fuel that was burned, there was no way for that excess fuel to ignite inside the unit. If the burners were shut down, then the post-purge air that followed would be available for mixing with the unburned fuel to produce an explosive mixture that could ignite somewhere. In this particular case, there was a significant source of ignition raging at the top of the stack.
I advised the plant engineer to slowly (I used a good three seconds to say the word ‘slowly’) decrease the gas input until the fire on the stack was extinguished. Then I suggested he get someone in to tune up the combustion controls as soon as possible. I waited on the phone and the plant engineer finally reported, ‘The flame on the stack simply floated away.’ The plant did spend some money improving the control system on that heater. I don’t know if the plant engineer kept his job.
The important lesson to remember is that incomplete combustion leaves unburned fuel that can mix with air from any number of sources, and then ignite in an uncontrolled manner, normally as an explosion. A wise person will also keep in mind that you are generating an inert gas with normal combustion. Remembering those two basic rules may protect life and limb, or at least some equipment, in the future.
Know your fuel consumption rate
Why didn’t the North Carolina plant notice the problem earlier? After all, shouldn’t a fuel rich gas fire look very yellow, lazy, and maybe even have smoky tips? Perhaps it’s because a vertically fired heater doesn’t have readily accessible furnace observation ports and the unit was operated remotely. Despite any arguments for detecting it by observation, if they had been monitoring its overall performance, they should have spotted the problem long before it became serious. Every article I write on fuel systems, every conversation I have with a customer includes the caveat: keep a record of fuel consumption rates on a per-unit basis.
You should keep a record of fuel usage rates for every fired unit in your facility. You should know the rate for every heating boiler, hot water heater, piece of fired process equipment, and (unconditionally) every power boiler. Sometimes you can’t afford metering for each piece of equipment and have to consider them in groups, especially if they’re small, but you should still keep records. For power boilers the value is Evaporation Rate-how many pounds of steam are generated for each gallon of fuel oil, pound of solid fuel, or therm of gas you burn? With other equipment it’s simply a matter of using whatever output value is available. In small heating plants, I like to see a comparison with degree days. Use whatever is available to catch a change in fuel consumption rates before lightning sets your stack on fire.
More about incomplete combustion of gas
For most burners, the method of introducing natural gas is via a gas ring. It’s a pipe rolled to produce a donut shape with an internal diameter matching, or nearly so, the inside diameter of the burner throat. The ring is fitted with a piping connection to receive the gas and drilled around its internal diameter with holes sized to match the burner capacity.
All too frequently I’m asked to look at a poorly performing gas burner, only to discover a lot of those holes partly obstructed with mortar or plastic refractory left from a recent furnace repair. Since the burner throat is a convenient opening in the boiler for people and material to enter for repairs, the burner ring becomes a candidate for blockage, normally at the bottom of the ring. Many a plant engineer has been embarrassed when, after badmouthing the boiler, burner, and control technicians for their lack of skill in restoring burner performance, he’s told he failed to ensure his gas ring was clean before closing the burner throat access.
Yes, I’ve heard of cracked gas rings, however, in 35 years I have yet to see one. I have seen evidence of gas ring connections leaking into the windbox, breaks at welds of mounting lugs on gas rings, and holes plugged by leakage from an oil gun. It’s also not unusual to encounter situations where the diffuser position was not restored when switching from oil to gas firing. When diffusers or register assemblies are significantly off center, unusual swirling action can occur at the burner throat creating a lopsided fire that is fuel rich on one side and lean on the other.
In the Baltimore-Washington Metropolitan area, we occasionally receive Algerian gas as part of the normal delivered fuel. Algerian gas is liquified natural gas (LNG) delivered by ship from North Africa that is vaporized and blended with the normal flow from Texas and Gulf gas wells. The blended gas has a significantly different theoretical air requirement, needing as much as 10% more air than the normal supply. Most domestic, commercial, and small boiler plants can handle the variation because they are not tightly tuned. Any tightly tuned boiler (10% excess air or less) without oxygen trim will experience incomplete combustion when receiving the LNG/natural gas mix, but they may not know or discover it.
Some years ago, during startup of a boiler converted to gas , the operation resulted in tripping another recently converted boiler because of low gas pressure. A combination of events led to popping the safety relief valve at the gas service. That alone shouldn’t have been a problem but the safety valve exhaust line terminated just above, and only a few feet away from a louver that admitted combustion air into the boiler plant. The boiler under startup suddenly became unstable because natural gas was being drawn in with the combustion air.
Gas is lighter than air, but, as bad as it sounds, an improperly placed exhaust from a safety valve is not as hazardous as systems with no safety valve. If your gas service is delivered from a system that operates at higher pressures than your components can tolerate (usually 50 psig on large systems, 5 psig on small ones), you should provide your own full capacity safety relief valve. That means providing a valve that will relieve 100% of the gas that the service is capable of delivering with a pressure rise that doesn’t exceed your system’s capability.
There is a common misconception that the utility will provide an adequate safety valve. On those occasions when the utility company provides a safety valve, you should be aware that the typical pressure rise for those safeties is 50%. That means the capacity isn’t relieved until the pressure is 150% of the opening set pressure.
Safeties, interconnections
Many services contain what I call a sentinel valve. It’s a relief valve that discharges to or through the equivalent of an air horn to sound a warning that the delivery pressure is higher than the safety pressure setting. Recently I found one of these sentinel valves on a service with a 300 psig supply, but with no provisions for additional safety relief, and the owner elements were rated at 50 psig.
Despite safety code requirements , exhaust, vent, bleed, and balancing piping are frequently interconnected. Engineers, installing contractors, and repair mechanics choose to save on installed piping by connecting these different piping systems together.
When gas is admitted to an exhaust or bleed piping system connected to the balancing line for a gas pressure regulator the result is delivery of fuel gas at a higher pressure than normal and what follows is a fuel rich furnace. It’s hazardous because the condition is intermittent. The quick variations from air-rich to fuel-rich provides an opportunity for the unburned fuel to mix with excess air to form an explosive mixture that is eventually ignited somewhere in your furnace or boiler. This condition is so prevalent I’m certain half of the readers will discover it exists in their plant. Even more dangerous is connecting these piping systems between multiple boilers.
Incomplete combustion of oils
Unlike gas, fuel oils almost always provide obvious indications of incomplete combustion, and there are more ways to do it. Most of us have observed the great clouds of black smoke spewing out a stack. That is the principal indication of incomplete combustion of oil. Incomplete combustion can also be detected in white smoke and, with heavier oils, accumulations of carbon deposits in the furnace. Just like gas, oil can also burn incompletely with no visible evidence.
No one ever tests for raw hydrogen in a stack, because hydrogen always burns. Thus, the smoke, soot, and other evidence of incomplete combustion result in mostly unburned carbon. We’re familiar with carbon in many forms, including the pencils we write with, charcoal, etc. In every case it’s black. Therefore, any black material around a boiler is likely an indication of incomplete combustion. It’s an indication that there’s not enough combustion air at the burner.
Hydrogen, and some of the carbon, are burned to generate enough heat to crack (a petrochemical term that describes the process of breaking complex hydrocarbons down into less complex forms) remaining fuel leaving mostly carbon. Complex hydrocarbons are reduced to simple gases by the heat of the fire and they burn to release energy, part of which is used to crack more of the fuel. Since there’s proportionately more carbon in liquid and solid fuels the cracking process results in some raw carbon remaining. The source of the bright yellow color in liquid and solid fuel fires is the slower burning carbon. When there isn’t enough air to burn all the carbon, it leaves the furnace as unburned fuel, regardless of temperatures, and appears as black smoke in the flue gases.
Black smoke can also exist even with sufficient oxygen in the flue gas to burn it completely, because the air and fuel must mix and be exposed to a source of ignition to burn. If the fuel and air are not completely mixed within the furnace, where temperatures are high enough to ensure ignition, a combustible mixture can pass on to the stack.
Simple mistakes, deadly results
Prime examples of the mixing problem are associated with simple mistakes. Inserting an oil gun in a burner without a tip can produce such results and is a very common error. The oil isn’t atomized and doesn’t completely mix with the air in the furnace. One customer in southern Pennsylvania discovered that burner tips can be loosened and fall off the burner into the furnace. An inexperienced operator can also assemble a burner improperly.
Most problems with black smoke and adequate air are due to problems with the oil gun or tip. If it occurs on startup, and personnel continue repeated attempts to light the burner, an explosion is bound to follow. One of my service technicians arrived at a site to help with a burner that wouldn’t light. While observing an attempt to light-off the burner, he noted the burner tip was missing, and had just walked away from the rear of the boiler to inform the operating personnel of their mistake when the entire rear of the boiler smashed against the concrete block wall behind it. Had he continued his observation for another two seconds, he would not be alive today. That same explosion also damaged the front of the boiler slightly , injuring one of the operators.
White smoke is caused by too much combustion air and indicates the presence of raw unburned fuel, virtually unaffected by the heat in the furnace. The oil is properly atomized, but because there is so much excess air, it never encounters enough heat to begin to ‘crack’ it. The resulting white smoke is the atomized droplets of oil making their way up the stack and refracting sunlight like water droplets. White smoke can also be an explosive mixture, and any increase in temperature from an external source-like an adjacent stack or lightning-could cause it to ignite.
Another form of incomplete combustion of oil is carbon buildup in the furnace. I recall looking in a burner observation port on one ship to see a complete arc of glowing carbon around the opening that the flame penetrated. Oil-fired furnaces are not equipped to remove carbon accumulations, so any carbon buildup is a serious problem. It also represents an accumulation of unburned fuel that could suddenly mix with air to form an explosive mixture. It’s a significant problem if it builds up on a furnace sidewall where it can fall off and fracture into thousands of bits of fuel. Most explosions from falling carbon buildups are not adequate to rupture a furnace setting, but there’s always a possibility of one being just enough.
Missing or improperly assembled tips are only two ways tip problems contribute to incomplete combustion. Worn tips are another. Tips improperly cleaned using steel or stainless instead of brass tools and brushes will also not atomize properly. Repeatedly, boiler operators use the improper tools to quickly clean burner tips believing they are doing the right thing by getting the burner back into service as quickly as possible. The reality is, burner tips damaged by improper cleaning require more frequent cleaning, and increase the frequency of soot blowing or tube brushing. Use of the wrong tools can result in boiler operators creating additional work for themselves.
Improper atomization is not always a function of burner tip assembly. It can also be caused by low fuel temperature, formation of paraffins from improper storage, oil contamination by water or soil, blending of incompatible oils, and high oil temperatures which produce flashing at the tip leading to oil that agglomerates rather than atomizes.
Inadequate soot blowing or fire-tube brushing can reduce heat transfer in a boiler sufficiently to promote over-firing. When that occurs the fire can strike the furnace walls depositing carbon and agglomerate the oil particles to produce more soot, making a bad situation worse. I’ve peered through furnace observation ports several times to see oil running down the tubes and walls due to improper atomization or over-firing.
Incomplete combustion of coal and other solid fuels
Most electrical energy generated in the United States is produced by coal-fired plants. Solid fuels, like coal, must be cracked to generate flammable gases that will burn and provide the heat to elevate carbon to temperatures where it will oxidize. Combustion becomes even more complex because of the difficulty of mixing the fuel and air but , because there are so many ways to accomplishing it, it’s beyond the scope of this article. Incomplete combustion of coal produces black smoke that can be soot, like oil, or can also be raw unburned fuel that doesn’t reflect or refract light to look white. Carbon can build up in solid-fuel fired furnaces just like in oil-fired units.
Unburned carbon is also found in the ash removed from solid-fuel firing. Sometimes referred to as LOI (loss on ignition), the combustibles content of ash is used to describe incomplete combustion in coal- and solid-fuel fired boilers. A solid-fuel fired installation I worked on in the late 1980’s had considerable carbon content in the flyash during startup. Burner modifications changed the black dirty ash to beige-colored sand practically devoid of carbon. Monitoring the carbon content of bottom ash and flyash is important in understanding the condition of a solid-fuel fired furnace and its fuel burning equipment.
Practically all solid fuels, and some oils, contain substantial quantities of ash. This ash can produce significant wear on tubes and refractory. Tube leaks at fuel beds in stoker-fired boilers can quench the fire in their vicinity to produce smoke and large quantities of carbon in the bottom ash. Flyash can wear away baffles in the boiler to produce bypassing that promotes over-firing and reduced boiler efficiency. In one small, pulverized coal-fired installation in central Pennsylvania, we found holes in the baffles that permitted raw fuel to accumulate and cause several damaging fires in the baghouse.
We all understand the accumulation of unburned solid fuels within boilers is a potential source for explosions. I have stirred up hot coals in a pile of wood ash that was more than a day old. That’s why NFPA (National Fire Prevention Association) codes limit the purge air-flow rate of coal-fired boilers. Operating soot blowers at low firing rates or during other operations with extremely high excess air can produce explosive mixtures by dislodging and mixing the accumulated unburned fuel with the air.
The many variations of coal- and solid-fuel fired systems makes it impractical to address all possible problems with, and sources of, incomplete combustion when firing those fuels. But as I said earlier, it’s important to maintain good records, track fuel consumption rate and watch the carbon content of bottom ash and flyash for early indications of incomplete combustion.
Air systems affect incomplete combustion
Over the years, I have regularly seen one common mistake that causes incomplete combustion. While plugged strainers, defective regulators, and other device failures are noted and maintained, operating and maintenance personnel always seem to fail to do anything about the dust and debris that accumulate on the inlet screen of the forced-draft fan, the fan blades, on louvers, and other features designed to admit combustion air into the boiler room.
Many industrial and institutional boilers I deal with are equipped with simple jackshaft controls where one modulating motor rotates a shaft that contains linkage connecting the fan damper and fuel flow control valves. Once set, this system reliably provides a consistent and repeatable air/fuel mixture at the burner. Fuel supplies and, when boilers are served by a common stack, furnace pressure control, all stabilize system operating pressures so the mere positioning of the fan damper and fuel valve reproduces a combustible mixture at the correct air to fuel ratio. But that assumes the air can reach the combustion chamber. I have seen fan inlet screens so obstructed that a gas-fired boiler produced smoke.
Always note the airflow at the door when entering a boiler plant. It’s an indication of problems with combustion air entering the building. On more than one occasion I have found it takes all my strength to open the door into the boiler room because the plant is under a vacuum. Only one inch of water column produces enough differential pressure to require a 38-lb. force to open the normal personnel door. I was engaged in troubleshooting one installation where restrictions in combustion air flow resulted in destruction of three heating boilers in less than three years because the boilers were alternatively exposed to reducing conditions (fuel rich) and oxidizing conditions (shut down) that removed all tube metal.
Modern burners, designed to minimize the generation of nitrogen oxides, have incorporated shrouds, baffles, and other elements in burner windbox construction. Those devices serve to provide an evenly balanced distribution of air to the burner. At the same time, they can disturb that balance if they fail, are contaminated with airborne dust and debris, or are simply improperly applied.
Proper distribution of air in multiple burner boilers is paramount to ensuring complete combustion.
Perhaps you have seen articles describing the intentional maldistribution of air to achieve staged combustion for nitrogen-oxides control. Those applications have their place, principally in utility boilers, but industrial and institutional boilers for the most part require uniform delivery of fuel and air so an adequate air/fuel mix is provided at each burner. Operation of a multiple burner boiler requires starting and stopping some of the burners and normally provides flame detection of individual burners. When operating at low excess air rates, it is important to control the distribution of air to each burner in concert with the distribution of fuel. Air register actuators that open and close the register control air flow simultaneous with the opening and closing of fuel shutoff valves to maintain proper air-to-fuel ratio at the burners that continue in operation. Improper operation of fuel valves and burner registers can result in fuel rich conditions at some burners and subsequent mixing of the unburned fuel with air passing through registers with their fuel valves closed. Those mixtures can reach explosive range anywhere in the boiler setting. Typical occurrences are an explosion early in the convection bank where temperatures are still high and ignition of those mixtures by sparking of an electrostatic precipitator.
Unique situations involving incomplete combustion
The standard arrangement of cross-limited combustion controls should prevent a fuel-rich situation, right? Only if the fuel flow signal isn’t in error or missing.
We had replaced controls on three boilers in a Baltimore plant in the late 1970’s with a successful turnaround. The owner was very happy with system performance until a week or two after the job was done. Suddenly, and without explanation, one of the boilers started huffing and puffing, then tripped on flame failure with a subsequent large puff. (I trust you understand that a ‘puff’ is really an explosion that doesn’t do any damage.) After testing and re-start, the boiler operated normally until it reached 50% firing rate, then the same disturbance occurred. Further inspection revealed the air supply regulator for the gas flow transmitter was set at 9 psig. If you’re familiar with pneumatic systems, you know 9 psi is 50% on a 3 to 15 psi system. Since the gas flow transmitter couldn’t output more than 50%, the controls continued to open the fuel valve wide any time the boiler master exceeded that value. Another boiler suffered a similar problem a few days later, and we discovered that the springs in the air pressure regulators were breaking. Replacing all the regulators eliminated further problems.
We had a similar problem with oil flow transmitters on an electronic installation at a western Maryland facility. The transmitters ‘hung up,’ failing to produce any flow signal, and did so randomly. We replaced the transmitters. To prevent sending another black smoke cloud over the entire city of Frederick, which we already had experience doing, one of my service technicians developed a controller program modification that alarms on loss of the fuel flow signal and locks the controls in the low-fire position. That logic worked so well I have incorporated it in every control system design since.
Two days after accepting the challenge to write this article, I was called to investigate emissions from a furnace that also serves as a fume incinerator. The customer claimed to have done everything possible to eliminate a brown haze at the stack.
This particular fume incineration system included a 300-ft. duct between the fume generating process and the burner; a fan above the burner that draws fumes from the process and injects them into the furnace; and a single blade discharge damper at the fan inlet with duct work that splits into two headers, one on each side of the burner, with a flame arrester at the top of each header.
Connecting the furnace to each header are five 4-in. pipes formed to provide ports around the burner. A dropout box at the fan inlet and the fan housing are both fitted with drains to convey condensed liquids to a waste tank. The two headers are also fitted with drain piping. To prevent back-flow of furnace gases, bleed steam is admitted to the header system after the damper. From the rear furnace inspection ports, there was no evidence of incomplete combustion at the fume ports. Having eliminated all other possibilities, we checked the drains at the bottom of the headers to find them plugged despite reports they were recently cleaned. The small amount of liquid condensed in the headers had accumulated until it ran into the furnace at the bottom port. Liquid introduced in that manner does not mix well with the combustion air and produced the visible emission.
I’ve seen failure of the top seal of an `A’ type boiler allow a portion of the flame to escape from the furnace directly to the boiler outlet. High CO and loss of boiler tube metal has been associated with tangent tube wall leaks.
Another recent investigation involved two new boilers that ‘never worked.’ When I climbed inside the furnace, the reason was apparent. The boilers were assembled wrong! These were modern bent tube boilers that should have been assembled with the tubes tangent in both the vertical and horizontal assembly. Since significant gaps existed in what was supposed to be a tangent tube furnace roof, incompletely burned fuel and CO passed quickly out of the furnace. The improper construction allowed subsequent mixing of fuel and air that generated a lot of noise and a couple of explosions within the tube bank that seriously damaged the boilers.
Many problems of incomplete combustion are revealed through complaints of flame noise. The condition referred to as ‘rumbling’ is normally due to improper mixing at the burner but subsequent mixing-to form miniature explosive pockets-in other parts of the boiler. Every incident of rumbling I have investigated has included high levels of CO in the stack gases. The condition is not readily fixed because the minute the fuel and air enter the burner, science takes a back seat to art, and the number of combustion ‘artists’ is dwindling.
Measuring incomplete combustion
All the foregoing involved what are really major problems with incomplete combustion. Most of the time we are dealing with it at a level that is undetectable by eye or through other means.
Typical means of monitoring incomplete combustion is the measurement of CO (carbon monoxide) in the boiler flue gas. That measurement is normally reported in parts per million (ppm), representing what was considered insignificant in boiler operation in the 50’s and 60’s. High levels of CO, despite adequate combustion air, are found in boilers with baffle problems, or in boilers with tangent tube baffle walls where the CO formed in the process of combustion is chilled by tubes or leakage into a cooler section of the boiler below the CO’s ignition temperature. Since the ignition temperature of CO is about 1,200 °F, it can easily happen. Measuring CO is measuring incomplete combustion.
You have seen the CO curves before.
As excess air is decreased, CO starts to form and increases exponentially as excess air approaches zero. This typical curve is not standard, as many people are willing to believe. Since oxygen is almost always 20.9% (by volume) of the combustion air, the oxygen curve is always as shown. The CO curve, however, is another story. Any extrapolation to the right would fail because CO will be produced and increase exponentially beginning somewhere between 100% and 400% excess air, it depends on the burner. Any burner with poor mixing will generate CO regardless of the amount of excess air so CO may never reach zero. And, the characteristic of the CO curve can vary from logarithmic (as shown) to a simpler or more complex form.
You’ve seen the curves several times and now you understand the CO element is seldom as shown, if ever, so what good is the curve? I can tell you this much-any published curve is useless to you. However, if you operate your burner at a fixed firing rate and measure flue gas oxygen and CO content while adjusting the combustion air to produce oxygen levels of 1% to 5%, you can create a curve that represents your burner’s performance.
If you find you fixed the problems we’ve already covered but still can’t operate without CO exceeding 100 ppm, then you should seek out one of those remaining combustion artists to get your burner adjusted or modified, followed by a repeat of the process to measure the incomplete combustion on your burner. Since the curve shown is representative of a properly operating burner, don’t be satisfied with anything worse.
Controlling incomplete combustion
Yes, you actually can control incomplete combustion. By installing a continuous CO analyzer on the outlet of a boiler and regulating the air to fuel ratio controls to maintain a constant CO at the outlet you control incomplete combustion. CO control is favored in several installations, especially those where setting leaks, or the like, do not provide an oxygen value at the outlet that is the same as furnace conditions. Air leaking into the equipment can increase the oxygen content of flue gas to prevent accurate control of excess air at the burner. The only effect of air in-leakage on CO measurement is slight dilution.
CO control also avoids a problem with oxygen trim systems using zirconium oxide analyzers. It is possible for those analyzers to misinterpret CO as oxygen when there is no oxygen present. When controlling excess air at low values an oxygen trim system can automatically swing into a reverse action that produces a lot of incomplete combustion. Many oxygen trim systems also use combustible analysis to detect the problem and alarm or reverse it. A CO analyzer is not capable of misinterpreting anything else as CO.
For many users, the cost and maintenance of CO analyzers may preclude use of CO control systems on small and medium size boilers (under 100 million Btu/hr).
Economics of incomplete combustion
Should you encounter a situation like the one in North Carolina (lightning hitting the stack), the simplest way to determine the financial impact is comparing fuel consumption rate.
First, calculate an absorption rate (such as heat added to the working fluid for each therm of gas consumed) during the incomplete combustion condition and after it’s corrected. Then determine the loss by comparing the two. Incomplete combustion of carbon in ash is valued by determining the number of pounds of carbon in the ash and giving it a heat value of 14,000 Btu per pound. Comparing the heat in that carbon collected over a given period of time with the heat value in fuel burned provides a percentage loss of the fuel burned. Loss in CO is determined similarly-calculate the mass of CO and give it a heating value of 10,000 Btu per pound.
Incomplete combustion is costly to ignore. With every company trying to improve profitability and productivity, paying attention to those boilers can add to the bottom line in more ways than one.
For more information about KEH Energy Engineering, visit www.KEH-EE.com or call (410) 679-6419.
Mr. Heselton is a graduate of the United States Merchant Marine Academy at Kings Point, Long Island, N.Y., where he served as a third and second assistant engineer aboard several ships before moving his career on shore. Mr. Heselton spent several years as the principal design engineer of Power and Combustion Inc., a contractor specializing in construction and modification of boiler plants before founding KEH Energy Engineering.
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