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Unburned Carbon in Ash
- Thread starter 749KDV
- Start date
orenda1168
Chemical
- Dec 12, 2002
- 234
749KDV:
Assuming the fuel preheat is where it should be for the fuel composition and required burner viscosity, the burners are in top-notch shape with the proper geometry for the fuel and furnace, and the atomizing steam is correct for the fuel, the residual ash carbon content should be well below 0.1%.
Variation from optimum of any of the above can and will result in a marked carbon residue increase.
Orenda
Orenda
Assuming the fuel preheat is where it should be for the fuel composition and required burner viscosity, the burners are in top-notch shape with the proper geometry for the fuel and furnace, and the atomizing steam is correct for the fuel, the residual ash carbon content should be well below 0.1%.
Variation from optimum of any of the above can and will result in a marked carbon residue increase.
Orenda
Orenda
749KDV:
It depends upon what you mean by "ash" when talking about units fired with heavy fuel oil. The flue gases from fuel oil firing will indeed contain solid particulates matter (PM) but it will also contain condensible PM which will will only become solid after the flue gas is cooled.
Furthermore, the flue gases will contain many different volatile organic carbon (VOC) species (i.e., benzene and other aromatics, and a host of other organic compounds) which will cool and condense into organic liquids all of which contain carbon.
It would be helpful to tell us whether you are only concerned with the solid PM or whether you are concerned with the solid PM plus the condensible PM ... or perhaps you are concerned with the total carbon in the flue gases.
It should also be noted that the amount of unburned carbon varies significantly with how much excess combustion air is being used. High amounts of excess combustion air result in lowering the amount of unburned carbon. Many power plants use low-NOx burners to lower their NOx emissions and those low-NOx burners usually entail lowering the amount of excess combustion air ... which increases the amount of unburned carbon. Thus, power plants using low-NOx burners will have higher amounts of unburned carbon than plants that do not use low-NOx burners.
Many boiler manufacturers offer new designs which can provide lower NOx emissions without unduly increasing the amount of unburned carbon. But not many existing power plants have yet been retrofitted with such designs.
Sorry to be so long-winded but perhaps you will find the above discussion useful.
Milton Beychok
(Contact me at www.air-dispersion.com)
.
It depends upon what you mean by "ash" when talking about units fired with heavy fuel oil. The flue gases from fuel oil firing will indeed contain solid particulates matter (PM) but it will also contain condensible PM which will will only become solid after the flue gas is cooled.
Furthermore, the flue gases will contain many different volatile organic carbon (VOC) species (i.e., benzene and other aromatics, and a host of other organic compounds) which will cool and condense into organic liquids all of which contain carbon.
It would be helpful to tell us whether you are only concerned with the solid PM or whether you are concerned with the solid PM plus the condensible PM ... or perhaps you are concerned with the total carbon in the flue gases.
It should also be noted that the amount of unburned carbon varies significantly with how much excess combustion air is being used. High amounts of excess combustion air result in lowering the amount of unburned carbon. Many power plants use low-NOx burners to lower their NOx emissions and those low-NOx burners usually entail lowering the amount of excess combustion air ... which increases the amount of unburned carbon. Thus, power plants using low-NOx burners will have higher amounts of unburned carbon than plants that do not use low-NOx burners.
Many boiler manufacturers offer new designs which can provide lower NOx emissions without unduly increasing the amount of unburned carbon. But not many existing power plants have yet been retrofitted with such designs.
Sorry to be so long-winded but perhaps you will find the above discussion useful.
Milton Beychok
(Contact me at www.air-dispersion.com)
.
- Thread starter
- #4
Thank you Orenda and Milt for responding so quickly. The discussion that was started indeed was useful and prompts me to quote Albert Einstein, "The more I learn, the more I realize I don't know. The more I realize I don't know, the more I want to learn".
Back to the subject, excess combustion air ~ 8%-10%. I am working on a retrofit of an older boiler (1960's vintage) and I am trying to "predict" the flue gas flow, ductwork pressure drop, fly ash and bottom ash loading, etc. In my combustion calc, I use a value of 2% unburned carbon in the ash as opposed to the 8% predicted value for the same unit while burning coal.
Milt you bring up valid points and I did increase the percent ash in the ultimate analysis to include asphaltenes and sediment, so the ash loading as a result of the combustion calc takes that into account. When you speak of the VOC's and other organic compounds that will condense when cooled, are you speaking of liquids that will clog an air heater? If this is the case, I am mainly concerned with what passes through the air heater, through the electrostatic precipitator and can ultimately be caught in a fabric filter (bag house). It is this piece of equipment which I am concerned.
I just wanted a warm fuzzy feeling that the value that I used for fuel oil is not way off the mark (as this value was pulled out of the derri~"air"). From the information that Orenda provided, my value of 10 times the predicted value seems reasonable given that all of the variables involved will not be at their optimum levels.
Ultimately, the value that I use for the percent unburned carbon in ash will have little effect on my conclusions, but I want to be sure that I use a reasonable educated assumption.
Back to the subject, excess combustion air ~ 8%-10%. I am working on a retrofit of an older boiler (1960's vintage) and I am trying to "predict" the flue gas flow, ductwork pressure drop, fly ash and bottom ash loading, etc. In my combustion calc, I use a value of 2% unburned carbon in the ash as opposed to the 8% predicted value for the same unit while burning coal.
Milt you bring up valid points and I did increase the percent ash in the ultimate analysis to include asphaltenes and sediment, so the ash loading as a result of the combustion calc takes that into account. When you speak of the VOC's and other organic compounds that will condense when cooled, are you speaking of liquids that will clog an air heater? If this is the case, I am mainly concerned with what passes through the air heater, through the electrostatic precipitator and can ultimately be caught in a fabric filter (bag house). It is this piece of equipment which I am concerned.
I just wanted a warm fuzzy feeling that the value that I used for fuel oil is not way off the mark (as this value was pulled out of the derri~"air"). From the information that Orenda provided, my value of 10 times the predicted value seems reasonable given that all of the variables involved will not be at their optimum levels.
Ultimately, the value that I use for the percent unburned carbon in ash will have little effect on my conclusions, but I want to be sure that I use a reasonable educated assumption.
Assuming that your #6 fuel oil contains sulfur within typical limits, your concern at the back end should be with sulfuric acid formation if the APH, ductwork, stack, etc. fall below the acid dew point of your flue gasses.
#6 oil fly ash what there is of it, is pretty sticky and nasty in my experience, not at all friable like coal fly ash, so if your APH is a Ljunstrom type, measures to clean the baskets (online if possible) should be considered.
I am going to have to put my thinking cap on to see if I can remember a baghouse on #6 oil.
Bottom ash is negligable. Most boilers I see that have elaborate bottom ash systems for #6 oil don't use them, and some are covered over with refractory. But this might not be the case with your oil. #6 oil, while a generic term, is different based on source, blending, and other factors. There have been many good discussions of #6 oil on this site. A search should reveal some interesting reading.
rmw
#6 oil fly ash what there is of it, is pretty sticky and nasty in my experience, not at all friable like coal fly ash, so if your APH is a Ljunstrom type, measures to clean the baskets (online if possible) should be considered.
I am going to have to put my thinking cap on to see if I can remember a baghouse on #6 oil.
Bottom ash is negligable. Most boilers I see that have elaborate bottom ash systems for #6 oil don't use them, and some are covered over with refractory. But this might not be the case with your oil. #6 oil, while a generic term, is different based on source, blending, and other factors. There have been many good discussions of #6 oil on this site. A search should reveal some interesting reading.
rmw
- Thread starter
- #6
- Thread starter
- #8
With a Ljunstrom remember that if you had just bought a brand new one "in the box", that it would come with a guaranteed leakage rate of somewhere near 8%. Older ones with years of service, abuse, warpage, multiple seal replacements, etc., can have leakage rates upwards to the neighborhood of 25%. I've seen them that high.
What this means to you is that you have to account for that leakage of the cold FD air around the seals into the ID ductwork from the APH on out to the stack in your calculations regarding predicted outlet gas temperatures from the APH downstream, especially if you are increasing your FD pressure to accomodate burner register pressures necessary for good oil firing.
You may need to adjust your economizer or boiler back pass surface area to accomodate this. It is an additional thermodynamic loss to have to raise the outlet temperature, but rotting down the back end tends to be detrimental to unit reliability.
rmw
What this means to you is that you have to account for that leakage of the cold FD air around the seals into the ID ductwork from the APH on out to the stack in your calculations regarding predicted outlet gas temperatures from the APH downstream, especially if you are increasing your FD pressure to accomodate burner register pressures necessary for good oil firing.
You may need to adjust your economizer or boiler back pass surface area to accomodate this. It is an additional thermodynamic loss to have to raise the outlet temperature, but rotting down the back end tends to be detrimental to unit reliability.
rmw
- Thread starter
- #10
749KDV:
Yes, when I spoke of VOCs condensing, I meant condensing to a liquid. Which VOCs will condense depends on your temperature profile as the flue gas flows through the air preheater and the subsequent equipment. Each specific VOC will condense when and if the temperature drops down to the atmospheric boiling point of that specific VOC. Condensed VOCs are probably what cause the "sticky" fly ash that RMW mentioned.
Milton Beychok
(Contact me at www.air-dispersion.com)
.
Yes, when I spoke of VOCs condensing, I meant condensing to a liquid. Which VOCs will condense depends on your temperature profile as the flue gas flows through the air preheater and the subsequent equipment. Each specific VOC will condense when and if the temperature drops down to the atmospheric boiling point of that specific VOC. Condensed VOCs are probably what cause the "sticky" fly ash that RMW mentioned.
Milton Beychok
(Contact me at www.air-dispersion.com)
.
749KDV:
In one of your post at 7:36 this morning, you mentioned that you had made a combustion calculation. Just as a "sanity" check, you should have about: (a) 11,000 to 12,000 scf of wet flue gas per million Btu of fuel oil fired and (b) about 10,000 to 11,000 scf of dry flue gas per million Btu of fuel oil fired. By scf, I mean a standard cubic foot of flue gas measured at 60 degrees F and 14.696 psia.
Milton Beychok
(Contact me at www.air-dispersion.com)
.
In one of your post at 7:36 this morning, you mentioned that you had made a combustion calculation. Just as a "sanity" check, you should have about: (a) 11,000 to 12,000 scf of wet flue gas per million Btu of fuel oil fired and (b) about 10,000 to 11,000 scf of dry flue gas per million Btu of fuel oil fired. By scf, I mean a standard cubic foot of flue gas measured at 60 degrees F and 14.696 psia.
Milton Beychok
(Contact me at www.air-dispersion.com)
.
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