Ammonia adsorption on ash

Prepared by Penelope Stamatakis

Introduction

There are two primary post combustion technologies that reduce NOx via the introduction of an 

amine based reducing agent, namely Selective Non Catalytic Reduction (SNCR) and Selective 

Catalytic Reduction (SCR). Ammonia slip is a by-product of both of these technologies and it 

refers to ammonia in the gaseous phase, typically measured at the economizer outlet using EPA 

method CTM-027. The control of ammonia slip is an integral part of the optimization phase in 

any SNCR or SCR application. The gaseous ammonia left uncontrolled, has the potential to

combine with SO3 in the flue gas and form undesirable ammonium bisulfate deposits on metal 

surfaces. Additionally, depending on the ash properties, a significant amount of the ammonia slip 

may be adsorbed on the ash. Typically, ammonia is adsorbed on the ash either chemically, via the 

formation of ammonium sulfate and bisulfate salts on the ash, or physically, on unburned carbon 

surfaces. This becomes a problem for clients who sell their ash to the cement industry, since 

during the making of concrete, ammonia may be released from the ash as the pH increases due to 

the addition of lime. Released ammonia gives off a unique odor which is detectable by smell if 

the levels of ammonia on the fly ash exceed the range of 50 to 100 mg/kg. Utilities that employ 

Fuel Tech’s SNCR and SCR technologies routinely ask for the expected level of ammonia on the 

fly ash. This study will address this question by looking at ammonia adsorption on the ash as a 

function of coal type and ash properties and develop a methodology to predict ammonia 

adsorption on ash.

Background

During the combustion of sulfur-containing fuels, over 95% of the sulfur is converted to sulfur 

dioxide. Subsequently, more than 1% of the sulfur dioxide may be further oxidized to sulfur 

trioxide. (Ref. 1) Sulfur trioxide has the potential to combine with the ammonia slip generated via

the SNCR and SCR processes and form ammonium sulfate and ammonium bisulfate salts. 

Ammonium bisulfate forms as a liquid which may deposit on cold metal surfaces that are 

maintained at temperatures below 360 oF. Ammonium sulfate is a powdery substance which 

forms at temperatures below 410 oF. (Ref. 2) Both of these species can deposit on the fly ash.

Coal ash with high calcium content such as PRB ash exhibits high alkalinity and as such it has a

low affinity for capturing ammonia. Eastern bituminous coal has a very low alkalinity ash which 

acts as an ammonia sponge. Not all the gaseous ammonia, however, will adsorb on the ash, since 

a portion of the ammonia may also combine with SO3 in the flue gas and form ammonium 

bisulfate deposits on cold metal surfaces. A study carried out by Southern Company using high S 

coal suggests that about 30% of the ammonia slip generated from an SNCR or SCR process 

becomes tied up in ammonium sulfate and bisulfate deposits on cold metal surfaces while 70% is 

available to the fly ash. (Ref. 3) Less than 1% of the ammonia slip will make it to the stack. 

Clearly, the results of this analysis depend on the operating conditions during the study, but they

give an indication for the affinity of fly ash to ammonia when fuels with high S content are used. 

Ash generated by PRB coal, which has high alkalinity, has low potential for adsorbing ammonia. 

In addition, due to the low SO3 concentration in the flue gas, ammonium sulfate and bisulfate 
formation will be fairly low as well, and as such, most of the ammonia slip will go up the stack. 

This number is not known exactly, but this analysis will assume that a minimum of 70% of the 

generated ammonia slip under PRB combustion will be released from the stack and only 30% will 

be available for adsorption. It is worth noting, however, that ammonia can still absorb on the 

unburned carbon as demonstrated by Fuel Tech’s studies at Nipsco’s Bailly #8, even if the ash has 

low affinity for the ammonia. (Ref. 4)

Many utilities sell their ash to the cement industry. Cement contains high quantities of lime, and 

as it is hydrated to make concrete, its alkalinity increases. This high alkalinity causes the release 

of ammonia from the concrete, and although it does not have any negative impact on the 

properties of the concrete, it causes an odor which is unacceptable to both the concrete 

manufacturer as well as the concrete end user. (Ref. 5) In general, the limits set by the cement 

industry on the acceptable level of ammonia on ash are in the 50 to 100 mg/kg range. In order to 

keep this concentration low, the ammonia in the gas phase needs to be limited in the 2 to 5 ppm 

range.

In 1993, Fuel Tech briefly considered the concept of thermally treating the ash to strip the 

ammonia. During this time, preliminary analytical work showed a direct correlation between the 

alkalinity of the ash and the amount of ammonia adsorbed. It was recognized, however, that more 

and more utilities started burning PRB coal which generates ash that has low affinity for ammonia, 

and the idea was abandoned. (Ref. 6)

Analysis

The flue gas flow generated by combustion can be calculated on the basis of the operating O2, the 

amount of fuel burned, the higher heating value of the fuel, and the Fd factor which is fuel specific 

and indicates the dry flue gas that is generated for every MMBtu of fuel burned as shown by the 

equation below:

Flue gas(dscfh)=Fd(dscf/MMBtu)*HHV(Btu/lb)*10-6MMBtu/Btu*Fuel(lb/hr)*20.9/(20.9-O2) (1)

Ammonia slip generated in the gas phase is typically expressed in parts per million, ppm, and 

represents the moles of ammonia per mole of flue gas multiplied by one million.

NH3 slip (ppm) = [NH3 (moles/hr)/Flue gas (moles/hr)]*106 (2)

Since the molecular weight of NH3 is 17, the molar flow of ammonia can be calculated by 

dividing the mass flow by 17. Similarly, the molar flow of the flue gas can be derived by dividing 

the volumetric flow by 385.4, where 385.4 comes from the ideal gas law and indicates the volume 

of flue gas occupied by one mole of flue gas under standard conditions of temperature and 

pressure. Equation (2) can therefore be rewritten as follows:

NH3 slip (ppm) = [{NH3 (lb/hr)/17(lb/mol)}/{Flue gas (dscfh)/385.4(dscf/mol)}]*106 (3)

Assuming a typical operating O2 of 3% and combining equations (1) and (3), the maximum 

ammonia generated in (lb/hr) is:

NH3 (lb/hr) = NH3 slip (ppm)*0.0515*Fd (dscf/MMBtu)*HHV (Btu/lb)*Fuel (lb/hr) (4)

The ammonia concentration on the ash is typically expressed on a gravimetric basis or ppm-w. 

This unit is equivalent to mg of ammonia/kg of ash or lb of ammonia/lb of ash divided by a 

million.
NH3 on ash (ppm –w) = [NH3(lb/hr)/Ash (lb/hr)] * 10-6

 (5)

Assuming that 80% of the ash becomes fly ash, the above equation can be rewritten as follows:

NH3 on ash (ppm-w) = [NH3(lb/hr)/{%Ash*Fuel(lb/hr)*0.8}]*10-6 (6)

It should be noted that for cyclone fired units only 40% of the ash becomes fly ash while for wet 

bottom units this number may be closer to 25%.

If all the ammonia slip is adsorbed on the ash and by combining equations 4 and 6, the maximum 

concentration of ammonia on the ash would be:

NH3 on ash (ppm-w), maximum = [NH3 slip(ppm)*0.0644 * Fd * HHV /%Ash]*10-6 (7)

If an adsorption rate is established, then the ammonia on the ash of a specific coal can be 

calculated as follows:

NH3 on ash (ppm-w) = Adsorption (%)*NH3 on ash (ppm-w), maximum or (8)

NH3 on ash (ppm-w) = Adsorption (%)*[NH3 slip (ppm)* 0.0644 * Fd * HHV /%Ash]*10-6 (9) 

EPRI has carried out several studies in an effort to investigate ammonia adsorption on fly ash for 

various coals. Fuel Tech will utilize the measured ammonia on ash for each of the cases studied 

by EPRI and will determine the % adsorption for each coal from the ratio of the measured amount 

of adsorbed ammonia and the maximum amount of ammonia available for adsorption. 

The EPRI study focused on the ash collected from the following 8 sites (Ref. 7):

TABLE I: Test sites

Utility Station Unit type Coal rank

Ameren Baldwin Cyclone Bit., hvC

Georgia Power Bowen #3 T-fired Bit., hvB

AEP Cardinal I Wall fired Bit., hvB

SRI combustor Lone Mountain Wall fired Bit., hvA

Alabama Power Miller #3 Wall fired PRB

WEPCO Pleasant Prairie Wall fired PRB

Ameren Sioux I Cyclone PRB/Bit. hvC

Southern Power Stanton Wall fired Bit., hvA

The fly ash samples from each site were collected from various ESP hoppers. (Ref. 6) All the 

samples from a specific site were blended together, and the analysis was done on this blended 

sample. The ammonia adsorption on the fly ash was measured by Washington’s University in St. 

Louis Air Quality Laboratory. The experiment consisted of exposing 1 gram of the blended fly 

ash sample for 30 min to a flue gas consisting of 14% CO2, 4% O2, 10% H2O, 500 ppm SO2, 15 

ppm of NH3 and the balance was N2. The flue gas temperature was maintained at 325 oF and the 

flue gas flow was 500 accm. From the ammonia flow, flue gas volume, and the exposure time, it 

was determined that the maximum gravimetric amount of ammonia that could have been produced 

is 0.106895 mg. If all this ammonia is adsorbed on the 1 g of fly ash, the maximum amount of 

ammonia on ash would be 106.9 mg/kg. The table below summarizes the actual amount of 

ammonia adsorbed on the ash for all the applications as measured by the Air Quality Laboratory. 
In addition, it compares this value to the calculated value of 106.9 mg/kg and takes the ratio. This 

ratio shows the percent of ammonia actually adsorbed on the ash out of the amount that is 

theoretically available for adsorption and is indicative of the potential for adsorption of ammonia 

on fly ash for various fuels.

TABLE II: Ammonia Adsorption on Fly Ash

Fixed Exposure

Utility Station NH3 Adsorbed 

(mg/kg)

NH3 Adsorbed 

(%)

Ameren Baldwin 92 86

Georgia Power Bowen #3 60 56

AEP Cardinal I 90 84

SRI combustor Lone 

Mountain

128 100*

Alabama 

Power

Miller #3 15 14

WEPCO Pleasant 

Prairie

 16 15

Ameren Sioux I 81 76

Southern 

Power

Stanton 110 100*

The * denotes that measured value was higher than what was theoretically available and for these 

cases it was assumed that 100% of the ammonia was adsorbed. The above results show that the 

ash from Miller and Pleasant Prairie exhibited the least amount of ammonia adsorption while fly 

ash from Lone Mountain and Stanton Station exhibited the highest amount of ammonia adsorption 

on the ash. It is worth noting that Miller and Pleasant Prairie burn PRB coal while lone Mountain 

and Stanton burn high volatility bituminous A. 

The objective of this analysis is to be able to correlate the adsorption potential with specific

components of the fly ash or the fuel. Fuel Tech located the fuel analysis and ash analysis for the 

above applications with the exception of Bowen #3. (Ref. 9 to 11). Plant Bowen is not 

specifically included in this discussion, although the general statement can be made that for this 

bituminous, high volatility B coal, the rate of adsorption exceeds 50%. Finally, Sioux Station used 

a blended coal, and the analysis is based on an 83% Caballo and 17% Illinois #6 (2) coal.

TABLE III: Fuel analysis

Weight (%)

Moisture and

ash free

Baldwin Cardinal Lone

Mountain

Miller Pleasant

Prairie

Sioux Stanton

C 78.9 84.1 87.84 74.8 74.94 75.6 83.27

H 5.5 5.6 5.43 5.37 5.27 5.3 5.53

O 10 4.96 4.23 18.4 18.34 1.14 8.4

N 1.38 1.53 1.58 0.96 1.07 1.13 1.6

S 4 3.86 0.93 0.46 0.38 1 1.08

HHV (Btu/lb) 12233 13859 15243 13032 14061 13750 13254

Fd (dscf/MMBtu) 11328 10755 10035 9661 8945 9305 10904
The ash analysis for the above fuels is tabulated below:

TABLE IV: Fly ash composition

Constituents Baldwin Cardinal Lone

Mountain

Miller Pleasant

Prairie

Sioux

*

Stanton

SiO2(%) 48.91 39.65 55.83 27.8 31.9 34.79 58.2

Al2O3 (%) 18.26 19.68 28.67 13.1 16.9 17.13 30.67

Fe2O3 (%) 18.06 27.79 7.58 5.5 5.6 7.72 4.88

TiO2 (%) 0.88 0.85 1.29 1.3 1.4 1.31 2.08

CaO (%) 4.82 4.54 2.56 26.6 24.7 21.32 1.16

MgO (%) 1.04 0.85 1.64 7 4.6 3.99 0.42

Na2O(%) 1.03 0.9 1.0 1.3 1.4 1.34 0.17

K2O (%) 2.1 1.21 2.23 0.3 0.3 0.61 0.99

SO3 (%) 4.68 4.18 1.5 16 12.2 10.92 1.29

P2O5 (%) 0.21 0.34 0.37 1.1 1.0 0.87 0.133

The primary acidic components of fly ash are SiO2, Al2O3 and TiO2 while the basic components 

are Fe2O3, CaO, MgO, Na2O and K2O. According to the ABB Combustion Fossil Power book, the 

sum of the acidic components ranges between 20 and 90% while the sum of the basic components 

ranges between 5 and 80%. The ratio of the sum of the basic components over the sum of the 

acidic components represents the Base/Acid (B/A) ratio of the ash. 

B/A = [Fe2O3 + CaO + MgO + Na2O + K2O]/[SiO2 + Al2O3 + TiO2] (10)

The following table illustrates the B/A ratio of the ash for the applications of interest as a function 

of lime and SO3 content in the ash as well as the volatile S in the fuel. Ash with high B/A ratio 

tends to have high CaO concentration which will react with the volatile S and form CaSO4. The 

SO3 content in the fly ash actually represents the amount of S captured in the form of CaSO4. This 

reaction neutralizes the S content of the fuel and minimizes the potential of the ammonia to be 

adsorbed on the ash. The hypothesis, therefore, is that the higher the B/A ratio as well as the CaO 

and SO3 content of the ash, the higher the alkalinity of the ash, and the lower the potential for 

ammonia adsorption on the ash. The B/A ratio is calculated for each application using the 

information on Table IV along with equation (10). The ammonia adsorption on the ash is taken 

from Table II and the relationship of all these parameters is summarized in the table below:

TABLE V: Relationship between the ammonia adsorption on ash and the S content of the 

fuel, as well as the B/A ratio, SO3 and CaO content of the ash

Baldwin Cardinal Lone

Mountain

Miller Pleasant

Prairie

Sioux Stanton

NH3 adsorbed (%) 86 84 100 14 15 76 100

B/A 0.42 0.586 0.175 0.964 0.729 0.653 0.084

Sdaf (%) 4.29 3.864 0.92 0.463 0.35 0.97 1.079

SO3 (%) 4.70 4.183 1.5 16 24.7 10.922 1.292

CaO (%) 5.40 4.542 2.56 26.6 12.2 21.32 1.157

Ash (%),dry 10.77 9.4 7.5 5.85 7.3 5.3 6.9

This information is illustrated graphically in the following four plots.
0.000

0.200

0.400

0.600

0.800

1.000

1.200

0.000

5.000

10.000

15.000

20.000

25.000

30.000

0 10 20 30 40 50 60 70 80 90 100

Base/Acid ratio

CaO (%)

Adsorption rate of ammonia on ash (%)

Figure 1: Ammonia adsorbed on the ash as a function of ash 

CaO and Base/Acid Ratio 

Ash CaO content Base/Acid ratio

0.000

0.200

0.400

0.600

0.800

1.000

1.200

0.000

5.000

10.000

15.000

20.000

25.000

30.000

0 10 20 30 40 50 60 70 80 90 100

Base/Acid ratio

CaO (%)

Adsorption rate of ammonia on ash (%)

Figure 2: Ammonia adsorbed on the ash as a function of ash 

CaO and Base/Acid Ratio (Excludes Sioux)

Ash CaO content Base/Acid ratio
0.000

0.500

1.000

1.500

2.000

2.500

3.000

3.500

4.000

4.500

0.000

2.000

4.000

6.000

8.000

10.000

12.000

14.000

16.000

18.000

0 10 20 30 40 50 60 70 80 90 100

Sulfur content, daf (%)

SO3 (%)

Adsorption rate of ammonia on ash (%)

Figure 3:Ammonia adsorbed on the ash as a function of ash 

SO3 and fuel S content 

Ash SO3 content Sulfur content (%)

0.000

0.500

1.000

1.500

2.000

2.500

3.000

3.500

4.000

4.500

0.000

2.000

4.000

6.000

8.000

10.000

12.000

14.000

16.000

18.000

0 10 20 30 40 50 60 70 80 90 100

Sulfur content, daf (%)

SO3 (%)

Adsorption rate of ammonia on ash (%)

Figure 4: Ammonia adsorbed on the ash as a function of ash 

SO3 and fuel S content (Excludes Sioux) 

Ash SO3 content Sulfur content (%)
Reviewing the above plots, it appears that in the case of the Sioux Station, which used the blended 

PRB and bituminous coal, the properties of the bituminous coal overwhelmingly affect the 

adsorption potential of the ash although the average Base/Acid ratio is high, and the CaO and SO3 

concentrations are relatively high as well. The blended coal application introduces a small amount 

of scatter in the data, and consequently, Figures 2 and 4 should be the ones used in estimating the 

adsorption potential of any given coal.

These graphs show that the rate of ammonia adsorption on the ash is very low, less than 20%, 

when the B/A ratio as well as the CaO and SO3 concentrations are high. On the other extreme, as 

the B/A ratio drops below 0.15, the ammonia adsorption on the ash approaches almost 100%. In 

general, the ammonia adsorption goes up if the S content is over 1%, however, the S content by 

itself is not the best indicator of how high the ammonia adsorption rate will be and will need to be 

used in conjunction with the CaO and SO3 concentrations. 

Entering the information read from the plots into Equation (9), the amount of ammonia adsorbed 

on the ash may be estimated. This is an expected value, however, and is not intended for making

guarantees. 

Working examples

The methodology for assessing the amount of ammonia adsorbed on fly ash is outlined below. The 

analysis is done for three different coals, namely: Arclair, Antelope and San Miguel Lignite. It is 

assumed that the amount of fly ash is 80% of the total ash and that the amount of ammonia slip 

measured at the economizer outlet is 3 ppm. For the low S applications, it will be assumed that 

30% of the ammonia slip will be available for adsorption while the rest will go out the stack. For 

the high S applications, it will be assumed that 70% of the ammonia slip will be available for 

adsorption with the rest been tied up in the air heater.

Appendix 1 shows that Arclair has a B/A ratio of 0.42, an SO3 content of 1% and a CaO content of 

4.2%. Appendix 2 shows that the S content of this fuel is 3.46% on a dry, ash free basis and the Fd

factor is 9623 dscf/MMBtu. In addition, the ash content is 8.65% and the Higher Heating 

Value13149 Btu/lb on a dry basis. Figure 2 illustrates that for a coal with a B/A ratio of 0.42, the 

adsorption rate is about 70% while based on a CaO content of 4.2%, the ammonia adsorption 

potential approaches 100%. This high adsorption rate is further supported by the SO3 and S 

concentration on Figure 4. Consequently, by averaging out all these factors, the ammonia 

adsorption on the ash for this particular coal is about 90%.

Applying the above adsorption rate in Equation (9), and assuming that only 70% of the ammonia 

slip will be available for adsorption, or just 2.1 ppm, it is estimated that the ammonia adsorbed on 

the ash in this application is 196 ppm-w. This is well above the 50 to 100 ppm-w threshold for ash 

sold to the cement industry. For the adsorbed ammonia to stay below this threshold, the NH3 slip 

will need to be maintained below 2 ppm which will severely limit the applicability of the SNCR 

process and perhaps challenge the SCR process as well.

For comparison purposes, the above analysis is repeated for Antelope coal under the same 

conditions. The B/A ratio from Appendix 1 is 0.77, the CaO concentration is 23.6% and the SO3 

concentration is10.1% . The fuel analysis in Appendix 2 shows that the S content is 0.35% on a 

dry, ash free basis and an Fd factor of 9852 dscf/MMBtu. The ash content is 7.21% and the 

Higher Heating Value 9505 Btu/lb on a dry basis. Using Figure 2 based a CaO concentration of

23.6% and a B/A ratio of 0.77, the amount of ammonia adsorbed on the ash is expected to be 

around 15%. This is also consistent with the information in Figure 4 based on the S concentration 

of 0.35% while based on the SO3 concentration the adsorption rate is closer to 30%. By averaging 

out all these factors, the ammonia adsorption rate for this coal is about 20%. In addition, since this 
is a low S PRB coal, 70% of the ammonia slip is expected to be released from the stack and only 

30% of the 3 ppm ammonia slip will be available for adsorption. Again, using Equation (9) for 0.9

ppm NH3 slip available for adsorption on the ash, the amount of ammonia adsorbed on the ash is 

only about 15 ppm-w. This suggests that even if the SNCR/SCR process operates at a relaxed 

ammonia slip of 5 to 10 ppm, the 50 to 100 ppm-w threshold of ammonia on ash is satisfied.

This is consistent with observations at the Boardman Station in Wyoming where Fuel Tech ran an 

SNCR demonstration in 2009. Many fly ash samples were collected and analyzed and the average 

amount of ammonia adsorbed on the ash at the different sections of the ESP were below 11.7 

ppm-w even when the ammonia dosage was as high as 21 ppm. This information is summarized 

in Appendix 4.

Finally, the above exercise is repeated for San Miguel Lignite. Appendix 1 shows that San Miguel 

Lignite has a B/A ratio of 0.112, an SO3 concentration of 2. 9% and a CaO content of 3.0%. 

Appendix 2 shows that the S content of this fuel is 3.66% on a dry, ash free basis and the Fd factor 

is 8665 dscf/MMBtu. In addition, the ash content is 36.3% and the Higher Heating Value is 8446

Btu/lb on a dry basis. Using Figure 2, it is determined that both on the basis of the CaO and the 

B/A, the ammonia adsorption potential approaches 100%. This high adsorption rate is further 

supported by the SO3 an S concentrations on Figure 4.

As in the case of the Arclair coal, since this is also a high S coal, it is assumed that 70% of the 3 

ppm ammonia slip is available for adsorption or 2.1 ppm. Surprisingly, when the above adsorption 

rate is used in Equation (9), it is estimated that the ammonia adsorbed on the ash in this 

application is only 27 ppm-w. This is a very low concentration and it is due to the high ash 

content of the fuel which dilutes the ammonia adsorption effect. Clearly, in cases like this, the 

amount of ammonia on the ash is not the driving factor for limiting the ammonia slip but rather the 

high potential for ammonium bisulfate fouling on the air heater surfaces.

The above analysis has not taken into account the ammonia adsorbed due to unburned carbon. Based on 

studies performed by Fuel Tech’s SCR group at Nipsco, it was determined that ammonia also adsorbs on 

unburned carbon and the ammonia slip measurement is not a true measure of the ammonia slip generated 

in the gaseous phase. The true ammonia slip will need to be adjusted by the % unburned carbon assuming 

a 10% adsorption rate. Therefore, the higher the amount of unburned carbon, the higher the true ammonia 

slip, the higher the amount of ammonia adsorbed on the ash.

Conclusions

1. For high S bituminous coals, about 70% of the generated ammonia slip is available for adsorption 

on the ash. Approximately 30% may react with SO3 to form ammonium bisulfate and sulfate salts 

which may deposit on cooler metal surfaces, and a very small portion is released from the stack.

2. For PRB coal, due to the low SO3 concentration in the flue gas, a small portion of the ammonia 

slip will participate in the formation of ammonium bisulfate and sulfate salts. In addition, due to 

the high alkalinity of the ash, the potential for ammonia adsorption on the ash is low, and it is 

expected that the majority of the ammonia slip will be released from the stack. For the purposes 

of this analysis, it has been assumed that 30% of the generated ammonia will be available for 

adsorption.

3. The potential of ammonia adsorption on the ash is great when the alkalinity of the ash is low as in 

the case of bituminous fuels. Under these conditions 80 to 100% of the gaseous ammonia 

available for adsorption on the ash may be adsorbed on the ash.

4. The potential of ammonia on the ash is low when the alkalinity of the ash is high as in the case of 

PRB fuels. Under these conditions, only 10 to 20% of the gaseous ammonia available for 

adsorption on the ash may adsorbed on the ash.
5. The B/A ratio, CaO and SO3 concentration of the ash, as well as the %S content of the fuel are 

good indicators in assessing the adsorption rate of ammonia on the ash.

6. The ash generated by a high S fuel may be very acidic if the CaO concentration is low and has the 

potential to adsorb 100% of the available ammonia. However, the actual concentration on the ash 

may still be an acceptable value for the cement industry, if this fuel has a very high ash 

concentration.

7. The ash produced by the combustion of a PRB fuel has a very low potential for adsorbing 

ammonia. This potential, however, increases in the presence of unburned carbon.

References

1. Combustion Fossil Power, Windsor, Connecticut : Combustion Engineering, Inc., 1991

2. Air heater Fouling by Ammonia Bisulfate Deposition, Fuel tech Internal Report, March 

1996

3. Lorimore L., Effects of Ammonia From Post Combustion NOx control on Ash Handling 

and Use., Fuel Chemistry Division Reprints, 2002

4. Discussions with Volker Rummenhohl internal to Fuel Tech

5. Homepage of W.S.Hinton and Associates, Fly Ash Behavior, www.wshinton.com

6. Handling of Ammonia in the Ash, Fuel Tech Internal Report, August 1993

7. Impacts of Ammonia Contamination of Fly Ash on Disposal and Use. EPRI Report 

1004609, October 2001

8. Investigation of Ammonia Adsorption on Fly Ash. EPRI Interim Report 112172, December 

1998

9. Arch Coal, Inc. Fuel Analyses

10. Ash Chemistry, Ultimate Analyses and Heating Values of Various Coals, www.et.byu.edu

11. Alstom Clean Combustion Technologies, Canada: Transcontinental printing, 2009
Appendix 1

Fuel SiO2 Al2O3 Fe2O3 TiO2 CaO MgO Na2O K2O SO3 P2O5 B/A

Beulah Lignite 21.23 13.97 12.25 0.42 16.36 4.46 6.50 0.22 24.60 0.00 1.12

Arclair 48.08 18.59 20.60 0.99 4.22 0.88 0.54 2.23 0.99 0.00 0.42

Buckskin 30.76 13.51 5.85 1.03 24.78 5.71 1.59 0.23 15.1 1.44 0.84

Black Thunder 30.67 16.46 5.10 1.29 21.32 4.80 1.43 0.35 17.67 0.92 0.68

Antelope 31.74 15.71 5.96 1.25 23.75 5.65 1.64 0.54 10.11 1.72 0.77

SUFCO 52.02 13.17 4.12 0.81 13.28 3.83 2.28 1.01 5.21 0.46 0.37

Elk Creek 53.94 23.57 6.58 0.99 3.94 1.41 1.76 1.59 1.76 1.01 0.20

McElroy 48.17 21.91 21.57 0.91 2.8 0.76 0.50 1.84 2.35 0.39

Eastern Kentucky 58.20 30.67 4.88 2.08 1.16 0.42 0.17 0.99 1.29 0.13 0.08

Western Kentucky 51.06 18.41 19.56 0.99 3.04 1.14 0.63 2.88 2.02 0.12 0.39

Ohio #9 47.30 23.00 22.80 1.00 1.30 0.90 0.30 2.00 1.2 0.38

Bailey/Enlow Fork 47.14 23.02 21.17 0.98 2.78 0.80 0.67 1.83 2.17 0.38

Illinois #6 (2) 52.69 12.84 18.77 0.71 5.39 0.55 1.45 1.38 4.72 0.16 0.42

Kentucky #9 44.38 18.66 22.69 0.97 5.56 0.92 0.46 2.57 3.09 0.44 0.50

Pittsburgh #8 (1) 41.70 20.66 29.33 0.90 2.08 0.79 0.40 1.74 2.35 0.15 0.54

Pittsburgh #8 (2) 47.82 24.14 16.85 1.05 3.47 0.84 0.45 1.76 3.00 0.62 0.32

Pittsburgh #8 (3) 39.66 19.68 27.79 0.85 4.54 0.85 0.90 1.21 4.18 0.34 0.59

Pocahontas #3 37.92 24.16 17.14 1.14 7.67 2.40 0.83 1.84 6.79 0.10 0.47

Alicia 47.48 24.08 17.11 1.12 3.57 0.68 0.68 1.58 2.99 0.33

San Miguel Lignite 66.79 19.69 1.69 0.88 3.04 0.49 2.63 1.91 2.86 0.01 0.11

Upper Freeport 51.53 24.35 13.46 0.92 2.48 1.30 0.30 3.07 2.43 0.14 0.27

Rochelle 34.10 17.00 5.50 1.30 23.5 5.50 1.70 0.40 9.80 1.20 0.70

Central Appalachia 55.83 28.67 7.58 1.29 2.56 1.64 1.00 2.23 1.50 0.37 0.18

Belle Ayr 27.80 13.10 5.50 1.30 26.60 7.00 1.30 0.30 16.00 1.10 0.96

Caballo 31.90 16.90 5.60 1.40 24.70 4.60 1.40 0.30 12.20 1.00 0.73

Blend Caballo&Illinois #6 (2) 35.34 16.21 7.84 1.28 21.42 3.91 1.41 0.48 10.93 0.86 0.68
Appendix 2

Fuel, dry ash free basis

C

(%)

H

(%)

N

(%)

S 

(%)

O

(%)

HHV,dry

(Btu/lb)

% 

H2O

% ash,

dry

Fd 

(dscf/MMBtu)

Beulah Lignite 70.49 4.75 1.22 2.14 21.36 7210 34.8 9.5 10533

Arclair 79.91 5.34 1.79 3.46 9.50 13419 9.33 8.65 9623

Buckskin 76.26 5.15 1.00 0.51 17.08 8979 30.86 5.1 9856

Black Thunder 74.73 5.40 1.00 0.51 18.27 9479 26.03 7.59 9833

Antelope 75.93 5.29 1.15 0.35 18.23 9505 26.5 7.21 9852

SUFCO 79.70 5.28 1.41 0.45 13.15 12146 10.13 12.1 9812

Elk Creek 77.97 5.39 1.75 0.56 7.6 13651 6.71 10.7 9293

McElroy 80.30 5.49 1.66 3.76 8.76 14023 6.17 10.2 9447

Eastern Kentucky 84.00 5.50 1.70 1.00 7.80 14664 2.5 7.2 9691

Western Kentucky 79.00 5.60 1.70 3.60 10.10 13223 8.3 12.2 9632

Ohio #9 80.70 5.07 1.32 3.73 8.33 13009 10.33 10.4 9678

Bailey/Enlow Fork 83.00 5.60 1.75 2.29 7.10 14038 6.32 8.06 9720

Illinois #6 (2) 78.70 5.50 1.40 3.50 10.90 11773 18.3 7.59 9549

Kentucky #9 80.10 5.50 1.70 4.70 8.00 13700 6.1 11.9 9720

Pittsburgh #8 (1) 80.90 5.70 1.50 2.50 10.90 13092 8.7 9.3 9843

Pittsburgh #8 (2) 86.70 5.50 1.81 1.47 4.50 15012 2.6 9.34 9842

Pittsburgh #8 (3) 84.07 5.58 1.53 3.86 4.96 10755

Pocahontas #3 91.65 4.46 1.31 0.79 1.62 14390 4.4 7.4 10387

Alicia 83.60 5.48 1.66 2.67 6.50 14237 5.96 8.6 9685

San Miguel Lignite 61.54 6.70 1.06 3.66 26.88 8446 32.49 36.3 8665

Upper Freeport 89.50 4.80 1.50 1.30 2.90 12372 1.1 8.58 12312

Rochelle 74.90 5.15 1.07 0.31 19.20 12566 2.73 6.3 9663

Central Appalachia 87.84 5.43 1.58 0.92 4.23 14252 6.5 7.5 10035

Belle Ayr 74.78 5.37 0.96 0.46 18.38 9148 29.8 6.55 9661

Caballo 74.94 5.27 1.07 0.38 18.34 8927 29.9 8.7 9876

Blend Caballo & Illinois #6 (2) 75.58 5.31 1.15 0.91 17.08 9384 27.9 8.5 9814
Appendix 3

Fuel B/A

S (%), 

daf CaO (%) SO3 (%)

Application similar 

to

%NH3 

adsorbed

Beulah Lignite 1.12 2.14 16.4 24.6

Arclair 0.42 3.46 4.2 1.0

Buckskin 0.84 0.51 24.8 15.1

Black Thunder 0.68 0.51 21.3 17.7

Antelope 0.77 0.35 23.8 10.1

SUFCO 0.37 0.45 13.3 5.2

Elk Creek 0.20 0.56 3.9 1.8

McElroy 0.39 3.76 2.8 2.4

Eastern Kentucky 0.08 1.00 1.2 1.3 Stanton 100

Western Kentucky 0.39 3.60 3.0 2.0

Ohio #9 0.38 3.73 1.3 1.2

Kentucky #9) 0.38 2.29 2.8 2.2

Illinois #6 (2) 0.42 3.50 5.4 4.7 Baldwin 86

Kentucky #9 0.50 4.70 5.6 3.1

Pittsburgh #8 (1) 0.54 2.50 2.1 2.3

Pittsburgh #8 (2) 0.32 1.47 3.5 3.0

Pittsburgh #8 (3) 0.59 3.86 4.5 4.2 Cardinal 84

Pocahontas #3 0.47 0.79 7.7 6.8

Alicia 0.33 2.67 3.6 3.0

San Miguel Lignite 0.11 3.66 3.0 2.9

Upper Freeport 0.27 1.30 2.5 2.4

Rochelle 0.70 0.31 23.5 9.8

Central Appalachia 0.18 0.92 2.6 1.5 Lone Mountain 100

Belle Ayr 0.96 0.46 26.6 16.0 Miller 14

Caballo 0.73 0.38 24.7 12.2 Pleasant Prairie 15

Blend Caballo and Illinois #6 (2) 0.68 0.91 21.4 10.9 Sioux 76
Appendix 4

REPORT OF FLY ASH

Title of the Project: Boardman Ammonia Testing During SNCR Trials Date Received: 08-Dec-09

Contact Person: Pam Flynn Tested By: KC

Project Number: 5257 Report Date: 16-Dec-09

Boral Sample ID Operations Details Sample Description NH3 (ppm NH3 in FA)

91208012 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 A 3.7

91208013 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 C 5.6

91208014 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 D 9.5

91208015 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 E 10.8

91208016 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 F 13.7

91208017 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 G 15.5

91208018 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 H 11.7

91208019 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 J 3.8

91208020 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 K 3.5

91208021 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 L 3.2

91208022 10 PPM dose rate. Boiler under normal conditions 12/4 Row 31 M 3.0

91208023 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 A 7.2

91208024 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 B 2.8

91208025 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 C 8.5

91208026 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 D 6.3

91208027 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 E 17.3

91208028 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 F 13.5

91208029 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 G 11.7

91208030 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 H 21.2

91208031 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 J 13.8

91208032 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 K 6.7

91208033 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 L 4.6

91208034 10 PPM dose rate. Boiler under normal conditions 12/4 Row 32 M 2.9

91208035 10 PPM dose rate. Boiler under normal conditions 12/4 Row 35 COMPOSITE 7.7

91208036 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 A 3.0

91208037 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 C 4.3

91208038 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 D 10.3

91208039 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 E 22.6

91208040 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 F 21.9

91208041 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 G 14.7

91208042 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 H 18.5

91208043 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 J 9.3

91208044 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 K 5.0

91208045 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 L 4.6

91208046 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 31 M 3.2

91208047 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 A 6.1

91208048 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 B 3.8

91208049 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 C 8.8

91208050 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 D 5.2

91208051 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 E 17.3

91208052 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 F 22.5

91208053 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 G 9.5

91208054 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 H 22.6

91208055 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 J 3.1

91208056 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 K 7.7

91208057 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 L 4.8

91208058 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 32 M 4.2

91208059 21 PPM dose rate. Boiler set to mimic low NOx conditions 12/6 Row 35 COMPOSITE 11.7

45 NE LOOP 410, SUITE 700 SAN ANTONIO, TEXAS (210) 349-4069