-------
than without reburn (up to 2,000 ppm versus less than 100 ppm without reburn).' To
reduce CO emissions during reburn testing, the primary zone stoicliiometry was
increased to 1.2. At this higher primary zone stoichiometry and gas reburn rates of 10 to
20%, NOX emissions were only 20 to 3C% lower than bi Mine levels. Possible
explanations for the relatively low NOX reduction achieved during these tests are that the
residence time (-0.5 sec) and flue gas temperatures in the reburn zone were too low for
the needed NOX reduction reactions. This problem may be reduced by installing the
reburn injection nozzles lower in the furnace. However, given typicai MWC operating
conditions, it is uncertain whether an acceptable injection location is available.
The Methane de-NOX process was evaluated during 1990 and 1991 using
one of the two combustors at the Olmsted County MWC facility in Rochester,
Minnesota.3'4-5 Each unit is designed to burn 100 tpd of MSW. The testing at Olmsted
County was preceded by laboratory furnace simulation experiments on a 1.7 MMBtu/hr
facility at IGT and pilot-scale testing using a 2.5 MMBtu/hr MSW-fired combustor
operated by Riley Stoker Corporation. As shown in Figure 2-5, the tests at Olmsted
County achieved an average reduction of 60% for NOX and 50% for CO compared to
baseline levels when injecting 15% natural gas at optimized conditions. Flue gas
residence time prior to OFA injection was 1 to 1.5 seconds. The testing also found that
20% NOX reduction could be achieved with FGR alone, but resulted in higher CO
emissions from incomplete combustion.
To address uncertainties associated with the performance of these two
approaches, the new MWC in Herning, Denmark is being designed with the ability to
use both approaches.9 The facility is being designed and constructed by Volund Ecology
Systems, with the gas injection system design being performed through a partnership
between Volund R&D Centre and Nordic Gas Technology Centre. The facility is
"CO is used as an indicator of good combustion practices for destruction of organic
emissions. To achieve this objective, CO concentrations are generally maintained below
100 ppm. As a result, increases in CO emissions such as measured at SYSAV are not
acceptable in a commercial MWC.
sdg/nrcl
scct-2.rpt 2-8
-------
s
©
6
300
250
200
150
100
0 CONVENTIONAL FIRING 1987
• CONVENTIONAL FIRING 1991
A METHANE de-NOX - NON-OPTIMUM CONFIGURATION
A METHANE de-NOX - OPTIMUM CONFIGURATION
50
20
40
60 80
CO (ppm @ 7% O2)
100
120
140
Figure 2-5. Effect of Methane de-NOX34 on CO and NOv Emissions
During Olmsted County Methane de-NOX5* Testing
sdg/nrcl
scct-Z.rpt
2-9
-------
scheduled for construction in 1994, with performance evaluations of reburning and
Methane de-NOX scheduled for the spring of 1995. The design objective for the facility
is 50% NOX reduction without adversely impacting emissions of other pollutants.
23 Key Design and Process Variables Affecting Performance
Based on the testing conducted to date on MWCs, key parameters affecting
NOX control performance of gas injection processes include combustion zone
stoichiometry, gas injection location, and residence time prior to OFA injection.
The effect of primary zone stoichiometry is critical to both CO and NOX
emissions. As shown in Figure 2-4 for the testing at Malmtf, CO emissions increased
sharply without reburning as the primary zone stoichiometry decreases to 1:1 and lower.
The reburn tests suggest that a portion of the injected natural gas was oxidized to CO,
but that the temperatures in the burnout zone were too low or residence times were too
short to complete oxidation of CO to CO2. As a result, it was necessary to increase the
primary zone stoichiometry to more than 1.2 to minimize CO emissions. When the
primary zone stoichiometry was increased, however, NOX emissions also increased. As a
result, only a portion of the expected reduction in NOX emissions was achieved.
With the Methane de-NOX process, natural gas is injected directly above
the grate, such that theie are not distinct primary and secondary zones. As shown in
Figures 2-6 and 2-7, the primary influences of combustion zone stoichiometry on NOX
appears to be low O2 levels and optimized operation of the FOR system, and secondarily
gas injection rate. As shown in Figure 2-7, varying the gas injection rate between 9 and
15% had a relatively small impact on NOX reduction. With low O2 and FGR alone,
however, there was an increase in CO levels. The benefit of gas injection is that it
allowed the combustor to simultaneously achieve both low NOX and low CO. Note from
Figure 2-6 that it was not necessary for gas injection to fully deplete O2 (i.e, create
fuel-rich conditions), but rather only to reduce O2 availability.
Blg/orel
sect-rrpt 2-10
-------
200
s
180
160
140
O BASELINE
• METHANE de-NOX
E 120
O 1CO
80
60
40
468
Secondary Zone Oxygen (%)
10
sdg/nnl
sect-Z.rpt
Figure 2-6. Effect of O2 Concentration on NOx Emissions
During Olmsted County Methane de-NOX5*1 Testing
2-11
-------
» B.
K> 9
•a. 3
^^
rs
o
®
§,
0.
5
z
zuu
190
180
170
160
ISO
140
130
120
110
100
90
80
70
60
«n
o • Optimized NCI
• Non-Optimum FGR
Baseline
_
+
-
-
-
i
-
-
• ^"
'
-
i i i i i i i i i i i i i i i i i
4 6 8 10 12
Natural Gas Heat Input (%)
14
16
Figure 2-7. Effect of Natural Gas Injection Rate on NOv Emissions
During Olmsted County Methane de-NOXSN' Testing
-------
As already discussed, gas injection location is important because it defines
whether fuel nitrogen compounds are still present in the combustion gas as NOX
precursors or have been oxidized to NOX. If natural gas is injected into the combustion
zone while NOX precursors are still present, the gas will reduce the availability of O2 and
result in reduced formation of NOX. If gas is injected after NOX is formed, NOX
reduction reactions are required. As indicated in Figure 2-2, however, the gas
temperatures in MWC may be too low for these reactions to proceed rapidly, thus
limiting the achievable NOX reduction.
The effect of NGI residence time on NOX emissions reduction is shown in
Figure 2-8 for the Methane de-NOX process. These data, based on synthetic combustion
gases generated by a laboratory furnace, show that at a given natural gas injection rate,
NOX emissions decreased with increasing residence time prior to OFA injection. For
example, with 15% gas injection, NOX emissions decreased from 135 ppm at a residence
time of 0.6 seconds to about 100 ppm at 1.6 seconds and 75 ppm at 4.5 seconds (about
40% reduction). The effect of increasing natural gas usage on NOX emissions is also
shown in Figure 2-8. Compared to slightly over 200 ppm NOX with no natural gas
addition, NOX levels decreased by 15% with 4% gas and 50 to 60% with 15% gas.
Full-scale data from Olmsted County suggest a 1 to 1.5 second residence time is
sufficient for 60% reduction.
2,4 Recent Advances and Further Research Needs
Both gas injection approaches have been tested at commercial MWCs-
reburning at Malmd and Methane de-NOX at Olmsted County. Based on the data from
these two test programs, Methane de-NOX appears to be better able to reduce NOX
without adversely impacting CO emissions. However, the Methane de-NOX testing has
been limited to a single, relatively small (100 tpd) combustor. If this approach is to be
applied to other existing MWCs, further analysis of the ability to achieve adequate gas
penetration into the primary combustion zone of larger MWCs is needed to define
achievable NOX reductions. Further, additional testing to assess continuously achievable
sdg/nnl
Ktt-lrpl 2-13
-------
s
a
Q.
Q.
250
225
200
175
160
126
100
76
fin
0.6 1.6 2.6 3.6
Residence Time (Sec)
4.6
6.6
Figure 2-8. Effect of Natural Gas Injection Residence Tune on NOX Emissions
During Pilot-Scale Testing of Methane de-NOX5* Process
sdg/nrel
sccl-2.rpl
2-14
-------
NOX reduction capabilities at various load conditions and to investigate possible
long-term impacts on MWC operation are needed prior to commercialization of the
process. Although the initial explanation for the high CO levels measured during the
Malmo testing is that furnace temperatures in MWCs are too low for the needed NOX
reduction reactions, further assessment of this issue is warranted.
Greater reductions in NOX emissions (75 to 85%) may be possible if gas
injection is combined with SNCR. With this approach, referred to as advanced NGI, the
NOX level is first controlled by gas injection to reduce NOX emissions by 50 to 60%,
followed by injection of ammonia or urea to achieve an additional 50 to 60% reduction.
This concept has been tested by combining reburning with SNCR on a 10 MMBtu/hr
pilot-scale coal-fired furnace.10 Based on the existing SNCR system at the plant, the
Malmo MWC would appear to be an ideal site for testing this concept. Such a program
could also address the use of Methane de-NOX in an MWC with less furnace residence
time than at Olmsted County. The economic benefits of advanced NGI are discussed in
Section 3.5.
25 Cost Analysis
2J>.1 Design Basis
As discussed in Section 2.1, two different NGI processes have been
developed for MWC's: reburning and Methane de-NOX. Although the performance
estimates used in this section are based on the Methane de-NOX testing conducted at
the Olmsted County MWC, the costs estimates are believed to be generally
representative of both processes. Costs for reburn could be higher because of the
increased number of injectors, tube penetrations, associated piping, etc. needed with this
process.
The design basis for the NGI system includes 60% NOX reduction at 15%
natural gas heat input and natural gas is available at the plant boundary. Based on an
sdg/orel
sect-Z.tpt 2-15
-------
uncontrolled NOX concentration of 250 ppm at 7% O,, the average stack concentration
associated with this system is 100 ppm at 7% O2. The 60% reduction represents
long-term (annual average) performance capabilities. Performance at individual plants
will vary, and this average performance level may not be achievable at all plants,
especially when considering retrotit situations.
Capital cost estimates for commercial gas injection systems applied to
MWCs are limited to a comparative analysis of gas injection and SNCR processes
prepared by IGT and Ogden Martin Systems for a 264 tpd MWC.7 That analysis
concluded that the capital costs for these two processes were essentially equal. As a
result, the capital cost estimate used in this analysis is based on the SNCR costing
procedures described in Section 3.5 and Appendix A. Based on the limited commercial
experience of this control technique, a process contingency of 20% is assumed. As
discussed in Section 2.5.2, capital costs have a n. 'atively small impact on the overall
economics of NGI. As a result, the lack of detailed procedures for estimating NGI
capital cost is not critical to defining key cost factors affecting process economics.
A key economic assumption associated with gas injection is whether the
combustor typically operates at 100% of design heat input or at less than design heat
input because of insufficient MSW flow or other factors. If ihe MWC operates at 100%
of design beat input capacity, application of NGI may require the facility to reduce the
MSW feed rate by an amount comparable to the heat input of the natural gas. As a
result, NGI may reduce the amount of MSW burned and the associated tipping fee
revenues, while the plant electrical output remains constant. As discussed in Section 2.3,
it may be possible to operate the combustor at lower excess air levels and, therefore,
higher thermal efficiency when injecting gas than when operating with 100% MSW.
However, because of the complexity of the combustor heat transfer and steam generating
systems, operation at higher thermal efficiency does not necessarily result in more steam
generation and turbine electrical output. Therefore, costs discussed in the following
sections do not include economic credit for operation at higher thermal efficiency. If the
sdg/nrcl
tcct-2.rpt 2-16
-------
NGI system is built into the system as part of the original design, the heat recovery
capacity could be optimized to provide additional revenue from electricity/steam sales.
If the MWC is operating at less than 15% of its design heat input capacity,
NGI can be used to increase the total heat input to the combustor and to increase the
amount of steam supplied to the turbine. In this case, the total amount of waste fired
and associated tipping fee revenues remain unchanged, but electrical sales revenues will
increase. An alternative case would be if the MWC's MSW input rate is air-supply
limited (e.g, inadequate fan capacity), but the MWC has adequate heat transfer and
turbine capacity to operate at greater than design thermal input. Provided that the
MWC's operating permit is not thermally limited, the ability to reduce excess air levels
by using NGI may allow some MWCs operating at 100% of design MSW flow to use
NGI without reducing MSW flow, and gain additional revenues from the increased sale
of electricity.
Cost estimates for NGI applied to an MWC operating at maximum MSW
and heat input and to an MWC operating at reduced load and heat input are presented
in Section 2.5.2.
252 Cost Results
Cost estimates for the NGI system were developed for 100, 400, and
750 rpd model combustors, assuming the units are able to operate at 100% of design
capacity on MSW alone (referred to as NGI-100). System-specific input and output
values for the 400 tpd model combustor are shown in Tables 2-1 and 2-2. Additional
inputs (e.g., labor rates, fuel price) are presented in Table A-l of Appendix A.
Table 2-3 presents the estimated capital cost per ton of capacity, tipping
fee impact, and NOX control cost effectiveness for the NGI system applied to the three
model MWCs. The tipping fee impacts are calculated based on the actual amount of
MSW burned when NGI is applied, not on the design capacity of the combustor. In
sdg/nrel
scct-2.rpt 2-17
-------
Table 2-1
Model Combustor Inputs For NGI (a)
Plant Characteristics
Unit Size (tpd)
Flowrate (dscfm @ 7% O2)
Flowrate (wscfm @ 11% O2)
Capacity Factor
Uncontrolled NOx (ppmv, dry)
NOx Removal Efficiency (%/100)
NGI Percentage (%/100)
Outlet NOx (ppmv, dry)
Tons of NOx removed (tons/yr)
Plant Tipping Fee ($/ton MSW)
Original MSW Heat Input (MMBtu/hr)
Natural Gas Heat Input (MMBtu/hr)
Resulting MSW Heat Input (MMBtu/hr)
Actual Tons/day of MSW Processed (tons/day)
Actual Tons/yr of MSW Processed (tons/yr)
Capital Recovery Factor (1/yrs)
400
41,271
70,462
0.9
250
0.60
0.15
100
152
80
150
23
128
340
111,690
0.0944
(a) For an MWC which does not have additional heat input capacity (NGI-100).
cdg/nnl
s«ct-2.rpl
2-18
-------
Table 2-2
Cost Outputs for NGI
Applied to the 400 TPD Model Combustor (a), (b)
Capital Cost Section ($1000)
Total Process Capital ($1000)
Engineering
Contingency
Total Control Cost ($1000)
Pre-Production
Inventory Capital
Total Capital Requirement ($1000)
Total Capital per Capacity (S1000/TPD)
Total Annualized Capital Requirement ($1000/yr)
429
86
206
720
32
31
783
1.96
74
Variable O&M Cost Section ($1000/yr)
Fuel Cost
Electricity
Lost Revenue
Total Variable O&M ($1000/yr)
621
3
1,577
2,201
Fixed O&M Cost Section ($1000/yr)
Operating Labor
Maintenance Material
Maintenance Labor
Administrative & Support Labor
Total Fixed O&M ($1000/yr)
22
5
3
8
38
Total Cost Section
Total Annualized Cost ($1000/yr)
Tipping Fee Impact ($/ton of MSW)
Cost Effectiveness ($/ton of NOx)
2,313
20.7
15,204
(a) For an MWC which does not have additional heat input capacity (NGI-100).
(b) $/ton can be converted to $/Mg by multiplying by 1.1.
sect-lrpt
-------
Table 2-3
Model Plant Cost Estimates for NGI for MWCs without Additional Heat Input Capacity (NGI-100) (a)
NOx Reduction {%)
100 TPD Mass Burn MWC
400 TPD Mass Burn MWC
750 TPD Mass Burn MWC
Total Capital Cost
($1000/TPD capacity)
45
5.18
1.92
1.41
60
5.22
1.96
1.45
65
5.23
1.97
1.46
Tipping Fee Impact
($/ton MSW)
45
14.5
12.6
12.3
60
22.7
20.7
20.4
65
25.7
23.7
23.3
Cost Effectiveness
($/ton NOx)
45
15.103
13,126
12,818
60
16,687
15,204
14,974
65
17,053
15,684
15,471
(a) $/ton can be converted to $/Mg by multiplying by 1.1.
to
o
-------
addition to the costs for a 60% NOX reduction, costs are also presented for 45% and a
65% NOX reduction. This represents the expected range of performance considering the
control technique and plant-to-plant performance variations. The natural gas injection
heat input levels associated with the 45% and 65% NOX levels of reduction are 9% and
17%, respectively. As shown in Table 2-3, capital costs, tipping fee impacts, and NOX
control cost effectiveness values decrease with increasing combustor size.
For a given combustor size, variations in NOX reduction level have little
impact on costs. A greater impact is observed for tipping fee impact and cost
effectiveness. For all three combustors, the tipping fee impact and cost effectiveness
value increase with increasing NOX reduction. This is primarily caused by the increased
revenue loss resulting from displacement of MSW when firing more natural gas.
Increased fuel (natural gas) costs are also incurred with increasing NOX reduction.
These data indicate that NGI economics are driven by the cost associated
with displacing the MSW -- !th natural gas. A more attractive application of NGI is for
an MWC that has unused capacity such that little or nc MSW is displaced when using
gas injection. Table 2-4 presents the results of NGI applied to the model combustors
assuming they have 15% additional heat input capacity available (referred to as
NGI-85)." The capital cost associated with this application is the same as those
presented in Table 2-3. However, the tipping fee impacts and cost effectiveness values
are 70 to 90% lower than for the previous case. The lower end of this difference occurs
at the higher NOX reduction level. For the 65% NOX reduction, the higher amount of
natural gas needed (17% versus 15%) exceeds the additional available heat input
capacity. Therefore, a portion of the waste is displaced, and the costs assor'.ated with
this are accounted for.
"The costs associated with this scenario are also generally representative of the case
for an MWC whose heat input is limited only by fan capacity such that the MWC can
continue to operate at design waste feed while using NGI.
sdg/nrcl
sect-2.rpt 2-21
-------
s s,
?«s.
(hi 3
la
Table 2-4
Model Plant Cost Estimates for NGI for MWCs with 15% Available Heat Input Capacity (NGI-85) (a)
NOx Reduction (%)
100 TPD Mass Burn MWC
400 TPD Mass Burn MWC
750 TPD Mass Burn MWC
Total Capital Cost
($1000/TPD capacity)
45
5.18
1.92
1.41
60
5.22
1.96
1.45
65
5.23
1.97
1.46
Tipping Fee Impact
($/ton MSW)
45
3.50
1.60
1.31
60
4.15
2.13
1.81
65
6.73
4.66
4.34
Cost Effectiveness
($/ton NOx)
45
3,649
_1,672
1,365
60
3,044
1,561
1,331
65
4,459
3,090
2,878
(a) $/ton can be converted to $/Mg by multiplying by 1.1.
-------
2.53 Sensitivity Analysis
To account for site-specific differences and other uncertainties in costs
used to develop Table 2-3 (NGI-100: MSW displaced case), an analysis of the sensitivity
of tipping fee impacts and NOX control cost effectiveness to differences in plant size (100
to 700 tpd), fuel cost ($2 to 5/MMBtu), annualized capital cost (±30%), plant tip fee
($40 to 120/ton), and NOX reduction (45 to 65%) was performed. Figure 2-9 presents
the effect of plant size, fuel cost, plant tip fee, and annualized capital cost on tipping fee
impact and cost effectiveness. Figure 2-10 presents the sensitivity of tipping fee impact
and cost effectiveness to NOX reduction. Since a 60% reduction is the design reference
plant reduction, the intersection of tipping fee impact and cost effectiveness occur at this
point.
The range in annualized capital cost accounts for differences in the actual
capital cost of a natural gas injection system, contingency factors, and the cost of money
used for project financing. For example, the annualized capital charge for a natural gas
injection system would be 24% higher if the capital discount rate (cost of money) is 10%
compared to the model combustor, which is based on a 7% capital discount rate. The
plant tip fee represents the amount of revenue a plant would lose per ton of MSW
displaced. The variation in NOX control efficiency results from varying the amount of
NGI to achieve higher or lower NOX reductions, rather than the variability in NOX
reductions that may be achieved by different combustors operating at the same NGI
level.
As shown in these figures, the tipping fee impact and NOX control cost
effectiveness associated with the reference MWC (the center point on Figure 2-9 and
2-iO) are approximately $21/ton of MSW and $15,200/ton of NOX removed. Of the
parameters shown in Figures 2-9 and 2-10, the variation in plant tip fee has the greatest
effect on tipping fee impact and cost effectiveness because this parameter is tied to the
amount of revenue lost when less MSW is burned. Going from the reference plant tip
fee of $80/ton of MSW to $ 120/ton of MSW results in almost a 35% increase in tipping
sdg/nrtl
s«t-2.rpt 2-23
-------
8 E.
Ic,
Kl
30-
28-
Rthrencc MWC Parmmctcrs
Uocontroltcd NOx = 250 ppm
NOx Reduction = 60%
12-
Unit Size (tpd) 100
Purl Cost (J/MMBlu) 2.00
Anoualized Capital (JlOOO/yr) 49
Pl.nt Tip Fe* (J/lon MSW) 40
1°7
Uuit Sizr
-S- Fu«ICost
Auuualixrd Capital
Pbut Tip F«
Figure 2-9, Effect of Unit Siie, Fuel Cost, Annualized Capital and
Plant Fee on Tipping Fee Impact and Cost Effectiveness for N^MOO
(for MWCs without additional heat input capacity)
12°
-------
i a
It
30-
28-
. 26H
(A
s
§ 24-
14-
12-
NOx Reduction (%) 45
Rtfe«ncc MWC ParmmfUrs
Unk Size = 400 ipd
Fuel Cost = S3.50/MMBIU
Aonualized Capita) = $74,000/yr
Plant Tip Fee *= $*0/loa MSW
UncontroUed NOx - Z5Q ppm
,..•*""
48
50
53
58
' Tipping Frr Impact -§§- Cost Effrclivmrcs
22.0
-20.6
-19.1
:17.6
s~-
1-16.2 |
M4.7
-13.2
-11.7
-10.3
$
G
O
3 8
6 '•§
.s
U-i
w
8.8
Figure 2-10. Effect of NOx Reduction on Tipping Fee Impact and Cost Effectivenes
for NG1-100 (for MWCs without additional heat input capacity)
-------
fee impact and cost effectiveness value. Similarly, a decrease to $40/ton MSW results in
a comparable decrease in tipping fee impact and cost effectiveness value.
Changes in NOX reduction also have a large effect on tipping fee impact,
since the amount of MSW that must be displaced increases with the increased amount of
natural gas needed for the larger NOX reduction. As discussed earlier, when MSW is
displaced by natural gas, revenues from that MSW are lost. With an increase in NOX
reduction from 60% to 65%, the tipping fee impact increases by close to 15%. A
decrease of NOX reduction to 45% results in a decrease in tipping fee impact by close to
40%. Changes in NOX reduction have a smaller impact on cost effectiveness. Increasing
NOX reduction to 65% results in small (<5%) increases in cost effectiveness values.
Decreasing NOX reduction to 45% reduces cost effectiveness values by close to 15%.
This results from a relatively constant balance between the amount of additional NOX
removed and the increased costs associated with the burning more gas. As a result, the
ratio of cost to the amount of NOX removed remains essentially unchanged.
Variations in fuel cost from $2.00 to SS.OO/MMBtu result in the next
largest effect on tipping fee impact and cost effective^ -, with these values increasing
linearly with the price of natural gas. Changes in annualized capital cost and unit size
have smaller effects, with annualized capital having almost no affect on tipping fee
impact and cost effectiveness. Unit size has a more pronounced effect on costs for the
small combustors.
2.6 References
1. Seeker, W. R., G. C. England, R. Lyon, and P. Duggan. Advanced
Pollution Control in Municipal Waste Combustors Using Natural Gas. In
Proceedings: 1991 International Conference on Municipal Waste
Combustion. Vol. 1, EPA-600/R-92-209a (NTIS PB93-124170),
November 1992.
2. Bergstrom, J. NOX Reduction Using Reburning with Natural Gas-Final
Report From Full-Scale Trial at SYSAV's Waste Incineration Plant in
idg/nrel
sed-2.rpt 2-26
-------
Malmo. Nordic Gas Technology Center, Hersholm, Denmark.
September 1993.
3. Hura, H. and B. Breen. Mixing and Heat Loss Effects on Nitric Oxide
Reduction During Natural Gas Reburning in Pulverized Coal Boilers.
Presented at the Tenth Annual Pittsburgh Coal Conference, Pittsburgh, PA.
September 1993.
4. Pasini, S. and G. DeMichele. Reburning Scaling Via Mathematical
Modeling. Presented at the 7th Topic Oriented Technical Meeting of the
International Flame Research Foundation, Gas Research Institute, and
American Flame Research Council, Chicago, IL. 1993.
5. Abbasi, H., M. Khinkis, C. Penterson, F. Zone, R. Dunnette, K. Nakazato,
P. Duggan, and D. Linz. Development of Natural Gas Injection
Technology for NOX Reduction from Municipal Waste Combustors. In
Proceedings: 1991 International Conference on Municipal Waste
Combustion, Vol. 1, EPA-600/R-92-209a (NTIS PB93-124170),
November 1992.
6. Biljetina, R., H. Abbasi, M. Cousino, and R. Dunnette. Field Evaluation of
Methane de-NOX at Olmsted Waste-to-Energy Facility. Presented at the
7th Annual Waste-to-Energy Symposium. Minneapolis, MN. January 1992.
7. Abbasi, H., M. Khinkis, and R. Scherrer. An Engineering and Economic
Evaluation of the Methane de-NOX Technology. Presented at the Third
International Specialty Conference on Municipal Waste Combustion.
Williamsburg, VA. April 1993.
8. Abbasi, H. A. and F. J. Zone. Emissions Reduction from MWC
Combustion Systems Using Natural Gas, Task 3--Field Evaluation. Gas
Research Institute, Chicago, IL. GRI-92/0370. December 1992.
9. Gas Reburning at a Waste Incineration Plant in Denmark. NGC News,
Nordic Gas Technology Centre, Horsholm, Denmark. October 1993. p.6.
10. SanyaJ, A., T. M. Sommer, B. A. Folsom, L. Angello, and R. Payne. Cost
Effective Technologies for SO2 and NOX Control. Presented at Power-Gen
1992. Orlando, FL. November 1992.
sdg/nrtl
sect-2.rpt 2-27
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3.0 SELECTIVE NON-CATALYTIC REDUCTION
3.1 Process Description
Selective non-catalytic reduction refers to add-on NOX control techniques
that reduce NOX to N2 without the use of catalysts.1 A generalized schematic of SNCR
applied to MWCs is shown in Figure 3-1. As indicated in the figure, one or more of
several reducing reagents is injected into the upper furnace to react with NOX and form
N2 and water. Specific SNCR processes include Thermal DeNOx™ (originally licensed
by Exxon Research and Engineering), based on ammonia (NH3) injection,2 NOXOUT™
(Electric Power Research Institute/Nalco Fuel Tech) which uses urea [CO(NH2)J
injection,J>4 and the addition of urea followed by methanol.5 This discussion is limited to
the Thermal DeNOx and the NOXOUT processes because of their predominant use.
3.1.1 Thermal DeNOx™
With Thermal DeNOx, either aqueous or anhydrous NH3 is injected into
the upper furnace of the combustor. Ammonia and NOX react according to the
following generalized reactions:
4 NO + 4 NH3 + O2 - 4 N2 + 6 H2O (3-1)
4 NH3 + 5 O2 - 4 NO + 6 H2O (3-2)
At 870 to 980°C (1,600 to 1,800°F), the first reaction dominates and NOX is reduced to
N2. Above 1,100°C (2,000°F), the second reaction dominates and NH3 is oxidized to NO.
Below 870°C (1,600°F), both reactions proceed slowly and a significant fraction of the
NH3 remains unreacted. These reaction pathways are illustrated in Figure 3-2.
As shown in Figure 3-2, the amount of amide radical (NH2) formed
through thermal decomposition of NH3 is critical to the destruction of NOX. Flue gas
temperature and carbon monoxide (CO) concentrations influence both the
sdg/nrel
s«t-3.rpt 3-1
-------
Figure 3-1. Schematic Diagram of SNCR Applied to an MWC
sdg/nrel
3-2
-------
8 £.
?«!.
Ut 3
NH
NB,
NH,
OH —- NO +
NO —- N2 + H2O
NH3 slip
Temperature
Figure 3-2. Ammonia Reaction Pathways
-------
decomposition of NH3 to NH2 and the interaction of NH2 with NO. If there is too much
CO present, excess hydroxyl (OH) radical is formed, which react with NH2 to eventually
form NO rather than reducing NO to N2.
3.12 NOXOUT™
The NOXOUT™ process uses stabilized ure.. injection to reduce NOX to
N2, CO2, and water. The generalized reaction pathways for this control technology are
shown in Figure 3-3.6
As shown in Figure 3-3, urea decomposes to NH3 and HNCO. The
reaction of NH3 with NO is similar to Thermal DeNOx d:,cussed above. The reaction of
NCO (produced by reaction of HNCO with hydroxyl [OH] radical) provides several
additional reaction paths. A». temperatures above 1,100°C (2,000°F), NCO reacts with
hydrogen and oxygen radicals:
NCO + H ^ NH + CO (3-3)
NCO + O -» NO + CO (3-4)
At these temperatures, NH can react with O2 and OH to form NO. Between 800°C
(1,500°F) and 1,100°C (2,000°F), the primary reaction is:
NCO + NO - N2O + CO (3-5)
This alternate reaction is important because both of the products, nitrous oxide (N2O)
and CO, are of environmental concern (N2O is of special concern because of its role as a
global warming "greenhouse" gas). However, at temperatures above 950°C (1.750T),
N2O will decompose thermally or react with oxygen to produce N2, and CO will react
with oxygen to produce CO2:
sdg/nrtl
wct-B.rpt 3-4
-------
s B.
?1
<" =
•3 1
+ OH
+ H
+ OH —- NO + H2O
O
NCO
+ NO " N9O -»- CO L* CO + O —- CO2
N2O
NO + CO
Temperature
N2+O
N2O + CO
Figure 3-3. Urea Reaction Pathways
-------
N2O - N2 + O (3-6)
N2O + O - N2 + O2 (3-7)
CO + O - CO2 (3-8)
At lower temperatures, however, the rates of reaction are relatively slow and the
potential exists for significant emissions of NH3, N2O, and CO. To reduce these
emissions, a variety of chemicals can be injected to promote reactions at temperatures as
low as 800°C (1,500°F) and thereby minimize by byproduct emissions.7
32 Development Status
SNCR has been applied to a number of MWCs in Japan, Europe, and the
U.S. MWCs in the U.S. that have permanently installed SNCR, have conducted
demonstration tests, or are currently in the planning stage are listed in Table 3-1.
33 Key Design and Process Variables
Five factors influence the performance of ammonia- or urea-based SNCR
systems: reagent-to-NOx ratio, flue gas composition, temperature, reagent distribution,
and residence time.
The reagent-to-NOx molar ratio, or more specifically the NH2-to-NOx ratio
(also known as the normalized stoichiometric ratio-NSR), ultimately determines the
potentially achievable NOX reduction.4'7'8 For NH3-based systems, the reagent ratio is
equal to the NH2-to-NOx molar ratio*. For urea-based systems, each mole of urea
contains two moles of NHj, such that a urea-to-NOx ratio of 0.5 results in an NSR of
1.0. Figure 3-4 shows that at an NSR of 1.0, reported NOX reductions from MWCs are
40 to 60%. Although not directly indicated on the figure, much of the variability in
'Molar ratio, as used in this instance, refers to the number of moles of reagent (e.g.,
NH3) to the number of moles of NOX in the flue gas.
sdg/nrel
s«n-3.rpt 3-6
-------
Table 3-1
Summary of U.S. SNCR Applications on Municipal Waste Combustors
Name/Location
Capacity
Cily ot' Commerce, CA
I x 380 tpd
Stanislaus County, CA
2 x 400 tpd
Lone Beach, CA (SERRF)
3X^60 tpd
Huntington, NY
3 x 25c
103 ppm
140 ppm
52 ppm
I50ppmk
--
9«ppm
96 ppm
< 165 ppm
70 ppm
70 ppm
-
--
(continued)
-------
Table 3-1
(Continued)
Name/Location
Capacity
Falls Township, PA
2 x 750 ipd
Montgomery County. MD
3x600tpd
Onondaga County, NY
3 x 330 fpd
Other
APCDs3
SD/FF/CI
SD/FF/CI
SD/FF/CI
Reagent
Urea
NH3
NH,
New or
RctroGt
N
19
New
1995
New
1995
Permitted
NO/
180 ppm
180 ppm
180 ppm"
200 ppm
Averaging
Tune
24-hr
24-hr block
24-hr block
3-hr rolling
Measured
N0,b'c
A
--
-
--
00
a APCD = air pollution control device
SD = spray dryer
FF = fabric tiller
FOR = flue gas recirculation
ESP = electrostatic precipitator
CI = carbon injection
''Emissions corrected to 7% O2 unless otherwise noted.
cMeasured values reflect performance test and/or typical values,
and are not appropriate for setting short-term permit limits.
^Limit is a South Coast Air Quality Management District limit for
all liquid and solid fuel-tired units in the basin.
eAlso must meet a 40 Ib/hr limit (1-hr basis) and a 825 Ib/day
limit.
Must also meet a 1130 Ib/day limit. Also has a.; NH-j limit of
50 ppm at actual C^-
SOr 160.5 Ib over a 3-hr period, whichever is more stringent.
.Or 1200 Ib/day, whichever is more stringent.
'Also must meet a 34 Ib/hr limit (1-hr basis) and a 720 Ib/day
.limit.
JAIso must meet a 65.5 lb/1 r/furnace limit (8-hr basis).
^Emissions coireeled to !2% CO2-
'Corrected to 12% CO2. Based on a permit that expired 1/92.
mAlso must meet a 801b/hr limit.
"Also must meet a 58 Ib/hr limit (3-hr rolling average) and a
0.35 Ib/MMBtu limit.
-------
•3*
100
&
ra
o
8
z.
90
80
70
60
50
40
30
20
10
Midrange + 25%
Midrange
0.4 0.8
1.2
1.6
NSR
2.4 2.8
Figure 3-4. Effect of Reagent Feedrate on SNCR Performance
-------
reported performance levels reflects the differences in NOX reductions achieved between
individual MWCs, rather than variability in performance at a single MWC. The
performance curves shown on the figure are generally reflective of the relationship
between NOX reduction and NSR experienced at individual facilities. At an NSR near
2:1, NOX reductions of 50 to 80% have been reported. Increasing the ratio beyond 2:1
has little additional effect on NOX reduction. However, at high NSR ratios, emissions of
unreacted NH3 (known as "NH3 slip") can be significant. Note from Figure 3-4 that
there is not a clear distinction in NOX reduction between NH3 and urea.
Second, the composition of the flue gas is also critical in determining the
potential efficiency of SNCR.4 The concentration of NOX determines the necessary
amount of reagent injection. In addition, CO and O2 levels at the point of reagent
injection affect process chemistry. High levels of O2 (above 6%) tend to improve
performance. CO concentration above 100 ppm can shift the reaction kinetics and lower
the effective temperature range for the NH2/NOX reaction. Other constituents typically
present in MWC flue gas, such as chlorides, do not seem to have a significant effect on
process gas phase chemistry.9
The third factor affecting NOX is flue gas temperature. Figure 3-5, which
is based on urea injection but is generally representative of NH3 injection, shows the
effect of combustion gas temperature and composition on NOX removal.6 At
temperatures below the acceptable operating range of 700 to 800°C (1,300 to 1,500°F),
the desired NOX reduction reactions do not occur and NH3 slip increases. Above the
acceptable temperature range, NH3 is oxidized to NOX, resulting in low NOX reduction
efficiency and reagent utilization. Also shown in Figure 3-5, N2O emissions are highest
between 800 and 1,000°C (1,500 and 1,800°F).
For MWCs, the required temperature window occurs in the upper section
of the furnace. Because of variability in MSW composition, however, there can be
significant variations in combustion gas temperatures over relatively short time intervals.
This can lead to significant changes in gas temperature at a given furnace elevation. As
sdg/nirl
sert-3.ipt 3-10
-------
•3 i
725
825 925
Temperature (°C)
1025
1125
Figure 3-5. Effect of Temperature and Flue Gas Composition on SNCR Performance
-------
a result, MWCs typically have installed several rows of reagent injection nozzles in order
to allow injection of reagent within the required temperature window. Because of
difficulty in monitoring furnace temperature, however, existing facilities have conducted
SNCR optimization tests soon after the MWC has commenced operation to determine
the injector elevation that generally provides the best balance between NOX reduction
and NH3 slip.8'10 During subsequent operation of the SNCP system, reagent is injected
through the injector row that was found to have the best performance during the
optimization test. Because of high and low temperature fluctuations that occur during
normal operation, however, the reagent can oxidize to increase NOX emissions or may
not fully react and result in NH3 slip. Recently developed techniques for providing
real-time monitoring of furnace temperature are discussed in Section 3,4.
The fourth factor affecting SNCR performance is distribution of the
reagent with the flue gas. The zone surrounding each reagent injection nozzle is mixed
by the turbulence of the flue gas. Distribution in regions distant from an injection nozzle
depends on adequate reagent velocity and momentum for penetration. Because of
reduced flue gas turbulence, stratification of the reagent and flue gas can be a problem
at low combustor loads.
The fifth factor affecting SNCR performance is the residence time of the
injected reagent within the required temperature window. A residence time of
0.5 seconds is generally adequate in most systems. If the residence times are too short,
there will be insufficient time for completion of the desired reactions between NOX and
NHj. Based on gas velocities and cooling rates in the upper furnace of MWCs,
residence time limitations are less severe than in many fossil fuel-fired combustor
applications.
Additional concerns related to SNCR processes are associated with
secondary environmental impacts caused by high reagent feed rates. These impacts
include NH3 emissions to the atmosphere and NHj concentrations in APCD ash. At an
NR of 1.5 and less, NH3 slip rates are generally less than 10 ppm and NH3 levels in
sdg/nrel
sfa-3.rpt j-l£
-------
APCD ash are low.4-7-8 As injection rates increase beyond an NSR of 1.5, NH3 slip and
ash concentrations increase substantially. In addition, because of health and safety
concerns associated with accidental release of NH3 during reagent transport, handling,
and storage operations, most SNCR systems are being designed for aqueous NH3 or
urea.
The variability in the reported data suggests that NH3 slip measurements
are also highly dependent on system design variations (residence time, temperature,
reagent distribution, APCD type), sampling location (prior to or after APCD), and
sampling method. Currently, there is not an established method (i.e., EPA standard) for
measuring NH3. Potential NH3 measurement problems include the loss of NH3 on cool
surfaces in the sampling train where water or ammonium salts may form and the release
of NH3 from sampling train impingers if acidic pH is not maintained
Unreacted NH3 can react with residual HC1 exiting the stack to form a
detached ammonium chloride (NH4C1) plume. These plumes are whitish in color and
can create concerns with visible emissions. Such plumes have been observed under
certain process and atmospheric conditions at several of the U.S. MWCs with SNCR. In
addition, ammonium sulfate salts can form when the unreacted NH3 contacts SO3 in the
flue gas. These salts can potentially lead to heat transfer surface scaling and corrosion;
however, these problems have not been reported to date by U.S. MWCs. If NH3 levels
in APCD ash are high (due to high NSR injection levels), it may be necessary to install
NH3 stripping and vapor collection equipment to protect worker health and safety during
ash handling operations.
An unresolved issue related to NH3 slip is the NH3 collection efficiency of
a fabric filter (FF) versus an ESP. Most of the NH3 slip data are from systems using a
FF for paniculate control. Relatively little data are available on units equipped with
ESPs or where NH3 levels have been measured prior to and after the control device.
Testing at a FF-equipped coal-fired boiler reported significant NH3 reduction across the
FF.11 Testing at an MWC indicated that NH3 levels following the FF were low except
alg/nrel
sect-3.rpt O-lj
-------
after extended operation at high NH3 feed rates." Discussions with MWC personnel
indicate that an NH3 odor is present in collected ash.12 All of these data suggest that
the filter cake removes a significant portion of the NH3 in the flue gas unless inlet NH3
levels are sufficiently high to exceed the adsorption capacity of the filter cake. It is
unclear, however, that an ESP will be equally effective at controlling NH3 slip emissions.
As a result, NH3 slip levels and the potential for an NH4C1 plume may be higher for an
MWC equipped with an ESP than for a unit with a FF.
3.4 Recent Advances and Further Research Needs
As discussed above, SNCR performance depends on injection of the
reagent within the desired gas temperature window. Because of the variability in MSW
composition, however, it has been difficult to monitor the flue gas temperature within
the furnace and to adjust the reagent injection elevation accordingly. As a result, a high
temperature excursion within the furnace can result in oxidation of NH3 to NOX, while a
low temperature excursion will delay the NH3/NOX reactions, which results in reduced
NOX reduction and increased NOX and NH3 emissions. High NH3 emissions during low
temperature excursions can be further increased if the SNCR control system is designed
to increase NH3 or urea feed rate in response to the higher NOX reading by the NOX
CEM located downstream of the furnace.
To overcome these limitations, two new technologies have been applied:
real-time furnace pyrometry to continuously monitor gas temperature and continuous
NH3 monitoring.
3.4.1 Temperature Monitoring
Two advanced techniques exist for continuously monitoring furnace
temperature.13 These are infrared (IR) pyrometry, which measures IR radiation emitted
from the hot combustion gases, and acoustic pyrometry, which determines gas
temperature based on the speed at which sound travels through heated gases. Infrared
tdg/nrcl
sect-3.rpt 3-14
-------
pyrometry is a simpler technology that measures IR emissions from solid "black body"
particles entrained in the combustion gases. Because of variations in the "dirtiness" of
the combustion gases over time, however, the black body emissivity characteristics of the
gas vary. As a result, the IR signal received by the pyrometer can vary independently of
temperature. For example, a relatively clean gas (one containing few solid particles) and
a dirty gas (one containing significant soot, "sparklers", or other solid particles) at the
same temperature will result in different IR responses. Despite these limitations,
however, IR pyrometry can be used to monitor fluctuations in gas temperature and to
detect flames (as opposed to hot gases) in the instrument's viewing plane.
Acoustic pyrometers determine the mean gas temperature between two
points by measuring the travel time for a sound signal and then converting this time to a
temperature based on the travel distance and the relationship between the speed of
sound and gas temperature. The advantage of this approach is that the speed of sound
in combustion gases is relatively insensitive to the dirtiness of the gas and, therefore,
provides a direct indication of gas temperature. In addition, by installing several
pyrometers in the furnace and measuring the travel time between each pyrometer pair, a
temperature (i.e., isotherm) map of the furnace can be generated.
Use of IR pyrometry to improve SNCR performance was evaluated during
a technology demonstration test funded by Ogden Martin Systems (OMS) at the
Lancaster, Pennsylvania MWC (conducted in January-March 1993).14 The system used
during this test, shown in Figure 3-6, included an IR pyrometer in the lower furnace to
monitor lower furnace temperature and flame height, two reagent injection rows,
separate aqueous NH3 and dilution water tanks, NOX and NH3 CEMS (see
Section 3.4.2), and a process controller. The pyrometer was used to determine which
injector row to use, while the CEMS were used to control the NH3 injection rate.
Dilution water was used to assure proper reagent injection momentum (i.e., good
distribution) as the NH3 feed rate varied. Using this scheme, during high temperature
periods, all of the NH3 was injected through the upper row, while the lower row was
used during low temperature periods. In addition, the NH3 analyzer was used to avoid
sdg/nrel
iect-3.rpt 3-15
-------
AMMONIA SIGNAL
FROM ECONOM
BOILER
FURNACE
SECTION
AQUEOUS
AMMONIA
©
DILUTION
WATER
NOx SIGNAL
FROM CEM
1. AQUEOUS AMMONIA STORAGE.
2. DILUTION WATER SUPPLY.
3 CENTRIFUGAL PUMP FOR AMMONIA.
4. CENTRIFUGAL PUMP FOR DILUTION WATER.
5. AMMONIA MANIFOLD (REGULATES DISTRIBUTION OF AMMONIA TO EACH ZONE).
6. WATER MANIFOLD (MAINTAINS CONSTANT PRESSURE AT EACH NOZZLE FOR
PROPER ATOMIZATION).
7. INJECTION NOZZLES - 2 ZONES.
8. ISOLATION VALVES.
9. AQUEOUS AMMONIA CONTROL LOOP TO MODULATE AMMONIA FLOW.
10. DILUTION WATER PRESSURE CONTROL LOOP.
11. AQUEOUS AMMONIA FLOW CONTROL VALVE.
t
FLUE
GAS
FLOW
(NOTE: During subsequent testing, a NOX signal from the economizer was used for
process control instead of the NH3 signal).
Figure 3-6. Schematic Diagram of Advanced SNCR Applied to the
Lancaster County MWC14-15
sdg/nrcl
JcctO.rpe
3-16
-------
overfeeding NH3 during periods of increased NOX resulting from slow NH3/NOX
reactions at low furnace temperatures. During the initial testing at Lancaster County,
NOX levels (corrected to 7% O2) varied between 30 and 120 ppm and averaged
approximately 70 ppm.14 Based on an assumed uncontrolled NOX level of 250 ppm, the
average emission rate of 70 ppm equates to a reduction of approximately 70%. These
tests indicated.^however, that at the NSR levels required to achieve this NOX reduction,
there were periodic excursions in NH3 slip that resulted in visible emissions. To better
define the ability of advanced SNCR to control visible emissions, OMS conducted
additional testing at Lancaster County in September-October 1993.'5 As part of these
subsequent tests, process control was maintained by measuring NOX with a fast response
analyzer located at the economizer, instead of using the NH3 analyzer. OMS replaced
the NH3 analyzer because it was not as reliable for process control as originally
anticipated. During these additional tests, OMS reduced the NSR and achieved visible
emissions of less than 10% opacity (based on 6-minute averages) at all times and of 5%
or lower opacity for 90% of the time. During these approximately 550 hours of testing,
NOX emissions averaged 100 ppm with a maximum recorded 3-hour average of 126 ppm.
Based on these data, OMS believes that a 3-hour emission limit of 140 ppm can be
continuously achieved with advanced SNCR.
Acoustic pyrometry has been in use at the North Munich MWC in Munich,
Germany since the summer of 1991.l2 This system consists of a six pyrometer array
(two each on the rear and two side walls) located approximately 33 feet (10 meters)
above the grate. As opposed to using the system solely lo determine the NH3 injection
elevation, the system is also used to control the rate of waste feeding and the distribution
of undergrate and overgrate air to minimize both temporal and spatial variations in
combustion gas temperatures. Although emissions performance data have not been
reported, the system is claimed to have reduced the variation in instantaneous furnace
gas temperatures from 300°C (540°F) using the previous control scheme to approximately
150°C (270°F) and reduced CO spikes due to better combustion control. By allowing
more careful control of the localized combustion conditions, the system is also claimed to
.dg/nrel
stct-J.rpt J-l/
-------
be capable of reducing furnace and superheater tube wastage caused by localized hot
spots and reducing environments.
3.4.2 Ammonia Continuous Emissions Monitors
As SNCR and SCR have become more common NOX control methods, the
need for real-time measurement of NHj for process control has increased. Ammonia
measurements can be used as part of a feedback loop to optimize SNCR-based NOX
control systems by allowing increased NH3 or urea injection rates while minimizing NH3
slip.
To meet this need, a number of vendors have been working to develop
NH3 CEMs. These instruments use a variety of spectrographic techniques, including
chemiluminescence, non-dispersive infrared (NDIR), ultraviolet (UV), ion mobility
(IMS), and differential optical adsorption (DOAS). Based on vendor data, UV and IMS
have the best measurement accuracy (± 1%) in low SO2 flue gases, but cannot be used
in high-SO2 environments (SO2:NH3 ratio s 80) due to measurement interference.
NDIR has somewhat lower accuracy (± 3%), but can operate at SO2 levels of up to
2,000 ppm. Chemiluminescence measurement of NH3 uses two monitors, one measuring
the NOX level in the flue gas and the other measuring the NOX concentration following
a reactor chamber that converts NH3 in the flue gas to NOX. Although
chemiluminescence can be used in high-SO2 environments, it has relatively low accuracy
(± 10%) due to potential measurement errors of the two monitors.
Based on typical MWC flue gas composition, any of these monitors may be
feasible. However, long-term operating and reliability data are limited and their use as a
process control or an emission compliance monitor has not been validated.
sdg/nrcl
tcct-3.rpt 3-18
-------
3.5 Cost Analysis
3.5.1 Design Basis
Several variations of SNCR technology exist, depending on the reagent
type and method of injection. As discussed in Section 3.1, reagent options include
anhydrous NH3, aqueous NH3, and urea. An anhydrous NH3 system generally will have
the lowest capital cost, but requires storage of potentially hazardous anhydrous NH3.
Aqueous NH3 (typically consisting of 25 to 29% NH3 dissolved in water) is safer to store
than anhydrous NH3, but requires a larger storage tank. Aqueous NH3 can be injected
either as a vapor, with an injection system similar to that described for an anhydrous
NH3 system, or as a liquid. If it is injected as a vapor, a steam- or electrically-heated
vaporizer is used to liberate the NH3 from the water carrier. If aqueous NH3 is injected
as a liquid or if urea is used, the cost of the vaporizer and high-pressure carrier gas
system are avoided; however, the thermal efficiency of the combustion process is reduced
because of the energy loss resulting from vaporization of the carrier water by the
combustion gases.
The costs presented in this section are based on injection of aqueous NH3
as a liquid. The capital costs for this system are similar to the costs for a urea-based
system, although the costs may be distributed somewhat differently. The capital cost for
an anhydrous NH3 system is expected to be slightly lower, while the cost of aqueous NH3
system with a vaporizer will be somewhat higher. The SNCR system designs examined
include: a conventional SNCR system similar to that described in Section 3.1, two
variations of the advanced SNCR system based on the concepts presented in Section 3.4,
and an advanced NGI system, which combines SNCR and NGI as described in
Section 2.4.
The design basis for the conventional SNCR system includes two rows of
reagent injectors, an average NOX reduction of 60%, and manual control of the NH3
injection system. Based on a typical uncontrolled NOX concentration of 250 ppm at 7%
sdg/nrcl
seo-3.rpt 3-19
-------
O2, this NOX reduction results in an average stack concentration of 100 ppm at 7% O2.
The 60% reduction represents long-term (annual average) performance capabilities when
considering performance at all facilities. Performance at individual plants will vary, and
this average performance level may not be achievable at all plants, especially when
considering retrofit situations. The average NSR needed to achieve this reduction is
assumed to be 1.4." The number of reagent injectors in each row is based on the
assumption of one injector per 40 tpd of MWC capacity. Control of the reagent
injection system is handled manually by the combustor operator based on visual
observation of furnace conditions and the measured NOX level in the stack. Because the
furnace camera and NOX CEM used for these purposes are required for other reasons,
the cost of these items are not included in the SNCR capital cost. Based on the
commercial status of this technology, the process contingency assumed for conventional
SNCR is 10%.
The advanced SNCR system design also includes two rows of reagent
injectors, as in the conventional SNCR system, but also includes automatic control of the
NH3 injection system. The NH3 injection control system includes an acoustic pyrometer,
an NH3 CEM, and a control system designed to vary injection location and rate based on
the pyrometer and CEM measurements. Through the use of this control system, a 60%
reduction is assumed to be achievable with an NSR of 1.0 (versus 1.4 with the
conventional SNCR system). As with the conventional SNCR system, this NOX
reduction results in an average stack concentration of 100 ppm at 7% O2, based on an
inlet concentration of 250 pprn at 7% O2. As stated above, this reduction level
represents long-term performance capabilities. A limited examination of an advanced
SNCR system with a 70% NOX reduction and an average stack concentration of 75 ppm
is also presented. An NSR of 2.0 is assumed to achieve the higher reduction. Also,
because of the potential for high NH3 levels in the ash resulting from the higher NSR,
" This level was selected as a reasonable balance between NO, reduction and NH3
slip. Because of fluctuations in "uncontrolled" NO, levels and furnace temperatures,
however, instantaneous NSRs, NOX reductions, and NH3 slip rates may be higher or
lower.
cdg/nrcl
s«ct-3.rpt 3-20
-------
NH3 stripping and vapor collection equipment ty protect worker health and safety during
ash handling operations are included. Based on the limited number of advanced SNCR
demonstrations, a process contingency of 25% is used for both advanced SNCL scenarios
to cover additional testing and potential costs for system modification.
The advanced NGI system design reduces NOX emissions by first using
natural gas injection to achieve a 60% reduction in NOX, followed by a 50% reduction
through the liquid injection of aqueous NHj. This results in an overall NOX reduction of
80%, which equals an outlet level of 50 ppm at 7% O2 assuming an uncontrolled NOX
level of 250 ppm at 7% O2.
For the gas injection portion of the system, natural gas is injected equalling
a heat input level of 15 percent. It is assumed that the MWC has additional heat input
capacity available such that lost revenue does not occur from diverting waste. The
SNCR portion of the system is the same as for the conventional SNCR system except
that to reduce the SNCR inlet NOX level (100 ppm) by 509o, an NSR of 0.8 is used.
352 Cost Results
Cost estimates for the conventional and advanced SNCR and for advanced
NGI were developed for 100, 400, and 750 tpd model combustors.
Conventional SNCR
s
Conventional SNCR-specific input and output values for the 400 tpd model
combustor are shown in Tables 3-2 and 3-3. Additional inputs (e.g., labor rates,
electricity price) used in the cost analysis of both technologies are presented in
Table A-2 of Appendix A. Table 3-4 presents the estimated capital cost per tpd of
capacity, tipping fee impact, and NOX control cost effectiveness for the conventional
SNCR system applied to the three model combustors. In addition to 60% NOX
reduction, the table also presents the estimated cost for 45% and 65% NOX reduction.
sdg/nrel
s«t-3.rpt 3-21
-------
Table 3-2
Model Combustor Inputs For Conventional SNCR
Injection System
Number of Wall Injectors
Ueagent
Injection Method
Fuel
Aqueous Ammonia
Liquid
MSW
Plant Characteristics
Unit csize (tpd)
Flowrate (dscfm @ 7% O2)
Flowrate (wscfm @ 11% O2)
Capacity Factor
Tons/yr of MSW Processed Oons/yr)
Uncontrolled NOx (ppmv, dry)
NOx Removal Efficiency (%/100)
Normalized Stoichiometric Ratio (N/NO)
Reagent Injection Rate (lb/hr)
Outlet NOx (ppmv, ciry)
Tons of NOx removed (tons/yr)
Capital Recovery Factor (1/yrs)
400
41,271
70,462
0.9
131,400
250
0.60
1.4
32
100
152
0.0944
sdg/nrc'
s«ct-3.rpt
3-22
-------
Table 3-3
Cost Outputs For Conventional SNCR
Applied to the 400 TPD Model Combustor (a)
Capital Cost Section ($1000)
Storage
Injection System
Compressor
Instrumentation
Installation
Total Process Capital (SI 000)
Engineering
Contingency
Total Control Cost ($1000)
License Fee
Pre-Production
Inventory Capital
Total Capital Requirement ($1000)
Total Capital per Capacity ($1000/tpd)
Total Annualized Capital Requirement (SlOOO/yr)
71
178
94
0
86
429
86
154
669
96
24
5
79*
1.98
75
Variable O&M Cost Section (SlOOO/yr)
Reagent Cost
Electric - Compressor
Energy Loss - Vaporization
Dilution Water
Total Variable O&M ($1000/yr)
38
2
2
0.16
42
Fixed O&M Cost Section (SlOOO/yr)
Operating Labor
Maintenance Material
Maintenance Labor
Administrative & Support Labor
Total Fixed O&M ($1000/yr)
44
10
7
15
76
Total Cost Section
Total Annualized Cost ($1000/yr)
Tipping Fee Impact ($/ton of MSW)
Cost Effectiveness ($/ton of NOx)
193
1.47
1,268
(a) $/ton can be converted to $/Mg by multiplying by 1.1.
sdg/nrcl
nctO.rpt
3-23
-------
S £.
?e.
<- =
i *
Table 3-4
Model Plant Cost Estimates For Conventional SNCR (a)
NOx Reduction (%)
100 TPD Mass Burn MWC
400 TPD Mass Burn MWC
750 TPD Mass Burn MWC
Total Capital Cost
(S1000/TPD capacity)
45
5.05
1.97
1.49
60
5.06
1.98
1.50
65
5.07
2.00
1.52
Tipping Fee Impact
($/ton MSW)
45
3.74
1.30
0.92
60
3.91
1.47
1.09
65
4.06
1.62
1.24
Cost Effectiveness
($/ton NOx)
45
4,308
1,496
1,058
60
3,378
1,268
940
65
3,235
1,289
986
(a) $/ton can be converted to $/Mg by multiplying by 1.1.
-------
This represents Ihe range of performance considering the control technique and
plant-to-plant performance variations. To achieve these alternate NOX reduction levels,
NSR of 0.6 and 2.0 were assumed. Although not quantified, the higher NOX reduction
rate is expected to also have higher NH3 slip levels and higher NH3 levels in the ash.
Costs for NH3 stripping and ash handling equipment are not included in the estimates
presented in Table 3-4. As shown in Table 3-4, capital costs, tipping fee impacts, and
NOX control cost effectiveness values decrease with increasing combustor size. Within a
model combustor size range, the impact on costs caused by variations in NOX reduction
level is smaller. This is especially true for capital cost. A more significant change is
observed in tipping fee impact and NOX control cost effectiveness. For all three model
combustors, the tipping fee impact increases with increased NOX reduction, primarily
due to increased reagent costs. NOX control cost effectiveness values for the 400 and
700 tpd model combustors are lowest at the 60% NOX reduction level, with increased
cost effectiveness values at the lower and higher reduction levels. For the 100 tpd model
combustor, cost effectiveness values are highest at the 45% NOX reduction level and
lowest at the 65% NOX reduction level.
Advanced SNCR
The estimated capital cost per tpd of capacity, tipping fee impact, and NOX
control cost effectiveness for ilw advanced SNCR system at a 60% reduction are
presented in Table 3-5 for the tlaee model combustors. As discussed in Section 3.5.1,
this advanced SNCR system is assumed to achieve this reduction with an NSR of 1.0. To
address the uncertainty of cost associated with this concept, the capital cost is varied
± 30% from the model case. Depending on the capital cost variance of ± 30%, the
capital costs associated with this system range from 16% higher to 3 times higher than
for the conventional system because of the costs of the controls and the higher process
contingency. The tipping fee impacts and cost effectiveness values, which consider
operating costs as we!l as capital costs, are 5 to 90% higher for the advanced system than
for the conventional system. As would be expected, the cost differential between
advanced and conventional systems is greatest for the 100 tpd MWC and decreases as
tdg/nrcl
«ct-3rpt 3-2.)
-------
Table 3-5
Model Plant Cost Estimates for Advanced SNCR (a), (b)
Capital Cost Variance (%)
100 TPD Mass Burn MWC
400 TPD Mass Burn MWC
750 TPD Mass Burn MWC
Total Capital Cost
($IOOO/TPD capacity)
-30%
8.30
2.62
1.73
0%
11.9
3.74
2.47
+30%
15.4
4.86
3.22
Tipping Fee Impact
($/ton MSW)
-30%
5.24
1.69
1.14
0%
6.26
2.01
1.35
+ 30%
7.28
2.33
1.56
Cost Effectiveness
($/ton NOx)
-30%
4,524
1,460
983
0%
5.407
1,738
1,167
+ 30%
6,289
2,016
1,351
(a) $/ton can be converted to S/Mg by multiplying by 1.1.
(b) Based on a 60% NOx reduction and an NSR of 1.0.
-------
MWC size increases. Although not quantifiable in a cost sense, the advanced system
operating at the lower NSR is expected to have lower levels of NH3 slip.
Another option for applying advanced SNCR is to increase the NSR to 2.0
to achieve a NOX reduction level of 70%. As with the conventional system, increasing
the amount of reagent increases the amount of NH3 slip and the levels of NH3 in the
ash. As presented for the advanced system at a 60% reduction level, the amount of
reagent required to achieve this level of reduction with the advanced system is less than
with the conventional system. Similarly, operating the advanced system to achieve a 70%
reduction would require an NSR of 2.0 as compared to a conventional system which
would have to operate at an NSR of 3.0 or higher. Nonetheless, the secondary impacts
still result with the NSR of 2.0. As discussed in Section 3.3, NH3 stripping equipment
and a vapor recovery system can be used to address the issue of potential ash handling
problems. The estimated costs for the advanced SNCR system operating at a 70%
reduction, including equipment costs for NH3 stripping and vapor recovery for ash
handling, are presented in Table 3-6 for the 400 tpd model combustor. Also shown in
this table are costs for the conventional and advanced SNCR systems at 60% reduction.
Although higher NOX reduction is achievable with the advanced SNCR system at the
NSR of 2.0, this additional reduction comes with higher costs and the potential for NH3
slip levels equal to or greater than the systems operating at 60% reduction.
Advanced NGI
The results of the advanced NGI cost evaluation are presented in
Table 3-7. The estimated capital cost per tpd of capacity, tipping fee impact, and NOX
control cost effectiveness are shown for the three model combuslors. In this evaluation,
the price of natural gas is varied from $2 to 5/MMBtu, as this parameter has the
greatest effect on the economics of this control technique. As discussed in Section 3.5.1,
the design basis for this process assumes a 60% NOX reduction based on gas injection
and a 50% reduction based on SNCR. This equals an overall NOX reduction of 80%.
As shown in Table 3-7, advanced NGI is a capital intensive control technique, especially
sect-3.rpt
-------
Table 3-6
Comparison of Conventional and Advanced SNCR Systems (a),(b)
Plant Characteristics
Unit Size (tpd)
Uncontrolled NOx (ppmv, dry)
NOx Removal Efficiency (%/100)
Normalized Sloichiomctric Ratio (N/NO)
Reagent Injection Rate (Ib/hr)
Outlet NOx (ppmv, dry)
Tons of NOx removed (tons/yr)
Conventional
400
250
0.60
1.4
32
too
152
Advanced
400
250
0.60
1.0
24
100
152
Advanced
400
250
0.70
2.0
48
75
177
Capital Cost Section ($1000)
Storage
Injection System
Compressor
Injection System Installation
Instrumentation
NH3 Stripper and Ash Handling
Total Process Capital ($1000)
Engineering
Contingency
Total Control Cost ($1000)
License Fee
Pre-Produciion
Inventory Capital
Total Capital Requirement ($1000)
Total Capital per Capacity ($1000/tpd)
Total Annualized Capital Requirement ($lOOO/yr)
71
178
94
86
0
0
429
86
154
669
96
24
5
793
1.98
75
71
178
94
86
350
0
778
156
420
1353
96
38
8
1,495
3.74
141
73
178
94
86
350
780
1.561
312
843
2,715
96
70
16
2,898
7.24
274
O&M Cost Section ($1000/yr)
Total Variable O&M ($1000/yr)
Total Fixed O&M ($1000/yr)
42
76
32
92
61
127
Total Cost Section
Total Annualized Cost ($IOOO/yr)
Tipping Fee Impact ($/ton of MSW)
Cost Effectiveness ($/ton of NOx)
193
1.47
1,268
264
2.01
1 ,738
461
3.51
2,599
(a) $/ton can be converted to $/Mg by multiplying by l.l.
(b) All three systems are assumed to have two rows of reagent injectors.
sdg/nrel
Kci-3 rpi
3-28
-------
Table 3-7
Model Plant Cost Estimates for Advanced NGI (a), (b)
Fuel Price ($/MMBtu)
100 TPD Mass Burn MWC
400 TPD Mass Burn MWC
750 TPD Mass Burn MWC
Total Capital Cost
($1000/TPD capacity)
2.00
10.2
3.88
2.89
3.50
10.3
3.92
2.94
5.00
10.3
3.97
2.98
Tipping Fee Impact
($/ton MSW)
2.00
5.21
1.05
0.40
3.50
7.25
3.09
2.44
5.00
9.28
5.13
4.48
Cost Effectiveness
($/ton NOx)
2.00
3,214
648
249
3.50
4,471
1,905
1,506
5.00
5,728
3,163
2,764
(a) $/ton can be converted to $/Mg by multiplying by 1.1.
(b) Based on an 80% NOx reduction and assumes the MWCs do have additional heat input capacity.
-------
for smaller MWCs. Both unit size and gas price have a large effect on tipping fee
impact and cost effectiveness. For all three model combustors, the costs increase with
decreasing unit size and increasing gas price.
3.53 Sensitivity Analysis
To account for site-specific differences and other uncertainties in the costs
used to develop Table 3-4 for conventional SNCR, an analysis of the sensitivity of tipping
fee impacts and NOX control cost effectiveness to differences in plant size (100 to
700 tpd), reagent cost (± 30%), annualized capital cost (± 30%), and NOX reduction (45
to 65%) was performed. Figure 3-7 presents the effect of plant size, chemical cost, and
annualized capital cost on tipping fee and cost effectiveness. Figure 3-9 presents the
sensitivity of tipping fee impact and cost effectiveness to NOX reduction. Since the 60%
reduction level represents the design reference plant reduction, the intersection of the
tipping fee impact and cost effectiveness occur at this point.
As discussed in Section 2.5.3 for the NGI sensitivity analysis, the range in
annualized capital cost accounts for differences in the actual capital cost of a system,
contingency factors, and the cost of money used for project financing. The variation in
NOX control efficiency effectiveness reflects the impact of varying the reagent feed rate
to achieve higher or lower NOX reductions rather than the variability in NOX reductions
that may be achieved by different combustors operating at the same reagent feed rate.
Again, although not quantified, variations in reagent feed rate to achieve higher or lower
NOX reductions will also impact NH3 slip rates and NH3 levels in the ash.
As shown in these figures, the tipping fee impact and NOX control cost
effectiveness associated with the reference MWC (the centerline point) are
approximately $1.50 of MSW and $l,270/ton of NOX removed. Of the parameters
shown in Figures 3-7 and 3-8, the variation of unit size from 100 tpd to 700 tpd has the
greatest effect on tipping fee impact and cost effectiveness. Both the tipping fee impact
and cost effectiveness value are inversely related to unit size, and thus, as unit size
sdg/nrel
seci-3.ipt 3-30
-------
8 s.
a?°_
w 9
•a 2.
CO
o
o
o
a
a.
E
I-H
-------
K S.
?«t
^ 3
•a a
OJ
Kl
O
C
O
«
ro
Q,
E
oo
C
NOx Rfduclion (%)
n~
»-
3-
2.5-
O —
C
1.5-
4
) 4
*——___
5
Reference MWC Parameters
Unit Size - 400 tpd
Reagent Cost = $300/ion
Annualized Capital - $75,000/yr
Uncontrolled NOx - 250 ppm
S-~_
— — — & — ,
I 1 1
48 50 53
- rj-j* • „,..«•• wiM'Jh" ********
111!
55 58 60 63 6
-
-------
decreases, the tipping fee impact and cost effectiveness value increase. This is especially
noticeable for a small MWCs, where a decrease in unit size from 400 tpd to 100 tpd
results in an almost three-fold increase in tipping fee impact and cost effectiveness values.
Variations in reagent cost and annualized capital cost of ± 30% have a
smaller impact on tipping fee and cost effectiveness and follow a similar trend to each
other. (Reagent cost refers to the cost of the reagent, not the solution.) This trend is
opposite that for varying unit size. The effect of variations in NOX reduction on tipping
fee impact is similar to varying reagent cost and annualized capital cost. Cost
effectiveness values are lowest at the 60% NOX reduction level. At lower NOX
reductions, the increase in cost effectiveness value reflects the reduced tonnage of NOX
reduction over which fixed costs are distributed. At higher NOX reductions, the increase
in cost effectiveness value reflects the higher reagent injection requirements and costs.
3.6 References
1. U.S. Environmental Protection Agency. Municipal Waste Combustors--
Background Information for Proposed Standards: Control of NOX
Emissions, Vol. 4. EPA-450/3-89-27d (NTIS PB90-154873). Research
Triangle Park, NC. August 1989.
2. Hurst, B. and C. White. Thermal DeNOx: A Commercial Selective
Non-Catalytic Reduction Process for Waste-to-Energy Applications.
Presented at the ASME National Waste Processing Conference, Denver,
CO. June 1986.
3. Wolfenden, L. R., W. F. Flowers, III, B. K. Luftglass, and S. M. Peters.
Commercial Application of the NOxOut Process at a Municipal Waste
Combustor. Presented at the 84th Annual Meeting of AWMA.
Vancouver, British Columbia. June 1991.
4. AJbanese, V., J. Hofmann, and R. Pachaly. NOX Control for Waste
Combustors. Presented at the 1993 International MWC Conference,
Willia- ^urg, VA. April 1993.
5. Jones. .. G., L. J. Munzio, E. Stocker, P. C. Nuesch, S. Negrea, G.
Lautenschlager, E. Wachter, and G. Rose. Two-Stage DeNOx Process
Test Data from Switzerland's Largest Incineration Plant. In Proceedings:
1989 International Conference on Municipal Waste Combustion, Vol. 4,
EPA-600/R-92-052d (NTIS PB92-174687), March 1992.
sdg/nret
scct-3.rpl 3-33
-------
6. HER Inc. and Westinghouse Resource Energy Systems Division. Technical
and Cost Analysis for Urea Injection Used for NOX Emission Reduction.
Submitted to the Michigan Department of Natural Resources in Support of
the Oakland County, Michigan Resource Recovery Facility Project.
September 1990.
7. Sun, W. H., P. G. Carmignani, J. E. Hofmann, D. A. Prodan, D. E. Shore,
L. J. Muzio, G. C. Quartucy, R. C. O'Sullivan, J. W. Stallings, and R. D.
Teetz. Control of By-product Emissions Through Additives for Selective
Non-Catalytic Reduction of NOX with Urea. Presented at the Power-Gen
American '93. Dallas, TX. November 17 to 19, 1993.
8. Personal communications between K. Nebel (Radian Corporation) and J.
Hofmann (Nalco Fuel Tech). April 1994.
9. McDonald, B. L., G.R. Fields, and M. D. McDannel. Selective
Non-Catalytic Reduction (SNCR) Performance on Three California
Waste-to-Energy Facilities. In Proceedings: 1991 International Conference
on Municipal Waste Combustion, Vol. 1, EPA-600/R-92-209a (NTIS
?B93-124170), November 1992.
10. Tozin, G. and L. Brasowski. Thermal DeNOx Optimization Program at
the Huntington MWC. Presented at the 86th Annual Meeting of AWMA.
1993.
II. Hunt, T., G. Schott, R. Smith, L. Muzio, D. Jones, and J. Steinberger.
Selective Non-Catalytic Operating Experience Using Both Urea and
Ammonia. Presented at the 1993 EPRI/EPA NOX Symposium. Miami,
FL. May 1993.
12. Personal communications between D. White (Radian Corporation) and C.
Tripp (City of Long Beach, California), F. Ferraro (Wheelabrator), and L.
Brazowski (Ogden Projects). May 1993.
13. Kleppe, J. The Reduction of NOX and NH3 Slip in Waste-to-Energy
Boilers Using Acoustic Pyrometry. Presented at Power-Gen Americas '93.
Dallas, TX. November 1993.
14. RTF Environmental Associates, Inc. BACT Determination for NOX
Emissions for the Proposed Mercer and Atlantic Counties Regional
Resource Recovery Facility. June 1993.
15. Ogden Martin Systems of Clark, Limited Partnership. Update of the
BACT Analysis for NOX Submitted in the PSD Application and the Ohio
EPA PTI Document of November 12, 1992 for the Mad River Energy
Recovery Facility. April 1994.
sdg/nrel
sect-3.rpl 3-34
-------
4.0 SELECTIVE CATALYTIC REDUCTION
4.1 Process Description
Selective catalytic reduction is an add-on control technology that
catalytically promotes the reaction between NH3 and NOX to form N2 and water.1 SCR
systems can be designed to utilize aqueous or anhydrous NH3, with the primary
differences being the size of the NH3 vaporization system and the safety requirements.
The primary reactions in an SCR system are:
4 NO + 4 NH3 + O2 - 4 N2 + 6 H,O (4-1)
4 NH3 + 5 O2 - 4 NO + 6 H2O (4-2)
These overall reactions are the same as those occurring in NH3-based
SNCR systems; however, the temperature at which 'hey occur are much lower.
Depending upon the catalyst, reaction 1 can take place at temperatures from 190°C
(375°F) to over 535°C (1000°F); however, most individual catalyst formulations used by
MWCs work best within a temperature window of 250 to 350°C (480 to 660°F). The
oxidation of NH3 (reaction 2) begins around 400°C (750°F) and becomes significant
above 480°C (900°F). Below the minimum recommended temperature for a given
catalyst, the NO/NH3 reaction becomes very slow and significant amounts of NH3 can be
emitted. Ammonia slip levels from a properly operated system are less than 10 ppm.
Two options exist for achieving the required catalyst temperature. These
options are shown schematically in Figure 4-1. The first option, sometimes referred to as
"cold-side" or "clean-gas" SCR, is the more common approach applied to MWCs. With
this approach, the catalyst is installed downstream of the other air pollution control
(APC) devices in order to avoid damage to the catalyst caused by acid gases, metals, and
particulate matter in the untreated flue gas. Because of the reduced flue gas
temperature following the final APC device, typically < 150°C (<300°F), it is necessary to
heat the flue gas to an acceptable catalyst operating temperature. The other option,
sdg/nrcl
stcM.rpi 4-1
-------
8£
I"!
Boiler
Acid
Gas
Scrubber
Baghousc
Or
ESP
Boiler
NH,
ESP
vv
Cold-Side SCR System
Hoi-Side SCR System
1
SCR
AGIO
oas
Scrubber
uagnouse
ESP
\/\/
<;
tac
Figure 4-1. Schematic of SCR Configurations
-------
referred to as "hot-side" or "dirty-gas" SCR. is the generally used approach where catalyst
damage from contaminants in untreated flue gas are acceptable. This approach avoids
the need for flue gas reheat, but is a harsher environment for the catalyst.
Most MWC SCR catalysts utilize a base metal oxide, such as vanadium
pentoxide and titanium oxide (V2O5/TiO2) or V2O5/TiO2 impregnated with tungsten
oxide (WO3). The exact composition of the catalyst can be varied to control its
operating characteristics. For instance, WO3 is used to increase catalyst resistance to
chemical deactivation and to reduce SO2 oxidation to SO3. Because of the critical role
of long-term catalyst performance on overall SCR system economics, catalyst resistance
to poisoning (chemical deactivation), pluggage (mechanical deactivation), and erosion
(physical wear) are key considerations in SCR system design. Specific MWC flue gas
constituents influencing catalyst design include acid gases (SO2 and HC1), alkali metal
oxides (Ca, Na, and K), several trace metals (Pb and As), and paniculate loading. The
significance of individual flue gas constituents on catalyst performance is discussed in
Section 4.3,
42 Development Status
To date, SCR has not been applied to any MWCs in the U.S. However, as
shown in Tables 4-1 and 4-2, SCR has been or is scheduled to be installed on a number
of units in Europe and Japan. The initial applications were installed in Japan in 1987
and in Europe in 1990.2J Most of these systems were cold-side designs. Although
operating data from these facilities are limited, deactivation of catalysts located
downstream of the particulate matter and acid gas control equipment has been within
acceptable limits. Vendor guarantees on catalyst life for these systems are approximately
24,000 hours (3 years); actual lifetimes are expected to be longer.
Several hot-side systems have been installed in Japan and Europe, mostly
since 1992. The oldest of these systems, the Hikarigoaka MWC in Tokyo, is the only
hot-side system with significant operating experience. This system was a retrofit
sdg/nrei
sect-4.rpt 4-3
-------
Table 4-1
Summary of SCR Applications on European MWC.s
Name/Location
Cwpaclty
Munii'li S<»illi. Gcniuny
2 x %0 irxl
Spiitclug/VicniM, Ausirin
1 X 960 trxJ
Joscfstn»,sM:/iU»rich, Switzerland
1 » ?00 iptl
FlowcrsicUi/Vicnnii. AuMriu
1 x 720 ipO
ImjolittaUi. Ocniwny
1 x IftOtfxl
HaucnliolA/Zuriih. Swiurrtautl
2 » 300 t(vt
AVR/R.Mlcrituii, HolliiiKt
6 x 620 tfxj
RQTEB/RoiierUiUii. HollumJ
4 i 330 i(xJ
Sfuiumrt. Gcnnauy
2 I 440 <|Kl
Augshwrj!. Ocmiany
JxlBOcfxl
ARN/Niimcecn. Hutl»n4
1 t 240 tpd. 1 * 570 (fx!
Other AI'CIV
Dsi/rr
ESH/3-.-iUijjc WS
SD/USP
ESP'3-siaj;c WS
ESP/WS
I-SP/WS
BSP/2.»Wfc WS/CF
J:SP/2^wt'5 WS'CF
ESPAVS/CSP
ESP/WS
F.SP/SD/BSP/Q'CP
SCR IxKailon &
Temperature
A Her FF
.VXTF xv/ rchciii
A her WS
536° F w/ rclieiit
AKer ESP
5(WF w/ reltcai
AKcr WS
500 "Fv/i rcliem
AKcr WS
SOO'F w/ reheat 1
flciwccn ESP & WS
$00' V wA> relieat
Ader CF
360" Fw/ rchciii
After CF
36U'F w/ rclical
After 2)HJ ESP
580 °F w/ tchcai
After WS
500* F w/ «hcai
Atlci 4«ciu.t>
570' F w/ reheat
Year Startup
New or Retrofit
1990
Retrofit
1990
Retrofit
1991
Retrofit
1992
iktrutii
1992
Retrofit
1993
Retrofit
1993
Retrofit
1993
Retrofit
1993
Retrofit
1993
l«WS
New & Retrofit-1
Target NO,
pptn"
48 ppni
70 pptn
48 ppni
70 ppni
34 ppni
44 ppni
48 pptn
48 ppm
48 ppm
50 ppm
48 ppm
Measured NO,
ppni & % Red."1'
39 ppm/84%
52 ppin/--
35 ppni/8T%
../..
29 ppin/--
29 ppin/91 %
../..
../..
../..
../..
../..
• APCD = »ir pollution control <
DSI = Ury *irt*m
FF * fthrit |llt«f
SO * spray ijryri
BSP = clcv'Moiis(it
WS = wvi stryhhcr
CF = tailniii filter I
Q - qiKiK.li vt
S torrcctcd t» 1% 0,.
values rctlcti pcrt'unnaiitc lexi aiul/or
appropriate for setting shon-icnn pcrniii limits
Ootli the new ami existing units wnl he equipped
typical values, aiiJ ;i.c nut
with SCR.
-------
If
2.
Table 4-2
Summary of SCR Applications on Japanese MWCs
Name/Location
Capacity
Iwatsuki
2 x 65 tpd
H ikarigaok«i/Toku>
2 x 150 ipd
Kaisushika/Tokyo
3 x 400 ipd
Sagamihara
3 x 150 ipd
Toyohashi
1 x 150 ipd
Kashawafuji
3 x 150 ipd
Nerima/Tokyo
2 x 300 ipd
CHh osc/Tokyo
1 x 600 tnd
Takalsuki/Osaka
2 x 180 tpd
Urawa/Saitama
3x 150 ipd
Tsurumi/ Yokohama
3 x 400 tpd
Nishi/Kobc
3 x 200 Ipd
Rinkai/Tukyo
;. r 200 tpd
Yao/Osaka
2 K 300 tpd
Sankaku/Chiba
3 x 190 ipd
Other APCDs"
SD/FF
ESP/WS
DSJ/ESP
SD/FF
Q/FF
ESP/WS
ESP/WS
SD/FF/WS
ESP/WS
SD/FF/WS
O/FF/WS
SD/FF
SD/FF/WS
SD/FF
SD/FF
SCR Location &
Temperature
After FF
410°F
After ESP
428"F
After ESP
M2°F
After FF
.192-F
After FF
4l(fF
After ESP
554°F
After ESP
51K°F
After FF
4l!fF
After WS
4IO'F
After FF
4lO°F
Afler FF
3W*F
After FF
3'tt'F
After WS
4IO°F
After FF
3'»2°F
After FF
m°?
Year Startup
1987
1987/1989
1989/IWI
1991
1991
1992
1992
1995
1995
1995
1994
1994
1994
1995
19%
Target NOj ppin
& % Rcd>
155 ppm/33%
120 ppm/38%
180 ppm/35%
80 ppm/58%
m ppm/67%
80 ppm/58%
95 ppm/25%
75ppm/5I%
80 ppm/67%
80 ppm/67%
80 ppm/50%
m ppm/75%
1 10 ppm/46%
KO ppm/58%
80 ppm/72%
Measured NO
ppm & % Red6-*
30 ppm/87%
93 ppm/02%
40 ppm/64%
../..
•-/--
--/--
-"/--
--/--
--/-•
--/--
• ../.,
•-/-
«/•-.
--/--
-/-
APCD = air pollution control device
DSI = dry sorbent injection
FF = fabric filler
ESP = electrostatic prccipitatur
WS = we,t scrubber
SD = spray dryer
Q = quench chamber
Emissions corrected to 7% O2.
c Measured values are based on performance tests, not
continuous emission monitoring data, and are not
appropriate for setting short-term permit limits.
-------
application designed to achieve a 30% NOX reduction. Testing conducted following
approximately two years of operation found some catalyst deactivation, but performance
recovered to near original conditions following washing.4 Information on other hot-side
SCR systems should become available with the next few years.
43 Key Design and Process Variables
Key SCR design considerations include flue gas composition, flue gas
velocity, catalyst volume and surface area, catalyst temperature, NSR, and outlet NH3
slip concentration.5
Flue gas composition plays a critical role in SCR design and performance.
As discussed in Section 4.1, flue gas composition is the key factor dictating whether a
cold-side or hot-side SCR system is required. Primary concerns are the levels oi
participates, acid gases, and metals in the flue gas. Paniculate matter is critical because
of its erosive effect or the catalyst and its potential for plugging or blinding of the
catalyst surface. Because of these concerns, the maximum allowable paniculate loading
into the catalyst is generally 50 mg/dscm (0.02 gr/dscf).6 The reported paniculate
loading exiting the ESP and entering the hot-side SCR at the Hagenholz MWC in
Zurich, Switzerland is 10 mg/dscm (0.004 gr/dscf).7 By comparison, typical flue gas
paniculate loadings exiting most U.S. MWCs are 2,000 to 6,000 mg/dscm (1 to
3 gr/dscf). As a result, use of a cold-side SCR system or a high-efficiency paniculate
matter control device (e.g., an ESP) upstream of a hot-side SCR system is required.
Acid gases are of significance because of the potential for catalyst
poisoning from ammonia salts such as ammonium chloride (NH4C1), ammonium sulfate
[(NH4)2SOJ, and ammonium bisulfate (NH4HSO4). Depending on the concentration of
NH3, HC1, and SO3 present in the flue gas, these salts can condense on and deactivate
the catalyst surface at temperatures of 200-350°C (400-660°F) and lower.8'9 Catalysts can
also be deactivated by various metals, including Pb, As, P, and various alkali metals. In
general, the greater the basicity of the metal oxide, the greater the deactivation rate.
sdg/nrcl
sect-4.ipt 4-6
-------
Addition of WO3 to the catalyst significantly reduces the rate of deactivation from both
acid gases and metals.
Gas velocity is significant in SCR design because of the erosion potential
from paniculate matter and because of the impact of velocity on gas residence time
within the catalyst. Gas residence time is typically referred to as "gas hourly space
velocity" [defined as the standard volumetric gas flow rate (ai 20°C [68°F]) divided by the
catalyst volume, vol/hr-r vol = hr"1] or "area velocity" [the standard volumetric gas flow
rate divided by the total surface area of the catalyst exposed to the gas flow, vol/hr -r
area = m-hr'1 (ft-hr'1)]. In addition to residence time, these two parameters also reflect
the configuration of the reactcr and catalyst. In general, NOX reduction increases as
space velocity and/or area velocity decrease (i.e., catalyst volume and surface area
increase). However, as catalyst volume and surface area increase, pressure drop also
generally increases due to limitations in cross-sectional area. Most systems have a limit
on the allowable pressure drop (usually on the order of 20 to 25 centimeters [8 to
10 inches] water for MWCs). Based on vendor data, NOX reductions on the order of
80% can be achieved on MWCs with space velocities ranging from approximately 4,000
to 6,000 hr'1, while keeping NH3 slip below 10 ppm.
Figure 4-2 illustrates the impact of temperature on NOX reduction. All
SCR catalysts have design operating temperatures for producing the maximum NOX
reduction. Below this temperature range, NH3 slip increases and NOX removal
decreases. Above this range, NH3 oxidation to NOX increases. For cold-side SCR
systems, the catalyst operating temperature is critical because it defines the amount of
flue gas reheat required. At several Japanese and European MWCs producing steam for
district heating purposes, steam is used for flue gas reheat. In these applications, the
flue gas reheat temperature is 180 to 210°C (360 to 410°F). To minimize catalyst
poisoning at these temperatures, target SOX levels are less than 5 ppm.6 At MWCs
generating electricity (as is common in the U.S.), use of steam for flue gas reheat may
not be feasible. In these situations, auxiliary fuel is generally fired directly into the flue
gas to provide the needed temperature increase. For this type of application, an
sect-4.rpt
4- /
-------
Increased
NH,Slip
Increased
_^. Reagent
Conversion
toNOx
c
o
o
U
X
o
Z
Desired
Operating
Window
Temperature
Figure 4-2. Effect of Temperature OD SCR Performance
«Sg/nrtl
sect-4-rpt
4-8
-------
operating temperature of 250 to 290°C (480 to 550°F) is typically used to provide longer
catalyst lifetimes.
SCR systems are generally designed to maintain near theoretical
stoichiometric performance (1 mole NH3 per mole NOX reduced) up to approximately 70
or 80% reduction. At these reductions, the fractional NOX reduction equals the NSR,
Because of incomplete mixing and secondary reactions, however, somewhat higher NH3
levels must be injected to achieve higher NOX reductions. At NOX reductions near 90%
and higher, the higher required NSR ratio results in incomplete use of NH3 and, thus,
increased NHj slip. To reduce NH3 slip at these high NOX reduction rates, additional
catalyst is needed.
4.4 Recent Advances and Further .Research Needs
Because of catalyst poisoning concerns, most MWC SCR systems have
been installed downstream of the paniculate and acid gas control systems. Because the
outlet temperatures from these systems are typically 50 to 150°C (90 to 270°F) below the
operating range for the catalysts, flue gas reheat has been required. As discussed in
Section 4.5, flue gas reheat can have a significant impact on NOX control costs. As a
result, significant research has been conducted by catalyst manufacturers to develop
catalyst formulations that are tolerant to common poisons. As discussed in Section 4.2,
several hot-side SCR systems have been installed in Europe and Japan since 1992 which
should provide information needed for assessing catalyst performance and lifetimes of
these systems. The economic tradeoffs of hot-stds versus cold-side SCR systems are
discussed in Section 4.5.
sdg/nrcl
tect-4.rpt 4-9
-------
45 Cost Analysis
4.5.1 Design Basis
The design basis assumes a cold-side SCR system, a NOX reduction level of
80%, and an NSR of 0.84. The 80% reduction represents long-term (annual average)
performance capabilities. Performance at individual plants will vary, and this average
performance level may not be achievable at all plants, especially considering retrofit
situations. The space velocity at the 80% reduction level is 4,400 hr'1, and the expected
NH3 slip is 8 ppm. The catalyst operates at a temperature of 290°C (550°F) and has a
catalyst life of 3 years. Reheat of the flue gas from 260°C (500°F) to 290°C (550°F) is
required. Based on the 80% NOX redaction and a typical uncontrolled NOX
concentration of 250 ppm at 7% O2, the average stack concentration associated with this
system is 50 ppm at 7% O2.
452 Cost Results
Cost estimates for the SCR system were developed for 100, 400, and
750 tpd model combustors.2"3 The system-specific input and output values for the 400 tpd
model combustor are shown in Tables 4-3 and 4-4. Additional inputs (e.g., labor rates,
fuel price) are presented in Table A-3 of Appendix A.
Table 4-5 presents the estimated capital cost per ton of capacity, tipping
fee impact, and NOX control cost effectiveness for the SCR system applied to the three
model combustors. In addition to the costs for a 80% NOX reduction, costs are also
presented for a 70% and a 90% NOX reduction, which represents the expected range of
performance considering the control technology and plant-to-plant performance
variations. The NSR associated with these levels of reduction are 0.74 and 0.94,
respectively. As shown in Table 4-5, capital costs, tipping fee impacts, and NOX control
cost effectiveness values increase with decreasing combustor size. Within a given
combustor ran^e, variations in NOX reduction level have less of an impact on costs. For
tdg/BJCl
iec«-4.rpt 4-10
-------
Table 4-3
Model Combustor Inputs for SCR
Plant Characteristics
Unit Size (tpd) 400
Flowrate (dscfm @ 7% O2) 41,271
Flowrate (wscfm @ 11 % O2) 70,462
Capacity Factor 0.9
Tons/yr of MSW Processed (tons/yr) 131,400
Uncontrolled NOx (ppmv, dry) 250
NOx Removal Efficiency (%/100) 0.80
Outlet NOx (ppmv, dry) 50
Tons of NOx removed (tons/yr) 203
Space Velocity (1/hr) 4,400
Catalyst Volume (ft3) 895
Catalyst Life (yrs) 3
Normalized Stoichiometric Ratio (N/NO) 0.84
Ammonia Injection Rate (Ib/hr) 20
Reheat Fuel (MMBru/hr) 5.9
Capital Recovery Factor (1/yrs) 0.0944
sdg/nrtl
s«ct-J.rpt 4-1 I
-------
Table 4-4
Cost Outputs for SCR Applied to the 400 TPD Model Combustor (a)
Capital Coat Section ($1000)
Flue Gas Handling
-dueling and reactor housing
Ammonia Handling, Storage, and Injection
Instrumentation & Controls
Reheat System
Installation
Total Process Capital ($1000)
Engineering
Contingency
Total Control Cost ($1000)
Pre-ProductioD
Inventory Capital
Initial Catalyst Charge
Total Capital Requirement ($1000)
Total Capital per Capacity ($1000/TPD)
Total Annualized Capital Requirement (SlOOO/yr) (b)
754
53
352
1,209
2,162
4,531
906
1,631
7,069
267
36
958
8,330
20.8
696
Variable O&M Cost Section (SlOOO/yr)
Ammonia Cost
Catalyst Replacement & Disposal
Fuel Cost (Reheat)
Electricity
Total Variable O&M ($1000/yr)
24
365
164
51
604
Fixed O&M Cost Section <$IOOO/yr)
Operating Labor
Maintenance Material
Maintenance Labor
Administrative & Support Labor
Total Fixed O&M (SlOOO/yr)
44
109
72
35
260
Total Cost Section
Total Annualized Cost (SlOOO/yr)
Tipping Fee Impact (S/ton MSW)
Cost Effectiveness (S/ton NOx)
1,560
1 1.9
7,689
sdg/nrel
sect-4.rpt
(a) S/ton can be converted to S/Mg by multiplying by 1.1.
(b) Initial catalyst charge not included in total annualized capital requirement.
4-12
-------
« a
It
Table 4-5
Model Plant Cost Estimates for SCR (a), (b)
NOx Reduction
100 TPD Mass Burn MWC
400 TPD Mass Burn MWC
750 TPD Mass Burn MWC
Total Capital Cost
($1000/TPD capacity)
70
49.7
20.6
14.9
80
49.9
20.8
15.1
90
50.4
21.3
15.6
lipping Fee Impact
($/ton MSW)
70
23.8
11.7
9.35
80
24.0
11.9
9.56
90
24.3"
12.3
9.94
Cost Effectiveness
($/ton NOx)
70
17,588
8,635
6,924
80
15,525
7,689
6,191
90
14,021
7.055
5,723
(a) $/ton can be converted to $/Mg by multiplying by 1.1.
t (b) Based on an 80% NOx reduction.
-------
example, an increase in ammonia injection rate and catalyst volume at the higher NOX
reduction levels results in a small increase in capital cost and tipping fee impact. For
cost effectiveness, the values decrease with increasing NOX reduction, since the increase
in cost of the SCR system associated with the higher NOX reduction is smaller than the
additional amount of NOX removed at the higher NOX reduction levels.
A comparison of the costs for the cold-side SCR system to those for a hot-
side SCR system are presented in Table 4-6. As discussed earlier, hot-side systems
typically follow a PM control device upstream of acid gas controls. Such a system could
be installed on an existing ESP-equipped MWC that is considering acid gas and NOX
control retrofits, if the ESP-controlled PM level is low enough [50 mg/dscm
(0.02 gr/dscf)) and the flue gas temperature is greater than 250°C (480°F).
Table 4-6 presents selected plant characteristics and costs to demonstrate
potential differences between cold-side and hot-side systems. To address uncertainties
regarding the catalyst performance of the hot-side systems, two systems are presented;
one with a catalyst life of 3 years, and one with a catalyst life of 2 years.
As shown in Table 4-6, the process capital for the hot-side systems is 30%
less than for the cold-side system because no reheat system is required. However,
because of the potential for increased catalyst degradation, the hot-side system will
require either more catalyst volume or installation of a high efficiency paniculate matter
control device prior to the SCR inlet. For the example presented, increased catalyst
volume is utilized, and the initial catalyst charge for the hot-side system is assumed to be
twice that for the cold-side system. As a result, the total capital requirements for the
hot-side systems are only 15% less than for the cold-side system. The reason for the
difference between the total capital requirements for the two hot-side systems,
specifically the preproduction costs, is the cost for catalyst replacement and disposal
which factors into the preproduction cost.
sdg/nrel
Mct-».rpt 4-14
-------
Table 4-6
Comparison of Cold- and Hot-side SCR Systems (a)
Plant Characteristics
Unit Size (tpd)
Uncontrolled NOsc (ppmv, dry)
NOx Removal Efficiency (%/IOO)
Space Velocity ( I /hr)
Catalyst Volume (ft3)
Catalyst Life (yrs)
Reheat Fuel (MMBtu/hr)
Cold
400
250
0.80
4,400
895
3
5.9
Hot
400
250
0.80
2,200
1,791
3
0
Hot
400
250
0.80
2,200
1,791
2
0
Capita! Cost Section ($1000)
Total Process Capital ($1000)
Total Control Cost ($1000)
Prc-Production
Inventory Capital
Initial Catalyst Charge
Total Capital Requirement ($1000)
Total Capita! per Capacity ($100Q/TPD)
Tolal Annualized Capital Requirement (SlOOO/yr)
4,5.11
7,069
267
36
958
8,330
20.8
696
3,153
4,973
239
26
1,916
7,154
17.9
494
3,153
4,973
269
26
1,916
7,184
18.0
497
O&M Cost Section ($1000/yr)
Catalyst Replacement & Disposal
Fuel Cost (Reheat)
Others (Ammonia, Electricity)
Total Variable O&M (SlOOO/yr)
Total Fixed O&M ($1000/yr)
365
164
51
604
260
730
0
77
802
198
1,060
0
77
1,132
198
Total Cost Section
Total Annualized Cost ($IOOO/yr)
Tipping Fee Impact ($/ton MSW)
Cost Effectiveness ($/ton NOx)
1460
11.9
7,689
1,495
11.4
7,370
1,827
13.9
9,010
(a) $/ton can be converted to $/Mg by multiplying by I.I.
sdg/nrel
seci-4.rpt
4-15
-------
The catalyst replacement and disposal cost takes into account the amount
of catalyst that must be disposed (proportional to the catalyst volume) and the life of the
catalyst. Therefore, the cost for the hot-side systems is greater than for the cold-side
system, especially for the hot-side system with the 2-year catalyst life. As a result of the
catalyst replacement and disposal cost, the variable O&M costs for these systems may be
higher than cold-side systems, even though the hot-side systems do not require reheat
(no fuel cost incurred). Fixed O&M costs for the hot-side systems are slightly lower than
for the cold-side system because of the lower process capital associated with the hot-side
systems.
Overall, the total annualized costs, tipping fee impact, and cost
effectiveness for the cold-side system fall between the costs for the hot-side systems. As
shown, the shorter catalyst life results in higher costs. More information on the
long-term effects of flue gas properties on catalyst degradation and poisoning is needed
to fully evaluate the economics of a hot-side system.
4.53 Sensitivity Analysis
To account for site-specific differences and other uncertainties in the costs
used to develop Table 4-5, an analysis of the sensitivity of tipping fee impacts and NOX
control cost effectiveness to differences in plant size (100 to 700 tpd), catalyst
replacement cost (±50%), annualized capital cost (±30%), and NOX reduction (70 to
90%) was performed. Figure 4-3 presents the effect of plant size, catalyst replacement
cost, and annualized capital cost on tipping fee and cost effectiveness. Figure 4-4
presents the sensitivity of tipping fee and cost effectiveness to NOX reduction.
The range in annualized capital cost accounts for differences in the actual
capital cost of an SCR system, contingency factors, and the cost of money used for
project financing. The variation in NOX control cost effectiveness reflects the impact of
varying the amount of ammonia injection to achieve higher or lower NOX reductions.
sdg/nrel
sect-4.rpt
-------
5 E
h
•a a
Uoil Siie <«pd)
•C.R. Co»l ($IOOO/yr)
Anouilizr-d Capital (JlOOO/yr)
Reference MWC Parameters
uncontrolled NOx • 250 ppm
NOx Reduction - 83%
* = C«t«lyil Repltcemrnt
-X- Uiiil S'atf
Cal>l;«t
l Cod
A«*«*lizni Capital
Figure 4-3. Effect of Unit Size, Catalyst Replacement Cost, and
Annualized Capital on Tipping Fee Impact and Cost Effectiveness for SCR
-------
If
•3 5.
*..
oo
26-
24-
22-
10-
8-
NOx Reduction (%) 70
Reference MWC Parameters
Unit Size - 400 tpd
Catalyst Replacement Cost = $365,000
Annualized Capital » $696,000/yr
16.8
hi 5.5
7}
—p..
77
1—
80
-6.5
5.2
87
90
*^K* Tipptug Fet Impact E3 Cost Effrctivrurss
Figure 4-4. Effect of NOx Reduction on Tippng Fee Impact and
Cost Effectiveness for SCR
-------
As shown in these figures, the tipping fee impact and NOX control cost
effectiveness associated with the reference MWC (the centerline point) are
approximately Sl2/ton of MSW and S7,690/ton of NOX removed. Of the parameters
shown in Figures 4-3 and 4-4, the variation in unit size has the greatest impact on tipping
fee and cost effectiveness. The costs increase with decreasing unit size, with the cost for
units between 100 to 300 tpd showing the steepest increase. From the reference unit size
of 400 tpd to the 100 tpd unit, tipping fee impact and the cost effectiveness value roughly
double. The costs decrease by less than 20% when going from the 400 tpd unit to the
700 tpd unit.
Variations in catalyst replacement cost of ±50% and annualized capital
costs by ±30% have practically the same effect on tipping fee impact and cost
effectiveness. Increases in catalyst replacement cost and annualized capital cost increase
the tipping fee impact and the cost effectiveness value. Variations in NOX reduction
have a similar but opposite impact on cost effectiveness, with increases in NOX reduction
resulting in a decrease in the cost effectiveness value. The effect of NOX reduction on
tipping fee impact is smaller, with increases in NOX reduction resulting in a slight
increase in the tipping fee impact.
4.6 References
1. U. S. Environmental Protection Agency. Municipal Waste Combustors--
Background Information for Proposed Standards: Control of NOX Emissions,
Vol. 4, EPA-450/3-89-27d (NTIS PB90-154873). Research Triangle
Park. NC. August 1S89.
2. FAX from M. Tomiku, Mitsubishi International Corporation, to D. White,
Radian Corporation. SCR Study for Weste to Energy Plant. October 5, 1993
and February 11, 1994.
3. FAX from V. Patel, Joy Environmental Technologies, to D. White, Radian
Corporation. SCR for MSW Plants. October 6, 1993.
4. California Environmental Protection Agency. Aii Resources Board. Air
Pollution Control at Resources Recovery Facilities-1991 Update.
sdg/nrcl
seci-4 rpi 4-19
-------
5. Becker, E. R. Selective Catalytic Reduction of NOx-Catalysis and Reactor
Design. Environmental Catalyst Consultants Short Course. Presented
May 8-10, 1990. Boston, MA.
6. FAX from M. Tomiku, Mitsubishi International Corporation, to D. White,
Radian Corporation. MWC SCR Data. December 13, 1993.
7. FAX from H. Meier, Abfuhrwesen Zurich, to D. White, Radian Corporation.
Municipal waste combustor plants Hagenholz and Josefstrasse. February 23,
1994.
8. Technical and Economic Feasibility of Ammonia-Based Postcombustion NOX
Control. Electric Power Research Institute. EPRI CS-2713.
9. Chen, J., R.T. Yang, and J.E. Cichanowicz, Poisoning of SCR Catalysts. In
Proceedings: 1991 Joint Symposium on Stationary Combustion NOX Control,
Vol. 2, EPA-600/R-92-093b (NTIS PB93-212850), July 1992.
sdg/nrcl
scct-4.rpt 4-2U
-------
APPENDIX A
Description of Costing Framework
A.1 Inputs
The NOX control costs for NGI, SNCR, and SCR are dependent on a
number of parameters including plant unit size (tpd and flue gas flowrates), fuel or
chemical costs, and economic assumptions. Table A-l presents the inputs (e.g., O2 level,
higher heating value) needed for calculating the flue gas flowrates of the model plants.
The tlowrates were calculated using EPA Method 19. For the purpose of sizing and
costing equipment, the flowrates were multiplied by a factor of 1.15 to account for
variability of short-term flowrates relative to design flowrates. Tables A-2, A-3, and A-4,
present the additional inputs (e.g., costs of chemicals) needed to calculate the outputs for
NGI, SNCR, and SCR, respectively.
A.2 Methodology
The basic methodology used to determined NOX control cost and cost
effectiveness is described in this section.
AJ2.1 Capital Costs
AJ2.1.1 Total Process Capital
Total process capital (TPC) includes equipment and installation costs and
is technology dependent. The equipment required and associated installation costs are
discussed in the individual sections of the report for each technology.
$dg/2S6,nrel
appcnd~a
-------
Table A-1
Generic Inputs For Flowrate Calculations
Parameter
Corrected O2
Actual O2
Higher Heating Value
H20, exhaust
Units
(%/100)
(%/100)
(Btu/lb)
(%/100)
Input
0.07
0.11
4,500
0.18
sdg/Z56.nrel
append-a
A-2
-------
Table A-2
Generic Inputs For NGI
Parameter
Density of Air
Specific Heat of Air
Energy per ton Constant
Compressor Demand
Fuel Cost (NG)
Electrical Cost
City Water
Labor Rate
Operating Labor
Discount Rate
Book Life
Maintenance
Admin & Support
Process Contingency
Project Contingency
Units
(Ib/scf)
(Btu/lb F)
(kWh/ton MSW)
(kW/wscfm)
($/MMBtu)
($/kWhr)
($/1000gal)
(S/hr)
(hr/shift)
(%/100)
(yrs)
(%/100)
(%/100)
(%/100)
(%/IOO)
Input
0.075
0.28
550
0.091
3.5
0.046
0.6
20
1.0
0.070
20
0.02
0.3
0.2
0.2
s
-------
Table A-3
Generic Inputs For SNCR
Parameter
Molecular Weight
Weight Ratio
Reagent N content
Dilution Ratio
Density of Air
Specific Heat of Air
Energy per ton Constant
Compressor Demand
Reagent Cost
Electrical Cost
City Water
Labor Rate
Operating Labor
Discount Rate
Book Life
Maintenance
Admin & Support
Process Contingency
Project Contingency
Heat of Reaction
Change in Enthalpy for H2O
Units
(Ib/lb mole)
(Ib solution/lb reagent)
(mol reagent/ mol N)
(Ib reagent/!b inj sol)
(Ib/scf)
(Btu/lb F)
(kWh/ton MSW)
(kW/wscfm)
($/ton)
($/kWhr)
($/ 1000 gal)
($/hr)
(hr/shift)
(%/100)
(yrs)
(%/100)
(%/100)
(%/100)
(%/100)
(Btu/lb)
(Btu/lb)
Input
17
3.4
1
0.1
0.075
0.28
550
0.091
300
0.046
0.6
20
2.0
0.070
20
0.04
0.3
0.1
0.2
-7671
1114.6
sdg/2S6.nrcl
appcnd-a
A-4
-------
Table A-4
Generic Inputs For SCR
Parameter
Molecular Weight
Weight Ratio
Reagent N content
Density cf Air
Specific Heat of Air
Energy p«r ton Constant
Compressor Demand
Chemical Cost (reagent)
Catalyst Cost
Catalyst Startup cost
Fuel Cost
Waste Disposal
Electrical Cost
City Water
Labor Rate
Operating Labor
Discount Rate
Book Life
Maintenance
Admin & Support
Process Contingency
Project Contingency
SCR Temperature
Stack Temperature
Heat Ex. Exit Temperature
Catalyst Pressure Drop
Unite
(Ib/lbmole)
(Ib solution/lb reagent)
(mol reagent/ mol N)
(Ib/scf)
(Btu/lb F)
(kWo/ton MSW)
(kW/wscfm)
(S/ton)
($/ft3)
(J)
(S/MMBTU)
(J/ton)
($/kWhr)
(S/lOOOgal)
($/hr)
(br/shift)
(%/100)
(y«)
(%/lOO)
(%/100)
(%/100)
(%/100)
(F)
(F)
(F)
(in H20)
Input
17
3.4
1
0.075
0.28
550
0.091
300
1,070
60,000
3.5
8.9
0.046
0.6
20
2.0
0.070
20
0.04
0.3
0.1
0.2
550
280
496
8
A-5
-------
A3.A2 Total Control Cost
Total control cost (TCC) includes TPC plus costs for engineering and
contingency. Assumptions used for engineering and contingency are discussed below.
Engineering. Engineering is assumed to be 20% of TPC and includes
engineering home office, overhead, and general facilities.
Contingency. Contingency is comprised of process contingency and project
contingency. Process contingency is calculated as a percentage of TPC. and project
contingency is calculated as a percentage of TPC plus engineering and process
contingency. The percentage assumptions for each NOX control technology are
presented in Tables A-l, A-2, and A-3.
A.2.13 Total Capital Requirement
Total capital requirement (TCR) includes TCC, preproduction costs,
inventory capital, and other technology specific costs such as license fee for SNCR or
initial catalyst charge for SCR. Information on preproduction costs and inventory capital
are provided below.
Preproduction Costs. Preproduction costs cover operator training,
equipment checkout, extra maintenance, and inefficient use of fuel and materials during
start-up. To estimate this, preproduction costs are calculated to be one month fixed
O&M costs, one montli variable O&M costs at full capacity, excluding fuel, 25% of
full-capacity fuel cost for one month (SCR and NGI only), and two percent of TCC.
Inventory Capital. Inventory capital is estimated to be 0.5% of TCC and
the cost of two weeks' inventory of chemicals (SNCR, SCR) or fuel (NGI).
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A.2.1.4 Total Capital Per Capacity
To calculate capital costs in terms of capacity, the TCC is divided by the
unit size of the plant.
A2.13 Total Annualized Capital Requirement
Capital costs are annualized by multiplying TCR by a capital recovery
factor. Equations to calculate the CRF and the annualized costs are shown below.
CRF(l/yr) = i (1 * i)n / ((1 * i)n -1]
where:
i = discount rate (decimal fraction)
n = book life of the loan
A.22 Operating and Maintenance Costs
Operating and maintenance cos's include variable and fixed O&M costs.
A2.2.1 Variable Operating and Maintenance Costs
Variable O&M costs include those O&M costs that are directly
proportional to the amount of time the facility is operating. Examples of variable O&M
costs are chemical, fuel, and electricity costs for a specific control technology.
A.2.2.2 Fixed Operating and Maintenance Costs
Fixed O&M costs include operating labor, maintenance materials,
maintenance labor, and administrative and support labor.
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Costs for operating labor depend on how many hours of labor per shift are
required for each technology and the labor rate. Tables A-l, A-2, and A-3 nclude the
inputs for these for each technology.
Total maintenance costs (materials and labor) are calculated based on a
percentage of TPC. The assumed percentage for each technology are included in
Tables A-l, A-2, and A-3. These costs are broken into the specific components
(materials and labor) based on a 60/40 breakout (60% attributable to materials and 40%
attributable to labor).
Overhead charges are assumed to be the cost for administrative and
support labor. This cost is taken as 30% of the O&M labor. General and administrative
expenses are not included, because they will be site specific, dependent on management
philosophy.
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