TO:	Bob Lucas, EPA/SPPD

FROM:	Jeff Coburn

DATE:	April 30, 2007

SUBJECT:	Documentation of NOx Control Cost Estimates

I.	Purpose

This memorandum documents the methodology used to estimate costs to
control nitrogen oxides (NOx) for the fluid catalytic cracking unit
(FCCU), the fluid coking unit, and process heaters. 

II.	NOx Controls

The following NOx control techniques were considered:

Flue Gas Recirculation.  Flue gas recirculation (FGR) uses flue gas as
an inert material to reduce flame temperatures.  In a typical flue gas
recirculation system, flue gas is collected from the heater or stack and
returned to the burner via a duct and blower.  The addition of flue gas
with the combustion air reduces the oxygen content of the inlet air
stream to the burner.  The lower oxygen level in the combustion zone
reduces flame temperatures, which in turn reduces NOx emissions.  The
normal NOx control efficiency range for FGR is 30 percent to 50 percent.
 When coupled with low-NOx burners (LNB) the control efficiency
increases to 50-72 percent. 

Low-NOx Burners.  Low-NOx burner (LNB) technology utilizes advanced
burner design to reduce NOx formation through the restriction of oxygen,
flame temperature, and/or residence time.  The two general types of low
NOx burners are staged fuel and staged air burners.  Staged fuel LNBs
are particularly well-suited for boilers and process heaters burning
process and natural gas, which generate higher thermal NOx.  The
estimated NOx control efficiency for LNBs where applied to petroleum
refining fuel burning equipment is generally around 40 percent.

Ultra-low NOx Burners.  Ultra-low NOx burners (ULNBs) may incorporate a
variety of techniques including induced flue gas recirculation (IFGR),
steam injection, or a combination of techniques.  These burners combine
the benefits of flue gas recirculation and low-NOx burner control
technologies.  Rather than a system of fans and blowers (like FGR), the
burner is designed to recirculate hot, oxygen-depleted flue gas from the
flame or firebox back into the combustion zone.  This leads to a
reduction in the average oxygen concentration in the flame without
reducing the flame temperature below temperatures necessary for optimal
combustion efficiency.  The estimated NOx control efficiency for ULNBs
in high temperature applications is 50 percent.  Newer designs have
yielded efficiencies of between 75 and 85 percent.  When coupled with
selective catalytic reduction, efficiencies in the range of 85 to 97
percent can be obtained.

Controlling Excess Oxygen in Complete Combustion FCCU Catalyst
Regenerators.  Most of the previous control options are specific to
process heaters and carbon monoxide (CO) boilers.  However, controlling
the oxygen concentration in the FCCU regenerator exhaust at
approximately 0.5 percent has been seen to reduce NOx concentrations by
20 to 40 percent as compared to NOx concentrations when the regenerator
exhaust oxygen concentration is between 1 and 2 percent.  As such,
complete combustion FCCU regenerators with active excess oxygen controls
are expected to have similar performance as partial combustion FCCUs
followed by CO boilers that use low-NOx burners or flue gas
recirculation. 

Selective Non-Catalytic Reduction.  In the selective non-catalytic
reduction (SNCR) process, urea or ammonia-based chemicals are injected
into the flue gas stream to convert nitric oxide (NO) to nitrogen gas
(N2) and water.  Without the participation of a catalyst, the reaction
requires a high temperature range to obtain activation energy.  The
optimum operating temperature for SNCR is 1,600 °F to 2,100 °F.  At
temperatures above 2,000 °F, NOx control efficiency decreases rapidly. 
The normal NOx control efficiency range for SNCR is 50 percent to 70
percent.  SNCR systems are usually lower in capital cost than SCR
systems for the same application.  One advantage of this technology is
the fact that no liquid or solid waste is generated.  SNCR technology
has been applied to CO boilers, process heaters and boilers in the
petroleum refining sector where control efficiencies are consistent with
the range mentioned above. 

LoTOxTM Technology.  The LoTOxTM process (i.e., low-temperature
oxidation) is a patented technology that uses ozone to oxidize NOx to
nitric pentoxide and other higher order nitrogen oxides, all of which
are water soluble and easily removed from exhaust gas in a wet scrubber.
 The system operates optimally at temperatures below 300°F.  Thus,
ozone is injected after scrubber inlet quench nozzles and before the
first level of scrubbing nozzles.  Outlet NOx emission levels have been
reduced to less than 20 parts per million by volume (ppmv), and often as
low as 10 ppmv, when inlet NOx concentrations ranged from 50 to 200 ppmv
(an 80 to 90 percent reduction efficiency). 

Selective Catalytic Reduction.  Selective catalytic reduction (SCR) is a
post-combustion NOx control technology in which ammonia (NH3) is
injected into the post-combustion gas stream in the presence of a
catalyst.  A catalyst bed containing metals in the platinum family is
used to lower the activation energy required for NOx decomposition.  The
reaction of NH3 and NOx is favored by the presence of excess oxygen. 
The NH3 oxidation to NOx increases with increasing temperature.  The
normal NOx control efficiency range for SCR is 70 to 90 percent.  There
are at least three SCRs currently in-use at refineries to control FCCU
NOx emissions.

Combination System.  Combination systems have used combustion controls
followed by SCR or SNCR technology in order to reduce costs of NOx
removal from a flue gas.  For example, LNB has been combined with SNCR
technology to minimize the capital and operating cost for NOx removal as
well as improve the control efficiency.  

Catalyst Additives.  An additional NOx emission control option specific
for the FCCU is the use of catalyst additive, such as X-NOX and DENOX
(from Grace-Davison; Bruhin, et al. 2003).  Non-platinum combustion
promoter additives appear to achieve a 30 to 50 percent emission
reduction.  Additional catalyst additives have had limited success at
further reducing the NOx emissions from the FCCU, and the results of
these other additives have been quite varied.

Not all of these control technologies are applicable to all units.  For
example, use of catalyst additives is applicable only to FCCUs, while
the use of low-NOx burners are not applicable to complete combustion
FCCU catalyst regenerators.  For each source type, costs for four
control scenarios were developed in 2005 dollars; the control scenarios
ranged between 35 percent and 95% NOx emission reduction efficiencies. 
As the baseline emissions of different FCCUs can span a fairly
significant range of outlet NOx concentrations, representative baseline
concentrations were assigned a weighting factor to simulate the
distribution of baseline NOx emissions.  For each representative
baseline NOx concentration, the control scenario needed to achieve a
given emission limit was assigned to the fraction of FCCUs represented
by that concentration.  The overall costs for a given scenario were then
calculated based on the weighting attributed to that uncontrolled NOx
concentration range.  Although this basic approach was used for each NOx
emission source type, the specific costing methodologies for each of the
three types of sources are presented in separate sections to clearly
identify the differences in the costs developed for the different
sources.

III.	Cost Estimates of FCCU NOx Control Systems

Control costs were developed for a model 50,000 barrel per day (bbl/d)
capacity FCCU with an estimated flow rate of 140,000 standard cubic feet
per minute (scfm).  Four control scenarios were evaluated:

Scenario 1:  a 35 percent reduction based on simply controlling the
amount of excess oxygen used in either the FCCU catalyst regenerator of
the CO boiler.

Scenario 2:  a 50 percent reduction based on:

Limiting excess oxygen and using non-platinum oxidation promoters in
complete combustion FCCU regenerators

Limiting excess oxygen and using low-NOx or ultra low-NOx burners in
FCCU equipped with CO boilers

Scenario 3:  a 90 percent reduction based on application of LoTOxTM or
SCR control system. 

Scenario 4:  a 95 percent reduction based on application of high
efficiency SCR control system 

Scenario 1.  For the most part, Scenario 1 is not expected to require
additional equipment and may have little to no actual impact on the
operational costs.  From information collected during site visits to
refineries and from consent decree evaluation reports submitted to EPA,
a 35 percent NOx reduction is achievable by controlling combustion
conditions, primarily the excess oxygen content.  Although all new FCCUs
are expected to have fully automated control, a capital cost of $20,000
and an annual operating cost of $4,000 per year were used to estimate
the costs of upgrading the computerized combustion control system. 
These costs were annualized over 5 years, so the annualized cost for
Scenario 1 was estimated to be $8,900 per year.

Scenario 2.  Two control options were evaluated for this scenario. 
Based on data reviewed from consent decree evaluation reports, complete
combustion FCCUs are expected to be able to reduce NOx emissions by 50
percent by controlling excess oxygen levels and replacing the platinum
combustion promoter with a non-platinum combustion promoter designed to
reduce NOx formation.  These costs include the costs of Scenario 1, plus
the additional cost of the non-platinum combustion promoter as compared
to the traditional platinum combustion promoter.  For the model FCCU,
the added combustion promoter cost was estimated to be $295,000 per
year.  Combined with enhanced combustion controls, the total annualized
cost of this option was $305,000 per year.

Capital costs for low-NOx burners were reported by MACTEC (2005) for gas
boilers as ranging from $430,000 to $5.5 million, while the capital
costs for low-NOx burners were reported to be $2.1 million.  From these
estimates, a capital cost of $2.1 million was selected for this option. 
The operating costs reported by MACTEC (2005) were $90,000 per year
based on operating and maintenance labor; the ultra low-NOx burners also
have compressed air costs.  While the labor costs may be associated with
the boiler operation, it seems unlikely that these costs would be
additional to the costs of operating the boiler without the low-NOx
burners.  However, given that the low NOx burners operate at lower
temperatures, it does seem reasonable that there may be an impact on
combustion efficiency or steam production when using the low NOx
burners.  As such, this $90,000 per year operating cost was used. 
Combined with enhanced combustion controls, the total annualized cost of
this option was just under $300,000 per year.  

Since the MACTEC report dealt primarily with retrofit technologies, it
is likely that the capital costs reported are specific to retrofits and
that the incremental capital cost for new construction would be
substantially less as indicated by the costs reported by ERG (2001) for
new process heaters.  On the other hand, refineries that use complete
combustion FCCU regenerators do not have the option of installing
low-NOx burners.  Therefore, even though the annualized costs of
applying low NOx burners is likely overstated, the annualized costs
determined for these options were very similar, and an average of the
two option costs was used as the costs for Scenario 2.

Scenario 3.  As with Scenario 2, two control options were evaluated for
this scenario.  Costs for a 90 percent efficient LoTOxTM system were
based on preliminary costs provided by Belco Technologies Corporation
(Hutter and Confuorto, 2006).  The additional capital cost for the
LoTOxTM system when added to a new wet scrubber control system was
estimated to be $6 million, with an annual operating cost of
approximately $1.6 million.  Costs for an SCR system were estimated
based on the costs developed by MACTEC (2005) for gas boilers.  Reported
capital costs ranged from $2 million to $17 million; a mid-range value
of $10 million was selected.  The operating costs are dominated by
electricity and catalyst replacement costs.  The annual operating costs
were adjusted based on the selected capital cost (insurance and taxes)
and on a 5-year catalyst replacement frequency to develop an annual
operating cost of approximately $1.4 million.  The electricity costs
were not altered even though the model boiler exhaust flow rate for
which MACTEC developed costs was larger than the model FCCU exhaust flow
rate.  As such, the annual operating costs are still expected to be
conservative, or at least reasonable, even if catalyst life of less than
5 years is realized.  For these two options, the total annualized costs
were estimated to be $2.1 to $2.3 million.  As the annualized costs for
these options were so similar, these costs were averaged to develop the
control costs for Scenario 3. 

Scenario 4.  Costs for Scenario 4 were assumed to be 30 percent higher
than the costs for Scenario 3. 

Additional Costs Associated with Existing Unit Retrofits due to
Modification or Reconstruction.  No additional retrofit costs were
attributed to Scenario 1.  A capital cost retrofit factor of 1.35 was
applied to escalate the capital costs of Scenarios 2 through 4 to
account for additional costs associated with applying the controls to an
existing unit.  For example, adding a LoTOxTM system to a unit with an
existing wet scrubber requires some modification of the existing
scrubber system, which adds cost to the control system retrofit.  The
application of this retrofit factor may be dubious for Scenario 2, as
these costs are arguably already applicable to retrofits, but it was
applied to insure the retrofit costs were not understated.

Monitoring, Recordkeeping, and Reporting Costs.  In addition to the
control system cost, an initial performance evaluation and continuous
NOx monitoring is required.  The monitor must be maintained and
calibrated, and the data must be recorded and emission exceedances
periodically reported.  To account for these costs, an initial cost of
$130,000 and annual operating costs of $21,000 per year were added to
the control costs outlined above.  

Summary of FCCU NOx Control Scenario Costs.  Table 1 summarizes the
fully burdened NOx control costs for new, modified, and reconstructed
FCCUs.  For completion, Scenario 0 was defined for FCCUs capable of
meeting a given regulatory alternative with no change in operation.  The
costs for this scenario are solely the costs associated with monitoring,
recordkeeping, and reporting.

Table 1.  Summary of Scenario Costs for FCCU NOx Controls

Scenario	New  Construction	Modified or Reconstructed

	Capital Cost

($1,000)	Annual Operating Cost ($1,000/yr)	Total Annualized Cost
($1,000/yr)	Capital Cost

($1,000)	Annual Operating Cost ($1,000/yr)	Total Annualized Cost
($1,000/yr)

0	 $ 130 	 $ 21 	 $ 40 	 $ 130 	 $ 21 	 $ 40 

1	 $ 150 	 $ 25 	 $ 49 	 $ 203 	 $ 27 	 $ 76 

2	 $ 1,210 	 $ 219 	 $ 333 	 $ 1,630	 $ 236 	 $ 390 

3	 $ 8,130 	$ 1,500 	$ 2,270	$ 11,000 	 $ 1,610 	 $ 2,650 

4	 $ 10,600	$ 1,650 	$ 2,650 	$ 14,300 	 $ 1,800 	 $ 3,140 



Estimation of FCCU NOx Emissions and Emissions Reductions.

Currently, subpart J does not have any NOx emission limits for FCCUs. 
Therefore, the baseline emissions for newly construcetd sources are
assumed to be uncontrolled NOx emissions.  Uncontrolled NOx emissions
are assumed to range between 50 ppmv and 300 ppmv, with a median value
of between 100 and 150 ppmv.  Numerous existing FCCUs are subject to
consent decrees that do impose NOx concentration limits on the FCCU
emissions.  Therefore, some of the existing FCCUs have installed NOx
controls, and the distribution of NOx concentrations at existing units
(those that will be modified or reconstructed) are skewed towards lower
concentrations than the newly constructed units.  Table 2 presents the
representative concentrations used in the baseline analysis and the
fraction of affected units that are represented by that concentration
for new construction and for modified and reconstructed units.

Table 2.  Summary of Representative Baseline NOx Emissions for New,
Modified, and Reconstructed FCCUs

Representative

Average NOx

Concentration

(ppmv)	Annual NOx Emissions  for Model FCCU at Average Concentration
(tons/yr)	Fraction of Newly Constructed Units Represented by Average NOx
Concentration	Fraction of Modified or Reconstructed Units Represented by
Average NOx Concentration

20	88	0	0.05

30	132	0	0.1

40	176	0	0.1

50	220	0.05	0.1

60	264	0.05	0.1

80	352	0.15	0.1

100	439	0.2	0.15

150	659	0.25	0.15

200	879	0.15	0.05

250	1,099	0.1	0.05

300	1,318	0.05	0.05



For the nationwide impact estimates, it was assumed that 15 new
refineries’ worth of processes would be new, modified, or
reconstructed over the next 5 years.  Based on the number of FCCUs
compared to the number of refineries in the U.S., there would be 12
affected FCCUs.  It was assumed that 40 percent of the affected units
would be new construction and 60 percent of the affected units would
become new due to modification or reconstruction.  Based on the assumed
number and distribution of these units, the nationwide impacts of
imposing different NOx concentration emission limits were estimated. 
The results of these calculations are provided in Table 3.



Table 3.  Summary of Nationwide Impacts of Various NOx Regulatory
Alternatives for FCCUs

Regulatory Alternative NOx Emission Limit (ppmv)	Total Capital
Investment  (million $)	Annual Operating Costs  (million $/yr)	Total
Annualized Costs  (million $/yr)	NOx Emission Reduction from Baseline

(tons/yr)

Nationwide Costs for Newly Constructed Units

80	                   13.5 	                     2.5 	                  
  3.8 	                 1,870 

60	                   22.8 	                     4.2 	                  
  6.4 	                 2,340 

40	                   32.0 	                     5.7 	                  
  8.7 	                 2,630 

20	                   42.5 	                     7.4 	                  
11.4 	                 2,830 

Nationwide Costs for Modified or Reconstructed Units

80	                   14.4 	                     2.1 	                  
  3.5 	                 1,590 

60	                   26.0 	                     3.8 	                  
  6.3 	                 2,030 

40	                   48.4 	                     6.9 	                  
11.5 	                 2,520 

20	                   78.7 	                   11.2 	                  
18.7 	                 2,940 

Nationwide Costs for all New, Modified, and Reconstructed Units

80	                   27.8 	                     4.6 	                  
  7.3 	                 3,460 

60	                   48.8 	                     8.0 	                  
12.7 	                 4,380 

40	                   80.4 	                   12.6 	                  
20.2 	                 5,150 

20	                 121.2 	                   18.6 	                  
30.1 	                 5,760 



IV.	Cost Estimates of Fluid Coking Unit NOx Control Systems

NOx control costs were developed for a model 40,000 bbl/d capacity fluid
coking unit.  The unit is assumed to have a CO boiler and an estimated
exhaust flow rate of 200,000 scfm.  The same four control scenarios as
developed for the FCCU were used for the fluid coking unit except that
Scenario 2 was based solely on low-NOx burners in the CO boiler.  As
many of the FCCU NOx control costs were developed from gas boilers
slightly larger than the model fluid coking unit CO boiler, no other
changes in the FCCU cost estimates were made (MACTEC, 2005).  

Most new coking units are expected to be delayed coking units.  Only one
affected fluid coking unit was projected in the first 5 years; this
fluid coking unit is assumed to become subject to the rule due to
modification or reconstruction.  As such, only the costs for retrofit
NOx controls apply.  

Currently, subpart J does not have any NOx emission limits for fluid
coking units.  Therefore, the baseline emissions for fluid coking units
are assumed to be uncontrolled NOx emissions.  Similar to the FCCU
analysis, a range of representative baseline concentration were assumed.
 Table 4 presents the assumed distribution of baseline NOx emissions for
fluid coking units. 

Table 4.  Summary of Representative Baseline NOx Emissions for Fluid
Coking Units

Representative

Average NOx

Concentration (ppmv)	Annual NOx Emissions  for Model Fluid Coking Unit
at Average Concentration (tons/yr)	Fraction of Fluid Coking Units
Represented by Average NOx Concentration

80	502	0.1

100	628	0.2

150	942	0.2

200	1,256	0.2

250	1,570	0.2

300	1,884	0.1



As with the FCCU analysis, different regulatory alternatives were
evaluated.  For each regulatory alternative, the control scenario needed
at each representative baseline concentration was determined.  Even
though only one fluid coking unit was expected to be impacted, a
distributional analysis of representative baseline NOx concentrations
was still used to develop the most representative average impacts for
fluid coking units.  Table 5 summarizes the nationwide impacts for the
NOx regulatory alternatives considered for fluid coking units.

Table 5.  Summary of Nationwide Impacts of Various NOx Regulatory
Alternatives for Fluid Coking Units

Regulatory Alternative NOx Emission Limit (ppmv)	Total Capital
Investment  (million $)	Annual Operating Costs  (million $/yr)	Total
Annualized Costs  (million $/yr)	NOx Emission Reduction from Baseline

(tons/yr)

80	            4.50 	            0.54 	            0.97 	            
760 

60	            6.66 	            0.86 	            1.49 	            
884 

40	            9.54 	            1.22 	            2.12 	            
978 

20	            12.6 	            1.70 	            2.90 	          1,043




V.	Cost Estimates of Process Heater NOx Control Systems

The NOx control scenarios considered for process heaters were similar to
those used for FCCUs with the following differences:

 

Scenario 2 was modified to be an 80 percent NOx emission reduction
using ultra low-NOx burners.  The effectiveness of ultra low-NOx burners
for process heaters is well-demonstrated, much more so than for FCCUs
and fluid coking unit CO boilers where the majority of the heating value
is in the exhaust gas rather than in the fuel fired to the boiler. 
Therefore, the Scenario 2 was assigned 80 percent control efficiency,
and the control costs were revised for ultra low-NOx burners based on
the costs reported by MACTEC (2005) for gas-fired boilers.  As discussed
in the FCCU section, these costs do not appear to be incremental costs,
especially for newly constructed units, but these costs were used as a
worst-case scenario for the ultra low-NOx burner costs.  

Costs for Scenario 3 and 4 were revised to be based solely on the use of
an SCR.

For process heaters, there are a greater number of affected sources
covering a much wider range of sizes than for the FCCU.  Therefore, the
cost estimates developed previously for the were not applicable without
some algorithm for adjusting the costs for size.  As a first step, the
size and number of process heaters at a model plant refinery with a
50,000 barrel per calendar day (bbl/cd) FCCU was assessed.  Process
heater capacities for the processes were estimated based on process
heater fuel gas use rates developed for the refinery emission model
(RTI, 2002).  Table 6 summarizes the process heater sizes in millions of
British thermal units per hour (MMBtu/hr) and the number of process
heaters of each size, assuming 15 refineries’ worth of processes
become subject to the rule over the next 5 years.

The costs developed for each scenario were broken into “fixed costs”
and costs that vary with the size of the process heater.  For example,
the cost of operating the NOx monitor was considered “fixed” because
it was independent of the size of the process heater.  The capital costs
that vary with process heater size were assumed to vary according to
Equation 1; the operating costs that vary with process heater size were
assumed to vary in direct proportion to the process heater size.  

 	Equation 1

 Where,

	VCIPH,i = 	variable capital investment for the ith process heater, $

	VCIPH,i = 	variable capital investment for the model process heater for
which costs were developed, $

	QPH,i =	volumetric flow rate of the ith process heater, scfm

	QMP =	volumetric flow rate of the model process heater for which costs
were developed, scfm

Subpart J does not have any requirements for NOx control from process
heaters.  The assumed baseline distribution of NOx emission
concentrations for process heaters is presented in Table 7.  The actual
annual mass emissions are dependent on the size of the process heater
being assessed.

Various regulatory alternatives were evaluated by assigning the
appropriate control scenario to each representative baseline
concentration in the same manner as with the FCCUs.  As the
cost-effectiveness of applying controls to smaller process heaters was
not as good as for larger process heaters, a variety of size thresholds
were also considered.  The following four regulatory alternatives were
considered:

Option 1.  80 ppmv NOx concentration limit applied to all process
heaters with a capacity greater than 20 MMBtu/hr.

Option 2.  40 ppmv NOx concentration limit applied to all process
heaters with a capacity greater than 20 MMBtu/hr.

Option 3.  30 ppmv NOx concentration limit applied to all process
heaters with a capacity greater than 40 MMBtu/hr.

Option 4.  40 ppmv NOx concentration limit applied to process heaters
with a capacity greater than 20 MMBtu/hr but less than or equal to 100
MMBtu/hr and 20 ppmv NOx concentration limit applied to process heaters
with a capacity greater than 100 MMBtu/hr.

Table 6.  Summary of Model Refinery Values Used to Assess the Size and
Number of Affected Process Heaters

Process Unit	Model Plant Size

(bbl/cd)	Fuel Use Factor

(MMBtu/bbl)	Process Heater Size (MMBtu/hr)	Projected Flow Rate (scfm)
Number of New, Modified, or Reconstructed Processes

Crude Distillation	143,000	0.087	520 	104,000 	15

Vacuum Distillation	71,000 	0.084	250 	49,900 	13.5

Thermal Cracking (coking)	28,600 	0.094	110 	22,400	6

Catalytic Cracking	50,000 	0.051	105 	21,100	12

Catalytic Reforming	28,600 	0.467	560 	111,000 	15

Hydrocracking	14,300 	0.105	60 	12,500	4.5

Hydrotreating/Hydrorefining	100,000 	0.018	70 	14,900 	30

Alkylation (general)	14,300	0.217	130 	25,800 	9

Polymerization	 2,900

	- 	3

Aromatics 	14,300	0.100	60 	11,900 	4.5

Isomerization	 7,100	0.150	45 	 9,000 	7.5

Other Lube Oil Processes	14,300	0.368	220 	43,800	0

Full-Range Distillation	14,286 	0.087	50 	10,400 	45

Hydrogen Planta	30a 	15.0a	18 	 3,600 	9

Sulfur Plantb	210b 	3.077b	27 	 5,500 	19.5

Asphalt Plant	14,300 	0.190	110 	22,600 	6

a Production in millions of cubic feet per day (MMcu.ft/day); fuel use
factor in MMBtu per MMcu.ft.

b Production in long tons per day (LTD); fuel use factor in MMBtu per
LTD.

Table 7.  Summary of Representative Baseline NOx Concentrations for
Affected Process Heaters

Representative

Average NOx

Concentration (ppmv)	Fraction of Affected Process Heaters Represented by
Average NOx Concentration

80	0.1

100	0.25

150	0.5

200	0.15



The nationwide impacts for the regulatory alternatives considered for
process heaters NOx control are presented in Table 8.

Table 8.  Summary of Nationwide Impacts of Various NOx Regulatory
Alternatives for Process Heaters

Regulatory Alternative 	Total Capital Investment  (million $)	Annual
Operating Costs  (million $/yr)	Total Annualized Costs  (million $/yr)
NOx Emission Reduction from Baseline

(tons/yr)

Nationwide Costs for Newly Constructed Units

Option 1	 48 	  4.4 	  9.5 	6,820 

Option 2	 68 	  5.8 	  12.7 	8,110 

Option 3	 95 	  8.0 	  17.4 	8,180 

Option 4	 158 	  14.2 	  29.6 	8,730 

Nationwide Costs for Modified or Reconstructed Units

Option 1	 91 	  8.8 	  18.3 	10,230 

Option 2	 132 	  12.1 	  25.3 	12,170 

Option 3	 187 	  16.7 	  35.0 	12,270 

Option 4	 314 	  27.9 	  58.3 	13,090 

Nationwide Costs for all New, Modified, and Reconstructed Units

Option 1	 139 	  13.2 	  27.7 	17,050 

Option 2	 199 	  17.9 	  38.0 	20,280 

Option 3	 282 	  24.7 	  52.4 	20,450 

Option 4	 471 	  42.1 	  87.9 	21,820 



VI.	References

Bruhin, T., G. McElhiney, G. Bourdillon, and P.A. Diddams.  2003. 
“Catalytic Solutions for FCC Unit Emissions.”  In the proceedings of
the World Petroleum Conference 2003.  pp. 144-147.  Available at: 

  HYPERLINK
"http://www.world-petroleum.org/isc2004/File%20022/144_145_146_147.pdf" 
http://www.world-petroleum.org/isc2004/File%20022/144_145_146_147.pdf  

Eastern Research Group (ERG).  2001.  Petroleum Refinery Tier 2 BACT
Analysis Report – Final Report.  Prepared for U.S. Environmental
Protection Agency, Manufacturing Branch, Washington, DC.  January 16,
2001.

MACTEC.  2005. Midwest Regional Planning Organization (RPO) Petroleum
Refinery Best Available Retrofit Technology (BART) Engineering Analysis.
 Report prepared by MACTEC Federal Programs/MACTEC Engineering and
Consulting, Inc. for The Lake Michigan Air Directors Consortium (LADCO).
 March 30, 2005.

Hutter, E. and Confuorto, N.  2006.  Email correspondence between Jeff
Coburn, RTI International; Edward Hutter, Applications Manager, Belco
Technologies Corporation; and Nick Confuorto, Vice President,
Technology, Sales & Marketing, Belco Technologies Corporation re: Design
and costs of wet scrubbers and LoTOx systems.  Date of final
communication:  September 9, 2006.

RTI.  2002.  Petroleum Refinery Source Characterization and Emission
Model for Residual Risk Assessment.  Prepared for U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC.  EPA Contract No. 68-D6-0014.  July 2,
2002.

Addressee:  Bob Lucas – Documentation of NOx Control Cost Estimates

April 30, 2007

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