Date:	April 27, 2007

To:	Bob Lucas, EPA/SPPD

From:	Kristin Parrish

Subject:	Data and Assumptions used in the Impacts Analysis for PM and
SO2 Emissions from Fluid Catalytic Cracking Units and Fluid Coking Units



I.	Introduction

The U. S. Environmental Protection Agency (EPA) is reviewing the new
source performance standards (NSPS) for petroleum refineries (40 CFR
part 60, subpart J).  Available control technologies were evaluated for
each process unit covered by subpart J to determine the appropriateness
of updating the standards.  Several regulatory options were considered
for fluid catalytic cracking units (FCCUs) and fluid coking units to
control particulate matter (PM) and sulfur dioxide (SO2) emissions.  The
options for FCCUs include:

Continue to meet PM limit of 1.0 kilograms per megagram (kg/Mg) of coke
burned (demonstrating compliance using Method 5B or 5F) and meet SO2
limit of 50 parts per million by volume (ppmv) on a 7-day rolling
average;

Meet PM limit of 1.0 kg/Mg of coke burned (demonstrating compliance
using Method 5) and meet SO2 limit of 50 ppmv on a 7-day rolling
average;

Meet PM limit of 0.5 kg/Mg of coke burned (demonstrating compliance
using Method 5) and meet SO2 limit of 50 ppmv on a 7-day rolling
average;

Meet PM limit of 0.5 kg/Mg of coke burned (demonstrating compliance
using Method 5) and meet SO2 limits of 50 ppmv on a 7-day rolling
average and 25 ppmv on a 365-day rolling average; and

Meet PM limit of 0.15 kg/Mg of coke burned (demonstrating compliance
using Method 5) and meet SO2 limits of 50 ppmv on a 7-day rolling
average and 25 ppmv on a 365-day rolling average.

For fluid coking units, the options include:

Meet PM limit of 1.0 kg/Mg of coke burned (demonstrating compliance
using Method 5) and meet SO2 limit of 50 ppmv on a 7-day rolling
average; and

Meet PM limit of 0.5 kg/Mg of coke burned (demonstrating compliance
using Method 5) and meet SO2 limits of 50 ppmv on a 7-day rolling
average and 25 ppmv on a 365-day rolling average.

The purpose of this memorandum is to document the assumptions and
methodology used to determine the costs (in 2005 dollars) and emission
reduction impacts for new, reconstructed, and modified FCCUs and fluid
coking units over the first 5 years of the regulation for these options.
 All impacts are expressed as the costs and emission reductions achieved
beyond implementing the current requirements of subpart J.  The results
are summarized in   REF _Ref165371505 \h  Table 1  and   REF
_Ref165371552 \h  Table 2 .

Table   SEQ Table \* ARABIC  1 .   Nationwide Fifth Year Costs and
Emission Reductions for PM/SO2 Regulatory Options for FCCUs

Option	Capital Cost ($1,000)	Total Annual Cost ($1,000/yr)	PM Emission
Reduction (tons/yr)	SO2 Emission Reduction (tons/yr)	Cost-Effectiveness
($/ton)





	Overall	Incrementala

1	500	3,100	17	6,800	500	--

2	670	3,600	350	6,800	500	1,400

3	40,000	9,200	1,200	7,200	1,100	4,400

4	40,000	9,500	1,200	8,300	1,000	220

5	140,000	30,000	460	7,900	3,600	N/A

a  Incremental cost-effectiveness from previous option.

Table   SEQ Table \* ARABIC  2 .  Nationwide Fifth Year Costs and
Emission Reductions for PM/SO2 Regulatory Options for Fluid Coking Units

Option	Capital Cost ($1,000)	Total Annual Cost ($1,000/yr)	PM Emission
Reduction (tons/yr)	SO2 Emission Reduction (tons/yr)	Cost-Effectiveness
($/ton)





	Overall	Incrementala

1	14,000	4,700	1,700	21,000	210	--

2	14,000	4,800	2,000	21,000	210	120

a  Incremental cost-effectiveness from previous option.

II.	Number of Impacted Process Units

To project the number of new, reconstructed, and modified process units
over the next 5 years, we used many of the same assumptions as in the
analysis for subpart GGG, including the average number of process units
at a refinery.  That analysis assumes that there are 0.8 FCCUs and
0.4 coking units per refinery and that 15 refineries’ worth of
process units become subject (i.e., are either new, reconstructed, or
modified) over the five years following proposal.  We also assumed that
40 percent of the FCCUs are new and 60 percent are reconstructed or
modified.

FCCUs

We identified four scenarios to characterize FCCUs, one for new process
units and three for reconstructed and modified process units.  In this
analysis, currently refers to the situation prior to proposal of new
NSPS requirements and baseline refers to the requirements if no new
standards are proposed (in most cases, baseline is compliance with
subpart J).

New (baseline = comply with subpart J)

Currently subject to subpart J (baseline = continue to comply with
subpart J)

Currently subject to consent decree (baseline = continue to comply with
consent decree requirements, assuming these are equal to or more
stringent than subpart J)

Currently subject to MACT (baseline = comply with subpart J)

We assumed that the currently existing process units that are
reconstructed or modified are broken down into Scenarios #2, 3, and 4 as
follows:

10 percent are subject to MACT and not subpart J (Scenario #4).

76.5 percent are units subject to a consent decree (Scenario #3). 
NOTEREF _Ref165193975 \h  \* MERGEFORMAT  1   For purposes of this
analysis, average consent decree requirements are assumed to be 1.0 kg
PM/Mg coke burn (using Method 5B or 5F), 50 ppmv SO2 over a 7-day
average, and 25 ppmv SO2 over a 365-day average.

The remaining 13.5 percent are subject to subpart J (Scenario #2).

The assumptions outlined above translate into the following values:

12 total new, reconstructed, or modified FCCUs (multiply estimate of 0.8
FCCU per refinery by 15 refineries’ worth of process units)

4.8 FCCUs are new

7.2 FCCUs are reconstructed or modified

1 is currently subject to subpart J

5.5 are currently subject to consent decree

0.7 are currently subject to MACT only

Fluid Coking Units

	We assumed that there will be six new, reconstructed, or modified
coking units over the next 5 years.  Based on industry trends, we
anticipate that five of these will be delayed coking units and only one
will be a fluid coking unit.  We assumed that the single fluid coking
unit will become subject through modification or reconstruction rather
than new construction.  At baseline, this fluid coking unit would comply
with subpart J, which includes no requirements for coking units.

III. 	Emissions Estimates

	For both FCCUs and fluid coking units, PM and SO2 controls were
evaluated together because a wet scrubber installed to reduce PM will
also achieve SO2 reductions.  The other control device considered for
FCCUs was an electrostatic precipitator (ESP) for PM reduction and
catalyst additives for SO2 emission reduction.  This option is not
technically feasible for a fluid coking unit; therefore, the analysis
for the one affected fluid coking unit assumed a wet scrubber as the
control device.

FCCUs

We assumed a model FCCU size of 50,000 barrels (bbl) per day.  This
model FCCU also has a volumetric flow rate of 140,000 dry standard cubic
feet per minute (dscfm) and a coke burn-off rate of 800,000 pounds (lb)
per day.  It operates at 95 percent of capacity.

In order to determine emission reductions beyond subpart J for each
option, we first estimated emissions attributed to meeting subpart J. 
Based on industry trends and control device capabilities, we assumed
that 35 percent of the FCCUs would meet subpart J with a wet scrubber
and 65 percent would meet subpart J using an ESP and catalyst additives.
 We assumed the basic model wet scrubber could meet the subpart J PM
limit with an 80 percent control efficiency and would average about 25
ppmv SO2.  (Other assumed parameters are included in section IV of this
memorandum.)  The model ESP also had a control efficiency of 80 percent
for PM.  For SO2, we calculated that the 9.8 kg/Mg coke burn is
equivalent to about 265 ppmv.

We estimated emissions of PM as the total of filterable PM that is less
than 10 micrometers (μm) in diameter (PM-10), filterable PM that is
less than 2.5 (μm) in diameter (PM-2.5), and condensable PM.  At
baseline, an FCCU meeting subpart J with a wet scrubber would emit
236 tons PM per year and an ESP would emit 305 tons PM per year.  (A
wet scrubber has a lower operating temperature than an ESP, which
provides improved removal of condensable PM and results in lower PM
emissions).  Based on the assumptions described above, we estimated
baseline PM emissions for the 12 FCCUs at 3,370 tons per year (1,350
tons per year from new FCCUs and 2,020 tons per year from reconstructed
and modified FCCUs).  For this model FCCU, we estimated emissions of SO2
as 1,540 tons per year for catalyst additives meeting 265 ppmv and 145
tons per year for wet scrubbers and catalyst additives meeting 25 ppmv. 
Based on the assumptions described above, we estimated baseline SO2
emissions for the 12 FCCUs at 9,600 tons per year (5,050 tons per year
from new FCCUs and 4,560 tons per year from reconstructed and modified
FCCUs).

To determine the emissions for each option, we assumed that the ratio of
ESPs to wet scrubbers chosen for new FCCUs would change depending on the
particular emission limits being considered.  For example, as the SO2
limit tightens, a wet scrubber becomes more cost-effective compared to
the catalyst additives.  On the other hand, we have no data to support
an assumption that wet scrubbers could achieve the Option 5 PM limit of
0.15 kg/Mg coke burn, so we assumed that for Option 5, all FCCUs would
be controlled with an ESP and catalyst additives.  In addition to these
considerations, we considered for reconstructed and modified FCCUs with
an existing control device whether cost-effectiveness or technical
limitations for each option would drive an operator to change the
control device.  For example, for Option 5, all wet scrubbers would be
removed in favor of ESPs that can meet the lower PM limit.  Our
estimations of control device breakdown are shown in   REF _Ref165452786
\h  \* MERGEFORMAT  Table 3  (see Appendix A for further detail.)

For each of the five options, we again estimated PM emissions as a total
of filterable PM-10 and PM-2.5 and condensable PM.  The total values
vary for each option and for the specific control device chosen. 
Further detail on the PM control devices is located in section IV of
this memorandum.  In addition to the SO2 emissions described for
baseline, we estimated emissions of 290 tons per year for catalyst
additives meeting 50 ppmv.  We also assumed that wet scrubbers designed
to meet 0.5 kg PM/Mg coke burn would achieve 12.5 ppmv SO2, which we
calculated to be equivalent to 73 tons per year.  See   REF
_Ref165371663 \h  \* MERGEFORMAT  Table 4  for the emission estimates
for each option; Appendix B includes further detail on these
calculations.

	

Fluid Coking Units

We assumed a model fluid coking unit size of 40,000 bbl/day.  This model
coking unit also has a volumetric flow rate of 200,000 dscfm.  At
baseline, there are no requirements for fluid coking units, so there are
no emission reductions for either PM or SO2.  For Option 1, we assumed
that a basic wet scrubber would be chosen.  We estimated emission
reductions of 1,710 tons PM per year (based on 84 percent efficiency)
and 20,600 tons SO2 per year (based on estimates of 94 percent
efficiency and uncontrolled SO2 emissions of 3.0 lb/bbl).  For Option 2,
we assumed that an enhanced wet scrubber would be chosen to meet the
emission limits.  We estimated emission reductions of 1,970 tons PM per
year (based on 97 percent efficiency) and 21,200 tons SO2 per year (also
based on an estimate of 97 percent efficiency).

IV. 	Cost Analysis

Before determining the cost of each individual model control device,
there were a number of constant values to determine.  These values are
described below:

Chemical Engineering Cost Index Value:  This value was used to project
base year equipment costs (1987 for ESPs and 1989 for wet scrubbers) to
2005 costs.  We used a value of 468.2, the annual value for 2005.

Labor Costs:  We identified two values from the May 2005 Bureau of Labor
Statistics (BLS) Employment and Wage Estimates.  The mean wage rate for
Standard Occupational Classification (SOC) Code 49-0000 (Installation,
Maintenance, and Repair Occupations) is $23.42, and the mean wage rate
for SOC Code 51-0000 (Production Occupations) is $22.05.

Cost of Electricity:  The value of $0.0527 per kilowatt-hour was the
cost of electricity for the industrial sector in 2004, according to the
Energy Information Administration.

Tipping Fee for Waste Disposal:  The tipping fee can vary widely
according to geographic location; we chose a value of $50 per ton to
represent an average.

Cost of Water:  A value of $0.20 per 1000 gallons was provided as a
baseline value for the year 1989.  Like the tipping fee for waste
disposal, the cost of water can vary widely based on location and type
of system providing the water.  Therefore, we estimated the 2005 cost by
inflating the 1989 cost by the Department of Labor 2005 Consumer Price
Index.

FCCUs

We estimated costs for model ESPs and wet scrubbers designed to meet the
PM emission limits:

Limit to Meet	Efficiency

1.0 kg/Mg coke burn (Method 5B or 5F)	80 percent

1.0 kg/Mg coke burn (Method 5)	84 percent

0.5 kg/Mg coke burn (Method 5)	92 percent 

0.15 kg/Mg coke burn (Method 5)	98 percent 



Wet scrubber design parameters such as pressure drop and electricity
consumption were provided in communications with Belco Technologies
Corporation.  The EPA Air Pollution Control Cost Manual provided
methodologies for determining the ESP design parameters and estimating
the costs of all control devices.  We used these methodologies along
with design parameters, the control efficiencies shown above, and a
retrofit factor to determine model control device costs.  Finally, we
estimated the cost of catalyst additives to be about $700 per ton of SO2
removed based on information in publications from Grace Davison and
BELCO Technologies Corporation.,  Appendix C shows the costs for the
model control devices.  Appendix D shows the costs for each option and
scenario and includes a description of how all the individual costs
described above were used to develop overall costs.

Fluid Coking Units

As mentioned previously, catalyst additives are not technically feasible
for fluid coking units.  Therefore, we estimated costs for a basic wet
scrubber to meet Option 1 and an enhanced wet scrubber to meet Option 2.
 These scrubbers differ from the model FCCU wet scrubbers only in vent
flow rate and annual dust loading.  Appendix E shows the cost
calculations for these two individual wet scrubbers.  In each case, we
selected a retrofit factor of 1.5 based on an assumption that special
reconfigurations might be required to install a control device on an
existing fluid coking unit.

V.	Results

The results of the impacts analysis for FCCUs are summarized in   REF
_Ref165379103 \h  \* MERGEFORMAT  Table 5 ; impacts for new FCCUs are
presented separately from reconstructed and modified FCCUs.  For new
sources, there is a negative incremental cost-effectiveness for Option
4.  As the SO2 limit tightens, it becomes more cost-effective to use wet
scrubbers than ESPs, and we expect that more owners and operators will
choose wet scrubbers for Option 4 than Option 3.  Therefore, the overall
total annual cost decreases slightly from Option 3 to Option 4,
resulting in a negative cost increase.  There is also a negative
incremental cost-effectiveness for all units for Option 5.  In this
case, the negative values indicate a decrease in emission reductions
from Option 4.  This decrease is due to the practice of injecting
ammonia into ESPs to improve the efficiency, which we expect will
increase condensable PM emissions.  Therefore, although Option 5
includes the most stringent filterable PM emission limit, it does not
achieve the most actual PM reductions.

The overall FCCU impacts were presented in   REF _Ref165371505 \h  Table
1 .  The impacts for the fluid coking unit were presented in   REF
_Ref165371552 \h  Table 2 .

Table   SEQ Table \* ARABIC  3 .  Fraction and Number of FCCUs Expected
to Choose Each Type of Control Device

FRACTION	New	Reconstructed / Modified

Option	PM (kg/Mg coke burn)	SO2 (ppmv)	Choose ESP/Catalyst Additives
Choose Wet Scrubber	Continue ESP/Catalyst Additives	Switch to Wet
Scrubber	Continue Wet Scrubber	Switch to ESP/Catalyst Additives

1	1.0 (Method 5B or 5F)	50	0.6	0.4	0.65	0	0.35	0

2	1.0 (Method 5)	50	0.6	0.4	0.65	0	0.35	0

3	0.5 (Method 5)	50	0.5	0.5	0.65	0	0.35	0

4	0.5 (Method 5)	25	0.4	0.6	0.65	0	0.35	0

5	0.15 (Method 5)	25	1	0	0.65	0	0	0.35

TOTAL NUMBER FCCUs	New	Reconstructed / Modified

Option	PM (kg/Mg coke burn)	SO2 (ppmv)	Choose ESP/Catalyst Additives
Choose Wet Scrubber	Continue ESP/Catalyst Additives	Switch to Wet
Scrubber	Continue Wet Scrubber	Switch to ESP/Catalyst Additives

1	1.0 (Method 5B or 5F)	50	2.88	1.92	4.68	0	2.52	0

2	1.0 (Method 5)	50	2.88	1.92	4.68	0	2.52	0

3	0.5 (Method 5)	50	2.4	2.4	4.68	0	2.52	0

4	0.5 (Method 5)	25	1.92	2.88	4.68	0	2.52	0

5	0.15 (Method 5)	25	4.8	0	4.68	0	0	2.52



  

Table   SEQ Table \* ARABIC  4 .  Emissions per FCCU, Total Nationwide
Emissions, and Total Nationwide Emission Reductions for Five Options

EMISSIONS PER FCCU	PM Emissions (tons/year)	SO2 Emissions (tons/year)

Option	PM (kg/Mg coke burn)	SO2 (ppmv)	ESP/Catalyst Additives	Wet
Scrubber	ESP/Catalyst Additives	Wet Scrubber

1	1.0 (Method 5B or 5F)	50	305	236	290	145

2	1.0 (Method 5)	50	277	208	290	145

3	0.5 (Method 5)	50	208	139	290	73

4	0.5 (Method 5)	25	208	139	145	73

5	0.15 (Method 5)	25	243	--	145	--

TOTAL NATIONWIDE EMISSIONS	PM Emissions (tons/year)	SO2 Emissions
(tons/year)

Option	PM (kg/Mg coke burn)	SO2 (ppmv)	New	Reconstructed/ Modified	Total
New	Reconstructed/ Modified	Total

1	1.0 (Method 5B or 5F)	50	1,330	2,020	3,350	1,120	1,730	2,840

2	1.0 (Method 5)	50	1,200	1,820	3,020	1,120	1,730	2,840

3	0.5 (Method 5)	50	832	1,320	2,160	871	1,540	2,410

4	0.5 (Method 5)	25	799	1,320	2,120	488	863	1,350

5	0.15 (Method 5)	25	1,170	1,750	2,910	697	1,050	1,740

TOTAL NATIONWIDE EMISSION REDUCTIONS	PM Emission Reductions (tons/year)
SO2 Emission Reductions (tons/year)

Option	PM (kg/Mg coke burn)	SO2 (ppmv)	New	Reconstructed/ Modified	Total
New	Reconstructed/ Modified	Total

1	1.0 (Method 5B or 5F)	50	17	0	17	3,930	2,830	6,760

2	1.0 (Method 5)	50	150	200	350	3,930	2,830	6,760

3	0.5 (Method 5)	50	516	699	1,220	4,180	3,020	7,190

4	0.5 (Method 5)	25	549	699	1,250	4,560	3,700	8,250

5	0.15 (Method 5)	25	183	275	458	4,350	3,510	7,860



Table   SEQ Table \* ARABIC  5 .  Impacts for New FCCUs and
Reconstructed / Modified FCCUs

NEW FCCUs



Option	PM (kg/Mg coke burn)	SO2 (ppmv)	Capital Cost ($1,000)	Total
Annual Cost ($1,000/yr)	Emission Reduction (tons/yr)	Cost-Effectiveness
($/ton)





	PM	SO2	Overall	Incrementala

1	1.0 (Method 5B or 5F)	50	500	2,500	17	3,900	640	--

2	1.0 (Method 5)	50	670	2,500	150	3,900	620	250

3	0.5 (Method 5)	50	9,000	3,500	520	4,200	740	1,500

4	0.5 (Method 5)	25	9,000	3,300	550	4,600	640	-410

5	0.15 (Method 5)	25	30,000	10,000	180	4,300	2,200	-12,000

RECONSTRUCTED/MODIFIED FCCUs



Option	PM (kg/Mg coke burn)	SO2 (ppmv)	Capital Cost ($1,000)	Total
Annual Cost ($1,000/yr)	Emission Reduction (tons/yr)	Cost-Effectiveness
($/ton)





	PM	PM	Overall	Incrementala

1	1.0 (Method 5B or 5F)	50	0	610	0	2,800	210	--

2	1.0 (Method 5)	50	0	1,000	200	2,800	340	2,200

3	0.5 (Method 5)	50	31,000	5,800	700	3,000	1,600	6,900

4	0.5 (Method 5)	25	31,000	6,200	700	3,700	1,400	620

5	0.15 (Method 5)	25	110,000	20,000	270	3,500	5,200	-20,000

a  Incremental cost-effectiveness from previous option.

VI. 	References

		

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. 

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ᔀ罨卾ᘀ表휴　ፊ䌀ᡊ䠀*ࡕ愁ᡊἀEnvironmental Fluid
Catalytic Cracking Technology.  Presented at the European Refining
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