Date:	April 30, 2007

To:	Bob Lucas, EPA/SPPD

From:	Kristin Parrish

Subject:	Data and Assumptions used in the Impacts Analysis for SO2
Emissions from Fuel Gas Combustion Devices



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 fuel gas combustion devices to control sulfur dioxide (SO2)
emissions.  The options include maintaining the 3-hour average 20 ppmv
SO2 emission limit (equivalent hydrogen sulfide (H2S) concentration
limit of 160 ppmv) and a 365-day average SO2 emission limit of:

10 ppmv (equivalent H2S concentration limit of 80 ppmv);

8 ppmv (equivalent H2S concentration limit of 60 ppmv); or

5 ppmv (equivalent H2S concentration limit of 80 ppmv).

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 fuel gas
combustion devices 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 .

Table   SEQ Table \* ARABIC  1 .  Nationwide Fifth Year Costs and
Emission Reductions for SO2 Regulatory Options for Fuel Gas Combustion
Devices

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





Overall	Incrementala

1	0	2,000	1,000	1,900	--

2	0	2,900	1,300	2,200	3,500

3	0	4,100	1,600	2,600	4,700

a  Incremental cost-effectiveness from previous option.

II.	Number of Impacted Process Units

We assumed that 30 refineries will construct, reconstruct, or modify a
fuel gas combustion device over the next five years.  This estimate is
based in part on the assumed average numbers of process units at a
refinery from the analysis for subpart GGG.  Industry representatives
have indicated that most fuel gas systems are centralized.  Therefore,
the entire system that includes the new, reconstructed, or modified
combustion device will essentially have to meet subpart Ja standards in
order for the new or reconstructed fuel gas combustion device to comply
with subpart Ja.

III. 	Emissions Estimates

We assumed that an average amine treatment system for fuel gas
combustion devices would have an average gas flow rate of 10,000
standard cubic feet per minute (scfm).  We developed this model system
based on information from various sources;,, further details about the
model are included in section IV of this memorandum.  Based on this flow
rate and an emission limit of 20 ppmv, one system would emit 0.27 pounds
(lbs) of SO2 per minute (min), or 70 tons per year (tons/yr). 
Nationwide (i.e., for 30 systems), the total emissions are 2,100 tons
per year.  The emissions from one system, nationwide emissions, and the
reduction from the baseline for each of the three options are shown
below:

Option	Emissions from One System	Nationwide Emissions (tons SO2/yr)
Reduction from baseline (tons SO2/yr)

	(lb SO2/min)	(tons SO2/yr)



1	0.13	35	1,050	1,050

2	0.10	26	786	1,310

3	0.07	17	524	1,570



IV. 	Cost Analysis

We assumed that the three options could be achieved by increasing the
amine circulation rate of an amine treatment system designed to meet the
current requirements of subpart J.  Our model amine treatment system has
an amine circulation rate of 400 gallons per minute (gpm) and a steam
ratio of 0.9 pounds per gallon (lbs/gal) of amine.  The incremental cost
from subpart J to achieve each of the options is the additional cost of
the steam required to regenerate the rich amine solution at the
increased amine circulation rate.  We estimated that the cost of steam
is $7.25 per 1000 pounds.  NOTEREF _Ref165643229 \h  \* MERGEFORMAT  4 

We assumed that each incremental 20 ppmv reduction in H2S concentration
would require a larger incremental increase in the amine recirculation
rate than the previous 20 ppmv reduction.  Using that assumption, we
projected the increased amine recirculation rate for each of the three
regulatory options considered.  Table 2 presents these projected
recirculation rate increases along with the costs associated with these
increases for each regulatory option. 

Table 2.  Summary of Cost Calculations for SO2 Regulatory Options for
Fuel Gas Combustion Devices

Option	Amine Circulation Rate Increase per Refinery (gpm)	Steam Use
Increase per Refinery 

(1,000 lb/yr)	Cost Increase per Refinery ($1000/yr)	Cost Increase
Nationwide ($1000/yr)

1	19	8,988	65	2,000

2	28	13,245	96	2,900

3	40	18,922	137	4,100



We calculated the steam use rate increase shown in Table 2 by
multiplying the amine circulation rate increases (gpm) by the steam
ratio (0.9 lb/gal), assuming the system operates 24 hour per day and 365
days per year.  We calculated the nationwide costs assuming 30 systems
would have to meet each option over the first 5 years of the regulation.

V. 	References

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.	Parrish, K., D. Randall, and J. Coburn.  October 30, 2006.  Data and
Assumptions used in the Equipment Leaks Cost Analysis for Petroleum
Refineries.  Memorandum to Karen Rackley, EPA/SPPD.  Docket Item No.
EPA-HQ-OAR-2006-0699-0034.

.	Polasek, J.C., J.A. Bullin, and S.T. Donnelly.  1982.  Alternative
Flow Schemes to Reduce Capital and Operating Costs of Amine Sweetening
Units.  Proceedings of the 1982 AIChE Spring National Meeting, New York,
NY: American Institute of Chemical Engineers.

.	Fedich, R.B., A.C. Woerner, and G.K. Chitnis.  May 2004.  Selective
H2S Removal.  Hydrocarbon Engineering, Vol. 9, No. 5, pp. 89-92.

.	Voltz, B.L., J.D. Corley, and R.B. Fedich.  November 2004.  Benefits
of a TGCU Amine Solvent Changeover.  Sour Oil & Gas Advanced Technology
2004 International Conference. 

