From: "Higgins, Cortney" <Cortney_Higgins@omb.eop.gov> 

Sent: 02/29/2012 01:32 PM 

To: Brenda Shine/RTP/USEPA/US@EPA 

Cc: Penny Lassiter/RTP/USEPA/US@EPA, Alex Macpherson/RTP/USEPA/US@EPA, 

William Nickerson/DC/USEPA/US@EPA 

Subject: Interagency Comments under EO 13563 on Petroleum Ja draft final rule 

Hi Brenda, 

Attached are comments on the Flares memo. 

 

Regards, 

Cortney 

<< Impacts_FlareGasRecovery_FGCD-01-25-12_InteragencyCommentsunderEO13563.doc >> 
FROM: Kristin Sroka and Jeff Coburn, RTI International 

TO: Brenda Shine, EPA/OAQPS/SPPD 

FOR: Petroleum Refinery NSPS Docket No. EPA-HQ-OAR-2007-0011 

DATE: January 25, 2012 

SUBJECT: Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options 

for Amendments to the Petroleum Refinery NSPS 

1. Introduction

The U.S. Environmental Protection Agency (EPA) issued new source performance standards 

(NSPS) for petroleum refineries beginning construction, reconstruction, or modification after 

May 14, 2007 (40 CFR part 60, subpart Ja) on June 24, 2008. Following promulgation, EPA 

received petitions for reconsideration from: 1) the American Petroleum Institute (API), the 

National Petrochemical and Refiners Association (NPRA), and the Western States Petroleum 

Association (WSPA) (collectively referred to as “Industry Petitioners”); 2) HOVENSA, LLC; 

and 3) the Environmental Integrity Project, Sierra Club, and Natural Resources Defense Council 

(collectively referred to as “Environmental Petitioners”). Based on information provided by the 

petitioners, EPA proposed amendments to subpart Ja regarding the requirements for flares and 

process heaters on December 22, 2008. 

The petitioners and commenters on the proposed amendments to the subpart Ja requirements 

provided information to improve the cost and emission reduction estimates that were presented at 

the time of promulgation of the final standards and the proposed amendments to the standards. 

Industry Petitioners noted that the provisions describing what actions cause a flare to become a 

modified source would cause many more than 30 flares to become subject to subpart Ja over the 

next 5 years. Environmental Petitioners noted that the sulfur dioxide (SO2) emissions per flaring 

event and emissions reductions per root cause analysis (RCA) were significantly underestimated, 

and they provided data on SO2 emissions from flares from three refineries in Texas (Schaeffer, 

2008). Public commenters stated that EPA should consider the impacts of the long-term 

hydrogen sulfide (H2S) concentration requirements for fuel gas sent to flares separately from the 

impacts of the other flare requirements. 

The costs and emission reduction impacts of several regulatory options were evaluated based on 

this additional information. Note that for purposes of the regulatory alternatives considered in 

this memorandum, flares are not considered fuel gas combustion devices (FGCD); rather, they 

are considered as separate affected sources. The regulatory options are as follows: 

 A limit of 60 parts per million by volume (ppmv) H2S or 8 ppmv SO2 over a 365-day 

rolling average for FGCD (as noted above, this does not include flares); 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

2

 Requiring owners and operators to limit the concentration of H2S in the fuel gas sent to 

flares to 60 ppmv on a 365-day rolling average; and 

 Requirements for flaring events, including a flare management plan, RCA for a discharge 

that causes 500 pounds (lb) SO2 emissions in a 24-hour period; and RCA for a discharge 

that causes flow rate to a flare in excess of 500,000 standard cubic feet (scf) above a 

baseline flow rate defined in the flare management plan within a 24-hour period. 

The purpose of this memorandum is to document the procedures and methodologies used to 

estimate the costs (in 2006 dollars) and emission reduction impacts for new, reconstructed, and 

modified flares and FGCD over the first 5 years for selected regulatory options. All impacts are 

expressed as the costs and emission reductions achieved beyond implementing the current 

requirements of subpart J. 

The nationwide impacts for the first regulatory option, the long-term fuel gas sulfur limit for 

FGCD, are shown in Table 1. Table 2 presents the nationwide impacts for the second regulatory 

option, the long-term sulfur concentration requirement for fuel gas sent to flares. The nationwide 

impacts for the third regulatory option, the standards for flaring events, are shown in Table 3. 

Table 1. Projected National Fifth Year Impacts of the Long-Term Fuel Gas Sulfur Limit for 

Potentially Affected Fuel Gas Combustion Devices 

Process Unit 

Capital cost 

($1,000) 

Total annual 

cost ($1,000/ 

yr) 

Emission 

reduction (ton 

SO2/yr) 

Cost 

effectiveness 

($/ton) 

New Fuel Gas Systems 1,200 560 520 1,100 

Modified and 

Reconstructed Fuel Gas 

Systems 

33,000 11,000 4,800 2,300 

Total 34,000 12,000 5,300 2,200 

Comment [A1]: Why 2006 dollars? 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the 

Petroleum Refinery NSPS 

January 25, 2012 

3

Table 2. Projected National Fifth Year Impacts of Long-Term Sulfur Concentration Requirement for Fuel Gas Sent to 

Potentially Affected Flares 

Process Unit 

Capital 

cost 

($1,000) 

Annual 

operating cost 

without 

natural gas 

offset ($1,000) 

Natural 

gas 

offset 

($1,000) 

Net 

annual 

operating 

cost 

($1,000) 

Total 

annual 

cost 

($1,000/ 

yr) 

SO2

Emission 

reduction 

(ton 

SO2/yr) 

NOX

Emission 

reduction 

(ton 

NOX/yr) 

VOC 

Emission 

reduction 

(ton 

VOC/yr) 

Cost 

effective

ness 

($/ton) 

New Flares 80,000 8,000 (4,000) 3,200 15,000 6 34 130 84,000 Modified and Reconstructed Flares 860,000 74,000 (39,000) 35,000 160,000 53 310 1,200 100,000 Total 900,000 80,000 (44,000) 38,000 170,000 59 340 1,300 99,000 

Table 3. Projected National Fifth Year Impacts of Other Standards for Potentially Affected Flares 

Standard 

Capital 

cost 

($1,000) 

Total annual cost without 

offset or 

credit ($1,000) 

Annual 

offset or 

credit 

($1,000) 

Total 

annual cost 

($1,000/yr) 

Emission 

reduction 

(ton 

SO2/yr) 

Emission 

reduction 

(ton 

NOX/yr) 

Emission 

reduction 

(ton 

VOC/yr) 

Overall cost 

effectiveness ($/ton) 

Sulfur and Flow Rate Monitoring + Recovery for Largest Flares 

460,000 92,000 (170,000) (76,000) 370 1,100 2,700 (18,000) 

Flare Management Plan -- 880 -- 880 -- -- 300 2,900 SO2 RCA/ Corrective Action 

Analysis -- 2,200 -- 2,200 2,900 -- -- 760 

Flow Rate RCA/ Corrective Action Analysis -- 1,000 (7,400) (6,400) 3.8 56 430 (13,000) Grand Total 460,000 96,000 (180,000) (79,000) 3,200 1,100 3,400 (10,000) 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

4

2. Number of Impacted Process Units

It was assumed at proposal that 30 refineries will construct, reconstruct, or modify one or more 

FGCD over the next 5 years. Industry representatives have indicated that most fuel gas systems 

are centralized. Therefore, the entire system that includes the new, reconstructed, or modified 

FGCD will essentially have to meet the sulfur standards in order for the affected FGCD to be in 

compliance. For that reason, it is more accurate to consider whether the fuel gas system is 

existing or will be constructed than whether the FGCD is new, reconstructed, or modified. In 

other words, if a new FGCD is added to an existing fuel gas system, the refinery will need to 

retrofit that existing system, so it is more accurate to consider that situation as a reconstructed or 

modified fuel gas system. For this analysis, it was assumed that 90 percent of the fuel gas 

systems with affected FGCD will be reconstructed or modified and 10 percent will be new. 

It was also assumed that 150 refineries will construct, reconstruct, or modify one or more flares 

over the next 5 years, based in part on the Industry Petitioners’ information. An estimate of the 

total number of flares in the petroleum refining industry was developed based on data collected 

from the 2002 National Emissions Inventory (NEI) for carbon monoxide (CO) emissions from 

sources with the source characterization code (SCC) for flares. Emissions were reported 

specifically for 252 flares at 77 refineries, suggesting that there approximately 3.3 flares per 

refinery. Applying that ratio to the 150 petroleum refineries, there are approximately 500 flares 

in the industry. It is assumed that 80 percent of these flares, or 400 flares, would become subject 

to subpart Ja over the next 5 years; the remaining flares are assumed to be dedicated flares that 

would not be modified quickly (e.g., flares dedicated to butane spheres). It was also assumed 

that 30 percent of the 400 affected flares, or 120 flares, either would meet the definition of 

“emergency flare” in subpart Ja or would be equipped with a flare gas recovery system. 

The number of coking units at the affected facilities was estimated based on information from 

Refinery Capacity 2006 (EIA, 2006) and the “2005 Worldwide Refining Survey” (Stell, 2005); 

the compiled list includes 150 operating refineries. There are 53 refineries with delayed coking 

units, four refineries with fluid or flexi-coking units, and two refineries with both delayed and 

fluid/flexi-coking units, for a total of 59 refineries that have at least one coking unit, which is 

39 percent of all refineries. For the FGCD analysis, therefore, 39 percent of the 30 affected 

facilities, or 12 refineries, have a fuel gas system that includes fuel gas generated by a coking 

unit. 

3. Long-term Sulfur Limit for Fuel Gas Combustion Devices

A. Emissions Estimates 

Baseline SO2 emissions from FGCD are dependent on the amount of fuel gas produced and the 

amount of sulfur in the fuel gas combusted. The primary sources of fuel gas are expected to be 

the crude distillation unit, the fluid catalytic cracking unit, and the coking unit, with each 

providing approximately equal amounts of fuel gas to a fuel gas system. The primary sulfur 

Comment [A4]: What percent? 

Comment [A5]: Confusing, suggest rephrasing. 

Comment [A6]: Than what? 

Comment [A7]: Percent? 

Comment [A8]: What are the implications of this 

assumption? 

Comment [A9]: Can you discuss additional 

information you received from the ICR or from the 

GHG reporting? 

Comment [A10]: Has there been any update to 

this number based on the ICR or other data? 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

5

compound in fuel gas is typically H2S, which is readily removed by amine treatment. However, 

information received by EPA from Flint Hills Resources suggests that there are other reduced 

sulfur compounds in fuel gas generated by coking units, mostly mercaptans, that contribute to 

SO2 emissions (Wilkes, 2005). These other sulfur compounds are not removed well by 

conventional amine treatment. As such, the SO2 emissions from FGCD at facilities that have 

coking units are expected to be significantly different than those at facilities that do not have 

coking units. Consequently, two model fuel gas systems were used to evaluate the baseline 

SO2 emissions and subsequent emission reductions achieved by a long-term sulfur limit. 

For this analysis, it is assumed that there is one affected centralized fuel gas system at the 

refinery providing fuel gas to one or more affected FGCD. The capacity of the centralized fuel 

gas system is dependent, among other things, on the types of units present at the facility. A fuel 

gas system that includes fuel gas generated by a coking unit was estimated to have an average 

gas flow rate of 50,000 standard cubic feet per minute (scfm). A fuel gas system without a 

coking unit would have an average gas flow rate of about one-third less, or 33,300 scfm (i.e., the 

fuel gas is generated by just the crude distillation unit and the fluid catalytic cracking unit). 

These two model systems were developed based on information from various sources (Fedich et 

al., 2004; Polasek et al., 1982; Voltz et al., 2004); further details about the models are included 

in Section 3.B of this memorandum. 

In the absence of subpart Ja requirements for new, modified, or reconstructed FGCD, the 

affected FGCD would meet the current requirements of subpart J. Nearly all FGCD currently 

meeting those standards comply with the H2S concentration limit of 0.1 grains per dry standard 

cubic feet (gr/dscf) in the fuel gas (equivalent to 162 ppmv H2S in the fuel gas) on a 3-hour 

average. For the model fuel gas system without a coking unit, a fuel flow rate of 33,300 scfm 

and a concentration of 162 ppmv H2S would emit approximately 0.90 pounds of SO2 per minute 

(lb SO2/min), or 240 tons of SO2 per year (ton SO2/yr) at baseline (note that 64 lb of SO2 is 

released during the combustion of 34 lb of H2S in the fuel gas). 

As discussed previously, there is strong evidence that coking units generate other reduced sulfur 

compounds, mostly mercaptans, that contribute to SO2 emissions from the FGCD (Wilkes, 

2005). In their public comments on the original proposed rule (72 FR 27178, May 14, 2007), 

ExxonMobil provided an estimated range of 200 to 300 ppmv mercaptans in fuel gas generated 

by a coking unit and they used a value of 300 ppmv when describing a specific treatment system 

(Feerick, 2007). The mercaptan concentration estimate provided by Flint Hills was higher than 

300 ppmv (although the exact value cannot be provided here due to confidentiality concerns), so 

a value of 300 ppmv mercaptans was selected as the midpoint of the range to calculate baseline 

SO2 emissions. This additional sulfur content only applies to the fuel gas generated by the 

coking unit, which is assumed to be 16,700 scfm in the model plant (i.e., 50,000 – 33,300). The 

weighted average sulfur content in the model fuel gas system with a coking unit was 

subsequently calculated to be 262 ppmv ([(300 ppmv mercaptans + 162 ppmv H2S) × 

16,700 scfm + 162 ppmv H2S × 33,300 scfm] / 50,000 scfm). Assuming an ideal gas at standard 

temperature and pressure (specifically, 20 °C and 1 atmosphere), 262 ppmv reduced sulfur is 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

6

about 2.2 lb SO2/min, so the baseline for one model fuel gas system with a coking unit is 570 ton 

SO2/yr at baseline. 

Based on the facility analysis presented in Section 2, it is estimated that 12 of the fuel gas 

systems with affected FGCD will be represented by the model fuel gas system that contains a 

coking unit and 18 of the affected fuel gas systems (i.e., 30 – 12) would not have a coking unit. 

Therefore, the total nationwide baseline SO2 emissions are estimated to be approximately 

11,000 tons per year (ton/yr) (240 ton/yr × 18 fuel gas systems + 570 ton/yr × 12 fuel gas 

systems) from FGCD. 

The SO2 emissions attributed to this regulatory option for FGCD are the SO2 emissions released 

when the FGCD meets the long-term sulfur limit. It was assumed that refiners would comply 

with the long-term H2S concentration limit rather than the direct SO2 limit. While the H2S and 

SO2 limits are roughly equivalent when H2S is the primary sulfur compound in the fuel gas, it is 

much easier for fuel gas systems with coking units to meet the 60 ppmv H2S concentration limit 

in the fuel gas than the 8 ppmv SO2 emission limit in the FGCD exhaust. For fuel gas systems 

without a coking unit, the SO2 emissions when meeting the long-term H2S concentration limit 

were estimated to be 0.33 lb SO2/min, or 87 ton SO2/yr (assuming an ideal gas at 20 °C and 

1 atmosphere, 60 ppmv H2S for a 33,300 scfm system is equivalent to 0.18 pounds of H2S per 

minute (lb H2S/min), or 0.33 lb SO2/min). Because the amine treatment system is not expected 

to reduce mercaptans for fuel gas systems with a coking unit, SO2 emissions reductions are based 

on a reduction of 102 ppmv H2S. Therefore, for fuel gas systems with a coking unit, the SO2

emissions when meeting the long-term H2S concentration limit were estimated to be 1.33 lb 

SO2/min, or 350 ton SO2/yr (assuming an ideal gas at 20 °C and 1 atmosphere, a reduction of 

102 ppmv H2S for a 50,000 scfm system is equivalent to a reduction in reduced sulfur 

compounds of 0.45 pounds per minute (lb/min), or a reduction of 0.85 lb SO2/min). The 

weighted average reduced sulfur content would be 160 ppmv when meeting the regulatory option 

([(300 ppmv mercaptans + 60 ppmv H2S) × 16,700 scfm + 60 ppmv H2S × 33,300 scfm] / 

50,000 scfm). 

The baseline SO2 emissions and the SO2 emissions for the two model fuel gas systems (one with 

a coking unit and one without) meeting the long-term fuel gas sulfur limit regulatory option are 

shown in Table 4. Table 4 also provides the nationwide emissions at baseline and at the 

60 ppmv H2S long-term concentration limit and the SO2 emission reduction from the baseline. 

Table 4. Emissions for Model Plants Meeting Long-Term Sulfur Limit for Fuel Gas 

Combustion Devices 

Conditions 

Emissions from Model Fuel Gas System Nationwide 

Emissions 

(ton SO2/yr) 

Reduction from 

baseline 

(ton SO2/yr) 

Without a coking 

unit (ton SO2/yr) 

With a coking unit 

(ton SO2/yr) 

Baseline 240 570 11,000 --- 

60 ppmv H2S 87 350 5,800 5,300 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

7

B. Cost Analysis 

It was estimated that roughly 85 percent of the existing fuel gas systems with affected FGCD 

would achieve the long-term sulfur limit by increasing the amine circulation rate of an amine 

treatment system designed to meet the current requirements of subpart J and 15 percent would 

add amine capacity. The model amine treatment system has a steam ratio of 0.9 pounds of steam 

per gallon (lb/gal) of amine; this value is the median of the steam ratios for the systems described 

in various sources (Fedich et al., 2004; Polasek et al., 1982; Voltz et al., 2004). For fuel gas 

systems without a coking unit, the amine circulation rate is 1,333 gallons per minute (gpm); for 

fuel gas systems that include fuel gas generated by a coking unit, the amine circulation rate is 

2,000 gpm. It is estimated that the owner or operator would need to increase the amine 

circulation rate by 3.5 percent to meet this regulatory option; the new amine circulation rate 

would be 1,380 gpm for fuel gas systems without a coking unit and 2,070 gpm for fuel gas 

systems that include fuel gas generated by a coking unit. The incremental cost between subpart J 

and this regulatory option is the additional cost of the steam required to regenerate the rich amine 

solution at the increased amine circulation rate. The cost of steam was estimated to be $7.25 per 

1000 pounds (Voltz et al., 2004). 

Estimated costs for fuel gas systems that would add amine treatment capacity were based on 

costs provided by public commenters. The commenters provided capital costs, annual operating 

costs, and total annual costs for eight relevant projects; further details on these projects are 

considered confidential business information (Chittim, 2007; Garg, 2007). Based on the 

averages for these eight projects, the estimated capital and total annual costs of increasing amine 

capacity for an existing fuel gas system were $11 million and $1.5 million, respectively. For a 

new fuel gas system that includes fuel gas from a coking unit, the estimated incremental capital 

cost between a fuel gas system designed to meet subpart J and a fuel gas system designed to meet 

the regulatory option was 11 percent of the cost of adding amine capacity to an existing system, 

or $1.2 million. 

Table 5 presents the estimate of the numbers of fuel gas systems with affected FGCD expected to 

use the various technologies described above to comply with the long-term sulfur limit. Table 6 

is a summary of the emission reductions and costs for each of the models for fuel gas systems. 

Given the number of each model fuel gas system as presented in Table 5 and the costs and 

emission reductions per model fuel gas system, the nationwide impacts of the long-term sulfur 

limits can be calculated; these results are presented in Table 7 (which is identical to Table 1). 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

8

Table 5. Number of Model Fuel Gas Systems Selecting Each Compliance Method to Meet 

a Long-Term Sulfur Limit for Fuel Gas Combustion Devices 

Type of Fuel Gas System 

Number of Fuel Gas Systems 

Increase in Amine 

Recirculation Rate 

Additional Amine 

Capacity 

New, without a coking unit 2 0 

New, with a coking unit 1 0 

Modified/Reconstructed, without a coking unit 14 2 

Modified/Reconstructed, with a coking unit 10 1 

Table 6. Summary of Costs and SO2 Emission Reductions for Each Model System for 

Two Compliance Methods Employed to Meet a Long-Term Sulfur Limit for Fuel Gas 

Combustion Devices 

Type of Fuel Gas System 

SO2

Emission 

Reduction 

(ton/yr) 

Increase in Amine 

Recirculation Rate 

Additional Amine 

Capacity 

Capital 

Cost 

($1,000) 

Total 

Annual Cost 

($1000/yr) 

Capital 

Cost 

($1,000) 

Total Annual 

Cost 

($1000/yr) 

New, without a coking unit 150 0 160 --- --- 

New, with a coking unit 220 1,200 240 --- --- 

Modified/ Reconstructed, 

without a coking unit 150 0 240 11,000 1,500 

Modified/ Reconstructed, with 

a coking unit 220 0 360 11,000 1,500 

Table 7. Projected National Fifth Year Impacts of the Long-Term Sulfur Limit for 

Potentially Affected Fuel Gas Combustion Devices 

Process Unit 

Capital cost 

($1,000) 

Total annual 

cost ($1,000/ 

yr) 

Emission 

reduction (ton 

SO2/yr) 

Cost 

effectiveness 

($/ton) 

New Fuel Gas Systems 1,200 560 520 1,100 

Modified and 

Reconstructed Fuel Gas 

Systems 

33,000 11,000 4,800 2,300 

Total 34,000 12,000 5,300 2,200 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

9

4. Long-term Sulfur Concentration Requirement for Fuel Gas Sent to Flares

A. Emissions Estimates 

In their comments on the proposed amendments to address the flare requirements, industry 

representatives stated that it is not cost effective to manage the fuel gas sent to flares by limiting 

the long-term concentration of H2S to 60 ppmv. They noted that almost all refineries with 

affected flares would need to add amine capacity rather than increasing the circulation of the 

amine (Cade, 2009; Chittim, 2009; Feerick, 2009; Saffell, 2009). Therefore, as previously noted, 

this analysis evaluates the cost and emission reductions from flares separately from FGCD. For 

this analysis, it is assumed that there are an average of 1.9 impacted flares per refinery (280 

impacted flares at 150 refineries). 

Baseline SO2 emissions from flares, like FGCD, are the result of H2S and other reduced sulfur 

compounds in the fuel gas. Therefore, two flare scenarios were used to evaluate the baseline SO2

emissions and subsequent emission reductions achieved by the limiting the long-term 

concentration of sulfur in fuel gas sent to flares. In the first scenario, the gas being flared does 

not contain fuel gas from a coking unit, and in the second scenario, the gas being flared is from a 

coking unit. In the absence of subpart Ja requirements for new, modified, or reconstructed flares, 

the affected flare would meet the current requirements of subpart J as an FGCD. As noted 

previously, nearly all FGCD currently meeting those standards comply with the H2S 

concentration limit of 0.1 gr/dscf in the fuel gas (equivalent to 162 ppmv H2S in the fuel gas) on 

a 3-hour average. 

The first step in this piece of the analysis was determining the amount of flare gas recovered and 

treated to meet the long-term sulfur concentration requirement. The flare flow rate selected for 

this analysis was 25,000,000 standard cubic feet per year (scf/yr); this is about the 50th percentile 

of the flow rates examined for the overall flare impacts analysis (See Section 5.A and Table 13 

for more information on the analysis of gas flow rates to flares). The flare flow was then 

converted to 48 scfm per flare (25,000,000 scf/yr ÷ 365 days per year ÷ 24 hours per day ÷ 60 

minutes per hour). Using a calculation similar to that for FGCD (Section 3.A), baseline SO2

emissions for this additional 48 scfm are 0.0013 lb/min, or 0.34 ton/yr, assuming none of the 

flare gas is from a coking unit. If the 48 scfm are from a coking unit, then the total baseline SO2

emissions are 0.0037 lb/min, or 0.96 ton/yr. 

Based on the facility analysis presented in Section 2, it is estimated that 59 of the affected flares 

will receive gas from a coking unit and 221 of the affected flares (i.e., 280 – 59) will not receive 

gas from a coking unit. Therefore, the total nationwide baseline SO2 emissions from affected 

flares are estimated to be approximately 131 ton/yr (0.34 ton/yr × 221 flares + 0.96 ton/yr × 

59 flares). 

The SO2 emissions attributed to this regulatory option for flares are the SO2 emissions released 

when the gas being flared meets the long-term sulfur concentration requirement. Similar to the 

calculations for FGCD, SO2 emissions for flares without coking unit gas meeting the long-term 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

10

sulfur concentration requirement are based on a reduction of 102 ppmv H2S (162 – 60 ppmv 

H2S), and the SO2 emissions were estimated to be 0.00047 lb SO2/min, or 0.12 ton SO2/yr 

(assuming an ideal gas at 20 °C and 1 atmosphere, 60 ppmv H2S for 48 scfm is equivalent to 

0.00025 lb H2S/min, or 0.00047 lb SO2/min). 

As with FGCD, the amine treatment system is not expected to reduce mercaptans for flare gas 

from a coking unit, so SO2 emissions reductions for flare gas from a coking unit are also based 

on a reduction of 102 ppmv H2S [(300 ppmv mercaptans + 162 ppmv H2S) – (300 ppmv 

mercaptans + 60 ppmv H2S)]. Therefore, for fuel gas systems with a coking unit, the SO2

emissions when meeting the long-term H2S concentration requirement for fuel gas were 

estimated to be 0.0028 lb SO2/min, or 0.75 ton SO2/yr (assuming an ideal gas at 20 °C and 

1 atmosphere, a reduction of 102 ppmv H2S for 48 scfm is equivalent to a reduction in reduced 

sulfur compounds of 0.00043 lb/min, or a reduction of 0.00081 lb SO2/min). 

The baseline SO2 emissions and the SO2 emissions for the two model flares (one with a coking 

unit and one without) meeting the long-term fuel gas sulfur concentration requirement for fuel 

gas are shown in Table 8. Table 8 also provides the nationwide emissions at baseline, the 

nationwide emissions for model flares meeting the 60 ppmv H2S long-term concentration 

requirement, and the SO2 emission reduction from the baseline for flares. 

Table 8. Emissions for Model Flares Meeting Long-Term Sulfur Concentration 

Requirement for Fuel Gas Sent to Flares 

Conditions 

Emissions from Model Flare Nationwide 

Emissions 

(ton SO2/yr) 

Reduction from 

baseline 

(ton SO2/yr) 

Without a coking 

unit (ton SO2/yr) 

With a coking unit 

(ton SO2/yr) 

Baseline 0.34 0.96 131 --- 

60 ppmv H2S 0.12 0.75 72 59 

While SO2 reductions are the primary focus of the long-term H2S concentration requirement for 

fuel gas, when these reductions are accomplished via flare gas recovery, there are also reductions 

in other pollutants, such and nitrogen oxides (NOX) and volatile organic compounds (VOC). As 

described in Section 5.A of this memorandum, the lower heating value for flare gas is estimated 

to be 1,440 Btu/scf (lower heating value basis). Using the emission factors for NOX, in EPA’s 

Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources

(AP-42) (U.S. EPA, 1995), recovery of 48 scfm of gas from being discharged to the flare would 

reduce NOX emissions by 1.2 tons/yr per flare. Only a small fraction of the VOC in the flare gas 

will be emitted, as the flare is expected to achieve 98 percent destruction efficiency. If that gas is 

recovered, it will likely be burned in an alternate combustion source such as a process heater or 

boiler. Assuming the alternate combustion source achieves 99 percent destruction efficiency, a 

net 1 percent reduction in VOC emissions is expected to be achieved due to flare gas recovery. 

If 25 percent of the flare gas is VOC with an average molecular weight of 58 g/mol, recovering 

48 scfm of flare gas is expected to yield VOC emission reductions of 4.8 tons/yr per flare. 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

11

B. Cost Analysis 

Based on industry information described previously, it was estimated that to meet the long-term 

sulfur concentration requirement, existing and new affected flares would need to add a flare gas 

recovery system to recover flare gas not meeting the sulfur concentration requirement. It is 

possible that some flares may need additional amine capacity to treat the recovered gas, but 

based on the small amount of gas recovered by the model flare (48 scfm), it is assumed for 

purposes of this analysis that once the gas is recovered, existing amine treatment systems at the 

refinery could handle the additional gas. Cost estimates were derived based on a series of flare 

gas recovery projects reported in the literature (John Zink Co, 2006; Envirocomb Limited, 2006; 

U.S. DOE, 2005). From these case studies, the following cost equations were developed: 

Total Capital Investment (TCI) Costs 

TCI ($) = 1,000,000 + 10,000,000 (FlowRate/876,000)0.65 (Eqn. 1) 

 Annual Operating Costs (AOC) 

AOC ($/yr) = 100,000 + 100,000 (FlowRate/876,000) (Eqn. 2) 

where: 

FlowRate = flare gas recovery system design flow rate, 1,000 scf/yr. 

The capital cost estimates include system design, costs of retrofitting the water seal and other 

ancillary equipment, and installation. The equations calculate the cost of installing a recovery 

system when constructing a new flare; to calculate the cost of retrofitting a reconstructed or 

modified flare with a recovery system, the capital cost was multiplied by a factor of 1.2. Capital 

costs were annualized using a 10-year equipment life and a 7 percent annual interest rate. In 

addition, the annualized costs include taxes and insurance equal to 4 percent of the capital cost. 

All costs are in 2006 U.S. dollars. 

Control costs were estimated using a system design flow rate of 50,000,000 scf/yr, or twice the 

average flow rate of the flare, so that the recovery system would be capable of handling 

variations in flow to the flare (i.e., capable of recovering short-term flaring events above the 

average annual flow rate to the flare). For each system, 80 percent of the flare gas is expected to 

be recovered, and all of the recovered flare gas can be used to reduce the refinery’s natural gas 

purchases. The other 20 percent would be unable to offset natural gas purchases due to 

undesirable characteristics (e.g., a heating value too low for combustion). The heat content of 

the recovered gas was calculated based on the estimated average heating value of the flare gas 

(i.e., 1,600 British thermal units per standard cubic foot [Btu/scf]). Natural gas has a heat 

content of approximately 1,028 Btu/scf (DOE, 2007, Table B2); therefore, each scf of flare gas 

recovered off-sets the purchase of 1.55 scf of natural gas. The average industrial cost of natural 

Comment [A11]: Although taxes should be 

reported as a cost to refiners, they are not a social 

cost. 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

12

gas was $7.86/1,000 scf (DOE, 2007, Table 23) in 2006 and was $5.33/1,000 scf (DOE, 2010, 

Table 23) in 2009; therefore, a value of $5.00 per 1,000 scf was used in the analysis to account 

for times when the recovered gas cannot offset natural gas purchases (assumed to be roughly 

10 percent of the time). 

Monitoring costs were also estimated for measuring the flow rate and sulfur content of gas to the 

flare. The capital costs of these monitors were estimated as $300,000 and the annual operating 

costs were estimated as $50,000. These costs are approximately 1.5 times the costs for these 

monitors as estimated by the CEMS Cost Model (U.S. EPA, 2007) to account for additional costs 

associated with monitoring highly flammable gases. The capital costs of the monitoring system 

were annualized using a 10-year equipment life and a 7 percent annual interest rate. 

Table 9 presents the estimate of the numbers of affected flares; the derivation of these estimates 

was described in Sections 2 and 3. Table 10 is a summary of the emission reductions and costs 

for each of the models for flares. Given the number of each model flare as presented in Table 9 

and the costs and emission reductions per model flare, the nationwide impacts of the long-term 

sulfur concentration requirement for fuel gas sent to flares can be calculated; these results are 

presented in Table 11 (which is identical to Table 2). 

Table 9. Number of Affected Flares for Each Model and Scenario 

Flare Model and Scenario Number of Flares 

New, without a coking unit 22 

New, with a coking unit 6 

Modified/Reconstructed, without a coking unit 199 

Modified/Reconstructed, with a coking unit 53 

Comment [A12]: Please explain why you do not 

use EIA projections of gas prices over next 5 years. 

Comment [A13]: Should probably also do 3% as 

per OMB guidance. 

Comment [A14]: Was the estimate of the new 

units estimates described n these sections? 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the 

Petroleum Refinery NSPS 

January 25, 2012 

13

Table 10. Summary of Costs for a Single Flare to Meet the Long-Term Sulfur Concentration Requirement for Fuel Gas 

Affected Flare 

SO2

Emission 

Reduction 

(ton/yr) 

Recovery System Costs 

Capital Cost 

($1,000) 

Annual 

Operating Cost 

($1000/yr) 

Natural Gas 

Offsets 

($1000/yr) 

Net Annual 

Operating Cost 

($1000/yr) 

Total Annual 

Cost 

($1000/yr) 

New, without a coking unit 0.21 2,900 270 160 110 520 New, with a coking unit 0.21 2,900 270 160 110 520 Modified/ Reconstructed, without a coking unit 0.21 3,400 290 160 140 620 Modified/ Reconstructed, with a coking unit 0.21 3,400 290 160 140 620 

Table 11. Projected National Fifth Year Impacts of Long-Term Sulfur Concentration Requirement for Fuel Gas Sent to 

Potentially Affected Flares 

Process Unit 

Capital 

cost 

($1,000) 

Annual 

operating cost 

without 

natural gas 

offset ($1,000) 

Natural 

gas 

offset 

($1,000) 

Net 

annual 

operating 

cost 

($1,000) 

Total 

annual 

cost 

($1,000/ 

yr) 

SO2

Emission 

reduction 

(ton 

SO2/yr) 

NOX

Emission 

reduction 

(ton 

NOX/yr) 

VOC 

Emission 

reduction 

(ton 

VOC/yr) 

Cost 

effective

ness 

($/ton) 

New Flares 80,000 8,000 (4,000) 3,200 15,000 6 34 130 84,000 Modified and Reconstructed Flares 860,000 74,000 (39,000) 35,000 160,000 53 310 1,200 100,000 Total 900,000 80,000 (44,000) 38,000 170,000 59 340 1,300 99,000 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

14

5. Other Standards for Flares

This section describes the development of costs and emissions estimates for the requirements for 

flaring events, including a flare management plan, RCA for a discharge that causes 500 lb SO2

emissions in a 24-hour period; and RCA for a discharge that causes flow rate to a flare in excess 

of 500,000 scf above a baseline flow rate defined in the flare management plan within a 24-hour 

period. 

A. Flow Estimates 

Carbon monoxide (CO) emissions from flares that were reported in the 2002 NEI were used to 

estimate the amount of fuel gas discharged to flares. CO emissions were reported specifically for 

the flare SCC for 252 flares at 77 refineries; these data are summarized in Attachment A. It is 

anticipated that some facilities/ states did not estimate CO emissions from flares or the emissions 

were reported using a more generic SCC code. As such, the fact that approximately 50 percent 

of the refineries reported CO emissions for flares is not surprising. The CO emissions reported 

in the NEI were assumed to be representative of the refinery flare usage nationwide. 

The CO emission factor for flares in EPA’s Compilation of Air Pollutant Emission Factors, 

Volume 1: Stationary Point and Area Sources (AP-42) is 0.37 pounds per million British thermal 

units (lb/MMBtu) (U.S. EPA, 1995). If 1 ton/yr of CO emissions were reported, then that 

facility is expected to have flared 5,405 million British thermal units per year (MMBtu/yr) of gas 

(1 ton/yr × 2000 lb/ton / 0.37 lb/MMBtu). 

The composition of refinery flare gas is highly variable. Table 12 presents ranges of flare gas 

composition reported in the literature (Peterson et al., 2007). The average composition of flare 

gas as reported in Table 12 was used to estimate a typical heat content of flare gas. The lower 

heating value (LHV) was calculated to be 1,540 Btu/scf and the higher heating value (HHV) was 

calculated to be 1,680 Btu/scf. The LHV is usually used for flares when calculating emissions, 

but if the fuel is recovered and used in process heaters, the HHV is typically monitored. For the 

purposes of this assessment, the fuel gas was assumed to have a HHV of 1,600 Btu/scf and a 

LHV of 1,440 Btu/scf. The LHV was used to estimate the flare flow rate from the CO emissions 

data and the HHV was used to estimate the amount of natural gas purchases that could be offset 

if the flare gas is recovered. Continuing the example of 1 ton/yr of CO, the 5,405 MMBtu/yr 

would equate to a flare gas flow rate of 3.75 million standard cubic feet per year (MMscf/yr). 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

15

Table 12. Typical Waste Gas Composition and Range 

Flare gas component 

Gas Composition Range 

Minimum, % Maximum,% Average,% 

Methane CH4 7.17 82 43.6 

Ethane C2H6 0.55 13.1 3.66 

Propane C3H8 2.04 64.2 20.3 

n-Butane C4H10 0.199 28.3 2.78 

Isobutane C4H10 1.33 57.6 14.3 

n-Pentane C5H12 0.008 3.39 0.266 

Isopentane C5H12 0.096 4.71 0.53 

neo-Pentane C5H12 0 0.342 0.017 

n-Hexane C6H14 0.026 3.53 0.635 

Ethylene C2H4 0.081 3.2 1.05 

Propylene C3H6 0 42.5 2.73 

1-Butene C4H8 0 14.7 0.696 

Carbon monoxide CO 0 0.932 0.186 

Carbon dioxide CO2 0.023 2.85 0.713 

Hydrogen sulfide H2S 0 3.8 0.256 

Hydrogen H2 0 37.6 5.54 

Oxygen O2 0.019 5.43 0.357 

Nitrogen N2 0.073 32.2 1.3 

Water H2O 0 14.7 1.14 

Source: Peterson et al., 2007 

Reported CO emissions were converted to flare gas flow rates using the AP-42 emission factor 

and average flare gas heating value as described above. Ten model flares were developed from 

these data. The 5th percentile flare flow rate from the data set was used to represent the smallest 

10 percent of flares. The 15th percentile flare flow rate from the data set was used to represent 

the next smallest 10 percent of flares, and so on so that the 95th percentile flare flow rate was 

used to represent the largest 10 percent of flares. Table 13 summarizes the model flares resulting 

from this analysis. 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

16

Table 13. Model Flare Flow Rates 

Plant Model 

Flow to flare 

(1000 scf/yr) 

Model Flare 1 (5th percentile, 0 to 10%) - 

Model Flare 2 (15th percentile, 10 to 20%) 969 

Model Flare 3 (25th percentile, 20 to 30%) 3,754

Model Flare 4 (35th percentile, 30 to 40%) 11,070 

Model Flare 5 (45th percentile, 40 to 50%) 21,006

Model Flare 6 (55th percentile, 50 to 60%) 40,648 

Model Flare 7 (65th percentile, 60 to 70%) 49,926 

Model Flare 8 (75th percentile, 70 to 80%) 101,351 

Model Flare 9 (85th percentile, 80 to 90%) 167,505 

Model Flare 10 (95th percentile, 90 to 100%) 675,931 

Note that for this analysis, each model flare represents 10 percent of the 400 total affected flares 

in the industry, or 40 flares. Model Flares 1, 2, and 3 represent a total of 120 flares that handle 

only startup, shutdown, and upset gases, which is consistent with the flare counts presented in 

Section 2 of this memorandum, and Model Flares 4 through 10 represent the remaining 280 

impacted flares. 

B. Cost Analysis for Flare Recovery and Monitoring System 

To determine the cost impacts of the requirements for flaring events, or “other standards,” it was 

assumed that a flare gas recovery system would be considered for flares with average releases 

greater than the RCA and corrective action analysis threshold of 500,000 scf per 24 hours 

(183 MMscf/yr) above baseline. At this action level, only the flares represented by Model 

Plant 10 in Table 13 would consider installing a flare gas recovery system. Owners or operators 

of flares receiving routine flows that can offset natural gas purchases by recovering flare gas are 

likely to conclude that installing a flare gas recovery system would be a cost effective alternative 

to the flaring event requirements. For this assessment, it was assumed that all of the flares 

represented by Model Plant 10 would install a flare gas recovery system as a result of their flare 

management plan analyses. Cost estimates were derived as described in Section 4.B. Control 

costs were estimated using the model plant flow rates as the system design flow rate. Each 

model system was estimated to recover 80 percent of the flare gas design flow rate. As discussed 

in Section 4.B, the recovered flare gas is expected to reduce the refinery’s natural gas purchases; 

each scf of flare gas recovered off-sets the purchase of 1.55 scf of natural gas, and a value of 

$5.00 per 1,000 scf of natural gas was used for this analysis (see Section 4.B of this 

memorandum). 

Monitoring costs were also estimated for measuring the flow rate and sulfur content of gas to the 

flare to comply with these standards. The capital costs of these monitors were estimated as 

Comment [A15]: How was this level chosen? 

Why only at that action level would facilities 

consider installing a flare gas system? 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

17

$300,000 and the annual operating costs were estimated as $50,000. These costs are 

approximately 1.5 times the costs for these monitors as estimated by the CEMS Cost Model 

(U.S. EPA, 2007) to account for additional costs associated with monitoring highly flammable 

gases. The capital costs of the monitoring system were annualized using a 10-year equipment 

life and a 7 percent annual interest rate. 

The total capital cost of a flare gas recovery system for certain flares and monitors for 280 flares 

is $460 million, and the total annual cost savings is $76 million (including an annual cost of 

$92 million and a natural gas offset of $170 million). 

C. Costs for Root Cause Analysis and Flare Management Plan 

Three different standards were included in this step of the analysis: RCA and corrective action 

analysis based on SO2 emissions; a flow rate RCA and corrective action analysis for reducing 

volatile organic compound (VOC) emissions; and a flare management plan for, among other 

things, minimizing flow and emissions from refinery process units connected to an affected flare. 

These standards primarily require additional labor hours to perform the RCA, determine the 

proper corrective action, or to evaluate the start-up and shutdown procedures to identify ways to 

reduce flaring. The following labor rates were used in the analysis: 

Labor Category Hourly Wage

Environmental engineering labor cost, $/hr (BLS May 2006, SOC 17-2081) $38.29 

General and operations managers labor cost, $/hr (BLS May 2006, SOC 11-1021) $57.58 

General office and admin support labor cost, $/hr (BLS May 2006, SOC 43-0000) $17.46 

Labor requirements were made based on direct technical hours (i.e., hour of environmental 

engineering). For each technical hour, 0.05 hours of management time and 0.1 hours of 

administrative support time were projected to be required. In addition, benefits and other 

overhead costs were estimated to be 60% of the direct labor costs. As such, each technical hour 

was estimated to cost $68.66 [($38.29 + 0.05 × $57.58 + 0.1 × $17.46) × 1.6]. 

An estimated 45 labor hours would be required to perform each RCA and associated corrective 

action analysis (whether triggered by SO2 or flow). The flare management plan was estimated to 

require 160 technical labor hours to develop. Unlike the direct control systems, these standards 

are expected to initiate routine operational or maintenance practices that will typically avoid a 

periodic emission event that may not occur again for one or two years. 

One of the primary considerations for the impacts of the RCA and corrective action analysis is 

the threshold at which the analyses are triggered. For the SO2 RCA and corrective action 

analysis, the refinery consent decrees have established a trigger of 500 lb in any 24-hour period. 

Using this as the threshold for the SO2 analyses, the cost effectiveness is estimated to be 

Comment [A16]: Please explain - this is the first 

mention of this. 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

18

approximately $490/ton of SO2 emissions avoided in the fifth year and an average of $760/ton of 

SO2 emissions avoided per year over the first 5 years. 

For the VOC/flow rate-based RCA and corrective action analysis trigger, it is assumed that the 

standards would reduce malfunctions and upsets that release VOC that would otherwise become 

product. Therefore, the cost savings is based on the value of the product rather than a reduction 

in natural gas purchases. The value of the product is assumed to be $560/ton of VOC, which is 

an approximate conversion from an estimate of $1.75 per gallon. That estimate assumes that the 

value of recovered VOC is consistent with the average of the price of brent crude (crack spread 

spot price of $74.96 per barrel ($1.78 per gallon) on September 7, 2007) and the product value 

(crack spread spot price of $87.04 per barrel ($2.08 per gallon) on September 7, 2007) (Stell, 

2007). The value of the product also assumes that the average petroleum refinery process stream 

has a specific gravity of 0.75. It is also assumed that the flares are operating properly and 

achieve a VOC destruction efficiency of 98 percent. In other words, 100 lb of VOC sent to the 

flare results in 2 lb of VOC emissions from the flare (the other 98 lb are converted to combustion 

products carbon dioxide and water). Therefore, the product credit of $560/ton of VOC sent to 

the flare is equivalent to $28,000 per ton of VOC emissions avoided. When the costs of 

conducting the analyses at flow events exceeding 500,000 scf in any 24-hour period are 

combined with the VOC credits, the resulting cost effectiveness is estimated to be a cost savings 

of $26,000/ton of VOC emissions avoided in the fifth year and an average cost savings of 

$15,000/ton of VOC emissions avoided per year over the first 5 years. 

Tables 14 and 15 summarize some of the key inputs for the cost and emission reduction 

calculations as well as the overall costs and emissions reductions for this regulatory option. 

Consistent with other impacts, over 5 years, a total of 150 different refineries were projected to 

become subject to the root cause analysis requirements (50 refineries in each of the first 3 years). 

In addition, owners and operators would be required to develop a flare management plan for all 

400 affected flares. Average annual nationwide costs in the fifth year were estimated as the 

average costs across the 5-year period (as the annual costs were generally higher in Year 3 than 

in Year 5). The annual emission reductions achieved in Year 5 were used directly. 

Comment [A17]: Did EPA run this analysis with 

a range of values, rather than a point estimate? 

Comment [A18]: Why is year 3 higher than year 

5? 

Comment [A19]: Why was Year 5 chosen? 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

19

Table 14. Key Inputs and Outputs for SO2 RCA and Corrective Action Analysis 

Item Description 

Refineries 

Affected 

SO2 Discharge Size 

Large Medium Small 

Labor required to perform each RCA and 

corrective action analysis 45 hours 45 hours 45 hours 

Emissions over 24 hours 6.25 tons 2.5 tons 0.5 tons 

Success rate of RCA/corrective action 35% 35% 35% 

Reduction efficiency for successfully avoided 

event 

100% of 

SO2

100% of 

SO2

100% of 

SO2

Average mass emissions per avoided event 2.19 tons 0.88 tons 0.18 tons 

Events per refinery (avg.), Year 1 50 5 3 2 

Events per refinery, Year 2 100 4 3 2 

Events per refinery, Year 3 150 3 2 1 

Events per refinery, Year 4 150 2 2 1 

Events per refinery, Year 5 150 1 1.2 0.5 

Cost per analysis ($) 3,090 

Nationwide average annual cost over 5 years ($1000/yr) 2,160 

Nationwide annual emission reductions (ton SO2/yr) 2,900 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

20

Table 15. Key Inputs and Outputs for Flow RCA and Flare Management Impacts 

Item Description VOC/Flow RCA Flare Management 

Size of average event 2,000,000 scf/ 

24 hours1 1,000,000 scf/ event2

Labor required to comply with requirements 45 hours 160 hours 

Success rate of RCA/corrective action 35% N/A 

Reduction efficiency for successfully avoided event 2% for VOC3

100% of SO2

2% for VOC3

Average mass emissions per avoided event 0.75 tons4 VOC 0.38 tons4 VOC 

Product recovery credit ($/day) 21,085 

Number of new refineries per year 50 each in Years 

1-3 -- 

Number of new flares per year -- 140 in Year 1; 130 each 

in Years 2 and 3 

Events per year (avg.), Year 1 5 per refinery 2 per flare 

Events per year, Year 2 4 per refinery 2 per flare 

Events per year, Year 3 3 per refinery 2 per flare 

Events per year, Year 4 2 per refinery 2 per flare 

Events per year, Year 5 1.5 per refinery 2 per flare 

Cost per analysis or plan ($) 3,090 11,000 

Nationwide average annual cost over 5 years ($1000/yr) 1,000 880 

Nationwide average annual credit over 5 years ($1000/yr) (7,400) -- 

Overall nationwide average annual cost over 5 years 

($1000/yr) (6,400) 880 

Nationwide annual VOC emission reductions (ton VOC/yr) 430 300 

Nationwide annual SO2 emission reductions (ton SO2/yr) 3.8 -- 

Nationwide annual NOX emission reductions (ton NOX/yr) 56 -- 

1 Average size of event that exceeds 500,000 scf. 

2 Estimated size of a planned startup or shutdown. 

3 Based on a flare destruction efficiency of 98 percent. 

4 VOC content of the flared gases was estimated to be 25 percent of the volumetric flow with an average molecular 

weight of for VOC of 58 g/mol (based on butane). 

For the two standards for which credits are estimated (natural gas offset credit for flare gas 

recovery on larger flares and product recovery credit for flow rate RCA), the magnitude of the 

credit is dependent on either the cost of natural gas or the value of the recovered product. To 

evaluate the sensitivity of the analysis to these values, the analysis was repeated with the cost at 

the low end of the potential ranges for natural gas price and product credit. If the natural gas 

price is reduced to $3.50/scf, then the total annual natural gas offset for flare gas recovery for 

larger flares is reduced from $170 million to $120 million, and the total annual cost savings is 

reduced from $76 million to $26 million. If VOC is reduced to $400/ton (an approximate 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

21

conversion from an estimate of $1.00 per gallon based on the average of the price of crude 

($31.84 per barrel on December 26, 2008) and the price of gasoline ($1.255 per gallon without 

taxes in December 2008) (Stell, 2009)), then the total annual product recovery credit for flow 

rate RCA is reduced from $7.4 million to $5.3 million, and the total annual cost savings is 

reduced from $6.4 million to $4.3 million. Considering these minimal credits and offsets 

together, then the overall total annual cost of all four flaring event standards would be reduced 

from a savings of $79 million to a savings of $27 million. Therefore, although the analysis 

depends on the magnitude of the credits and offsets, consideration of minimal values for these 

credits and offsets still results in an annual cost savings. (In fact, based on this analysis, natural 

gas cost could dip to as low as $3.00/scf and VOC could be as low as $50/ton and these 

standards would continue to result in an annual cost savings.) 

The cost and emission reduction impacts of the final standards presented in Table 16 (identical to 

Table 3) were calculated as the sum of the impacts for flare gas recovery systems (expected to be 

needed for approximately 10 percent of the affected flares to limit the number of events above 

500,000 scf/24 hrs above baseline), the impacts for SO2 and flow root cause analyses, the 

impacts of flare management plans, and the impacts of flow and sulfur monitors associated with 

the flaring event requirements. 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the 

Petroleum Refinery NSPS 

January 25, 2012 

22

Table 16. Projected National Fifth Year Impacts of Other Standards for Potentially Affected Flares 

Standard 

Capital 

cost 

($1,000) 

Total annual cost without 

offset or 

credit ($1,000) 

Annual 

offset or 

credit 

($1,000) 

Total 

annual cost 

($1,000/ yr) 

Emission 

reduction 

(ton 

SO2/yr) 

Emission 

reduction 

(ton 

NOX/yr) 

Emission 

reduction 

(ton 

VOC/yr) 

Overall cost 

effectiveness ($/ton) 

Sulfur and Flow Rate Monitoring + Recovery for Largest Flares 

460,000 92,000 (170,000) (76,000) 370 1.100 2,700 (18,000) 

Flare Management Plan -- 880 -- 880 -- -- 300 2,900 SO2 RCA/ Corrective Action 

Analysis -- 2,200 -- 2,200 2,900 -- -- 760 

Flow Rate RCA/ Corrective Action Analysis -- 1,000 (7,400) (6,400) 3.8 56 430 (13,100) Grand Total 460,000 96,000 (180,000) (79,000) 3,200 1,100 3,400 (10,000) 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

23

The final parameter evaluated was the reduction in CO2 emissions due to flow rate RCA and 

flare gas recovery. An emissions factor of 211,641.6 lb/MMscf was used, converted from the 

emissions factor of 60 kg/MMBtu from the Mandatory Greenhouse Gas Reporting Rule based on 

the heat content of fuel gas given in Section 4.B of this memorandum. For the flow rate RCA, 

the CO2 emissions factor was applied to the flow rate of releases prevented in the fifth year, 

1,138 MMscf/yr, for an emissions reduction of 120,000 ton/yr, or 110,000 metric tonnes per year 

(tonne/yr). For flare gas recovery, the CO2 emissions prevented per large flare were estimated 

by applying an 80 percent recovery factor (see Section 4.B of this memorandum) to the CO2

emissions for Model Flare 10 without a flare gas recovery system (65,000 ton/yr; see Section 4.A 

and Attachment A of this memorandum), resulting in an emissions reduction of 52,000 ton/yr per 

flare for flares that install flare gas recovery. For 40 large flares, the CO2 emissions reductions 

would be 2.1 million ton/yr, or 1.9 million tonne/yr. 

In addition to the primary emissions reduction impacts, the secondary CO2 emissions generated 

as the result of the electricity needed to operate the compressors for flare gas recovery systems 

were evaluated. Based on information provided by Envirocomb Limited (2006), 1,927 megawatt 

hours per year (MWh/yr) would be needed to operate a system designed to handle a flare flow of 

1,000 to 1,600 cubic meters per hour (m3

/hr); the midpoint of that range, 1,300 m3/hr, is equal to 

a flow rate of 424 million scf/yr. Based on these values, a flare gas recovery system would need 

4.5 MWh of electricity for every 1 million scf of design capacity. Given that Model Flare 10 is 

676 million scf/yr, the additional electrical consumption for Model Flare 10 would be 

3,100 MWh/yr, or 120,000 MWh/yr for 40 flares. If the additional electricity is purchased from 

a power plant, the standards will increase secondary CO2 emissions by 110,000 ton/yr, or 

100,000 tonne/yr. 

The final estimate of CO2 emissions reductions, considering the reductions from both flare 

requirements as well as the secondary impacts described above, would be 2.1 million ton/yr, or 

1.9 million tonne/yr. See Table 17 for a summary of the CO2 emissions reduction impacts. 

Table 17. Nationwide Estimate of CO2 Emissions Reductions for Flare Standards1

Standard 

CO2 emissions 

reductions (ton/yr) 

CO2 emissions 

reductions (tonne/yr) 

Electricity Generation for Flare Gas Recovery 

(120,000 MWh/yr Nationwide) (110,000) (100,000) 

Flare Gas Recovery for Largest Flares 2,100,000 1,900,000 

Flow Rate RCA/ Corrective Action Analysis 120,000 110,000 

Total 2,100,000 1,900,000 

1

 Emissions reductions are shown as positive values; emissions increases are shown as negative values 

(i.e., negative reductions). 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

24

6. References

Cade, R. 2009. Marathon Petroleum Company LLC Comments on EPA Proposed Amendments 

to Proposed Standards of Performance for Petroleum Refineries for Which Construction, 

Reconstruction, or Modification Commenced After May 14, 2007 (Proposed 40 CFR 60 

Subpart Ja). Letter to EPA Docket Center. February 3. Docket Item No. EPA-HQ-OAR2007-0011-0296. 

Chittim, R. 2007. Comments of American Petroleum Institute (API), the National 

Petrochemical and Refiners Association (NPRA), and the Western States Petroleum 

Association (WSPA) on the proposed Standards of Performance for Petroleum Refineries: 

Proposed Rule. Letter to EPA Docket Center. August 27. Docket Item No. EPA-HQ-OAR2007-0011-0154. 

Chittim, R. 2009. Comments of American Petroleum Institute (API), the National 

Petrochemical and Refiners Association (NPRA), and the Western States Petroleum 

Association (WSPA) on the Standards of Performance for Petroleum Refineries: Proposed 

Amendments. Letter to EPA Docket Center. February 5. Docket Item No. EPA-HQ-OAR2007-0011-0311. 

Energy Information Administration (EIA), U.S. Department of Energy. 2006. Refinery 

Capacity Report 2006. June 15. Docket Item No. EPA-HQ-OAR-2007-0011-0048. 

Envirocomb Limited. 2006. Zero flaring by flare gas recovery. Presented at the Gas Processors 

Association 1st Specialized Technical Session: Zero Flaring Seminar. Al-Khobar, Saudi 

Arabia, November 29. Available at: http://www.gpa-gccchapter.org/PDF/Zero%20Flaring%20By%20Flare%20Gas%20Recovery.pdf 

Fedich, R.B., A.C. Woerner, and G.K. Chitnis. 2004. “Selective H2S Removal.” Hydrocarbon 

Engineering, Vol. 9, No. 5, pp. 89-92. May. Docket Item No. EPA-HQ-OAR-2007-0011-

0032. 

Feerick, C. 2007. ExxonMobil Comments on NSPS Ja Proposed Rule. Letter to EPA Docket 

Center. August 24. Docket Item No. EPA-HQ-OAR-2007-0011-0148. 

Feerick, C. 2009. ExxonMobil Comments on Proposed Revisions to NSPS Ja. Letter to EPA 

Docket Center. February 5. Docket Item No. EPA-HQ-OAR-2007-0011-0301. 

Garg, D. 2007. Valero Energy Corporation Comments on the Proposed Revisions to New 

Source Performance Standards Subpart J and the Proposed Promulgation of Subpart Ja. 

Letter to EPA Docket Center. August 27. Docket Item No. EPA-HQ-OAR-2007-0011-

0138. 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

25

John Zink Company. 2006. Flare gas recovery (FGR) to reduce plant flaring. Presented at the 

Gas Processors Association 1st Specialized Technical Session: Zero Flaring Seminar. AlKhobar, Saudi Arabia, November 29. Available at: http://www.gpa-gccchapter.org/PDF/Flare%20Gas%20Recovery%20White%20Paper.pdf

Peterson, J., N. Tuttle, H. Cooper, and C. Baukal. 2007. Minimize facility flaring. 

Hydrocarbon Processing. June. Pp. 111-115. Available at: 

http://www.johnzink.com/products/flares/pdfs/flare_hydro_proc_june_2007.pdf. 

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. 

Docket Item No. EPA-HQ-OAR-2007-0011-0020. 

http://www.bre.com/portals/0/technicalarticles/Alternative%20Flow%20Schemes%20to%20

Reduce%20Capital%20and%20Operating%20Costs%20of%20Amine%20Sweetening%20U

nits.pdf. 

Saffell, K. 2009. Valero Energy Corporation Comments on the Proposed Amendments to New 

Source Performance Standards (“NSPS”), Subpart J and Subpart Ja. Letter to EPA Docket 

Center. February 5. Docket Item No. EPA-HQ-OAR-2007-0011-0310. 

Schaeffer, E. 2008. TCEQ Refinery Emission Data. Email to K. Hustvedt, USEPA, from E. 

Schaeffer, Environmental Integrity Project. September 25. 

Stell, J., ed. 2005. “2005 Worldwide Refining Survey.” Oil & Gas Journal, Vol. 103, No. 47. 

(Available online only: http://www.ogj.com/resourcecenter/survey.cfm#worldref.) 

Stell, J., ed. 2007. “Statistics,” Oil & Gas Journal, Vol. 105, Issue 35. “OGJ Crack Spread,” p. 

90. September 17. 

Stell, J., ed. 2009. “Statistics,” Oil & Gas Journal, Vol. 107, Issue 2. “OGJ Gasoline Prices” 

and “World Crude Prices,” p. 57. January 12. 

U.S. Department of Energy. 2005. Petroleum Best Practices Plant-wide Assessment Case 

Study. Valero: Houston refinery uses plant-wide assessment to develop an energy 

optimization and management system. DOE/GO-102005-2121. Available at: 

http://www1.eere.energy.gov/industry/bestpractices/pdfs/valero.pdf. 

U.S. Department of Energy, Energy Information Administration (EIA). 2007. Natural Gas 

Annual 2006. DOE/EIA-0131(06). October. Available at: 

http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/natural_gas_annual/historical/

2006/nga_2006.html. 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS 

January 25, 2012 

26

U.S. Department of Energy, Energy Information Administration (EIA). 2010. Natural Gas 

Annual 2009. DOE/EIA-0131(09). December. Available at: 

http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/natural_gas_annual/historical/

2009/nga_2009.html. 

U.S. EPA (Environmental Protection Agency). 1995. Compilation of Air Pollutant Emission 

Factors. Volume 1: Stationary Point and Area Sources. AP-42, Fifth Edition. Office of Air 

Quality Planning and Standards, Research Triangle Park, NC. 

U.S. EPA (Environmental Protection Agency), Emissions Measurement Center. 2007. CEMS 

Cost Model. http://www.epa.gov/ttn/emc/cem.html. March 7. 

Voltz, B.L., J.D. Corley, and R.B. Fedich. 2004. “Benefits of a TGCU Amine Solvent 

Changeover.” Sour Oil & Gas Advanced Technology 2004 International Conference. 

November. Docket Item No. EPA-HQ-OAR-2007-0011-0033. 

Wilkes, J. 2005. Letter to U.S. Department of Justice and U.S. Environmental Protection 

Agency containing Flint Hills Resources, L.P., Pine Bend, Minnesota Refinery Combined 

Technology Test Report (18-month report). September 26. 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-1

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

2 Hunt Refining Company 0.73 2,740 

2 Hunt Refining Company 0.73 2,740 

2 Hunt Refining Company 0.73 2,740 

8 Tesoro Alaska Company - Kenai 

Refinery 

Refinery Flare, J-801, Unit 

0042 

0.03 113 

8 Tesoro Alaska Company - Kenai 

Refinery 

Sru Flare, Unit 0043 0.03 113 

8 Tesoro Alaska Company - Kenai 

Refinery 

Refinery Flare, J-801, Unit 

0042 

5.43 20,383 

12 Lion Oil Company Sn822--823 High/Low Flare 13.80 51,802 

16 Chevron Usa Inc. - Richmond V-282 South Isom 3.65 13,701 

16 Chevron Usa Inc. - Richmond North Isomax Fla 3.65 13,701 

16 Chevron Usa Inc. - Richmond Fcc Flare V-731 3.65 13,701 

16 Chevron Usa Inc. - Richmond Alkane Flare 0.24 893 

16 Chevron Usa Inc. - Richmond "V-732, Alky-Poly" 0.08 282 

16 Chevron Usa Inc. - Richmond Refinery Waste G 3.65 13,701 

16 Chevron Usa Inc. - Richmond High Level Flare 3.65 13,701 

18 Shell Oil Products Us - Martinez Refinery Waste Gas F 11.60 43,532 

18 Shell Oil Products Us - Martinez Opc1_Fxg Flare 73.80 277,023 

18 Shell Oil Products Us - Martinez Logi2-Lpg Loadin 2.53 9,508 

18 Shell Oil Products Us - Martinez Lrgo Flare 0.30 1,115 

18 Shell Oil Products Us - Martinez Opc7_Hc Flare 24.66 92,583 

21 Tricor Refining (Prev. Golden Bear 

Oil Specialties) 

Lube Oil Finishing 0.00 - 

30.1 Conocophillips Co. - Rodeo (Prev. 

Phillips 66 Co.) 

Refinery Waste Gas F 5.48 20,552 

30.1 Conocophillips Co. - Rodeo (Prev. 

Phillips 66 Co.) 

C-1 Flare 15.51 58,228 

30.2 Conocophillips Co. - Santa Maria 

(Prev. Phillips 66 Co.) 

Incinerators 0.67 2,504 

31 Tesoro (Prev. Ultramar Inc.) 39.24 147,286 

31 Tesoro (Prev. Ultramar Inc.) 8.21 30,826 

31 Tesoro (Prev. Ultramar Inc.) 39.24 147,286 

31 Tesoro (Prev. Ultramar Inc.) 39.24 147,286 

31 Tesoro (Prev. Ultramar Inc.) 39.24 147,286 

33 Valero Refining Co. - Benicia Refinery Waste Gas F 15.51 58,228 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-2

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

33 Valero Refining Co. - Benicia Refinery Waste Gas F 5.48 20,552 

37 Valero Refining Co. (Prev. Motiva 

Enterprises LLC) 

Propane Pit Flare 1.60 6,006 

37 Valero Refining Co. (Prev. Motiva 

Enterprises LLC) 

Repower - Clean Gas Flare 798.30 2,996,622 

37 Valero Refining Co. (Prev. Motiva 

Enterprises LLC) 

Repower - Raw Gas Flare 112.40 421,922 

37 Valero Refining Co. (Prev. Motiva 

Enterprises LLC) 

Flare System 18.90 70,946 

37 Valero Refining Co. (Prev. Motiva 

Enterprises LLC) 

Accidental Releases 0.00 - 

39 Chevron Hawaii Refinery Fcc Flare, Vocs 19.51 73,236 

39 Chevron Hawaii Refinery Crude Flare, Vocs 19.51 73,236 

40 Tesoro Hawaii Corp. Refinery Flare 0.11 424 

40 Tesoro Hawaii Corp. Refinery Flare 49.56 186,051 

41 Pdv Midwest Refining Llc (Citgo 

Petroleum) 

South Refinery Flare Gas 

Recovery System 844c-3 

2.66 9,985 

46 Conocophillips Co. (Prev. Phillips 

66 Co.) 

Process Unit Vents To Flares 100.94 378,904 

46 Conocophillips Co. (Prev. Phillips 

66 Co.) 

N Prop Ground 

Flare(Hydrocarbon Recovery) 

13.27 49,812 

46 Conocophillips Co. (Prev. Phillips 

66 Co.) 

Aromatic High Pressure Flare 

(Hydrocarbon Recovery Flare) 

5.60 21,021 

46 Conocophillips Co. (Prev. Phillips 

66 Co.) 

Aromatic Low Pressure Flare 

(Hydrocarbon Recovery Flare) 

11.87 44,557 

46 Conocophillips Co. (Prev. Phillips 

66 Co.) 

Wrr-16 Alkylation Unit 60.53 227,215 

46 Conocophillips Co. (Prev. Phillips 

66 Co.) 

Distill Flare (Hydrocarbon 

Recovery) 

4.20 15,766 

48 Countrymark Cooperative Inc. Flare 3.21 12,064 

53 Marathon Petroleum Company Llc Point 0qu 0.00 - 

54 Somerset Refinery Inc Point 004 0.49 1,833 

56 Calcasieu Refining Co 0.00 - 

56 Calcasieu Refining Co 0.00 - 

57 Calumet Lubricants Co. - Cotton 

Valley 

 0.00 - 

61 Citgo Petroleum Corp. - Lake 

Charles 

 16.00 60,060 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-3

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 31.00 116,366 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 1.00 3,754 

61 Citgo Petroleum Corp. - Lake 

Charles 

 11.00 41,291 

61 Citgo Petroleum Corp. - Lake 

Charles 

 27.00 101,351 

61 Citgo Petroleum Corp. - Lake 

Charles 

 53.00 198,949 

61 Citgo Petroleum Corp. - Lake 

Charles 

 2.00 7,508 

61 Citgo Petroleum Corp. - Lake 

Charles 

 0.00 - 

62 Conocophillips Co. - Westlake 

(Prev. Conoco Inc.) 

 18.00 67,568 

66 Motiva Enterprises,Llc/Convent 0.00 - 

66 Motiva Enterprises,Llc/Convent 0.00 - 

66 Motiva Enterprises,Llc/Convent 35.00 131,381 

66 Motiva Enterprises,Llc/Convent 55.00 206,456 

66 Motiva Enterprises,Llc/Convent 108.00 405,405 

74 Valero Refining Co. - Krotz 

Springs 

 16.00 60,060 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-4

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

74 Valero Refining Co. - Krotz 

Springs 

 5.00 18,769 

78 Chevron Products Company, 

Pascagoula Ref 

Aa-384 159.00 596,847 

78 Chevron Products Company, 

Pascagoula Ref 

Aa-591 320.00 1,201,201 

78 Chevron Products Company, 

Pascagoula Ref 

Aa-381 134.00 503,003 

78 Chevron Products Company, 

Pascagoula Ref 

Aa-382 256.00 960,961 

78 Chevron Products Company, 

Pascagoula Ref 

Aa-383 263.00 987,237 

78 Chevron Products Company, 

Pascagoula Ref 

Aa-592 205.00 769,520 

78 Chevron Products Company, 

Pascagoula Ref 

Aa-757 102.00 382,883 

82 Cenex Harvest States 1.00 3,754 

83 Conocophillips Co. (Prev. Conoco 

Inc.) 

 3.00 11,261 

84 Exxonmobil Billings Refinery 8.00 30,030 

84 Exxonmobil Billings Refinery 0.00 - 

85 Montana Refining 0.00 - 

87 Hess Corporation (Prev. 

Amerada-Hess Corp.) 

RF; The Refinery Flare Is A 

Safety Device For Combusting 

Emergency Releases From 

11.14 41,817 

88 Sunoco, Inc. (Prev. Coastal Eagle 

Point Oil Co.) 

Refinery Fla; Refinery Plant 

Flare System To Control Relief 

Gas Releases Through 

5.78 21,697 

90 Valero Refining Co.- N.J. Sru Therm.Ox; Sru Thermal 

Oxidizer 

0.27 1,014 

91 Giant Industries Inc. - Bloomfield F-1 Flare Zink 1.22 4,580 

95 Bp Products North America Inc East Flare 276.66 1,038,514 

95 Bp Products North America Inc Sru #1 Flare 11.47 43,056 

95 Bp Products North America Inc West Flare 83.16 312,162 

95 Bp Products North America Inc East Acid Gas Flare 11.47 43,056 

96 Marathon Petroleum Company Llc North Area Flare 0.22 826 

96 Marathon Petroleum Company Llc South Area Flare 0.14 526 

99 Conocophillips Co. (Prev. Conoco 

Inc.) 

South Plant Flare 3.20 12,027 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-5

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

99 Conocophillips Co. (Prev. Conoco 

Inc.) 

Div. C Flare For Alky, Cat Poly 

Coker, #2 Reformer 

140.22 526,340 

99 Conocophillips Co. (Prev. Conoco 

Inc.) 

West Flare For Lube Plant, No. 

1 CTU, No. 4 CTU, SGP 

11.71 43,971 

99 Conocophillips Co. (Prev. Conoco 

Inc.) 

East Plant Flare - South For 

No. 3 Reformer 

6.94 26,059 

100 Wynnewood Refining Co. (Prev. 

Gary-Williams Energy Corp.) 

North Vapor Recovery Backup 

Flare 

0.04 150 

100 Wynnewood Refining Co. (Prev. 

Gary-Williams Energy Corp.) 

South Vapor Recovery Flare 4.28 16,066 

100 Wynnewood Refining Co. (Prev. 

Gary-Williams Energy Corp.) 

Peabody Flare 0.01 38 

101 Sinclair Oil Corp Flares No 1 & No 2 (Point 5) 53.81 201,989 

102 Sunoco Inc Wpu Flare Id 266 0.64 2,402 

102 Sunoco Inc #2 Alkyllation Flare Id 267 16.35 61,374 

102 Sunoco Inc Coker Flare Id 268 1.29 4,854 

102 Sunoco Inc Lube Flare Id 269 0.51 1,907 

104 American Refining Group Inc. Refinery Gas Flare 3.33 12,500 

105 Sunoco Inc (R&M)/Marcus Hook 

Refinery 

12 Plant Flare 2.15 8,071 

105 Sunoco Inc (R&M)/Marcus Hook 

Refinery 

10 Plant Flare 1.50 5,631 

106 Sunoco Inc. - Philadelphia Gp Flare 433 6.00 22,523 

106 Sunoco Inc. - Philadelphia Gp Flare 1231 40.60 152,402 

106 Sunoco Inc. - Philadelphia Gp Flare 1232 0.00 - 

106 Sunoco Inc. - Philadelphia Flare At Srtf 8.60 32,282 

107 Conocophillips Co. (Prev. Phillips 

66 Co.) 

Main Flare 237.10 890,015 

109 Valero Refining Co. (Prev. 

Premcor Refining, Prev. Williams 

Refining LLC) 

 93.90 352,477 

111 Alon USA Energy Inc. (Prev. Alon 

USA LP) 

Southside Flare 0.56 2,120 

111 Alon USA Energy Inc. (Prev. Alon 

USA LP) 

Tank From Flare 0.26 986 

111 Alon USA Energy Inc. (Prev. Alon 

USA LP) 

Crude Unit Flare 1.06 3,988 

111 Alon USA Energy Inc. (Prev. Alon 

USA LP) 

North Side Flare (East) 1.06 3,988 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-6

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

111 Alon USA Energy Inc. (Prev. Alon 

USA LP) 

Reformer Flare 0.38 1,424 

111 Alon USA Energy Inc. (Prev. Alon 

USA LP) 

Gtr Asphalt Vcu 0.05 193 

112 Total Petrochemicals Inc. (Prev. 

Atofina Petrochemicals, Inc.) 

Marine Dock Flare 1 7.96 29,880 

112 Total Petrochemicals Inc. (Prev. 

Atofina Petrochemicals, Inc.) 

Benzene Vapor Combustor 1.28 4,805 

112 Total Petrochemicals Inc. (Prev. 

Atofina Petrochemicals, Inc.) 

East End Tanks Flare 7.32 27,477 

113 Bp - Texas City Flare #3 10.82 40,614 

113 Bp - Texas City Flare #4 0.88 3,304 

113 Bp - Texas City Ultracracker Flare 1.97 7,394 

113 Bp - Texas City Flare No. 1 1.09 4,103 

113 Bp - Texas City Flare #2 4.81 18,054 

113 Bp - Texas City Hydrogen Plant Flare 0.69 2,596 

113 Bp - Texas City Resid/Cat Feed Flare 1.37 5,155 

113 Bp - Texas City Sulfur Recovery Unit 0.74 2,770 

113 Bp - Texas City Flare 11.76 44,141 

113 Bp - Texas City Aru Benzene Flare 0.45 1,705 

113 Bp - Texas City Acid Plant 0.00 - 

113 Bp - Texas City Aromatics Unit #2 5.39 20,233 

113 Bp - Texas City Wastewater Treatment Plant 

Flare 

47.99 180,143 

114 Western Refining Co. LP - North 

(Prev. Chevron USA Inc.) 

Rheniformer Flare 0.25 938 

114 Western Refining Co. LP - North 

(Prev. Chevron USA Inc.) 

Relief Gas Flare 3.00 11,261 

114 Western Refining Co. LP - South 

(Prev. Chevron USA Inc.) 

Process Flare 3.08 11,562 

114 Western Refining Co. LP - South 

(Prev. Chevron USA Inc.) 

S.W.S. Emergency Flare 0.49 1,839 

117 Pasadena Refining Systems Inc. 

(Prev. Crown Central Petroleum 

Corp.) 

Emergency Flare - East 1.37 5,154 

117 Pasadena Refining Systems Inc. 

(Prev. Crown Central Petroleum 

Corp.) 

Emergency Flare - West 3.64 13,661 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-7

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

118 Exxonmobil Corp. - Baytown Flare Stack 04 (Wlfs) 47.79 179,390 

118 Exxonmobil Corp. - Baytown Flare Stack 05 (Wlfs) 3.69 13,846 

118 Exxonmobil Corp. - Baytown Flare Stack 06 (Wlfs) 7.22 27,089 

118 Exxonmobil Corp. - Baytown Flare Stack 11 (Fecc) 0.16 602 

118 Exxonmobil Corp. - Baytown Flare Stack 14 (Fecc) 26.62 99,928 

118 Exxonmobil Corp. - Baytown Flare Stack 03 (Wlfs) 3.21 12,039 

118 Exxonmobil Corp. - Baytown Flare Stack 15 (Lcc) 6.09 22,875 

118 Exxonmobil Corp. - Baytown Flare Stack 16 (Lcc) 43.62 163,738 

118 Exxonmobil Corp. - Baytown Flare Stack 17 (Fncc) 6.86 25,735 

118 Exxonmobil Corp. - Baytown Flare Stack 20 6.86 25,735 

118 Exxonmobil Corp. - Baytown Flare Stack 21 (Fncc) 6.86 25,735 

118 Exxonmobil Corp. - Baytown Flare Stack 18 (Fncc) 6.86 25,735 

118 Exxonmobil Corp. - Baytown Flare Stack 22 (Fncc) 0.00 - 

118 Exxonmobil Corp. - Baytown Flare Stack 25 (Fxk) 0.00 - 

118 Exxonmobil Corp. - Baytown Flare Stack 26 (Fxk) 444.82 1,669,729 

118 Exxonmobil Corp. - Baytown Flare Stack 27 (Ps7) 1.28 4,816 

119 Exxonmobil Corp. - Beaumont Flare System Chd-1 Flare 13.03 48,914 

119 Exxonmobil Corp. - Beaumont Flare System Chd-2 Flare 2.00 7,505 

119 Exxonmobil Corp. - Beaumont Flare System High Pressure 

Flare 

13.03 48,914 

119 Exxonmobil Corp. - Beaumont Flare System Coker Flare 13.03 48,914 

119 Exxonmobil Corp. - Beaumont Flare System Low Pressure 

Flare 

13.03 48,914 

119 Exxonmobil Corp. - Beaumont Flare System No.6 Flare 13.03 48,914 

119 Exxonmobil Corp. - Beaumont Flare System No. 7 Flare 13.03 48,914 

119 Exxonmobil Corp. - Beaumont Flare System Fcc Flare 13.03 48,914 

119 Exxonmobil Corp. - Beaumont Flare System Isom Flare 13.03 48,914 

120 Flint Hills Resources Lp - Corpus 

Christi East 

West Flare 4.04 15,180 

120 Flint Hills Resources Lp - Corpus 

Christi East 

Emergency Flare 22.20 83,328 

120 Flint Hills Resources Lp - Corpus 

Christi West 

2nd Stage (Main,Ag,Uf)Flare 37.84 142,030 

120 Flint Hills Resources Lp - Corpus 

Christi West 

1st Stage Flare 14.92 55,991 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-8

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

120 Flint Hills Resources Lp - Corpus 

Christi West 

3rd Stage Flare 12.39 46,509 

121 Delek Refining Ltd (Prev. Lagloria 

Oil & Gas Co.) 

Flare No. 3 24.82 93,168 

121 Delek Refining Ltd (Prev. Lagloria 

Oil & Gas Co.) 

Flare No. 1 6.55 24,587 

121 Delek Refining Ltd (Prev. Lagloria 

Oil & Gas Co.) 

Flare No. 5 1.23 4,598 

121 Delek Refining Ltd (Prev. Lagloria 

Oil & Gas Co.) 

Flare No. 2 7.26 27,260 

121 Delek Refining Ltd (Prev. Lagloria 

Oil & Gas Co.) 

Flare No. 4 7.91 29,684 

121 Delek Refining Ltd (Prev. Lagloria 

Oil & Gas Co.) 

Wastewater Flare 1.12 4,204 

122 Houston Refining Lp Flare 338k0007 88.09 330,681 

122 Houston Refining Lp Flare 338k0008 216.80 813,812 

122 Houston Refining Lp Flare 338k0001 7.92 29,719 

122 Houston Refining Lp North Plant Flare ("Merox 

Flare") 

11.70 43,918 

122 Houston Refining Lp Flare 338k0005 0.58 2,160 

123 Marathon Petroleum Company Llc V.D.U. Flare 0.13 469 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

East Refinery Flare 62.59 234,964 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

West Refinery Flare 14.80 55,567 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

Cat Flare 39.24 147,301 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

Ngl Non-Corrosive Flare 131.52 493,699 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

Ngl Corrosive Flare 19.40 72,817 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

Ngl Acid Gas Flare 21.85 82,026 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

100m Swt Brine Flare Pit @ Jtf 0.09 340 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

100m Sour Brine Flare Pit @ 

Jtf 

0.09 340 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

55m Sour Brine Flare Pit @ Jtf 0.09 340 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-9

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

100m Swt Brine Flare Pit @ Jtf 0.09 340 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

30m Swt Brine Flare Pit @ Jtf 0.09 340 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

Ards Derrick Flare 51.07 191,704 

125 Conocophillips Co. - Borger (Prev. 

Phillips 66 Co.) 

Ards Hydrocarbon Flare 38.28 143,676 

126 Conocophillips Co. - Sweeny 

(Prev. Phillips 66 Co.) 

Sour Water Stripper Flare 0.72 2,691 

126 Conocophillips Co. - Sweeny 

(Prev. Phillips 66 Co.) 

Dea Stripper Flare 1.20 4,498 

127 Valero Refining Co. - Port Arthur 

(Prev. Premcor Refining Group 

Inc.) 

Emergency Flare No.19 0.00 - 

128 Deer Park Refining Limited 

Partnership (Shell Oil Products 

Us) 

Ep Flare:East Prop Flare Stack 293.43 1,101,467 

128 Deer Park Refining Limited 

Partnership (Shell Oil Products 

Us) 

Flarelub:Lube Flare 5.52 20,716 

128 Deer Park Refining Limited 

Partnership (Shell Oil Products 

Us) 

Wp Flare:West Prop Flare 

Stack 

41.10 154,272 

128 Deer Park Refining Limited 

Partnership (Shell Oil Products 

Us) 

Flarelht:Lht Flare 6.57 24,662 

128 Deer Park Refining Limited 

Partnership (Shell Oil Products 

Us) 

Flnflare:North Property Flare 111.32 417,858 

128 Deer Park Refining Limited 

Partnership (Shell Oil Products 

Us) 

Ckgflare:Coker/Goht Flare 242.46 910,148 

129 Trigeant LTD Flare Pilot 1.01 3,791 

129 Trigeant LTD Flare Streams 67.96 255,105 

129.5 South Hampton Resources Inc. 

(Prev. South Hampton Refining 

Co.) 

Plant Flare 1.48 5,556 

130 Valero Energy Corp. - Three 

Rivers (Prev. Diamond Shamrock 

Refining) 

West Plant Flare 9.74 36,572 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-10

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

130 Valero Energy Corp. - Three 

Rivers (Prev. Diamond Shamrock 

Refining) 

Hcu Flare 12.46 46,767 

130 Valero Energy Corp. - Three 

Rivers (Prev. Diamond Shamrock 

Refining) 

East Plant Flare 25.36 95,203 

130 Valero Energy Corp. - Three 

Rivers (Prev. Diamond Shamrock 

Refining) 

Dot/Btx Flare 13.47 50,568 

131 Valero Energy Corp. - Mckee 

(Prev. Diamond Shamrock 

Refining) 

Refinery & Gasoline Plant 

Units To Flare 

22.58 84,764 

131 Valero Energy Corp. - Mckee 

(Prev. Diamond Shamrock 

Refining) 

F.C.C. Units To Flare 24.28 91,124 

131 Valero Energy Corp. - Mckee 

(Prev. Diamond Shamrock 

Refining) 

H.C.U. Unit To Flare 11.87 44,556 

131 Valero Energy Corp. - Mckee 

(Prev. Diamond Shamrock 

Refining) 

Flare "Fl-4" Pilot 0.41 1,551 

132 Valero Refining Co. - Corpus 

Christi East 

Sour Water Stripper 

Emergency Flare 

1.25 4,681 

132 Valero Refining Co. - Corpus 

Christi West 

Main Flare 8.54 32,057 

132 Valero Refining Co. - Corpus 

Christi West 

M.T.B.E. Flare 0.00 - 

132 Valero Refining Co. - Corpus 

Christi West 

Main Flare & Acid Gas 0.00 - 

132 Valero Refining Co. - Corpus 

Christi West 

Ground Flare 31.13 116,854 

134 Valero Refining Co. - Texas City Safety Flare No. 2 19.40 72,813 

134 Valero Refining Co. - Texas City Flare No.4 11.51 43,197 

134 Valero Refining Co. - Texas City No. 1 Flare 1.23 4,619 

134 Valero Refining Co. - Texas City Safety Flare No. 3 44.43 166,780 

134 Valero Refining Co. - Texas City Sws Emergency Flare 0.00 - 

135 Tesoro - Salt Lake City 27.19 102,072 

135 Tesoro - Salt Lake City 44.98 168,853 

135 Tesoro - Salt Lake City 4.35 16,343 

136 Chevron - Salt Lake City 11.23 42,161 
Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS – Attachment A 

January 25, 2012 

A-11

Attachment A. Flare Data from 2002 National Emissions Inventory 

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

136 Chevron - Salt Lake City 11.23 42,161 

136 Chevron - Salt Lake City 11.23 42,161 

137 Silver Eagle Refining 0.50 1,877 

138 Big West Oil Co. (Flying J) 7.69 28,866 

138 Big West Oil Co. (Flying J) 7.69 28,866 

139 Holly Corp. (Prev. Phillips 66 Co.) 0.70 2,628 

139 Holly Corp. (Prev. Phillips 66 Co.) 6.49 24,362 

141 Bp West Coast Products - Cherry 

Point 

Low Pressure Flare 37.00 138,889 

141 Bp West Coast Products - Cherry 

Point 

High Pressure Flare 95.00 356,607 

142 Shell - Anacortes Flares (For Emergencies Only) 131.00 491,742 

144 Tesoro Northwest Company Flares 44.00 165,165 

147 Ergon - West Virginia, Inc. Plant Flares 13.52 50,751 

147 Ergon - West Virginia, Inc. Plant Flares 0.84 3,153 

150 Little America Refining Co. 

(Sinclair) 

Emergency Flare 0.90 3,378 

151 Sinclair Oil Corp-Sinclair Refinery Refinery Flare 50.26 188,664 

152 Wyoming Refining Co_Newcastle 

Refinery 

Flare Pilots (H_10) 0.10 375