### From: Brenda Shine/RTP/USEPA/US@EPA

Sent: 02/2 1 /2012 0 8 : 37 A M

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

Cc: William Nickerson/DC/USEPA/US@EPA

, Penny Lassiter/RTP/USEPA/US@EPA, Alex Macpherson/RTP/USEPA/US@EPA,
Subject: Ja memo on flaring and call tomorrow

Hi Cortney,

Here is the memo on flaring and costs for the Ja package.

Also, we tentatively set up a meeting for 10:30 to noon tomorrow to discuss the RIA.

Is that time still good for you? Will you send a call in number or should we set that up?

<< Impacts_FlareGasRecovery_FGCD

- 01

- 25

- 12.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 2 5 , 2012

SUBJECT: Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Optio ns for Amendments to the Petroleum Refinery NSPS

1

. Introduction

The U. S. Environmental Protection Agency (EPA) is sued new source performance standards (NSPS) for petroleum refineries beginning construction, reconstruction, or modification after May 14, 20 07 (40 CFR part 60, subpart J a ) on June 24, 2008

. Following promulgation, EPA

received petitions for reconsideration from : 1) t he American Petroleum Institute (API), the National Petrochemical and Refiners Association (NPRA), and the Western States Petro leum 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 provi ded 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 action s 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 ( SO 2 

### ) emissions per flaring event and emissions reductions per root cause analysis (RCA) were significantly underestimated, and they provided data on SO 2 

### emissions from flares from three refineries in Texas (Schaeffer, 2008)

. Public commenters stated that EPA should consider the impacts of the long

- term hydrogen sulf ide ( H 2 

### S ) concentration requirements for fuel gas sent to flares separately from the impacts of the other flare requirements

.

T he 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 source s . The regulatory options are as follows:

• A limit of 60 pa rts per million by volume (ppmv) H 2 

### S or 8 ppmv SO 2 

### 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 H 2 

### S in the fuel gas sent to

flares to 60 ppmv on a 365

- d ay rolling average ; and

• R equirements for flaring events, including a flare management plan, RCA for a discharge that causes 500 pounds (lb) SO 2 

### emissions in a 24

- hour period; and RCA for a discharge that causes flow rate to a flare in excess of 500,000 sta ndard 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 methodolog ies used to
estimate the costs (in 2006 dollars) and emission reducti on impacts for new

, reconstructed , and

modified flares and FGCD o ver the first 5 year s for selected regulatory options

. All impacts are expressed as the costs and emission reductions achieved beyond implementing the curr ent 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 s ent 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 Combust ion Devices

Process Unit Capital cost ($1,000) Total annual cost ($1,000/ yr) Emission reduction (ton
SO 2 /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 3 4 ,000 1 2,000 5

, 3 00 2

, 2 00

### 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) SO 2 Emission

reduction (ton
SO 2 /yr) NO X Emission

reduction (ton

NO X /yr) VOC

Emission

reduction (ton VOC/yr) Cost

effective

ness ($/ton)

New Flares 80,0 00 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 Impact s of Other Standards for Potentially Affected Flares

Standard Capital

cost ($1,000) Total annual

cost without

offset or credit ($1,000) Annual

o ffset or

credit ($1,000) Total

annual cost ($1,000/yr) Emission

reduction (ton
SO 2 /yr) Emission

reduction (ton

N O X /yr) Emission

reduction (ton VOC/yr) Overall c ost
effective

ness ($/ton)

Sulfur and Flow Rate Monitoring + Recovery for Largest Flares 460 ,000 92

, 0 00 ( 170 ,000) ( 76 ,000) 370 1

, 10 0 2,700 ( 18 ,000 )

Flare Management Plan

-- 880

-- 880

-- -- 300 2,900

SO 2 RCA/ Corrective Action Analysis -- 2,200

-- 2,200 2, 90 0

-- -- 760

Flow Rate RCA/ Corrective Action Analysis -- 1,000 (7 ,4 00) (6,400) 3.8 56 430 (13, 0 00)

Grand Total 460 ,000 96,000 ( 180

, 0 00) ( 79

, 0 00 ) 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 Pro cess Units

It was assumed 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 compl iance

. For that reason, it is more accurate to consider whether the fuel gas system is existing or will be constructed th an 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 15 0 refineries will construct, reconstruct, or m odify one or more flares

over the next 5 years , b ased 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 Inv entory (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. Applyi ng 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

.

T he 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 include s 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 F uel Gas Com bustion Devices

A

. Emissions Estimates

Baseline SO 2 

### 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, t he 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

### 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 H 2 

### S, which is readily removed by amine treatment. However,

infor mation 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

SO 2 

### emissions (Wilkes, 2005). These other sulfur compounds are not remove d well by conventional amine treatment. As such, the SO 2 

### 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

SO 2 

### 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 m ore 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 f low 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, 3 00 scfm ( i.e. , the fuel gas is generated by just the crude distillation unit and the flui d catalytic cracking unit)

. T hese 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 S ection 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 H 2 

### S concentration limit of 0.1 grain s per dry standard cubic feet ( gr/dscf ) in the fuel gas (equivalent to 162 ppmv H 2 

### S 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, 3 00 scfm

and a concentration of 162 ppmv H 2 

### S would emit a pproximately 0.9 0 pounds of SO 2 

### per minute ( lb SO 2 

### / min), or 2 4 0 tons of SO 2 

### per year (ton SO 2 

### /yr) at baseline (note that 64 lb of SO 2 

### is

released during the combustion of 34 lb of H 2 

### S in the fuel gas)

.

As discussed previously

, there is strong evidence that coking units generate other reduced sulfur compounds, mostly mercaptans, that contribute to SO 2 

### 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 r ange 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

SO 2 

### emissions. This additional sulfur content only applies to the fuel ga s generated by the coking unit, which is assumed to be 1 6, 700 scfm in the model plant ( i.e. , 50,000

– 33, 3 00). The weighted average sulfur content in the model fuel gas system with a coking unit was subsequently calculated to be 26 2 ppmv ( [ (300 ppmv merca ptans + 16 2 ppmv H 2 

### S ) × 16,700 scfm + 16 2 ppmv H 2 

### S × 33, 3 00 scfm] / 50,000 scfm ) . Assuming an ideal gas at standard temperature and pressure (specifically, 20 °C and 1 atmosphere) , 26 2 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 SO 2 

### /min, so the baseline for one m odel fu e l gas system with a coking unit is 570 ton

SO 2 

### /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 SO 2 

### emissions are estimated to be approximately

11

, 0 00 tons per year ( ton/yr ) (240 ton /yr × 18 fuel gas systems + 570 ton/ yr × 12 fuel gas systems) from FGCD.

The SO 2 

### emissions attributed to this regulatory option for FGCD are the SO 2 

### emissions released

when the FGCD meets the long

- term sulfur limit. I t was assumed that refiners would comply with the long

- term H 2 

### S co ncentration limit rather than the direct SO 2 

### limit. While the H 2 

### S and

SO 2 

### limits are roughly equivalent when H 2 

### S is the primary s ulfur compound in the fuel gas, it is

much easier for fuel gas systems with coking units to meet the 60 ppmv H 2 

### S concentration limit in the fuel gas than the 8 ppmv SO 2 

### emission limit in the FGCD exhaust. For fuel gas systems without a coking unit, the SO 2 

### emissions when me e ting the long

- term H 2 

### S concentration limit

were estimated to be 0.33 lb SO 2 

### /min, or 87 ton SO 2 

### / yr (assumin g an ideal gas at 20 °C and

1 atmosphere , 60 ppmv H 2 

### S for a 33, 3 00 scfm system is equivalent to 0.18 pounds of H 2 

### S per minute (lb H 2 

### S/min) , or 0.33 lb SO 2 

### /min ). Because the amine treatment system is not expected to reduce mercaptans f or fuel gas systems w ith a coking unit, SO 2 

### emissions reductions are based

on a reduction of 102 ppmv H 2 

### S

. Therefore, for fuel gas systems with a coking unit, the SO 2 

### emissions when meeting the long

- term H 2 

### S concentration limit were estimated to be 1.33 lb

SO 2 

### /min , or 350 ton SO 2 

### /yr (assuming an ideal gas at 20 °C and 1 atmosphere, a reduction of 102 ppmv H 2 

### S 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 SO 2 

### /min ). T he weighted av erage reduced sulfur content would be 1 6 0 ppmv when meeting the regulatory option ([(300 ppmv mercaptans + 60 ppmv H 2 

### S ) × 16,700 scfm + 60 ppmv H 2 

### S × 33, 3 00 scfm] / 50,000 scfm).

The baseline SO 2 

### emissions and the SO 2 

### emissions for the two model fuel gas s ystems (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 H 2 

### S long

- term concentration limit and the SO 2 

### emission reduction from the baseline.

Table 4 . Emissions for Model Plants Meeting Long

- Term Sulfur Limit for Fuel Gas
Combustion Device s

Conditions Emissions from Model Fuel Gas System Nationwide
Emissions (ton SO 2 /yr) Reduction from
baseline (ton SO 2 /yr ) Without a coking unit (ton SO 2 /yr) With a coking unit (ton SO 2 /yr)

Baseline 2 4 0 570 11 ,000

--- 60 ppmv H 2 S 87 350 5

, 8 00 5

, 3 00

### 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 ac hieve 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 ami ne 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 betw een 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).

Estimate d 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 t hese 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 t he 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 a re 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 Sul fur 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 co king unit 14 2

Modified/Reconstructed, with a coking unit 10 1



### Table 6

. Summary of Costs and SO 2 

### 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 SO 2 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 S ulfur Limit for Potentially Affected Fuel Gas Combustion Devices

Process Unit Capital cost ($1,000) Total annual cost ($1,000/ yr) Emission reduction (ton
SO 2 /yr) Cost

effectiveness ($/ton)

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

Modified and

Reconstruc ted Fuel Gas Systems 33,000 11,000 4,800 2,300

Total 3 4 ,000 1 2,000 5

, 3 00 2

, 2 00

### 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 requiremen ts, industry representatives stated that it is not cost effective to manage the fuel gas sent to flares by limiting the long

- term concentration of H 2 

### S 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, i t is assumed that there are an average of 1.9 impacted flare s per refinery ( 280 impacted flares at 150 refineries)

.

Baseline SO 2 

### emissions from flares, like FGCD, are the result of H 2 

### S and other reduced sulfur compounds in the fuel gas. Therefore, t wo fla re scenarios were used to evaluate the baseline SO 2 

### 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 g as 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, n early all FGCD currently meeting those standards comply with the H 2 

### S

concentration limit of 0.1 gr/dscf in the fuel gas (equivalent to 162 ppmv H 2 

### S in the fuel gas) on

a 3

- hour average.

The first step in this piece of the analy sis 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 2 5,000,000 s tandard c ubic f eet per year (scf/yr); this is about the 50 th 

### percentil e of the flow rates examined for the overall flare impacts analysis (See Section 5 .A and Table 1 3

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 y ear ÷ 24 h ours per day ÷ 60

min utes per hour ). Using a calculation similar to that for FGCD (Section 3 .A) , baseline SO 2 

### 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 SO 2 

### 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 SO 2 

### emissions from affected

flares are estimated to be approximately 131 ton/ y r ( 0.34 ton/ yr × 221 flare s + 0 .96 ton/ yr × 59 flare s).

Th e SO 2 

### emissions attributed to this regulatory option for flares are the SO 2 

### emissions released

when the gas being flared meets the long

- term sulfur concentration requiremen t

. Similar to the

calculations for FGCD

, SO 2 

### emissions for flares without coking un it 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 H 2 

### S (162

– 60 ppmv
H 2 

### S ) , and the SO 2 

### emissions were estimated to be 0.00047 lb SO 2 

### /min , or 0.12 ton SO 2 

### /yr (assuming an ideal gas at 20 °C and 1 atmosphere, 60 ppmv H 2 

### S for 48 scfm is equivalent to

0.00025 lb H 2 

### S /min, or 0.00047 lb SO 2 

### /min ).

As with FGCD, the amine treatment system is not expected to reduce mercaptans for flare gas from a coking unit, so SO 2 

### emissions reductions for flare gas from a coking uni t are also based on a reduction of 102 ppmv H 2 

### S [(300 ppmv mercaptans + 162 ppmv H 2 

### S )

– (300 ppmv mercaptans + 60 ppmv H 2 

### S )] . Therefore, for fuel gas systems with a coking unit, the SO 2 

### emissions when meeting the long

- term H 2 

### S concentration requirement fo r fuel gas were estimated to be 0.0028 lb SO 2 

### /min , or 0.75 ton SO 2 

### /yr (assuming an ideal gas at 20 °C and

1 atmosphere, a reduction of 102 ppmv H 2 

### S for 48 scfm is equivalent to a reduction in reduced

sulfur compounds of 0. 000 4 3 lb/min , or a reduction of 0. 000 8 1 lb SO 2 

### /min ).

The baseline SO 2 

### emissions and the SO 2 

### 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 H 2 

### S long

- term concentration requirement, and the SO 2 

### 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 SO 2 /yr) Reduction from
baseline (ton SO 2 /yr) Without a coking unit (ton SO 2 /yr) With a coking unit (ton SO 2 /yr)

Baseline 0.34 0.96 131

--- 60 ppmv H 2 S 0.12 0.75 72 59



### While SO 2 

### reductions are the primary focus of the long

- term H 2 

### S concentration requirement for fuel gas , when these reductions are accomplished via flare gas recovery, there are also reductions in other pollutant s, such and nitrogen oxides ( NO X 

### ) 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 NO X 

### , 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 discharge d to the flare would

reduce NO X 

### 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. Assumin g 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/m ol

, 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

, e xisting and new affected flares would need to add a flare gas recovery system to recover flare gas not meet ing the sulfur concentration requiremen t

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

based o n 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 bas ed 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)

w here :

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

The capital cost estimates includ e 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 e qual 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 hand ling 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 e ach 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 calc ulated 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 g as recovered off

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

### 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 wa s 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 affecte d flares; the derivation of these estimates

was described in Section s 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 em ission 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 a re 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 19 9

Modified/Reconstructed, with a coking unit 53

### 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 Cost s for a Single Flare to Meet the Long

- Term Sulfur Concentration Requirement for Fuel Gas

Affected Flare SO 2 Emission

Reduction

( ton/ yr) Recovery System Costs

Capital Cost ($1,000) Annual Operating Cost ($1000/yr) Natural Gas
Offsets ($1000/yr) Ne t 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

opera ting cost

without natural gas offset ($1,000) Natural

gas offset ($1,000) Net

annual operating

cost ($1,000) Total

annual

cost ($1,000/ yr) SO 2 Emission

reduction (ton
SO 2 /yr) NO X Emission

reduction (ton

NO X /yr) VOC

Emission

reduction (ton VOC/yr) Cost

eff ective

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 F lare s

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 SO 2 

### 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 Estimate s

Carbon monoxide (CO) emissions from flares that were reported in t he 2002 NEI w ere used to

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

the flare SCC for 25 2 flares at 77 refineries ; these data are summarized in Attachment A . It is anticipated that some facilities/ s tates 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. T he CO emissions reported

in the NEI we re assumed to b e 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 refine ry 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 heater s, 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 t o 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 CH 4 7.17 82 43.6

Ethane C 2 H 6 0.55 13.1 3.66

Propane C 3 H 8 2.04 64.2 20.3

n

- Butane C 4 H 10 0.199 28.3 2.78

Isobutane C 4 H 1 0 1.33 57.6 14.3

n

- Pentane C 5 H 12 0.008 3.39 0.266

Isopentane C 5 H 12 0.096 4.71 0.53

neo

- Pentane C 5 H 12 0 0.342 0.017

n

- Hexane C 6 H 14 0.026 3.53 0.635

Ethylene C 2 H 4 0.081 3.2 1.05

Propylene C 3 H 6 0 42.5 2.73

1

- Butene C 4 H 8 0 14.7 0.696

Carbon monoxide CO 0 0.932 0.186

Carbon dioxide CO 2 0.023 2.85 0.713

Hydrogen sulfide H 2 S 0 3.8 0.256

Hydrogen H 2 0 37.6 5.54

Oxygen O 2 0.019 5.43 0.357

Nitrogen N 2 0.073 32.2 1.3

Water H 2 O 0 14.7 1.14

Source: Peterson et al., 2007



### Reported CO emissions were convert ed 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 5 th 

### percentile flare flow rate from the data set was used to represent the smallest

10 percent of flares. The 15 th 

### 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 95 th 

### 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 4 0 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 (18 3 MMscf/yr) above baseline

. At this action level

, only the flares represented by Model

Plant 10 in Table 13 would consider install ing a flare gas recovery system

. Owners or operators

of f lares receiving routine flows that can offse t natural gas purchases by recovering f lare gas are likely to conclude that installing a flare gas recovery system would be a cost eff ective alternative to the flaring event requirements. For this assessment, it was assumed that all of the flares represented by Model Plant 10 w ould 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

mod el 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 th is 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 the se standards . The capital costs of these monitors were estimated as

### 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 ga s 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 Flar e Management Plan

Three different standards were included in this step of the analysis : RCA and corrective action analysis based on SO 2 

### 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 emission s 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

Gener al 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 estimat ed to cost $68.66 [( $ 38.29 + 0.05 × $ 57.58 + 0.1 × $ 17.46) × 1.6].

An estimated 4 5 labor hours would be required to perform each RCA and associated corrective action analysis (whether triggered by SO 2 

### or flow). The flare ma nagement plan w as estimated to require 160 technical labor hours to develop. Unlike the direct control systems, these sta ndards are expected to initiate routine operational or maintenance practices that will typically avoid a periodic emission event that may not occ ur 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 SO 2 

### RCA and corrective action analysis, the refinery consen t decrees have established a trigger of 500 lb in any 24

- hour period. Using this as the threshold for the SO 2 

### analyses, the cost effectiveness is estimated to be

### 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 SO 2 

### emissions avoided in the fifth year and an average of $760/ton of

SO 2 

### 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. T herefore, 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 $ 5 60 /ton of VOC, which is an approximate conversion from an estimate of $1. 75 per gallon. That est imate 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 , 200 7 ) and the product value ( crack spread spot price of $87.04 per bar rel ( $ 2.08 per gallon ) on September 7, 2007 ) (Stell,

200 7 ). 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 V OC 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 $ 5 6 0/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 effectiven ess 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 ,00 0/ton of VOC emissions avoided per year over the first 5 years.

Tables 14 and 15 summarize some of the key inputs for the c ost 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 a nalysis 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.

### 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 SO 2 

### RCA and Corrective Action Analysi s

Item Description Refineries

Affected SO 2 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 ton s 2.5 tons 0.5 tons

Success rate of RCA/correc tive action 35% 35% 35%

Reduction efficiency for successfully avoided

event 100% of
SO 2 100% of
SO 2 100% of
SO 2

Ave rage mass emissions per avoided event 2.19 ton s 0.88 ton s 0.18 ton s
Events per refinery (avg

. ), Year 1 50 5 3 2

Events per refinery, Y ear 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 SO 2 /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 2,0 00,000 scf/

24 hours 1 1,000,000 scf/ event 2

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 VOC 3

100% of SO 2 2% for VOC 3

Average mass emissions per avoided event 0. 75 tons 4 VOC 0.38 tons 4 VOC

Product recov ery credit ($/day) 2 1

, 085

Number of new refineries per year 50 each in Years

1

- 3 --

Number of new flares per year

-- 1 4 0 in Year 1; 130 each
in Years 2 and 3

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

Events per year , Year 2 4 per refin ery 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 V O C /yr) 430 300

Nationwide annual SO 2 emission reductions (ton SO 2 /yr) 3.8

--

Nationwide annual NO X emission reductions (ton NO X /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 f lares 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 pri ce 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 t o 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, nat ural 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

Ta ble 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 SO 2 

### 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

Sta ndard Capital

cost ($1,000) Total annual

cost without

offset or credit ($1,000) Annual

o ffset or

credit ($1,000) Total

annual cost ($1,000/ yr) Emission

reduction (ton
SO 2 /yr) Emission

reduction (ton

NO X /yr) Emission

reduction (ton VOC/yr) Overall c ost
eff ective

ness ($/ton)

Sulfur and Flow Rate Monitoring + Recovery for Largest Flares 460 ,000 92

, 0 00 ( 170 ,000) ( 76 ,000) 370 1.100 2,700 ( 18 ,000)

Flare Management Plan

-- 880

-- 880

-- -- 300 2,900

SO 2 RCA/ Corrective Action Analysis -- 2,200

-- 2,200 2, 90 0

-- -- 760

Flow Rate RCA/ Corrective Action Analysis -- 1,000 (7 ,4 00) (6,400) 3.8 56 430 (13,100)

Grand Total 460 ,000 96,000 ( 180

, 0 00) ( 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 CO 2 

### 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 me morandum. For the flow rate RCA,

the CO 2 

### 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 reco very, the CO 2 

### emissions prevented per large flare were estimated by applying an 80 percent recovery factor (see Section 4.B of this memorandum) to the CO 2 

### 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 52,0 00 t on/yr per flare for flares that install flare gas recovery. For 40 large flares, the CO 2 

### emissions reductions

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

In additio n to the primary emissions reduction impacts, the secondary CO 2 

### 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 (m 3 

### /hr) ; the midpoint of that range, 1,300 m 3 

### /hr, is equal to

a flo w 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 1 2 0 ,000 MWh/yr for 40 flares

. If the additional electricity is purchased from a power plant, the standards will increase secondary CO 2 

### emissions by 110,000 ton/yr , or 100,000 tonne/yr.

The final estimate of CO 2 

### emissions reductions, considering the reductio ns 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 CO 2 

### emissions reduction impacts.

Table 17. Nationwide Estimate of CO 2 

### Emissions Reduc tions for Flare Standards 1

Standard CO 2 emissions
reductions (ton/yr) CO 2 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.

, n egative 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

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- 0 30 1

.

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 2 7 . Do cket Item No. EPA

- HQ

- OAR

- 2007

- 0011

- 01 3 8.

### 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 Zin k Company. 2006. Flare gas recovery (FGR) to reduce plant flaring. Presented at the

Gas Processors Association 1 st 

### Specialized Technical Session: Zero Flaring Seminar. Al

Khobar, Saudi Arabia, November 29. Available at: http://www.gpa

- gcc

chapter.org/PDF/Flare%20Gas%20Recovery%20White%20Paper.pdf

Peterson, J

. , N. Tuttle, H. Cooper, and C. Baukal. 2007. Min imize 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 Enginee rs. Docket Item No. EP A

- 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

- 0 310

.

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#worl dref .)

Stell, J., ed. 200 7 . “Statistics,” Oil & Gas Journal

, Vol. 10 5 , Issue 3 5. “OGJ Crack Spread, ” p.

90

. September 17

.

Stell, J., ed. 200 9 . “Statistics,” Oil & Gas Journal

, Vol. 10 7 , Issue 2 . “OGJ Gasoline Prices”

and “World Crude Pric es,” p. 5 7

. 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

. DO E/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)

. 20 1 0. Natural Gas

Annual 2009

. DO E/EIA

- 0131(0 9 ). 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. Vol ume 1: Stationary Point and Area Sources

. AP

- 42, Fifth Edition. Office of Air Quality Planning and Standards, Rese arch 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

. Novemb er. 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

Emis sions

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 Compan y

- 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 Chevro n 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 U s

- 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 G as 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. Ultra mar 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

Emis sions

per flare

(tpy) Projected

Flow Rate (1000 scf/yr)

33 Valero Refini ng 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 C o. (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 Ref inery 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 Conocophi llips 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. Phill ips 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 So merset 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

Emis sions

per flare

(tpy) Projected

Flow Rate (1000 scf/yr)

61 Citgo Petroleum Corp.

- Lak e 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

6 1 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.

- La ke
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 Cit go 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

Emis sions

per flare

(tpy) Projected

Flow Rate (1000 scf/yr)

74 Valero Refining Co.

- Krotz Springs 5.00 18,769

78 Chevron Products Company, Pascagoula Re f 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 Compan y, 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 Relea ses 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 In dustries 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

Emis sions

per flare

(tpy) Projected

Flow Rate (1000 scf/yr)

99 Conocophilli ps 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

10 0 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 Su noco 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

Refi nery 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

Emis sions

per flare

(tpy) Projected

Flow Rate (1000 scf/yr)

111 Alon USA Energy Inc. (Prev. Alon

U SA 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 Petroc hemicals, 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 Recov ery 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 Sys tems 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

Emis sions

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 S tack 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 F lare 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 Exxonmo bil 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 S ystem 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 Resou rces 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

Emis sions

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. Laglo ria 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.) F lare 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 Re finery 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.) N gl 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

Emis sions

per flare

(tpy) Projected

Flow Rate (1000 scf/yr)

12 5 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 Derr ick 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. Phil lips 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

Pa rtnership (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:C oker/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 (Pre v. 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

Emis sions

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.

- Mck ee (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" Pil ot 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 V alero 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 Fl are 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 27.1 9 102,072

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

Emis sions

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 Refin ing 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 Vi rginia, 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 Refini ng Co_Newcastle Refinery Flare Pilots (H_10) 0.10 375