FROM: Jeff Coburn, RTI International

TO: Andrew Bouchard and Brenda Shine, EPA/OAQPS

DATE: January 16, 2014

SUBJECT: Petroleum Refinery Sector Rule: Flare Impact Estimates

1. Purpose

This memorandum provides cost and emission impact estimates for different regulatory 

alternatives to ensure petroleum refinery flares used as a control device meet an equivalent level 

of emissions control (e.g., 98 percent destruction) for various sources of emissions as prescribed 

in the petroleum refinery national emissions standards for hazardous air pollutants (NESHAP).

2. Background

Flares used as a control device subject to NESHAP are required to meet certain design and 

operating requirements as specified in 40 CFR 63.11. The available data at the time suggested 

that flares meeting these design and operating requirements would achieve a minimum 

destruction efficiency of no less than 98 percent emissions. With the advent of activities to 

reduce the amount of flaring at refineries, more refinery flares are commonly operated at high 

turndown (minimum flow conditions). Recent evidence through Passive Fourier Transform 

Infrared (PFTIR) spectroscopy testing suggests that steam- and air-assisted flares can have a 

significant degradation in destruction efficiency when operated at high turndown or at other 

times when steam- and air-assist rates are too high (EPA, 2012). As many of the flares operated 

at petroleum refineries are steam- or air-assisted, concerns of poor flare destruction efficiency are 

particularly significant for petroleum refinery flares.

The U.S. Environmental Protection Agency (EPA) supported a study to better understand flare 

performance and to identify key operating/monitoring parameters that would ensure adequate 

performance of flares at all times (EPA, 2012). The EPA is also performing a risk and 

technology review of the petroleum refinery NESHAP (40 CFR part 63, subparts CC and UUU) 

as part of their requirements under the Clean Air Act (CAA) sections 112(d)(6) and (f)(2). 

Particularly, under CAA section 112(d)(6), the EPA is required to review these technology-based 

NESHAP and to revise them “as necessary (taking into account developments in practices, 

processes and control technologies)” no less frequently than every 8 years. Many of the organic 

hazardous air pollutant (HAP) emission controls specified in the refinery NESHAP require 95 to 

98 percent control efficiency (or reduce to 20 parts per million by volume (ppmv) total organic 

carbon) and flares meeting the general provisions requirements for flares as control devices were 

deemed acceptable control alternatives. However, given the growing body of data indicating that 

flares that are over-assisted are likely not meeting these target control levels, the EPA is 

considering revising the flare monitoring and operational requirements to the refinery NESHAP 

to ensure compliance with the CAA section 112(d)(2) and (d)(3) standards. This memorandum 
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

documents the cost and emission impacts associated with alternative monitoring options to 

ensure the proper performance of flares.

3. Control Alternatives

The EPA conducted a detailed review of performance data for flares (EPA, 2012) and 

determined that, for steam- and air-assisted flares, the combustion zone’s lower flammability 

limit, combustible gas concentration, or the net heating value all provided equivalent indications 

of the flare combustion efficiency. As each of these parameters would require an evaluation of 

combustion zone parameters, monitoring of the flare gas flow and composition (or heat content)

must also be matched with steam- or air-assist rate monitoring. Unassisted flares would only 

need to monitor the flare gas composition (or heat content) since there is no dilution with assist 

gas; however, these flares may still need to install monitors to ensure adequate combustion 

efficiency for the flare at all times. For steam- or air-assisted flares, monitors are generally 

expected to be needed for measuring flare gas flow rates, flare gas composition (or heat content), 

and assist gas flow rates.

As an alternative to continuous monitoring systems, process knowledge, engineering calculations 

and/or grab samples can be used to determine the composition (or heat content) of the flare gas. 

The key disadvantage of this option is that refinery owners or operators will generally have to 

make this assessment after the fact and they will not be able to actively adjust assist gas rates or 

natural gas supplementation to ensure compliance during the event. However, there are a 

number of situations where the refinery owner or operator may elect to use this option. For 

example, some flares receive flows only from a specific process that has a consistent 

composition and high heat content. In this case, flare and assist gas flow rate monitoring alone 

would be sufficient to determine compliance on a proactive basis without the need to install a gas 

composition monitor. This alternative may also be preferred for flares that are used infrequently 

(emergency only and non-routine flow flares) or that have flare gas recovery systems (FGRS)

that are designed and operated to recover 100 percent of the flare gas under typical conditions. 

For these flares, flaring events may be so seldom that the refinery owner or operator may prefer 

the uncertainty in proactive control to the high cost of continuous monitors that would seldom 

see flow. Additionally, if these flares generally handle larger events, the flare gas flow rate is 

typically sufficient to avoid over-assisting, so that the owner or operator may be comfortable 

with an after the fact determination of compliance using engineering calculations and a grab 

sample analysis of the flared gas.

The action levels for the operating parameters are expected to be established based on the policy 

requirement that flares achieve 98 percent control efficiency. While owners or operators may 

elect to comply with any of the three different operating parameters, the cost and environmental 

impacts of the flare standard are estimated considering the refinery owner or operator will elect 

to comply with the net heating value standard. The following regulatory alternatives are 

considered in this impacts analysis memorandum.

1) Thresholds equivalent to 270 British thermal units per standard cubic foot (Btu/scf) in 

the combustion zone (380 Btu/scf for flares with hydrogen-olefin interactions) with 

options for either continuous monitoring or engineering calculations/grab samples.

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

2) Thresholds equivalent to 270 Btu/scf in the combustion zone (380 Btu/scf for flares with 

hydrogen-olefin interactions) with a requirement for continuous monitoring for all flares.

4. Emission Estimates

Baseline emission estimates for flares are difficult to develop because flare gas can be highly 

variable in composition and flaring events can be unpredictable and episodic in nature. Due to 

the lack of a contained exhaust stack, it is difficult to measure the combustion products and to 

determine the destruction efficiency of flares on an on-going basis. While there have been 

studies to indicate that “over-assisted” flares can have poor destruction efficiencies, it is difficult 

to project the percentage of gas that may be poorly destroyed in these flares. Many times, “overassisting” occurs during high turn down (i.e., low flare flow). During periods of high flare gas 

flow (during large episodic events), the destruction efficiency for these flares is likely to be high 

because the flare would not be “over-assisted” during these high flow events. Consequently, the 

baseline emission estimate has considerable uncertainty. Ranges of emission estimates are 

provided in order to frame the uncertainty of the analysis.

Baseline Emissions for Flares Assuming 98 Percent Control Efficiency

The EPA’s Greenhouse Gas Reporting Program (GHGRP) in 40 CFR part 98 requires several 

industry sectors to report their greenhouse gas (GHG) emissions (74 FR 56260). The GHGRP 

includes specific reporting requirements for flares and other GHG emission sources at petroleum 

refineries (40 CFR part 98, subpart Y). The total GHG emissions reported for flares under 

subpart Y for the first two reporting years under the GHGRP are summarized in Table 1.

Table 1. Flare Emissions as Reported Under 40 CFR Part 98, Subpart Y

Inventory Year

CO2 Emissions 

(tonnes/yr)a CH4 Emissions (tonnes/yr)a N2O Emissions (tonnes/yr)a

2010 3.67-million 10,400 36.4

2011 3.95-million 11,500 39.3

a CO2 = carbon dioxide; CH4 = methane; N2O = nitrous oxide; tonnes/yr = metric tons per year.

The GHG calculation methodologies for flares in subpart Y assume a flare combustion efficiency 

of 98 percent. Based on the equations required to be used in the GHGRP, one can calculate the 

total methane flow to the flare as well as the total hydrocarbon (THC) flow to the flare (assuming 

there is no significant carbon monoxide (CO) or carbon dioxide (CO2) in the flare gas; i.e., all 

CO2 is produced from hydrocarbon combustion). The volatile organic compound (VOC) 

emissions are then solely dependent on the ethane concentration of the flare gas (since THC and 

methane emissions are fixed based on the GHGRP flare emissions and VOC emissions = THC 

emissions – methane emissions – ethane emissions). Table 2 shows the calculated VOC 

emissions for refinery flares for three different concentrations of ethane to provide a reasonable 

range for VOC emission estimates.

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014 

Table 2. VOC Emissions Estimates from GHGRP Data for Petroleum Refinery Flares

Assuming 98 Percent Destruction Efficiency

GHGRP Reporting Year

VOC Emissions (tons/yr)a

High Ethane Caseb Low Ethane Caseb

Mid-Range Ethane 

Caseb

2010 9,500 15,200 12,600

2011 9,800 16,100 13,200

a tons/yr = tons per year.

b The following flare gas concentrations (in volume percent (%)) were assumed and held constant for all cases: 

ethylene, 1%; propylene, 4%; butane, 6%; butene, 1%; hydrogen, 6%; and inerts (nitrogen), 4%. The 

concentration for ethane was as follows: high ethane case, 20%; low ethane case, 5%; and mid-range ethane 

case, 12%. The concentrations of methane and propane were then determined for each reporting year based 

on the constraints of the reported GHG emissions.

In 2011, the EPA also conducted a detailed Information Collection Request (ICR) of the 

petroleum refining industry (EPA, 2011). Under Component 1 of this ICR, the EPA required 

petroleum refineries to provide information about specific process units and emission sources 

present at the facility, including information about flares. Under Component 2 of this ICR, the 

EPA required petroleum refineries to submit a detailed emissions inventory (for the calendar 

year 2010) following the guidance provided in the Emissions Protocol for Petroleum Refineries

(RTI, 2011; hereafter referred to as “the Protocol document”). The Protocol document 

specifically instructed respondents to assume 98 percent destruction efficiency when estimating 

emissions from flares. Information for 519 flares was reported under Component 1 of the ICR 

with 510 flares at “major source” facilities.

1

 Under Component 2, VOC emissions data (either as 

overall VOC emissions or as individual non-HAP VOC emissions) were reported for a total of 

432 flare sources with 427 flares at major source refineries. A compilation of all nonconfidential Component 1 responses and all Component 2 responses are available on the EPA’s 

Technology Transfer Network (see: http://www.epa.gov/ttn/atw/petref/petrefpg.html). The VOC 

and HAP data extracted from the Component 2 dataset used in this analysis are provided in 

Attachment 1 to this memorandum; the facility data highlighted indicate data from flares at 

facilities that reported to be “synthetic minor” (or “area source”) facilities2

 and are, therefore, not 

subject to 40 CFR part 63, subparts CC and UUU. Note that some refinery owners or operators

reported flare emissions in the “emissions_non_routine_2010” column instead of or in addition 

to the “emissions_2010” column. Only the “emissions_2010” column data was originally 

extracted and used in this analysis. 

1 Major source facilities are facilities that have a potential to emit considering controls, in the aggregate, 10 tons per 

year or more of any hazardous air pollutant or 25 tons per year or more of any combination of hazardous air 

pollutants as defined in CAA section 112(a)(1). 2 Synthetic minor facilities are facilities that received federally enforceable emission limits so that their potential to 

emit considering controls, in the aggregate, is less than 10 tons per year of any hazardous air pollutant and less than

25 tons per year of any combination of hazardous air pollutants. These facilities therefore meet the definition of 

“area sources” in CAA section 112(a)(2). 

4 

 
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

For this analysis, VOC emissions from Component 2 were determined as the larger of the overall 

VOC emissions, as reported, or the sum of the individual VOC and volatile organic hazardous air 

pollutant (VOHAP) emissions reported for a given flare source. If only HAP data were reported, 

no VOC estimate was made. The cumulative VOC emissions total determined for the 432 flares 

reported in Component 2 was 9,270 tons per year (tons/yr), with 9,260 tons/yr released from the 

427 flares at major source facilities. An additional 1,740 tons/yr of VOC was reported in 

Component 2 for flares in the “emissions_non_routine_2010” column. Extrapolating the VOC 

emissions to all flares assuming the 87 “missing” flares have similar emission characteristics 

yields an estimated 13,200 tons/yr [(9,270 + 1,740) × 519 ÷ 432 tons/yr] of VOC emissions in 

2010. All flare data are used for this extrapolation because the GHGRP requires all refineries to 

report their GHG emissions regardless of size. This extrapolated value of 13,200 tons/yr of VOC

agrees well with the VOC emissions estimated for flares based on the data reported to the EPA’s 

GHGRP assuming a moderate ethane concentration. Because the ICR data were “missing” 87 

flares, the 2010 GHGRP baseline emission estimate using the mid-range ethane concentration of 

12,600 tons/yr was selected as the best estimate of 2010 VOC emissions if flare control 

efficiency is 98 percent. Also, based on the uncertainties in this analysis and the small VOC 

emissions reported for flares at area source facilities, this estimate of 12,600 tons/yr VOC 

emissions is assumed to be a reasonable estimate of the annual emissions for all flares at major 

source refineries.

The Component 2 data were also reviewed to estimate VOHAP emissions from flares. VOHAP 

emissions were reported for 357 flares; however, not all flares that reported VOHAP emissions 

also reported non-HAP VOC emissions. There were 348 flare sources that reported both VOC 

and VOHAP emissions; the ratio of the nationwide VOHAP emissions to VOC emissions for 

these flare sources was 0.115 (1,030 tons/yr HAP ÷ 8,970 tons/yr VOC). This ratio was not 

impacted when the analysis was limited to major source refineries. Consequently, a reasonable 

baseline VOHAP emission estimate for all petroleum refinery flares at major source refineries

(assuming 98 percent control efficiency) is approximately 1,450 tons/yr (12,600 tons/yr × 0.115).

Table 3 provides flare counts for all flares at major source refineries by assist type, operation 

type, and whether the flare is subject to 40 CFR 63.11. Approximately 80 percent of petroleum 

refinery flares are steam-assisted, 10 percent are air-assisted, and 10 percent are unassisted. This 

profile appears to hold regardless of operational class (routine or non-routine flow flares) or 

whether or not a flare is subject to 40 CFR 63.11. Given that approximately 90 percent of 

petroleum refinery flares are assisted flares, a significant portion of refinery flares may have flare 

combustion efficiencies well below 98 percent if they are over-assisted.

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

Table 3. Counts of Major Source Refinery Flares by Flare Assist Type

Flare Assist Type

Total # of Flares # Routine Flow Flaresa # Non-routine Flow 

Flaresb

63.11c Alld 63.11c Alld 63.11c Alld

Unassisted 28 49 13 19 15 30

Steam Assisted 217 402e 161 228 56 174e

Air Assisted 27 59 21 38 6 21

Total No. of Flares 272 510 195 285 77 225

a Routine Flow Flares were those flares that were reported in the Petroleum Refinery 2011 ICR, Component 1, Part II, 

Section 12. Flares, Flare Operating Hours as 1-4 (operate on a routine or clearly defined timeframe) or left that 

answer blank. b Non-routine Flow Flares were those flares that were reported in the Petroleum Refinery 2011 ICR, Component 1, 

Part II, Section 12. Flares, Flare Operating Hours as 5-7 (operate to handle start-up, shutdown, and/or upsets 

only). c Flares that reported to be subject to 40 CFR 63.11 in the Petroleum Refinery 2011 ICR. d All Flares represents the total number of flares at major sources reported from the Petroleum Refinery 2011 ICR. e One flare reported as a hybrid steam and air assist flare; this flare was counted as a steam-assisted flare.

While it is possible that some of the flares subject to 40 CFR 63.11 are subject because of 

NESHAP other than subparts CC and UUU, it is reasonable to assume that essentially all of the 

flares subject to 40 CFR 63.11 would be impacted by amendments to the petroleum refinery 

NESHAP (subparts CC and UUU) to enhance the flare monitoring provisions to ensure proper 

flare control performance. It is also possible that other amendments to subparts CC and UUU 

(such as new requirements for pressure relief valves in subpart CC) may cause some of the 

flares not currently subject to 40 CFR 63.11 to have to comply with the new flare requirements.

It is interesting to note that while only 53 percent of all flares are subject to 40 CFR 63.11, 

routine flow flares that are subject to 40 CFR 63.11 represent 68 percent of all routine flow 

flares. This could indicate that the flares subject to 40 CFR 63.11 could contribute well more 

than 50 percent of the nationwide flare VOC/HAP emissions. Additionally, the flares subject to 

40 CFR 63.11 would be likely to receive flare gas with a higher HAP content than flares not 

subject to 40 CFR 63.11. However, it is difficult to quantify the impact of these ‘likelihoods;” 

therefore, emissions for flares currently subject to 40 CFR 63.11 are estimated to be 50 percent

of the total nationwide flare emissions (on both a VOC and HAP basis).

Baseline Emissions of Flares Based on Actual Average Flare Control Efficiency

The American Petroleum Institute (API), the National Petrochemical and Refiners Association 

(NPRA; now known as the American Fuels and Petrochemical Manufacturers (AFPM)), and the 

American Chemistry Council (ACC) gathered data about flare waste gas and steam flow rates for 

38 steam-assisted flares, characterizing different operating conditions by waste gas flow rate, 

composition, and duration of that operating condition. A summary of the study and the data 

collected by API/NPRA/ACC are included in Attachment 2 to this memorandum. The flares in 

the API/NPRA/ACC dataset represent flares for which flow and compositional data were

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

available and also included several chemical plant flares, so this dataset is not necessarily 

representative of flares nationwide in the petroleum refining industry. All flow conditions for 

two olefin flares were removed from the data because these flares were not considered to be 

representative of refinery operations. Additionally, data were removed for a few operating 

scenarios where either no assist steam was used or where conditions appeared to consist of 

standby/purge only flow for which the operating limits would not apply. The remaining 

flare/flow conditions from the API flare dataset were used to estimate refinery flare performance; 

this dataset is referred to as the “refinery flare dataset” to distinguish it from the full 

API/NPRA/ACC flare dataset. While the representativeness of either the full API/NPRA/ACC 

or refinery flare dataset is questionable, these data provide the only means by which the average 

net heating value of the gas in the flare’s combustion zone (i.e., accounting for dilution from the 

assist steam) could be calculated across a reasonable sample of flares and differing flow 

conditions for those flares.

In order to use the refinery flare dataset to estimate average flare performance (i.e., baseline and 

“controlled” emissions), a correlation is needed between combustion zone net heating value 

(NHVcz) and flare performance. The flare data appears to suggest a snuff point of the flare at an 

NHVcz value of 80 Btu/scf and the combustion efficiency of 96.5 percent (assumed to be 

equivalent to 98 percent destruction efficiency) at an NHVcz value of 270 Btu/scf. Therefore, the 

following equation was proposed to determine combustion efficiency as a function of NHVcz.

For NHVcz ≥ 80,

( ) 100%

1 11.6 0.145

11.6 0.145

×

+ − +

− + =

cz

cz

NCV

NHV %CE (Eqn. 1)

For NHVcz ≤ 80,

%CE = 0 (Eqn. 2)

where:

%CE = combustion efficiency, percent.

NHVcz = net heating value of the gas in the flare’s combustion zone, Btu/scf.

Figure 1 shows the flare combustion efficiency data from the performance studies along with the 

projected flare combustion efficiency as projected by Equation 1.

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

Figure 1. Flare performance data as a function of NHVcz.

In the flare performance studies, the combustion efficiency was determined based on complete 

oxidation of the hydrocarbons to CO2. The HAP destruction (or control) efficiency of a flare is

expected to be slightly higher than the combustion efficiency as the hydrocarbon may be 

partially oxidized to CO rather than fully converted to CO2. The following equations were used 

to convert the combustion efficiencies to destruction efficiencies.

For %CE ≤ 97.98 percent,

96.5

98 %DE = %CE × (Eqn. 3)

For %CE >97.98 percent,

%DE = 99.5% (Eqn. 4)

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0 100 200 300 400 500 600 700 800 900

Combustion Efficiency

NHVcz (BTU/scf)

PFTIR Data

Regression Eqn

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

where:

%DE = destruction (or reduction/control) efficiency, percent.

%CE = combustion efficiency, percent.

For each flare and flow condition, the total flow of VOC to the flare, the NHVcz, and the 

controlled VOC emissions from the flare (based on the calculated DE) were determined. The 

sum of the VOC input and the sum of the calculated emissions across all of the flare/flow 

conditions were used to estimate a flow weighted average destruction efficiency across all flares 

in the refinery flares dataset. Based on this analysis, the average VOC control efficiency for 

flares in the refinery flares data set was 93.9 percent.

Table 4 summarizes baseline estimate for nationwide VOC and HAP emissions from petroleum 

refinery flares assuming 98 percent control efficiency (as described in the previous section) and 

the baseline emissions projected if the average control efficiency of flares is 93.9 percent. It is 

clear from Table 4 that flares may be a much larger source of emissions than projected assuming 

98 percent control efficiency, with a baseline VOC emission estimate of 38,600 tons/yr. After 

investigating flare performance issues, the EPA’s Office of Enforcement and Compliance 

Assurance (OECA) estimated that VOC emissions from flares operated by Marathon were 

5,609 tons/yr rather than 453 tons/yr as reported by Marathon, or 12 times higher than previously 

estimated. Similarly, the EPA estimated that VOC emissions from flares operated by BP 

Whiting were 3,119 tons/yr rather than 123 tons/yr reported by BP Whiting or 25 times higher 

than previously estimated. Based on OECA’s analysis, VOC emissions from flares could 

approach 100,000 tons/yr (Foley, 2013). Thus, while the baseline VOC emission estimate of 

38,600 tons/yr derived from the refinery flare dataset is significant, it appears reasonable based 

on all available data.

The emission estimates labeled “Refinery Flares Directly Impacted by Amendments to 40 CFR 

Part 63, Subparts CC and UUU” (hereafter referred to as “Part 63 flares”) are expected to be a 

lower limit of the baseline emission for impacted flares due to the considerations previously 

discussed. Emission estimates for “All Flares at Major Source Refineries” are included to 

represent an upper limit of the emissions for all flares potentially impacted by amendments to 

40 CFR part 63, subparts CC and UUU.

Table 4. VOC and HAP Emissions Estimates for Petroleum Refinery Flares

Assumed 

Destruction 

Efficiency

Refinery Flares Directly Impacted by 

Amendments to 40 CFR Part 63,

Subparts CC and UUU All Flares at Major Source Refineries

VOC Emissions 

(tons/yr)

HAP Emissions 

(tons/yr)

VOC Emissions 

(tons/yr)

HAP Emissions 

(tons/yr)

98% 6,300 725 12,600 1,450

93.9% 19,300 2,220 38,600 4,440

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

Emissions Reductions Estimates for Control Alternatives

The emission reductions were estimated based on the overall flare control efficiency estimates 

for the regulatory alternatives. The calculation methodology followed the calculations made to 

estimate the actual average baseline flare control efficiency. Using the same refinery flare

dataset, any flare/flare gas flow scenario in which NHVcz was less than the target value of the 

control alternative was assumed to be raised to the minimum target NHVcz (by first decreasing 

steam flow and then, if necessary, by increasing natural gas use if additional heat content was 

needed at the minimum steam use rates to meet the required NHVcz). The calculations were 

performed first using the general NHVcz target value of 270 Btu/scf. The hydrogen and olefins 

concentration in the combustion zone were then evaluated based on the steam assist and natural 

gas addition rates needed to meet the 270 Btu/scf target to determine if the higher NHVcz target 

value of 380 Btu/scf was required due to anticipated hydrogen-olefin interactions. If the higher 

NHVcz target value of 380 Btu/scf was required, the steam flow and, if necessary, the natural gas 

addition rates were again adjusted to meet the 380 Btu/scf target value.

The combustion and destruction efficiencies for each flare/flare flow scenario were then 

calculated based on the “post-control” NHVcz using the equations presented previously. The 

controlled VOC emissions were calculated across all flares and flow conditions, summed, and 

compared to the total VOC input to the flares to determine a weighted-average destruction 

(control) efficiency for the control alternative. This method was used directly to estimate the 

post-control emissions and emission reductions for Control Alternative 1. Because Control 

Alternative 2 has the same target NHVcz values as Alternative 1, these alternatives would be

projected to have the same VOC emission reductions. However, as Control Alternative 2 has 

more dynamic monitoring requirements, Control Alternative 2 was assumed to have slightly 

greater average control efficiency than determined for Alternative 1. The overall control 

(destruction efficiency) for Alternative 1 was calculated to be 99.1 percent, so the control 

efficiency for Alternative 2 was set at 99.3 percent. Table 5 presents the estimated control 

efficiency and emission reductions projected for each regulatory alternative for all petroleum 

refinery flares. It should be noted that emission reductions for “Part 63 flares” are estimated to 

be no less than half the emission reductions for all flares as presented in Table 5.

Table 5. Nationwide Flare Control Efficiency and Emission Reduction Estimates for Flare 

Control Alternatives (All Flares)

Control Alternative 

Description

Average 

Destruction 

Efficiency

VOC 

Emissions 

(tons/yr)

HAP 

Emissions 

(tons/yr)

VOC 

Emission 

Reductions 

(tons/yr)

HAP 

Emission 

Reductions 

(tons/yr)

Baseline 93.9 38,600 4,440

1. 270 Btu/scf; Engr. Calcs 99.1 5,500 630 33,100 3,810

2. 270 Btu/scf; Monitors Only 99.3 4,200 480 34,400 3,960

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

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The nationwide GHG emission estimates from flares reported by petroleum refinery in the 

GHGRP (provided in Table 1 of this memorandum) assume a 98 percent destruction efficiency. 

If the destruction efficiency of flares is currently closer to 93.9 percent, then the current GHG 

emissions from petroleum refinery flares would be higher than the estimates in Table 1. This is 

because of the higher global warming potential (GWP) of methane. While CO2 emissions from 

flares will increase with higher destruction efficiencies, emissions of methane will decrease and 

there will be a net decrease in GHG emissions on a CO2 equivalence (CO2e) basis. Table 6

provides the projected GHG impacts of Control Alternative 1. Considering only the 

improvement in destruction efficiencies, requiring owners or operators of flares to maintain a

minimum NHVcz of 270 Btu/scf is projected to reduce GHG emissions by 366,000 metric tons 

(tonnes) CO2e/yr using GWP for methane of 21 (IPCC, 1995) or by 473,000 tonnes CO2e/yr 

using the GWP for methane of 25 (IPCC, 2007). As noted in the following section, owners or 

operators of these flares are expected to install improved steam controls and reduce steam usage 

under certain flow conditions, but they are also expected to increase their natural gas use to 

supplement the net heating value of the flare gas under other flow. Lowering steam usage lowers 

the energy usage at the refinery is projected to decrease CO2 emissions at the refinery by 

158,000 tonnes/yr; increasing supplemental natural gas usage is projected to increase CO2

emissions at the refinery by 197,000 tonnes CO2/yr. These secondary impacts tend to cancel 

each other out, but they result in a net increase in CO2 emissions. Thus, the combined GHG 

impact of Control Alternative 1 is a net decrease of 327,000 tonnes CO2e/yr. These impacts are 

based on a GWP for methane of 21, as currently used in the GHGRP. The EPA has begun using 

25 for the GWP of methane (78 FR 71904). Using this higher GWP, Control Alternative 1 is 

projected to decrease GHG emissions by 434,000 tonnes CO2e/yr.

Table 6. Nationwide Flare GHG Emissions for Control Alternative 1 (All Flares)

Description

Average 

Destruction 

Efficiency

CO2

Emissions 

(tonnes/yr)

CH4

Emissions 

(tonnes/yr)

N2O 

Emissions

(tonnes/yr)

CO2e 

Emissionsa

(tonnes/yr)

Baseline 93.9 3,514,000 31,400 35.1 4,185,000

Control Alternative 1

Emissions based on improved 

destruction efficiency 99.1 3,711,000 4,600 37.1 3,819,000

Steam savings (12 MMlb/yr/flare)b (158,000) (158,000)

Natural Gas Use (860 klb/yr/flare)b 197,000 197,000

Total for Control Alternative 1 3,750,000 4,600 37.1 3,858,000

Net GHG Impacts for Control Alternative 1 (327,000)

a CO2e calculated using GWP of 21 for CH4 and 310 for N2O. b MMlb/yr/flare = million pounds per year per flare; klb/yr/flare = thousand pounds per year per flare.

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Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

5. Cost Estimates

In order to assess the cost impacts for the different regulatory alternatives, costs of installing the 

new monitoring systems must be estimated and the number of flares that would need to install 

new monitoring systems needs to be determined.

Specific Monitoring System Costs

In general, facilities are expected to need a flare gas flow monitor and either a gas 

chromatograph (GC), total hydrocarbon (HC) analyzer, or calorimeter (Btu monitor). Most 

flares are expected to have already installed a flare gas flow monitor and sulfur analyzer system 

(including analyzer shelter) in order to comply with the requirements of the new source 

performance standards (NSPS) for refineries (40 CFR part 60, subpart Ja) prior to the 

compliance date for amendments to subparts CC and UUU. However, subpart Ja does not 

require continuous flow monitors for “emergency only” flares. These “emergency only” flares 

were assumed to use the engineering calculations under Control Alternative 1. Installation of 

new flare gas flow monitoring systems would only be necessary under Alternative 2 (when these 

“emergency flares” would no longer be allowed to use engineering calculations). Costs were not 

estimated for visible emissions requirements or monitoring systems used to indicate the presence 

of a pilot flame as these are already requirements in the current set of refinery NESHAP.

Actual industry costs submitted to the EPA through consent decrees were used as the primary 

source of cost estimation. These costs included all installation and ancillary costs associated 

with the installation of the monitors (i.e., analyzer shelters and electrical connections). For some 

equipment, vendor quotes were collected and total installed costs were projected using basic cost 

estimation procedures as provided in the EPA Office of Air Quality Planning and Standards 

(OAQPS) Control Cost Manual (EPA, 2002). The specific cost data collected for this analysis 

are provided in Attachment 3 to this memorandum. Table 7 presents the best-estimate average 

cost for the different types of monitoring equipment based on the data collected. Table 6 also 

provides the projected supplemental natural gas use and steam savings projected for the different 

threshold levels. The steam savings and supplemental natural gas use costs were estimated based 

on the refinery flare dataset. Flare flow cases not compliant with the specified threshold were 

first assumed to reduce their steam addition rate in order to meet the combustion zone net heating 

value. However, many flares have a minimum steam flow rate (to protect the flare tips and to 

prevent water condensation in the steam lines). Therefore, in some flare flow cases, steam 

reductions were constrained by this minimum flow rate and supplemental natural gas was needed 

to keep the combustion zone net heating value above the specified threshold. The cumulative 

steam reductions and natural gas additions across all flares was calculated and divided by the 

number of flares in the analysis to determine an average cost (or credit) per flare. The natural 

gas costs and steam savings estimated from the refinery flare dataset are in-line with those

realized by Marathon upon upgrading their monitoring equipment and complying with a 

combustion zone operating limit for their steam assisted flares. Based on data provided by 

Marathon, supplemental natural gas costs of $52,000/yr/flare were estimated to achieve a 

300 Btu/scf NHVcz limit and Marathon realized a steam savings of about $150,000/yr/flare (see 

Attachment 4; steam costs for Texas City refinery were not used since there were no cost 

estimates for 2007 or 2008). Based on comparison with Marathon’s estimates, the costs 

12
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

developed from the refinery flare dataset appear realistic, but may overestimate the net cost for 

steam assisted flares.

Table 7. Summary of Flare Monitoring Equipment and Material Costs (in 2010$)

Monitoring Equip. or 

Material

Total 

Capital 

Equipment 

($)

Annual 

Operating and 

Maintenance 

Costs ($/yr)

Total 

Annualized 

Cost ($/yr) Source/Assumptionsa

Gas Chromatograph (GC) 980,000 49,000 141,500 See Attachment 3

Hydrocarbon (HC) Analyzer 180,000 44,000 61,000 See Attachment 3

Calorimeter 105,000 20,100 30,000 See Attachment 3

Analyzer Building Included in costs provided for monitors.

Flare Gas Flow Monitor 440,000 39,210 80,750 See Attachment 3

Steam Controls/Flow Monitor 684,000 59,730 124,300 See Attachment 3

Air Controls/ Flow Monitor 164,000 36,520 52,000 See Attachment 3

Average Natural Gas Costs

per Flare to Meet NHVcz

Targets

0 98,660 98,660

$5/Mscf; Quantity of 

natural gas needed per 

flare was estimated from 

refinery flare dataset

Steam Costs (Savings) per 

Flare for Steam Controls to 

Meet NHVcz Targets

0 -73,770 -73,770

$6.12/1,000 lb; Quantity 

of steam saved per flare 

was estimated from 

refinery flare dataset

Engineering Calculation Costs 7,000 12,500 13,160

Capital costs: Sroka,

2011; Operating costs: 

$500 analytical costs and 

$1,000 engr. labor per 

event; 5 events/yr and 3 

samples per event.

a $/Mscf = dollars per thousand standard cubic feet; $/1,000 lb = dollars per 1,000 pounds.

Based on the data available from the refinery flare dataset, only a direct analysis of compliance 

with the combustion zone net heating value requirement could be assessed. In order to comply 

only with the combustion zone net heating value requirement, only the installation and use of a 

calorimeter is necessary. A total HC analyzer could be used to comply with a combustion zone 

combustibles concentration and a GC would be needed to determine the lower flammability limit 

of the gas mixture. While the use of a calorimeter would limit the capital costs, it would only 

provide a demonstration of compliance with the combustion zone net heating value requirement. 

If a GC is installed, the owner or operator of the flare can determine all three indicators of good 

combustion and comply with whichever limit requires the least supplemental natural gas 

addition. In addition to some reductions in natural gas costs, Marathon representatives indicated

that gas composition information provided by a GC had enabled identification of product leaks 

into the flare gas system (see Attachment 5). As a consequence, installation of a GC to 

determine waste gas composition resulted in additional cost savings due to reduced product 

13
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

losses. While this savings is highly variable and was not monetized by Marathon, this 

experience suggests that use of a GC rather than a calorimeter may result in additional cost 

savings. When considering this additional cost savings, the annualized cost of using a GC may 

be comparable to the annualized cost of using a calorimeter for compliance with the flare 

monitoring provisions.

Number of Flares Needing New Monitoring Systems

Under Alternative 1, all flares would be required to meet the specified operating limits, but the 

individual owner or operator would have the choice of whether to install continuous monitoring 

systems or to use grab samples and engineering calculation. In Alternative 2, owners or 

operators of flares would have to install continuous monitoring systems on each flare.

As noted previously, many flares will be required to install flare gas flow meters to comply with 

the provisions of 40 CFR part 60, subpart Ja. While the subpart Ja requirements apply only to 

new or modified flares, subpart Ja has a “quick trigger” for modifications and the EPA projects 

that all flares will become subject to subpart Ja over the next 5 years. Under subpart Ja, 

emergency-only flares and flares with adequately sized and operated FGRS are not required to 

install flare gas flow meters; all other flares would have flare gas flow meters installed. 

Therefore, it is assumed under Alternative 1, all flares would already have installed a flare flow 

monitor. It is further assumed that all flares that were projected to use the alternative monitoring 

approach of grab samples and engineering calculations under Alternatives 1 would need to install 

a flare flow meter in order to comply with the requirements in Alternative 2.

Information from ICR Component 1 was used as a means to estimate the number of flares that 

would install monitoring systems rather than using the grab sampling and engineering calculation 

alternative. ICR respondents could specify whether flare gas was combusted routinely or only 

during startup, shutdown, or upsets. ICR respondents could also specify the types of control 

used for a given flare, including use of a FGRS. Two options were provided for FGRS: 1) a 

FGRS is present, but not designed to recover 100 percent of the flare gas during normal 

operations and 2) a FGRS is present that is designed to recover 100 percent of the flare gas 

during normal operations. Counts for routine and non-routine flares were provided previously in 

Table 3. Table 8 provides additional counts for “routine” flares based on the FGRS designation. 

All flares that receive routine flow and that do not have a FGRS designed to recover all of the 

flare gas were assumed to use the continuous monitoring alternative.

14
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

Table 8. Breakdown of Routine Flares with Respect to FGRS

Flare Assist Type

# Routine Flares

# Routine Flares 

with full FGRS

# Routine Flares 

with partial FGRS

# Routine Flares 

without FGRS

63.11a Allb 63.11a Allb 63.11a Allb 63.11a Allb

Unassisted 13 19 3 3 1 1 9 15

Steam Assisted 161 228 31 38 19 27 111 163

Air Assisted 21 38 1 1 0 1 20 36

Total No. of Flares 195 285 35 42 20 29 140 214

a Flares that reported to be subject to 40 CFR 63.11 in the Petroleum Refinery 2011 ICR.

b All Flares represents the total number of flares at major sources reported from the Petroleum Refinery 2011 ICR.

Many flares already have flare gas monitoring systems to comply with state or local 

requirements or to gain process operating information. Net heating values are commonly 

determined by compositional analysis, so some flares are expected to already be equipped with a 

GC. Data reported in the Refinery ICR were used to determine if calorimeters or GC monitors 

were already available for the flare. Flares that had an existing flare management plan (FMP) 

during the time period of the Refinery ICR (circa 2010) were requested to provide information 

regarding the components of that plan; one of the FMP component options was monitoring the 

heat content of the flared gas. Thus, for flares that have an FMP, there was a direct indication for 

a heat content monitor, but only a limited number of flares had an FMP. All flares were required 

to report the “typical lower heating value of the waste gas.” A significant number of flares 

reported heating values to the nearest 1 Btu or even fractions of a Btu. A facility that does not 

have a heat content monitor would be expected to provide a rounded heating value number like 

“800 Btu/scf” while a flare that has a Btu monitor may report “831 Btu/scf.” Similarly, it is 

unlikely that a facility that does not have a Btu monitor on their flare would report a value of 

“810 Btu/scf”; they would generally provide an estimate to the nearest 100 Btu, such as 

“800 Btu/scf.” Thus, the accuracy to which a respondent reported the “typical” Btu content of 

the flare gas was used as another indication that heat content monitoring equipment is used for 

that flare.

Table 9 provides a summary of the number of flares expected to use the continuous monitoring 

option (i.e., all routine flares that do not have full-flare gas recovery) as well as the number of 

those flares that are expected to already have versus need to install heat content monitors.

15
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

Table 9. Estimate of the Number of Flares Needing Additional Heat Content Monitors

Flare Assist Type

# Routine flares that do 

not have full FGRS

# of these flares with 

existing heat content 

monitor

# of flares needing to 

install a new heat 

content monitor

63.11a Allb 63.11a Allb 63.11a Allb

Unassisted 10 16 5 8 5 8

Steam Assisted 130 190 92 123 38 67

Air Assisted 20 37 14 27 6 10

Total No. of Flares 160 243 111 158 49 85

a Flares that reported to be subject to 40 CFR 63.11 in the Petroleum Refinery 2011 ICR.

b All Flares represents the total number of flares at major sources reported from the Petroleum Refinery 2011 ICR.

The GHGRP requires flares that have carbon content or heat content monitors on flares to 

determine their emissions using those monitors using Equation Y-1a, Y-1b, or Y-2 of 40 CFR 

part 98, subpart Y. Of 460 flares reporting under subpart Y in the 2011 reporting year, emissions 

from 134 flares were reporting using Equation Y-1a, Y-1b, or Y-2. This agrees reasonably well 

with the estimate of 161 existing monitors as projected from the ICR Component 1 data and 

presented in Table 8.

All steam-assisted flares electing to use the continuous monitoring option were assumed to 

install the steam controls and steam flow monitors and all air-assisted flares electing to use the 

continuous monitoring option were assumed to install the air controls (i.e., variable fan drive 

blower) and air flow monitors. All flares using the engineering calculation method were 

assumed to use existing manual assist-media controls and estimate flow from line pressure, valve 

position, and other process variables.

Nationwide Cost Estimate for Flare Control Alternatives

The nationwide cost estimates were determined by multiplying the flare monitoring system cost 

elements in Table 7 by the number of flares expected to need that monitoring system based upon

the flare counts in Table 9 or, in the case of Alternative 2, the flare counts in included in Table 3. 

For this analysis, owners or operators of flares were projected to install a calorimeter and comply 

with the net heating value operating limit. As noted previously, it may be advantageous in some 

cases to install a GC so that compliance can be determined using any of the alternative operating 

parameters and to help identify potential product losses. Facilities installing GC systems would 

have higher initial capital costs but are expected to have similar or lower annualized costs based 

on historic product recovery credits realized by facilities who have installed continuous GC 

monitoring systems and potentially lower supplemental natural gas costs (if, for example, the 

lower flammability limit can be met with less supplemental natural gas than the net heating value 

operating limit). Steam reduction credits and natural gas supplementation costs were only 

assigned to flares electing continuous monitoring; flares using the engineering calculation were 

assumed to maintain their current steam and natural gas use rates. Table 10 provides a summary 

of the cost calculations for Control Alternative 1 considering all flares at major source refineries.

16
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014 

Table 10. Calculation of Costs for Control Alternative 1 for all Flares at Major Source 

Refineries (in 2010$)

Monitoring Equip. or 

Material

Capital 

Equipment 

Cost 

($/flare)

Annualized 

Cost 

($/yr/flare)

Number 

of 

Flares

Nationwide 

Capital 

Equipment 

Cost (MM$)g

Nationwide 

Total 

Annualized 

Cost 

(MM$/yr)g

GC 980,000 141,500 0a 0 0

HC Analyzer 180,000 61,000 0a 0 0

Calorimeter 105,000 30,000 85a 8.93 2.55

Flare Gas Flow Monitor 440,000 80,750 0b 0 0 

Steam Controls/Flow Monitor 684,000 124,300 190c 130.0 23.62

Air Controls/ Flow Monitor 164,000 52,000 37d 6.07 1.92

Average Natural Gas Costs per 

Flare to Meet NHVcz Targets 0 98,660 190c 0 18.75

Steam Costs (Savings) per 

Flare for Steam Controls to 

Meet NHVcz Targets

0 -73,770 190c 0 -14.02

Engineering Calculation Costs 7,000 13,160 267e 1.87 3.51

Nationwide Totals 510f 147 36.3

a Assumed all refineries elect to install a calorimeter if needing a monitor. Number of flares needing a monitor is 88 

(from Table 9). b Assumed all routine flow flares already have a flow monitor to comply with NSPS subpart Ja. c Number of steam-assisted flares with routine flow but without full FGRS from Table 9. d Number of air-assisted flares with routine flow but without full FGRS from Table 9. e Number of non-routine flares (225 from Table 3) plus the number of routine flow flares with full FGRS (42 from 

Table 8). 225+42=267. f

Total number of all flares at petroleum refineries from Table 3.

g MM$ = million dollars; MM$/yr = million dollars per year.

It is expected that flares that elect to use the engineering calculation method under Alternative 1

will have less opportunity for steam savings as well as less need for supplemental gas. A 

significant portion of the gas discharged to these flares will be associated with startup, shutdown, 

or upsets characterized by higher flow rates, so there would be limited times where steam or 

natural gas adjustments would be necessary. Under Alternative 2, the “other” flares (non-routine 

flow flares including flares with full FGRS) are required to install continuous heat content or 

composition monitors. They were also assumed to install steam- or air-assist control and flow 

monitors, but they were assumed to have half the supplemental natural gas needs as the “routine” 

flares and also half the steam reduction credits as the “routine” flares. Table 11 provides a 

summary of the cost calculations for Control Alternative 2 considering all flares at major source 

refineries. 

17 
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014 

Table 11. Calculation of Costs for Control Alternative 2 for all Flares at Major Source 

Refineries (in 2010$)

Monitoring Equip. or 

Material

Capital 

Equipment 

Cost 

($/flare)

Annualized 

Cost 

($/yr/flare)

Number 

of 

Flares

Nationwide 

Capital 

Equipment 

Cost (MM$)

Nationwide 

Total 

Annualized 

Cost 

(MM$/yr)

GC 980,000 141,500 0a 0 0

HC Analyzer 180,000 61,000 0a 0 0

Calorimeter 105,000 30,000 352a 37.0 10.56

Flare Gas Flow Monitor 440,000 80,750 267b 117.5 21.56

Steam Controls/Flow Monitor 684,000 124,300 402c 275.0 49.97

Air Controls/ Flow Monitor 164,000 52,000 59d 9.7 3.07

Average Natural Gas Costs per 

Routine Flow Flare to Meet 

NHVcz Targets

0 98,660 190e 0 18.75

Steam Costs (Savings) per 

Routine Flow Flare for Steam 

Controls to Meet NHVcz Targets

0 -73,770 190e 0 -14.02

Average Natural Gas Costs per 

“Other” Flare to Meet NHVcz

Targets

0 49,330 212f 0 10.46

Steam Costs (Savings) per 

“Other” Flare for Steam 

Controls to Meet NHVcz Targets

0 -36,885 212f 0 -7.82 

Engineering Calculation Costs 7,000 13,160 0 0 0

Nationwide Totals 510g 439 92.5

a

 All flares at major source refineries (510 from Table 3) minus flares with existing monitors (158 from Table 9). b Number of all “other” flares (non-routine or with full FGRS) = all flares (510 from Table 3) minus routine flow flares 

without full FGRS (243 from Table 9). Assumed all routine flow flares already have a flow monitor to comply 

with NSPS subpart Ja. c Number of all steam-assisted flares from Table 3. d Number of all air-assisted flares from Table 3. e Number of steam-assisted flares with routine flow but without full FGRS from Table 9. f

Number of “other” steam-assisted flares = 402 (table note “c”) – 190 (table note “e”) = 212. g Total number of all flares at petroleum refineries from Table 3.

Table 12 summarizes the control costs associated with the regulatory alternatives considering 

only “Part 63 flares” and considering all flares at major source refineries. As noted previously, 

the cost for “Part 63 flares” is likely to be a lower estimate of the actual costs of the amendments 

and the costs for all flares is expected to be an upper, but more accurate, estimate. Table 13 

provides the VOC cost effectiveness of the control alternatives considering all flares; Table 14

provides the HAP cost effectiveness of the control alternatives considering all flares. Because 

both the emission reductions and costs were estimated on a per flare basis, the cost effectiveness 

18 
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates

January 16, 2014

value for “Part 63 flares” is expected to be essentially equivalent to the cost effectiveness for all 

flares at major source refineries.

Table 12. Summary of Capital and Annualized Costs for Flare Control Alternatives

Control Alternative 

Description

Flares Currently Subject to 

40 CFR 63.11

All Flares at Major Source 

Refineries

Total Capital 

Investment 

(MM$)

Total 

Annualized 

Cost (MM$/yr)

Total Capital 

Investment 

(MM$)

Total

Annualized 

Cost (MM$/yr)

1. 270 Btu/scf; Engr. Calcs 98 23.4 147 36.3

2. 270 Btu/scf; Monitors Only 219 66.1 439 92.5

Table 13. Summary of VOC Cost Effectiveness for Flare Control Alternatives (All Flares at 

Major Source Refineries)

Control Alternative 

Description

Total 

Annualized 

Cost (MM$/yr)

VOC Emission 

Reductions 

(tons/yr)

Cost

Effectiveness 

($/ton)

Incremental

Cost

Effectiveness 

($/ton)

1. 270 Btu/scf; Engr. Calcs 36.3 33,100 1,100 1,100

2. 270 Btu/scf; Monitors Only 92.5 34,400 2,690 43,200

Table 14. Summary of HAP Cost Effectiveness for Flare Control Alternatives (All Flares at 

Major Source Refineries)

Control Alternative 

Description

Total 

Annualized 

Cost (MM$/yr)

HAP Emission 

Reductions 

(tons/yr)

Cost 

Effectiveness 

($/ton)

Incremental

Cost

Effectiveness 

($/ton)

1. 270 Btu/scf; Engr. Calcs 36.3 3,810 9,540 9,540

2. 270 Btu/scf; Monitors Only 92.5 3,960 23,400 375,000

6. References

EPA (U.S. Environmental Protection Agency). 2002. EPA Air Pollution Control Cost Manual. 

Sixth Edition. EPA/452/B-02-001. U.S. Environmental Protection Agency, Office of Air 

Quality Planning and Standards, Research Triangle Park, NC. January 2002.

19
Technical Memorandum – Petroleum Refinery Sector Rule: Flare Impacts Estimates 

January 16, 2014 

 20 

EPA (U.S. Environmental Protection Agency). 2011. Petroleum Refinery Database, based on 

Refinery Information Collection Request (ICR) for Calendar Year 2010. September 2011. 

Docket Item Nos. EPA-HQ-OAR-2010-0682-0061 through 0069. 

EPA (U.S. Environmental Protection Agency). 2012. Parameters for Properly Designed and 

Operated Flares. Prepared for U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. April 2012. 

IPCC (Intergovernmental Panel on Climate Change). 1995. Climate Change 1995: The Science 

of Climate Change – Contribution of Working Group I to the Second Assessment Report of 

the Intergovernmental Panel on Climate Change. Prepared by the Intergovernmental Panel 

on Climate Change. Available at 

http://www.ipcc.ch/ipccreports/sar/wg_I/ipcc_sar_wg_I_full_report.pdf. 

IPCC (Intergovernmental Panel on Climate Change). 2007. Climate Change 2007: Working 

Group I: The Physical Science Basis. Prepared by the Intergovernmental Panel on Climate 

Change. Available at 

http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_wg1

_report_the_physical_science_basis.htm. 

Foley, P. 2013. U.S. EPA Flare Enforcement Overview. Presented at the American Fuels and 

Petrochemical Manufacturers (AFPM) Annual Meeting, San Antonio, TX. March 18, 2013. 

RTI (RTI International). 2011. Emission Estimation Protocol for Petroleum Refineries. 

Version 2.1.1, Final ICR Version Corrected. Prepared for U.S. Environmental Protection 

Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. May 

2011. Docket Item No. EPA-HQ-OAR-2010-0682-0060. Most current version also 

available at http://www.epa.gov/ttn/chief/efpac/protocol/. 

Sroka, K. 2011. Attachment 2 of memorandum from Kristin Sroka to Docket ID No. EPA-HQOAR-2007-0011 regarding “NSPS Subpart J Review: Meeting minutes for February 25, 

2011, Conference Call Between the U.S. EPA and Representatives of Lion Oil and John 

Zink” dated October 21, 2011. Docket Item No. EPA-HQ-OAR-2007-0011-0337. 
Attachment 1

VOC and HAP Data from the Component 2 Dataset
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI01053ref1.5 Goodway Refining LLC Atmore AL 306009 Facility Flare Flare 0.046 0.019 0.019

NEI02185ref4 BP Exploration (Alaska) Inc. Prudhoe Bay AK 30600904 1 F1 F1 2.531

NEI02185ref4 BP Exploration (Alaska) Inc. Prudhoe Bay AK 30600904 1 F2 F2 0.485

NEI109 SUNOCO MARCUS HOOK REF MARCUS HOOK PA 30600904 10-4 Fccu 10 Plant Flare 10 Plant Flare 73.506 7.321 7.321

NEI109 SUNOCO MARCUS HOOK REF MARCUS HOOK PA 30600904 12 Plant 12 Plant Flare 12 Plant Flare 8.747 7.321 7.321

NEI109 SUNOCO MARCUS HOOK REF MARCUS HOOK PA 30600904 Ethylene Oxide EC Flare EC Flare 37.096 3.373 3.373

NEI11119 SHELL OIL DEER PARK DEER PARK TX 30600904 Alkylation Unit FLNFLARE FLNFLARE 7.804 28.274 0.251

NEI11119 SHELL OIL DEER PARK DEER PARK TX 30600904 Coker CKGFLARE CKGFLARE 0.350 0.282 0.0018

NEI11119 SHELL OIL DEER PARK DEER PARK TX 30600904 CR3TF EP FLARE EP FLARE 87.171 93.977 0.134

NEI11119 SHELL OIL DEER PARK DEER PARK TX 30600904 GIRBOTOL A1005 A1005 0.764 0.896 0.0041

NEI11192 EL PASO REFINERY EL PASO TX 30600904 112 112 112 0.0084 0.0129 0.0030

NEI11192 EL PASO REFINERY EL PASO TX 30600904 D-2914 D-2914 D-2914 0.0602 0.0921 0.0214

NEI11192 EL PASO REFINERY EL PASO TX 30600904 R-2911 R-2911 R-2911 0.0084 0.0129 0.0030

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 306009 E-MC-24-25 E-MC-24-25 E-MC-24-25 21.644 3.416 0.721

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 306009 WWTP-8742 F-01-TO1 F-01-TO1 20.780 17.500 5.725

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 103B F-103FLARE F-103FLARE 0.0121 0.0045 0.0045

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 13 F-13-FLARE F-13-FLARE 24.298 8.971 8.971

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 15 F15FLARE F15FLARE 0.615 0.227 0.227

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 18 F-18-FLARE F-18-FLARE 0.549 0.203 0.203

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 19 F-19-FLARE F-19-FLARE 2.015 0.744 0.744

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 2 F-22-FLARE F-22-FLARE 0.604 0.223 0.223

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 20 F-20-FLARE F-20-FLARE 0.339 0.125 0.125

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 23 E-23-FLARE E-23-FLARE 14.409 5.320 5.320

NEI11200 Valero Refining Co. - Port Arthur (prev. Pre PORTARTHUR TX 30600904 Flare 5 F-05-FLARE F-05-FLARE 2.344 0.866 0.866

NEI11232 CHANNEL ENERGY ENERGY HOUSTON TX 30600904 338-UNIT 338K0001 338K0001 1.921 1.868 0.044

NEI11232 CHANNEL ENERGY ENERGY HOUSTON TX 30600904 338-UNIT 338K0002 338K0002 1.578 1.796 0.026

NEI11232 CHANNEL ENERGY ENERGY HOUSTON TX 30600904 338-UNIT 338K0005 338K0005 0.826 0.256 0.004

NEI11232 CHANNEL ENERGY ENERGY HOUSTON TX 30600904 338-UNIT 338K0007 338K0007 10.930 4.624 0.054

NEI11232 CHANNEL ENERGY ENERGY HOUSTON TX 30600904 338-UNIT 338K0008 338K0008 0.627 0.507 0.021

NEI11232 CHANNEL ENERGY ENERGY HOUSTON TX 30600904 736-UNIT 736K0101A 736K0101A 2.015 0.551 0.080

NEI113 CONOCOPHILLIPS CO. TRAINER REFINERY TRAINER PA 306009 103 103 103 45.100 0.903 0.904

NEI113 CONOCOPHILLIPS CO. TRAINER REFINERY TRAINER PA 306009 120 120 120 31.230 2.020 0.226

NEI113 CONOCOPHILLIPS CO. TRAINER REFINERY TRAINER PA 306009 121 121 121 13.600 0.866 0.097

NEI11450 SUNOCO INC. TOLEDO REFINERY OREGON OH 30600904 P008 P008 P008 170.000 42.666 9.722

NEI11450 SUNOCO INC. TOLEDO REFINERY OREGON OH 30600904 P009 P009 P009 73.000 5.965 1.359

NEI11574 MARATHON PETROLEUM COMPANY LLC, CANTON OH 30600904 General P003 P003 5.738 0.347 0.082

NEI11574 MARATHON PETROLEUM COMPANY LLC, CANTON OH 30600904 General P004 P004 10.352 0.092 0.022

NEI11663 Valero Refining Co. (prev. Premcor Refinin LIMA OH 306009 P006 P006 P006 38.000 1.738 0.050

NEI11663 Valero Refining Co. (prev. Premcor Refinin LIMA OH 306009 P007 P007 P007 101.000 1.371 0.184

NEI11663 Valero Refining Co. (prev. Premcor Refinin LIMA OH 306009 P036 P036 P036 0.042

NEI11715 BP PRODUCTS NORTH AMERICA INC, WHI WHITING IN 30600903 4UF 224-06 224-06 18.323 5.095 5.095

NEI11715 BP PRODUCTS NORTH AMERICA INC, WHI WHITING IN 30600903 ALKY 140-01 140-01 45.828 5.095 5.095

NEI11715 BP PRODUCTS NORTH AMERICA INC, WHI WHITING IN 30600903 DDU 698-02 698-02 21.649 5.095 5.095

NEI11715 BP PRODUCTS NORTH AMERICA INC, WHI WHITING IN 30600903 FCU5 230-02 230-02 8.476 5.095 5.095

NEI11715 BP PRODUCTS NORTH AMERICA INC, WHI WHITING IN 30600903 OMDN 604-01 604-01 3207.650 5.095 5.095

NEI11715 BP PRODUCTS NORTH AMERICA INC, WHI WHITING IN 30600903 SRU 162-03 162-03 4.537 5.095 5.095

NEI11715 BP PRODUCTS NORTH AMERICA INC, WHI WHITING IN 30600903 UIU 220-04 220-04 16.702 5.095 5.095
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI11715 BP PRODUCTS NORTH AMERICA INC, WHI WHITING IN 30600903 VRU1 241-01 241-01 6.886 5.095 5.095

NEI11885 MARATHON ASHLAND PETROLEUM DETROIT MI 306009 Melvindale / CP / Crud Rane 2 Rane 2 1.548 0.000020 0.000005

NEI11885 MARATHON ASHLAND PETROLEUM DETROIT MI 30600903 11 25FS-1 25FS-1 37.234 24.404 0.293

NEI11885 MARATHON ASHLAND PETROLEUM DETROIT MI 30600903 4 4V7 4V7 3.285 2.463 0.039

NEI11885 MARATHON ASHLAND PETROLEUM DETROIT MI 30600903 7 7FS-2 7FS-2 46.092 34.177 0.415

NEI11885 MARATHON ASHLAND PETROLEUM DETROIT MI 30600903 9 9FS-1 9FS-1 6.571 4.900 0.067

NEI12044 MARATHON ASHLAND PETROLEUM CO LLTEXAS CITY TX 30600904 25 ES33A ES33A 0.612 0.256 0.154

NEI12044 MARATHON ASHLAND PETROLEUM CO LLTEXAS CITY TX 30600904 84 P1 P1 25.945 25.507 3.697

NEI12044 MARATHON ASHLAND PETROLEUM CO LLTEXAS CITY TX 30600904 84 P200 P200 24.015 24.015 5.230

NEI12084 VALERO REFINING - TEXAS L.P. CORPUS CHRISTI TX 306009 BUP Flare Flare - BUP Flare - BUP 0.040

NEI12084 VALERO REFINING - TEXAS L.P. CORPUS CHRISTI TX 306009 Ground Flare Flare - Ground Flare - Ground 2.807

NEI12084 VALERO REFINING - TEXAS L.P. CORPUS CHRISTI TX 306009 MFL-1 Flare - Main Flare - Main 15.521 4.733 4.733

NEI12458 CENEX INC LAUREL REFINERY LAUREL MT 30600903 FL-7201 FL-7201 FL-7201 3.705 2.290 2.290

NEI12458 CENEX INC LAUREL REFINERY LAUREL MT 30600903 FL-7202 FL-7202 FL-7202 3.470 2.290 2.290

NEI12459 CONOCO INCORPORATED REFINERY BILLINGS MT 30600999 FLR-1 FLR-1 FLR-1 9.100 2.340 2.340

NEI12464 MONTANA REFINING COMPANY GREAT FALLS MT 30600904 999 999 999 8.780 0.402 0.402

NEI12486 VALERO THREE RIVERS REFINERY THREE RIVERS TX 306009 FL-003 FL-003 FL-003 39.114 39.619 1.979

NEI12486 VALERO THREE RIVERS REFINERY THREE RIVERS TX 306009 FL-004 FL-004 FL-004 18.050 18.283 0.750

NEI12486 VALERO THREE RIVERS REFINERY THREE RIVERS TX 306009 FL-005 FL-005 FL-005 1.608 0.131 0.131

NEI12486 VALERO THREE RIVERS REFINERY THREE RIVERS TX 306009 FL-006 FL-006 FL-006 22.429 22.719 1.046

NEI12486 VALERO THREE RIVERS REFINERY THREE RIVERS TX 306009 FL-501 FL-501 FL-501 13.844 14.023 0.683

NEI12711 VALERO REFINING HOUSTON REFINERY HOUSTON TX 30600999 A Hydrotreater Unit 27ENG1 27ENG1 0.0070 0.00044 0.00026

NEI12711 VALERO REFINING HOUSTON REFINERY HOUSTON TX 30600999 All Units 30FL1 30FL1 0.588 0.475 0.000006

NEI12711 VALERO REFINING HOUSTON REFINERY HOUSTON TX 30600999 Groundwater Recover 81SKD5602 81SKD5602 0.090 0.011 0.011

NEI12711 VALERO REFINING HOUSTON REFINERY HOUSTON TX 30600999 Groundwater Recover 81SKD5603 81SKD5603 0.042 0.005 0.005

NEI12711 VALERO REFINING HOUSTON REFINERY HOUSTON TX 30600999 Groundwater Recover 91CB915 91CB915 1.841 0.029 0.029

NEI12711 VALERO REFINING HOUSTON REFINERY HOUSTON TX 30600999 Supply and Distributio 90CB5601 90CB5601 8.788 0.605 0.287

NEI12711 VALERO REFINING HOUSTON REFINERY HOUSTON TX 30600999 Ultra-Low Sulfur Diese 30FL6 30FL6 24.027 9.158 0.121

NEI12791 Valero Refining Co. Texas TEXAS CITY TX 30600903 #1 & #2 CRUDE, UTILIT EFL-1 EFL-1 10.654 6.977 0.340

NEI12791 Valero Refining Co. Texas TEXAS CITY TX 30600903 ALKY, #2 REFORMER, P EFL-02 EFL-02 7.803 4.739 0.059

NEI12791 Valero Refining Co. Texas TEXAS CITY TX 30600903 COKER, GDU, LRU EFL-05 EFL-05 2.399 1.502 0.186

NEI12791 Valero Refining Co. Texas TEXAS CITY TX 30600903 FCCU, GAS CON, INALK EFL-3 EFL-3 7.823 4.342 0.214

NEI12791 Valero Refining Co. Texas TEXAS CITY TX 30600903 FCCU, GOHT, GOHT SREFL-4 EFL-4 7.267 4.795 0.875

NEI12968 SINCLAIR OIL TULSA REFINING TULSA TRUTULSA OK 30600903 #1 Flare, #2 Flare Flares Flares 4.500

NEI12968 SINCLAIR OIL TULSA REFINING TULSA TRUTULSA OK 30600903 CCR CCR Chlorosorb Vent CCR Chlorosorb Vent 1.608

NEI12969 SUNOCO PIPELINE LP - SUNOCO BALLINGE TULSA OK 30600903 Coker Flare Coker Flare Coker Flare 0.408 0.082 0.082

NEI12969 SUNOCO PIPELINE LP - SUNOCO BALLINGE TULSA OK 30600903 LEU Flare Lube Flare Lube Flare 0.140 0.038 0.038

NEI12969 SUNOCO PIPELINE LP - SUNOCO BALLINGE TULSA OK 30600903 Platformer Flare #2 Alkyllation Flare #2 Alkyllation Flare 25.998 7.806 7.806

NEI12988 CONOCOPHILLIPS CO PONCA CITY REFI NEPONCA CITY OK 30600904 Coker Combo Alky FlarFLARE - CC FLARE - CC 20.778

NEI12988 CONOCOPHILLIPS CO PONCA CITY REFI NEPONCA CITY OK 30600904 East Plant Flare FLARE - EP FLARE - EP 2.012

NEI12988 CONOCOPHILLIPS CO PONCA CITY REFI NEPONCA CITY OK 30600904 FLARE-CF FLARE-CF FLARE-CF 2.544

NEI12988 CONOCOPHILLIPS CO PONCA CITY REFI NEPONCA CITY OK 30600904 Miscellaneous CPC LOADING FLARE CPC LOADING FLARE 7.390 0.123 0.123

NEI12988 CONOCOPHILLIPS CO PONCA CITY REFI NEPONCA CITY OK 30600904 Miscellaneous Flare-total Flare-total 8.510 8.510

NEI12988 CONOCOPHILLIPS CO PONCA CITY REFI NEPONCA CITY OK 30600904 South Plant Flare FLARE - SP FLARE - SP 4.601

NEI13322 CHEVRON PRODUCTS CO - HAWAII REFIN KAPOLEI HI 30600904 23 M8 M8 1.696 0.493 0.476

NEI13322 CHEVRON PRODUCTS CO - HAWAII REFIN KAPOLEI HI 30600904 23 M9 M9 0.035 2.301 1.270

NEI13371 Tesoro Alaska Petroleum Company Kenai KENAI AK 306009 Refinery Flare Refinery Flare Refinery Flare 22.577 1.312 0.313
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI13371 Tesoro Alaska Petroleum Company Kenai KENAI AK 30600903 J801 Pilot J801 Pilot J801 Pilot 0.0035 0.0054 0.0013

NEI13371 Tesoro Alaska Petroleum Company Kenai KENAI AK 30600999 SRU Flare SRU Flare SRU Flare 0.0035 0.0054 0.0013

NEI18394 HUNT REFINING CO A CORPORATION TUSCALOOSA AL 30600904 Coker Unit M-2201 M-2201 0.120

NEI18394 HUNT REFINING CO A CORPORATION TUSCALOOSA AL 30600904 Crude Unit STF-5-24C STF-5-24C 0.180

NEI18394 HUNT REFINING CO A CORPORATION TUSCALOOSA AL 30600904 Gas Oil Hydrobon UnitD10.3301 D10.3301 0.120

NEI18394 HUNT REFINING CO A CORPORATION TUSCALOOSA AL 30600904 Hydrocracker Flare Hydrocracker Flare Hydrocracker Flare 0.700

NEI18415 PETRO STAR VALDEZ REFY VALDEZ AK 306009 21 21 21 0.0011 0.00011 0.00011

NEI19834 SHELL OIL PRODUCTS US - MARTINEZ REF MARTINEZ CA 30600904 Flare 1 Flare_LOP Flare_LOP 0.0145 0.00041 0.00045

NEI19834 SHELL OIL PRODUCTS US - MARTINEZ REF MARTINEZ CA 30600904 Flare 3 Flare_OPCEN Flare_OPCEN 0.0145 0.00041 0.00045

NEI19834 SHELL OIL PRODUCTS US - MARTINEZ REF MARTINEZ CA 30600904 Flare 4 Flare_Flexigas Flare_Flexigas 0.0072 0.00020 0.00022

NEI19834 SHELL OIL PRODUCTS US - MARTINEZ REF MARTINEZ CA 30600904 Flare 5 Flare_DCU Flare_DCU 0.0792 0.0022 0.0025

NEI19834 SHELL OIL PRODUCTS US - MARTINEZ REF MARTINEZ CA 30600905 Flare 6 Flare_LPG_Loading Flare_LPG_Loading 14.9893 0.0245 0.0084

NEI19834 SHELL OIL PRODUCTS US - MARTINEZ REF MARTINEZ CA 30600999 Flare 7 Flare_VRS1 Flare_VRS1 0.000670 0.000019 0.000021

NEI19834 SHELL OIL PRODUCTS US - MARTINEZ REF MARTINEZ CA 30600999 Flare 9 Flare_VRS3 Flare_VRS3 0.000042 0.0000012 0.0000013

NEI19869 CONOCOPHILLIPS SANTA MARIA FACILITY ARROYO GRANDE CA 30600903 Refinery C-451 C-451 0.017 0.004

NEI19870 CONOCOPHILLIPS SAN FRANCISCO AREA R RODEO CA 306009 Main Main Flare Main Flare 9.992 4.402 4.402

NEI19870 CONOCOPHILLIPS SAN FRANCISCO AREA R RODEO CA 306009 MP-30 MP-30 Flare MP-30 Flare 0.446

NEI20103 KERN OIL & REFINING COMPANY BAKERSFIELD CA 306009 ############# S-37-7 S-37-7 1.080 1.080

NEI20154 SAN JOAQUIN REFINING COMPANY INCORBAKERSFIELD CA 30600903 HAD/HDS/HOH 51 - 7 51 - 7 0.210 0.020 0.021

NEI20174 Big West Oil LLC (prev. Shell Oil Products UBAKERSFIELD CA 30600903 S-33-18-8 S-33-18-8(NG) S-33-18-8(NG) 4.201 0.012 0.0064

NEI20174 Big West Oil LLC (prev. Shell Oil Products UBAKERSFIELD CA 30600903 S-33-64-3 S-33-64-3(NG) S-33-64-3(NG) 0.018 0.000053 0.000029

NEI20174 Big West Oil LLC (prev. Shell Oil Products UBAKERSFIELD CA 30600903 S-33-65-5 S-33-65-5(NG) S-33-65-5(NG) 0.263 0.00073 0.00040

NEI20174 Big West Oil LLC (prev. Shell Oil Products UBAKERSFIELD CA 30600903 S-34-11-9 S-34-11-9(NG) S-34-11-9(NG) 0.116 0.00033 0.00019

NEI20174 Big West Oil LLC (prev. Shell Oil Products UBAKERSFIELD CA 30600904 S-33-18-8 S-33-18-8(FG) S-33-18-8(FG) 1.322 0.00445 0.00247

NEI20174 Big West Oil LLC (prev. Shell Oil Products UBAKERSFIELD CA 30600904 S-33-64-3 S-33-64-3(FG) S-33-64-3(FG) 0.086 0.00025 0.00014

NEI20174 Big West Oil LLC (prev. Shell Oil Products UBAKERSFIELD CA 30600904 S-33-65-5 S-33-65-5(FG) S-33-65-5(FG) 7.417 0.021 0.012

NEI20174 Big West Oil LLC (prev. Shell Oil Products UBAKERSFIELD CA 30600904 S-34-11-9 S-34-11-9(FG) S-34-11-9(FG) 0.632 0.0018 0.0010

NEI21130 PARAMOUNT PETROLEUM CORP PARAMOUNT CA 30600904 multiple units C396 C396 0.084 0.084

NEI21466 Valero Refining Co. - Wilmington (prev. Ul WILMINGTON CA 306009 -88 75-FT-1 75-FT-1 0.945 0.335 0.217

NEI21466 Valero Refining Co. - Wilmington (prev. Ul WILMINGTON CA 306009 -88 89-FT-900 89-FT-900 0.610 0.451 0.214

NEI21466 Valero Refining Co. - Wilmington (prev. Ul WILMINGTON CA 306009 -88 89-FT-9000 89-FT-9000 0.352 0.333 0.212

NEI21466 Valero Refining Co. - Wilmington (prev. Ul WILMINGTON CA 30600905 Unit 82 82-FT-1 82-FT-1 0.016 0.220 0.207

NEI25450 VALERO REFINING CO CALIFORNIA BENICI BENICIA CA 306009 S-17 (Butane Flare) Butane Flare Butane Flare 2.662 0.174 0.041

NEI25450 VALERO REFINING CO CALIFORNIA BENICI BENICIA CA 306009 S-18 (South Flare) South Flare South Flare 2.662 0.174 0.041

NEI25450 VALERO REFINING CO CALIFORNIA BENICI BENICIA CA 306009 S-19 (North Flare) North Flare North Flare 2.662 0.174 0.041

NEI25450 VALERO REFINING CO CALIFORNIA BENICI BENICIA CA 30600904 S-16 (Acid Gas Flare) AG Flare AG Flare 2.662 0.174 0.041

NEI26218 Valero Refining Co. (prev. Motiva Enterpri DELAWARE CITY DE 30600904 45-1 North Flare STACK-45-1 STACK-45-1 2.800

NEI26218 Valero Refining Co. (prev. Motiva Enterpri DELAWARE CITY DE 30600904 45-2 South Flare STACK-45-2 STACK-45-2 2.640

NEI26218 Valero Refining Co. (prev. Motiva Enterpri DELAWARE CITY DE 30600904 Unit 520 STACK-Propane Pit FlaSTACK-Propane Pit Flar 0.150

NEI26218 Valero Refining Co. (prev. Motiva Enterpri DELAWARE CITY DE 30600999 Barge Loading Flare STACK-Barge Loading STACK-Barge Loading F 0.200

NEI26533 TESORO HAWAII CORPORATION REFINERYKAPOLEI HI 30600904 FFlare 21 (FFlare(RFG)) 21 (FFlare(RFG)) 0.005 0.012 0.0028

NEI26533 TESORO HAWAII CORPORATION REFINERYKAPOLEI HI 30600904 FFlare 21 (Fflare(WasteGas)) 21 (Fflare(WasteGas)) 26.341 5.304 4.111

NEI2CA131003 BP CARSON REFINERY CARSON CA 30600904 16001 C1302 C1302 0.133 1.744 1.744

NEI2CA131003 BP CARSON REFINERY CARSON CA 30600904 C1305 C1305 C1305 0.041 1.744 1.744

NEI2CA131003 BP CARSON REFINERY CARSON CA 30600904 C1308 C1308 C1308 0.068 1.744 1.744

NEI2CA131003 BP CARSON REFINERY CARSON CA 30600904 C1326 C1326 C1326 0.027 1.744 1.744

NEI2CA131003 BP CARSON REFINERY CARSON CA 30600904 C1661 C1661 C1661 0.094 1.744 1.744
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI32353 COUNTRYMARK COOPERATIVE, INC MOUNT VERNON IN 306009 All units 700-V-101 700-V-101 0.001 0.004 0.001

NEI32762 FRONTIER EL DORADO REFINING COMPANEL DORADO KS 306009 13 EU-B1302 EU-B1302 4.510 0.525 0.110

NEI32762 FRONTIER EL DORADO REFINING COMPANEL DORADO KS 30600905 13 EU-B1304 EU-B1304 0.597 0.597 0.597

NEI32801 NATIONAL COOPERATIVE REFINERY MC PHERSON KS 306009 HYD FS-01 - HYD FS-01 - HYD 0.070

NEI32864 MARATHON ASHLAND PETROLEUM/CATL CATLETTSBURG KY 306009 Multiple FCC Flare FCC Flare 0.045 0.056 0.148

NEI32864 MARATHON ASHLAND PETROLEUM/CATL CATLETTSBURG KY 306009 Multiple HF Alky Flare HF Alky Flare 0.554 0.111 1.152

NEI32864 MARATHON ASHLAND PETROLEUM/CATL CATLETTSBURG KY 306009 Multiple Lube Area Flare Lube Area Flare 2.116 4.610 10.967

NEI32864 MARATHON ASHLAND PETROLEUM/CATL CATLETTSBURG KY 306009 Multiple NNA Flare NNA Flare 2.373 0.240 3.206

NEI32864 MARATHON ASHLAND PETROLEUM/CATL CATLETTSBURG KY 306009 Multiple Pitch Flare Pitch Flare 0.080 4.540 4.663

NEI32997 SOMERSET REFINERY SOMERSET KY 30600904 Flare EP 4 EP 4 0.032 0.003 0.003

NEI33007 Calumet Lubricants Co. LP - Princeton PRINCETON LA 30600904 Hydrotreater PH-25 PH-25 18.945 1.123 0.265

NEI33007 Calumet Lubricants Co. LP - Princeton PRINCETON LA 30600904 Multiple 00-1 00-1 16.341 0.276 0.065

NEI33008 CALUMET SHREVEPORT LUBRICANTS AND SHREVEPORT LA 306009 All Units EQT016 EQT016 0.383 0.005 0.005

NEI33010 CALCASIEU REFINING CO LAKE CHARLES LA 306009 All Process Units F-400 F-400 0.074 0.114 0.027

NEI33031 MOTIVA ENTERPRISES LLC - NORCO REFINNORCO LA 306009 2-84 2-84 2-84 14.879 9.332 0.084

NEI33031 MOTIVA ENTERPRISES LLC - NORCO REFINNORCO LA 306009 3-84 3-84 3-84 21.390 12.638 9.036

NEI33031 MOTIVA ENTERPRISES LLC - NORCO REFINNORCO LA 306009 4-84 4-84 4-84 17.781 5.970 1.306

NEI33031 MOTIVA ENTERPRISES LLC - NORCO REFINNORCO LA 306009 5-84 5-84 5-84 0.366 0.101 0.0094

NEI33031 MOTIVA ENTERPRISES LLC - NORCO REFINNORCO LA 306009 6-84 6-84 6-84 2.145 1.488 0.169

NEI33031 MOTIVA ENTERPRISES LLC - NORCO REFINNORCO LA 306009 7-84 7-84 7-84 80.558 55.886 6.346

NEI33031 MOTIVA ENTERPRISES LLC - NORCO REFINNORCO LA 306009 8-84 8-84 8-84 0.014 0.014 0.000046

NEI33031 MOTIVA ENTERPRISES LLC - NORCO REFINNORCO LA 306009 9-84 9-84 9-84 49.285 16.495 1.903

NEI33039 CALUMET LUBRICANTS CO - COTTON VAL COTTON VALLEY LA 30600904 All Units SR0038 SR0038 0.330 0.198 0.153

NEI34057 CHEVRON TEXACO PRODUCTS COMPANY PASCAGOULA MS 30600904 38 F-3801 F-3801 0.085 0.130 0.031

NEI34057 CHEVRON TEXACO PRODUCTS COMPANY PASCAGOULA MS 30600904 38 F-3802 F-3802 0.085 23.143 5.457

NEI34057 CHEVRON TEXACO PRODUCTS COMPANY PASCAGOULA MS 30600904 38 F-3803 F-3803 0.470 616.119 145.154

NEI34057 CHEVRON TEXACO PRODUCTS COMPANY PASCAGOULA MS 30600904 38 F-3804 F-3804 0.077 11.617 2.734

NEI34057 CHEVRON TEXACO PRODUCTS COMPANY PASCAGOULA MS 30600904 38 F-3805 F-3805 0.280 261.859 61.690

NEI34057 CHEVRON TEXACO PRODUCTS COMPANY PASCAGOULA MS 30600904 38 F-3806 F-3806 0.110 0.341 0.081

NEI34057 CHEVRON TEXACO PRODUCTS COMPANY PASCAGOULA MS 30600904 38 F-3807 F-3807 0.610 859.764 202.536

NEI34069 ERGON REFINING INC VICKSBURG MS 30600903 FL-2 Flare AI-756 Flare AI-756 0.371

NEI34863 CITGO ASPHALT REFINING COMPANY PAULSBORO NJ 306009 U14 Flare U14 Flare U14 Flare 0.031 0.000008 0.000008

NEI34898 Navajo Refining Co. - Artesia ARTESIA NM 30600904 FL-400 FL-400 FL-400 0.731

NEI34898 Navajo Refining Co. - Artesia ARTESIA NM 30600904 FL-401 FL-401 FL-401 0.182

NEI34898 Navajo Refining Co. - Artesia ARTESIA NM 30600904 FL-402 FL-402 FL-402 0.182

NEI34898 Navajo Refining Co. - Artesia ARTESIA NM 30600904 FL-403 FL-403 FL-403 0.030

NEI34898 Navajo Refining Co. - Artesia ARTESIA NM 30600904 FL-404 FL-404 FL-404 1.490

NEI34907 Giant Refining Co. - Ciniza Refinery JAMESTOWN NM 306009 FL-1 FL-1 FL-1 13.882 0.850 0.850

NEI363 FRONTIER REFINING INC. CHEYENNE WY 30600904 44 44 44

NEI371 Little America Refining Co. (Sinclair) CASPER WY 306009 ME-1155 ME-1155 ME-1155 0.705 0.803 0.803

NEI40039ref1033 Ventura Refining & Transmission, LLC Thomas OK 30600904 All Units F-1 F-1 0.092 0.092

NEI40039ref1033 Ventura Refining & Transmission, LLC Thomas OK 30600999 L-1 F-2 F-2 0.013 0.013

NEI40371 Tesoro - Mandan MANDAN ND 306009 Alky EUI 2B EUI 2B 2.549 2.549

NEI40371 Tesoro - Mandan MANDAN ND 306009 Combo EUI 1C EUI 1C 2.086 1.961

NEI40371 Tesoro - Mandan MANDAN ND 306009 GHT EUI 3B EUI 3B 1.989 1.960

NEI40371 Tesoro - Mandan MANDAN ND 306009 SRU EUI 6B EUI 6B 2.574 2.549

NEI404 WYOMING REFINING COMPANY NEWCASTLE WY 30600904 Flare Flare Flare 1.700
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI40531 WYNNEWOOD REFINING CO WYNNEWOOD OK 30600903 FLR SYS FS1401 FS1401 0.003

NEI40531 WYNNEWOOD REFINING CO WYNNEWOOD OK 30600903 FLR SYS FS1402 FS1402 0.003

NEI40531 WYNNEWOOD REFINING CO WYNNEWOOD OK 30600903 FLR SYS FS1451 FS1451 0.003

NEI40531 WYNNEWOOD REFINING CO WYNNEWOOD OK 30600903 FLR SYS FS1503 FS1503 0.003

NEI40723 SUNOCO GIRARD POINT REFINERY PHILADELPHIA PA 30600904 GP 1231 Flare GP 1231 Flare GP 1231 Flare 24.936 10.347 10.347

NEI40723 SUNOCO GIRARD POINT REFINERY PHILADELPHIA PA 30600904 GP 433 Flare GP 433 Flare GP 433 Flare 3.133 10.347 10.347

NEI40723 SUNOCO GIRARD POINT REFINERY PHILADELPHIA PA 30600904 PB 867 Acid Gas Flare PB 867 Acid Gas Flare PB 867 Acid Gas Flare 2.192 7.321 7.321

NEI40723 SUNOCO GIRARD POINT REFINERY PHILADELPHIA PA 30600904 PB 867 SWS Gas Flare PB 867 SWS Gas Flare PB 867 SWS Gas Flare 1.549 7.321 7.321

NEI40723 SUNOCO GIRARD POINT REFINERY PHILADELPHIA PA 30600904 PB North Yard LPG Fla PB North Yard LPG FlaPB North Yard LPG Flar 4.563 7.321 7.321

NEI40723 SUNOCO GIRARD POINT REFINERY PHILADELPHIA PA 30600904 PB South Yard North F PB South Yard North FPB South Yard North Fl 0.155 7.321 7.321

NEI41591 Valero Refining Co. (prev. Premcor Refinin Memphis TN 30600904 P029 P029 P029 1.611 4.000 4.001

NEI41591 Valero Refining Co. (prev. Premcor Refinin Memphis TN 30600904 P030 P030 P030 0.565 1.404 1.404

NEI41771 TOTAL PETROCHEMICALS USA INC. - PORT PORT ARTHUR TX 30600904 30CKRFLARE 30CKRFLARE 30CKRFLARE 0.650 2.950 0.010

NEI41771 TOTAL PETROCHEMICALS USA INC. - PORT PORT ARTHUR TX 30600904 41NORTHFLR 41NORTHFLR 41NORTHFLR 13.190 28.430 0.060

NEI41771 TOTAL PETROCHEMICALS USA INC. - PORT PORT ARTHUR TX 30600904 53SOUTHFLR 53SOUTHFLR 53SOUTHFLR 0.760 2.610

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 306009 180 EP-FLARE1 EP-FLARE1 36.381 1.489 1.489

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 306009 180 HCU-FL1 HCU-FL1 0.042 0.012 0.012

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 306009 180 REF2-FL1 REF2-FL1 10.592 0.124 0.124

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 306009 180 WP-FLARE1 WP-FLARE1 0.859 7.222 7.222

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 306009 SRU1-FLARE SRU1-FLARE SRU1-FLARE 0.215 0.806 0.806

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 306009 SRU2-FLARE SRU2-FLARE SRU2-FLARE 0.019 0.173 0.173

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 306009 SWS-FLARE SWS-FLARE SWS-FLARE 0.019 0.173 0.173

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 30600999 176 TO-3 TO-3 0.017 0.003 0.003

NEI41863 VALERO REFINING TEXAS LP CORPUS CHR CORPUS CHRISTI TX 30600999 179 TO-2 TO-2 0.032 0.017 0.017

NEI41864 FLINT HILLS RESOURCES LP - WEST PLANT CORPUS CHRISTI TX 30600903 10BD1001 V-5, Pilot Gas Combus V-5, Pilot Gas Combust 0.033 0.033 0.012

NEI41864 FLINT HILLS RESOURCES LP - WEST PLANT CORPUS CHRISTI TX 30600903 45BD1 V-6, Pilot Gas Combus V-6, Pilot Gas Combust 0.030 0.030 0.010

NEI41864 FLINT HILLS RESOURCES LP - WEST PLANT CORPUS CHRISTI TX 30600903 45BD2 V-7, Pilot Gas Combus V-7, Pilot Gas Combust 0.183 0.188 0.065

NEI41864 FLINT HILLS RESOURCES LP - WEST PLANT CORPUS CHRISTI TX 30600903 Monroe Separator V-8 V-8 3.476 0.298

NEI41864 FLINT HILLS RESOURCES LP - WEST PLANT CORPUS CHRISTI TX 30600903 Monroe Separator V-8, Pilot Gas Combus V-8, Pilot Gas Combust 0.001 0.001 0.000

NEI41865 TRIGEANT LTD CORPUS CHRISTI TX 30600999 FLAREPILOT FLAREPILOT FLAREPILOT 12.410

NEI42016 Big West Oil Co. (Flying J) NORTH SALT LAKE UT 30600904 Plant (North) Flare 2 Plant (North) Flare 2 Plant (North) Flare 2 1.760 0.260 0.260

NEI42016 Big West Oil Co. (Flying J) NORTH SALT LAKE UT 30600904 Plant (South) Flare 1 Plant (South) Flare 1 Plant (South) Flare 1 1.760 0.260 0.260

NEI42020 HOLLY REFINING & MARKETING, FKA PHIL WoodsCross UT 30600904 62 62-1 62-1 1.884 0.271 0.271

NEI42025 Silver Eagle Refining WOODS CROSS UT 306009 Utilities North Flare North Flare 0.811 0.332 0.332

NEI42025 Silver Eagle Refining WOODS CROSS UT 306009 Utilities South Flare South Flare 0.270 0.111 0.111

NEI42040 Tesoro - Salt Lake City SALT LAKE CITY UT 30600903 North Flare Pilot North Flare Pilot North Flare Pilot 0.141 0.216 0.051

NEI42040 Tesoro - Salt Lake City SALT LAKE CITY UT 30600903 South Flare Pilot South Flare Pilot South Flare Pilot 0.141 0.216 0.051

NEI42040 Tesoro - Salt Lake City SALT LAKE CITY UT 30600903 SRU Flare Pilot SRU Flare Pilot SRU Flare Pilot 0.141 0.216 0.051

NEI42040 Tesoro - Salt Lake City SALT LAKE CITY UT 30600904 North Flare North Flare North Flare 6.452 0.037 0.038

NEI42040 Tesoro - Salt Lake City SALT LAKE CITY UT 30600904 South Flare South Flare South Flare 11.179 0.154 0.155

NEI42081 CHEVRON USA PRODUCTS COMPANY SALT LAKE CITY UT 30600904 Multiple Flare #1 Flare #1 3.601 0.592 0.592

NEI42081 CHEVRON USA PRODUCTS COMPANY SALT LAKE CITY UT 30600904 Multiple Flare #2 Flare #2 0.645 0.592 0.592

NEI42081 CHEVRON USA PRODUCTS COMPANY SALT LAKE CITY UT 30600904 Multiple Flare #3 Flare #3 31.421 0.592 0.592

NEI42309 GIANT YORKTOWN REFINERY GRAFTON VA 30600904 ALL UNITS S-010 S-010 38.180 6.483

NEI42309 GIANT YORKTOWN REFINERY GRAFTON VA 30600904 ALL UNITS S-011 S-011 0.161 0.027

NEI42370 U.S. OIL & REFINING CO. TACOMA WA 306009 F-2 F-2 F-2 2.662 1.270 1.270

NEI42370 U.S. OIL & REFINING CO. TACOMA WA 30600904 F-1 F-1 F-1 1.388 1.264 1.264
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI42381 ANACORTES REFINERY TESORO NORTHW ANACORTES WA 306009 Flares X-813 X-813 10.600 0.528 0.528

NEI42381 ANACORTES REFINERY TESORO NORTHW ANACORTES WA 306009 Flares X-814 X-814 10.800 0.528 0.528

NEI42381 ANACORTES REFINERY TESORO NORTHW ANACORTES WA 306009 Flares X-819 X-819 18.500 0.528 0.528

NEI42382 SHELL OIL ANACORTES REFINERY ANACORTES WA 30600904 Flare East Flare East Flare 21.683 0.026 0.026

NEI42382 SHELL OIL ANACORTES REFINERY ANACORTES WA 30600904 Flare North Flare North Flare 0.026 0.000031 0.000031

NEI42382 SHELL OIL ANACORTES REFINERY ANACORTES WA 30600904 Flare South Flare South Flare 0.791 0.001 0.001

NEI42382 SHELL OIL ANACORTES REFINERY ANACORTES WA 30600904 SRU3 SRU3 Incinerator SRU3 Incinerator 0.261 0.009 0.009

NEI42382 SHELL OIL ANACORTES REFINERY ANACORTES WA 30600904 SRU4 SRU4 Incinerator SRU4 Incinerator 0.049 0.0016 0.0016

NEI42413 BP West Coast Products - Cherry Point BLAINE WA 30600904 29 110 110 12.800 1.112 0.040

NEI42413 BP West Coast Products - Cherry Point BLAINE WA 30600904 29 111 111 3.000 0.261 0.009

NEI42583 MURPHY OIL USA, INC., SUPERIOR REFINESUPERIOR WI 30600903 Main Flare Main Flare Main Flare 1.717

NEI43243 SINCLAIR OIL CORPORATION SINCLAIR WY 306009 Flare 37 37 15.702 3.417 3.417

NEI43243 SINCLAIR OIL CORPORATION SINCLAIR WY 306009 Flare 73 73 2.759 3.417 3.417

NEI46556 HOVENSA LLC CHRISTIANSTED VI 30600904 Refinery Flare System #2 Flare (H-1105) #2 Flare (H-1105) 0.504 0.009 0.009

NEI46556 HOVENSA LLC CHRISTIANSTED VI 30600904 Refinery Flare System #3 Flare (H-1104) #3 Flare (H-1104) 0.559 0.0096 0.0096

NEI46556 HOVENSA LLC CHRISTIANSTED VI 30600904 Refinery Flare System #5 Flare (H-3351) #5 Flare (H-3351) 0.510 0.0087 0.0087

NEI46556 HOVENSA LLC CHRISTIANSTED VI 30600904 Refinery Flare System #6 Flare (H-3352) #6 Flare (H-3352) 0.455 0.0078 0.0078

NEI46556 HOVENSA LLC CHRISTIANSTED VI 30600904 Refinery Flare System #7 Flare (H-3301) #7 Flare (H-3301) 1.657 0.028 0.028

NEI46556 HOVENSA LLC CHRISTIANSTED VI 30600904 Refinery Flare System FCC Flare (L.P. Flare - FCC Flare (L.P. Flare - ST 2.581 0.044 0.044

NEI46556 HOVENSA LLC CHRISTIANSTED VI 30600904 Refinery Flare System Ground Flare (H.P. Fla Ground Flare (H.P. Flare 0.957 0.016 0.016

NEI46556 HOVENSA LLC CHRISTIANSTED VI 30600905 Refinery Flare System LPG Flare (STK 7921) LPG Flare (STK 7921) 0.011 0.0002 0.0002

NEI46752 ERGON - WEST VIRGINIA, INC. NEWELL WV 306009 Main Flare Main Flare Main Flare 1.350

NEI46764 AMERICAN REFINING GROUP INC BRADFORD PA 30600904 Foster Brook-Flare Foster Brook-Flare Foster Brook-Flare 0.179 0.179

NEI46764 AMERICAN REFINING GROUP INC BRADFORD PA 30600904 Platformer Unit-Flare Platformer Unit-Flare Platformer Unit-Flare 0.228 0.228

NEI49781 MARATHON PETROLEUM CO LLC ROBINSON IL 306009 Multiple Flare #1 Flare #1 0.070 0.107 0.025

NEI49781 MARATHON PETROLEUM CO LLC ROBINSON IL 306009 Multiple Flare #2 Flare #2 0.055 0.085 0.020

NEI49781 MARATHON PETROLEUM CO LLC ROBINSON IL 306009 Multiple Flare #3 Flare #3 0.083 0.127 0.030

NEI49781 MARATHON PETROLEUM CO LLC ROBINSON IL 306009 Multiple Flare #4 Flare #4 0.081 0.124 0.029

NEI49781 MARATHON PETROLEUM CO LLC ROBINSON IL 306009 Multiple Flare #5 Flare #5 0.076 0.117 0.028

NEI49781 MARATHON PETROLEUM CO LLC ROBINSON IL 306009 Multiple Flare #6 Flare #6 0.065 0.100 0.023

NEI49781 MARATHON PETROLEUM CO LLC ROBINSON IL 306009 Multiple Flare #7 Flare #7 0.042 0.064 0.015

NEI53702 CITGO Petroleum Corp LEMONT IL 30600904 120 844C-5 844C-5 2.936

NEI55835 CONOCOPHILLIPS CO WOOD RIVER REFINROXANA IL 306009 Alkylation Flare Alkylation Flare Alkylation Flare 2.290 1.204 1.204

NEI55835 CONOCOPHILLIPS CO WOOD RIVER REFINROXANA IL 306009 Aromatics North Flare Aromatics North FlareAromatics North Flare 4.930 1.724 1.724

NEI55835 CONOCOPHILLIPS CO WOOD RIVER REFINROXANA IL 306009 Aromatics South Flare Aromatics South FlareAromatics South Flare 0.713 0.243 0.243

NEI55835 CONOCOPHILLIPS CO WOOD RIVER REFINROXANA IL 306009 Distilling Flare Distilling Flare Distilling Flare 0.365 1.069 1.069

NEI55835 CONOCOPHILLIPS CO WOOD RIVER REFINROXANA IL 306009 Distilling West Flare (c Distilling West Flare (cDistilling West Flare (co 13.200 3.797 3.797

NEI55835 CONOCOPHILLIPS CO WOOD RIVER REFINROXANA IL 306009 Hydrogen Plant 1 FlareHydrogen Plant 1 Flar Hydrogen Plant 1 Flare 4.010 1.529 1.529

NEI55835 CONOCOPHILLIPS CO WOOD RIVER REFINROXANA IL 306009 Lube Flare (LSG) Lube Flare (LSG) Lube Flare (LSG) 0.056 0.372 0.372

NEI55835 CONOCOPHILLIPS CO WOOD RIVER REFINROXANA IL 306009 North Property Flare North Property Flare North Property Flare 5.810 1.332 1.332

NEI56009ref1502 Garco Energy Douglas Refinery Douglas WY 306009 Sunn Flare-Sunn Flare-Sunn

NEI56009ref1502 Garco Energy Douglas Refinery Douglas WY 30600999 TCI Flare-TCI Flare-TCI

NEI6022 TETRA PROCESS SERVICES LC EXXON REF BATON ROUGE LA 30600999 BRCP FLARE 7 FLARE 7 0.698

NEI6022 TETRA PROCESS SERVICES LC EXXON REF BATON ROUGE LA 30600999 Docks DOCKS/MVR LOAD DOCKS/MVR LOAD 46.506 17.172 15.733

NEI6062 CONOCOPHILLIPS CO - LAKE CHARLES REFWESTLAKE LA 306009 FLARE-NORTH FLARE-NORTH FLARE-NORTH 16.323 9.702 9.702

NEI6062 CONOCOPHILLIPS CO - LAKE CHARLES REFWESTLAKE LA 30600903 EP-31 EP-31 EP-31 21.725 7.981 3.204

NEI6062 CONOCOPHILLIPS CO - LAKE CHARLES REFWESTLAKE LA 30600999 FL-76002 FL-76002 FL-76002 0.982 0.361 0.283
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI6062 CONOCOPHILLIPS CO - LAKE CHARLES REFWESTLAKE LA 30600999 MVRU2-FL MVRU2-FL MVRU2-FL 20.448 38.243 10.225

NEI6062 CONOCOPHILLIPS CO - LAKE CHARLES REFWESTLAKE LA 30600999 NFL-1 NFL-1 NFL-1 2.129 2.400 2.427

NEI6062 CONOCOPHILLIPS CO - LAKE CHARLES REFWESTLAKE LA 30600999 T-38FL T-38FL T-38FL 42.048 12.572 7.996

NEI6062 CONOCOPHILLIPS CO - LAKE CHARLES REFWESTLAKE LA 30600999 T-8001FL T-8001FL T-8001FL 4.424 3.655 3.666

NEI6084 MOTIVA ENTERPRISES LLC/CONVENT REF CONVENT LA 30600903 19 19G305 19G305 8.170

NEI6084 MOTIVA ENTERPRISES LLC/CONVENT REF CONVENT LA 30600903 85 85D105 85D105 0.787

NEI6087 MARATHON ASHLAND PETROLEUM LLC GARYVILLE LA 30600904 20 20A-08 20A-08 59.629 5.790 0.887

NEI6087 MARATHON ASHLAND PETROLEUM LLC GARYVILLE LA 30600904 20 20B-08 20B-08 13.586 3.079 0.256

NEI6087 MARATHON ASHLAND PETROLEUM LLC GARYVILLE LA 30600904 50 107-90 107-90 16.261 1.018 0.947

NEI6087 MARATHON ASHLAND PETROLEUM LLC GARYVILLE LA 30600904 59 69-74 69-74 26.240 0.949 1.257

NEI6087 MARATHON ASHLAND PETROLEUM LLC GARYVILLE LA 30600904 59 83-74 83-74 14.332 1.479 0.353

NEI6087 MARATHON ASHLAND PETROLEUM LLC GARYVILLE LA 30600904 66 3-88 3-88 0.010 17.689 4.121

NEI6087 MARATHON ASHLAND PETROLEUM LLC GARYVILLE LA 30600904 69 69-74V 69-74V 4.720

NEI6095 VALERO SAINT CHARLES REFINERY NORCO LA 30600904 EQT 0007 RE0007 RE0007 17.942 0.102 0.104

NEI6095 VALERO SAINT CHARLES REFINERY NORCO LA 30600904 EQT 0013 RE0013 RE0013 13.499 0.082 0.083

NEI6095 VALERO SAINT CHARLES REFINERY NORCO LA 30600904 EQT 0034 RE0034 RE0034 0.807 0.005 0.005

NEI6095 VALERO SAINT CHARLES REFINERY NORCO LA 30600904 EQT 0360 RE0360 RE0360 1.067 0.006 0.006

NEI6116 BP OIL COMPANY ALLIANCE REFINERY BELLE CHASSE LA 30600999 308F 308FD1 308FD1 52.670 13.094 11.542

NEI6116 BP OIL COMPANY ALLIANCE REFINERY BELLE CHASSE LA 30600999 308F 308FD2 308FD2 28.980 9.682 8.330

NEI6116 BP OIL COMPANY ALLIANCE REFINERY BELLE CHASSE LA 30600999 406 MVR MVR 14.700 8.341 7.068

NEI6123 EXXONMOBIL REFINERY COMPLEX CHALMETTE LA 306009 MVR MVR MVR 0.902 0.485 0.291

NEI6123 EXXONMOBIL REFINERY COMPLEX CHALMETTE LA 306009 Refinery EQT269 EQT269 0.150 0.002 0.002

NEI6123 EXXONMOBIL REFINERY COMPLEX CHALMETTE LA 306009 Refinery EQT270 EQT270 0.770 0.042 0.044

NEI6123 EXXONMOBIL REFINERY COMPLEX CHALMETTE LA 306009 Refinery Flare 1 Flare 1 0.060

NEI6123 EXXONMOBIL REFINERY COMPLEX CHALMETTE LA 306009 Refinery Flare 2 Flare 2 30.760 1.680 1.764

NEI6127 MURPHY OIL USA INC MERAUX TERMINA MERAUX LA 30600903 0018 EQT 0018 EQT 0018 13.900 1.668 1.652

NEI6127 MURPHY OIL USA INC MERAUX TERMINA MERAUX LA 30600903 0020 EQT 0020 EQT 0020 0.810 4.182 4.182

NEI6127 MURPHY OIL USA INC MERAUX TERMINA MERAUX LA 30600903 0035 EQT 0035 EQT 0035 18.070 1.668 1.652

NEI6127 MURPHY OIL USA INC MERAUX TERMINA MERAUX LA 30600903 0049 EQT 0049 EQT 0049 12.318 1.668 1.652

NEI6127 MURPHY OIL USA INC MERAUX TERMINA MERAUX LA 30600903 MT007 MT007 MT007 22.307 5.493 5.493

NEI6130 PLACID REFINING CO LLC/PORT ALLEN RE PORT ALLEN LA 30600903 FLARE 18-74 18-74 0.147 2.372 2.372

NEI6136 VALERO REFINING CO/KROTZ SPRINGS REKROTZ SPRINGS LA 30600904 5-85 5-85 5-85 97.630 0.682 0.682

NEI6136 VALERO REFINING CO/KROTZ SPRINGS REKROTZ SPRINGS LA 30600904 8-78 8-78 8-78 12.500 1.720 1.720

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 315 315B9 315B9 18.862 0.327 0.327

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 319 319B8 319B8 20.867

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 320 320B12 320B12 7.270

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 327 327B11 327B11 64.084 0.408 0.408

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 328 328B1 328B1 36.000 3.402 3.402

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 330 330B4 330B4 37.242

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 343 343B5 343B5 31.596 0.579 0.579

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 343 343B6 343B6 38.996 1.873 1.873

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 343 343B7 343B7 21.186 0.262 0.262

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 360 360CB11 360CB11 3.021

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 399 399B16 399B16 3.116 0.017 0.017

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 484 484B104 484B104 5.293 0.029 0.029

NEI6166 CITGO PETROLEUM CORPORATION LAKE CHARLES LA 30600904 PG PG-FLR PG-FLR 0.051

NEI6375 BAYWAY CHEMICAL PLANT OF INFINEUM LINDEN NJ 30600904 OS1 E275 ABW Flare ABW Flare 0.353 0.079 0.015
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI6375 BAYWAY CHEMICAL PLANT OF INFINEUM LINDEN NJ 30600904 OS3 E276 CLEU Flare CLEU Flare 0.027 0.079 0.015

NEI6375 BAYWAY CHEMICAL PLANT OF INFINEUM LINDEN NJ 30600904 OS5 E277 Eastside Flare Eastside Flare 0.271 0.061 0.011

NEI6375 BAYWAY CHEMICAL PLANT OF INFINEUM LINDEN NJ 30600904 OS9 E279 Poly Flare Poly Flare 0.017 0.004 0.001

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 AU2 AU2 AU2 0.147 12.962 12.929

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 CFHU CFHU CFHU 0.857 13.436 12.983

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 DDU DDU DDU 1.541 14.155 13.997

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 Power 2 SW SW 12.920 12.920

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 Power 2 Torch 1 Torch 1 0.006 17.209 17.195

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 Power 2 Torch 2 Torch 2 1.000 15.530 15.530

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 Power 2 Torch 3 Torch 3 2.314 14.262 13.598

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 Power 2 Torch 4 Torch 4 0.062 13.003 13.003

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 Power 2 Torch 6 Torch 6 0.123 17.318 17.195

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 Power 2 Torch 8 Torch 8 0.103 12.999 12.934

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 SRU SRU C-D SRU C-D 12.920 12.920

NEI6436 BP TEXAS CITY REFINERY TEXAS CITY TX 306009 ULC ULC ULC 3.141 24.236 23.095

NEI6446 FINA OIL & CHEMICAL BIG SPRING TX 30600904 02 02CRUDEFLR 02CRUDEFLR 0.206

NEI6446 FINA OIL & CHEMICAL BIG SPRING TX 30600904 05 05REFMRFLR 05REFMRFLR 0.295

NEI6446 FINA OIL & CHEMICAL BIG SPRING TX 30600904 14 14NEASTFLR 14NEASTFLR 0.506

NEI6446 FINA OIL & CHEMICAL BIG SPRING TX 30600904 16 16SOUTHFLR 16SOUTHFLR 0.466

NEI6446 FINA OIL & CHEMICAL BIG SPRING TX 30600904 37 37SLTWLFLR 37SLTWLFLR 0.016

NEI6446 FINA OIL & CHEMICAL BIG SPRING TX 30600905 37 37BAYRKFLR 37BAYRKFLR 5.120 0.122 0.122

NEI6475 DELEK TYLER REFINERY TYLER TX 30600904 FLARES FLRFN0001 FLRFN0001 3.674 1.528

NEI6475 DELEK TYLER REFINERY TYLER TX 30600904 FLARES FLRFN0002 FLRFN0002 12.517 5.817

NEI6475 DELEK TYLER REFINERY TYLER TX 30600904 FLARES FLRFN0003 FLRFN0003 2.900 1.192

NEI6475 DELEK TYLER REFINERY TYLER TX 30600904 FLARES FLRFN0004 FLRFN0004 20.838

NEI6475 DELEK TYLER REFINERY TYLER TX 30600904 FLARES FLRNF0005 FLRNF0005 5.150 2.117

NEI6475 DELEK TYLER REFINERY TYLER TX 30600904 WWT WWSFLWFLR WWSFLWFLR 0.259

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 28.1 28.1-61-10 28.1-61-10 0.253 0.039

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 28.1 28.1-61-9 28.1-61-9 0.279

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 29-61-1 29-61-1 29-61-1 0.135 0.669 0.0015

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 30 56-61-23 56-61-23 4.380

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 56-61-1 56-61-1 56-61-1 0.619 0.618 0.236

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 56-61-11 56-61-11 56-61-11 0.053 0.019

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 56-61-16 56-61-16 56-61-16 0.081 0.172

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 56-61-17 56-61-17 56-61-17 0.002 0.007

NEI6519 PHILLIPS 66 COMPANY SWEENY COMPLEXBRAZORIA TX 30600903 56-61-19 56-61-19 56-61-19 0.280 0.156 0.00026

NEI6617 CITGO REFINING & CHEMICALS CO LP CORPUS CHRISTI TX 30600903 552-U552 552-U552 552-S10 552-U552 552-S10 

NEI6617 CITGO REFINING & CHEMICALS CO LP CORPUS CHRISTI TX 30600903 555-U555 555-S9P 555-S9 555-S9P 555-S9 

NEI6617 CITGO REFINING & CHEMICALS CO LP CORPUS CHRISTI TX 30600904 573-ME1 573-ME1 573-ME1 573-ME1 573-ME1 

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL1 66FL1 0.765 0.234 0.235

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL10 66FL10 0.025 0.025

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL11 66FL11 1.236 0.757

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL12 66FL12 0.087 0.0042 0.0042

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL13 66FL13 36.570

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL2 66FL2 50.115 1.150 1.150

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL3 66FL3 9.100 0.234 0.234

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL4 66FL4 24.861 9.198 9.198
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL6 66FL6 0.102 0.047 0.047

NEI6963 ConocoPhillips Co. - Borger (prev. Phillips BORGER TX 306009 Other 66FL8 66FL8 0.175 0.113

NEI7130 AGE Refining & Manufacturing SAN ANTONIO TX 306009 ALL UNITS FL-2 FL-2 1.290

NEI7130 AGE Refining & Manufacturing SAN ANTONIO TX 306009 L-2 FL-1 FL-1 2.823 0.003 0.003

NEI7134 KOCH REFINING COMPANY CORPUS CHRISTI TX 30600903 E01Fl100 FL-97, Pilot Gas Comb FL-97, Pilot Gas Combu 0.0048 0.0050 0.0017

NEI7134 KOCH REFINING COMPANY CORPUS CHRISTI TX 30600903 E01FL101 FL-28 FL-28 11.383 9.983 3.263

NEI7134 KOCH REFINING COMPANY CORPUS CHRISTI TX 30600903 E01Fl101 FL-28, Pilot Gas Comb FL-28, Pilot Gas Combu 0.0036 0.0037 0.0013

NEI7233 EXXONMOBIL OIL BEAUMONT REFINERY BEAUMONT TX 30600904 Flare System 60FLR_001 60FLR_001 10.000 4.784 0.040

NEI7233 EXXONMOBIL OIL BEAUMONT REFINERY BEAUMONT TX 30600904 Flare System 60FLR_002 60FLR_002 0.590 0.0084 0.0003

NEI7233 EXXONMOBIL OIL BEAUMONT REFINERY BEAUMONT TX 30600904 Flare System 60FLR_003 60FLR_003 100.000 68.102 0.997

NEI7233 EXXONMOBIL OIL BEAUMONT REFINERY BEAUMONT TX 30600904 Flare System 60FLR_004 60FLR_004 5.600 7.806 0.011

NEI7233 EXXONMOBIL OIL BEAUMONT REFINERY BEAUMONT TX 30600904 Flare System 60FLR_005 60FLR_005 120.000 81.928 0.823

NEI7233 EXXONMOBIL OIL BEAUMONT REFINERY BEAUMONT TX 30600904 Flare System 60FLR_006 60FLR_006 6.700 4.377 0.052

NEI7233 EXXONMOBIL OIL BEAUMONT REFINERY BEAUMONT TX 30600904 Flare System 60FLR_008 60FLR_008 45.000 28.729 0.386

NEI7233 EXXONMOBIL OIL BEAUMONT REFINERY BEAUMONT TX 30600904 Flare System 60FLR_010 60FLR_010 140.000 109.879 0.433

NEI7441 PORT ARTHUR REFINERY PORT ARTHUR TX 306009 ECRU4 ECRU4 ECRU4 0.0037 0.0057 0.0013

NEI7441 PORT ARTHUR REFINERY PORT ARTHUR TX 306009 EDCU1 EDCU-1 EDCU-1 0.0034 0.0051 0.0012

NEI7441 PORT ARTHUR REFINERY PORT ARTHUR TX 306009 EFCCU1&2 EFCCU1&2 EFCCU1&2 0.0037 0.0057 0.0013

NEI7441 PORT ARTHUR REFINERY PORT ARTHUR TX 306009 EFCCU3 EFCCU3 EFCCU3 0.0037 0.0057 0.0013

NEI7441 PORT ARTHUR REFINERY PORT ARTHUR TX 306009 EHCU EHCU EHCU 0.0050 0.0076 0.0018

NEI7441 PORT ARTHUR REFINERY PORT ARTHUR TX 306009 EHTU EHTU EHTU 0.0034 0.0051 0.0012

NEI7441 PORT ARTHUR REFINERY PORT ARTHUR TX 306009 EVPS4 EVPS4 EVPS4 0.0037 0.0057 0.0013

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600903 -88 FL29 FL29 0.680 0.416

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FL19 FL19 0.120 0.121

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FL20 FL20 31.270 31.268 4.430

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FL21 FL21 15.140 15.138 2.150

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FL22 FL22 0.061 0.061

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FL27 FL27 5.980 2.009

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FL3 FL3 8.820 3.090

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FL5 FL5 0.003 0.003

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FL6 FL6 0.180 0.162

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FLARE11 FLARE11 14.170 4.150 0.00009

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FLARE14 FLARE14 54.510 9.051 0.00018

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FLARE15 FLARE15 8.950 8.954 2.098

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FLARE16 FLARE16 11.210 11.208 2.625

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FLARE17 FLARE17 14.170 14.170 2.008

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 -88 FLARE18 FLARE18 7.670 7.674 1.089

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 FXK FL25 FL25 0.220 0.224 0.005

NEI7781 EXXONMOBIL REF & SUPPLY BAYTOWN TX 30600904 FXK FL26 FL26

NEI7988 CITGO EAST PLANT REFINERY CORPUS CHRISTI TX 30600999 85-U85 82-FLARE F454 82-FLARE F454 

NEI8139 Valero Energy Corp. - McKee (prev. Diamo SUNRAY TX 306009 0360 V-18 V-18 2.330 0.105 0.105

NEI8139 Valero Energy Corp. - McKee (prev. Diamo SUNRAY TX 306009 1220 FL-7 FL-7 0.037

NEI8139 Valero Energy Corp. - McKee (prev. Diamo SUNRAY TX 306009 1240 FL-9 FL-9 1.006 0.0004 0.0004

NEI8139 Valero Energy Corp. - McKee (prev. Diamo SUNRAY TX 306009 400 FL-3 FL-3 18.297 0.007 0.007

NEI8139 Valero Energy Corp. - McKee (prev. Diamo SUNRAY TX 306009 430 FL-4 FL-4 25.524 0.009 0.009

NEI8139 Valero Energy Corp. - McKee (prev. Diamo SUNRAY TX 306009 920 FL-6 FL-6 0.088

NEI8139 Valero Energy Corp. - McKee (prev. Diamo SUNRAY TX 306009 All Units FL-1 FL-1 32.278 0.012 0.012
NEI SITE ID FACILITY NAME CITY STATE SCC EMISSION UNIT ID PROCESS ID

EMISSION RELEASE 

POINT ID

Directly Reported 

"VOC" Emissions 

(tpy)

Speciated VOC 

Emissions (tpy)

Organic HAP 

Emissions (tpy)

NEI876 LION OIL COMPANY EL DORADO AR 30600999 HP Flare SN-823 SN-823 1.250 8.007 2.490

NEI876 LION OIL COMPANY EL DORADO AR 30600999 LP Flare SN-822 SN-822 0.285 5.345 1.740

NEI889 SUNCOR DENVER REFINERY COMMERCE CITY CO 306009 P2Truck (410) P2Truck (410) P2Truck (410) 0.010 0.315 0.321

NEI889 SUNCOR DENVER REFINERY COMMERCE CITY CO 30600904 AU (19) F3 (39) F3 (39) 1.095 0.000 0.000

NEI889 SUNCOR DENVER REFINERY COMMERCE CITY CO 30600904 F1 (39) F1 (39) F1 (39) 10.000 2.076 2.076

NEI889 SUNCOR DENVER REFINERY COMMERCE CITY CO 30600904 F2 (57) F2 (57) F2 (57) 9.990 1.159 1.159

NEI889 SUNCOR DENVER REFINERY COMMERCE CITY CO 30600999 P1Rail (12) P1RailFlare P1RailFlare 2.545 0.151 0.151

NEI889 SUNCOR DENVER REFINERY COMMERCE CITY CO 30600999 P1Truck (12) P1TruckFlare P1TruckFlare 11.947 1.091 1.091

NEI889 SUNCOR DENVER REFINERY COMMERCE CITY CO 30600999 P2LPGRail (310) P2LPGFlare P2LPGFlare 0.455 0.087 0.087

NEICA0370363 UNION OIL CO LOS ANG REFINERY WILMINGTON CA 30600904 W-Utilities LPG Flare LPG Flare 0.0057 0.058 0.0033

NEICA0370363 UNION OIL CO LOS ANG REFINERY WILMINGTON CA 30600904 W-Utilities North Flare North Flare 0.015 0.009 0.005

NEICA0370363 UNION OIL CO LOS ANG REFINERY WILMINGTON CA 30600904 W-Utilities South Flare South Flare 0.017 0.060 0.039

NEICA0370363 UNION OIL CO LOS ANG REFINERY WILMINGTON CA 30600904 W-Utilities UK Flare UK Flare 0.015 0.019 0.006

NEICA0379991 CONOCOPHILLIPS CARSON PLANT CARSON CA 30600904 C-Utilities East Flare East Flare 0.169 0.089 0.077

NEICA0379991 CONOCOPHILLIPS CARSON PLANT CARSON CA 30600904 C-Utilities West Flare West Flare 0.028 0.013 0.010

NEICA1910268 Shell Oil Products US - Wilmington WILMINGTON CA 30600904 Flare 1, Flare 2 LAR Flares LAR Flares 6.319 0.795 0.415

NEICA1910268 Shell Oil Products US - Wilmington WILMINGTON CA 30600904 SRP Flare SRP Flare SRP Flare 0.079 0.424 0.411

NEINJT$891 VALERO REFINING CO PAULSBORO NJ 30600904 New South Flare N. South Flare N. South Flare 0.060

NEINJT$891 VALERO REFINING CO PAULSBORO NJ 30600904 North Flare North Flare North Flare 0.103

NEINJT$891 VALERO REFINING CO PAULSBORO NJ 30600904 Old South Flare Old South Flare Old South Flare 0.167

NEINMT$12478 Navajo Refining Co. - Lovington LOVINGTON NM 30600904 FL-1001 FL-1001 FL-1001 0.033

NEIOKT$11009 VALERO RFNRY CO/ARDMORE RFNRY ARDMORE OK 30600904 810 HI-81001 HI-81001 18.000 20.165 3.320

NEIWYT$12156 SILVER EAGLE REFINING-EVANSTON EVANSTON WY 306009 Crude Unit T-103 T-103 0.000011 0.000016 0.000004

NEIWYT$12156 SILVER EAGLE REFINING-EVANSTON EVANSTON WY 306009 Flare Flare Flare 7.240 0.130 0.130

NEIWYT$12156 SILVER EAGLE REFINING-EVANSTON EVANSTON WY 306009 LR-Flare LR-Flare LR-Flare 0.718 0.000 0.000

NEIWYT$12156 SILVER EAGLE REFINING-EVANSTON EVANSTON WY 306009 Utilities - Hot Oil H-791 H-791 0.626 0.868 0.204

**Shaded rows indicates flares at an area source (synthetic minor) petroleum refinery
Attachment 2

API/NPRA/ACC Flare Dataset
F I N A L

API/NPRA/ACC Steam-Assisted Flare 

Operations and Control Survey

December 7, 2011
FINAL

December 7, 2011

Page 1

Conclusions and Recommendations

• Flares that sometimes operate with high steam assist ratios do not 

necessarily have high VOC emissions

• Several variables influence the potential benefit from monitoring 

and controlling steam-assist ratio or CZNHV

o The VOC content of the flare gas

o The annual VOC load 

o The VOC load during periods of high steam-to-flare gas ratio

o The duration of high steam-to-flare gas periods

o The combustion efficiency achieved through current operating 

practices

• The cost-effectiveness for adding extensive monitoring and control 

is very poor for flares with a low potential for significant VOC 

emissions reduction

• For some flares, opportunities exist to cost-effectively reduce VOC 

emissions. However, most studied flares have no cost effective 

potential for significant VOC emission reductions through additional 

monitoring and controls

• The degree to which VOC emissions might be reduced depends 

upon a flare’s specific design, service and operation

• Potential cost-effective VOC reductions are achieved primarily 

through control of steam 

• There is little opportunity to reduce VOC emissions from flares with 

no or minimal flow or VOC load during normal operations (i.e. flares 

that only handle startup, shutdown (equipment clearing), 

malfunction, flares with flare gas recovery, and flares that combust 

non-VOC gases)

• To assure cost-effective VOC emissions reductions, monitoring and 

control requirements should be based upon individual flare 

operations.
FINAL

December 7, 2011

Page 2

Introduction

An analysis of potential VOC1 emission reductions and cost-effectiveness 

(cost/ton VOC reduced) of possible steam-assisted flare monitoring and 

control requirements was performed. The analysis evaluated use of a 

Steam-to-Flare Gas Ratio (SFR) or a Combustion Zone Net Heating Value 

(CZ-NHV) as metrics for assuring high Combustion Efficiency (CE)2

Refining and chemical companies provided blinded operating data for steamassisted flares – both under “standby” and “upset” conditions.

.

3

Table 1

Generally, 

the operating scenario information was developed by gathering and 

averaging similar operating periods from hourly data. Seven companies 

provided detailed information on 38 steam-assisted flares, identifying a total

of 128 flare operating scenarios. One hundred and eight individual flare gas 

compositions were provided. The flare characterization information provided 

by the respondents is tabulated in .

Analyses Performed

Operating data gathered included flare gas rates, steam rates, gas 

composition4

Attachment 1

, and annual operating hours for each operating scenario. 

shows the individual flare and scenario information, except for 

the composition information. The compositions provided covered a broad 

range, summarized as follows:

VOC range: 0-97 vol.% - LHV range: 300-2470 BTU/scf

H2 range: 0-90 vol.% - CH4 range: 0-100 vol.%

Inerts range: 0-72 vol.% 

 1 VOCs included all non-methane, non-ethane hydrocarbon constituents reported in the flare gas. 2 For the purposes of this study, VOC destruction efficiency was assumed equal to the CE, though destruction 

efficiency may actually be somewhat higher than the CE.

3 Flare operation is highly dynamic, particularly during process upset conditions. Standby conditions are likely 

more representative of typical, normal operations and multiple scenarios were typically provided to illustrate upset 

situations.

4 Volume fraction – hydrogen, methane, ethane, propane, butanes, pentanes and pentenes, hexanes and hexenes, 

ethylene, propylene, butenes, carbon monoxide, carbon dioxide, and nitrogen
FINAL

December 7, 2011

Page 3

Using the submitted data, VOC emissions were estimated based upon two 

models: 

1) SFR model: 98% CE for SFR <4; 80% CE otherwise5

2) CZ-NHV model: 98% CE if CZ-NHV ≥ 300 Btu/scf;

.

90% CE if 300 Btu/scf > CZ-NHV ≥ 200 Btu/scf;

80% CE if 200 Btu/scf > CZ-NHV ≥ 100 Btu/scf; and

70% CE if CZ-NHV < 100 Btu/scf

To meet either the SFR or CZ-NHV target, steam assist first was reduced. 

Steam was reduced to as low as the reported minimum steam 

manufacturer’s recommendation.6

The VOC emission reduction potential for a particular flare operating scenario 

was then calculated as the difference between the VOC emissions before 

steam or natural gas rates were adjusted and the VOC emissions assuming a 

98% combustion efficiency.

Where further reductions in the SFR ratio 

or increases in the CZ-NHV were needed to meet the SFR or CZ-NHV target, 

natural gas was added until the target was achieved.

The analysis assumed an average capital cost of $1.0 million per flare for 

monitoring and controls for the SFR model and $2.3 million per flare for the 

CZ-NHV model.

7 Natural gas was valued at $0.10 per pound and steam at 

$1.00 per thousand pounds. Annual maintenance costs associated with the 

capital investments were taken as 2% of the steam and flare gas control

cost and 5% of the analyzer related investment.8

Attachment 2

A capital recovery factor 

(CRF) of 0.09439 was used (7% interest rate for 20 years) to annualize 

capital investments. provides additional detail on the cost 

effectiveness analysis procedure.

 5 This model matches the recommendations in EPA’s Emission Estimation Protocol for Petroleum Refineries, Version 

2 and was the basis for flare emission estimates in the recently submitted Refinery Information Collection Request 

(ICR).

6 Flare manufacturer recommendations for minimum steam are intended to protect the mechanical integrity of the 

flare tip. This may not be the practical minimum steam rate for a specific flare. For instance, flares operating in 

cold climates may require more steam to keep lines hot and to avoid condensation or freezing in the steam lines. 

If freezing were to occur, then no steam-assist would be available, leading to a smoky flare. 7 Capital investments: $1 million for instrumentation included flow meters and control valves required to monitor 

and control the steam assist for both models and an additional $1.3 million for other instrumentation, including a 

BTU or composition analyzer for real-time CZ-NHV monitoring for the CZ-NHV model. No specific investments for 

natural gas addition facilities were assumed 8 Analyzer maintenance is typically much more extensive that flow meter and control valve maintenance. 
FINAL

December 7, 2011

Page 4

Estimates of potential VOC reductions and the cost effectiveness of potential 

flare control requirements are quite sensitive to the assumptions made 

about combustion efficiency. As such, a sensitivity analysis of the key 

assumptions in each employed model was performed. The SFR model was 

augmented to consider the impact of varying the SFR ratio to 3 or 5 or 

reducing the CE assumption from 80% to 70% for SFR ratios above the goal. 

Similarly, the sensitivity of the CZ-NHV model was evaluated by considering

the impact of assuming a CZ-NHV value of 200 or400 BTU/scf to achieve 

98% CE and/or varying the CE assumptions for CZ-NHV values below the 

selected goal. The sensitivity scenarios evaluated are displayed in Table 2, 

along with a tabulation of the overall CE for all 38 flares in the context of the 

models before and after steam reductions.

Additionally, sensitivity analyses were performed regarding the investment 

costs and the price assumptions for natural gas and steam. Select cases 

were run at higher and lower investments and for higher and lower natural 

gas and steam values.9

Discussion of Results

 

Table 3 and Table 4 summarize the cost effectiveness calculated employing 

the SFR and CZ-NHV models, respectively, including sensitivity cases. For 

most flares, the SFR or CZ-NHV goal could be achieved through steam 

reductions before the minimum steam rate was reached.10

Table 5

Where further 

reductions in the SFR ratio or increases in the CZ-NHV were needed to meet 

the goal, natural gas was added. The results of the sensitivity analysis to 

the cost assumptions are presented in and Table 6 for the SFR and 

CZ-NHV models, respectively. 

In evaluating the analysis results, it is important to recall that the analyzer 

capital investment is applied for the CZ-NHV model, even if the goal is met 

through steam reductions alone, since the analyzer is needed to determine 

the CZ-NHV value.

 9 Steam values, in particular, are highly variable from site to site and steam can even have zero value if low 

pressure waste steam is being used as assist gas. 10 In practice, some flares may smoke before the manufacturer’s recommended minimum steam is reached and 

thus the calculated steam reductions may not be achievable and additional natural gas addition may be necessary.
FINAL

December 7, 2011

Page 5

Although costs are the same regardless of the assumed CE values (SFR or 

CZ-NHV model assumptions), the assumed CE values strongly influence the 

calculated potential VOC emission reductions and the cost effectiveness of 

monitoring and controls. However, the trends and relative cost effectiveness 

values are very informative, as discussed below, and are likely good 

indicators of the relative impact of the various alternative monitoring and 

control requirements. Clearly, and regardless of the model chosen for CE, it

is not cost effective to apply monitoring and controls to all flares. For all of 

the models evaluated, a significant proportion of the 38 flares already meet 

the SFR and CZ-NHV goals under all operating scenarios. The analyses 

herein indicate that 16% or 18% of the flares studied may benefit costeffectively from establishing SFR11 or CZ-NHV12 goals, respectively, requiring

the types of monitors and controls evaluated in this study.

13

 11 The sensitivity analysis suggests that the most conservative SFR model assumptions employed indicate up to 

24% of the flares could cost effectively benefit, requiring the types of monitors and controls evaluated in this 

study.

12 The sensitivity analysis suggests that the most conservative CZ-NHV model assumptions employed indicate up to 

32% of the flares could cost effectively benefit, requiring the types of monitors and controls evaluated in this 

study.

13 Graphical representations of cost-effectiveness conclusions and a summary of the study can be found in the 

accompanying presentation titled, “Steam-Assisted Flares: Cost-Effective Analysis of Potential Additional 

Monitoring and Controls.”
FINAL

December 7, 2011

Page 6

Table 1. Flare Information

Flare 

Number

Flare 

Description

Flare 

Diameter 

(in)

Flare 

Capacity

(lb/hr)

Min. Flare 

Steam 

Rate*

(lb/hr)

Comments

1 Refinery 36 601,000 0 Averages of 2010 hourly 

data. Includes purge gas. 

Operates with 0 steam 

when flare gas rate is very 

low.

2 Refinery 42 1,450,000 0 Averages of 2010 hourly 

data. Includes purge gas. 

Operates with 0 steam 

when flare gas rate is very 

low.

3 Refinery 24 427,000 1,144 Averages of 2010 hourly 

data. Includes purge gas

4 Refinery 30 417,000 0 Averages of 2010 hourly 

data. Includes purge gas. 

Operates with 0 steam 

when flare gas rate is very 

low.

5 Refinery 24 293,000 0 Averages of 2010 hourly 

data. Includes purge gas. 

Operates with 0 steam 

when flare gas rate is very 

low.

6 Refinery 48 1,684,000 1,200

7 Refinery 60 890,000 2,500 Steam rate less than 

minimum reported

8 Refinery 48 341,250 2,750

9 Chemical 21 59,865 1,205

10 Chemical 24 36,447 750 Flare is configured without 

capability for center steam. 

Minimum steam rate from 

manufacturer not available. 

Historical minimum 

provided.

11 Olefins 46.2 1,949,444 3,300

12 Olefins 46.2 1,949,444 3,300

13 Chemical 30 330,023 2,300 Flare capacity design data 

is not available. Value for 

Flare 14 used.

14 Chemical 30 330,023 2,120

15 Chemical 24 285,000 1,900

16 Refinery 30 350,000 1,200

17 Refinery 30 370,000 1,200 Purge gas flow only

18 Refinery 24 208,000 375 Based on hourly averages.
FINAL

December 7, 2011

Page 7

Flare 

Number

Flare 

Description

Flare 

Diameter 

(in)

Flare 

Capacity

(lb/hr)

Min. Flare 

Steam 

Rate*

(lb/hr)

Comments

19 Refinery 24 171,000 450 Emergency and SSM Flare, 

No flow during normal 

operations. Based on 

hourly averages.

20 Refinery 42 715,000 600 Based on hourly averages.

21 Refinery 30 634,500 300 Design min steam is for 

ring steam tip cooling. 

Steam rate is not 

measured; only steam 

valve position is monitored. 

Actual steam rate listed is 

from the 2008 stack test. 

22 Refinery 42 923,100 500 Design min steam is for 

ring steam tip cooling. 

Steam rate is not 

measured; only steam 

valve position is monitored. 

Actual steam rate listed is 

from the 2008 stack test.

23 Refinery 42 250,000 2,100

24 Refinery 42 250,000 2,100

25 Refinery 42 250,000 2,100

26 Refinery 36 750,000 2,000

27 Refinery 36 750,000 2,000

28 Refinery 36 505,000 1,500 Based on averages of 2010 

hourly data. Includes 

purge gas.

29 Refinery 36 561,000 1,880 Based on averages of 2010 

hourly data. Includes 

purge gas.

30 Refinery 24 400,000 1,810 Based on averages of 2010 

hourly data. Includes 

purge gas.

31 Refinery 36 1,354,000 950 Based on averages of 2010 

hourly data. Includes 

purge gas.

32 Chemical 38 100,000 870 Staged ground flare. 

Based on averages of 2010 

hourly data. Includes 

purge gas.

33 Chemical 30 400,000 1,950 Based on averages of 2010 

hourly data. Includes 

purge gas.

34 Chemical 14 120,000 500 Based on averages of 2010 

hourly data. Includes 

purge gas.
FINAL

December 7, 2011

Page 8

Flare 

Number

Flare 

Description

Flare 

Diameter 

(in)

Flare 

Capacity

(lb/hr)

Min. Flare 

Steam 

Rate*

(lb/hr)

Comments

35 Chemical 48 1,870,000 3,025 Based on averages of 2010 

hourly data. Includes 

purge gas.

36 Chemical 48 1,300,000 0 Based on hourly averages.

37 Chemical 48 3,400,000 0 Emergency and SSM Flare, 

No flow during normal 

operations. Based on 

hourly averages.

38 Chemical 42 1,498,000 0 Based on hourly averages.

*Minimum steam rate as recommended by the manufacturer for flare integrity protection. 

Actual minimum steam may be higher if control, smoking, need for rapid response time, or 

other factors are considered.
FINAL

December 7, 2011

Page 9

Table 2. Combustion Efficiency (CE) Assumptions and Summary

The calculated overall combustion efficiency for the 38 flares for the SFR model and CZ-NHV models 1) as submitted 

(i.e. current operating practices) and 2) as submitted with steam reductions towards meeting an SFR or CZ-NHV

goal (no natural gas addition).

SFR Model

SFR Goal

Overall Combustion 

Efficiency as 

submitted, %

Overall Combustion 

Efficiency Achieved with 

Reduced Steam, % CE Assumptions

SFR Goal = 3 96.0 97.5 SFR<3, CE=98%; SFR≥3, CE=80%

SFR Goal = 4 96.6 97.7 SFR<4, CE=98%; SFR≥4, CE=80%

SFR Goal = 4 95.8 97.5 SFR<4, CE=98%; SFR≥4, CE=70%

SFR Goal = 5 96.8 97.9 SFR<2, CE=98%; SFR≥2, CE=80%

CZ-NHV Model

CZ-NHV Goal

Overall Combustion 

Efficiency as 

submitted, %

Overall Combustion 

Efficiency Achieved 

with Reduced Steam, 

No NG Addition% CE Assumptions

CZ-HNV Goal = 200 96.0 97.3 CZ-NHV≥200, CE=98%; CZ-NHV<200, CE=90%; 

CZ-NHV<100, CE=80%; CZ-NHV<50, CE=70%

CZ-HNV Goal = 300 92.7 96.1 CZ-NHV≥300, CE=98%; CZ-NHV<300, CE=90%; 

CZ-NHV<200, CE=80%; CZ-NHV<100, CE=70%

CZ-HNV Goal = 300 91.8 96.0 CZ-NHV≥300, CE=98%; CZ-NHV<300, CE=90%; 

CZ-NHV<200, CE=80%; CZ-NHV<100, CE=50%

CZ-HNV Goal = 400 91.3 95.3 CZ-NHV≥400, CE=98%; CZ-NHV<400, CE=90%;

CZ-NHV<200, CE=80%; CZ-NHV<100, CE=70%
FINAL

December 7, 2011

Page 10

Table 3. SFR Model Cost Effectiveness Summary

A summary analysis of cost effectiveness calculations, indicating the number and percent of the 38 flares 

in selected cost effectiveness ranges employing the SFR model.

Calculation Case Count % Count % Count % Count % Count % Count %

SFR Goal = 3, Overall CE, 80-98% CE 6 15.8 1 2.6 3.0 7.9 5 13.2 1 2.6 22 57.9

SFR Goal = 3, Reduce Steam Step, 80-98% CE 6 15.8 2 5.3 1.0 2.6 1 2.6 2 5.3 26 68.4

SFR Goal = 3, Add Nat. Gas Step, 80-98% CE 2 5.3 3 7.9 2.0 5.3 3 7.9 0 0.0 28 73.7

SFR Goal = 4, Overall CE, 80-98% CE 6 15.8 0 0.0 3 7.9 4 10.5 0 0.0 25 65.8

SFR Goal = 4, Reduce Steam Step, 80-98% CE 5 13.2 2 5.3 1.0 2.6 1 2.6 0 0.0 29 76.3

SFR Goal = 4, Add Nat. Gas Step, 80-98% CE 1 2.6 2 5.3 0 0.0 3 7.9 1 2.6 31 81.6

SFR Goal = 4, Overall CE, 70-98% CE 6 15.8 3 7.9 1 2.6 3 7.9 1 2.6 24 63.2

SFR Goal = 4, Reduce Steam Step, 70-98% CE 6 15.8 2 5.3 0 0.0 1 2.6 0 0.0 29 76.3

SFR Goal = 4, Add Nat. Gas Step, 70-98% CE 1 2.6 2 5.3 2 5.3 1 2.6 1 2.6 31 81.6

SFR Goal = 5, Overall CE, 80-98% CE 5 13.2 2 5.3 2 5.3 3 7.9 1 2.6 25 65.8

SFR Goal = 5, Reduce Steam Step, 80-98% CE 5 13.2 1 2.6 2 5.3 1 2.6 0 0.0 29 76.3

SFR Goal = 5, Add Nat. Gas Step, 80-98% CE 0 0.0 1 2.6 2 5.3 1 2.6 1 2.6 33 86.8

Flare by Flare Cost Effectiveness Statistics

< 1K $/ton 1K - 5K $/ton 5K - 10K $/ton 10K - 100K $/ton 100K - 1,000K $/ton > 1,000K $/ton
FINAL

December 7, 2011

Page 11

Table 4. CZ-NHV Model Cost Effectiveness Summary

A summary analysis of cost effectiveness calculations, indicating the number and percent of the 38 flares 

in selected cost effectiveness ranges employing the CZ-NHV model.

Calculation Case Count % Count % Count % Count % Count % Count %

CZ-NHV Goal = 200, Overall, 70 -98% CE 2 5.3 5 13.2 3 7.9 7 18.4 3 7.9 18 47.4

CZ-NHV Goal = 200, Reduce Steam Step, 70 -98% CE 2 5.3 4 10.5 0 0.0 9 23.7 1 2.6 22 57.9

CZ-NHV Goal = 200, Add Nat. Gas Step, 70 -98% CE 1 2.6 7 18.4 3 7.9 2 5.3 1 2.6 24 63.2

CZ-NHV Goal = 300, Overall, 70 -98% CE 5 13.2 3 7.9 3 7.9 10 26.3 2 5.3 15 39.5

CZ-NHV Goal = 300, Reduce Steam Step, 70 -98% CE 5 13.2 3 7.9 2 5.3 6 15.8 1 2.6 21 55.3

CZ-NHV Goal = 300, Add Nat. Gas Step, 70 -98% CE 0 0.0 4 10.5 4 10.5 6 15.8 2 5.3 22 57.9

CZ-NHV Goal = 300, Overall, 50 -98% CE 5 13.2 3 7.9 5 13.2 8 21.1 2 5.3 15 39.5

CZ-NHV Goal = 300, Reduce Steam Step, 50 -98% CE 6 15.8 2 5.3 2 5.3 6 15.8 1 2.6 21 55.3

CZ-NHV Goal = 300, Add Nat. Gas Step, 50 -98% CE 0 0.0 5 13.2 4 10.5 5 13.2 2 5.3 22 57.9

CZ-NHV Goal = 400, Overall, 70 -98% CE 5 13.2 7 18.4 1 2.6 14 36.8 2 5.3 9 23.7

CZ-NHV Goal = 400, Reduce Steam Step, 70 -98% CE 5 13.2 7 18.4 2 5.3 7 18.4 0 0.0 17 44.7

CZ-NHV Goal = 400, Add Nat. Gas Step, 70 -98% CE 0 0.0 5 13.2 3 7.9 8 21.1 3 7.9 19 50.0

Flare by Flare Cost Effectiveness Statistics

< 1K $/ton 1K - 5K $/ton 5K - 10K $/ton 10K - 100K $/ton 100K - 1,000K $/ton > 1,000K $/ton
FINAL

December 7, 2011

Page 12

Table 5. SFR Model Cost Sensitivity Summary

Calculation Case Count % Count % Count % Count % Count % Count %

Base

SFR Goal = 4, Overall CE, 80-98% CE 6 15.8 0 0.0 3 7.9 4 10.5 0 0.0 25 65.8

SFR Goal = 4, Reduce Steam Step, 80-98% CE 5 13.2 2 5.3 1 2.6 1 2.6 0 0.0 29 76.3

SFR Goal = 4, Add Nat. Gas Step, 80-98% CE 1 2.6 2 5.3 0 0.0 3 7.9 1 2.6 31 81.6

Double Natural Gas and Steam Prices

SFR Goal = 4, Overall CE, 80-98% CE 6 15.8 0 0.0 2 5.3 4 10.5 1 2.6 25 65.8

SFR Goal = 4, Reduce Steam Step, 80-98% CE 6 15.8 1 2.6 1 2.6 1 2.6 0 0.0 29 76.3

SFR Goal = 4, Add Nat. Gas Step, 80-98% CE 1 2.6 0 0.0 2 5.3 3 7.9 0 0.0 32 84.2

Quadruple Steam Price

SFR Goal = 4, Overall CE, 80-98% CE 6 15.8 1 2.6 3 7.9 3 7.9 0 0.0 25 65.8

SFR Goal = 4, Reduce Steam Step, 80-98% CE 6 15.8 1 2.6 1 2.6 1 2.6 0 0.0 29 76.3

SFR Goal = 4, Add Nat. Gas Step, 80-98% CE 1 2.6 2 5.3 0 0.0 3 7.9 1 2.6 31 81.6

Quadruple Natural Gas Price

SFR Goal = 4, Overall CE, 80-98% CE 5 13.2 1 2.6 1 2.6 5 13.2 1 2.6 25 65.8

SFR Goal = 4, Reduce Steam Step, 80-98% CE 5 13.2 2 5.3 1 2.6 1 2.6 0 0.0 29 76.3

SFR Goal = 4, Add Nat. Gas Step, 80-98% CE 0 0.0 1 2.6 0 0.0 5 13.2 0 0.0 32 84.2

Double Investment Costs

SFR Goal = 4, Overall CE, 80-98% CE 4 10.5 2 5.3 2 5.3 5 13.2 0 0.0 25 65.8

SFR Goal = 4, Reduce Steam Step, 80-98% CE 4 10.5 3 7.9 0 0.0 2 5.3 0 0.0 29 76.3

SFR Goal = 4, Add Nat. Gas Step, 80-98% CE 1 2.6 2 5.3 0 0.0 3 7.9 1 2.6 31 81.6

Half Investment Costs

SFR Goal = 4, Overall CE, 80-98% CE 6 15.8 2 5.3 2 5.3 3 7.9 1 2.6 24 63.2

SFR Goal = 4, Reduce Steam Step, 80-98% CE 7 18.4 1 2.6 0 0.0 1 2.6 0 0.0 29 76.3

SFR Goal = 4, Add Nat. Gas Step, 80-98% CE 1 2.6 2 5.3 0 0.0 3 7.9 1 2.6 31 81.6

Flare by Flare Cost Effectiveness Statistics

< 1K $/ton 1K - 5K $/ton 5K - 10K $/ton 10K - 100K $/ton 100K - 1,000K $/ton > 1,000K $/ton
FINAL

December 7, 2011

Page 13

Table 6. CZ-NHV Model Cost Sensitivity Summary

Calculation Case Count % Count % Count % Count % Count % Count %

Base

CZ-NHV Goal = 300, Overall, 70 -98% CE 5 13.2 3 7.9 3 7.9 10 26.3 2 5.3 15 39.5

CZ-NHV Goal = 300, Reduce Steam Step, 70 -98% CE 5 13.2 3 7.9 2 5.3 6 15.8 1 2.6 21 55.3

CZ-NHV Goal = 300, Add Nat. Gas Step, 70 -98% CE 0 0.0 4 10.5 4 10.5 6 15.8 2 5.3 22 57.9

Double Natural Gas and Steam Prices

CZ-NHV Goal = 300, Overall, 70 -98% CE 5 13.2 2 5.3 1 2.6 11 28.9 4 10.5 15 39.5

CZ-NHV Goal = 300, Reduce Steam Step, 70 -98% CE 5 13.2 3 7.9 2 5.3 6 15.8 1 2.6 21 55.3

CZ-NHV Goal = 300, Add Nat. Gas Step, 70 -98% CE 0 0.0 2 5.3 2 5.3 9 23.7 2 5.3 23 60.5

Quadruple Steam Price

CZ-NHV Goal = 300, Overall, 70 -98% CE 6 15.8 2 5.3 4 10.5 9 23.7 2 5.3 15 39.5

CZ-NHV Goal = 300, Reduce Steam Step, 70 -98% CE 6 15.8 2 5.3 2 5.3 6 15.8 1 2.6 21 55.3

CZ-NHV Goal = 300, Add Nat. Gas Step, 70 -98% CE 0 0.0 4 10.5 4 10.5 6 15.8 2 5.3 22 57.9

Quadruple Natural Gas Price

CZ-NHV Goal = 300, Overall, 70 -98% CE 5 13.2 1 2.6 1 2.6 12 31.6 4 10.5 15 39.5

CZ-NHV Goal = 300, Reduce Steam Step, 70 -98% CE 5 13.2 3 7.9 2 5.3 6 15.8 1 2.6 21 55.3

CZ-NHV Goal = 300, Add Nat. Gas Step, 70 -98% CE 0 0.0 0 0.0 2 5.3 10 26.3 3 7.9 23 60.5

Double Investment Costs

CZ-NHV Goal = 300, Overall, 70 -98% CE 4 10.5 4 10.5 2 5.3 10 26.3 3 7.9 15 39.5

CZ-NHV Goal = 300, Reduce Steam Step, 70 -98% CE 4 10.5 3 7.9 0 0.0 8 21.1 2 5.3 21 55.3

CZ-NHV Goal = 300, Add Nat. Gas Step, 70 -98% CE 0 0.0 4 10.5 4 10.5 6 15.8 2 5.3 22 57.9

Half Investment Costs

CZ-NHV Goal = 300, Overall, 70 -98% CE 5 13.2 3 7.9 6 15.8 7 18.4 2 5.3 15 39.5

CZ-NHV Goal = 300, Reduce Steam Step, 70 -98% CE 7 18.4 3 7.9 1 2.6 5 13.2 1 2.6 21 55.3

CZ-NHV Goal = 300, Add Nat. Gas Step, 70 -98% CE 0 0.0 4 10.5 4 10.5 6 15.8 2 5.3 22 57.9

Flare by Flare Cost Effectiveness Statistics

< 1K $/ton 1K - 5K $/ton 5K - 10K $/ton 10K - 100K $/ton 100K - 1,000K $/ton > 1,000K $/ton
FINAL

December 7, 2011

Page 14

Attachment 1 - Scenario Information

Flare Information Scenario

Flare

#

Flare 

Description 

Flare 

Diameter

Flare 

Capacity

Min. 

Flare 

Stea

m 

Rate

Hours

per year 

for 

Scenario

Flare Gas 

Rate Scenario Description

(in) (lb/hr) (lb/hr) (hours) (lb/hr)

1 Refinery 36 601000 0 8656 228 Normal Operations - Flare Gas Recovery

36 601000 0 17 2224 Emergency Flaring

36 601000 0 6 1322 Startup/Shutdown

36 601000 0 75 6250 Fuel Gas Imbalance

36 601000 0 6 361 Minor Venting

2 Refinery 42 1,450,000 0 8179 392 Normal Operations - Flare Gas Recovery

42 1,450,000 0 86 15515 Emergency Flaring

42 1,450,000 0 445 7830 Startup/Shutdown

42 1,450,000 0 50 14065 Unrecoverable Stream

3 Refinery 24 427,000 1,144 8541 68 Normal Operations - Flare Gas Recovery

24 427,000 1,144 20 3544 Emergency Flaring

24 427,000 1,144 15 2349 Startup/Shutdown

24 427,000 1,144 97 1708 Unrecoverable Stream

24 427,000 1,144 83 1196 Fuel Gas Imbalance

24 427,000 1,144 4 1708 Minor Venting

4 Refinery 30 417,000 0 8493 117 Normal Operations - Flare Gas Recovery

30 417,000 0 23 3962 Emergency Flaring

30 417,000 0 231 5338 Startup/Shutdown

30 417,000 0 7 2252 Fuel Gas Imbalance

30 417,000 0 6 292 Minor Venting

5 Refinery 24 293,000 0 7971 47 Normal Operations - Flare Gas Recovery

24 293,000 0 76 10800 Emergency Flaring

24 293,000 0 528 9950 Startup/Shutdown

24 293,000 0 175 2039 Unrecoverable Stream
FINAL

December 7, 2011

Page 15

Flare Information Scenario

Flare

#

Flare 

Description 

Flare 

Diameter

Flare 

Capacity

Min. 

Flare 

Stea

m 

Rate

Hours

per year 

for 

Scenario

Flare Gas 

Rate Scenario Description

(in) (lb/hr) (lb/hr) (hours) (lb/hr)

24 293,000 0 10 76 Minor Venting

6 Refinery 48 1,684,000 1,200 8160 309 Non-relief avg

48 1,684,000 1,200 600 2765 Relief avg

7 Refinery 60 890,000 2,500 8160 60 Non-relief avg

60 890,000 2,500 600 1357 Relief avg

8 Refinery 48 341,250 2,750 8090 102 Non-relief avg

48 341,250 2,750 218 5504 Relief scenario 1

48 341,250 2,750 9 6970 Relief scenario 2

48 341,250 2,750 36 1833 Relief scenario 3

48 341,250 2,750 360 16612 Relief scenario 4

48 341,250 2,750 24 5556 Relief scenario 5

48 341,250 2,750 23 1387 Relief scenario 6

9 Chemical 21 59,865 1,205 8736 5987 10% T/D @ min steam

21 59,865 1,205 24 23946 Typical Emergency Operation

10 Chemical 24 36,447 750 8736 2916 8% T/D @ min steam

24 36,447 750 24 10934 Typical Emergency Operation

11 Olefins 46.2 1,949,444 3,300 8700 2534 0.13 % t/d

46.2 1,949,444 3,300 50 97472 Emergency Relief Situation #1

46.2 1,949,444 3,300 10 389889 Emergency Relief Situation #2

12 Olefins 46.2 1,949,444 3,300 8700 2534 0.13 % t/d

46.2 1,949,444 3,300 50 97472 Emergency Relief Situation #1

46.2 1,949,444 3,300 10 389889 Emergency Relief Situation #2

13 Chemical 30 330,023 2,300 8760 99 0.03 % t/d

14 Chemical 30 330,023 2,120 8750 3300 1% t/d

30 330,023 2,120 10 33002 Emergency Relief Situation

15 Chemical 24 285,000 1,900 8736 570 0.2 % t/d

24 285,000 1,900 24 22800 Emergency Relief Situation
FINAL

December 7, 2011

Page 16

Flare Information Scenario

Flare

#

Flare 

Description 

Flare 

Diameter

Flare 

Capacity

Min. 

Flare 

Stea

m 

Rate

Hours

per year 

for 

Scenario

Flare Gas 

Rate Scenario Description

(in) (lb/hr) (lb/hr) (hours) (lb/hr)

16 Refinery 30 350,000 1,200 7800 420 1.0 % T/D

17 Refinery 30 370,000 1,200 8600 93 Normal T/D (Purge Gas Only)

18 Refinery 24 208,000 375 48 645 < 1000 lb/hr

24 208,000 375 48 1602 1000 - 2000 lb/hr

24 208,000 375 288 2700 2000 - 3000 lb/hr

24 208,000 375 840 3484 3000 - 4000 lb/hr

24 208,000 375 1224 4655 4000 - 5000 lb/hr

24 208,000 375 5616 7051 5000 - 6000 lb/hr

24 208,000 375 672 11014 10,000 - 20,000 lb/hr

19 Refinery 24 171,000 450 120 140 100 - 200 lb/hr

24 171,000 450 48 215 200 - 300 lb/hr

24 171,000 450 72 693 500 - 1000 lb/hr

24 171,000 450 24 3124 > 1000 lb/hr

20 Refinery 42 715,000 600 144 172 < 200 lb/hr

42 715,000 600 1152 293 200 - 400 lb/hr

42 715,000 600 1080 493 400 - 600 lb/hr

42 715,000 600 1104 708 600 - 800 lb/hr

42 715,000 600 1296 894 800 - 1000 lb/hr

42 715,000 600 3024 1233 1000 - 1500 lb/hr

42 715,000 600 840 1723 1500 - 2000 lb/hr

42 715,000 600 96 2610 > 2000 lb/hr

21 Refinery 30 634,500 300 8760 8249 Normal operation

22 Refinery 42 923,100 500 8760 11077 Normal operation

23 Refinery 42 250,000 2,100 232 5000 Typical Emergency Operation

42 250,000 2,100 358 5000 Typical Emergency Operation

42 250,000 2,100 105 10000 Typical Emergency Operation

24 Refinery 42 250,000 2,100 123 5000 Typical Emergency Operation

42 250,000 2,100 85 10000 Typical Emergency Operation
FINAL

December 7, 2011

Page 17

Flare Information Scenario

Flare

#

Flare 

Description 

Flare 

Diameter

Flare 

Capacity

Min. 

Flare 

Stea

m 

Rate

Hours

per year 

for 

Scenario

Flare Gas 

Rate Scenario Description

(in) (lb/hr) (lb/hr) (hours) (lb/hr)

25 Refinery 42 250,000 2,100 292 5000 Typical Emergency Operation

26 Refinery 36 750,000 2,000 8610 3750 Normal Operation

36 750,000 2,000 150 165000 Smokeless Operation - Emergency

27 Refinery 36 750,000 2,000 8610 3750 Normal Operation

36 750,000 2,000 150 165000 Smokeless Operation - Emergency

28 Refinery 36 505,000 1,500 365 34436 >25,000 lb/hr

36 505,000 1,500 1502 15054 10,000-25,000 lb/hr

36 505,000 1,500 2383 6792 5,000-10,000 lb/hr

36 505,000 1,500 4510 2889 0-5,000 lb/hr

29 Refinery 36 561,000 1,880 115 43304 >25,000 lb/hr

36 561,000 1,880 358 12067 5,000-25,000 lb/hr

36 561,000 1,880 1133 2199 1,500-5000 lb/hr

36 561,000 1,880 7154 331 <1,500 lb/hr

30 Refinery 24 400,000 1,810 45 13492 >10,000 lb/hr

24 400,000 1,810 222 4956 1,000-10,000 lb/hr

24 400,000 1,810 8493 8 0-1,000 lb/hr

31 Refinery 36 1,354,000 950 3 45846 >10,000 lb/hr

36 1,354,000 950 13 3480 1,000-10,000

36 1,354,000 950 8743 203 0-1,000

32 Chemical 38 100,000 870 5022 3682 Stage 1 (8 burners) - 0-6,000 lb/hr

38 100,000 870 3437 8074 Stage 2 (24 burners) - 6,000-15,000 lb/hr

38 100,000 870 301 27472 Stage 3 (60 burners) - 15,000-100,000 lb/hr

33 Chemical 30 400,000 1,950 2 10440 >10,000 lb/hr

30 400,000 1,950 1202 6724 5,000_10,000 lb/hr

30 400,000 1,950 6875 2404 2,000-5,000 lb/hr

30 400,000 1,950 681 1728 0-2,000 lb/hr

34 Chemical 14 120,000 500 4605 1386 1,000-4,000 lb/hr

14 120,000 500 4155 524 0-1,000 lb/hr
FINAL

December 7, 2011

Page 18

Flare Information Scenario

Flare

#

Flare 

Description 

Flare 

Diameter

Flare 

Capacity

Min. 

Flare 

Stea

m 

Rate

Hours

per year 

for 

Scenario

Flare Gas 

Rate Scenario Description

(in) (lb/hr) (lb/hr) (hours) (lb/hr)

35 Chemical 48 1,870,000 3,025 54 58531 >25,000 lb/hr

48 1,870,000 3,025 57 12716 5-25,000 lb/hr

48 1,870,000 3,025 484 1664 1,000-5,000

48 1,870,000 3,025 8165 673 <1,000 lb/hr

36 Chemical 48 1,300,000 0 600 1950 1000-2000 lb/hr

48 1,300,000 0 4032 2389 2000-3000 lb/hr

48 1,300,000 0 2160 3539 3000-4000 lb/hr

48 1,300,000 0 1032 4446 4000-5000 lb/hr

48 1,300,000 0 720 6184 5000-10000 klb/hr

48 1,300,000 0 192 11788 10000 - 20000 lb/hr

48 1,300,000 0 24 26312 > 20000 lb/hr

37 Chemical 64 3,400,000 0 192 1428 1000-2000 lb/hr

64 3,400,000 0 48 2550 2000-3000 lb/hr

64 3,400,000 0 24 8177 5000-10000 klb/hr

38 Chemical 42 1,498,000 0 2929 719 < 1000 lb/hr

42 1,498,000 0 5463 1378 1000-2000 lb/hr

42 1,498,000 0 353 2157 2000-3000 lb/hr

42 1,498,000 0 1 3011 3000-4000 lb/hr

42 1,498,000 0 5 4479 4000-5000 lb/hr

42 1,498,000 0 7 7850 5000-10000 klb/hr

42 1,498,000 0 2 14635 10000 - 20000 lb/hr
FINAL

December 7, 2011

Page 19

Attachment 2 – Methodology for Calculating Cost Effectiveness

Step 1: Calculation of Potential Annual VOC Emission Reduction

1. Calculate VOC content for each flare composition using submitted 

composition.

2. Calculate VOC rate to the flare for each operating period.

3. Calculate flare combustion efficiency (CE) for each operating period 

using basis presented on Page 2 (or alternate for sensitivity analyses).

4. Calculate as submitted and “controlled” VOC emissions rate = VOC 

rate to flare ∗ (1-CE) for each operating period.

5. Subtract controlled VOC emission rate from “as submitted” VOC 

emission rate.

6. Multiply emission rate difference for each operating period times hours 

of operation for that period.

7. Calculate total potential annual VOC emissions reduction by 

summation of the differential VOC emissions for each operating period.

Step 2: Calculation of Annual Flare Monitoring and Control Cost

1. Total capital costs assumed to be $1.0 MM per flare (Case 1) and 

$2.3MM per flare (Case 2). CRF: (20 yr., 7%) = 0.09439 used to 

annualize.

2. Annual maintenance cost assumed to be 5%of investment for analyzer 

related investment, 2% otherwise.

3. Calculate annual steam savings from reducing steam to meet goal. 

($1.00/1000 lb assumed steam price.)

4. Calculate annual natural gas addition required to meet goal where 

steam reductions inadequate. (NG valued at $0.10/lb.)

5. Calculate annual cost = (CRF ∗ total capital cost) + annual 

maintenance cost – annual steam savings + annual supplemental gas 

cost.
FINAL

December 7, 2011

Page 20

Step 3: Calculate cost-effectiveness for each flare by dividing the annual

cost by the annual total VOC reduction

Step 4: Calculate the overall cost effectiveness for all 38 flares by dividing 

the sum of the annual costs for all 38 flares by the sum of the annual total 

VOC reduction.

NOTE: This calculation counts the investment in monitoring and controls for 

all 38 flares, whether or not a particular flare generates VOC reductions.
Attachment 3

Cost Data
Parameters/Costs

Flow Instrument to Measure 

Vent Gas Volumetric/Mass Flow, 

Temperature, and Molecular Wt

Flow Instrument to Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition &

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

8

(2 sets per flare header & 

2 existing)

8 - Temperature Transmitters

8-Pressure Transmitters

5-Flow Ttransmitters

4

4

(start-up steam valves; 1 

at each location. 1 

main steam valve 

replacement at NNA)

5

0

(using existing)

0

(using existing)

B. Equipment Manufacturer & Model2

GE/PANAMETRIC -ULTRASONIC 

GAS FLOWMETER PER M 

 K005J101A. PART# GF868-2-11-

21424-FM-0-0 - 

GE/PANAMETRIC - ULTRASONIC 

GAS FLOWMETER PER M 

 K005J100A. PART# GS868-1-11-

21414-FM-0-0 - 

Fisher-67CFR Siemens - Maxum II N/A N/A

2011 2011 2011 2011 N/A N/A

D. Total Capital Cost, $

1. Purchased equipment cost $198,029 $93,361 $63,825 $1,959,249 N/A N/A

2. Materials: piping, civil, structural,

electrical, mechanical, insulation, paint, $1,319,865 $699,938 $524,639 $251,397 N/A N/A

3. Installation

(for items 1 & 2 above) $1,087,159 $542,735 $389,104 $300,217 N/A N/A

4. Indirects 

(e.g. supervision, scaffolding, etc)

(including electrical and construction)

$1,099,756 $518,482 $354,452 $259,548 N/A N/A

5. Start-up, initial certification & 

calibration $52,773 $52,773 $52,773 $52,773 N/A N/A

6. Prepare QA/QC plan

(if applicable) $0 $0 $0 $0 N/A N/A

7. Total capital cost $3,757,583 $1,907,290 $1,384,793 $2,823,184 $0 $0

E. Total Engineering Cost, $ $588,003 $328,103 $254,762 $456,664 N/A N/A

$168,311 $168,311 $168,311 $168,311 N/A N/A

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 4

C. Year Instrument/Controls Were Installed

(or are expected to be installed)

A. For each equipment category,

indicate the quantity that you are costing

F. Total One Time Expenses, $ 

(OWNER COST)

MPC Catlettsburg, KY Refinery 

Flare Monitoring Costs

jrw/jrw

Catlettsburg Flare Monitoring and Control Costs (03-02-11)-rev1.XLSX

3/14/2013 1
Parameters/Costs

Flow Instrument to Measure 

Vent Gas Volumetric/Mass Flow, 

Temperature, and Molecular Wt

Flow Instrument to Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition &

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 4

A. For each equipment category,

indicate the quantity that you are costing

MPC Catlettsburg, KY Refinery 

Flare Monitoring Costs

G. Contingency, $ $376,516 $191,048 $138,711 $282,791 N/A N/A

H. Total Annual Cost, $/yr

1. Operation (labor & materials) $90,244 $47,882 $35,921 $46,496 N/A N/A

2. Maintenance (labor & materials) $90,244 $47,882 $35,921 $68,000 N/A N/A

3. On-going certification & calibration

(if not included in items 1 & 2 above) 0 0 0 0 N/A N/A

4. Utilities

(if not included in items 1 & 2 above) $250,000 $200,000 $150,000 $200,000 N/A N/A

5. Property taxes, insurance, & administration 0 0 0 0 N/A N/A

6. Total annual cost (excluding recordkeeping 

and reporting) $430,488 $295,763 $221,841 $314,496 $0 $0

I. Additional Questions

1. Do you operate a computer interface system (e.g., DCS) that interacts (or could interact) with the monitoring equipment 

listed above? 

2. If yes, can the computer interface system be programmed to automatically monitor heat content in the combustion zone 

and/or steam ratios? If so, what are the estimated costs and/or time required to do programming?

Answer:

Yes

Yes; approximately one month

jrw/jrw

Catlettsburg Flare Monitoring and Control Costs (03-02-11)-rev1.XLSX

3/14/2013 2
Parameters/Costs

Flow Instrument to 

Measure 

Vent Gas 

Volumetric/Mass Flow, 

Temperature, and 

Molecular Weight

Flow Instrument to 

Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition 

and

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

7 4 4 2

1

B. Equipment Manufacturer & Model2 GE (GF-2-11-21824-FM-0-0) GE (GS868-1-11-21814-FM-0-0)

Fisher V-Ball (ground Flare) ; 

Fisher 657 (Stick Flares) Siemens IA2018.2

Met One Instruments

2011 2011 2011 2011 2006

D. Total Capital Cost, $

1. Purchased equipment cost $380,000 $125,000 $75,000 $350,000 $30,000

2. Materials: piping, civil, structural,

electrical, mechanical, insulation, paint, etc $300,000 $250,000 $300,000 $850,000 $10,000

3. Installation

(for items 1 & 2 above) $1,300,000 $1,750,000 $500,000 $400,000 $60,000

4. Indirects 

(e.g. supervision, scaffolding, etc)

(including electrical and construction)

$350,000 $400,000 $200,000 $100,000 $20,000

5. Start-up, initial certification & calibration $100,000 $100,000 $500,000

6. Prepare QA/QC plan

(if applicable)

7. Total capital cost $2,430,000 $2,625,000 $1,075,000 $0 $2,200,000 $120,000 $0

E. Total Engineering Cost, $ $100,000 $100,000 $100,000 $100,000 $20,000

F. Total One Time Expenses, $

G. Contingency, $ $400,000 $400,000 $100,000 $400,000

H. Total Annual Cost, $/yr

1. Operation (labor & materials) $20,000 $20,000 $25,000

2. Maintenance (labor & materials) 15,000 $15,000 $10,000 $15,000

3. On-going certification & calibration

(if not included in items 1 & 2 above)

4. Utilities

(if not included in items 1 & 2 above)

5. Property taxes, insurance, & administration $10,000

6. Total annual cost (excluding recordkeeping 

and reporting) $35,000 $35,000 $10,000 $0 $40,000 $10,000 $0

I. Additional Questions

Notes (feel free to footnote where necessary):

1 Please describe the details in the entry cell for "Equipment Model Type" as to what you are pricing for steam controls (e.g. two fine tune valves and one gross tune valve, etc).

2 Be specific; include both the manufacturer and model number.

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 4

C. Year Instrument/Controls Were Installed

(or are expected to be installed)

1. Do you operate a computer interface system (e.g., DCS) that interacts (or could interact) with the 

monitoring equipment listed above? 

2. If yes, can the computer interface system be programmed to automatically monitor heat content in 

the combustion zone and/or steam ratios? If so, what are the estimated costs and/or time required to 

do programming?

Answer:

yes

yes, 80 man hours

A. For each equipment category,

indicate the quantity that you are costing

MPC Garyville, LA Refinery 

Flare Monitoring Costs

JRW/jrw

Garyville Flare Monitoring and Control Costs.XLSX

3/14/2013
Parameters/Costs

Flow Instrument to 

Measure 

Vent Gas 

Volumetric/Mass Flow, 

Temperature, and 

Molecular Weight

Flow Instrument to 

Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition 

and

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

6 6

6 

An additional fine tune 

steam control valve is 

being added to each 

flare

4 - 

3 flares share 1 

analyzer

N/A N/A

B. Equipment Manufacturer & Model2

GE Panametrics dual 

channel Ultrasonic Flow 

meter - Model # GF868

GE Panametrics Ultrasonic 

Steam meter - Model # 

GS868

Siemens Maxum Edition II 

GC Analyzer

3 - 2010

3 - 2012

3 - 2010

3 - 2012

3 - 2010

3 - 2012

1 - 2010

3 - 2012

D. Total Capital Cost, $

1. Purchased equipment cost $720,000 $213,000 $308,000 $2,078,000

2. Materials: piping, civil, structural,

electrical, mechanical, insulation, paint, 

etc

$152,500 $212,000 $99,500 $274,000

3. Installation

(for items 1 & 2 above) $560,000 $393,000 $358,000 $1,039,000

4. Indirects 

(e.g. supervision, scaffolding, etc)

(including electrical and construction)

$171,000 $257,000 $85,000 $440,000

5. Start-up, initial certification & 

calibration $80,000 $12,000 $46,000

6. Prepare QA/QC plan

(if applicable)

7. Total capital cost $1,683,500 $1,087,000 $850,500 $3,877,000 $0 $0

E. Total Engineering Cost, $ $437,000 $441,000 $190,000 $1,272,000

F. Total One Time Expenses, $

G. Contingency, $ $99,000 $103,000 $42,000 $285,000

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 6

C. Year Instrument/Controls Were Installed

(or are expected to be installed)

A. For each equipment category,

indicate the quantity that you are costing

MPC Robinson, IL Refinery 

Flare Monitoring Costs

JRW/jrw

Robinson Flare Monitoring and Control Costs (03-02-11).XLSX

3/14/2013 1
Parameters/Costs

Flow Instrument to 

Measure 

Vent Gas 

Volumetric/Mass Flow, 

Temperature, and 

Molecular Weight

Flow Instrument to 

Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition 

and

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 6

A. For each equipment category,

indicate the quantity that you are costing

MPC Robinson, IL Refinery 

Flare Monitoring Costs

H. Total Annual Cost, $/yr

1. Operation (labor & materials) $70,000 $35,000 $25,000 $70,000

2. Maintenance (labor & materials) 70,000 $35,000 $25,000 $90,000

3. On-going certification & calibration

(if not included in items 1 & 2 above) $15,000 $32,000

4. Utilities

(if not included in items 1 & 2 above) 100,000 $75,000 $70,000

5. Property taxes, insurance, & 

administration

6. Total annual cost (excluding 

recordkeeping and reporting) $255,000 $145,000 $50,000 $262,000 $0 $0

I. Additional Questions

Notes (feel free to footnote where necessary):

1 Please describe the details in the entry cell for "Equipment Model Type" as to what you are pricing for steam controls (e.g. two fine tune valves and one gross tune valve, etc).

2 Be specific; include both the manufacturer and model number.

1. Do you operate a computer interface system (e.g., DCS) that interacts (or could interact) with the 

monitoring equipment listed above? 

2. If yes, can the computer interface system be programmed to automatically monitor heat content in 

the combustion zone and/or steam ratios? If so, what are the estimated costs and/or time required to 

do programming?

Answer:

Yes 

Yes. Estimated time to complete programming is 1000 hours. 

JRW/jrw

Robinson Flare Monitoring and Control Costs (03-02-11).XLSX

3/14/2013 2
Parameters/Costs 7

Flow Instrument to 

Measure 

Vent Gas 

Volumetric/Mass Flow, 

Temperature, and 

Molecular Weight

Flow Instrument to 

Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition 

and

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

2 2

Two fine tune valves

and two gross tune 

valves

2 1 2 (monitoring only)

B. Equipment Manufacturer & Model2 GE Panametrics - 

Model GF868

GE Panametrics - 

Model GS868

Siemens - Maxum 

Edition II TBD3

2005 2009/2010 2009/2010 2005 2011 (Planned) 2009

D. Total Capital Cost, $

1. Purchased equipment cost $50,000 $100,000 INCLUDED IN PREVIOUS 

COLUMN

ROW D.2.

$500,000 $30,000 4

2. Materials: piping, civil, structural,

electrical, mechanical, insulation, paint, etc $420,000 $138,000 INCLUDED IN PREVIOUS 

COLUMN

ROW D.2.

$167,000 $15,000 4

3. Installation

(for items 1 & 2 above) $215,000 $497,000 INCLUDED IN PREVIOUS 

COLUMN

ROW D.3.

$180,000 $50,000 4

4. Indirects 

(e.g. supervision, scaffolding, etc)

(including electrical and construction)

$91,000 $136,000

INCLUDED IN PREVIOUS 

COLUMN

ROW D.4.

$93,000 $15,000 4

5. Start-up, initial certification & calibration

6. Prepare QA/QC plan

(if applicable)

7. Total capital cost5 $776,000 $1,081,000 INCLUDED IN PREVIOUS 

COLUMN

ROW D.7.

$940,000 $150,000 4 $25,000

$0

E. Total Engineering Cost, $ $174,600 $210,000 INCLUDED IN PREVIOUS 

COLUMN

ROW E.

$172,200 $25,000 4

F. Total One Time Expenses, $

G. Contingency, $ $15,000 4

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 2

C. Year Instrument/Controls Were Installed

(or are expected to be installed)

A. For each equipment category,

indicate the quantity that you are costing

MPC Texas City, TX Refinery 

Flare Monitoring Costs

jrw/jrw

Texas City Flare Monitoring and Control Costs.xlsx

3/14/2013 1
Parameters/Costs 7

Flow Instrument to 

Measure 

Vent Gas 

Volumetric/Mass Flow, 

Temperature, and 

Molecular Weight

Flow Instrument to 

Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition 

and

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 2

A. For each equipment category,

indicate the quantity that you are costing

MPC Texas City, TX Refinery 

Flare Monitoring Costs

H. Total Annual Cost, $/yr

1. Operation (labor & materials) $23,000 $20,000 $15,000 $24,000

2. Maintenance (labor & materials) $2,000 $2,000 $15,000 $24,000 $1,000 4

3. On-going certification & calibration

(if not included in items 1 & 2 above) $5,000 $5,000 $5,000 4

4. Utilities

(if not included in items 1 & 2 above) $60,000 $40,000 $35,000 $55,000

5. Property taxes, insurance, & administration $17,000 6

$11,000 6$2,000 6

6. Total annual cost (excluding recordkeeping 

and reporting) $90,000 $67,000 $65,000 $103,000 $6,000 4 $0

I. Additional Questions

Notes (feel free to footnote where necessary):

1 Please describe the details in the entry cell for "Equipment Model Type" as to what you are pricing for steam controls (e.g. two fine tune valves and one gross tune valve, etc).

2 Be specific; include both the manufacturer and model number.

3 Still being engineered - specific equipment manufacturer not yet selected

4 Still being engineered - costs are estimated

5 Includes engineering and contingency 

6 Based on discussions with accounting this is estimated at 1% of TIC (Line 7)

7 Does not include any costs for supplemental gas control (if required). Does not include any costs for sulfur measurement.

1. Do you operate a computer interface system (e.g., DCS) that interacts (or could interact) with the 

monitoring equipment listed above? 

2. If yes, can the computer interface system be programmed to automatically monitor heat content in 

the combustion zone and/or steam ratios? If so, what are the estimated costs and/or time required to 

do programming?

Answer:

Yes - steam control is based on input from vent gas flow meter, steam flow and GC parameters

We currently monitor and record both the heat content in the combustion zone as well as the steam to vent gas ratio.

jrw/jrw

Texas City Flare Monitoring and Control Costs.xlsx

3/14/2013 2
Parameters/Costs

Flow Instrument to 

Measure 

Vent Gas 

Volumetric/Mass Flow, 

Temperature, and 

Molecular Weight

Flow Instrument to 

Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition 

and

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

4 4 9 4

N/A Existing 

Equipment N/A

B. Equipment Manufacturer & Model2 GE GF868-2 GE GS868-1 Masoneilan Camflex II Siemens Maxum II N/A N/A

2010 2010 2010 2010 N/A N/A

D. Total Capital Cost, $

1. Purchased equipment cost $173,146 $89,481 $71,027 $1,450,068 N/A N/A

2. Materials: piping, civil, structural,

electrical, mechanical, insulation, paint, etc $175,500 $87,750 $70,200 $1,421,550 N/A N/A

3. Installation

(for items 1 & 2 above) $197,910 $98,950 $79,165 $1,603,050 N/A N/A

4. Indirects 

(e.g. supervision, scaffolding, etc)

(including electrical and construction)

$57,500 $28,750 $23,000 $465,750 N/A N/A

5. Start-up, initial certification & calibration $46,650 $23,320 $18,658 $377,820 N/A N/A

6. Prepare QA/QC plan

(if applicable) N/A N/A N/A N/A N/A N/A

7. Total capital cost $650,706 $328,251 $262,050 $5,318,238 N/A N/A

E. Total Engineering Cost, $ $144,560 $72,280 $57,524 $1,301,040 N/A N/A

F. Total One Time Expenses, $ $75,000 $75,000 N/A N/A N/A N/A

G. Contingency, $ N/A actual costs N/A actual costs N/A actual costs N/A actual costs N/A N/A

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 4 Flares

C. Year Instrument/Controls Were Installed

(or are expected to be installed)

A. For each equipment category,

indicate the quantity that you are costing

MPC Detroit, MI Refinery 

Flare Monitoring Costs

JRW/jrw

Detroit Enviromental Cost Review.XLSX

3/14/2013
Parameters/Costs

Flow Instrument to 

Measure 

Vent Gas 

Volumetric/Mass Flow, 

Temperature, and 

Molecular Weight

Flow Instrument to 

Measure 

Steam Mass Flow

Steam Controls

(including steam 

manifolds and valves)1

Heating Value Analyzer 

(e.g. Calorimeter) to 

Measure Vent Gas Heat 

Content

Gas Chromatograph to 

Measure 

Vent Gas Composition 

and

Heat Content

Met Station to Measure 

Wind Speed, 

Temperature, etc.

Video Monitoring and 

Storage

Indicate in the yellow box, how many flares are associated with the equipment you describe in this worksheet: 4 Flares

A. For each equipment category,

indicate the quantity that you are costing

MPC Detroit, MI Refinery 

Flare Monitoring Costs

H. Total Annual Cost, $/yr

1. Operation (labor & materials) $45,000 $45,000 $35,000 $55,000 N/A N/A

2. Maintenance (labor & materials) $45,000 $45,000 $35,000 $55,000 N/A N/A

3. On-going certification & calibration

(if not included in items 1 & 2 above) Included Above Included Above Included Above Included Above N/A N/A

4. Utilities

(if not included in items 1 & 2 above) 160,000 140,000 120,000 150,000 N/A N/A

5. Property taxes, insurance, & administration N/A N/A

6. Total annual cost (excluding recordkeeping 

and reporting) $250,000 $230,000 $190,000 $260,000 N/A N/A

I. Additional Questions

Notes (feel free to footnote where necessary):

1 Please describe the details in the entry cell for "Equipment Model Type" as to what you are pricing for steam controls (e.g. two fine tune valves and one gross tune valve, etc).

2 Be specific; include both the manufacturer and model number.

1. Do you operate a computer interface system (e.g., DCS) that interacts (or could interact) with the 

monitoring equipment listed above? 

2. If yes, can the computer interface system be programmed to automatically monitor heat content in 

the combustion zone and/or steam ratios? If so, what are the estimated costs and/or time required to 

do programming?

Answer:

Yes, the new equipment is connected to DCS

Yes, estimate 200 hours of programming time and 2 months for full programming effort.

JRW/jrw

Detroit Enviromental Cost Review.XLSX

3/14/2013
Table 3-6. Gas chromatograph analyzer cost estimates provided by vendors.

Parameter AIT (a) SIEMENS

(b)

Wasson-ECE

(c)

Rosemount 

Emerson

(d)

TASC

(e)

Average Cost 

(Median of 

Ranges)

Gas Chromatograph $41,700 $50-60K $48,350

Sampling System $51,690 $30-35K $42,095

Options $41,330 $41,330

Total Instrument System $134,720 $70-95K $150,000 $80-200K $126,805

Building (f) $35-45,000 $40,000

Installation/Startup $11,160 $11,160

TCI $177,965

TCI (Rounded)

Discount Rate 7%

Equipment Life (yrs) 20

CRF 0.094

Annual Maintenance $2,000

Gas Cost $2,551

TAC (h) $16,799

TAC (Rounded) $17,000

Notes:

Based on information from Wasson-ECE Instrumentation

Based on information from Wasson-ECE Instrumentation

Capital Costs

Annualized Costs

(f) Cost based on a 3-sided shelter (also known as a bus stop).

(g) Sampling system cost from TASC is the average of an injection system and pump system, plus sampling line and a probe.

(h) TAC does not include electricity or utilities other than instrument gas requirements.

Based on information from SIEMENS

(a) Email from David Peters on 3/8/2013 of Applied Instrument Technologies, Inc. (AIT). http://www.aitanalyzers.com/

(b) Phone conversation on 3/18/13 with Jerry Combs of SIEMENS.http://www.usa.siemens.com/answers/en/

(c) Email from Brice Van Der Volgen on 3/12/2013 of Wasson-ECE Instrumentation. http://www.wasson-ece.com/

(d) Email from Dallas Wiard on 3/15/2013 of Rosemount Analytical, Emerson Process Management. http://www2.emersonprocess.com/enUS/brands/rosemountanalytical/GC/Pages/index.aspx

(e) Phone conversation on 10/17/12 with Nick Valasek of Technical Automation Services Company (TASC). http://www.tascorp.com/
Applied Instrument Technologies, Inc.

 

 

Budgetary Proposal for ERG for Model FXi GC analyzing Flare 

Gas

Proposal #: G130306-1BP0

Proposal Made by: Applied Instrument Technologies, Inc.

2121 Aviation Drive

Upland, CA, USA 91786

WARNING

COPYRIGHT© 2010 APPLIED INSTRUMENT TECHNOLOGIES, INC. THIS DOCUMENT IS THE PROPERTY OF APPLIED INSTRUMENT 

TECHNOLOGIES, INC. (AIT). YOU MAY NOT POSSESS, USE, COPY OR DISCLOSE THIS DOCUMENT OR ANY INFORMATION IN IT, FOR ANY 

PURPOSE, INCLUDING WITHOUT LIMITATION, TO DESIGN, MANUFACTURE OR REPAIR PARTS, OR OBTAIN ANY GOVERNMENT APPROVAL 

TO DO SO, WITHOUT AIT’S EXPRESS WRITTEN PERMISSION. NEITHER RECEIPT NOR POSSESSION OF THIS DOCUMENT ALONE, FROM ANY 

SOURCE, CONSTITUTES SUCH PERMISSION. POSSESSION, USE COPYING OR DISCLOSURE BY ANYONE WITHOUT AIT’S EXPRESS WRITTEN 

PERMISSION IS NOT AUTHORIZED AND MAY RESULT IN CRIMINAL AND/OR CIVIL LIABILITY.

G130306-1BP0 Page 1 of 18 March 7, 2013 

Applied Instrument Technologies’ proprietary information, use or disclosure of information on this page is subject to the notice or restrictions on 

this documents first or title page.
Applied Instrument Technologies, Inc.

 

 

TO: ERG DATE: March 7, 2013

2909 Fox Glove Dr. QUOTE# G130306-1BP0

Winterville, NC 28590 OFFER FIRM FOR: 90 Days

DELIVERY: 16-18 weeks

TERMS: 30% with order,

Balance, upon Shipment

ATTN: Phillip Crawford FCA: Upland, California

TEL: Budgetary

FAX: ISSUED BY: B. Profeta

EMAIL: Approvals: J. V. LaConte

 FXi Series5 Process Gas Chromatography Systems

ITEM QTY

PART

NUMBER DESCRIPTION

LIST 

PRICE, 

US$

1 1 FXi FXi Series5 PROCESS GAS CHROMATOGRAPH

Model Code FXi-1C1A1AGSX-2M

Tag Number: Flare Gas 

Including: Application Engineering, Testing and Documentation

$41,700.00

2 1 P170-9001-

154

SAMPLE CONDITIONING SYSTEM GC#1

1-Stream Gas Sample Conditioning System, complete with heated 

sample probe, liquid separator, sample cooler, fast loop filter & 

flow meters, stream select valves, calibration select valve, sample 

flow meter, guard filter, completely piped and mounted in 

insulated, enclosure.

$51,690.00

TOTAL PRICE $93,390.00

Packaging and Handling $400.00

3 1 lot SERV STARTUP & COMMISSIONING SUPPORT

Startup & Commissioning support, Up to 3 days service support 

at Plant site.

TOTAL $11,160.00

TOTAL SYSTEM PRICE $104,950.00

4 1 39-

0086/0007

OPTIONAL: REMOTE ANALYZER 

WORKSTATION

Workstation PC package for remote monitoring, operation, 

chromatogram review, and control, including printer.

$7,720.00

5 1 RAMS OPTIONAL: PC ANALYZER SOFTWARE 

(Unbundled)

Windows based Software package for customer supplied PC for 

remote monitoring, operation, chromatogram review, and control.

$1,120.00

6 1 lot SPARES OPTIONAL: Tools and Commissioning Spares $6,930.00

7 1 lot SPARES OPTIONAL: Spares for 2 Years Operation $20,910.00

8 1 lot FAT OPTIONAL: FACTORY ACCEPTANCE TEST 

INSPECTION

Estimated 3 days of Factory Acceptance Inspection and Testing

Note FAT is not eligible for Commissions

$4,650.00

G130306-1BP0 Page 2 of 18 March 7, 2013 

Applied Instrument Technologies’ proprietary information, use or disclosure of information on this page is subject to the notice or restrictions on 

this documents first or title page.
Applied Instrument Technologies, Inc.

 

 

SERVICE

Service is not included and will be billed separately. If Service 

from AIT is required, please contact Applied Instrument 

Technologies for standard International Service rates.

TERMS

Payment shall be 30% with order, Balance, upon Shipment.

All prices are FCA Upland, California and are subject to change without 

notice. Orders will be invoiced at price in effect at time of order.

WARRANTY

Applied Instrument Technologies, FXi Series GC products and 

accessories carry a one-year parts warranty from date of shipment. This 

warranty excludes all consumable items.

3. Warranty

FXi accessories carry a parts warranty only. The warranty period is 12- months from the date of 

shipment. This warranty covers defects in materials and workmanship and excludes all 

consumable items. All warranty labor and travel is the responsibility of the Purchaser.

4. How to Order

To place an order for a FXi GC, send a purchase order to Applied Instrument Technologies

attention Rita Pierce. She can be contacted at:

Phone: 909-204-3733

Fax @ 909-204-3701 or 

Email: orders@aitanalyzers.com 

G130306-1BP0 Page 3 of 18 March 7, 2013 

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this documents first or title page.
Applied Instrument Technologies, Inc.

 

 

5. TERMS AND CONDITIONS OF SALE

THIS MATERIAL IS QUOTED AND WILL BE SOLD, IF ORDERED, SUBJECT TO THE 

FOLLOWING TERMS AND CONDITIONS:

1. TAXES - Buyer is responsible for the ultimate payment of all taxes which may be assessed 

or levied on or on account of materials sold hereunder to the Buyer. Prices are subject to change 

due to any Federal or State laws taxing raw or processed materials or governing the working 

hours or compensation of labor. Buyer will be notified of any impact to prices at the time a 

purchase order/contract is placed.

2. PACKING/LOSS OR DAMAGE IN TRANSIT - Materials will be packed for shipment in 

a manner suitable to the method of shipment specified by Buyer or to the method selected by 

Seller in the absence of instructions. Risk of loss or damage to materials in transit is upon the 

Buyer.

3. DELIVERY - Shipment schedules are approximate and are based on conditions at the time 

of acceptance. Seller will make every effort to complete shipment as indicated, but assumes no 

responsibility or liability for loss or damage by reason of delay or inability to ship caused by acts 

of God, fires, floods, wars, embargoes, labor disputes, acts of sabotage, riots, accidents, delays of 

carriers, subcontractors or supplies, voluntary or mandatory compliance with any governmental 

act, regulation or request, shortage of labor, materials or manufacturing facilities, or any other 

cause or causes beyond Seller’s reasonable control. If, by reason of any of these things, Seller’s 

supplies of the materials covered hereby are limited, Seller shall have the right to prorate the 

available supply in such manner as it, in its discretion determines.

4. PARTIAL DELIVERY - Partial deliveries shall be accepted and paid for at contract prices 

on maturity of bills therefore. If any part of the material is not delivered by the Seller or is not in 

accordance with the order, the order for the remainder of the material and the Buyer’s obligation 

there under shall not be affected thereby. The Seller may, at its option, replace any or all 

returned material within a reasonable time after it is finally determined that the returned goods 

are not in accordance with the contract; and in such event the Seller shall not be liable for any 

damage arising from the defective delivery or delay caused thereby.

5. FCA POINT - Transfer of title shall take place at Seller’s factory, Upland, California.

6. PAYMENT TERMS – 30% with order, Balance, upon Shipment.

7. INSPECTION ON ARRIVAL - The Buyer shall inspect the material immediately on its 

arrival and shall within fifteen (15) days of its arrival give written notice to the Seller of any 

claim for shortage or that the material does not conform to the terms of the contract. If the Buyer 

shall fail to give such notice, the material shall be deemed to conform to the terms of the contract 

and the Buyer shall be bound to accept and pay for the material in accordance with the terms of 

the contract.

8. WARRANTY – See paragraph 3.

G130306-1BP0 Page 4 of 18 March 7, 2013 

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this documents first or title page.
Applied Instrument Technologies, Inc.

 

 

9. INDEMNITY – The Buyer will protect and indemnify the Seller against all claims for 

damages or profits arising from infringement of patents, design copyrights or trademarks, with 

respect to all goods manufactured, either in whole or part, to the Buyer’s specifications.

10. DIES, TOOLS OR FIXTURES – Invoices covering dies, tools and fixtures, whether of a 

mechanical, electrical, electronic, or optical nature, do not convey any title or interest to the 

Buyer. Only part of such cost is ordinarily charged the Buyer, while the Seller assumes the 

remainder and provides engineering time and experience in their design. For these reasons, dies, 

tools and fixtures remain the property of the Seller and are not removable from the Seller’s 

factory.

11. MODIFICATIONS – No deletion, amendment or addition to the terms hereof shall be 

effected by the acceptance or acknowledgement of a purchase order or other forms unless 

expressly agreed to in writing signed by an authorized representative of the Seller. All orders are 

subject to acceptance or rejection at Seller’s factory, Pomona, California, and written 

acknowledgement will be made of all orders accepted.

12. APPLICABLE LAWS – This quotation and any contract resulting therefore shall be 

construed in accordance with the laws of the State of California.

13. AUTHORITY TO EXPORT – If this quotation results in a contract which is subject to 

issuance of an export license by the United States Government for export of the ordered items, 

then the Buyer shall provide Seller with relevant import certificate, or any other document 

necessary to secure such export license and/or to permit the import of such goods into the 

country of destination.

Buyer shall be responsible for all approvals and/or export licensing for products to be shipped 

outside the United States. It is the Buyer’s responsibility to provide complete end-user 

information.

14. REMANUFACTURED COMPONENTS – The product purchased hereunder may contain 

some components which have been remanufactured after previous field utilization. This is 

necessitated because of materials and component shortages, conservation of resources and to 

effect economies in the manufacturing process which are reflected in the price to the Buyer. If 

the remanufactured components are contained in the product purchased hereunder, they have 

been tested for quality, meet or exceed the Seller’s standards and are subject to all the warranties 

of the Seller.

G130306-1BP0 Page 5 of 18 March 7, 2013 

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this documents first or title page.
Applied Instrument Technologies, Inc.

 

 

Item #1: Model FXi-1C1A1AFSZ-2M, GC #1, with the following:

• 120 VAC, +/- 10%, 50/60 Hz Supply Voltage, 1100 VA cold start

• Thermal Conductivity Detector

• 4 Solid State Stream Switching Relays (1 stream select, 2 calibration select)

• Includes one solid-state system function alarm and one solid-state warning alarm.

• Instrument Air at 50 psi minimum and 2 to 3 ft3/min Required

FXi Process Gas Chromatograph consisting of an Analyzer oven, integrally mounted microprocessor GC 

controller and Front Panel operator interface, featuring the following:

A. MICROPROCESSOR-BASED GC CONTROLLER 

• Integrally mounted with oven

• Automatic program reload (with SAFE auto re-start)

• GC Auto re-start

• Gate or slope driven integration

• Auto calibration

• Auto analysis report

• On-line diagnostic tests

• Data alarms for printout on I/O device

B. FXi FRONT PANEL INTERFACE

• Front Panel Display with Complete Programming Functions from GC

• Enhanced View (Chart Recorder Type) Real-Time ChromatogramEV

• Standard Displays with One-Button Key Function Screens

• Data/Programming entry via front panel with 12.1” (diagonal) Color Touch Screen display

• Front Panel Display includes:

• Pentium® 1.4GHz fan-less computer with Windows® XP SP2 Embedded Operating System

• 800 x 600 Resolution 

• 1GB memory with dual 4GB compact Flash Drives 

• User Configurable and Optional Displays Available

• Dedicated menu-driven workstation with HELP displays

• One-on-one security

• Local programming (with dual micro processors)

C. OUTPUTS & COMMUNICATIONS 

• 2 RS-232, internal Serial Communication for Front Panel-GC Controller Communication

• 2 RS-232/422/485 with DB9 Connectors 

• 2 Ethernet TCP/IP 10/100Base-T RJ-45 ports for remote monitoring/communications

• 2 USB UHCI, 2.0 compliant Ports

• 2 or 4 wire RS-485 with MODBUS RTU Protocol

D. SAFETY

FM Certified for Class I, Groups B,C, & D, Division 2, Temperature T3 

G130306-1BP0 Page 6 of 18 March 7, 2013 

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this documents first or title page.
Applied Instrument Technologies, Inc.

 

 

Item #1 con’t: Application for FXi Gas Chromatograph, GC# 1

• Analyzer Oven with Air bath heating system

• Automatic high temperature cutoff switch (protects against overheating)

• Modular separation assembly containing valves, columns and flow controllers to permit quick 

removal for repair/replacement

• Application Engineering: includes the following:

• Sample inject – Vapor Inject

• Switching Valves 

• Packed Columns 

• Estimated Cycle Time ~20-25 minutes per stream

• Operating Instrument Air, dry and oil free, 3.4 to 5.1 m3/hr, minimum 50 psi, max 100 psi 

• Dual Carrier Gas Regulator System, includes the following:

• Hydrogen Carrier, chromatograph grade @ 99.995% pure, approx 40 cc/min, 60 psi max.

• Hydrogen Shutdown System into GC if Instrument Air Supply gas stopped

• Argon Carrier, chromatograph grade @ 99.995% pure, approx 40 cc/min, 60 psi max.

• Carrier Gas Low Pressure Alarm

• Automatic TCD Shutdown on loss of carrier flow

STREAM SPECIFICATIONS: 

Components Units Stream #1

Min/Norm/ Max

Measured Range 

of Stream

Estimated 

Repeatability % of 

Full Scale 

H2 Mol % 0 / 28.63/ 50% 0-50% +/-1%

C6+ Mol % 0 / 4.565 / 10% 0-10% +/-1%

CO2 Mol % 0 / 0.80 / 2% 0-2% +/-1%

C2=, Ethylene Mol % 0 / 0.702 / 5% 0-5% +/-1%

C2, Ethane Mol % 0 / 2.46 / 5% 0-5% +/-1%

C3, Propane Mol % 0 / 0.258 / 10% 0-10% +/-1%

C3=, Propylene Mol % 0 / 0.77 / 10% 0-10% +/-1%

iC4, iso-Butane Mol % 0 / 0.049 / 1% 0-1% +/-1%

nC4, n-Butane Mol % 0 / 0.072 / 1% 0-1% +/-1%

iC4=, Isobutylene Mol % 0 / 0.64 / 1% 0-1% +/-1%

trans-2-Butene Mol % 0 / 0.001 / 1% 0-1% +/-1%

C5+, Pentane+ Mol % 0 / 0.89 / 5% 0-5% +/-1%

cis-2-Butene Mol % 0 / 0.029 / 1% 0-1% +/-1%

1,3-Butadiene Mol % 0 / 0.093 / 1% 0-1% +/-2%

O2 Mol % 0 / 0.10 / 1% 0-1% +/-1%

N2, Nitrogen Mol % 0 / 4.832 / 50% 0-50% +/-1%

C1, Methane Mol % 0 / 59.13 / 20% 0-70% +/-1%

CO Mol % 0 / 0.073 / 1% 0-1% +/-1%

Benzene Mol % 0 / 1.198 / 5% As C6+

BTU BTU/scf 0-1000

Stream Conditions: Stream #1 

Physical State: Vapor 

Sample Pressure: Not indicated 

Sample Temperature: Not indicated 

Return Pressure: Not indicated 

 

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Typical BTU Report Available from GC & PC Workstation:

Attached below is typical complete BTU report available from Process Gas Chromatograph Workstation 

with RAMS BTU Software. A Summary report is optional that lists only the Calculated Heating Values, 

Wobbe Indexs, Densities, and Average Molecular Weight of the composite gas (Short form of data shown 

in bottom of this report).

NOTE: The software package for BTU calculations for as shown above is a standard package included in 

the FXi PGC. The heating value can be calculated for ISO Standard 6976, GPA Standard 2172 or ASTM 

Standard D-3588 methods.

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Item #2: SAMPLE CONDITIONING SYSTEM FOR GC#1:

1-Stream Flare Gas Sample System, which includes the following:

• Sample Filter Probe

• Stream Isolation Block Valves

• Liquid Separator/Knockout system

• Sample Cooler and Drain pumps

• Bypass Filter and Flow meter

• Liquid Drain, Condensate return pump

• Sample Pump

• Air Actuated Stream Select Valve

• Air Actuated Calibration Select Valve (2)

• Pressure Gauges

• Sample Flow meter 

• Guard Filter with Liquid Block 

• Sample Atmospheric Correction Block and Bleed on inject

• 316 Stainless Steel Components on Process wetted

• NEMA 4X Insulated Enclosure

NOTE: Stream conditions and Flare sampling have not been provided, and this proposed sample 

system is based on heavy solids, and high water content system. AIT cannot accept order until stream 

conditions are confirmed, reviewed, and pricing is subject to change based on further details.

Item #3: Start-up Commissioning Service at Plant Site:

Unit pricing for 2 days of travel and 3 days of service, as follows;

Travel time is billed at Zone 4 $ 3,325

 

Per Diem/Expenses/Other is Billed at $295 per day $ 1,475

 5 days (3 days commissioning and start-up)

Labor is billed at $265 per hour 

 3 days @ 8 hrs each $ 6,360 

 Total $11,160

 

Payment Prior to Dispatch for Service Work 

Parts and material are not included in this quotation and will be billed at AIT’s

Published USA Price List. 

G130306-1BP0 Page 9 of 18 March 7, 2013 

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ITEM #4: OPTIONAL: REMOTE RAMS WORKSTATION PACKAGE:

The Remote Software System (RAMS/PCAnywhere) is a PC-based Windows based software package 

that allows remote monitoring of data, configuration, operation, and control of the FXi Process Gas 

Chromatograph via a personal computer through TCP/IP port. This system provides view of Real-Time 

Chromatograms and saving last Chromatogram to file or overlay or printout. The software package is 

installed in a supplied Pentium Desktop computer, with printer. The communication package operates 

under Windows and can provide for remote data transfer and diagnostics.

Primary Features are:

• Display Analyzer Data

• Create Printed Reports for Analysis and Alarms

• Analyzer Maintenance Operation and Control

• Upload, Edit, Download and Save Analyzer GC Parameters

• Display Actual Real-time and Saved Chromatograms

• Save Chromatograms in a Windows Graphic Format

• Remotely Configure GC 

Desktop Computer with the following minimum requirements:

• Windows XP® Professional, SP2,x32, with Media English Operating System

• 3.00 GHz, 2X2M, 800 MHz 730TD FSB Pentium 925 microprocessor

• 2 GB DDR2 Non-ECC SDRAM

• PS2 Serial Port adapter

• Dell USB Keyboard

• 80 GB SATA Hard Drive

• 48X CDRW/CD COMBO and 48X CDROM

• PCI-e Network Adapter Card

• LCD Monitor

ITEM #5: OPTIONAL: REMOTE LAMS SOFTWARE (Unbundled):

The Remote FXi Software System (RAMS/PCAnywhere) is a PC-based software package (unbundled, 

and does not include PC) that allows remote monitoring of data, configuration, operation, and control of 

the FXi Process Gas Chromatograph via a personal computer through TCP/IP port. This system provides 

view of Real-Time Chromatograms and saving last Chromatogram to file or overlay or printout. The 

software package is installed in a Customer supplied Pentium Desktop computer. The communication 

package operates under Windows and can provide for remote data transfer and diagnostics.

Primary Features include:

• Remote configuration and operation of the PGC via a PC

• Analyses of PGC data via user-configured Windows

• Tree-structure Display of all PGC functions

• Real-time chromatograms for troubleshooting

• View and save last chromatogram to file for overlay or printout

• Status Displays indicating PGC activity

• Password protection (user defined)

• On-line Help Screens for both PGC and LAMS

 

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Item #6: OPTIONAL: FXi GC Tools and Commissioning Spares

 Tools and Commissioning Spares

Qty Part Number Description Unit Price Extended Price

1 PM Rotor Extractor $27 $27

2 ZBNV1 Restrictor Valve $381 $762

2 HT002VV Sample Rotor 10-port $321 $642

1 AT010SW TCD Filament Wrench $591 $591

1 AT006FH TCD Filament Set $393 $393

4 XP002JR TCD Filament Gaskets $6 $24

2 HT002VW Sample Rotor 6-port $321 $642

1 190011500 Portable Flow Meter $3852 $3849

$6,930.00

Item #7: OPTIONAL: Spare Parts for Two Years Operation:

Spare Parts for Two Years Operation

120V Chromatograph – TCD Det

Qty Part Number Description Unit Price Extended 

Price

1 AT016MU Regulator, Carrier Gas $1452 $1452

1 AT016GQ Regulator, Oven Air $306 $306

1 AT018QM Gauge, Pressure $488 $488

1 AS012DG Switch, Pressure $544 $544

2 XP003NB Solenoid Valve, 120VAC $327 $654

2 C3510KZ Power Supply Fuse $13 $26

1 EX-AS700GA PWA, Temperature Controller, 120VAC $5095 $5095

2 ZBNV1 Restrictor Valve $381 $762

1 HT002VY Sample Valve, 6-port $2507 $2507

2 HT002VW Sample Valve, Rotor 6-port $321 $642

1 HT002VX Sample Valve, 10-port $3256 $3256

4 HT002VV Sample Valve, Rotor, 10-port $321 $1284

1 AP011GD Heater cartridge assembly, 120VAC $3048 $3048

2 C35010KK Fuse, 250 V, 0.062 A $6 $12

2 AT006FH TCD Filament Set $393 $786

8 XP002JR TCD Filament Gaskets $6 $48

$20,910.00

G130306-1BP0 Page 11 of 18 March 7, 2013 

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Item #8: OPTIONAL: FAT INSPECTION:

Estimated 3 Days of Factory Inspection and Testing.

The functional testing is to demonstrate the proper operation of the system by using known samples to 

confirm calibration and function of the analyzer system and to confirm that all outputs are the proper 

value. 

a. Calibration: A known sample within the range of the analyzer will be used to confirm 

calibration of the analyzer. Review of repeatability run data. NOTE: Repeatability run will not be 

run at FAT, the repeatability run is performed before customer inspection.

b. The operation of all controls will be checked to confirm that each particular switch controls its 

correct device.

c. The measurement of electrical signals will be checked to confirm that analyzer outputs exist in 

their proper form; i.e., milliamp, millivolt, etc. All alarms will be checked to confirm that they 

trip.

d. Automatic operation of running analyzers with calibration sample or surrogate will be witnessed and 

the output signals monitored on local indication, recorder, and/or printer devices.

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ANALYTICAL SYSTEMS

STANDARD INSPECTION AND TESTING

I. INTRODUCTION

II. IN-COMING INSPECTION

III. IN-PROCESS INSPECTION

IV. QUALITY CONTROL INSPECTION

V. CONFIGURATION CHECK

VI. STATIC INSPECTION (GENERAL)

VII. STATIC INSPECTION (ELECTRICAL)

VIII. STATIC INSPECTION (CUSTOMER SUPPLIED EQUIPMENT)

IX. INSPECTION

X. FUNCTIONAL TEST

XI. RESALE ANALYZERS

XII. CUSTOMER ACCEPTANCE

XIII. CONDITIONS OF CUSTOMER WITNESS TESTS

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ANALYTICAL SYSTEMS STANDARD INSPECTION AND TESTING

I. INTRODUCTION:

a. This document describes the standard testing and inspection procedure implemented by AIT, Applied 

Instrument Technologies for analyzers and analyzer systems. It has been established to ensure the highest 

level of system quality and integrity.

b. It is the intent of this document to define certain procedures and list the standard tests for analyzers, 

analyzer equipment, and analyzer systems.

c. The analyzers, analyzer equipment, and the analyzer systems will be completely checked out, tested, 

and functionally checked in accordance with this document prior to any customer witness, testing, and 

inspection.

d. Only those tests listed as standard will be performed unless specified elsewhere in the AIT offering. 

Any special testing or testing designated as optional should be arranged for, at time of order placement.

II. INCOMING-INSPECTION

a. Non-AIT miscellaneous hardware, including vendor standard catalogue components, are inspected for 

part number, size, damage, quantity, etc., as defined by the AIT purchase order. The material is stocked 

for general use and the inspection copy of the AIT purchase order is kept on file.

b. Non-AIT resale equipment is inspected as in a. above. The material is stocked for use in the specific 

sales order and the inspection copy of the AIT purchase order is kept on file.

c. Customer supplied equipment is visually inspected for damage, quantity, and against other available 

information. The material is properly identified and stored for use on the specific sales order.

d. Fabricated assemblies, when purchased, are subject to acceptance by receiving inspection either when 

received or at the source. They are inspected for conformance to AIT purchase specifications and good 

workmanship practices.

e. AIT manufactured analyzers received are not subject to incoming inspection. Other than visual 

inspection for damage, they are accepted on certification from AIT's Analyzer Manufacturing Operations 

as completed analyzers ready for shipment.

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ANALYTICAL SYSTEMS STANDARD INSPECTION AND TESTING (cont.)

III. IN-PROCESS INSPECTION (IN-HOUSE AND VENDOR SHOPS)

Quality Control and/or Engineering will make in-process inspections during final assembly to insure 

quality standards are met.

IV. QUALITY CONTROL INSPECTION

Each analyzer, analyzer system, or subsystem is thoroughly inspected prior to release from the 

manufacturing area. Inspection is per sales order drawings for proper configuration and to insure that it 

meets all appropriate AIT workmanship standards.

V. CONFIGURATION CHECK

The Check-Out Specialist will check the completed analyzer, analyzer equipment, and analyzer system 

against the applicable documents to insure that the correct hardware and count exist in the assembly.

VI. STATIC INSPECTION (NO POWER OR AIR) GENERAL

The Check-Out Specialist checks the following for conformance to the engineering drawings:

1. Analyzer Tagging

2. Nameplates

3. Adherence to specification details

4. Accessibility of all equipment for maintenance or removal

VII. STATIC INSPECTION (NO POWER) ELECTRICAL

The Check-Out Specialist will check the following for conformance to the engineering drawings:

1. Wire size, color codes, fuse size

2. Identification and accessibility of all terminal board wiring for customer connection

3. Physical separation of high and low level circuitry and assurance that proper wiring practices have been 

followed

4. Proper electrical grounds for analyzers and other devices

5. Power supply voltages

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ANALYTICAL SYSTEMS STANDARD INSPECTION AND TESTING (cont.)

VIII. STATIC INSPECTION (NO POWER) CUSTOMER SUPPLIED EQUIPMENT

Check for physical damage, proper wiring, and signal polarity.

IX. INSPECTION

The following tests are to ensure that the system is assembled, piped, and wired according to the most 

recent approved drawings, and to leak test the system. 

a. Continuity Test: The QC Representative and the Project Engineer will initial and date the drawings 

confirming they are the latest revision and are correct for this test. 

b. A continuity test will be performed on all wiring to ensure circuit integrity to the point of origin and to 

the point of termination of each wire. 

c. As the test is being performed, the Check-Out Specialist will trace each end of the wire on the print 

with a yellow marker. This will indicate that the test is complete for that wire. 

d. Piping Test: The QC Representative and the Project Engineer will initial and date the drawing 

confirming that they are the latest revision and are correct for this test. 

e. The Check-Out Specialist will visually trace all piping and tube runs to confirm proper routing. 

f. The Check-Out Specialist will inspect all equipment to ensure proper installation and compliance with 

all codes, standards, and specifications.

g. Leak Test: The Check-Out Specialist will test all piping and sample flow paths with instrument air at 

30 psig, unless otherwise noted. Precaution will be taken to valve OFF or jump around any device that 

would be damaged. Then, 30 psig air will be trapped in the system and the supply air will be valved off. 

A pressure gauge will be observed for ten minutes. Any decrease in pressure will cause the test to fail. 

Any leaks will be located, repaired and the test will be run again. 

h. As the test is being performed, the Check-Out Specialist will trace the pipe or tube run with a yellow 

marker. This will indicate that the test is complete for that pipe, tube, or device.

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ANALYTICAL SYSTEMS STANDARD INSPECTION AND TESTING (cont.)

X. FUNCTIONAL TEST

The functional test is to demonstrate the proper operation of the system by using known samples to 

confirm calibration and function of the analyzer system and to confirm that all outputs are the proper 

value. 

a. Calibration: A known sample within the range of the analyzer will be used to confirm calibration of the 

analyzer.

b. The operation of all controls will be checked to confirm that each particular switch controls its correct 

device.

c. The measurement of electrical signals will be checked to confirm that analyzer outputs exist in their 

proper form; i.e., milliamp, millivolt, etc. All alarms will be checked to confirm that they trip.

d. Automatic operation of running analyzers with calibration sample or surrogate will be witnessed and 

the output signals monitored on local indication, recorder, and/or printer devices.

XI. RESALE ANALYZERS

a. AIT Supplied - Power circuit will be energized and the analyzer checked per this document.

b. Customer Supplied - No power or sample will be applied.

XII. CUSTOMER ACCEPTANCE

AIT warrants the analyzer system based on this inspection and our published Terms and Conditions of 

Sale. If additional testing or inspection is required, it may be done under the following options:

Option #1: - Visual Inspection (No Charge).

If prearranged at time of order placement, the analyzer, analyzer system, and analyzer equipment will be 

held for up to one week after AIT's standard check-out. During this time the system will be available for 

customer visual inspection. No power or sample will be applied. Duration of inspection will be limited 

to one day.

Option #2: - Inspection and Function Test $1650/day.

If prearranged at time of order placement, customer or his representative may witness a repeat of the 

standard test described in Sections V. through X. at a fee established per sales order.

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ANALYTICAL SYSTEMS STANDARD INSPECTION AND TESTING (cont.)

XII. CUSTOMER ACCEPTANCE (cont.)

Option #3: - Extra Charge

On more complex systems incorporating customer software, special sample system design, etc., the 

testing may require the participation of the Project Engineer or other AIT personnel. Description of this 

special testing and fee are established per sales order.

XIII. CONDITIONS OF CUSTOMER WITNESS TESTS

1. All customer inspection and customer witness testing must be prearranged at the time of order 

placement. The number of customer personnel should be kept to a minimum to facilitate testing and so 

as not to interfere with other on-going checkout activities in the checkout area. Customer witness testing 

will be performed between the hours of 8:30 a.m. and 3:30 p.m. Customers and/or their representatives 

must be accompanied at all times by a designated AIT employee.

2. Upon completion of above inspection and testing activities, the customer will be requested to provide a 

written Acceptance for Shipment of the analyzer system. The Acceptance for Shipment does not waive 

AIT's responsibility and warranty as specified within the purchase order for the analyzer system.

1. NOTES:

1. This proposal contains confidential and proprietary information of Applied Instrument Technologies (the 

“Company”) and is not to be disclosed to any third parties without the express prior written consent of the 

Company. This proposal is submitted solely for the purpose of enabling client to evaluate the Company’s bid 

on this project and shall be returned to the Company or destroyed if so requested by the Company.

2. AIT – Applied Instrument Technologies- standard terms and conditions apply.

3. Any changes in configuration, after receipt of order, either at the request of the client or agreed upon by the 

client and the Company may delay the committed shipment date and/or result in a price increase.

4. Demo systems are subject to availability.

G130306-1BP0 Page 18 of 18 March 7, 2013 

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this documents first or title page.
Quote Summary Information Sheet

Vendor Name: SIEMENS

Date of Quotation: 3/18/2013

Cost Component List Price

Gas Chromatograph $40,000 - $60,000

Sample Conditioning System $30,000 - $35,000

Packaging/Handling NA

Total Equipment Cost $70,000 - $95,000

Startup & Commissioning Support NA

Options

Remote Analyzer Workstation NA

Analyzer Software NA

Tools and Commissioning Spares NA

Spares for 2 years of Operation NA

Factory Acceptance Test Inspection NA

Total with All Options $ -

Notes: 

Quote obtained via telephone with SIEMENS representatives. SIEMENS 

indicated they supplied turnkey solutions, but ERG was unable to obtain 

quotation for startup/commissioning or available options. 

NA - information was not obtained from vendor
Quote Summary Information Sheet

Vendor Name: Wasson-ECE

Date of Quotation: 3/12/2013

Cost Component List Price

Gas Chromatograph NA

Sample Conditioning System NA

Packaging/Handling NA

Total Equipment Cost $ 150,000.00

Startup & Commissioning Support NA

Options

Remote Analyzer Workstation Included in total equipment cost

Analyzer Software Included in total equipment cost

Annual Maintenance Costs $ 2,000.00

Annual Gas Costs $ 2,550.83

Gas

Consumpt

ion (25C, 

1atm) 

ml/min

Cubic Feet 

per year

Unit Size* 

(CF) Units/yr Unit Price* Total Cost

Helium 35 622.9513 292 2.133395 $ 110.12 $ 234.93

Nitrogen 30 533.9583 304 1.756442 $ 65.93 $ 115.80

Hydrogen 30 533.9583 261 2.045817 $ 67.44 $ 137.97

Air 400 7119.444 312 22.81873 $ 90.37 $ 2,062.13

Total Cost $ 2,550.83

*Provided by Airgas (quote provided by Airgas of Morrisville on 3/18/2013)

Notes: 

$150,000 includes

Process Cabinet for GC, Glass 1, Div 2

Sampling System for 4 streams

Agilent Technologies GC

Custom hardware and method development

Computer and Agilent data collection software

Wasson-ECE software for 24/7 operation

MODBUS communications

1 year warranty

Vendor provided gas consumption information below
FW: GC Cost Information Quote 65837 

From: <Dallas.Wiard@Emerson.com> 

To: <Philip.Crawford@erg.com> 

CC: <Curt.Reiber@emerson.com> 

Date: Friday - March 15, 2013 1:34 PM 

Subject: FW: GC Cost Information Quote 65837 

Attachments: Mime.822 

Mr. Crawford,

Price range from $80K to $200K. 

Regards, and Thank You for your interest in Rosemount Analytical products.

Dallas Wiard | Application Support Specialist |Rosemount Analytical | Emerson 

Process Management | 10241 W Little York Rd @ US Hwy 290 | Houston | TX | 77040 T + 

1 713 396 8869 | F + 1 713 466 8175 Dallas.Wiard@Emerson.com | 

www.EmersonProcess.com

From: Philip Crawford [mailto:Philip.Crawford@erg.com] 

Sent: Tuesday, March 12, 2013 2:26 PM

To: Wiard, Dallas [PROCESS/RMT/HSTN]

Subject: RE: GC Cost Information Quote 65837

Mr. Wiard,

Thank you very much for your assistance. Temperatures will likely range from 55 - 

110F. Pressures will generally be about 1 psig to 2 psig. 

Thanks,

Philip

Philip Crawford

Chemical Engineer

ERG

2909 Fox Glove Dr

Winterville, NC 28590

252-364-8136

Philip.Crawford@erg.com

>>> 03/12/13 10:23 AM >>>

Mr. Crawford,

We will provide a quote for this application. Can you provide pressure temperature 

this request.

Thanks,

Dallas Wiard | Application Support Specialist |Rosemount Analytical | Emerson 

Process Management | 10241 W Little York Rd @ US Hwy 290 | Houston | TX | 77040 T + 

1 713 396 8869 | F + 1 713 466 8175 Dallas.Wiard@Emerson.com | 

www.EmersonProcess.com

From: Philip Crawford [mailto:Philip.Crawford@erg.com] 

Sent: Monday, March 11, 2013 4:20 PM

To: Martin, John [PROCESS/RA/HSTN]

Cc: Wiard, Dallas [PROCESS/RMT/HSTN]

Subject: GC Cost Information

Mr. John Martin,

Page 1
My name is Philip Crawford. I am with Eastern Research Group; we are an 

environmental consulting firm. I contacted Rosemount/Emerson using the online 

contact information as was provided the screening form (attached) and the ADS Form 

for GC along with your email address. 

I have a client with U.S. EPA who is interested in general cost information for an 

online/continuous GC system for measuring the composition of refinery vent gas 

en-route to a flare. My Client doesn't have any specific requirements (such as 

communication ports/power supply available/etc) other than a hazardous environment 

(class 1 div 1). The client has, however, provided a typical compositional analysis 

which I've attached to this email. The client is interested in a typical cost range,

such as a minimum to maximum of these types of analyzers. Is this something you 

might be able to provide, based on the information supplied?

I very much appreciate your time and assistance.

Thank you,

Philip Crawford

Philip Crawford

Chemical Engineer

ERG

2909 Fox Glove Dr

Winterville, NC 28590

252-364-8136

Philip.Crawford@erg.com

Page 2

Attachment 4

Steam Savings Data for Marathon Refineries
Marathon Flare Meeting with EPA 
AGENDA

1. Flare Design Considerations (Jim Franklin)2. PFTIR Test Results (Scott Evans) PFTIR Test Results (Scott Evans)3. LFL Methodology (Scott Evans)4. Total En ironmental Impact (R th Cade) Total Environmental Impact (Ruth Cade)5. Engineered Solution (Ruth Cade)6. Flow Caps (Jim Wilkins)
Implementation of Flare Instrumentation

 MPC has implemented the flow instrumentation and GC on the f

in 2010 and early 2011 for several flares:

 4 Flares in Detroit Refinery 1 Flare System in Robinson Refinery, which is a 3-flare staged system 2 Flares in Texas City Refinery (partially in place for HRVOC rule) 2 Flares in Texas City Refinery (partially in place for HRVOC rule)

 Results have yielded some useful insights into MPC’s flare heade

 Si

gy g p nificantl

y lower VOC content in flare vent 

gas than ex

pected

 In many places, lower vent gas flow rates and consequently lower wa

rates than expected

 A primary source of vent gas sources are have been initially identified 

A primary source of vent gas sources are have been initially identified 

leaking process safety relief valves and closed block valves.
Configuration of Systems with On-Line Instrum

MPC Flare with Operating Instrumentation

Min Steam Rate (lb/hr)

Avg VOC in Vent Gas(vol %)

Diam(inch

Detroit1 West Plant Flare 400 6.8 2 Unifiner Unifiner Flare 325 4 5. 3 Alkylation Flare 450 36 4 Crude 375 5.1 Robinson5,6,7 #1 (with 5/6 Staged) 

Fl

1465 13 

are

Texas City8 Main Flare 1250 4.5 

9 Alkylation Flare 1400 18.2 
Vent Gas Compositions

MPC Flare GC Data

4 5

MPC Flare GC Data

H2, N2, & Inerts Methane & Ethane VOC

40 1

10.6

20.3

6.6 4.5

42

8.0 13.4 6.0

20.3

40.1

88 3

68.7 41.2

53.3

86.5

66.7

55

88.3

4 3.9

24.9

37.8

Det West Plant 

Flare

Det Unifiner 

Flare

Det Alkylation 

Flare

Det Crude 

Flare

Rob #1-#5-#6 

Flares

TXC Main Flare TXC Alkyla

Flare
Detroit Flare Flow Make-Up

Marathon Petroleum Company LP

1,173,729 1,200,000

1,400,000

Marathon Petroleum Company, LP

Significant differences be

flow and hydrocarbo

1,000,000

FD)

600,000800,000

w Rate (SC

341,534 400,000

Flo

116,422

79

124,837 145,342

37,722 

0

200,000

Det West Plant Flare Det Unifiner Flare Det Alkylation Flare DeDet West Plant Flare Det Unifiner Flare Det Alkylation Flare De

Total Vent Gas Waste Gas (Hydrocarbon)
Robinson & Texas City Flare Flow Make-Up

Marathon Petroleum Company, LP

3,233,561

3,000,0003,500,0002,500,0001,500,0002,000,000

Flow Rate (SCFD)

1,222,731

733,473

1,000,000

75,025 

0

500,000

Rob #1-#5-#6 Flares TXC Main Flare 

Total Vent Gas Waste Gas (Hydrocarbon Only)
Lessons Learned

 Most flares will be able to comply with steam minimization strate

 Redesign steam systems to deliver “just right” amounts of steam Fine tune control syp p stems to operate at Incipient Smoke Point Possibility for increased reports of visible emissions as interpreted to

 Some flares may require large amounts of supplemental fuel

 Larger diameter flares that require more minimum steam for mechan Dependent upon the VOC content in the waste gas

– Heavier VOCs provide more VG NHV than natural gas

 In conjunction with future waste gas (or flare gas) minimization p

flares may be faced with trading a molecule of VOC for a molecugas.

 When drawing the line for the operating limit, the total environm

in terms of trading VOC reduction for GHG, CO, and NOx increase

taken into consideration.

Combined with 

MPC Base Test Runs
Impact of Safety Factor Choice on Criteria and GHG Flare Emissions

(4) Detroit (2) Texas City and (3) Robinson Flares

400.0450.0

(4) Detroit, (2) Texas City, and (3) Robinson Flares

Marathon Petroleum Company, LP

CO2_eq

300.0350.0

PY)

200.0250.0

Emissions (T

100.0150.0

VOC 

0.0

50.0

A = 6 (300 BTU/scf)

A = 6.5 (325 BTU/scf)

A = 7 (350 BTU/scf)

A = 7.5 (375 BTU/s

A 6 (300 BTU/scf)

A 6.5 (325 BTU/scf)

A 7 (350 BTU/scf)

A 7.5 (375 BTU/s

VOC NOx CO2_eq

Using M
Project Scope

 Marathon operates 20 flares across 6 refineries  Project Scope includes for each flare:

 Dual channel ultrasonic flow meters with molecular weight analyzer 

Dual channel ultrasonic flow meters with molecular weight analyzer 

 Siemens Maxim II Gas Chromatograph on vent gas Ultrasonic flow meter for total steam measurement Redesign steam delivery system to include a smaller steam control va Replace minimum steam restriction orifices which may have been ov Globe valve on center steam for better tuning Ability to add supplemental natural gas 

 To date, this system has been installed on a total of 9 Flares

 4 – Detroit Michigan Detroit, Michigan 3 – Staged Flares at Robinson, Il 2 – Texas City, Texas
Typical Flare Control Schematic

Steam Supply Header

Process 

Minimum Steam RO

Smaller Trim Cv Flow (scfh or lb/hr)

Pressure (psig)

Temperature (deg F)

Ultrasonic Steam Flow 

Meter

Upper Steam

Larger Staged Cv

Temperature (deg F)

Minimum Steam RO

Center Steam

`

Fl K k O tD

Ultrasonic Vent Gas Flow VG Meter

Globe Valve

Supplemental Natural Gas

Flare Knock-Out Dru

m

Flow (scfh or lb/hr)

MW (Lb/lbmol)

Pressure (psig)

Temperature (deg F)

GC

NHVvg (BTU/scf)

N2, H2

O2, CO, O2

Methane

Ethane

VOC C2 C5'VOCs C2 - C5's 

saturates & olefins
Ultrasonic Flow Meter Lessons Learned

 D l h l ifi d f l & f l

Dual c

hannel specifi

e

d

for low 

&

f

ul

measurement.

 Special handling of nitrogen necess

detected by instrument GC feedbadetected by instrument. GC feedba

installed for adjusted MW & flow

 Desire independent flow outputs fo

transducers

– factory will average b

factory will average b

specified.

Dual Channel – 4 Ports on Bias 90 & 45

Hot Tap machine installing connec
New GC Shelter Buildings

 Desired added advanta

detection by real-time 

– High olefins (FCCU); sa

pl t HF Alk ) h d 

lan

t or HF Alk

y); h

y

d

 10 – 12 minute cycle ti $660 000 average tota

$660,000 average tota
Supplemental 

Addition
2 Percent

Steam Demand to Flare

FC 51.30

SPLIT RANGE

CALCULATED VALUES

150#

Steam

Ultrasonic Flow Meter -1 %

PPH

129

736

10769

Molecular Wt (Flowmeter)VG Volumetric Flow SCFHNHV (VG) Btu/SCF

23.22

12942 SCFH

359

196

PSIGF

RATIO

NHV (FCZ) Btu/SCFMolecular Wt (GC calc) 20.38

I/O Timeout

296

2.61

9963

NHV (VG) - Adj H2 Btu/SCF 900NHV (FCZ) - Adj H2 Btu/SCF 365

331 PPH Cen

10769

Actual to API 521 Ratio (S/S521)VG Volumetric Flow SCFHAPI 521 Steam Rate (S521) PPHAPI 521 to VG RatioFlare Exit Gas Velocity FPS -2 %Actual to VG Ratio 1.13

HRVOC (daily average)

HRVOC (30 d )

257

0.43

2.61

2.07

257 PPH

9963

-2 %

0.85

Fla

HRVOC (30 day average)

VG Vol Flow (HC only) MSCFD

VG (HC only - NG/SG) MSCFDMomentum Flux Ratio

168.89

78.080.253

S521

MI

257 PPH

RESET

FC

BTU - V

>

2.96

588 SCFH

Ultrasonic Flow Meter

Natural Gas

25-V-1

190 SCFH

BTU - FCZ

-0 %

16 %

Secondary KO POT

25-V-2

101 F

-0.03 PSIG

Complex 4 Relief

PrimaryKO Pot

20 %

25-P-1 A B/ 25-P-2 A B/
GC Output

 GC Output

GC Output Information

18.40

2.50

Nitrogen 21.04

HC Concentration Range

Mol %

OxygenHydrogen

Componnent

0.110.220.66

48.17

Carbon Dioxide

3.07

Carbon MonoxideEthyleneEthaneMethane

0.090.083.000.77

n-Butane 0.94i-ButanePropylenePropaneAcetylene

0.200.240.200.082.33

1,3-Butadienei-Pentane+i-Butene, Butene-1trans-Butene-2cis-Butene-2
Control Set Up 

 Goal is to set up the control scheme to maintain:

 NHVcz > 300 BTU/scf on a 3-HR rolling Average & S/VG < 3 scf/scf on a 1-HR rolling average.

 In Practice, using automatic steam control system on flow contro

 Set Point determined via trial and error to be indicative of Incipient S

but generally between 0.8 – 1.5 scf steam per scf vent gas

 As vent gas increases or decreases, steam flow rate follows in the sam

 Moves made by control system minute by minute

 Monitoring NHVcz at each update of the GC (10 – 12 minute inte

 Add natural gas when approaching 300 BTU/scf NHV Moves made by control system minute by minute based upon the las
For a flare operator, which has visible emission

13
Cultural Lessons

 Years of being taught to operate with no visible emissions have y

operation with no visible flame

 We’re finding that the cultural change of operating near or at the 

smoke point is like stopping an adiction.

 Advanced training is being developed to include modules on

 What does incipient smoke point mean, Why black soot within the flame itself is not visible emissions Why black soot within the flame itself is not visible emissions,

 Why invisible flares are bad

 Recommend that the no visible emissions standard be clarified w

future rulemaking. 
Ruth A. Cade, PE

Marathon Petroleum Company LP Marathon Petroleum Company, LP

RACade@marathonpetroleum.com

606-921-2422 ( ) office)

MPC Refining Division - Steam Usage at Process Flares

Steam Usage (1) Annual Cost (2) Steam Usage (1) Annual Cost (2) Steam Usage (1) Annual Cost (2) Steam Usage (1) Annual Cost (2) Steam Usage (1) Annual Cost (2)

lb/hr $/yr lb/hr $/yr lb/hr $/yr lb/hr $/yr lb/hr $/yr

North Flare Data Not Available Data not Available 3,258 148,412 3,024 137,740 4,623 210,568 2,069 94,248

South Flare 2,503 114,020 4,279 194,930 3,377 153,823 2,060 93,841 3,487 158,822

Plant Wide 2,503 114,020 7,537 343,342 6,401 291,563 6,683 304,409 5,556 253,069

Lube Flare 18,462 840,971 12,349 562,527 12,982 591,374 11,989 546,133 9,087 413,929

NNA Flare 7,392 336,715 6,575 299,522 2,555 116,390 1,856 84,530 4,840 220,483

FCC Flare 1,874 85,383 1,885 85,853 1,694 77,165 1,512 68,871 1,618 73,703

Alky Flare 3,962 180,476 3,953 180,058 3,953 180,086 3,953 180,058 4,061 184,967

Plant Wide 31,690 1,443,544 24,762 1,127,959 21,185 965,014 19,310 879,592 19,606 893,083

Alkylation Flare 3,220 146,674 4,861 221,415 1,964 89,474 1,059 48,236 724 32,969

Unifiner Flare 4,429 201,734 3,811 173,618 1,252 57,053 646 29,405 2,850 129,836

CP (West Plant) Flare 2,522 114,883 2,009 91,517 874 39,829 543 24,724 950 43,264

Crude Flare 1,311 59,716 1,021 46,523 804 36,645 766 34,871 385 17,547

Plant Wide 11,482 523,008 11,703 533,072 4,896 223,000 3,013 137,236 4,909 223,616

North Flare 26,381 1,201,702 16,821 766,223 9,263 421,953 4,620 210,441 2,835 129,161

South Flare 1,777 80,967 2,694 122,737 1,675 76,319 1,410 64,250 2,516 114,590

Plant Wide 28,158 1,282,670 19,515 888,960 10,939 498,272 6,030 274,691 5,351 243,750

#1 Flare 6,340 288,779 6,339 288,767 1,465 66,734 1,465 66,734 2,330 106,137

#2 Flare 2,235 101,818 2,235 101,818 4,988 227,194 4,763 216,950 2,580 117,502

#3 Flare 9,899 450,926 8,024 365,504 4,850 220,936 3,622 164,971 5,240 238,702

#4 Flare 7,979 363,454 7,914 360,495 7,208 328,343 3,788 172,534 1,251 56,966

#5 Flare 1,400 63,774 1,400 63,779 1,454 66,222 1,505 68,573 1,152 52,465

#6 Flare 12,425 565,976 18,972 864,217 8,593 391,438 6,052 275,667 5,411 246,469

Plant-Wide 40,278 1,834,726 44,885 2,044,579 28,558 1,300,868 21,194 965,428 17,963 818,242

Main Plant Flare Data Not Available Data not Available Data Not Available Data not Available 4,353 198,275 3,154 143,682 3,368 153,401

Alky Flare Data Not Available Data not Available Data Not Available Data not Available Data not Available 2,007 91,433 2,768 126,082

Plant Wide 4,353 198,275 5,161 235,115 6,135 279,483

MPC Refinery-Wide 114,111 5,197,968 108,402 4,937,913 76,330 3,476,992 61,391 2,796,471 59,520 2,711,243

2. Annual steam costs based upon boilers being 88% efficient, a natural gas cost of $4.50 per million BTU (LHV), and 2% blowdown rate for boiler

1. Includes minimum cooling steam to protect integrity of the flare tip

2007 Operating Year 2008 Operating Year 2009 Operating Year

MPC Flare

2010 Operating Year 2011 Operating Year 

(Through 12/8/11)

Catlettsburg Refinery

Robinson Refinery

Garyville Refinery

Canton Refinery

Detroit Refinery

Texas City Refinery

JRW/jrw

MPC_Steam_Savings 01-12-12.xlsx

7/10/2013
Attachment 5

Flare Operation and Management Best Practices

Presented at Texas Chemical Council and Association of Chemical Industry of Texas 

Environmental Health and Safety Seminar. Galveston, Texas. June 4-7, 2012.
Flare Operation and Management

Best Practices

John Bigham

Technical Services Supervisor

Texas City, Texas
Discussion Topics

• Project Scope

• Operating window

• Cultural impacts to refinery operations
Background

• MPC has been working on Flare issue with EPA/DOJ since early 2008 

after Region 5 inspections at St. Paul Park and Robinson refineries.

• First Refining company to field performance test an operating flare.

• Significant Investment that applies to all 21 MPC flares

– $52 MM project cost for instruments and controls

– $0.9 MM for flare performance testing at Texas City & Detroit

– $52.9 MM

• Benefits

– VOC Reductions of ~4700 tpy system-wide

– 48% reduction in steam usage system-wide (to date) by operating at minimum 

steam

– Project significant value in recoverable product or raw material loss to flare.

– Use of real Combustion Efficiency Curve for projected VOC emissions from flares, 

truing up emissions inventory projections with actuals.

3
Strive for Balance

Smoke Formation

Too little steam

Good Combustion Efficiency

Transparent Flame

Too much steam

Bad Combustion Efficiency
Typical Flare Control Schematic

Process Unit Process Unit

Process Unit

Flare Knock-Out Drum Ultrasonic Vent Gas Flow Meter

Flow (scfh or lb/hr) MW (Lb/lbmol) Pressure (psig) Temperature (deg F) GC NHVvg (BTU/scf) N2, H2 O2, CO, O2 Methane Ethane VOCs C2 - C5's saturates & olefins

VG

Steam Supply Header

Minimum Steam RO

Smaller Trim Cv Larger Staged Cv Flow (scfh or lb/hr) Pressure (psig) Temperature (deg F)

Ultrasonic Steam Flow Meter

Globe Valve Minimum Steam RO Center Steam

` Upper Steam

Supplemental Natural Gas
Project Scope

• MPC operates 21 flares across 6 refineries 

• Project Scope includes for each flare:

– Dual channel ultrasonic flow meters with molecular weight 

analyzer on vent gas

– Siemens Maxim II Gas Chromatograph on vent gas

– Ultrasonic flow meter for total steam measurement

– Redesign steam delivery system to include a smaller steam 

control valve

– Replace minimum steam restriction orifices which may have 

been oversized

– Globe valve on center steam for better tuning

– Ability to add supplemental natural gas 
Ultrasonic Flow Meter Lessons Learned

• Dual channel specified for low & full flow measurement.

• Special handling of nitrogen necessary – N2 is not detected by 

instrument. GC feedback loop installed for adjusted MW & flow

• Significant troubleshooting upon installation – contracted with a 

common GE technician across all 6 plants to work out bugs.

Dual Channel – 4 Ports on Bias 90 & 45 Hot Tap machine installing connections on live line
New GC Shelter Buildings

• Desired added 

advantage of source 

detection by realtime speciation

• 10 – 12 minute cycle 

time

Nitrogen

Carbon Dioxide

Mol %

1,3-Butadiene

Pentanes +

n-Butane

i-Butene, 1-Butene

trans-2-Butene

cis-2-Butene

i-Butane

Propylene

Propane

Acetylene

Carbon Monoxide

Ethylene

Ethane

Methane

Oxygen

Hydrogen

Component

Total VOC

Flare Gas GC Results

Hydrogen Sulfide

Total GC Recovery

20.67

0.18

32.67

26.28

0.04

0.34

5.77

2.66

0.00

No Data

5.25

0.61

3.02

0.79

0.31

0.19

0.13

0.00

1.06

103.25

724

14.04

Total Olefins Scan Off

Calorific Value
Supplemental 

Gas Addition
Gas Chromatograph vs BTU Analyzer

• GC was chosen to assist in troubleshooting flare sources

• Provides additional insight into flare composition

– Identified leakage around emergency dump valves on a hydrogen net gas 

compressor.

– Identified leaking safety relief valves on a crude tower.

– Identified over-sized restriction orifices on a nitrogen line

• Measures:

– Inerts - Hydrogen, Nitrogen, CO2, O2

– Saturates – Methane, Ethane, Propane, Butanes

– Olefins – Ethylene, Propylene, Butenes, 1,3 Butadiene, Acetylene

• Installed on 5-plants to date – Typical Composition

– 10% VOC, 25% Methane & Ethane, 65% Hydrogen, Nitrogen & Inerts
Control Set Up 

• Goal is to set up the control scheme to maintain:

– NHVcz > ~300* BTU/scf on a 3-HR rolling Average &

– S/VG < 2.7 scf/scf on a 1-HR rolling average.

• In Practice, using automatic steam control system on flow control

– Set Point determined via trial and error to be indicative of Incipient Smoke 

Point, but generally between 0.8 – 1.5 scf steam per scf vent gas

– As vent gas increases or decreases, steam flow rate follows in the same 

ratio.

– Moves made by control system minute by minute

* Note: Using dynamic minimum target of a Safety Factor * Lower Flammability Limit of 

the Vent Gas. This equates to about 300 BTU/scf, but can fluctuate based upon vent 

gas composition.
Control Set Up 

• Monitoring NHVcz at each update of the GC (10 – 12 minute 

intervals)

– Add natural gas when approaching 300 BTU/scf NHVcz (or the minimum 

Lower Flammability Limit (LFL) floor of the vent gas)

– Moves made by control system minute by minute based upon the last GC 

reading
13

Flare Monitoring & Control System

Flare OV

Refinery OV

Liquid to Rerun

355TK & 358TK

-0.04

0.725 PSIG

RO:FI120B

RO:FI120A

0.000 MMSCFD

RO:AI120

Supplemental

Fuel Gas

Flare Gas

From FCC

2-117-F-1

2-117-G-1, 2

FCC AREA FLARE TIME 2/9/2012 11:09:00 AM

100

Flare Intensity

Nitrogen

Carbon Dioxide

Mol %

1,3-Butadiene

Pentanes +

n-Butane

i-Butene, 1-Butene

trans-2-Butene

cis-2-Butene

i-Butane

Propylene

Propane

Acetylene

Carbon Monoxide

Ethylene

Ethane

Methane

Oxygen

Hydrogen

Component

Calorific Value, BTU/SCFH

Flare Gas GC Results

0.21

MMSCFD

RO:FC124

40

Hydrogen Sulfide

Total GC Recovery

>

Flux

Ratio

RO:AC57H RO:AC57CZ RO:CF120M

1095 362 3.1719

10.53

0.16

13.98

36.80

0.35

0.52

13.60

17.80

0.00

No Data

0.82

2.99

1.18

0.20

0.45

0.20

0.12

0.00

0.35

123

Momentum

FV116B

FV116A

2.789 MLb/Hr

FV116C

0

Ring

Center

Steam / Flare Gas

Ratio

RO:CF120R

2.0

450#

STEAM

4 "

3 "

1 "

2 "

Current Waste Gas:

30 Day Average Limit:

382025 SCFD RO:CF120W x 1E6

250000 SCFD

Environmental Calculations

2.0

No Data

0

1095

362

1

2.2

0

0

1090

301

1

DegF

4 3

2 2

Molecular Weight

463

PSIG

DegF

462

%

997

FV116D

FV124

RO:TI120B

RO:PI120B

RO:FC113

%

2-11-FS-4

MMSCFD

0%

0%

0%

Heating Value

BTU/SCF

Zone HV

BTU/SCF

Vent Gas Combustion

1.708

1.479

MLb/Hr

Low range

High range

H2S, ppm

Parameter Current

Comb Zone HV, BTU/SCF

Vent Gas HV, BTU/SCF

Steam:Flare Gas Ratio

Value

Average

Value

Time

Basis Limit

Exit Velocity, Ft/Sec

SO2, Lb/Day

1 hr block

3 hr rolling

24 hr block

3 hr rolling

3 hr rolling

1 hr rolling

> 300

>

< 2.0

< 60 *

<162

< 500

* exit velocity limit <60 if BTU/SCF <1000; <400 if BTU/SCF >1000

Momentum Flux Ratio 3.1719 1 hr rolling > 0.0030

S P

310

ro

3.1719

2.0

Total VOCs 24.1
Operating Trends

• Automatic Steam Control – steam addition tracks vent gas flow rate

Total Steam to West Plant Flare Mass Flow Vent Gas to West Plant Flare Volume Flow Vol Steam/Vol Vent Gas to West Plant Flare CS

25FI0058A

LBS/HR

25FI0056C

SCFH

25MC0058C.MD

Ad-Hoc Trend

6/1/2011 12:00:00 AM 6.00 days 6/7/2011 12:00:00 AM

1000

2000

3000

4000

5000

6000

0

7000

0

4.E+05

0

2

Auto

9919.7

671.97

Steam Control in Auto

Steam Flow

Vent Gas Flow
Control System in Practice... changing 

with time

Total Vol Steam to West Plant Flare Vent Gas to West Plant Flare Volume Flow Natural Gas Injection to West Plant Flare 

25FC0058

SCFH

25FI0056C

SCFH

25FC0055

SCFH

Ad-Hoc Trend

6/8/2011 8:12:00 AM 6.00 minutes 6/8/2011 8:18:00 AM

20000

40000

60000

80000

1.E+05

0

1.2E+05

10000

90000

0

16000

3 Hour Rolling Avg NHV Cor to H2 Flare Combustion Zone

BTU/SCF

Ad-Hoc Trend

6/8/2011 8:12:00 AM 6.00 minutes 6/8/2011 8:18:00 AM

333.5

334

334.5

335

335.5

336

336.5

337

333

337.5

VG Flow Increases

Steam Increases

Natural Gas 

Maintained NHVcz above target
For a flare operator, which has visible emissions?

1 2

3 4
Cultural Lessons

• Years of being taught to operate with no visible emissions 

have yielded operation with no visible flame

• We’re finding that the cultural change of operating near or at 

the incipient smoke point is like stopping an addiction.

• Advanced training is being developed to include modules on

– What does incipient smoke point mean,

– Why black soot within the flame itself is not visible emissions,

– Why invisible flares are bad.
Emissions Inventory

• Common practice was to use 98+% combustion efficiency when 

estimating VOC emissions regardless of steam rate.

• Once flow indicators came on-line, we were able to estimate 

NHVcv for historical time periods, and correlate that to CE from 

MPC’s Flare testing.

• Wasn’t uncommon to see historical NHVcz estimates between 

125 – 250 BTU/scf or 65 – 96% CE for some flares.

• VOC Emissions = 11 times higher than originally estimated
Source: “Performance Test of a Steam-Assisted Elevated Flare with PFTIR - Detroit. November 23, 2010. MPC and CAE
Conclusion

• Controlling steam to the flare has both 

environmental and economic benefit.

• Understanding what is in our flare headers will 

make us better operators.

• Cultural changes at the refinery and 

community level continue to be needed to 

understand that invisible flares are worse than 

visible emissions.
Ruth A. Cade, PE

Marathon Petroleum Company, LP

RACade@marathonpetroleum.com

606-921-2422 (office)