Date: March 28, 2013 

To: Andrew Bouchard and Brenda Shine, EPA/OAQPS/SPPD 

From: Jeff Coburn 

Subject: Meeting Minutes for Meetings Between the U.S. EPA and Petroleum Refinery 

Industry Representatives regarding Potential Flare Performance Standards: 

December 8, 2011; March 21, 2012; October 11, 2012; February 19, 2013; and 

March 19, 2013 

Representatives of the U.S. Environmental Protection Agency (EPA) and their 

contractors (Eastern Research Group and RTI International) participated in a series of meetings 

with representatives of American Petroleum Institute (API) and other industry representatives. 

The purpose of these meetings was to discuss issues identified with the performance of some 

petroleum refinery flares and potential new monitoring standards to improve flare performance. 

Attachment 1 to this memorandum includes a list of attendees during these meetings. 

Discussion Topics – December 8, 2011 

In this meeting, industry representatives presented their data collection efforts for flare 

flow, composition, and steam usage rates and summarized their preliminary analysis of the data. 

Attachment 2 to this memorandum is the flare operations and control survey report 

documenting the data used and analyses performed to assess cost-effectiveness of potential 

compliance options that was provided just prior to the meeting. Attachment 3 to this 

memorandum is a copy of the presentation made during this meeting. Key points made by the 

industry representatives were that cost effective emission reductions were mostly identified for 

flares that can reduce steam usage rates to comply with the operating limit and that flares with 

minimal routine flare gas flow were generally not cost effective to control. 

Discussion Topics – March 3, 2012 

This meeting covered a broad range of issues concerning the Refinery MACT 1 and 2 

rules as well as proposed uniform standards. Only the discussion points related to flare 

combustion efficiency requirements are summarized in this memorandum. The EPA 

representatives indicated that they were starting the process of conducting a peer review of the 

flare combustion efficiency report summarizing the findings of recent efficiency tests conducted 

on flares. Industry representatives indicated that the peer review panel should include people 

from industry that have actual experience operating a flare and not be limited to academia or 

flare manufacturers. The industry representatives noted that, as more refineries implement flare 

gas recovery, the emissions from flares will decrease. They also indicated that significant 

emission reductions can be achieved by operator training. Current operators have been trained 
2

only to prevent the flares from smoking, Training the operators to minimize excess steam use 

and maintain a visible flame can effectively reduce flare emissions (by increasing combustion 

efficiency performance) without the need to implement draconian operating limits to ensure 

proper flare combustion performance. 

Discussion Topics – October 11, 2012 

In this meeting, industry representatives presented the concept of a “flare combustion 

efficiency plan” and then presented some case studies of the application of such a plan for 

different flare configurations. The presentation material which guided the discussion is provided 

as Attachment 4 to this memorandum. 

According to the industry representatives, a flare combustion efficiency plan, analogous 

to flare management plan in 40 CFR 60.103a, could be used to allow refineries to develop sitespecific work practices to ensure flares are not over assisted. A flare-specific approach would 

help to account for the different configurations and uses of flares. A key concept of the plan uses 

visible flame observations to identify appropriate flare-specific operating limits for the 

combustion zone net heating value or steam to flare gas flow ratios that would then be used to 

assess compliance. According to the industry representatives, flare efficiency is high whenever 

there is a visible flame, so the appropriate operating envelop can be determined by visibly 

observing the flame. 

The EPA representatives questioned the validity of the statement that a visible flame 

ensured high combustion efficiency and requested the data and documentation supporting this 

hypothesis. The EPA representatives inquired if there were some method, such as infrared 

cameras, that could be used to verify that a flare is achieving high combustion efficiency near the 

operating parameters that were established. The EPA representatives also questioned the need 

for secondary operating parameters. If a visible flame ensured good combustion, then why not 

simply require continuous visible flame monitoring? Industry representatives indicated that, 

while flares have cameras to view the flare to see if the flare is smoking, these cameras could not 

be used to see the flare flame at all times based on the relative position of the sun to the flare and 

camera. 

Discussion Topics – February 19, 2013 

Industry representatives outlined their key thoughts on flare performance requirements 

following the handout provided (see Attachment 5 to this memorandum), which guided the 

discussion for this meeting. The industry representatives’ first point was that it makes sense to 

focus only on those flares with significant flow. According to industry representatives, the 

significant costs associated with installing complex monitoring and control systems dictates that 

one needs a minimum amount of flow to the flare in order to have any chance of cost effective 

emissions reductions. 

Second, the industry representatives suggested that the unassisted flare heating content of 

200 British thermal units per standard cubic foot (Btu/scf) should be used as the minimum target 

combustion zone heat content. For unassisted flares, there is no assist dilution and so the 

combustion zone heat content is 200 Btu/scf. The 300 Btu/scf minimum heat content for assisted 
3

flares was selected, according to the industry representatives, to account for the assist dilution 

(i.e., the 300 Btu/scf flare gas requirements were selected to have a combustion zone heat content 

of 200 Btu/scf like that for unassisted flares). The industry representatives suggested that 

200 Btu/scf for combustion zone heating content should be sufficient and that the flare test data, 

when accounting for errors/uncertainties in test data, support the selection of a minimum 

200 Btu/scf combustion zone heating content. The industry representatives did not believe the 

320 Btu/scf combustion zone heating content suggested by the EPA is justified. Industry 

representatives also noted that, if flares are required to meet a 320 Btu/scf limit, they would need 

to add more supplemental gas to meet the level, which would waste energy resources and 

generate additional carbon dioxide emissions. 

Third, the industry representatives strongly encouraged the EPA to include a parametric 

monitoring approach for some cases (like a high-hydrogen stream), where they could use an 

alternative approach to the complex monitoring system, even for flares receiving higher/routine 

flows. The industry representatives reiterated their previous meeting’s assertion that a visible 

flame is a good indicator that the flare is getting good combustion efficiency. The industry 

representatives expressed their desire for significant flexibility in establishing appropriate 

parameters to be monitored, including allowance to use engineering calculations. 

Industry representatives also noted that periodic events are unpredictable and operators 

will need time to adjust steam use to meet the changing steam assist rates. Therefore, they need 

some averaging time for the minimum combustion zone heat content. For example, if a certain 

flaring event stops abruptly, the flare will be over-steamed for some period of time as the 

operators adjust for the decreased flare gas flow rate. There is a 5-minute allowance for smoking 

events in §63.11(b)(4); a similar allowance (or sufficient averaging time) should be provided for 

the minimum combustion zone heat content. The industry representatives also noted that, if they 

operate with minimum steam at low flow conditions, they are likely to smoke the flares if the 

flare gas flow rate suddenly increases. The industry representatives suggested that the EPA 

should consider increasing the current 5-minute allowance for a 2-hour period for smoking flares 

to 10 minutes to allow operators to feel comfortable using less steam. Industry representatives 

expressed their belief that they get maximum combustion efficiency at the insipient smoking 

point, but they generally cannot operate at that point because of the rules preventing smoking 

flares. If the EPA desires high combustion efficiency, then the industry representatives 

suggested that the EPA consider changes to the current requirements concerning smoking flares. 

The industry expressed concern that some gases might reach their incipient smoking 

point at combustion zone heating content less than the minimum value the EPA establishes 

(particularly if the EPA sets a higher combustion zone minimum heat content value). For 

example, if they start smoking at 280 Btu/scf, and the limit is 320 Btu/scf, then they would be in 

violation of the heat content or the smoking rule requirements. Therefore, the rule needs to allow 

alternate emission limits (combustion zone heat content) to be set on a site-specific basis, 

perhaps using site-specific passive Fourier transform infrared (PFTIR) testing. The EPA 

representatives noted that the Clean Air Act specifically allows, and the General Provisions 

include procedures, for facilities to develop an equivalent work practice standard. They would 

need to prove they are getting the required combustion efficiency at the lower combustion zone 

heat content value. Industry representatives suggested that they should be allowed to use the 

insipient smoking point and back off a little to set an appropriate combustion zone heat content 
4

value or parametric monitoring values rather than having to do a PFTIR test (since the smoking 

point would effectively set the high efficiency combustion zone conditions). 

The EPA representatives inquired as to what data industry representatives are using to 

assert that a visible flame correlates with good combustion. The industry representatives stated 

that is was the “conventional wisdom of those that performed the tests” and that it was clear that 

when the flame starts to get quenched (i.e., disappears or flickers significantly) is when 

combustion efficiency drops significantly. Industry representatives again asserted that 

parametric monitoring limits could be established based on visible flame observations and the 

insipient smoking point. They expressed concern about possible enforcement action if a onetime PFTIR test done to confirm compliance showed combustion efficiency of less than 

98 percent. One industry representative indicated that, for small or infrequently used flares, that 

any flare combustion efficiency in the above 95 percent should be acceptable. Industry 

representatives noted that there is some uncertainty in the PFTIR testing (different tests are done 

slightly differently), so there is some uncertainty in the number that implies 98 percent. The 

EPA representatives noted that they do not want to provide an alternative that is susceptible to 

failing a PFTIR test. The EPA representatives also noted that this would not be unlike other 

sources that use periodic testing along with control device parametric monitoring. If a facility 

does not meet the emission limits during a periodic performance test, that source must change the 

process or control device operating conditions, re-test to prove it is meeting the emissions 

standard, and establish new operating limits based on the most recent, compliant source test. 

Finally, industry representatives suggested that any flare performance rule should 

accommodate whatever is in a given facility’s consent decree. That is, if a consent decree allows 

certain monitoring systems or set points, then the flare performance rule should not make those 

facilities to change their operations (i.e., use different monitors or use more stringent minimum 

combustion zone heat content values). 

Based on the discussion, there appears to be a disparity in the interpretation of the flare 

data. Industry representatives suggest the data support a 200 Btu/scf minimum combustion zone 

heat content and the EPA suggests the data support a 320 Btu/scf minimum combustion zone 

heat content. The industry representatives suggested holding a follow-up meeting or 

teleconference to wade into the details of the test data to better understand the differences in 

these interpretations/conclusions. 

Discussion Topics – March 19, 2013 

This meeting was scheduled to follow up on differences in interpretation of the flare data 

with respect to a target combustion zone net heating value for flares. The industry 

representatives presented Figure 1 and indicated that, while a regression fit of all the data 

suggests that a combustion efficiency of 96.5 percent (expected to be equivalent to a destruction 

efficiency of 98 percent) would be achieved at a combustion zone net heating value of about 

360 Btu/scf, that regression line does not match well the sharp drop-off in combustion efficiency 

seen at about 110 Btu/scf. The industry representatives noted that if the x-intercept is fixed at 

114 Btu/scf, the resulting regression line appears to fit the data better and predicts that a 

combustion efficiency of 96.5 percent would be achieved at a combustion zone net heating value 

of about 200 Btu/scf. The industry representatives also indicated that the 200 Btu/scf 
5

combustion zone net heating value limit agrees well with the current operating limit for nonassisted flares. 

Figure 1. Industry representative correlation of flare combustion efficiency as a function 

of the combustion zone net heating value of the flared gas. 

At this meeting, the industry representatives presented their recommendations for 

“Group 1” and “Group 2” flares (see the presentation handout included as Attachment 6 of this 

memorandum). Group 1 flares are those that have routine flare gas flow and would be subject to 

a combustion zone net heating value limit and would be required to install continuous parameter 

monitors to demonstrate compliance. Group 2 flares are flares with limited flare gas VOC flow 

and would have a simple visible flame work practice standard, according to the industry 

representatives. The EPA representatives indicated that in Refinery MACT 1, flares are control 
6

devices and not emission sources, so subcategorizing into Group 1 and Group 2 flares was not 

appropriate. All flares must meet the 98 percent destruction efficiency target. Industry 

representatives indicated that their primary point is that it is not cost-efficient to require flares 

that operate infrequently or that receive very little VOC mass flow to install continuous 

monitoring systems to comply with the target combustion zone net heating value. Thus, while 

the nomenclature may need to be changed, the concept of providing an alternative to continuous 

parameter monitoring systems for “non-routine use” flares is still valid. While the industry 

representatives provided their recommendations for defining the “Group 2” flares, they noted 

that the precise criterion for defining these “Group 2” flares is somewhat subjective and should 

be flexible. For example, if a flare that routinely operates less than 500 hours per year has one 

year in which it operated 1,200 hours due to a combination on very unusual circumstances (e.g., 

plant turnaround coupled with a hurricane-forced shutdown), that flare should not be required to 

install continuous monitors. 

 
Attachment 1 

Participants in Meetings Between the EPA and Representatives of the Petroleum Refining 

Industry 

Industry Representatives 

Matt Todd, API (12/8/11; 3/21/12; 10/11/12; 2/19/13; 3/19/13) 

John Wagner, API (12/8/11; 3/21/12; 10/11/12) 

David Friedman, American Fuel and Petrochemical Manufacturers (AFPM) (12/8/11; 3/21/12) 

Bob Hermanson, BP (10/11/12) 

Clay Freeberg, Chevron (12/8/11; 3/21/12; 10/11/12; 2/19/13) 

Chuck Feerick, ExxonMobil (12/8/11; 3/21/12; 10/11/12; 2/19/13; 3/19/13) 

Bob Morehouse, ExxonMobil (3/21/12) 

George Graham, ExxonMobil (10/11/12) 

Duane McGregor, ExxonMobil (2/19/13) 

Charles Bennett, Marathon Petroleum (12/8/11; 3/21/12; 10/11/12) 

Erin Tullos, Phillips66 (12/8/11; 3/21/12; 10/11/12; 2/19/13; 3/19/13) 

John Askounis and Frank Tracy, Phillips66 (10/11/12) 

Dave Pavlich, Phillips66 (3/21/12) 

Gary Mueller, Shell (2/19/13; 3/19/13) 

Shari Keller, Shell (12/8/11; 3/21/12; 10/11/12; 2/19/13) 

Matt Hodges, Valero (12/8/11; 3/21/12) 

Norm Morrow, Fresh Air Consulting (12/8/11; 3/21/12; 10/11/12; 2/19/13; 3/19/13) 

U.S. EPA Representatives 

Andrew Bouchard (12/8/11; 3/21/12; 10/11/12; 2/19/13; 3/19/13) 

Eric Goehl (12/8/11; 3/21/12; 2/19/13) 

Penny Lassiter (12/8/11; 3/21/12; 10/11/12; 3/19/13) 

Brenda Shine (12/8/11; 3/21/12; 10/11/12; 2/19/13; 3/19/13) 

Gerri Garwood, Kevin McLaughlin, Nick Parsons and Erika Sasser (3/21/12) 

Susan Stahle and Jan Tierney (10/11/12) 

Brian Shrager (2/19/13) 

EPA Contractors 

Jeff Coburn, RTI International (12/8/11; 3/21/12; 10/11/12; 2/19/13; 3/19/13) 

Kristin Sroka, RTI International (12/8/11; 3/21/12) 

Jason Renzaglia, Eastern Research Group, Inc. (12/8/11; 3/21/12; 2/19/13; 3/19/13) 

Mae Thomas, Eastern Research Group, Inc. (12/8/11; 3/19/13) 
Attachment 2 

API/NPRA/ACC Steam-Assisted Flare Operations and Control Survey - Final 

 December 7, 2011 
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 

 Presentation Slides 

 Steam-Assisted Flares 

Cost-Effectiveness Analysis of Potential Additional Monitoring and Controls 

 Industry Flare Technical Work Group 

December 7, 2011 
Slide 1

Steam-Assisted Flares

Cost-Effectiveness Analysis

of

Potential Additional Monitoring and Controls

Industry Flare Technical Work Group

December 7, 2011

Final
Slide 2

Study Approach and Objectives

• Collect operating data of steam-assisted flares in the Refining/Chemicals 

industry

• Assess potential VOC emission reductions associated with potential VOC 

destruction improvements via steam reduction and natural gas addition

• Analyze the cost effectiveness (cost/ton VOC reduced) resulting from 

installation of monitoring equipment, steam control, and supplemental gas 

addition controls

• Develop a perspective on relationships among operating scenarios, 

emissions, and costs 
Slide 3

Key Learnings

• 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.
Slide 4

Flare Study Information

• 38 flares

– 7 companies

– 24 refinery flares

– 14 chemicals flares

– 128 operating scenarios 

• Combustion efficiencies (CEs) were 

calculated assuming: Case 1

- 98% CE if steam-to-flare gas ratio < 4

- 80% CE if steam-to-flare gas ratio > 4

 Case 2

- 98% CE if CZ-NHV ≥300

- 90% CE if CZ-NHV <300, ≥200

- 80% CE if CZ-NHV <200, ≥100

- 70% CE if CZ-NHV <100

• Assumed total CAPEX:

- Case 1 - $1,000,000

- Case 2 - $2,300,000
Slide 5

VOC Emissions Reductions Achieved thru Monitoring & Control of 

Operations are Cost-Effective for only a Small Proportion of Flares

Only 8 Flares have Cost 

Effectiveness of 

<$5000/Ton of VOC
Slide 6

VOC Emissions Reductions Achieved thru Monitoring & Control of 

Operations are Cost-Effective for only a Small Proportion of Flares 

Only 6 Flares have Cost 

Effectiveness of 

<$5000/Ton of VOC
Slide 7

CE Monitoring & Control has only a Small Impact on VOC 

Emissions for the Majority of Flares in the Study
Slide 8

• 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

– The VOC content of the flare gas

– The annual VOC load 

– The VOC load during periods of high steam-to-flare gas ratio

– The duration of high steam-to-flare gas periods

– 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

In Summary
Attachment 4 

 Presentation Slides 

 Presentation to EPA OAQPS on Flare Combustion Efficiency Plan Concept 

 Air Toxics Group 

October 11, 2012 
Presentation to EPA OAQPS on 

Flare Combustion Efficiency Plan 

Concept 

Air Toxics Group 

October 11, 2012 
en ·Jli'l Overview 

Objectives of Today's Discussion 

• Describe the concept of Flare Combustion Efficiency 

Plans as an effective regulatory approach 

• Provide a number of industry examples of how the 

concept would work in practice 

Content 

• Existing flare regulations 

• Flare regulatory challenge 

• Concept to address regulatory challenge 

• Important aspects of this concept 

• Learnings based on steam optimization efforts 

• Examples 

2 
energitill Existing Flare Regulations 

All Flares 

• § 60.18 I§ 63.11 establish requirements for all flares used as 

control devices: 

- Visible emissions (smoking) 

- Presence of a pilot flame 

- Minimum flare gas heat content 

- Maximum tip exit velocity 

Most Refinery Flares 

• § 60.1 04/§ 60.1 03a regulates sulfur content 

• § 60.1 03a requires: 

- Flare Management Plans (to minimize flow to the flare) 

- Root cause analyses/corrective actions based on 802 

emissions and flare flow 

• § 60.1 07a requires: 

- Flare gas flow meters 

- Continuous monitoring systems for H2S 

- Continuous monitoring systems or grab samples for total 

sulfur 

3 
Flare Regulatory Challenge 

• No regulatory requirement to control assist gas (steam/air) 

rates - however: 

Flare test data have shown that excess steam can degrade flare 

combustion efficiency (CE), in particular at high turn-down 

- Data show that highest levels of CE occur at or near the incipient 

smoke point, i.e. the point where wisps of smoke (marbling) are 

observed 

Data also show that high levels of CE occur when a "visible" 

flame is present 

I Unacceptable 

Reguhdlallo da nat .. low Aarw .t "'ncipient smoke Flare wiUI wlolblo, ollghtlJ Floro with wlslltlo flame "'-• wHh smsll1 wlslblo, Flue wiUI .. ....., pluYislltle omlsslons (om"*•l paint" - tr.,slont wisps .r "m•blocl"ftomo. with ••-rogl-• .r tr.,oparont flame. .ndno Ylsllllo ftomo. 

for m•otlum S mlnvto11 in om"*•· Mlullmurn tr.,o,..renq. Minimum apt!fotlng Siloam cauld bo quenching 

o "our parlod. 

4 
Concept to Address the 

Regulatory Challenge 

• Flare Combustion Efficiency Plans (FCEP) 

• Over steaming can be prevented by training, procedures, and customized 

flare-specific operating plans and control parameters. 

• Similar to the concept used in the §60.1 03a flare management plan and the 

§63.1574(f) operation, maintenance, and monitoring plan, require CE/assist 

control aspects to be addressed in a flare combustion efficiency plan. 

• The FCEP would include site-developed work practices, which would ensure 

high combustion efficiency of regulated material (i.e. a "visible" flame). 

• Advantages 

• Concept provides a regulatory framework for each flare to be operated in a 

way that ensures high CE, without introducing unreasonable, costly 

conservatism 

- Flares are designed to be "fit-for-purpose", making a one-size-fits-all 

approach inappropriate and, unless highly conservative, not guaranteed 

to achieve the desired results in all cases 

- Customized approach ensures that controls and operating parameters 

will be tailored specifically to each individual flare and operating 

condition 

5 
energ61i'l lmportant Aspects of This Concept 

• Sites would be required to develop a FCEP that addresses each assisted flare and 

ensures flares are operated with high combustion efficiency when flaring 

• A flare CE control strategy is derived based on flare-specific conditions which maintain 

a "visible" flame when flaring regulated material 

- Define control parameters & associated operating envelope 

- e.g., steam/flare gas ratio (SFR), combustion zone net heating value (CZ-NHV), 

visual monitoring 

• Control would be automatic or manual, as appropriate for the flare and determined by 

the site 

• Records would be kept to demonstrate adherence to the control strategy 

- A reasonable flare-specific averaging time is allowed (e.g. three-hour rolling for a 

continuous flare) 

- An excursion from the operating envelope does not constitute a deviation if a 

visible flame is maintained (with records to that effect) 

- A loss of visible flame during short "transition periods" (e.g. 10 minutes) is allowed 

to account for composition swings/episodic events 

• The plan would be submitted to the Administrator but does not need regulatory 

approval to implement or update. A periodic internal review would be required 

6 
Learnings Based on Steam 

Optimization Efforts 

• Every flare is different, requiring a unique, customized control strategy 

• Flaring with a "visible" flame is achievable, even at low flow 

- In some cases, may require addition of supplemental gas 

- To improve reliability and minimize supplemental gas additions, many sites 

may invest in equipment upgrades (e.g. flare gas flow meters, dual range 

steam control valves, steam flow meters, BTU analyzers, automated 

control instrumentation) 

• Implementation of flare gas minimization/root cause analyses/flare gas 

recovery has greatly reduced industry flaring events 

• Flare operator training and involvement is vital to success 

- When they are part of the team that develops the control strategy, their 

commitment to excellence is assured 

7 
energitill Summary of Examples 

• Case 1: Looped refinery flare system with full flare gas recovery and 

no routine flare gas flow. Control strategy based on visual 

observations of the flare and records of each flaring event 

• Case 2: Refinery flare with no flare gas recovery and high volume of 

high Btu gas and minimum steam. Control strategy based on CZNHV 

• Case 3: Chemical plant flare with partial flare gas recovery and 

moderate volumes of routine flare gas flow. Control strategy based 

on CZ-NHV 

• Case 4: Refinery flare with full flare gas recovery and no routine flare 

gas flow. Control strategy based on visual observations and 

steam/flare gas ratio (SFR) 

• Case 5: Refinery flare with high volume of purge gas plus low 

volumes of routine flare gas flow. Control strategy based on SFR 

8 
Case 1 

1. General description 

a. Eight elevated, steam assisted refinery flares (tied together in a single loop) 

b. Full flare gas recovery (three reciprocating compressors; two online with one spare) 

c. Seal drum on each flare 

d. No routine/ continuous flare gas to the flares 

e. Flare gas generally flows to two flares, but pressure can cause flow to go to any of the eight flares 

f. Steam is only added during an event as needed for visible emissions control 

2. Flare gas description 

Normal operations is under complete flare gas recovery with no flare gas flow to the flares. The refinery typically will have 20 

to 30 flaring events during the year. Total flaring time is on the order of 15 hrs/yr, and the majority of flaring events are less 

than 10 minutes in duration. Events are the result of emergency/unplanned flaring, or associated with equipment startup and 

shutdown. Flare gas includes refinery fuel gas, coker vent gas or other low VOC-containing gas, hydrogen, nitrogen 

3. Measurement equipment 

a. Future flare gas flow meters (required under NSPS Ja) 

b. Manual steam control using steam flow meters or control valve position 

c. Visual camera on each flare to observe visible emissions 

4. Combustion efficiency operating parameters 

Flare console operator is alerted by unit personnel whenever there is anticipated abnormal flow to the flare recovery system. 

The operator manually controls the rate of steam and/or natural gas addition to the flare for each flaring event to ensure no 

visible emissions and to maintain a visible flame. Upon cessation of the event, the operator completes an incident report 

form. Information recorded includes: 

a. Date, time, duration, source, and description of the flaring event 

b. Flare gas flow rate; type and amount of material released 

c. Steam addition rates, if any 

d. Whether any visible emissions were observed and if so for how long 

e. Whether a visible flame was maintained and if not, for how long was the visible flame lost 

f. A video record of each flaring event is maintained for one week 

9 
Case2 

1. General description 

a. Refinery flare 

b. Elevated flare with steam assist 

c. Multiple baseline flow scenarios 

d. The flare receives routine flow and does not have a flare gas recovery system. 

e. The minimum required purge gas is 500 seth (purchased natural gas) 

f. Minimum center steam is 1 ,500 lbs/hr 

g. Minimum upper steam is 500 lb/hr. 

2. Flare gas description 

-1,000-70,000 seth of routine/ continuous flow of high Btu, "sweet" flare gas from various sources 

3. Measurement equipment Unit 1 flare header 

Knockout Pot 

a. Flare gas flow meter To Unlt1 +---------l b. Purge gas flow meter i<-----C><I---- From other 

c. Center steam controlled by restriction orifice 

d. Flow meter on tip ste~m with minimum set by restriction orifice 

e. BTU analyzer on ~are gas 

f. IR camera on pilot 

g. Visual camera to observe visible emissions 

h. Portable infrared camera available 

4. Combustion efficiency operating parameters 

a. CZ-NHV > 200 Btu/scf 

Collection of 

relief valves 

Knockout Pot 

ToUnit +------l 

Flare Header 

b. Instrumentation and calculation into DCS with audible alarm for CZ-NHV < 300 Btu/scf 

"ormaltv Closed 

4CIIrrontl~ 

locudl 

flare header 

l 

IRcaQ r~ Steam Il l 

ToCEMS / 

flow Meter 

Pilot 

c. Operator control with steam reductions and natural gas addition as needed (m'*nL.!..!u~a~l,__~~==::::ilL..J 

Flare 

knockout 

pot 

10 
energ..-rl Case 3 

1. General description 

a. Chemicals flare (primary flare for the plant); elevated, steam assisted, simple tip 

b. Two additional staged flares serve as backup to this primary flare 

c. Seal drum 

d. Flare gas recovery (1 0 klb/hr) designed to handle -50-90% of the normal flare flow rate 

e. Minimum required steam 2.3 klbs/hr added continuously for tip cooling 

2. Flare gas description 

a. Normal flow is - 10 klbs/hr, but flow can be as low as 1 klb/hr 

b. Typical composition of the flare gas 

I. -50% nitrogen 

II. -40% mixtures of C2-C5s (including olefins) 

Ill. -3-11% C5+ 

3. Measurement equipment 

a. Flare gas flow meter 

b. Steam flow meters 

c. Gas chromatograph 

d. IR camera on pilots 

e. Video camera 

4. Combustion efficiency operating parameters 

a. CZ-NHV > 210 Btu/scf established based on steam optimization testing and verified by visual observation of the flame 

b. Narrow operating range (between 210-240 Btu/scf); visible flame compromised below 210 Btu/scf and smoking begins 

above 240 Btu/scf 

c. Steam control valve is monitored and used to calculate and manually control discretionary steam flow rates. Natural gas is 

added automatically to maintain minimum required Btu value. 

d. Console operator records all periods when the CZ-NHV falls below the minimum value along with visible observations of 

flame appearance during those periods 

11 
energ-Jtill Case4 

1. General description 

a. Refinery flare 

b. Elevated flare with steam assist 

c. Not a back-up to another and is not part of a cascaded system 

d. Has a flare gas recovery system 

e. Minimum purge is 100 lb/hr (purchased natural gas) 

f. Minimum steam is 0 lb/hr 

g. 0 lb/hr of tip steam at low flare gas rates 

2. Flare gas description 

Typically, 100 lb/hr of natural gas (-8,500 hrs/yr). Otherwise, emergency flaring, startup/ shutdown, and other minor venting 

Includes natural gas and hydrogen with low VOC, and occasional nitrogen (up to about 5,500 lb/hr). 

3. Measurement equipment 

a. Flare gas flow meter Coii!C!Jon of Unfts 

b. Purge gas flow meter 

c. Flow meter on steam 

d. IR camera on pilot 

e. Visual camera to observe visible emissions 

4. Combustion efficiency operating parameters Collection ol Unit> 

a. SFR < 2:1 

b. Instrumentation and calculation into DCS with audible alarm for SFR > 1.5:1 

c. Operator control with steam reductions and natural gas addition as needed (manual) 

Unit 

Low Pressure 

Flare Header 

Low Pressure 

Flare Header 

Liquid Knock Out Pot 
Case 5 

1 . General description 

a. Refinery flare; elevated, steam assisted, simple tip 

b. No seal drum 

c. Purge gas rate 500,000 scfd of purge gas (refinery fuel gas) added on a continuous basis (note: future project plan 

to reduce to 30,000 scfd) 

d. No flare gas recovery 

e. Minimum steam requirement is 450 lbs/hr 

2. Flare gas description 

-1 ,500-2,200 lbs/hr of routine/ continuous flow of "sweet" flare gas from various sources 

3. Measurement equipment 

a. Flare gas flow meter 

b. Steam flow is controlled by a John Zink ZOOM control system. Measurement is determined by steam control 

valve position which is applied to a curve of steam flow versus valve position 

c. Automated steam control valves tied to John Zink ZOOM (infrared sensors) system with manual override 

d. Visual camera 

4. Combustion efficiency operating parameters 

a. SFR < 1.5:1 based on steam optimization trials and confirmed by visual observation of the flare 

b. Project planned that will allow steam control valves to be controlled based on SFR rather than at the ZOOM 

system, i.e. this will automate the control of the SFR and provide a record in the DCS 

c. Exceptions to SFR < 1.5:1 include the need to exceed ratio for visible emissions control 

d. Console operator to record all periods when the ratio is exceeded along with visual observations of flame 

appearance during those periods. 

e. When the refinery implements the project to reduce purge gas flow, the steam optimization trials will be repeated 

and SFR adjustments made as appropriate. 

13 
Attachment 5 

Handout 

Regulatory Objective: Cost-effective mitigation of excess emissions resulting from flare 

over-assist 
Regulatory Objective: Cost-effective mitigation of excess emissions 

resulting from flare over-assist 

Important Considerations 

1 . The potential for excess emissions is highest for flares with continuous or routine 

flows of regulated material 

2. Emissions reductions are most cost-effectively achieved through assist gas 

reductions/ management 

3. Significant potential costs include both instrumentation and control equipment as 

well as supplemental gas additions 

4. Approximately ~ 45 tons VOC reduction is needed to justify instrumentation of 

$2.3M ($5000/ton VOC) 

Regulatory Approach: Refinery Flares 

1. Recognizing that significant investment has been made across the industry in flare 

gas recovery and other flare minimization technologies and practices, subdivide 

flares based upon the potential for excess emissions 

2. Flares with discrete or intermittent flow of regulated materials have a low potential 

for excess emissions 

a. Define these flares in a way which encompasses flares equipped with flare gas 

recovery and other flare minimization technologies and practices e.g. less than 

some minimum hours/ year, or less than some tons/year of VOC loading 

b. Establish a compliance metric based on a minimum combustion zone net 

heating value (recommended 200 btu/scf) or equivalent 

c. As an alternative, allow enforceable, flare-specific parametric monitoring 

bounded by conditions which maintain a visible flame or equivalent 

d. Allow maximum flexibility in demonstrating compliance, including engineering 

calculations, documentation of a visible flame, etc. 

e. Compliance demonstration must recognize that these intermittent events may 

be sudden and of short duration. Operators will need sufficient time to respond 

to these events, that is, an adequate averaging time (e.g. cannot exceed the 

compliance metric for more than 15 minutes in any one hour period) 

3. Flares with continuous or routine flows of regulated materials have a higher 

potential for excess emissions 

a. Ensure a minimum combustion zone net heating value (recommended 200 

btu/scf) or equivalent is maintained 

b. Provide flare specific alternative approach to establish the minimum 

combustion zone net heating value or equivalent 
c. Instrumentation to include flow meters, the ability to control the rates of steam 

and if necessary supplemental gas addition, and some measure of vent gas 

combustibility (e.g. calorimeter, total hydrocarbon analyzer, GC if appropriate) 

d. An adequate averaging time must also be provided which recognizes the 

responsiveness/limitations of the monitoring and control equipment 

e. Flares with a well-defined operating conditions (e.g. loading rack flares, etc.) 

should be provided maximum flexibility for demonstrating compliance, for 

example, through the use of grab samples and/or engineering calculations 

4. Provisions should be included to accommodate holders of Consent Decrees or 

other site-specific requirements that already achieve the high combustion 

efficiency 

5. The rule or preamble should recognize that compliance with new requirements 

constitutes good air pollution control practices 
Attachment 6 

Handout 

Flare Combustion Efficiency Concept 

 
Flare Combustion Efficiency Concept 

• Group 2 (<1,000 hours/year flaring VOC or <100 Tons VOC contained in 4380 hours in a 

year.) 

Work practice- maintain visible flame 

{associated demonstration- still images, documentation, etc.) 

• Group 1 (Routine VOC flow) 

Combustion property limit 

Group 1A Compliance Demonstrations 

- Flow (gas & steam) 

NHVcz, combustibles, etc. 

(Calorimeter, GC, hydrocarbon analyzer,% combustibles, etc.) 

- CPMS requirements (rather than CEMS) 

- Flare-specific alternative limit development flexibility 

(Performance test- PFTIR? Visible flame?) 

- Flare-specific alternate monitoring 

(maintain flare operations within limits (e.g., SVG Ratio) that is established via performance 

test) 

Group 1B Compliance Demonstrations 

- Well defined composition -? engineering calculations 

(e.g., loading rack flares, narrow composition, dedicated, single unit, etc.) 
1 

0.9 • ~ 0.8 >- u 0.7 c 

G) 

·c:; 

IE 

0.6 

w 0.5 

c 

0 0.4 :w 

en 

::I 

.a 0.3 

E 

0 0.2 0 

0.1 

0 

0 

Solver - for all points Solver - fixed x-offset 

Steepness 10.57884 Steepness 2.854453 

X-offset 75.13327 X -offset 114 

Combustion Zone Net Heating Value 

100 

364 Btu/scf 

CE (x) 

1 + 

1 

• Flare Data 

--Functional fit- all points 

--Functional fit -fixed x-offset 

a 

(x f3) 

200 

3_o_o __ ooHv __ (B-tu_s'o_: _f) __ soo - 700- aoo - _ _]