### Date: March 28, 2013

To: Andrew Bouchard and Br enda Shine, EPA/OAQPS/SPPD

From: Jeff Coburn

Subject: Meeting Minutes for Meetings Betw een the U.S. EPA and Petroleum Refinery Industry Representatives regarding Pote ntial Flare Performance Standards: December 8, 2011; March 21, 2012; Oct ober 11, 2012; February 19, 2013; and March 19, 2013

Representatives of the U.S. Environmen tal Protection Agency (EPA) and their contractors (Eastern Research Group and RTI Intern ational) participated in a series of meetings with representatives of American Petroleum Ins titute (API) and other industry representatives. The purpose of these meetings was to discuss is sues identified with the performance of some petroleum refinery flares and pot ential new monitoring standards to improve flare performance. Attachment 1 to this memorandum includes a list of a ttendees during these meetings.

Discussion Topics – December 8, 2011

In this meeting, industry repres entatives presented their data collection efforts for flare flow, composition, and steam usage rates and summari zed their preliminary an alysis of the data. Attachment 2 to this memorandum is the flare op erations and control survey report documenting the data used and analyses perfor med to assess cost-eff ectiveness of potential compliance options that was provide d 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 reducti ons 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 gene rally not cost effective to control.

Discussion Topics – March 3, 2012

This meeting covered a broad range of issu es concerning the Refinery MACT 1 and 2 rules as well as proposed uniform standards. Only the discussion poi nts related to flare combustion efficiency requirements are su mmarized in this memorandum. The EPA representatives indicated that th ey were starting the process of conducting a peer review of the flare combustion efficiency repor t summarizing the findings of r ecent efficiency tests conducted on flares. Industry representativ es indicated that the peer re view panel should include people from industry that have actual experience operati ng a flare and not be limited to academia or flare manufacturers. The industry representatives noted that, as mo re refineries implement flare gas recovery, the emissions from flares will decrease. They also indicated that significant emission reductions can be achie ved by operator training. Current operators have been trained

### 2 only to prevent the flares from smoking, Trai ning 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 repr esentatives presente d the concept of a “flare combustion efficiency plan” and then presented some case st udies of the application of such a plan for different flare configurations. The presentation material which guided th e discussion is provided

as Attachment 4 to this memorandum.

According to the industry repr esentatives, a flare combustion efficiency plan, analogous to flare management plan in 40 CFR 60.103a, could be used to allow refine ries to develop sitespecific work practices to ensure flares are not over assisted. A flare- specific approach would help to account for the different c onfigurations and uses of flares. A key concept of the plan uses visible flame observations to identify appropriate flare-speci fic operating limits for the combustion zone net heating value or steam to flar e gas flow ratios that would then be used to assess compliance. According to the industry representatives, flar e 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 validi ty of the statement that a visible flame ensured high combustion efficiency and request ed the data and documentation supporting this hypothesis. The EPA representa tives inquired if there were some method, such as infrared cameras, that could be used to verify that a fl are is achieving high combus tion efficiency near the operating parameters that were established. Th e EPA representatives also questioned the need for secondary operating parameters. If a visi ble flame ensured good combustion, then why not simply require continuous visible flame monitori ng? Industry representa tives indicated that, while flares have cameras to view the flare to see if the flare is smoki ng, 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 represen tatives’ 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 comple x monitoring and control systems dictates that one needs a minimum amount of flow to the flare in order to have any chan ce of cost effective emissions reductions.

Second, the industry representatives suggested th at the unassisted flar e heating content of 200 British thermal units per standard cubic foot (B tu/scf) should be used as the minimum target combustion zone heat content. For unassisted flares, there is no assi st dilution and so the combustion zone heat content is 200 Btu/scf. The 300 Btu/scf mini mum heat content for assisted

### 3 flares was selected, according to the industry re presentatives, to account for the assist dilution ( i.e. , the 300 Btu/scf flare gas requirements were se lected 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 shoul d be sufficient and that the flare test data, when accounting for errors/uncertainties in te st data, support the selection of a minimum 200 Btu/scf combustion zone heating content. Th e industry representatives did not believe the 320 Btu/scf combustion zone heating content su ggested 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 le vel, which would waste energy resources and generate additional carbon dioxide emissions.

Third, the industry representatives strongly en couraged the EPA to include a parametric monitoring approach for some cases (like a hi gh-hydrogen stream), where they could use an alternative approach to the comp lex monitoring system, even for flares receiving higher/routine flows. The industry representatives reiterated th eir previous meeting’s as sertion that a visible flame is a good indicator that the flare is ge tting good combustion efficiency. The industry representatives expresse d their desire for significant flex ibility in establishing appropriate parameters to be monitored, including a llowance to use engineering calculations.

Industry representatives also noted that periodic events ar e unpredictable and operators will need time to adjust steam use to meet the ch anging 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 simila r allowance (or sufficient averag ing time) should be provided for the minimum combustion zone heat content. The i ndustry representatives also noted that, if they operate with minimum steam at lo w flow conditions, they are like ly to smoke the flares if the flare gas flow rate suddenly increases. The i ndustry representatives s uggested 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 comfor table 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 e fficiency, then the i ndustry representatives suggested that the EPA consider changes to the current requirements concer ning smoking flares.

The industry expressed concern that some gases might reach their incipient smoking point at combustion zone hea ting content less than the mini mum value the EPA establishes (particularly if the EPA sets a higher combus tion 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. Ther efore, the rule needs to allow alternate emission limits (combustion zone heat c ontent) to be set on a site-specific basis, perhaps using site-specific pa ssive Fourier transform infrar ed (PFTIR) testing. The EPA representatives noted that the Clean Air Act specifi cally 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 com bustion efficiency at the lower combustion zone heat content value. Industry representatives su ggested that they should be allowed to use the insipient smoking point and back off a little to se t an appropriate combustion zone heat content

### 4 value or parametric monitoring values rather th an having to do a PFTIR test (since the smoking point would effectively set the high e fficiency combustion zone conditions).

The EPA representatives inquired as to what data industry representatives are using to assert that a visible flame corr elates with good combustion. The industry representatives stated that is was the “conventional wisdom of those that performed the tests” a nd that it was clear that when the flame starts to get quenched ( i.e. , disappears or flickers significantly) is when combustion efficiency drops significantly. I ndustry representatives again asserted that parametric monitoring limits could be establis hed based on visible flame observations and the insipient smoking point. They expressed concer n about possible enforcement action if a onetime PFTIR test done to confirm compliance sh owed combustion efficiency of less than 98 percent. One industry representa tive 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 uncertain ty in the number that implies 98 percent. The EPA representatives noted that they do not want to provide an alte rnative that is susceptible to failing a PFTIR test. The EPA representatives al so noted that this w ould not be unlike other sources that use periodic testing along with control device parame tric monitoring. If a facility does not meet the emission limits during a periodic performance test, that source must change the process or control device opera ting conditions, re-test to prov e it is meeting the emissions standard, and establish new operating limits ba sed on the most recent, compliant source test.

Finally, industry representatives suggeste d that any flare performance rule should accommodate whatever is in a given facility’s cons ent decree. That is, if a consent decree allows certain monitoring systems or set points, then th e 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 representativ es suggested holding a follow-up meeting or teleconference to wade into the de tails of the test data to bett er understand the differences in these interpretations/conclusions.

Discussion Topics – March 19, 2013

This meeting was scheduled to follow up on diff erences in interpretation of the flare data with respect to a target combustion zone net heating value for flares. The industry representatives presente d Figure 1 and indicated that, while a regression fit of all the data suggests that a combustion efficiency of 96.5 percen t (expected to be equivalent to a destruction efficiency of 98 percent) would be achieved at a combustion z one 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 i ndustry representatives noted that if the x-intercept is fixed at 114 Btu/scf, the resulting regres sion line appears to fit the data better and predicts that a combustion efficiency of 96.5 percent would be ac hieved at a combustion zone net heating value of about 200 Btu/scf. The industry represen tatives 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 representa tives 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 woul d be required to inst all continuous parameter monitors to demonstrate compliance. Group 2 flar es 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 indicate d that in Refinery MACT 1, flares are control

### 6 devices and not emission sources, so subcategorizing into Gro up 1 and Group 2 flares was not appropriate. All flares must meet the 98 per cent destruction efficien cy target. Industry representatives indicated that thei r primary point is that it is not cost-efficient to require flares that operate infrequently or that receive ve ry little VOC mass flow to install continuous monitoring systems to comply with the target co mbustion zone net heating value. Thus, while the nomenclature may need to be changed, the c oncept of providing an a lternative to continuous parameter monitoring systems for “non-routine us e” flares is still valid. While the industry representatives provided their r ecommendations for defining the “G roup 2” flares, they noted that the precise criterion for de fining these “Group 2” flares is somewhat subjective and should be flexible. For example, if a flare that rou tinely operates less than 500 hours per year has one year in which it operated 1,200 hours due to a co mbination on very unusual circumstances ( e.g. , plant turnaround coupled with a hurricane-forced s hutdown), that flare should not be required to install continuous monitors.

### Attachment 1 Participants in Meetings Betw een the EPA and Representative s 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 Manufacture rs (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 Petrol eum (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 Interna tional (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 Gr oup, Inc. (12/8/11; 3/19/13)

### Attachment 2

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

December 7, 2011

# F I N A L



# API/NPRA/ACC Steam

- Assisted Flare Operations and Control Survey

December 7 , 2011FINAL 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 in fluence 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 fl are’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 operatio ns (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 ba sed upon individual flare operations.FINAL December 7 , 2011

Page 2 

## Introduction

An analysis of potential VOC 1 

### 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 steam

assisted flare s

– both under “stand by” 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. O ne hundred and eight individual flare gas compositions were provided

. The flare characterization information provided by the respondents is tabulated in

.



## Analyses Performed

Operating d ata gathered included flare gas rates, steam rates, gas composition 4



### Attachment 1 , and annual operating hours for each operating scenario.

shows the individual flare and scenario information , except for the composition inf ormation. The compositions provided covered a broad range, summarized as follows:

VOC range: 0

- 97 vol

. %

- LHV range: 300

- 2470 BTU/scf

H 2 

### range: 0

- 90 vol

. %

- CH 4 

### 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 effi ciency 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, ca rbon dioxide, and nitrogenFINAL December 7 , 2011

Page 3 

### Using the submitted data, VOC emissions were es timated based upon two
models:

1) SFR model: 98% CE for SFR < 4 ; 80% CE otherwise 5



### 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

7 0% CE if CZ

- NHV < 100 Btu/scf

T o 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 f or 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

.

T he analysis assumed a n 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 va lued 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 facto r (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 recommen dations 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 req uire 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 m eters 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. N o specific i nvestments 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 an d the cost effectiveness of potential flare control requirement s 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

augme nted 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 co nsider ing the impact of assuming a CZ

- NHV value o f 200 or 400 B TU /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 analys e s w ere performed regarding the investment
costs and the price assumptions for natural gas and steam. Select cases

were run at higher and lower investme nts and for higher and l ower 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, includ ing 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, natur al 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, i t 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 natur al 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
valu es 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 monitor ing and controls to all flares. For all of
the models evaluated, a significant proportion of the 38 flares a lready meet
the SFR and CZ

- NHV goa ls under all operating scenarios. The analyses
herein indicate that 16% or 18% of the flares studied may benefit cost

effectively from establishing SFR 11 

### or CZ

- NHV 12 

### goals , respectively, requiring the ty pes 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 co uld 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 co uld cost effectively benefit, requiring the types of monitors and controls evaluated in this study.

13 Graphical repre sentations 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) M in. 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. Operat es 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 l ow. 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 48 341,25 0 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) M in. 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 D esign 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 a verages 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 hour ly 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 a verages 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) M in. 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 ma nufacturer 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 com bustion efficiency for the 38 flares for the SFR model and CZ

- NHV model s 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 Overal l 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 submitte d, % 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

- N HV<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< 2 00, CE=80%; CZ

- NHV<1 0 0, 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 5K - 10K $/ton 10K - 100K $/ton 100K - 1,000K $/ton > 1,000K $/ton 1K - 5K $/tonFINAL 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 5K - 10K $/ton 10K - 100K $/ton 100K - 1,000K $/ton > 1,000K $/ton 1K - 5K $/tonFINAL 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 5K - 10K $/ton 10K - 100K $/ton 100K - 1,000K $/ton > 1,000K $/ton 1K - 5K $/tonFINAL 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 5K - 10K $/ton 10K - 100K $/ton 100K - 1,000K $/ton > 1,000K $/ton 1K - 5K $/tonFINAL 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 De scription (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 Ga s 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 Imbala nce 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 StreamFINAL 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 De scription (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 8 090 102 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 sc enario 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 SituationFINAL 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 De scription (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
24 208,0 00 375 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 85 100 00 Typical Emergency OperationFINAL 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 De scription (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 3 750 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 1044 0 >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 l b/hrFINAL 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 De scription (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 26 312 > 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/hrFINAL December 7 , 2011

Page 19 

## Attachment 2

– Methodology f or 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 combu stion 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. Multip ly 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 emi ssions 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 maintenanc e 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

stea m 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 Potentia l 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

# ene rgitill 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 

# 80 2 

# 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 smsll 1 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

# ene rg61i'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

# ene rgitill 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 h e ader Knockout Pot



### a. Flare gas flow meter

To Unlt1 +----- ----l 

### b. Purge gas flow meter i<--

--- C><I--

-- F rom 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 Knock o ut Pot

ToUnit +------l F lare Header



### b. Instrumentation and calculation into DCS with audible alarm for CZ-NHV < 

### 300 Btu/scf "o r ma ltv Closed**4CIIrrontl~** locu dl flare header 

# l IRcaQ

# r~

Steam 

# Il l

ToCEMS / fl ow Me t e r Pilot



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

knockout

pot

10

# ene rg..-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

## ene rg-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 Un f ts 

### 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 Collect i on 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 mitigatio n 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 

### 0.3 .a 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 B tu/scf



# CE (x)


# 1 

# + 1 • Flare Data

-- Functional fit- all points

-- Functional fit -fixed x-offset



# a (x 

# f3)

200 

## 3

_

o

_ o

__

# oo**Hv** __ (B

- tu

_ s'o

_ :

_

f)

__ soo

- 700

- 

# aoo

-

_ _]