From: "Ron Chittim" [Chittim@api.org] 

Sent: 09/21/2010 08:31 AM AST 

To: Brenda Shine 

Cc: Bob Lucas; "Bennett, Charles D." <cdbennett@marathonoil.com>; "David Friedman" 

<DFriedman@npra.org>; Ken Hustvedt; <wwehrum@hunton.com> 

Subject: NSPS Ja - Refining Industry Responses to EPA's 3 Questions 

Brenda - EPA previously asked the refining industry (API, NPRA & WSPA) to provide additional 

information/data on 3 topics: monitoring, necessary flaring & RCA/FMP. In response to your 

request, attached are separate write-ups on each topic. Also attached is a presentation by 

BAAQMD on flare minimization plans that provides additional information. 

 

Please review this industry input and let us know if you have any questions. Recall that several 

industry representatives will be meeting with you next week to discuss this package further. Feel 

free to raise any questions at that time also. thanks. 

 

Ron Chittim 

API 

202/682-8176 

chittim@api.org

<< Monitoring - Flare Flow-No Flow Reply to EPA (9-21-10)(Final).pdf >> 

<< Necessary Flaring - NSPS Ja (9-21-10)(Final).pdf >> 

<< Flare Management Plan - Input to EPA (9-21-10)(Final).pdf >> 

<< EPA - BAAQMD Petroleum Refinery FMP (8-26-10).pdf >> 

From: Shine.Brenda@epamail.epa.gov

Sent: Fri 7/30/2010 2:49 PM 

To: Ron Chittim 

Cc: Lucas.Bob@epamail.epa.gov; Bennett, Charles D.; David Friedman; 

Hustvedt.Ken@epamail.epa.gov; wwehrum@hunton.com

Subject: Re: Draft NSPS Ja Questions for EPA 

Sorry Ron, I missed this email, but Bill has been leaving me messages to take a look. 

I think these questions below are okay and they do reflect the conversation we had, and they will 

inform us. 

Thanks. 

Brenda Shine 

Environmental Engineer 
US Environmental Protection Agency 

Research Triangle Park, NC 27711 

(919) 541-3608, Mail Drop E143-01 

From: "Ron Chittim" [Chittim@api.org] 

Sent: 07/23/2010 02:31 PM 

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

Cc: Bob Lucas/RTP/USEPA/US@EPA, Ken Hustvedt/RTP/USEPA/US@EPA, "Bennett, 

Charles D." <cdbennett@marathonoil.com>, <wwehrum@hunton.com>, "David 

Friedman" <DFriedman@npra.org> 

Subject: Draft NSPS Ja Questions for EPA 

Brenda – following up on our call earlier this week, EPA requested some additional information 

from the refiners on the NSPS Ja issue. I have drafted the questions below in an effort to respond 

to your request. Please look over the questions and let me know if I am asking for the right 

information or edit/comment the questions as needed. After I hear back from you, I will send out 

the questions to our group and begin to collect the information/data. Thanks. 

• Monitoring - How accurate/sensitive is the water seal for determining flow/no flow? For 

specific situations where flow monitoring may not be required, what will show/record an indication 

of flow? 

• Necessary Flaring – We need information/examples of situations where flaring is necessary 

and can’t be handled by Flare Management Plans (Root Cause Analysis and Corrective Action). 

 

• Flare Management – We need information/data to show that implementation of Flare 

Management Plans really does reduce flaring. [OECA CD emission trends improvements from 

refinery flares and information from refinery CD semi-annual reports on flare events and CAs 

should help with this question] 

Ron Chittim 

API 

202/682-8176 

Chittim@api.org 
API/NPRA/WSPA Input to EPA Sept. 21, 2010

EPA Question #1

Monitoring - How accurate/sensitive is the water seal for determining flow/no flow? For specific 

situations where flow flare gas monitoring may not be required, what will show/record an 

indication of flow? 

API/NPRA/WSPA Response:

Flare Seal Monitoring

Where a flare seal drum is employed on a flare system, flare flow can be determined by monitoring 

various parameters, as discussed below. This type of flare flow monitoring should be allowed by the 

rule for determining flow/no flow for these types of systems. 

A simple comparison of the seal pot water level and the seal pot flare header pressure is a reliable 

and accurate method to determine whether flaring is actually occurring in a flare system that uses a 

flare seal drum. As long as the flare seal remains intact, there is no gas flow to the flare and any 

flare gas flow meter reading should be discounted as instrument noise or circulation in the line. The 

South Coast Air Quality Management District and the Bay Area Air Quality Management District both 

accept these measurements as indicators of no flow, overriding any indication of flow by a flare gas 

flow meter.

The water level in a flare drum is normally maintained using an overflow weir inside the drum. 

Make-up water is supplied as needed to maintain the level. In some designs a continuous water 

flow is maintained. Flares seals are monitored by continuously monitoring the water level on the 

upstream side of the weir and either the flare gas header pressure or the delta pressure up and 

downstream of the water seal. Water level can vary somewhat as the flare header pressure and 

water makeup varies, but as long as the water level stays above the level of the submerged flare gas 

header, no flow to the flare has occurred. Water seals vary in height depending on the size of the 

drum, the size of the flare header and the characteristics of the gas streams that are potentially 

routed to the flare. Thus, the backpressure the seal exerts on the flare header varies. Typically, this 

backpressure is in the order of 0.1-1.0 psi, corresponding to roughly a 3” to 30” water seal. In 

systems where the flare stack exerts negligible backpressure (or constant and known backpressure) 

on the seal drum, a pressure monitor in the flare header upstream of the water seal can readily 

indicate that the design backpressure has or has not been exceeded. Since flare headers are 

typically large diameter and for safety reasons do not have liquid seals other than the seal drums, 

the upstream pressure measurement can be made in the flare header anywhere between the last 

gas entry point and the seal drum. In systems where the flare stack has a significant backpressure 

or is variable at low gas flows, the delta pressure is monitored.

In addition to whether upstream pressure or seal delta pressure are monitored and the specifics of 

where those monitors are located, the level and pressure that indicated the water seal has been 

lost, is specific to every individual flare seal drum. Therefore, it is recommended that, where a 

source opts to use this monitoring, they specify in the FMP the parameters that will be monitored 

and the criteria that will be used to determine seal loss. For water seal systems in use, it is reported 

that properly designed and maintained systems are accurate and consistent in determining flow/no 

flow for flare events.
API/NPRA/WSPA Input to EPA Sept. 21, 2010

In a particular, a flare system on the West Coast uses the comparison of the seal pot water level and 

the seal pot flare header pressure as an accurate method to determine whether flaring occurs. As 

long as the seal pot flare header pressure (typically measured in inches of water pressure) is lower 

than the seal pot water level in inches of water, there cannot be any flaring since the water seal is 

intact. “This method is recognized by both the BAAQMD and SCAQMD as appropriate to ensure the 

compliance with flare operations and reporting. [Bay Area Air Quality Management District 

(BAAQMD) Regulation 12-12-501; South Coast Air Quality Management District (SCAQMD) Rule 

1118].”

Water seals are more accurate than flow meters for determining flow/no flow since a flow meter 

will typically show “noise” that may indicate flow when there really is no flow. The water seal will 

prevent flow (and will indicate no flow) as long as the flare header pressure is less than the pressure 

of the water seal.

Below is information on the dynamics of a typical liquid seal on a flare system and how it can be 

used to determine flow/no flow to the flare:

A pressure transmitter upstream of a liquid seal is at least as accurate at detecting a flaring 

event as a flow meter, so long as the liquid seal height is maintained and the liquid seal 

mechanical integrity is not breached. Furthermore, in systems with a conventional flare flow 

meter to detect flaring, the pressure transmitter enables a low flow signal to be assessed if it is 

indeed a flaring event or a “phantom” flow.

Liquid Seal Operation:

The liquid seal provides 2 key functions. First and foremost, it prevents air from the flare (item 

1) from flowing into the flare header (item 2), which could create a combustible mixtures of 

gases. Second, the liquid seal prevents gas from the flare header from escaping to the flare 

unless it builds up sufficient pressure. The liquid seal operates by having the flare header (item 

2) with a tip (item 7), commonly known as a “seal leg”, submerged under a water level (item 8). 

The water level is fixed due to an overflow baffle (item 9). To ensure the water is always 

overflowing the baffle, there is a make-up water supply (item 6). The depth of water above the 

highest opening on the seal leg is the seal depth. Common liquid seal depths range from 4” to 

24” inches, though seal depths outside of the range are in use. The seal operates by requiring 

the gas in the flare header to pressure up and displace the water depth in the seal leg before the 

gas can escape into the flare. For a 4” water liquid seal, the flare header must increase in 

pressure to 0.14 psig to overcome the liquid seal. For a 24” water liquid seal, the flare header 

must increase in pressure to 0.87 psig to overcome the liquid seal. If the liquid seal is not 

overcome, there is zero gas flow from the flare header to the flare. Therefore, if the integrity of 

the liquid seal can be guaranteed, no gas emissions may be assured.
API/NPRA/WSPA Input to EPA Sept. 21, 2010

Typical Horizontal Flare Seal Drum

In conclusion, the comparison of the seal pot water level and the seal pot flare header pressure is a 

reliable and accurate method to determine whether flaring occurs. As long as the seal pot flare 

header pressure (typically measured in inches of water pressure) is lower than the seal pot water 

level in inches of water, there cannot be any flaring since the water seal is intact. Therefore we 

recommend this method be incorporated into the rule for determining flow/no flow for flares that

have a seal drum system.
API/NPRA/WSPA Input to EPA Sept. 21, 2010

EPA Question #2

Necessary Flaring – We need information/examples of situations where flaring is necessary 

and can’t be handled by Flare Management Plans (Root Cause Analysis and Corrective Action

Analysis). 

API/NPRA/WSPA Response:

Industry believes Root Cause Analysis (RCA) and Corrective Action Analysis (CAA) are powerful 

elements of Flare Management Plans (FMP) and have been proven effective in dramatically 

reducing flaring at refineries. 

However, the refining industry’s experience for almost ten years demonstrates that use of RCA 

and CAA on flare events is not appropriate in all cases (e.g., for certain types of streams).

Industry suggests that EPA focus the use of RCA and CAA on flaring events where it can have an 

impact on emissions reductions (e.g., typically unplanned events such as malfunctions).

Industry considers it useful to define this limited subset of flaring events which can be classified 

as “baseline” flaring events, and subject to a one-time minimization evaluation as part of the 

FMP, but not make them subject to the RCA/CAA requirement. In general, “baseline” flaring 

events are those which are necessary for the safe and proper operation of the refinery, or which 

are necessary to effect control of emissions as required by EPA, state, or local regulations. 

These types of flare events would be evaluated on a one-time basis as part of the FMP.

Industry recognizes a need for additional clarity on baseline flare flows and presents typical 

examples of baseline flaring events in the table below:

“Baseline” Flow Type Comments

Sweep gas (introduced into the flare header 

system upstream of the flare)

Necessary to prevent dead spots in flare 

header system and consequent danger of 

pyrophoric ignition. Additionally, increased 

amounts of sweep gas are necessary after hot 

flaring events and during storms to prevent 

thermal contraction of gas in the flare header 

which can lead to flow reversal in the header 

and introduction of O2, creating a significant 

safety risk. Diurnal, seasonal and operating 

conditions account for some necessary 

variability in the amount of unique flow for 

each given flare system.

Purge gas (introduced at flare) Necessary to prevent O2 infiltration into the 

flare stack and the associated safety risk.

Fuel gas imbalance and hydrogen venting

(Note: this situation is addressed explicitly by 

§63.103a(a)(5) of the Reproposal’s FMP 

provisions. It’s not clear to INDUSTRY why this 

should be also subject to RCA/CAA.)

Cause may be structural (related to the 

inherent configuration or location of the 

refinery and/or offsite fuel gas consumers), 

seasonal (related to inability to reject heat 

from a process during high ambient 

temperatures, typically during summer 
API/NPRA/WSPA Input to EPA Sept. 21, 2010

months), or operational (related to the 

planned or unplanned shutdown of fuel gas 

consumers). This may also occur when 

customers can’t purchase normal amounts of 

gas from refineries that produce excess 

refinery fuel gas.

Coker blow down in compliance with the NSPS 

Ja fuel gas limit

After coke drum pressure diminishes to a level 

below which it’s not possible to route this 

stream to the coker’s hydrocarbon recovery 

equipment.

Venting of accumulated inert and noncondensable gases from process vessels or 

other equipment

Necessary to avoid gas pockets at the top of 

distillation columns, condensers, etc. and thus 

to prevent upsets and poor operations. These 

turnaround activities are typically addressed in 

SIPs.

Environmental Control such as (but not limited 

to):

Vapors generated during product loading 

operations

Fugitive venting (filters, pumps, and 

compressor seals, etc)

Analyzer vents, instrument tap 

blowdowns, sampling vents

Wastewater, sumps, etc.

Tank inerting vents

Closed Vent systems

Misc Process Vents (e.g., under MACT CC)

Venting during catalyst changeout, 

regeneration, and conditioning operations 

Planned startup and shutdown related venting

(Note: this situation is addressed explicitly by 

Section 63.103a(a)(3) of the of the 

Reproposal’s FMP provisions. It’s not clear to 

INDUSTRY why this should be also subject to 

RCA/CAA.)

Due to the unique configuration of each refinery and its flare systems, other necessary flaring 

may be needed as costs for controls may exceed BDT levels.

Because it is not know what final direction EPA might take on FMPs, INDUSTRY is providing some 

additional thoughts on “Necessary Flaring” to add support to our previous comments:

Quantification: Usually, emissions from “baseline” flaring activities are at least theoretically 

quantifiable, so a calculation can normally be made of typical aggregate base-case flow rates to 

a flare. This baseline can serve as the floor for establishing the RCA/CAA trigger.
API/NPRA/WSPA Input to EPA Sept. 21, 2010

Control of baseline events: Industry believes the initial “assessment” required under the 

reproposed Flare Management Plan (FMP) provisions [at §63.103a(a)(1)] constitutes

appropriate NSPS-level control on these necessary activities.

Flaring During Startup and Shutdown and Fuel Gas Imbalance: Industry believes requiring RCA 

and CAA for flare flows associated with planned startups and shutdowns is redundant, since 

those events are already subject to both the initial assessment [at §63.103a(a)(1)] and the 

particular requirement to develop procedures to minimize flows on startup and shutdown [at 

§63.103a(a)(3) and (5)].

Repetitive RCA and CAA: In general, industry believes the FMP provisions in the reproposed 

NSPS Ja provide refiners with considerable incentive to minimize flare flows or to develop 

appropriate alternative dispositions for them. However, industry believes that even with an 

effective flare management plan, some flows probably would still be sent to a flare for two 

principal reasons:

The complexities of configuration and operation of a petroleum refinery make it difficult 

to comprehensively list in advance, and plan for minimization of, all events which might 

lead to flows to flare.

Control of some flows, even when identified, will probably not be feasible within the 

limits of best demonstrated technology or best practices in industry.

For such flows, it seems to not make sense to require repeated use of RCA and CAA each time 

the same event occurs. Accordingly, industry believes that for events where the results of a 

previously-conducted RCA and CAA are applicable, the refinery operator should not be required 

to repeat these evaluations. In such cases, the operator should be allowed to implement 

previously-developed corrective actions.
API/NPRA/WSPA Input to EPA Sept. 21, 2010

1

EPA Question #3

Effectiveness of Root Cause Analyses (RCAs) and Flare Management Plans (FMPs) on Reducing the Number 

and Magnitude of Refinery Flare Incidents

API/NPRA/WSPA Response:

EPA has asked for information/data to help support the position that implementation of RCAs and FMPs 

have had a measureable effect on reducing the number and magnitude of refinery flare incidents. Under 

the New Source Review (NSR) Consent Decrees (CDs), many refineries have been required to perform RCAs 

for all acid gas flaring, tail gas incineration, and hydrocarbon flaring incidents that exceed 500 lbs SO2/24 hr 

period. In addition to identifying the root cause of the incident, the RCA also includes corrective actions 

designed to prevent a recurrence of the incident. These RCAs are required to be reported to EPA. The RCAs 

for acid gas and tail gas incidents must be reported within 45 days of the cessation of the incident. The RCAs 

for hydrocarbon flaring incidents must be reported in the subsequent Semi-Annual Report.

In California, both the South Coast Air Quality Management District (SCAQMD) and the Bay Area Air Quality 

Management District (BAAQMD) have issued rules requiring reductions in flare emissions via such 

mechanisms as RCAs and FMPs. Both agencies have published information on the effectiveness of these 

rules. 

Attached are data from several refining companies which document reductions in the number and 

magnitude of flaring incidents post implementation of the NSR CDs and the California flaring rules.
API/NPRA/WSPA Input to EPA Sept. 21, 2010

2

ABC Refining

Our NSR CD requires that each refinery perform a root cause analysis, including identification and 

implementation of reasonable corrective measures, for all acid gas, tail gas, and hydrocarbon flaring 

incidents (i.e. >500 lbs SO2/24-hr ). As of 2009, we have reduced the annual number of these flaring 

incidents by ~50% since the inception of the CD (see charts below). This reduction in the number of 

incidents is in large part attributable to the focus on detailed root cause investigations and implementation 

of corrective measures to prevent recurrences. Root cause analyses/corrective measure reports for all 

flaring incidents have been submitted to the EPA as required by the CDs (within 45 days of the incident or in 

the Semi-Annual Reports). 

ABC Refining: NSR CD Hydrocarbon Flaring Incidents

0

20

40

60

80

100

120

2006 2007 2008 2009

No. of Incidents

ABC Refining: NSR CD Acid Gas Flaring & Tail Gas 

Incineration Incidents

0

5

10

15

20

25

30

35

2006 2007 2008 2009

No. of Incidents
API/NPRA/WSPA Input to EPA Sept. 21, 2010

3

XYZ Refining

The NSR CD root cause analyses and implementation of corrective actions have had a significant impact on 

our flaring operations. We have taken steps to ensure that unit operators now understand and can stay 

within the capacity of the flare gas recovery compressors. Attached below is a statistical summary of flaring 

events (e.g., streams getting by the compressors to the flare tip which resulted in > 500 lbs SO2/24 hrs)

which illustrates the reduction in events over time.

86

39

76

23

58

10 13

27

19

35

24 27

16

10

6

9

3 3

0

10

20

30

40

50

60

70

80

90

2001 2002 2003 2004 2005 2006 2007 2008 2009

Operating Year

XYZ Refining 

Hydrocarbon Flaring Incidents 

Excess Sulfur Dioxide Emissions (TPY) Number of Incidents

Flaring Events with greater than 500 pounds of sulfur dioxide 
API/NPRA/WSPA Input to EPA Sept. 21, 2010

4

24

15

9 4 6 3 4 4 7 2 2

54 50

28 30

17

48

4

110

28

10 6

0

20

40

60

80

100

120

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Operating Year

XYZ Refining 

Acid/Ammonia Gas Flaring Incidents 

No. of Events Sulfur Dioxide Emissions (TPY)

DEF Refining

Our plants that have implemented RCAs and/or FMPs have demonstrated a very significant reduction in 

flaring. For example, our California plants have demonstrated reductions in emissions of about 61% 

(Refinery A) and 89% (Refinery B) since they implemented RCA/FMPs in response to the NSR Consent 

Decree and regulatory requirements. This reduction is attributed primarily to root cause analyses and 

assessments of ways to reduce startup/shutdown flaring.

GHI Refining

Refineries A & B implemented a “flare policy” in 2001. While the “flare policy” contains many of the 

elements of the flare management plan and root cause analysis described in NSPS Ja, the elements are 

not aggregated into a single document. The “flare policy” serves as a general policy statement regarding 

internal goals to minimize flaring. Below is a chart showing the average time in the flare for Refinery A 

and Refinery B. The bump up in 2008 was due to planned maintenance on the flare gas recovery system 

at Refinery A.
API/NPRA/WSPA Input to EPA Sept. 21, 2010

5
k • 4

.. 1(:

BAYAUA

AIRQyAUTY

MA AGUU T

DISTllCT

Agenda: 5

Petro eum Refinery

are inimization Plans

Introduction

Background

2nd MP Annual Updat

Flare Emission Trend

Pr v ntion ea ur

Flare etrics

Continuous Improvern nt

1
Typical I re System

c-':.)

SJid~ J

Background

Each Flare Minimization Plan mu t includ :

../' B ic d ign and operation of flare gas rec very y terns·

../' Pr v ntion m a ur ummary- and

../' dditional feasible measures implementati n chedule.

,. lnitial F P approv d July 16, 2007.

,. FMP irst nnual Update approved pril 17 2009.

, FMP Second Annual Update approved Dc mb r 29 2009.

fit Disu:cr

2
2nd FMP Annual Update

Submitted October 1, 2009

District Analysis

-/Completeness and feasibility.

Public Comment Period

-/October 16,2009 - November 14, 2009.

Continuous Improvement

-/ Over SO prevention measures for minimization.

BayArm Air QrtDIity Managemem District SlideS

Flare Emissions Trends

Regulations are effective.

Total hydrocarbon emissions down from 8 tons per day to

0.4 tons per day.

Significant reduction in vent gas volumes to flares.

Flare emissions continue to decrease.

IkIyArm AirQrtDIity Management District Stide6

3
Flare Volume and

drocarbon Trend

finery v. G Flow & He EmJUJOM

v

&n ,lrl"d ,/lr Q,uIJIII' MtlJltI~<III"1I/ nUll IN

Flare Monitoring Rule

Rare Control Rule

Yo...

1

~!• no

Slide

Vent Gas Volume

Refinery Vent Gas Volume Flared

1600

J 1400

0_ 1200 - . I.L~ 1000 .0

e"W 800

.. 600 c_ 400 > 200

0

• Chevron

OCP

OSheU

• Tesoro

10 Valero

2004 2005 2006 2007 2008 2009

Year

4
etha e mi sions

Flaring CH4 Emissions

I_che...-onl

J---==---------- DC?

OShel

I

_Tesoro

Valero

40

E

w 20

;- 100 ,--------------,

Q.

C 80

c 60 .2

J:

(J

2004 2005 2006 2007 2008 2009

Year

"TPY • Ion. per

8m, fir (l",,1 I)' Mnnalltmrnl Ihrtria S/id~ \I

on-Methane ydrocarbon Emissions

Flaring NMHC Emissions

350 ,-----------.....,

.2. 300 +-.__------------1 ,...------,

- 250 +-1.--1-------------1 - Chevron

> O~

... 200 OShel

(J - 150 _ Tesoro

100 Valero

50

o

2004 2005 2006 2007 2008 2009

Year

'TPV • toni 1* yeet

&n Irm I" Qllt/lm U JfPIIml Dulna SliM /0

5
8ulfi r Dio id

Flaring 502 Emissions

&Jallaa.:Jsions

800 ,...--------------, e: 700 i-t__----------j __---,

-; 600

c 500

oS! 400 •

300

E 200

w 100 N

o 0 ...........a.-.,-= '--'--L=..-.I~-.--JI~

en

2004 2005 2006 2007 2008 2009

Year

II", lit" lIT Q""IIO \(aAl mrnt Dlstrin ./~ II

Prevention and Minimization

Source Reduction

,. V nt Ga Compressor Capacity

y Fu I Ga Balance

, Scrubbing Sour Gas es

/1

6
Source Reduction Measures

Pre-turnaround flare minimization planning.

)0 Additional instrumentation for real-time monitoring of

headersystems.

)0 Flare gas used as fuel for cogeneration plant.

)0 Re-routing ofprocess streams.

)0 Unit feed ,reductions and process cuts.

)0 Improved startup/shutdown procedures.

Bay AmI Air(}ua/ily lIlanagemelll District SlidelJ

Recovery Compressor Measures

)0 Installation ofnew compressors & re-servicing existing

compressors to flare gas recovery.

)0 Improvements in flare gas recovery compressor

reliability:

./ Upgrades to compressor internals to increase MW range and

reduce overheating.

./Improved knockout drum monitoring.

)0 Modifications to cool vent gases in flare headers before

compressors.

Bay AmI Ai, QIIQ/ity Management District SlideU

7
Fuel Gas Balance Measures

Modifications to Cogeneration Steam Generator to bum

low btu gas.

»Addition of a new Delayed Coker to reduce amount of

fuel gas produced.

Re-routing ofvent gases into processes heaters.

»Improved monitoring ofprocess vents to flare system.

Improved communications among unit operators.

Bay Area Air Q/lillity Mana~m~nl DUlricl Slide IS

Sour Gas Scrubbing Measures

Minimizing vent gas to flare to reduce Sulfur Dioxide

emissions.

»Temporary spare scrubbing unit during primary

scrubbing unit maintenance.

Back-up powersupply for scrubbing system.

New sulfurrecovery plant including new sour water

stripper and amine regeneration.

Bay Area AirQrlillity Mt/lla~ment District Slide /6

8
lare egulation iolations

om 111..11 C nI Aan'

Rl.'finl.'ry To"" \loaleoriDl: R<a>rdJ "ooleoria\: \lIn1mJullo" 'oM) C.llul Ao"

ChC"TOn 24 11 5 I I

C 0-

Phillips II 6 I 4

Shell 2 2

TC!>Of'O 14 1 4 J

Valero IS 11 I 2

Total 66 44 6 - I .. 3

&n Irt,..~U" Qt IIIl It tnlDwria

Flare Minimization

ttk I

etrics

5 Year Rolling Averages Period Ending 2008 vs. 2009

1200 t=======;::::===-------------.....:..:--.~

8",

1000 I------t

800 t--4""-----J

600

200

0+----

..l".

"JrQuaJ/f\ .11""" trU!nt DiHrra

(IOnS)

CH4

Slak I,

9
Continuous Improvement

Regulations are effective and considered as model for

other agencies.

Causal reports and lessons learned yield additional

feasible prevention measures.

3rd Annual Flare Minimization Plan Update due

October 1,2010.

Reductions; 56% in volume and 69% emissions!.

I Comparison ofIlaril1s befolll VI. after f1alllllllJll1lllons

Bay Area Air QII/J/ity M(JfIIJgemeni District Slide 19

10