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 indust ry (API, NPRA & WSPA) to provide additional information/data on 3 topics: monitoring, necessa ry 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 EngineerUS 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 dra fted 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.orgAPI/NPRA/WSPA Input to EPA Sept. 2 1 , 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, f lare flow can be determined by monitoring various parameters , as discussed below . T his type of flare flow monitoring should be allowed by the rule for determining flow/no flow for t hese types of systems

. A simple comparison of the seal pot water level and the seal pot flare header pressure is a reliable and accurate meth od to determine whether flaring is actually occurring in a flare system that uses a flare seal drum

. A s 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 i nstrument noise or circulation in the line. T he South Coast Air Quality Management District and the Bay Area Air Quality Manage ment 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 a s 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 u p 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 seal s 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 backp ressure 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 measuremen t 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 upstr eam 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 syst ems are accurate and consistent in determining flow/no flow for flare events.API/NPRA/WSPA Input to EPA Sept. 2 1 , 2010

I n a particular, a flare system on the W est C oast uses the comparison of the seal pot water level and the seal pot flare header pressure as an accurate method to determine wheth er 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 recog nized by both the B A AQMD and S C AQMD 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]. ”

Wa ter 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 flow ing 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 overflow ing 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 flar e 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, t he 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 emi ssions may be assured.API/NPRA/WSPA Input to EPA Sept. 2 1 , 2010



### Typical Horizontal Flare Seal Drum

In conclusion, t he 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 p ot 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 ru le for determining flow/no flow for flares that have a seal drum system

.API/NPRA/WSPA Input to EPA Sept. 2 1 , 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 R oot Cause Analysis (RCA) and Corrective Action Analysis (CAA) are powerful elements of F lare M anagement P lans (FMP) and have been proven effective in dramatically reducing flaring at refineries.

However, t he 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., fo r 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 malfun c tions )

. 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 F MP, 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, stat e, 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

e xamples o f baseline flaring events in the tabl e below:

“Baseline” Flow Type Comment s 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 swee p 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 operat ing 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 a nd 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 summerAPI/NPRA/WSPA Input to EPA Sept. 2 1 , 2010

months), or operationa l (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 b low down in compliance with the NSPS Ja fuel gas limit After coke drum pressure diminishes to a le vel below which it’s not possible to route this
stream to the coker’s hydrocarbon recovery equipment. Venting of accumulated inert and non

condensable gas es 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 l oading operations Fugitive venting (filters, pumps, and compressor seals, etc) Analyzer vents, i nstrument tap blowdowns, s ampling 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 R CA/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 providin g some
a dditional t houghts 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 agg regate base

- case flow rate s to a flare. This baseline can serve as the floor for establishing the RCA/CAA trigger.API/NPRA/WSPA Input to EPA Sept. 2 1 , 2010

Control of baseline events : Industry believes the initial “ assessment ” required under the reproposed F lare M anagement P lan (FMP) provisio ns [at §63.103a(a)(1)] constitute s 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 shut downs 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 CA A: In general , industry believes the FMP provisions in the reproposed NSPS Ja provide refiners with considerable incentive to minimize flare flow s or to develop appropriate alternative dispositions for them. However, industry believes that even with an effect ive 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 minimi zation 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 se nse 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. 2 1, 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 fl aring, 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. The se RCAs are required to be reported to EPA. The RCAs for acid gas and tail gas incidents must be rep orted 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 publi shed 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. 2 1, 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 ).API/NPRA/WSPA Input to EPA Sept. 2 1, 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 u nit 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

.API/NPRA/WSPA Input to EPA Sept. 2 1, 2010

4

D EF Refining

Our plants that have implemented RCAs and/or FMP s have demonstrated a very significant reduction in flaring. For example, our California plants have demonstrated reductions in emissions of about 61% ( R efinery A ) and 89% ( R efinery B ) since the y 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 po licy 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. 2 1, 2010

5

### k • 4



# .. 1(:

BAYAUA AIRQyAUTY

MA AGUU T

DISTllCT 

### Agenda: 5



## Petro eum Refinery

are inimization Plans



# Introduction

Background

2 nd 

### 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

# 2 nd 

# 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.

Bay Arm 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.

IkIy Arm Air QrtDIity 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



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## 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 header systems.

)0 

## Flare gas used as fuel for cogeneration plant.

)0 

## Re-routing of process 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 of new 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 of vent gases into processes heaters.



# » Improved monitoring of process 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 power supply for scrubbing system.

New sulfur recovery plant including new sour water stripper and amine regeneration.

Bay Area Air Qrlillity**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. 3 rd 

## Annual Flare Minimization Plan Update due October 1,2010. Reductions; 56% in volume and 69% emissions!.

I Comparison of Ilaril1s befolll VI. after f1alllllllJll1lllons

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



### 10