# E C



# / R Incorporated

Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 25 0  Chapel Hill, North Carolina 2751 4

Telephone: (919)484

- 0222  Fax: (919) 484

- 0122 

## MEMORANDUM

Date: October 14 , 2010

Subject: Summary of the October 12

, 2010 Meeting between the Environmental

Protection Agency (EPA) and American Petroleum Institute (API)

From: Denise Grubert , EC/R Incorporated

To: Bruce Moore, EPA/OAQPS/SPPD/CCG

I. PURPOSE

This memorandum summarizes the October 12 , 2010 meeting between the EPA and industry

representatives from API . The meeting was requested by API as a follow

- up to a September 9,

2010 conference call. The intent of the assembly was to further discuss current informational

needs , methodology, and as an opportunity for EPA to inquire information in regards to control

technologies.

II. DATE

The meeting took place on October 12, 2010 from 1p.m . to 4:45 p .m. at the United States

Environmental Protecti on Agency in Research Triangle Park, North Carolina.

III. ATTENDEES

The following individu als were present at the meeting. Please note this may not be an extensive

list, but represents the names of people who signed the attendance sheet.

Industry Representatives

A merican P etroleum I

nstitute : Matt Todd

Kathy Kalisz (Phone Call

- In)

B ritish P etroleum : Jeffrey A. Adams

Chevron : Clay Fleeberg,

Janet Bounds (Phone Call

- In)

Shankar Ananthakrishna (Phone Call

- In)

ConocoPhillips : Clint Gill

ExxonMobil : Tom Monahan

Marathon Oil : Jenny Yang

Shell : George Deeley

# E C



# / R Incorporated

Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 25 0  Chapel Hill, North Carolina 2751 4

Telephone: (919)484

- 0222  Fax: (919) 484

- 0122 

## U.S. Environmental Protection Agency (EPA /OAQPS /SPPD/CCG )

Bruce Moore

Nick Parsons

Anne Pope

Dav id S alman

EC/R Incorporated

Heather Brown

Denise Grubert

Phil Norwood

IV. SUMMARY OF DISCUSSION

The meeting was scheduled in response to the phone conference between EPA and API on

September 9, 2010. This meeting provided EPA an additional opportunity to ask specific

questions regarding control options for various emissions sources. Prior to the meeting, Rachel

Agnew of EPA, e

- mailed Matt Todd of API directed questions to facilitate the discussio n

regarding c losed

- loop systems , p neumatic controllers/valves , and c entralized gathering system s

for produced wate r . API provided written response which is provided as Attachment I

.

Bruce Moore of EPA reiterated EPA’s position on find ing cost

- effective cont rols that reduce air

pollutants; as there is growing public concern on air emission sources from Oil and Gas dr illing

and production, which is rapidly exp anding in the public’s backyard.

API then began discussion on specified control topics. In regards to central ized liquid gathering

systems, t he decision to install a system varies based on field parameters, volum e of the

produced water and economics

. Ideally, centralized liquid gathering systems would appear at

new fields at the time of production.

API clarified their interpretati on of the term “closed

- loop.” Closed

- loop systems capture gas and

funnel gas back towards the sales line. This must occur at very low pressure.

EPA mentioned Uniform S tandards were likely to impact what and how we regulate certain

sources in the future. Several uniform standards that could eventually impact this rulemaking

include: wastewater treatment, storage tanks, leak detection and repair (LDAR) including

ancillar y equipment, heat exchangers, and closed vent systems (includes flares)

. It was noted that

applicability would have a major role in determining the sources regulated and what level of

regulation.

Phil Norwood from EC/R asked API to comment on flare techn ology including efficiency, the

current use of portable flare devices , and limitations of flares as a control device. API responded

that VMAX is a concern under 40 CFR 60.18. John Zinck is currently working on an issue paper

# E C



# / R Incorporated

Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 25 0  Chapel Hill, North Carolina 2751 4

Telephone: (919)484

- 0222  Fax: (919) 484

- 0122 

## regarding VMAX and flares and A PI has commented that they will send EPA the study . It was

noted that Sonic flares, which have high efficiency, are not allowed under 40 CFR 60.18 due to

the c ontinuous pilot requirement. Continuous pilots are also a hindrance because in some

applications , i.e. unmade remote locations, electric ignitions would be preferable. In instances

that do not apply to the rule, sonic flares have successfully controlled emissions.

LDAR was presented as a topic. API stated that the “Drill and tap” is not a typical practice as

defined in another rulemaking and most companies must use costly third

- party contractors. This

becomes highly expensive when performed in remote areas. In addition, API mentioned the 15

day time period is not long enough when in remote areas wi th contractors. In addition, API

restated their preference for A udio, V isual O lfactory (AVO ) versus EPA’s Method 21, especially

a t remote locations. FLIR camera s are a great option, but costly (Capital over $100,000 and

annual costs of $1,000) and there are limited contractors with proper training. API is highly

concerned with keeping track of tags [required in Method 21 when leak is detected]

. EPA

questioned the efficiency of AVO at production facilities when odor has not been added to the

gas stre am. API mentioned due to pressure, you can hear and sometimes see vapors raising off

pipes much like heat. Bubble solution already incorporated into normal work practices.

EPA asked API for comments on compressor seals, which are exempt under the standa rd engine

rule. Specifically, EPA wanted to know the time between rod packing replacements. API

responded that it was variable and they would need to discuss with the operators in regards to

maintenance plans. It was suggested a potential for a phone cal l with a few engineers could be

possibly, but was not scheduled at this time. API suggested sending all questions through e

- mail

and written responses could be returned.

API raised concern about potential pneumatic controls. It seems as though EPA is foc using on

high greenhouse gas emissions and low VOC emissions, rather than sources with high VOCs and

HAP. EPA stated methane is currently being reduced as a co

- benefit, but it was possibl e to

redefine VOC service within the rule. API stated subpart KKK an d subparts VV/GGG have

different definitions, currently.

API was concerned that Oil and Gas would be the first industry regulated under 111(d) . There

was c oncern on the basis for cost

- benefit, as it is arguable hard to justify anything other than the

use of current market prices.

Under new ozone designations, API feels many counties will be non

- attainment when monitors

are in place. CTG may be more affective in non

- attainment ar eas. API mentioned it could be

more effective to include remote rule burden, much like the current HH regulation.

EPA discussed the potential emission floor of 1 ton of benzene could potentially be used. API

raised questions on record keeping for facilit ies above and below the emission floor. EPA

responded that nothing has been officially decided.

# E C



# / R Incorporated

Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 25 0  Chapel Hill, North Carolina 2751 4

Telephone: (919)484

- 0222  Fax: (919) 484

- 0122 

## In regards to Risk Assessment, have data from NEI database with 17,000 major emission

sources. After coordinates are assessed, could API potentially help loca te if incorrect? API

agreed. It was also noted that EPA has formulated dose

- response levels for ethyl

- benzene, which

were not included in risk assessments prior so this could change outcomes. API can check EPA’s

website for more information.

EPA raised a question regarding tanks and emission calculations

. Texas has a study where they

summarize acceptable methodologies. AP I ranked the foll owing (1) Prosy m, (2) E & P Tanks

, (3) GOR method, (4) Vasquez

- Beggs (limited applicability). API stated they feel AMINECALC

does a pretty good job at simul ating amine treaters. API also provided information, including a

handout which has been included as Attachment 2, on the geographical database for E & P

Tanks. TCEQ does not allow this in Texas, currently. Working a nd breathing losses from tanks

are better estimated using TANKS 4.09d. It could be appropriate for E & P Tanks to analyze C5

and higher. API raised a question from the prior meeting in July regarding thief hatches on tanks.

API has their own standards for tanks, but not thief hatches. Thief hatches need strong gasket

material appropriate for field parameters. To ensure p roper repair of gaskets there should be

enough time to perform repair. This only matters if the tank is controlled, and many are not

under control and vent to atmosphere.

API raised questions regarding gas composition formulated to estimate nationwide emissions.

Each basin is extremely variable within itself that API feels skeptical by just one estimate. EPA

explained the profile itsel f is not used to make decisions but gather information on average

emissions. EPA stated it would forward API more information regarding the composition.

EPA also provided API with emissions sources that are being considered for r egulation

, however, no final decision has been made. These sources may not include water pits, land farms,

pipelines. It was restated that no official decision has been made final.

API agrees with EPA that multi

- well sites are more effective for air emis sion controls, however,

there are many reason to discontinue use of multiple wells sites. API mentioned the new 1

- hour

NO X 

## is hurting centralized facilities.

API also stated they would send technical comments submitted to TCEQ that may be relevant to

emi ssion sources under consideration by EPA.

The meeting adjourned at 4:45pm (EST) . No addi tional meeting or phone call has been officially

scheduled at this time.OilandGasNSPS/NESHAPRuleControlTechnologyCentralizedWater“Treatment”EPAhasrequestedourcommentsregardingthefeasibilityofcentralized producedwater“treatment” versusthepracticeofhaulingwaterfromsmallerandmorenumeroustankbatteries.Thebenefitstheagencycurrentlyseesincentralizationare:-Reducedvehiclemilestravelled(loadingandunloading)-Fewercontrol devicesareneeded-Reductioninleaks-Smaller footprintTheoilandgasindustryuses thetermswaterstorageanddisposalinsteadofcentralizedwater treatment.Decisions regardingwater storageandtreatmentarebusinessdrivenbasedonoperationalneeds,flexibility,feasibilityconsiderations,costeffectiveness,proximitytowellsandproductionrates.Otherlimitingfactorsincludeavailabilityandlocationofdisposalwellswithadequate capacity,leaserequirements,pipelinecapacity,andright-of-ways. Economicsandoperabilityneedtoremaintheprimarydriversinfluencingtheneedforcentrallocationoffacilities.Furthermore,itwillbeverydifficult,ifnot impossible,toestablishacleardefinitionofthegeographic boundaryforanycentralfacility requirement.Thebest timetodeterminefeasibilityanddesignofacentralproduced waterfacilityisduringthedevelopmentplanningofanewproducingfield.Thehurdlesdiscussedbelowaremostprominentwhen lookingatthefeasibilityofcentralizinganexistingfieldor anin-fielddevelopmentprogram.Typically,central facilityconsiderationusingpipelinefeedsmakesthemostsensewhereoperatorshaveexclusiveleaserightsorareabletosecurejointinterest agreementsamongother operators that allowsharingofacentralfacilityforproducedwaterstorage.Thelimitationisthatleaserightschange,donotremainexclusiveandmaybecomejointagreements. Joint interest agreementsforcentralprocessingfacilitiescanalsohavelimitations.Theremaybelimitationsonproductionvolumescontainedinanagreementresultinginsettingcondensateandlorproducedwatertanksatthewellsitetoaccommodatetheadditionalvolumes,thereby,minimizingthebenefitofasharedcentralprocessingfacilityandresultinginincreasedemissions.Iftherearelease,distance,and/orpipelineright-of-wayproblems,acentralfacilitywithpipelinefeedsisnotpossible.Thefootprintandemissionswillincreaseduetoincreasedpipelineright-of-ways,andadditionalcompressorandpumpstationsmaybeneeded.Acentralfacilitymightstillbeconstructed,butsmallertankbatterieswouldstillneedtotruckwaterthroughouttheproducingareatothecentralizedwaterstorageanddisposalsite;therebyincreasingthevehiclemilestravelled.Considerationmustbegiventohowandwherethewaterwillbedisposed.TheoptimalsituationthatwouldmeettheEPAbenefitexpectationsisifthedisposalwell(s)is/areclosetothecentralfacilityandcanadequatelyhandlethethroughputvolumeatthefacility.Inthisidealscenario,watercouldbeseparatedneartheweilsite,pumpedtothecentraltankfacility,andtheninjecteddirectlyfromcentralstoragetothedisposalwell(s)whicheliminatesproducedwatertrucking.Ontheotherhand,ifproducedwaterdisposalcanbesenttoathirdpartydisposalsite,orthedisposalwellsneededtohandlethevolumearescatteredacrossthefieldanddistantlyapart,directinjectionfromthecentralfacilityislessfeasibleandwatermayhavetobetruckedtothedisposalwellsorlengthypipelinesmayhavetobeconstructedtoreachthedisposalwells.Economicsandpracticalitymightthenfavortruckingfromornearthepointofinitialseparation.Pipelineconstructioneithertoorfromthecentralfacilitypresentspotentialchallengesthatmakeitinfeasible.Milesofadditionalrights-of-waymustbesecuredseparatefromleaserights-of-wayfromproductflowlinesandpipelines.Theserights-of-waynegateanyfootprintreductionthatisperceivedfromconstructingacentralfacilityasvegetationmustbeclearedforconstructionandmaintenanceaccess.Dependingonthetopographyanddistancebetweenlocations,additionalpumpcapacityand/orpumpstationsmayberequiredtomaintainadequatepressuretomoveliquidstoacentralprocessingfacility.Aspipelinesareaddedfromwellsitestoacentralprocessingfacility,theriskofleaksactuallyincreases.Theleakpotentialincreasesbecauseofmanyfactors,butismainlyduetotheexposureofmorepipetovariousoperatingconditions(environmentalandphysical),adecreaseinsecurity,andanincreaseinpotentialfor3rdpartydamages.Finally,itisimportanttorememberthatanyadditionalpipingwillinevitablyincreaseexposuretoenvironmentallysensitiveareas(e.g.,rivers,creeks,wetlands,andwildlife).ClosedLoopSystemsSeveralcontroltechnologieslistedontheOilandGasVOCEmissionControlOptionstablecanbeconsidered“closedioopsystems”.APIdidnotspecificallyusetheterm“closedloopsystem”.Dependingontheuseanddesign,theEmissionControlTechnologieslistedbelowandhavingthesameidentifieronthesubjecttable,canbeconsidereda“closedloopsystem”:•“Collectionoflowpressuregasesintofuelsupply”•“VaporRecoveryUnit”•“GlycolDehydratorRichGlycolFlashSeparator”•“SecondarySeparatorforliquidstream”LeakDetectionandRepairProgramforOil&GasExistingSubpartKKKforNaturalGasProcessingPlantsTheexistingSubpartKKKrequirementsarestillprotectiveandthebestdemonstratedcontroltechnology.ThemorestringentleakratedefinitionspromulgatedfortherefiningandSOCMIindustriesarenotreasonablebecauseofthelightaverageMWofthesubstancesinthenaturalgasprocessingindustry.ThedefinitionofVOCservicewaschangedtoincludeunprocessednaturalgas(wetgas)thatisoftenover90%methaneandethane.ItisdifficulttostopleaksoftheselightgasestothelowlevelsmaintainedinrefineriesandSOCMIfacilities.Additionally,the“drillandtapmethod”ofinjectingvalvesealanthasbeenproposedtobeatechnicallyfeasibleon-linerepairmethodforrefiningandSOCMIfacilitiesbyEPAintheNSPS,SubpartVVreview(see71FR65309)inNovember2006.However,thisisnotthecaseforthenaturalgasprocessingindustryduemostlytotheremoteanddispersednatureofO&Gfacilities.RefiningandSOCMIfacilitiesaretypicallylocatedinneareachotherinconcentratedindustrialcenterswherethespecializedmaintenancecontractorsnecessaryforthe“drillandtapmethod”aremorereadilyavailable.However,O&GfacilitiesarelocatedinruralareasofColorado,Kansas,NewMexico,Oklahoma,Texas,Wyoming,Alaska,etc.wherethesecontractorsarenotavailable.FortheO&Gindustry,the“drillandtapmethod”isstillan“extraordinaryrepairmethod”becauseofthedistancecontractpersonnelandequipmentwouldhavetotraveltomaketherepairs.OilandGasProductionFacilitiesWhenpromulgatingNSPS,SubpartKKK,EPArightfullyrecognizedthattherequirementforfugitivemonitoringbyMethod21usinginstrumentstomeasurealeakratewouldbeburdensomeforevensmallgasprocessingfacilities,thusprovidedanexemptionforthesesmallfacilities(see4OCFR6O.633(d)).O&Gproductionfacilitieswouldbeevenmoreburdenedbythistypeofmonitoringrequirements.However,ifEPAbelievesthatLDARisrequiredfornew(afterproposaloftherule)O&Gproductionoperations,thenAPIbelievesthatauditory,visual,andolfactory(AVO)inspections(similartothoserequiredby4OCFR6O.502(j)forBulkGasolineTerminals)withbyexceptiondocumentationrepresentsBDCT(BestDemonstratedControlTechnology.By-exceptiondocumentationwouldconsistofimmediatelytagginganyleakfounduntiltheleakingcomponenthasbeenrepairedwithin15days.Theleakwillalsorequiredocumentationinaleakingcomponentlogandlorworkorder.RequirementstotagallfugitivecomponentsordocumentAVOinspectionswhereleaksarenotfoundwillbeexcessivelyburdensomebecauseoftheremoteanddispersednatureofmostO&Gproductionfacilities.ItisimportantthattheLDARprogramrequirementsbedesignedsuchthatoperatorscancompletetheserequirementswithintheirnormalinspectionandmonitoringroutines.Otherwise,addedvehiclemileswilloffsetanypotentialreductionsthatmayberealized.‘I

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Known Separator Stream lnlormatisn Control Etlicrency

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Data Output N ortheast AtI Regions H2S 0.0000

02 0.0000

C02 0.0100

N2 0.0100

Cl 4.3300

2.5800

3.4200

3.4300

3.7300

5.5500

36500

8.0700

1 4.6500

13.2600

7.8000

13.6300

0.5400

1.9200

0 1700

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4.4300

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E-Benzene

l<ylenes i.rrn.y

No API Gravity 

## I RVP [psia[ I Pressure[psig[ I Ternperatute [F)

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2_ 58 10.6 300 813

3_ 53 10.0 110 72

4 60 9.4 750 SO

5 61 70 85 85

6 61 9.8 730 84

7 62 10.4 57 82

8_ 63 7.0 72 80

9 63 11.9 730 80

00 64 6.4 580 77

64 11.0 730 80

02 66 11.8 807 96

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MW

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1 2 401

I 801

i Cl 604 

### I Sale Oil 

### I Flash Gas Tw&S Gas TiotalEmissions

07

10

8 C4___________ 812

9 nC4 812

10 CS 7215

11 nC5 7215

12C6 8816

13 C7___________ 100.21)

14 C8 114.23

15 9 12828

16 C10+ 16600

17 Bensene 78.11

18 Toluene 8213

19 E8enzene 10617

20 Xylenes 106.17

21 n•C6 86.18

22 224Trimethy 114.24

MW

Stream Mote Ratio

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4. 8300 0.2285 0. 0247 40.5828 9 1 644 38.6108

2.5800 0.5927 0.41 28 17.6576 20.3686 17 7424

34200 1 8651 1.6803 15.2168 23.2087 154666

3 4300 2.7565 2.6664 8 5398 14 3538 8 7215

3.7300 3.2826 3.2255 7.0488 12.1981 7.2098

5.5500 5.6805 5.6681 4 5601 8.3507 4.6786

3.6500 3.8346 3.8379 2.2492 4.2080 2.3104

8.0700 8 8085 8.8688 1.7007 3.3540 1 7524

146500 16.4468 165891 1 0169 2.1185 1 0514

13.2600 14.8703 151102 0.2843 0.6264 0.2948

7 8000 8.8206 8.8050 0 0564 0.1310 0.3587

19.6300 22.2172 224324 0.0008 0.0023 0.0008

0 5400 0.6005 0.6050 0.0811 0.1620 0 0836

1 9200 2 1626 2.1822 0.0794 0,1685 0.0821

01700 0.1821 0.1839 0.0023 0 0051 0 0023

2.2200 2.5092 2.5331 0.0255 0.0576 0.0265

4 4300 4.91 82 4.9541 0.7261 t 4561 0 7488

0 0000 0.0000 0.0000 0.0000 0.0000 0.0000

106.20 15.44 115.84 36.16 4989 3658

1.0000 0.8835 0.8798 0 1165 0.0038 0.1202

2081 33 2802.89 2103.87

1.25 1.72 126

18214 21 07 1343

316.85 85.54 71 87

0.681 0.692 0.693



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### Oil and Gas Flaring and Issues with 40 CFR §60.18

Introduction

For emissions control in oil and gas production operations, flare design and purpose is varied. Oil

and gas flares generally serve one or a combination of several different purposes

. Uses i nclude

continuous control for process operation s , standby for backup to primary control systems, and

blowdowns for maintenance startup shutdown (MSS) events or emergency upset events

. Each

use require s a flare design that is fit for purpose for optimum operation al efficiency.

In many cases, especially at newer, larger natural gas compressor stations and gas processing

plants, flares are designed to meet 40 CFR §60.18 requirements

. Even if there is no applicable

NSPS Subpart

, permits often refer to §60.1 8 for flare design . However, depending on operating

conditions , additional operating efficiencies would be possible if these sites were not restricted to

the continuous pilot and Vmax provisions of § 60.18

.

For situations or sites that don’t presently r equire a §60.18 compliant flare, flares may not operate

with a continuous 24/7 pilot or they may have “sonic” high velocity flare tips that exceed the

Vmax of 400 ft/sec in §60.18. In either case, if properly designed, these flares can meet or

exceed the control efficiencies of a §60.18 compliant flare. With new NSPS rules that increase

the scope of regulated facilities, the default reference to §60.18 for flare design will be

impractical and detrimental to many oil and gas sites. Allowances need to be m ade for alternative

flare designs.

Attached to this document is a short white paper from John Zink, a large, well known vendor for

flare systems as well as the test study referenced in the Zink paper

. The paper argues the value of

allowing sonic flare de signs for oil and gas applications where high BTU gas will be flared.

Sonic flares have destruction efficiencies t hat exceed conventional flares and are used worldwide

in the oil and gas industry. However, due to NSPS limitations from §60.18, efficient s onic flare

designs are in limited use in the U. S. You will note that at the end of the Zink paper is a table of

recent test results witnessed by the TCEQ in October, 2010 in which all but one of 8 tests

achieved 100% destruction efficiency. The one lone test achieved a destruction efficiency of >

99%.

Below is a discussion for making allowances for flares that do not have continuous pilots ( 24

hours a day /7 days a week)

.

Flare Pilots

There are a number of operating scenarios where use of a continuou s 24/7 pilot is not desirable,

and is inefficient. In these cases, pilot fuel gas may be in limited supply or not available, or

flaring events are so infrequent, that use of continuous pilot gas is wasteful and creates

unnecessary emissions. Unnecessary wear also occurs to the flare tip when a pilot is needlessly

lit continuously. Listed below are a few examples of flare uses where these conditions would

apply:

Emergency Only /Planned MSS Flare : Flare is designed for control of emergency upsets only

, pl anned MSS events only or both . No continuous process streams are routed to the flare. Use of

flare is intermittent with long periods between flaring events that could be less than once per year

. A separate conventional flare system may exist to handle p rocess streams.

### Low Pressure Backup Flare : Flare is designed for low pressure, low volume burning and may

serve as a backup to a primary emissions control or recycling device such as a vapor recovery

unit (VRU). Use is intermittent with potentially long periods of time in between uses (e.g.,

during periods of maintenance or downtime to the primary control or recycling system )

.

Intermittent Low Pressure Process Control Flare: Flare is designed for controlling intermittent

emission periods such as durin g truck loading when operating conditions warrant emissions

control of vapors . Truck loading is a manual operation, so emissions are generated manually, and

flare is used only as needed when a truck pulls up to be loaded. This type of flare may have a

du al use as a Low Pressure Backup Flare.

Storage Tank Vapor Flare 1 

### : Another low pressure flare that burns storage tank vapors. Pilot gas

may not be available due to insufficient produce d gas volume associated with oil production and

a gas delivery syste m is unavailable. Purchased gas may have to be used for ignition gas as a

substitute for produced gas.

In cases where a 24/7 pilot is not used, it is recognized that a good pilot flame is necessary to

ensure combustion efficiency during flaring events. Consequently, a good flare design will have

a stream detection system tied to an auto ignition system so that the pilot lights as needed to

combust the waste stream going to flare. When the waste stream stops, the pilot shuts off. In

effect, the pilot is continuously lit , but only during the flare event itself.

In cases where pilot gas is not available, or use of a separate pilot gas stream is undesirable due to

intermittent flaring events

, low pressure flare designs exist where the flare stream i tself o perates

as its own pilot so that a separate pilot fuel stream is unnecessary. As an example, b elow is a

technical description from John Zink of how this type of flare might work

. Other vendors should

have equivalent designs.

Model EFF

- ZFF Flaring System : The ZFF is a gas

- assisted, pre

- mix flare for smokeless

burning of waste gas. The flare is highly efficient for the combustion of small waste gas

flows; the ZFF is capable of combusting hydrocarbons, low BTU, and toxic gases. An

additional feature of th e ZFF is that the flare acts as its own pilot. The pre

- mix feature

allows the ZFF to be utilized in applications with very low available pressure.

Purge Gas Reduction: The ZFF induces a vacuum in the knockout drum when initially

being ignited. This re duces the need for venting purge gas continuously through the

system, which makes the ZFF more economic during normal operations because gas will

not be continuously vented to the atmosphere.

Purge Gas: During operations the ZFF will utilize 1000 scfh of pilot gas.

Ignition Gas: During ignition the ZFF will utilize 250 scfh of ignition gas.

Purge Gas Seal: Due to the aspirating mixer drawing a vacuum on the waste line it is not

necessary to have a seal on the flaring system. This is ideal for installing a flare system

on a VRU system; The VRU system generally operates at 3

- 6 ounces.

Non

- continuous Ignition/ Purge Gas Flare: The ZFF is not a conventional flare. The

flare neither requires continuous purge gas or a seal mechanism to ensure that air does

not become entrained in the system. The lack of continuous purge gas or a seal

mechanism is possible because of the pre

- mix feature. Also, the ZFF does not have

continuous ignition, this is possible because the flare acts as its own pilot.

ZFF Control Panel Logic: Once the vapor pressure reaches 5 ounces, and the control

valve will send a signal to the control panel to ignite the ZFF . Then the panel will send a

signal to the fuel gas control valves to allow pilot gas and ignition gas to the flare. The

igniter will continue sparking approximately every ten seconds until the thermocouple

### senses it is lit. Once the pilot is lit, the control panel will send a signal to close the

ignition gas control valve. The flare will operate until the control valve s enses that the

system pressure is below 5 ounces.

While the above describes the operation for a low pressure vapor flare application, the control

panel logic described in the last paragraph can be applied to more conventional flare designs as

well . Inte rmittent flare streams can be detected by sensors that trigger lighting of the pilot.

1 

### To avoid confusion, the flare described here refers to a conventional flare with a flare tip at the end of a

vertical stack designed to promote efficient burning

. Another type of combustion unit known within

industry as a vapor combustor to control tank emissions is sometimes misnamed as an enclosed flare.

This is not really a flare in the conventional sense. Vapor combustors generally consist of an

encl osure/stack, a burner array (typically a ring burner), a pilot (some have dual pilots), a backflash

preventer, and a thermal well for temperature monitoring that is mostly tied into the automation system for

data archiving and alarms when the combustor fai ls for any number of reasons. A fair number of the se

units have a "hot point" element (a metal probe with a high heat holding capacity) which provides "re

- light"

for momentary flame outages. A much smaller number have UV fire detection and electronic re

- light

capabilities. These units are generally naturally aspirated with no air or gas assist. Many of these units

have been "stack tested" in the Jonah/Pinedale area of Wyoming and have DRE's north of 98

- 99%.

Attachment 1 provides a diagram showing how c ombustor systems are typically designed.

This rulemaking needs to allow for the use of combustors without reference §60.18.

## System Description:

1. Maximum f

low conditions are detailed in adjacent text box. 400 BBL is sometimes seen on new 5 pad wells, but normal

production is less than 100 BBL/day.

2. All lines from the condensate tank to the combustor are 4” pipe.

3. The tank Enardo is set at 12

- 1 4 oz. The tank Thief Hatch is set at 16 oz.

4. The knock out tank prevents an y liquid head in the underground line

5. The combus tor is generally set with 300 feet of the tank.

6. Additional pressure drop

– other than piping associated with the combustor system, there is an additional pressure drop at the

combustor consisting of an orifice, burner and flash back arrestor

, with the majo rity of the drop across the orifice. If excessive

pressure is encountered on the orifice, the orifice size is increased to eliminate any venting of the Enadros. Condensate Tank

Combustor Double Walled

Knock out T ank



## Berm Enardo vent set at 12

- 14 oz 

## Pressure Drop P rofile for Combustor System

Example Design

Thief Hatch set at 16 oz

### © 2010 by John Zink Company 

### 1



# Applicability of the 40CFR 60.18 Requirements for

Upstream Oil & Gas Flares

Kevin Leary

Product Director – Flare Systems

John Zink Company LLC

November 14, 2010

### © 2010 by John Zink Company 

### 2



## I. Introduction

The purpose of this paper is to examine the design and operation of flares used in the

Upstream Oil & Gas Industry as related to complianc e with 40CFR 60.18 and the

destruction efficiency requirements of such flares. In particular we will examine the

currently available documentation related to the 40 CFR 60.18 requirements for a

maximum velocity (Vmax) limits for flares used in u pstream oil & gas industries.



## II. Vmax Requirements for Upstream Oil & Gas Production Flares

The minimum BTU values and Vmax requirements are th e result of analysis of a series of

flare efficiency tests that were sponsored by the E PA and Chemical Manufacturers

Association and summarized in the following EPA pub lications:

• Flare Efficiency Study , EPA-600/2-83-052, July 1983

• Evaluation of the Efficiency of Industrial Flares: Test Results, EPA-600/2-84-

095, May 1984.

• Evaluation of the Efficiency of Industrial Flares: Flare Head Design and Gas

Composition, EPA-600/2-85-106, September 1986

These studies measured the emissions from flares fo r the determination of destruction

efficiency of primarily steam assisted, air assiste d and nonassisted flares under various

operating conditions. These tests utilized natural gas, propane / nitrogen and propylene /

nitrogen gas mixtures of varying heating value, fla ring rates and assist medium rates.

The results of these studies were used to develop t he minimum heating value and Vmax

requirements in 40CFR 60.18. It was concluded that flares operated within these

guidelines would produce minimum destruction effici encies of greater than 98%.

The testing that was performed in the studies refer enced above was limited in its study of

high velocity nonassisted and air assisted flares a nd high BTU content flares that are

common in the Upstream O&G industry. This was due primarily to the limits of the

testing methods available at that time. High veloc ity, high BTU content flares of any

appreciable size produce tall flames. It is unfeas ible to collect the combustion products

from such tall flames with the test methods that we re used in these studies.

A substantial amount of data for low BTU flares (20 0 – 1000 BTU/SCF) gas streams was

collected in these tests for relatively low velocit y flares. The Vmax requirements of

40CFR 60.18 are fairly substantiated for this regio n of gases. The 400 ft/sec limitation

for steam assisted and unassisted flares greater th an 1000 BTU/SCF is likely based of the

lack of data for high BTU / high velocity flares. The limit of available data from these

tests does not allow extrapolation into this region . Similarly the Vmax limitation for air

assisted flares (much less than 400 ft/sec) is due to the lack of test data in this operating

region.

### © 2010 by John Zink Company 

### 3

The data presented in several of the studies noted above suggests that if flares are

operated safely above the minimum heating value for stability, high combustion

efficiencies are achieved. Although years of study of flares indicates that stable flare

flames from high BTU gases can be observed at exit velocities well above Vmax, there

is no published data to confirm this for air assist ed, steam assisted or nonassisted flares.

There is reluctance in the regulatory community to extrapolate beyond the available test

data. Although many flare designers are producing nonassisted and air assisted flares that

are designed to maintain stable flare flames above Vmax on high BTU gases, this is

based on visual observation of flame properties. I f the regulatory community were to

accept visual observation alone as the determinatio n of flame stability, these designs

could be proven through a series of testing. Curre ntly approved methods of

measurements of flare efficiency are not practical to apply to these designs



## III. Pressure Assisted Flares in Upstream Oil & Gas Indu stry

As noted earlier, pressure assisted flares are a se parate class of flares that are used

extensively in the O&G Production industry. Hundre ds (perhaps thousands) of pressure

assisted flares are currently in use in O&G product ion facilities around the world. This

class of flare is also used extensively in staged g round flare configurations in many

refineries and petrochemical plants. Currently 40C FR 60.18 does not address use of this

class of flare to meet the requirements of this reg ulation. Pressure assisted flares are the

optimum choice of design for high pressure flares i n the O&G industry when low

radiation, smokeless flaring is desired / required. Pressure assisted flares have the unique

ability to provide smokeless flaring without the ne ed for operator attention to adjust the

air rates or steam rates that are required with air assisted and steam assisted flares.

If the industry were forced to design these flares to the current requirements of 40CFR

60.18 it would be not be feasible. Offshore flares , for instance, would require longer

flare booms or taller flare towers that could not p ractically be retrofitted on existing

structures. Retrofitting existing onshore high pre ssure flares to air assisted flares would

likewise be impractical.

There is however currently available certified test data on the efficiency of some types of

pressure assisted flares. During several of the te sts of the 1983-1986 flare testing

referenced above there was flare efficiency testing conducted on several pressure assisted

flare head designs. This testing concluded that th ese pressure assisted flares can

effectively provide high combustion efficiencies wh en flaring high BTU gases at

velocities above Vmax.

There are many different configurations of pressure assisted flare head designs currently

used in the industry. The geometry of these flare heads and methods of flame

stabilization vary widely in these designs. Conseq uently, there is reluctance in the

regulatory community to certify pressure assisted f lares as a whole class. Certified flare

### © 2010 by John Zink Company 

### 4

efficiency testing has, in several cases, been requ ired to permit use of these flares to meet

the minimum destruction efficiency requirements tha t 40CFR 60.18 specifies.

Many pressure assisted designs can produce short co mpact flames at high exit velocities.

These designs therefore lend themselves to use of s imilar test protocols used in the EPA

flare efficiency studies from the 1980’s. In addi tion to the pressure assisted flare

efficiency data presented in these studies, there i s additional recent certified test data that

was collected on specific pressure assisted flare h ead designs. One such test is

summarized in the paper Pressure-Assisted Flare Emissions Testing presented at the

American-Japanese Flame Research Committees Interna tional Symposium, October

2007. This report concludes that a well designed a nd properly operated pressure assisted

flare burner will achieve greater than 99% DRE unde r operating conditions including

sonic velocity (>> Vmax) with high BTU gas streams. This testing was performed on

multiport high pressure flare nozzles commonly used in multi-point flare systems.

In order to expand the available certified test dat a on pressure assisted flares, John Zink

recently conducted testing on another pressure assi sted flare burner that is commonly

used in Upstream O&G production flares. Variable s lot Coanda based flares are

currently used extensively in O&G production facili ties. These flares are proven to

provide very stable smokeless flaring in these appl ications, however this class of flare

had never been tested for combustion efficiency.

The Texas Commission on Environmental Quality (TCEQ ) recently commissioned the

University of Texas to perform additional certified testing on air assisted and steam

assisted flares. The results of this testing are s cheduled to be reported in 2011. During

this testing, which was performed at John Zink’s Tu lsa Flare Research Center, John Zink

utilized the same certified test protocols and thir d party data collection techniques to test

a variable slot Coanda based pressure assisted flar e head under a wide variable of

operating conditions. This pressure assisted head was tested on variant flare gas

compositions including 100% natural gas and 100% pr opane. Flow rates from very low

purge rates through sonic flow conditions (approxim ately 1400 ft/sec for natural gas),

were also tested.

The results of this series of tests on the pressure assisted flare design are summarized in

Table 1 (see appendix). These tests show that this type of pressure assisted flare head

design can effectively provide >99% destruction eff iciency over the full range of

operating conditions from low flow rates through so nic velocity over a wide range of gas

compositions.

We believe that pressure assisted flare heads that have been designed and tested to meet

the DRE targets established by 40CFR 60.18 should be excluded from the Vmax

requirements of this regulation. This type of flar e is already used extensively in the

Upstream O&G industry and could easily be retrofitt ed on many existing air assisted and

nonassisted flares in these applications.

### © 2010 by John Zink Company 

### 5



## IV. References

1. McDaniel, Flare Efficiency Study , EPA-600/2-83-052, July 1983

2. Pohl, J.H., Payne, R., and Lee, J., Evaluation of the Efficiency of Industrial

Flares: Test Results, EPA-600/2-84-095, May 1984.

3. Pohl, J.H. and Soelberg, N.R. Evaluation of the Efficiency of Industrial Flares:

Flare Head Design and Gas Composition, EPA-600/2-85-106, September 1986

4. Varner, V., Fox, S., Schwartz, R., Wozniak, R., Pressure-Assisted Flare

Emissions Testing presented at the American-Japanese Flame Research

Committees International Symposium, October 2007.

### © 2010 by John Zink Company 

### 6



## V. Appendix

### Thief Hatch Work Practices

Research indicates there are no API or ASTM standards that address specific inspection

and maintenance practices for thief hatches. However, API RP 12R may come the

closest to being a tech nical reference for thief hatch work and maintenance practices

.

From what has been found in engineering and vendor literature, four general work

practices for thief hatches on tanks controlled for emissions can be listed as the

following:

Operator needs to s elect the appropriate gasket mate rial based on fluid composition

of the storage tank and weather conditions.

Inspect in a regularly scheduled p reventive m aintenance (PM) program

. Annual

inspection of thief hatch seal is the most common suggestion although some sites

inspect on a more or less frequent basis. When applicable, inspection should occur

in conjunction with thieving or gauging tank to minimize additional periods of an open

hatch.

Replace gasket within 30 days if inspection shows evidence of deterioration or

cracking. In the interim, grease the gasket if deterioration or leakage is found to

improve seal while waiting on replacement gasket.

Keep thief hatch in good working order

. V erify thief hatch seal is capable of holding

pressure in excess of the pressure /vacuum relief devi ce (PRD )

. The thief hatch

spring or weight relief set point should be greater than the set point on the PRD, and

both the thief hatch and PRD set points need to be greater than the back pressure

set point of the control system.

Standard practice is to im plement preventative maintenance during routine inspections

including cleaning surfaces and seals, greasing the gasket to improve the seal, and

repairing or replacing springs. I f a leaking gasket is discovered during inspection, the

temporary initial fix is to grease the gasket to improve the seal. If unable to verify a good

seal, then replace the gasket within 3 0 days unless a custom gasket must be fabricated

for replacement (e.g. older storage tanks)

.

Gasket selection

Elastomers n itrile and neoprene appear to be the “standard” gasket materials for oil

storage, with Fluoroelastomers for H2S service. Thermoplastic seals are not commonly

used, but can be. There are various grades of seals within each material category for

selection in the proper fluid composition and temperature environment the gasket will be

used.

Any rulemaking should not mandate specific gasket materials but rather specify gasket

material appropriate for type of chemical service and operating conditions including

weather.

Refer ences

www.jayco.org

www.enardo.com

API RP 12R