Methane Cost Curve Report

8/12/2019 Methane Cost Curve Report

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EconomicAnalysisof

MethaneEmission

ReductionOpportunities

inthe

U.S.

Onshore

Oil

andNaturalGas

Industries

March2014

Preparedfor

EnvironmentalDefenseFund

257ParkAvenueSouth

NewYork,NY10010Preparedby

ICFInternational

9300LeeHighway

Fairfax,VA22031


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blankpage


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EconomicAnalysisofMethaneEmissionReductionOpportunitiesintheU.S.OnshoreOilandNaturalGas

Industries

ICFInternational iii March2014

Contents

1. ExecutiveSummary....................................................................................................................11

2.

Introduction...............................................................................................................................

21

2.1. GoalsandApproachoftheStudy.............................................................................................. 21

2.2. OverviewofGasSectorMethaneEmissions............................................................................. 22

2.3. ClimateChangeForcingEffectsofMethane............................................................................. 25

2.4. CostEffectivenessofEmissionReductions............................................................................... 26

3. ApproachandMethodology.......................................................................................................31

3.1. OverviewofMethodology......................................................................................................... 31

3.2. Developmentofthe2011EmissionsBaseline........................................................................... 32

3.3. Projectionto2018..................................................................................................................... 34

3.4. IdentificationofTargetedEmissionSources............................................................................. 36

3.5. SelectedMitigationTechnologies............................................................................................. 39

3.6.

SourceCategories

Not

Addressed

...........................................................................................

323

4. AnalyticalResults.......................................................................................................................41

4.1. DevelopmentofEmissionControlCostCurves......................................................................... 41

4.2. EmissionReductionCostCurves................................................................................................ 42

4.3. CoBenefits.............................................................................................................................. 411

5. CaseStudies...............................................................................................................................51

5.1. WetSealCompressorDegassingforCentrifugalCompressors................................................. 51

5.2. DrySealReplacement/Retrofit.................................................................................................. 52

5.3. WetSealDegassingCaptureSystems........................................................................................ 52

5.3.1. EconomicAnalysisofInstallingWetSealDegassingCaptureSystems........................ 53

5.4.

Liquids

Unloading

......................................................................................................................

5

6

5.4.1. Background................................................................................................................... 56

5.4.2. PlungerLifts.................................................................................................................. 57

5.4.3. AdditionalOptionsforRemovingorRemediatingLiquidsProblems........................... 59

5.4.4. LiquidsIssuesinHorizontalWells............................................................................... 512

6. Conclusions................................................................................................................................61

AppendixA.AdditionalSensitivities..................................................................................................A1

AppendixB.Developmentofthe2011EmissionsBaseline................................................................B1

AppendixC.EmissionProjectionto2018..........................................................................................C1

AppendixD.MethaneMitigationTechnologies.................................................................................D1

Figures

Figure11 MarginalAbatementCostCurveforMethaneReductionsbySource................................... 12

Figure21 NaturalGasIndustryProcessesandExampleMethaneEmissionSources............................ 23

Figure31EmissionProjectionto2018(IncludingOffshore).............................................................. 35

Figure32 DistributionofEmissionsin2018........................................................................................... 35


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ICFInternational iv March2014

Figure33 EIAOilandGasRegions.......................................................................................................... 36

Figure34 2018ProjectedOnshoreEmissions........................................................................................ 38

Figure35 ReciprocatingCompressorRodPacking............................................................................... 313

Figure36 WetSealCompressorSchematic.......................................................................................... 315

Figure37

PlungerLift

Schematic

..........................................................................................................

317

Figure41 ExampleMACCurve............................................................................................................... 42

Figure42NationalAggregateMACCurveforBaselineTechnologyAssumptions................................ 43

Figure43 DistributionofEmissionReductionPotential......................................................................... 45

Figure44 EmissionReductionbyIndustrySegment.............................................................................. 46

Figure45EmissionReductionsfortheGasProductionSegment......................................................... 47

Figure46 EmissionReductionsfortheOilProductionSegment............................................................ 48

Figure47 EmissionReductionsfortheGatheringandBoostingSegment............................................. 49

Figure48 EmissionsReductionsfortheGasTransmissionSegment..................................................... 49

Figure49 NationalAggregateMACCurvewithBaselineTechnologyAssumptionand

EconomyWideValueRecognition......................................................................................... 410

Figure410 NationalAggregateMACCurvebyRegion......................................................................... 411

Figure411CoBenefitReductionsofVOCsandHAPs......................................................................... 412

Figure412 VOCReductionCoBenefits................................................................................................ 412

Figure413 HazardousAirPollutantCoBenefits.................................................................................. 413

Figure51 DrySealsonaCentrifugalCompressor.................................................................................. 52

Figure52Wetsealdegassingrecoverysystemforcentrifugalcompressors(SourceU.S.

EPA).......................................................................................................................................... 53

Figure53 PlungerLiftSchematic............................................................................................................ 57

Figure54 InstallationofVelocityTubingServingtoReductiontheCrossSectionAreaof

theProductionTubing............................................................................................................ 511

Figure55 DifferentTypesofHorizontalWells...................................................................................... 513

Tables

Table31 Summaryof2011MethaneEmissionsBaseline...................................................................... 33

Table32 HighestEmittingOnshoreMethaneSourceCategoriesin2018............................................. 37

Table33 LDARHourlyCostCalculation................................................................................................ 310

Table34CostCalculationQuarterlyLDAR........................................................................................ 312

Table35 AssumptionsforRodPackingReplacement.......................................................................... 314

Table36 SummaryofMitigationMeasuresApplied............................................................................ 321

Table37 SummaryofMitigationMeasureCharacteristics.................................................................. 322

Table41AnnualizedCostandReductionandInitialCapitalCost......................................................... 44

Table42 InitialCapitalCostbyIndustrySegment.................................................................................. 47

Table51 DegassingRecoverySystemEstimatedInstallationandEquipmentCosts............................. 54

Table52 WetSealDegassingRecoverySystemCostsandSavingsforOneCompressor...................... 56

Table53 WetSealDegassingRecoverySystemCostsandSavingsforFourCompressors

ataStation............................................................................................................................... 56

Table54 ReportedCapitalandOperatingCostRangesforInstallingPlungerLift

Systems.................................................................................................................................... 59


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ICFInternational v March2014

Acknowledgement

ICFreceivedandconsidereddataandcommentaryfromnumerousstakeholderorganizations,

includingoilandgasproducers,pipelines,equipmentvendors,serviceproviders,andatrade

organization. Noinformationinthisreportshouldbeattributedtoanysingleorganization,asall

dataisaggregatedfrommultiplesourcesandoftenusesaveragevalues. Furthermore,

acknowledgementofindustryparticipationdoesnotimplytheiragreementwiththestudy

conclusions,whichreflecttheprofessionaljudgmentofICF.

We

thank

all

of

the

stakeholder

organizations

for

providing

input

to

this

study,

and

specifically

acknowledgethefollowingentities:AnadarkoPetroleum,BGGroup,PioneerNaturalResources,

SouthwesternEnergy,andtheAmericanGasAssociation.


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ICFInternational vii March2014

Acronym/Abbreviation StandsFor

MMTCO2e MillionMetricTonnesCO2equivalent

NESHAP NationalEmissionStandardsforHazardousAirPollutants

NPV

NetPresent Value

NSPS NewSourcePerformanceStandards promulgatedundertheFederalCleanAirAct

OpEx OperatingExpenditures

PRO PartnerReportedOpportunity

psig PoundsperSquareInch Gauge

RECs ReducedEmissionCompletions

scf StandardCubicFeet

scfd StandardCubicFeetperDay

scfh

StandardCubic

Feet

per

Hour

scfm StandardCubicFeetperMinute

TEG TriethyleneGlycol

TSD TechnicalSupportDocument

USD U.S.Dollars

VOC VolatileOrganicCompound

VRU VaporRecoveryUnit


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ExecutiveSummary

ICFInternational 11 March2014

1.ExecutiveSummaryMethaneisanimportantclimatechangeforcinggreenhousegas(GHG)withashorttermimpactmany

timesgreater

than

carbon

dioxide.

Methane

comprised

9%

of

U.S.

greenhouse

gas

(GHG)

emissions

in

2011accordingtotheU.S.EPAInventoryofUSGreenhouseGasEmissionandSinks:199020111,and

wouldcompriseasubstantiallyhigherportionbasedonashortertimescalemeasurement.Recent

researchalsosuggeststhatmitigationofshorttermclimateforcerssuchasmethaneisacritical

componentofacomprehensiveresponsetoclimatechange2.Emissionsfromtheoilandgasindustryare

amongthelargestanthropogenicsourcesofU.S.methaneemissions.Atthesametime,therearemany

waystoreduceemissionsoffugitiveandventedmethanefromtheoilandgasindustryand,becauseof

thevalueofthegasthatisconserved,someofthesemeasuresactuallysavemoneyorhavelimitednet

cost.

EnvironmentalDefense

Fund

(EDF)

commissioned

this

economic

analysis

of

methane

emission

reduction

opportunitiesfromtheoilandnaturalgasindustriestoidentifythemostcosteffectiveapproachesto

reducethesemethaneemissions.Thestudyprojectstheestimatedgrowthofmethaneemissionsfrom

theseindustriesthrough2018asafuturedateatwhichnewemissionreductiontechnologiescouldbe

installed.Itthenidentifiesthelargestemittingsegmentsandestimatesthemagnitudeandcostof

potentialreductionsachievablethroughcurrentlyavailabletechnologies.Thekeyconclusionsofthe

studyinclude:

EmissionGrowth Methaneemissionsfromoilandgasactivitiesareprojectedtogrow4.5%from2011to2018includingreductionsfromEPAregulationsadoptedin2012(knownasNewSource

PerformanceStandards

(NSPS)

Subpart

OOOO).

All

of

the

projected

net

growth

is

from

the

oil

sector,largelyfromflaringandventingofassociatedgas.Growthfromnewnaturalgassourcesis

offsetbytheNSPSandothercontinuingemissionreductionactivities.Nearly90%oftheemissions

in2018comefromexistingsources(sourcesinexistencein2011).

80/20RuleforSources 22oftheover100emissionsourcecategoriesaccountforover80%ofthe2018emissions,primarilyatexistingfacilities.

AbatementMagnitudeandEconomics A40%percentreductioninonshoremethaneemissionsisprojectedtobeachievablewithexistingtechnologiesandtechniquesatanettotalcostof

$0.66/Mcfofmethanereduced,orlessthan$0.01/Mcfofgasproduced,takingintoaccountsavings

that

accrue

directly

to

companies

implementing

methane

reduction

measures

(Figure

1

1).

If

the

full

economicvalueofrecoverednaturalgasistakenintoaccount,includingsavingsthatdonotdirectly

accruetocompaniesimplementingmethanereductionmeasures,the40%reductionisachievable

1Calculatedata100yearGWPof21seeSection2.3.

2Shoemaker,J.et.al.,WhatRoleforShortLivedClimatePollutantsinMitigationPolicy?.ScienceVol34213December2013


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EconomicAnalysisofMethaneEmissionReductionOpportunitiesintheU.S.OnshoreOilandNaturalGasIndustries

ExecutiveSummary


whilesavingtheU.S.economyandconsumersover$100millionperyear. Thecostforsome

measuresandsegmentsoftheindustryismoreorlessthanthenettotal.Theinitialcapitalcostof

themeasuresisestimatedtobeapproximately$2.2billionwiththemajorityofthecostsintheoil

andgasproductionsegments.

Figure11MarginalAbatementCostCurveforMethaneReductionsbySource

AbatementOpportunitiesByvolume,thelargestopportunitiestargetleakdetectionandrepairoffugitiveemissions(leaks)atfacilitiesandgascompressors,reducedventingofassociatedgas,and

replacementofhighemittingpneumaticdevices.

CoBenefitsReducingmethaneemissionswillalsoreduce atnoextracost conventionalpollutantsthatcanharmpublichealthandtheenvironment.Themethanereductionsprojected

herewouldalsoresultina44%reductioninvolatileorganiccompounds(VOCs)andhazardousair

pollutants(HAPs)associatedwithmethaneemissionsfromtheoilandgasindustry.

Thereareseveralcaveatstotheresults:

The2011EPAinventoryisthebeststartingpointforanalysis,butitisbasedonmanyassumptionsandsomeolderdatasources.Althoughtheinventoryisimprovingwithnewdata,itisdesignedto

beaplanningandreportingdocumentandisimperfect,especiallyatthedetailedlevel,fora

granularanalysisofthistype.

Emissionmitigationcostandperformancearehighlysitespecificandvariable.Thevaluesusedhereareestimatedaveragevalues.


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Theanalysispresentsareasonableestimateofpotentialcostandmagnitudeofreductionswithinarangeofuncertainty.


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Introduction


2.IntroductionMethaneemissionshaveanenhancedeffectonclimatechangebecausemethanehasaclimateforcing

effect25

times

greater

on

a100

year

basis

than

that

of

carbon

dioxide,

the

primary

greenhouse

gas

(GHG).Methanesimpactisalmostthreetimesgreaterona20yearbasisandthereisresearchthatmay

causebothfactorstobeincreased.(SeeSection2.3) Recentresearchalsosuggeststhatmitigationof

shorttermclimateforcerssuchasmethaneisacriticalcomponentofacomprehensiveresponseto

climatechange.

EmissionsfromtheoilandgasindustriesareamongthelargestanthropogenicsourcesofU.S.methane

emissionsaccordingtotheU.S.EPAInventoryofU.S.GreenhouseGasEmissions3,andrecentanalyses

indicatethattheEPAinventoryestimatesmayunderstatetotalmethaneemissionsfromthissource

category4.Atthesametime,therearemanywaystoreduceemissionsoffugitiveandventedmethane

fromthe

oil

and

gas

industries

and,

because

of

the

value

of

the

gas

that

is

conserved,

some

of

these

measuresactuallysavemoneyorhavelimitednetcost.

Companiesintheoilandgasindustrieshavemadesignificantvoluntaryreductionsinmethane

emissions.However,voluntaryadoptionofcontroltechniquesisuneven. TheU.S.hasestablished

emissionregulationsforconventionalpollutants(NSPSSubpartOOOOandoilandgasNESHAPS)that

willhavetheeffectofsignificantlyreducingmethaneemissionsfromcertainnewsourcesinsome

segmentsofthegasindustry.Somestatesalsohaveproposedorestablishedregulationsthatlimit

methaneemissionsfromtheoilandgasindustry.However,theseregulationsgenerallydonotapplyto

emissionsfromtheexistinginfrastructure,sothereisalargepopulationofuncontrolledsources.

Overall,methane

emissions

are

significant

and

there

is

asizeable

potential

for

additional

cost

effective

reductionopportunities.

2.1. GoalsandApproachoftheStudyEnvironmentalDefenseFund(EDF)commissionedthiseconomicanalysisofmethaneemissionreduction

opportunitiesfromtheoilandnaturalgasindustry.ThisICFanalysisissolutionsorientedand

complementsEDFsongoingworkonmethaneemissionsintheoilandnaturalgassectors.The

approachtothestudywasto:

Defineabaselineofmethaneemissionsfromtheoilandgassectors.Thebaselinewasestablishedfor2018asaconservativeestimateofapointwhennewmitigationtechnologiescouldhavebeen

installed.

3U.S.EPA,InventoryofU.S.GreenhouseGasEmissionsAndSinks:19902011.April2013.

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.htmlBasedona100yearGWPof21seeSection2.34Brandt,A.et.al.,MethaneLeaksfromNorthAmericanNaturalGasSystems.ScienceVOL34314February2014


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Introduction


Reviewexistingliteratureandconductfurtheranalysistoidentifythelargestreductionopportunitiesandvalidateandrefinecostbenefitestimatesofmitigationtechnologies.

Conductinterviewswithindustry,technologyinnovators,andequipmentvendorswithaspecificfocustoidentifyadditionalmitigationoptions.

Usethisinformationtodevelopmarginalabatementcost(MAC)curvesformethanereductionsintheseindustries.

Documentandpresenttheresults.Thefinaloutputsofthestudyinclude:

Theprojected2018emissionsbaseline.(Chapter3andAppendixC) Inventoryofmethanemitigationtechnologies.(Chapters3and6andAppendixD) Emissionsabatementcostcurvesacrossarangeofscenarios(Chapter4andAppendixA) Indepthcasestudiesoftwospecificmethanemitigationoptions.(Chapter5) Conclusions(Chapter6)

2.2. OverviewofGasSectorMethaneEmissionsTherearemanysourcesofmethaneemissionsacrosstheentireoilandgassupplychain.These

emissionsarecharacterizedaseither:

Fugitiveemissions

methane

that

leaks

unintentionally

from

equipment

such

as

from

flanges,

valves,orotherequipment.

Ventedemissionsmethanethatisreleasedduetoequipmentdesignoroperationalprocedures,suchasfrompneumaticdevicebleeds,blowdowns,incompletecombustion,orequipmentventing.

Althoughleaksissometimesusedtorefertoallmethaneemissionsfromtheoilandgasindustry,we

usethemorenarrowtechnicaldefinitionsinthisreport.

Figure21illustratesthemajorsegmentsofthenaturalgasindustryandexamplesoftheprimary

sourcesofmethaneemissionsasgasisproduced,processed,anddeliveredtoconsumers.Naturalgasis

producedalongwithoilinmostoilwells(asassociatedgas)andalsoingaswellsthatdonotproduce

oil(asnonassociatedgas).Upuntilthepastfewyears,mostoftheU.S.naturalgassupplycamefrom

theGulfofMexicoandfromwesternandsouthwesternstates.Morerecently,midcontinentaland

northeasternshaleplayshavebeenagrowingsourceofoilandgassupply.


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Introduction


Figure21 NaturalGasIndustryProcessesandExampleMethaneEmissionSources

Sources:AmericanGasAssociation;EPANaturalGasSTARProgram

Rawgas(includingmethane)isventedatvariouspointsduringtheproductionprocess.Gascanbe

ventedwhenthewelliscompletedattheinitialphaseofproduction.Further,becausegaswellsare

ofteninremotelocationswithoutelectricity,thegaspressureisusedtocontrolandpoweravarietyof

controldevicesandonsiteequipment,suchaspumps.Thesepneumaticdevicestypicallyreleaseor

bleedsmallamountsofgasduringtheiroperation.Inbothoilandgasproduction,waterand

hydrocarbonliquidsareseparatedfromtheproductstreamatthewellhead. Theliquidsreleasegas,

whichmaybeventedfromtanksunlessitiscaptured.Waterisremovedfromgasstreambyglycol

dehydrators,whichventtheremovedmoistureandsomegastotheatmosphere.Insomecases,thegas

releasedbytheseprocessesandequipmentmaybeflaredratherthanvented,tomaintainsafetyandto

relieveoverpressuringwithindifferentpartsofthegasextractionanddeliverysystem.Flaringproduces

CO2,asignificantbutlesspotentGHGthanmethane,butnoflareis100%efficient,andsomemethaneis

emittedduringflaring.Inadditiontothevarioussourcesofventedemissions,themanycomponents

andcomplexnetworkofsmallgatheringlineshavethepotentialforfugitiveemissions.

Althoughsomegasispureenoughtobeusedasis,mostgasisfirsttransportedbypipelinefromthe

wellheadtoagasprocessingplant.Thegatheringsystemhaspneumaticdevicesandcompressorsthat

ventgasaswellaspotentialfugitiveemissions.Gasprocessingplantsremoveadditionalhydrocarbon

liquidssuchasethaneandbutaneaswellasgaseousimpuritiesfromtherawgas,includingCO2,inorder

forthegastobepipelinequalityandreadytobecompressedandtransported.Suchplantsareanother

sourceoffugitiveandventedemissions.


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Fromthegasprocessingplant,naturalgasistransported,generallyoverlongdistancesbyinterstate

pipelinetothecitygatehubandthentoconsumers.Thevastmajorityofthecompressorsthat

pressurizethepipelinetomovethegasarefueledbynaturalgas,althoughasmallshareispoweredby

electricity.Compressors

emit

CO2

and

methane

emissions

during

fuel

combustion

and

are

also

asource

offugitiveandventedmethaneemissionsthroughleaksincompressorseals,valves,andconnections

andthroughventingthatoccursduringoperationsandmaintenance. Compressorstationsconstitute

theprimarysourceofventedmethaneemissionsinnaturalgastransmission.

Somepowerplantsandlargeindustrialfacilitiesreceivegasdirectlyfromtransmissionpipelines,while

othersaswellasresidentialandcommercialconsumershavegasdeliveredthroughsmallerdistribution

pipelinesoperatedbylocalgasdistributioncompanies(LDCs).Distributionlinesdonottypicallyrequire

gascompression;however,somemethaneemissionsdooccurduetoleakagefromolderdistribution

linesandvalves,connections,andmeteringequipment.Thisisespeciallytrueforoldersystemsthat

havecast

iron

distribution

mains.

Manyoftheemissionsourcesfromdomesticoilproductionaresimilartothoseingasproduction

completionemissions,pneumaticdevices,processingequipmentandengine/compressors.Crudeoil

containsnaturalgasandthegasisseparatedfromtheoilstreamatthewellheadandcanbecaptured

forsale,vented,orflared.Ventingorflaringismostcommoninregionsthatdonothavegasgathering

infrastructure.ThisisthecasecurrentlyinNorthDakota,whererapidgrowthinoilproductionhastaken

placeinaregionwithlittlegasgatheringinfrastructure.Whilenewgatheringlinesarebeingbuilt,

productionisstillaheadofthegatheringcapacity,resultingincontinuedflaring.

Oil

is

taken

from

the

wellhead

in

electric

powered

pipelines

and

more

recently

by

rail,

to

refineries

for

processing.Petroleumproductsarethentakentoconsumersbypipeline,truck,rail,orbarge.The

downstreammethaneemissionsinthepetroleumsectoraremuchsmallerthaninthegassectoras

mostofthemethanehasbeenremovedfromtheoilbythispoint.

Forthelast100years,domesticoilproductionhasbeenprimarilyintheSouthwest(Texas,Arkansas,

Oklahoma),theGulfofMexico,California,andAlaska. Domesticgasproductionhasbeenmostlyinthe

Southwest,GulfofMexico,andtheRockies. Morerecently,thefocusofnewnaturalgasandoil

developmenthasbeenintheextractionofgasfromshaleformations. Shaleisasedimentaryrock

composedofcompactedmud,clayandorganicmatter. Overtime,theorganicmaterialcanproduce

naturalgasand/orpetroleum,whichcanslowlymigrateintoformationswhereitcanberecoveredfrom

conventionaloilandgaswells.Theshalerockitselfisnotsufficientlypermeabletoallowthegastobe

economicallyrecoveredthroughconventionalwells;thatis,gaswillnotflowsufficientlyfreelythrough

theshaletoawellforproduction.

Gasandoilfromshaleformationsisrecoveredbyhydraulicallyfracturingtheshalerocktoreleasethe

hydrocarbons. Thisinvolvespumpingwaterandadditivesathighpressureintothewelltofracture

theshale,creatingsmallcracksthatallowthegasand/oroiltoflowout. Whenthewaterflowsback


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outofthewell,methaneisentrainedandmaybevented. Duetothehighglobalwarmingpotentialof

methane,thiscanbealargesourceofGHGs. Forthesereasons,theincreasedproductionofshalegasis

apotentialsourceofincreasedGHGemissions.

Federalregulationspromulgatedin2012requirethemajorityofnewhydraulicallyfracturedgaswellsto

captureorflaretheflowbackgas.Theseregulationsandotherfederalandstateregulationsalsorequire

controlofothermethaneemittingprocesses,thoughmanyapplyonlytonewsourcesandtothose

wellsthatprimarilyproducenaturalgasratherthanwellsthatprimarilyproduceoil,sothereremainsa

largepopulationofexistinguncontrolledsources.

Significantamountsofbothoilandgasareproducedfromoffshorefacilities.Whilethesefacilities

reportsignificantmethaneemissions,thereportsdonothavethedetailandspecificityoftherestofthe

methaneinventoryandthereforecannotbeincludedinthesamemethodologyappliedtotherestof

theinventory

for

this

analysis.

Therefore,

this

study

focuses

only

on

onshore

oil

and

gas

industry

operations.Additionalstudyofoffshoreemissionsandreductionopportunitieswouldbeauseful

followuptothisanalysis.

2.3. ClimateChangeForcingEffectsofMethaneDifferentgreenhousegasespersistintheatmospherefordifferentlengthsoftimeandhavedifferent

warmingeffects,andthushavedifferenteffectsonclimatechange. Inordertocomparethem,the

scientificcommunityusesafactorcalledtheglobalwarmingpotential(GWP),whichrelateseachGHGs

effecttothatofCO2,whichisassignedaGWPof1.Thescienceandpolicycommunitieshavehistorically

lookedto

the

Intergovernmental

Panel

on

Climate

Change

(IPCC)

assessment

reports

as

the

authoritativebasisforGWPvalues.ThecurrentlyacceptedvaluesarefromtheIPCCFourthAssessment

report5(AR4).

CO2emissionsdeterminetheamountofclimatechangeoverthelongterm,duetotheirlonglifetimein

theatmosphere. BecausestabilizingclimatewillrequiredeepcutsinCO2emissions,GWPvaluesare

mostcommonlyexpressedona100yeartimehorizon.Ona100yearbasis,methaneisassignedaGWP

of25bytheAR4.Thismeansthatonetonofmethanehasthesameeffectas25tonsofCO2over100

years.The100yearGWPisthestandardvalueusedbytheEPAandotherfederal,state,and

internationalagenciestomeasureGHGemissions.(OneexceptionistheEPAGHGinventory,whichuses

a

100

GWP

of

21,

as

specified

by

the

United

Nations

Framework

Convention

on

Climate

Change

(UNFCC)

inventoryprotocol.)

5IPCC.ClimateChange2007:ThePhysicalScienceBasis.ContributionofWorkingGroupItotheFourthAssessmentReportof

theIntergovernmentalPanelonClimateChange.(CambridgeUniversityPressandNewYork,NY,Cambridge,UnitedKingdom,

2007).


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SomeGHGs,includingmethane,haveastrongerclimateforcingeffectthanCO2butashorterlifetimein

theatmosphere(12yearsformethane).Inordertoevaluatetheshorttermeffects,theGWPisalso

calculatedona20yearbasis.Ona20yearbasis,theAR4assignsmethaneaGWPof72.TheIPCCis

currentlypreparing

aFifth

Assessment

Report

(AR

5)6.

The

first

phase

of

that

work

has

adopted

higher

GWPvaluesduetoupdateddataonmethanesroleintheatmosphere.TheAR5valuesarea100year

GWPof28anda20yearGWPof84formethane.Insummary:

TheEPAGHGinventoryusesa100yearGWPof21. Mostotherregulationsandinventories(includingtheEPAGreenhouseGasReportingruleasof

2013)usetheAR4100yearGWPof25.TheAR420yearGWPis72.

TheGWPsbeingputforthintheAR5are28for100yearsand84for20years. ThisreportusestheAR4100yearGWPof25exceptwhereotherwisenoted.

2.4. CostEffectivenessofEmissionReductionsItiscommonindiscussingemissionreductionstodescribecosteffectiveemissionreductions.

However,therearethreedifferentconceptsofcosteffectivenessthatmustbeunderstoodand

differentiated.

Thefirstconceptiscosteffectivenessforthecompanyimplementingthemeasure.Inthiscase,cost

effectivemeansthatthevalueofgasthatisrecoveredthroughamethanereductionmeasureexceeds

theincrementalcapitalandoperatingcostofthemeasuresufficientlytocreateapaybackorrateof

returnthat

meets

the

companys

investment

criteria.

Measures

that

meet

these

criteria

might

be

describedashavingapositivenetpresentvalue(NPV),ashortpaybackperiod,oraninternalrateof

returnthatmeetsacertainthreshold.

Inorderforameasuretomeetthiscosteffectivenesscriterion,themeasuremustrecoverthemethane

emissionsandbeabletorecovertheirmonetaryvalue.Flaringofmethaneemissionsdoesnotmeetthis

criterion,forexample.Inaddition,thecompanymustbeabletomonetizethevalueoftherecovered

methane.Forexample,ifaproducerreducesmethanelosses,itwillhavemoregastosellandwill

receiveaneconomicbenefit.

Thesecondconceptiscosteffectivenessattheeconomywidescale.Insegmentsinwhichthecompany

ownsthegas,suchasoilandgasproduction,thecompanycanclearlymonetizethevalueofreduced

gaslosses.Thisisalsotrueinsomeothersectors.Mostmidstreamcompanies(gathering,processing,

6IPCC.ClimateChange2013:ThePhysicalScienceBasis.ContributionofWorkingGroupItotheFifthAssessmentReportof

theIntergovernmentalPanelonClimateChange.(CambridgeUniversityPressandNewYork,NY,Cambridge,UnitedKingdom,

2013).


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Introduction


storage)arepaidafixedfeeforgaslostandconsumedduringtheiroperations.Iftheycanreducetheir

lossesthentheywillbenefitdirectlyfromthereducedlosses.

Althoughtransmission

and

local

distribution

companies

typically

have

asimilar

cost

structure,

they

are

usuallyrequiredbyregulatorstoreturnthevalueofreducedlossestotheircustomers,sotheycannot

recoverthebenefitofreducedmethanelosses.Methanereductionsinthesesegmentsoftheindustry

willnothaveapositivereturntothecompanyorbecosteffectiveinthissense.Thatsaid,thevalueof

reducedlosseswillaccruetootherpartsoftheeconomy.IfapipelineorLDCreducesitslosses,the

benefitwilleventuallyflowthroughtothecustomersandtotheeconomyoverall.Reducedlosseswill

eventuallyflowthroughaslowerpricesforgasdeliveryanddeliveredcostofgastoconsumers.Thus,

evenwhentheentityimplementingareductioncannotdirectlybenefitfromreducedlosses,thereisa

broaderbenefitandthatfulleconomicbenefitcanbecalculatedandallocatedagainstthecostofthe

methanereduction,thesecondkindofcosteffectiveness.

Thelastconceptofcosteffectivenessisinthecontextofpollutioncontrolprograms.Inconventional

pollutioncontrolprogramsthecontroltechnologyrarelyresultsinacostreductiontothecompanythat

isrequiredtoimplementit.Thatis,thecostofcontrolisalmostalwayspositiveandthenetpresent

valueisnegativeandthereisnopaybackfortheinvestment.Nevertheless,theseprogramsincorporate

theconceptofcosteffectiveness,meaningthatthecostisacceptabletosocietyasameansofmeeting

publichealthandenvironmentalgoals.Thecosteffectivenessvariesfordifferentpollutantsand

differentregulatoryprograms.Forexample,$10,000/tonofVOCreducedmaybeconsideredcost

effectiveinsomeozonenonattainmentareaswhile$100/tonofSO2maybeconsideredcosteffective

foranacidrainreductionprogram.Inthiscontext,methanereductionscanbeconsideredcosteffective

evenifthey

have

anet

cost

to

the

company

or

society

overall.

Where

methane

reductions

do

create

a

netvaluetotheimplementingcompany,thecostofcontrolwillbenegative,i.e.,thecompanyis

reducingemissionsandsavingmoneyratherthanspendingmoney.

Inthisstudy,thevalueofrecoveredgasisincludedincalculatingthecosteffectivenessofmitigation

measureswherethegascanberecoveredandwhereitcanbemonetizedbythecompany.Therefore,

thesamemeasuremayhavedifferentcostsfordifferentsegments,e.g.,reducingcompressoremissions

willhavealowernetcostintheproductionsegmentthaninthetransmissionsegment.Thisreflectsthe

netcosttothecompanytoimplementthemeasure.However,wheregascanberecoveredthrougha

mitigationmeasure,itwillhavevaluetothebroadereconomy,evenifitisnotrecognizedbythe

companythat

must

make

the

investment.

Therefore

we

also

show,

in

certain

cases,

an

economy

wide

costeffectivenessmeasure,whichrecognizesthevalueofallrecoveredgas,evenifitcannotbe

recognizeddirectlybytheaffectedcompany.Thesecasesareclearlylabeledassuch.Thecostof

control,whetherpositiveornegative,canbealsoevaluatedintheregulatorysenseandcomparedto

otheravailableemissionreductionoptions.Finally,thereareadditionalsocialandenvironmental

benefitsofmethanereductionsthatarenotcapturedinthesecalculations,includingthebroader


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Introduction


economicvalueofreducedclimateriskandcobenefitreductionsofconventionalpollutantssuchas

groundlevelozoneandhazardousairpollutants.


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ApproachandMethodology


3.ApproachandMethodology3.1.

Overview

of

Methodology

Thissectionprovidesanoverviewofthemethodologyappliedforthisstudy.Themajorstepswere:

Establishthe2011BaselineforanalysistheanalysisstartedwiththemostrecentU.S.EPAinventoryofmethaneemissionsintheEPAInventoryofU.S.GHGEmissionspublishedin2013with

datafor20117.Thisinventorywasreviewedandrevisedtoaccountforadditional,morerecent

informationsuchasinformationfromtheEPAGHGReportingProgram8andtheUniversityof

Texas/EDFgasproductionmeasurementstudy9.ThesechangeswereappliedtodevelopanICF2011

Baseline,whichwasusedasthebasisforprojectingonshoremethaneemissionsto2018.

Project

emissions

to

2018

the

analysis

of

potential

reductions

was

based

on

the

projected

2018

emissionlevel.Theyear2018waschosenasaconservativedatebywhichnewcontroltechnologies

couldhavebeeninstalled.TheinventorywasalsodisaggregatedfromthenationallevelintheEPA

inventorytothesevenregionsusedintheU.S.EIAsoilandgasdatatoprovideregionalreporting.

Identificationofmajorsourcesandkeymitigationoptionsthenextstepwastoidentifythelargestemittingsourcesintheprojected2018inventoryandthemitigationoptionsthatwouldbe

mosteffectiveandcosteffectiveforthesesources.

Characterizationofemissionreductiontechnologiesakeypartofthestudywastoreviewandupdateinformationonthecostandperformanceoftheselectedmitigationtechnologies.

Informationwasgatheredfromequipmentmanufacturers,oilandgascompanies,andother

knowledgeableparties.

Developmentofthemarginalabatementcostcurvesthetechnologyinformationwasappliedtotheemissionsinventorytocalculatethepotentialemissionreductionandcost.Theresultswere

displayedinaseriesofmarginalabatementcostcurves.

Thekeystepsarediscussedfurtherinthefollowingsections.

7U.S.EPA,InventoryofU.S.GreenhouseGasEmissionsAndSinks:19902011,

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html8http://www.epa.gov/ghgreporting/

9Allen,David,et.al.,MeasurementsofMethaneEmissionsatNaturalGasProductionSitesintheUnitedStates.

10.1073/pnas.1304880110


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3.2. Developmentofthe2011EmissionsBaselineThedevelopmentofthe2011BaselinetakesasitsstartingpointtheU.S.EPAsInventoryofU.S.

GreenhouseGas

Emissions

and

Sinks:

1990

2011

published

in

2013

with

data

for

201110,

specifically

theportiononmethanefromNaturalGasandPetroleumSystems.WhiletheEPAInventoryisthemost

comprehensivesourceforthistypeofinformation,itisdesignedtobeaplanningandreportingtool

ratherthanthebasisforthistypeofgranularanalysis.ThereforeICFdevelopedanew2011Baseline,

adaptingtheEPAstructuretotheneedsoftheanalysisandincorporatingmorerecentinformation.This

wasnotacompleteupdateoftheinventory,whichwasbeyondthescopeofthisproject,butanupdate

ofanysectionsforwhichneworbetterdatacouldbereadilyidentified.TheEPAInventory11estimates

436billioncubicfeet(Bcf)or8.4millionmetrictonnesofmethaneemissionsforthepetroleumand

naturalgassectorsincludingoffshoreproductionin2011.Thepetroleumandnaturalgassectorsare

thenfurtherdividedintothevarioussegmentsforthenaturalgassector(GasProduction,Gatheringand

Boosting,Gas

Processing,

Gas

Transmission,

Gas

Storage,

LNG

Import/Export,

and

Distribution)

and

the

petroleumsector(OilProduction,Transportation,andRefining).

TheEPAInventorybreaksoutmethaneemissionsforapproximately200sources,andcalculates

uncontrolledemissionsusingactivityfactors(e.g.,equipmentcounts)multipliedbyemissionfactors

(averageemissionsfromeachsource)toestimatethetotalemissions.Thetotaluncontrolledemissions

arereducedbyemissionreductionsreportedprimarilyfromtheEPAsvoluntaryNaturalGasSTAR

Program,plusadditionalreductionsfromothersources,suchasstateregulations.

Thedevelopmentofthe2011Baselinereliedonthe2011EPAInventoryanddatafromseveralpublically

availablereferences.

The

most

common

source

of

updated

information

was

the

U.S.

EPAs

mandatory

GreenhouseGasReportingRule(GHGRP)subpartsC(combustionfromstationarysources)andW

(methaneemissionsfrompetroleumandnaturalgassystems).ICFalsousedinformationanddatafrom

theU.S.EnergyInformationAdministration(EIA),EPAs1996GRIstudyofmethaneemissions12,theEPA

ManualofEmissionFactorsAP4213,variousstateenergyandenvironmentaldepartments,andthe

EDF/UniversityofTexasmethanemeasurementstudy.Muchofthisinformationwasnotavailableatthe

timethatthe2011EPAinventorywasoriginallydeveloped.

Whilesomesourcecategoriesincreasedandsomedecreasedduetotheseadjustments,theoverall

effectwasanincreaseof2.4%inthenetestimatedmethaneemissionsfromtheoilandgassectorsto

10U.S.EPA,InventoryofU.S.GreenhouseGasEmissionsAndSinks:19902011,

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html11

Whilethe2013editionoftheInventorywasthecurrentversionatthetimethestudywasinitiated,EPAhassincereleased

thedraftofthe2014edition.HoweverthisstudydoesnotaddressthatnewerversionoftheInventory.12

http://epa.gov/gasstar/tools/related.htmlunderMethaneEmissionsfromtheNaturalGasIndustry13

http://www.epa.gov/ttn/chief/ap42/index.html


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446Bcf(8.6millionmetrictonnes)ofmethane.Theestimatedemissionsfromthenaturalgassector

were2%(10Bcf)lowerwhiletheemissionsfromtheoilsectorincreasedby26%(20Bcf)comparedto

theEPAinventory.Table31summarizestheemissionsinthe2011Baselinecomparedtothe2011EPA

Inventory.

ThechangesbyindustrysegmentareshowninTable31.

Table31 Summaryof2011MethaneEmissionsBaseline

Segment

2011EPAInventory ICF2011Baseline

Change(%)(Million

tonnesCH4)(BcfCH4)

(Million

tonnesCH4)(BcfCH4)

NaturalGas

GasProduction

2.2

113

2.0

103

9%

GatheringandBoosting 0.5 24 0.8 43 80%

GasProcessing 0.9 48 0.8 44 9%

GasTransmission 1.7 87 1.4 75 14%

GasStorage 0.3 17 0.3 15 11%

LNG 0.1 5 0.1 6 22%

GasDistribution 1.3 69 1.3 69 0%

Petroleum

OilProduction 1.4 72 1.8 92 27%

OilTransportation < 0.1 < 1 < 0.1


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Inventorybasedonthe1996GRImeasurementstudyratherthanbeingfullybrokenoutasaseparate

segment.Inthisstudy,somesourcesweremovedfromProductiontotheGatheringandBoosting

segmentinordertoallowthemtobeanalyzedseparatelyforthissegment,andnewemissions

estimates,for

some

sources

underrepresented

in

the

2011

EPA

inventory,

were

added.

The

major

sourceadditionswerenewestimatesofcompressorandpneumaticdeviceemissions.Inaddition,

emissionsfromcondensatetanksweremovedfromtheProductionsegmenttotheGatheringand

Boostingsegment.

TheoverallnetchangetotheNaturalGassegmentoftheU.S.Inventoryisadecreaseof2%compared

totheEPAInventoryvalue.Thisistheneteffectofincreasedestimatesforwellheadfugitivesand

GatheringandBoosting(forcompressorsandpneumaticdevices)anddecreasesintheestimatesfor

wellcompletionandworkoveremissions(basedondataandfactorsfromSubpartW)andcompressor

exhaustemissions.ThesechangesarediscussedinAppendixB.

ThenetchangetothePetroleumsegmentofthe2011Baselineis26%higherthantheEPAInventory

value.Thebiggestcategoriescontributingtothisincreaseweretheinclusionofstrandedgasventing

fromoilwellsandupdatedestimatesofassociatedgasflaringestimates.Allofthesechangesare

discussedinmoredetailinAppendixB.

3.3. Projectionto2018The2018forecastofnaturalgasandpetroleumsystemsmethaneemissionsstartswiththe2011

BaselinedescribedinSection3.2. Oneprimarydriverfortheprojectingthe2011emissionsto2018was

theU.S.

EIAs

Annual

Energy

Outlook

2013

and

2014

Early

Release.

ICF

also

relied

upon

a2011

study

for

theINGAAFoundation14thatforecastrequirementsforselectedinfrastructureandequipmentforthe

naturalgasandpetroleumindustry. Inaddition,expectedemissionreductionsasaresultofNSPS

SubpartOOOOwereincorporatedintotheforecast.WithouttheNSPS,emissionsgrowfrom446Bcfin

2011to491Bcfin2018.WiththeNSPSadjustments,totalemissionsareprojectedtogrowby4.5%to

466Bcfthrough2018.Almostallofthisgrowthisfromtheoilsectorwhereasthenetemissionsforthe

gassectorarealmostunchanged(Figure31).Growthfromnewsourcesinthegassectorisoffsetby

NSPSreductions,andreductionsfromexistingsourcessuchascontinuingreplacementofcastiron

mainsandturnoverofhighemittingpneumaticdevices.Despitetheoverallgrowth,nearly90%ofthe

emissionsin2018comefromexistingsources(sourcesinplaceasof2011)asshowninFigure32.

14NorthAmericanMidstreamInfrastructureThrough2035ASecureEnergyFuture,PreparedfortheINGAAFoundation,ICF

International,2011.


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Figure31EmissionProjectionto2018(IncludingOffshore)

Figure

3

2

Distribution

of

Emissions

in

2018


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Industries



Theprojectionalsodisaggregatedthenationallevelemissionsestimateofthe2011inventorytoregions

usedbytheEIAtoreportoilandgasdata(Figure33).Thedetailsoftheanalysisarediscussedin

AppendixC.

Figure33 EIAOilandGasRegions

3.4. IdentificationofTargetedEmissionSourcesTable32summarizesthelargestemittingsourcecategoriesintheprojected2018emissionsfortheoil

andgassectorsbymajorsourcecategory.Duetothelackofspecificdataontheemissionsourcesfor

offshoreoilandgasproduction,thestudyfocusedononshoreproductionandoffshoreemissionsare

excludedfromthislist.Thetop22sourcecategoriesaccountfor80%ofthetotal2018onshoremethane

emissionsof404Bcfandtheremaining100+categoriesaccountfor1%orlessofthetotalemissions

each.Althoughthesesourcecategorieswerenotincludedinthisanalysisduetotheirsmallsize,there

aredemonstratedmethanereductiontechnologiesthatcanprovidecosteffectivereductionsformany

ofthem.

Figure34showsthedistributionofsourcesgraphically.Fugitiveemissionsarethelargestemission

sourcecategoryoverall.Ventedemissionsfrompneumaticcontrollersandpumpsarealsosignificantas

isventedassociatedgasfromoilwellcompletionsandproduction.Ventingfromwetsealcentrifugal

compressorsisalsoalargesource.


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Table32 HighestEmittingOnshoreMethaneSourceCategoriesin2018

Source

2018

Emissions

(Bcf)

Percentof

Total

Cumulative

Bcf

Cumulative

%

ReciprocatingCompressorFugitives 53.8 13% 53.8 13%

HighBleedPneumaticDevices 28.7 7% 82.5 20%

LDCMetersandRegulators 28.7 7% 111.2 28%

CentrifugalCompressors(wetseals) 24.0 6% 135.3 33%

GasEngineExhaust 22.2 5% 157.5 39%

WellFugitives 20.8 5% 178.3 44%

ReciprocatingCompressor

Rod

Packing

17.6 4% 195.9

48%

LiquidsUnloading Wellsw/PlungerLifts 13.2 3% 209.1 52%

IntermittentBleedPneumaticDevices 13.0 3% 222.1 55%

KimrayPumps 11.5 3% 233.6 58%

OilTanks 11.5 3% 245.1 61%

Flares 9.0 2% 254.1 63%

StrandedGasVentingfromOilWells 8.4 2% 262.5 65%

IntermittentBleedPneumaticDevices DumpValves 7.7 2% 270.2 67%

OilWellCompletions withFracturing 6.9 2% 277.1 69%

PipelineLeaks(All) 6.7 2% 283.8 70%

PipelineVenting(Transmission) 6.6 2% 290.4 72%

CentrifugalCompressors(dryseals) 6.4 2% 296.8 73%

MainsPlastic 6.3 2% 303.2 75%

Mains CastIron 6.3 2% 309.4 77%

TransmissionStationVenting 6.2 2% 315.7 78%

ChemicalInjection

Pumps

5.9 1% 321.6

80%

Residential 5.6 1% 327.2 81%

GatheringandBoostingStations 5.6 1% 332.8 82%


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EconomicAnalysisofMethaneEmissionReductionOpportunitiesintheU.S.OnshoreOilandNaturalApproachandMethodology


Figure34 2018ProjectedOnshoreEmissions


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Industries



3.5. SelectedMitigationTechnologiesThefollowingsectionsdescribethemitigationmeasuresincludedinthisanalysistoaddressthehigh

emittingsource

categories.

Some

of

the

most

significant

measures

are

discussed

in

greater

detail

in

AppendixD.Muchofthecostandperformancedataforthetechnologiesisbasedoninformationfrom

theEPANaturalGasSTARprogram15buthasbeenupdatedandaugmentedwithinformationprovided

byindustryandequipmentvendorsourcesconsultedduringthisstudy.Thediscussionisorganized

accordingtotheemissionsourceandmitigationoption.

Thisanalysisattemptstodefinereasonableestimatesofaveragecostandperformancebasedonthe

availabledata.Thecostsandperformanceofanactualindividualprojectmaynotbedirectly

comparabletotheaveragesemployedinthisanalysisbecauseimplementationcostsandtechnology

effectivenessarehighlysitespecific.Costsforspecificactualfacilitiescouldbehigherorlowerthanthe

averagesused

in

this

analysis.

FugitiveEmissionsFugitiveemissionsaretheunplannedlossofmethanefrompipes,valves,flanges,

andothertypesofequipment.Fugitiveemissionsfromreciprocatingcompressors,compressorstations

(transmission,storage,andgathering),wells,andLDCmeteringandregulatorequipmentarethelargest

combinedemissioncategory,accountingforover120Bcf,or30%ofthehighlightedsources.

LeakDetectionandRepair(LDAR)isthegenerictermfortheprocessoflocatingandrepairingthese

fugitiveleaks.Thereareavarietyoftechniquesandtypesofequipmentthatcanbeusedtolocateand

quantifythesefugitiveemissions.ExtensiveworkhasbeendonebyEPAandotherstodocumentand

describethese

techniques,

both

in

the

Gas

STAR

reference

materials

and

in

several

regulatory

analyses.

Thepotentialsizeandnatureofthesefugitiveemissionscanvarywidelybyindustrysegmentandeven

bysite.LDARprogramshavebeenanalyzedforseveralrecentregulatoryinitiatives,includingforthe

EPAsNSPSSubpartOOOO16andthecurrentproposedrevisionstotheColoradoAirQualityControl

CommissionRegulationNumber7(5CCR10019)17.ThisstudyusedboththeColoradoregulatory

analysisandtheEPATechnicalSupportDocument(TSD)18forNSPSSubpartOOOOasthebasisforcost

andreductioneffectivenesscalculations.

15http://www.epa.gov/gasstar/

16http://www.epa.gov/airquality/oilandgas/

17http://www.colorado.gov/cs/Satellite/CDPHEAQCC/CBON/1251647985820

18U.S.EPA,OilandNaturalGasSector:StandardsofPerformanceforCrudeOilandNaturalGasProduction,Transmission,and

Distribution.BackgroundSupplementalTechnicalSupportDocumentfortheFinalNewSourcePerformanceStandards.

http://www.epa.gov/airquality/oilandgas/pdfs/20120418tsd.pdf


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Thekeyfactorsintheanalysisarehowmuchtimeittakesaninspectortosurveyeachfacility,howmany

inspectionsarerequiredeachyear,howmuchreductioncanbeachieved,andhowmuchtimeis

requiredforrepairs.ResearchcitedbybothColoradoandEPAindicatesthatmorefrequentinspections

resultin

greater

reductions,

summarized

as

approximately:

Annualinspection=40%reduction Quarterlyinspection=60%reduction Monthlyinspection=80%reductionICFadaptedtheColoradoanalysis,whichcalculatesthecapitalandlaborcosttofieldafulltime

inspector,includingallowancesfortravelandrecordkeeping(Table33).ICFaddedadditionaltimefor

training.Thecapitalcostincludesaninfraredcamera(whichisusedtolocatefugitiveemissions)atruck

andthecostofarecordkeepingsystem. Thecombinedhourlycostwasthebasisforthecost

estimates.

Table33 LDARHourlyCostCalculation

Labor CapitalandInitialCosts

InspectionStaff $75,000 InfraredCamera $122,200

Supervision(@20%) $15,000 PhotoIonizationDector $5,000

Overhead(@10%) $7,500 Truck $22,000

Travel(@15%) $11,250 Recordkeepingsystem $14,500

Recordkeeping(@10%) $7,500 Total $163,700

Reporting(@10%) $7,500

Fringe(@30%) $22,500 TrainingHours 80

SubtotalCosts $146,250 TrainingDollars $6,223

Hours/yr 1880 AmortizedCapital +Training $44,825

Hourly LaborRate $77.79 AnnualLabor $146,250

AnnualTotal Cost $191,075

TotalCostasHourlyRate $101.64

Manyanalyseshaveusedfacilitycomponentcountsandhistoricaldataonthetimerequiredtoinspect

eachcomponenttoestimatefacilitysurveytimes.However,theuseoftheinfraredcameratechnology


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allowsmuchshortersurveytimes19andtheEPAandColoradotimeestimateshavebeencriticizedastoo

long.Theestimatesherearebasedonexperiencewiththeinfraredcameraandareshorterthanthe

ColoradoandEPAestimatesthatbasedoncomponentcounts.

ICFthenadoptedthebaselineemissionvaluesforwells,gatheringandtransmissionstations,and

processingstationsfromtheEPAanalysis.EPAincludesthreewellpadsizeswithdifferentbaseline

emissions.TheEPAanalysisdidnotprovideestimatesofthedistributionofthethreesizesforexisting

facilitiessothemiddleestimatewasusedforthisanalysis.Usingthesmallerandlargerwellpad

emissionestimateswouldresultinhigherandloweremissionreductioncostsrespectively.

ForLDCs,theanalysisonlyincludeslargemeterandregulatorfacilities.Smallerfacilitieshadamuch

highercostduetothesmallbaselineemissions.TheLDCcostingwasdoneusingthesameoperatorand

capitalcostsasfortheupstreamandmidstreamfacilities.ThebaselineemissionfactorsforLDCswere

adaptedfrom

an

EPA

Gas

STAR

document

20

which

found

that

on

average

two

100

Mcf/year

leaks

were

foundat50%ofthefacilitiesandtheleakswerereducedby50%throughtheprogram.

Table34summarizestheassumptionsfortheoverallLDARcalculation.Thisanalysisassumesquarterly

emissionsurveysforallfacilities.Thereductionisassumedtobe60%,whichisconsistentwithdata

presentedintheNSPSTSDandColoradoanalysis.Inadditiontothesurveys,theestimateincludesone

initialvisittoeachsitetoinventorytheequipment(equivalenthourstotwoinspectionvisitsforeach

sitewithcostaveragedoverfiveyears)andadditionalvisitsforrepairs.Gasprocessingplantsare

alreadysubjecttosomeLDARrequirementsforconventionalpollutants,whichresultincobenefit

methanereductions.Themiscellaneousfugitiveemissionsforgasprocessingwerebelowthesize

threshold

for

this

analysis

but

the

costs

developed

here

for

gas

processing

are

applied

to

compressors

in

thatsegment.

Somerepairscanbemadeatthetimeofthesurvey,suchastighteningvalvepackingorflangesbut

otherswillrequireadditionalrepairtime.Thisanalysisassumesrepairtimeequivalenttothreesurvey

visitsforeachfacilityforrepairseachyear.Thecapitalcostoflargerrepairsisnotincludedonthe

assumptionthattheserepairswouldneedtobemadeanywayandtheLDARprogramissimplyalerting

theoperatortotheneed.ThetimeforrepairsisconsistentwiththelowendoftheColoradoanalysis

thatwasderivedbasedoncomponentcountsandleakrates.Thislowerrepairestimatetakesinto

accountthat:

Theseareaveragevaluesacrossfacilitiesnoteveryfacilitywillrequirerepairs.

19Robinson,D,et.al.,RefineryEvaluationofOpticalImagingtoLocateFugitiveEmissions.JournaloftheAir&Waste

ManagementAssociation.Volume57June2007.20

EPAGasSTARDirectedInspectionandMaintenanceatGateStationsandSurfaceFacilities.

http://epa.gov/gasstar/documents/ll_dimgatestat.pdf


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Industries



Theseareaveragevaluesovertimenoteveryfacilitywillneedrepairseveryyearwhilebeingmonitoredonacontinuingbasis.

Someorallofcostofmajorrepairsisassumedtobepartofregularfacilitymaintenance.Table34CostCalculationQuarterlyLDAR

WellPads Gathering Processing Transmission LDC

MethaneMcf/yr 440 1,676 2,448 4,671 150

%Reduction 60% 60% 60% 60% 60%

ReductionMcf 264 1,006 1,469 2,803 90

HourseachInspection 2.7 8 8 8 2

Frequency(peryear) 4 4 4 4 4

Annual InspectionCost $1,084 $3,252 $3,252 $3,252 $813

InitialSetUp $108 $325 $325 $325 $81

RepairLaborCost $813 $2,439 $2,439 $2,439 $407

TotalCost/yr $2,006 $6,017 $6,017 $6,017 $1301

RecoveredGasValue* $1,340 $5,105 $7,455 $12,416 $399

NetCost $666 $912 $1,438 $6,399 $902

CostofReduction($/Mcfmethanereduced)

WithoutGasCredit $7.60 $5.98 $4.10 $2.15 $14.45

WithGasCredit $2.52 $0.91 $0.98 $2.28 $10.03

*Gasat$4/Mcf

Thevalueofreducedgaslossesiscreditedtotheprogramfortheupstreamsegments. Thesefinal

reductioncostvalueswereusedfortheanalysis.


Rod

Packing

Reciprocating

compressors

are

used

in

most

segments

of

the

naturalgasandoilindustry,thoughmuchlesscommonlyinlocalgasdistributionthaninother

segments.Rodpackingsystemsareusedtomaintainasealaroundthepistonrod,minimizingthe

leakageofhighpressuregasfromthecompressorcylinder,whilestillallowingtherodtomovefreely

(Figure35).However,somegasstillescapesthroughtherodpacking,andthisvolumeincreasesasthe

packingwearsoutovertime,potentiallytomanytimestheinitialleakrate.Thereisnostandard

optimumintervaltoreplacetherodpacking,buttheNSPSSubpartOOOOrequiresrodpackinginnew


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Industries



reciprocatingcompressorsintheproductionandprocessingsectorstobereplacedevery26,000hours

ofoperation(approximatelyeverythreeyears).

Figure35


Rod

Packing

Industryreportsthattherodpackingforcompressorsatgasprocessingplantsandsometransmission

stationsisroutinelyreplacedatleastthatfrequentlyaspartofroutinemaintenance.However,itis

believedthatrodpackingintheproductionandgatheringandboostingsectorsisreplacedless

frequently.Thisisdue,inpart,toseveralfactors,includingtheremotelocationofthesecompressors,

thelackofabackupcompressorforuseduringcompressordowntime,andbecausemanyofthe

compressorsinthesesectorsareleasedratherthanowned.Thisanalysisassumesarequirementto

replacerodpackingforallreciprocatingcompressorsevery26,000hoursofoperation.

GasSTARdata21indicatethatrings(thecompressorpacking)costbetween$300and$600percylinder

and$1,000to$2,500percompressortoinstall.Industrysourcesforthisstudyputthecostat$5,000per

cylinder,whichwasadoptedforthisanalysis.TheTechnicalSupportDocument(TSD)forNSPSSubpart

OOOOprovidesadetailedanalysisofrodpackingreplacement.Theemissionsfromnewrodpackingare

estimatedintheTSDat11.5standardcubicfeetperhour(scfh).Baselineemissionsforrodpackingare

estimatedatapproximately57scfh,howevertheageofthepackingatthattimeisnotstated.Thereis

littledata

on

the

emissions

from

rod

packing

over

time

but

reductions

for

this

mitigation

option

come

fromreplacingtherodpackingatashorterintervalthancurrentlybeingpracticedatgivenfacility.

21ReducingMethaneEmissionsFromCompressorRodPackingSystems

http://www.epa.gov/gasstar/documents/ll_rodpack.pdf


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Forthisanalysisitwasassumedthatthefacilitycurrentlyreplacestherodpackingeveryfiveyearsand

thattheintervalisreducedtothreeyears(26,000hours).Itwasassumedthatthenewrodpacking

emits11.5scfhandtheemissionsincreaselinearlyto57scfhafterthreeyearsandincreaselinearly

thereafter.Comparing

the

emissions

under

this

scenario

for

15

years,

the

three

year

replacement

schedulewouldemit35%lessthanthefiveyearreplacementschedule. Inaddition,thecostofrod

packingreplacementwouldbe66%greaterforthethreeyearreplacementschedulethanthefiveyear

schedule.Asnotedabove,itwasassumedthatrodpackingisalreadychangedonthisscheduleinmany

processingplantsandsometransmissionstations,sotheapplicabilitywasreducedto25%for

processingand70%fortransmission,storageandLNG.TheassumptionsaresummarizedinTable35.

Table35 AssumptionsforRodPackingReplacement

CentrifugalCompressors(wetseals)Thesealsinacentrifugalcompressorperformasimilarfunction

totherodpackinginareciprocatingcompressorallowingtherotatingshafttomovefreelywithout

allowingexcessivehighpressuregastoescape(Figure36).Centrifugalcompressorswithwetsealsuse

circulatingoilasasealagainsttheescapeofhighpressuregas,andtheoilentrainssomeofthegasasit

circulatesthrough

the

compressor

seal.

This

gas

must

be

separated

from

the

oil

to

maintain

proper

operation(calleddegassingthesealoil),andthegasremovedfromthesealoilistypicallyventedto

theatmosphere.22Theseemissionscantotal30,000Mcf/yearormore.Whilewetsealscanbereplaced

bydrysealsthatdonotuseoilanddonotventsignificantamountsofgas,thisisanextremelyexpensive

process.Alowercostoptionistocaptureandusetheentrainedsealoilgasratherthanventingit.This

technologycurrentlyexistsatseveralcompressorstationsthathadsuchsystemsinstalledasoriginal

equipment,butithasnotbeenappliedcommerciallyasaretrofit.However,theequipmentneededfora

retrofitiscommerciallyavailable.Themeasuremodeledhereistoapplythistechnologyasaretrofit.

Thisisdescribedasoneofthecasestudiesinsection5.1wherethecapitalcostisestimatedat$33,700

fora99%reduction.Becausethistechnologyhasnotbeencommerciallydemonstratedasaretrofit,the

analysisassumedaconservativecostof$50,000and95%reduction,yieldingacosteffectivenessof

$4.87/Mcfwithcreditforrecoveredgasor$0.21/Mcfwithoutrecovery.Althoughthegascanbere

captured,itmaybedifficulttouseitproductively,asthisdependsonboththepressureofthecaptured

22ReplacingWetSealswithDrySealsinCentrifugalCompressors http://www.epa.gov/gasstar/documents/ll_wetseals.pdf

CapitalCost

per

Compressor

Percent

Reduction

Mcf

Reduced/year

Lifetime

(years)

Costw/oGas

Credit

$6,000 35% 350 3 $6.89/Mcf


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Replacehighemittingintermittentcontrollers(notdumpvalves)withlowbleedcontrollers.Somecomponentsrequirehighbleedcontrollersforoperationalreasons,primarilyforfastactingvalves

associatedwithcompressors,sothemeasurewasappliedtoonly60%oftheinventoryofhighbleed

controllersintransmission,storage,andLNG,80%inprocessingand90%ofthehighbleedcontrollersin

othersegments.AlthoughtherearelowercostestimatesfromGasSTARandvendors,thismeasure

assumedacostof$3,000perreplacementbasedonindustrycomments.Bothoptionsyieldagreater

than90%reduction.Thisyieldsareductioncostof$3.08/Mcfofmethaneforreplacementofhighbleed

pneumaticsand$0.58/Mcfofmethaneforreplacementofintermittentbleedpneumatics,includinga

creditforrecoveredgas,whereapplicable.

ChemicalInjectionPumpsThesearesmallpumpsusedtoinjectvariouschemicals,mostcommonly

methanol,intogaswellstopreventwellfreezeupduringcoldweather.Theyaretypicallydrivenbygas

pressureandventgaswhentheyoperate.Thesuggestedmitigationmeasureistoreplacethegasdriven

pumpswithelectricpumpsdrivenbysolarenergy.(Wellpadsandmanygathering/boostingstations

typicallydonothaveelectricity.)ThistechnologyhasbeendemonstratedbyGasSTARPartnersand

industryrespondentsindicatedthatitisgainingbroaderacceptance.Replacementresultsinelimination

ofthemethaneemissions,andthegasdrivenpumpcouldbeleftinplaceasabackup.Thecostofthe

measurewasestimatedat$5,000perpump,yieldinganannualreductionof180Mcf/yearandacost

effectivenessof$0.22/Mcfofmethanereducedwiththerecoveredgascredit.Localconditionsor

operationalconsiderationsmaylimittheapplicabilitysothemeasureisappliedto80%oftheinventory.

OilandCondensateTankswithoutControlDevicesCrudeoilandliquidcondensateproductionat

wellsandgatheringfacilitiesisstoredinfixedrooffieldtanksanddissolvedgasintheliquidsisreleased

andcollects

in

the

tank

space

above

the

liquid.

Ultimately,

this

gas

is

often

vented

to

the

atmosphere.

Vaporrecoveryunits(VRUs)collectandcompressthisgas,whichcanthenberedirectedtoasalesline,

usedonsiteforfuel,orflared.BasedonGasSTARandindustrydata,thecapitalcostofthismeasureis

assumedtobe$100,000withanoperatingcost(electricity)of$7,500peryearandareductionof13,410

Mcfperyear.Thisyieldsareductioncostof$0.51/Mcfifthegasisrecoveredforsaleor$4.57/Mcfifit

isflared.SomefacilitiesalreadyhaveVRUsandtheymaynotbeeffectivewheretheliquidvolumeis

smallorthemethanecontentislow.AlsoVRUsrequireelectricity,whichisnotavailableatallsites.For

thesereasons,themeasureisappliedto50%oftheremainingoiland25%oftheremainingcondensate

tankemissioninventory.

KimrayPumps

Kimray

pumps

are

gas

powered

pumps

used

to

circulate

glycol

in

gas

dehydrators.

They

arelargerthanthechemicalinjectionpumpsandventlargeramountsofgas.Inthefacilitiesthathave

electricity,thesecouldbereplacedbyelectricmotordrivenpumps.Thereplacementcostisestimated

at$10,000perpumpbasedonvendorandGasSTARdata.Unlikethesolarpumps,thesepumpswill

requiregridelectricity,estimatedtocost$2,000peryear.Basedona5,000Mcfemissionreduction,the

costeffectivenessis$4.17/Mcfofmethanewithcreditforgasrecoveredanditisappliedto50%ofthe

inventory.


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LiquidsUnloadingLiquidsunloadingistheprocessofremovingliquidsfromthebottomofgaswells

whentheaccumulationisimpedingthegasproduction.Theliquidsmustberemovedinordertoallow

effectiveproductionfromthewell.Historicallythishasbeenpracticedonolder,verticalwellswhose

pressurehasdeclined.

Whilethereareavarietyofmethodsofremovingthisliquid,onemethodisbyventingorblowingthe

welltotheatmosphere,usingthepressurizedgasinthereservoirtoliftandblowtheliquidsoutofthe

well.Thefrequencyanddurationofliquidsunloadingdependsonthewellandreservoirconditions,

however,ventingisnotaveryeffectivemethodofremovingtheliquids.Further,sincethewellisvented

totheatmosphere,itresultsinlargemethaneemissionsandlossesofgas.Therearemultiplemethods

ofremovingliquidswithoutventing,butinstandardpractice,theprimarygoalofliquidsunloadingisto

improvewellperformance,notreduceemissions.Thechoiceofmethodisnormallyafunctionofthe

costversusthevalueofimprovedwellperformance.Thistopicisfurtherdiscussedinsection5.4.

Figure37 PlungerLiftSchematic

Plungerliftsaredevicesthatfitintothewellboreandusethe

gaspressuretobringliquidstothesurfacemoreefficiently

whilecontrollingandlimitingtheamountofventing(Figure

37).Ifthereissufficientreservoirpressure,thegascanbe

directedtothesaleslinewithnoventing.Ifthereisinsufficient

pressuretodirectthegastothesaleslineandthegasmustbe

vented,theemissionscanstillbereducedby90%comparedto

uncontrolledventing.Plungerliftsarearelativelylowcost

optionandcanbeimplementedinarelativelysimplemanual

controlmethodormorecomplexautomatedinstallations.That

said,thetechnologydoeshavelimitations.Thewellmusthave

sufficientpressuretooperatetheplungerandolderwellsmay

requirecleanoutsorworkoverstoallowtheplungerto

operate.Further,notallwelltypescanuseaplungerliftfor

liquidsremoval.

GasSTARestimatesforplungerliftinstallationrangefrom$2,500to$10,00023butindustrycommenters

onthisstudycitedcostsintherangeof$15,000andpointedoutthatwelltreatmentsandcleanouts

mayberequiredbeforeplungerliftscanbeinstalled.Thisanalysisassumesacostof$20,000,including

theallowancethatsomewellsmayneedcleanoutsorotherwork. GasSTARPartnersreportreductions

ofventingemissionsof90%forplungerliftsthatdonotgotothesalesline.Inaddition,theyreportthat

liquidsunloadingcanincreaseproductionbyanywherefrom3to300thousandcubicfeetperday

23InstallingPlungerLiftSystemsInGasWellshttp://epa.gov/gasstar/documents/ll_plungerlift.pdf


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(Mcf/day).Theincreasedproductivityofthewellistheprimarygoalofliquidsunloadingandthehigher

gasproductioncanpayforthecostofplungerliftsmanytimesover.However,thesubsequentincrease

inwellproductivityisdifficulttopredictandisnotincludedinthisanalysis.Withoutcreditforthe

productivityincrease,

the

cost

effectiveness

breakeven

point

is

at

about

1,200

Mcf/year

of

venting,

estimatedhereasareductioncostof$0.05/Mcfreduced.

Ifthewelldoesnothavesufficientpressureorcannotsupportaplungerlift,thereareavarietyof

mechanicalpumpingtechnologiesthatcanbeemployedtoremoveliquids.However,thesearemuch

moreexpensiveandwhiletheymayhaveapositivepaybackforincreasingwellproduction,theymost

oftendonotpurelyforthemethaneemissionreduction.Moreover,themethanereductionvalueonly

appliesifthewellwouldotherwisebevented.Asthewellpressuredeclines,ventingbecomesa

diminishinglyeffectiveoption.Inaddition,itisnotclearhoweffectiveventingwillbeatremovingliquids

fromlonghorizontalwellsthatarenowbeingdrilled.Itmaybethatventingforliquidsremovalwill

continueto

be

primarily

focused

on

older,

vertical

wells.

TheGHGReportingProgramSubpartWprovidesdataonwellsthatareventingforliquidsunloading

withandwithoutplungerlifts.Thedatafor2012showover53,000wellsventinganaverageof167Mcf

peryearwithoutplungerliftsandover74,000wellswithplungerliftsventinganaverageof277Mcfper

year.Wellsthatuseplungerliftsandsendthegastothesaleslinedonothaveanyventingemissions

anddonotreporttothispartofSubpartW.Whileitseemscounterintuitivethatwellswithplungerlifts

thatventwouldbeemittingmorethanthosewithoutplungerlifts,ICFinterpretsthisinformationto

indicatethatmostofthewellswiththelargestventingemissionshavealreadyinstalledplungerlifts

whilemostoftheremainingwellsareventinginfrequentlyorventingsmallvolumesthatdonotjustify

thecost

of

installing

plunger

lifts.

That

said,

there

are

asmall

number

of

wells

without

plunger

lifts

that

reportlargerventingemissionsandaccountforadisproportionatefractionoftheventingemissionsfor

wellswithoutplungerlifts,approximately36%oftotalventingemissions.Installingplungerliftsonthese

wellscouldbecosteffectiveandcreatesignificantemissionreductions. Becauseplungerliftsarenot

applicabletoallwells,themeasurewasappliedto30%ofthisemissionsegmentfortheanalysis.

Asnotedabove,wellswithplungerliftsalsoreportsignificantemissionsfromventing.Operationofa

plungerliftiscomplexanditseffectivenessasanemissionreductiontechniquedependsonmany

factorstooperatetheplungerattheoptimumtimetomaximizeproductionandminimizeemissions.

Approachestoplungerliftoperationrangefromadhocmanualoperation,tofixedmechanicaltimers,to

programmablefuzzy

logic

automated

controllers.

Specific

data

on

the

potential

reductions

from

optimizedplungerliftoperationisnotavailablebutitisclearfromindustryexperiencethatan

integratedprogramoftraining,technology,andautomationcanimprovetheperformanceofplunger

liftsforbothproductivityandemissionreductions.Consequently,theremaybeanopportunityfor

significantemissionreductionthroughoptimizationofplungerlifts,whichisnotincludedhereand

wouldbeadditionaltothereductionestimatesthisanalysisprovidesforinstallationofnewplungerlifts.


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respondentssuggestedacostof$30,000forafullstationredesign.Thecostadoptedfortheanalysis

was$15,000assumingachangeinprocedurebutnostationredesign,yieldingacosteffectivenessof

$0.98/Mcfwithnogasrecoverycredit.

Summary

Table36summarizesthemitigationmeasuresappliedintheanalysisforeachmajoremissionsource.

Table37summarizesthecharacteristicsofthemeasuresmodeled.Thecosteffectiveness($/Mcfof

methaneremoved)wascalculatedwithandwithoutcreditforanyrecoveredgas.Theannualcostwas

calculatedastheannualamortizedcapitalcostovertheequipmentlifeplusannualoperatingcosts.This

wasdividedbyannualmethanereductionstocalculatethecosteffectivenesswithoutcreditfor

recoveredgas.Wheregascanberecoveredandmonetizedbytheoperatingcompany,thevalueofthat

gaswassubtractedfromtheannualcosttocalculatethecosteffectivenesswithcreditforrecovered

gas.The

costs

shown

here

are

the

baseline

costs,

which

are

adjusted

for

regional

cost

variation

in

the

analysis.Asnotedearlier,theseareaveragecoststhatmaynotreflectsitespecificconditionsat

individualfacilities.


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Table36 SummaryofMitigationMeasuresApplied

Source MitigationMeasureOil/Condensate Tanks

w/o

Control

Devices VaporRecoveryUnits

LiquidsUnloading Wellsw/oPlungerLifts PlungerliftsHighBleedPneumaticDevices ReplacewithlowbleeddevicesIntermittentBleedPneumaticDevices ReplacewithlowbleeddevicesChemicalInjectionPumps SolarelectricpumpsKimrayPumps ElectricpumpsPipelineVenting(RoutineMaintenance/Upsets) PipelinepumpdownCentrifugalCompressors(wetseals) WetsealgascaptureTransmissionStationVenting GascaptureOilWellCompletions withFracturing FlaringStrandedGasVentingfromOilWells FlaringReciprocatingCompressorRodPacking RodpackingreplacementReciprocatingCompressorFugitives Leakdetectionandrepair (LDAR)CompressorStationFugitives Leakdetectionandrepair (LDAR)WellFugitives Leakdetectionandrepair (LDAR)GatheringStationFugitives Leakdetectionandrepair (LDAR)LargeLDCFacilityFugitives Leakdetectionandrepair(LDAR)


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EconomicAnalysisofMethaneEmissionReductionOpportunitiesintheU.S.OnshoreOilandNatural


Table37 SummaryofMitigationMeasureCharacteristics

Name CapitalCostOperating

Cost

Percen

Reductio

Earlyreplacementofhighbleeddeviceswithlowbleeddevices $3,000 $0 9

Earlyreplacementofintermittentbleeddeviceswithlowbleeddevices $3,000 $0 9

ReplacementofReciprocatingCompressorRodPackingSystems $6,000 $0 3

InstallFlaresCompletion $50,000 $6,000 9

InstallFlaresVenting $50,000 $6,000 9

LiquidUnloading InstallPlungerLiftSystemsinGasWells $20,000 $2,400 9

InstallVaporRecoveryUnitsonTanks $100,000 $7,500 9

TransmissionStationVentingRedesignBlowdownSystems/ESDPractices $15,000 $0 9

ReplacePneumaticChemicalInjectionPumpswithSolarElectricPumps $5,000 $75 10

ReplaceKimrayPumpswithElectricPumps $10,000 $2,000 10

PipelineVenting PumpDownBeforeMaintenance $0 $12,000 8

WetSealDegassingRecoverySystemforCentrifugalCompressors $50,000 $0 9

LDARWells $169,923 $146,250 6

LDARGathering $169,923 $146,250 6

LDARLargeLDCFacilities $169,923 $146,250 6

LDARProcessing

$169,923

$146,250 6

LDARTransmission $169,923 $146,250 6


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3.6. SourceCategoriesNotAddressedSeveralsourcecategorieswithrelativelylargeemissionswerenotaddressedintheanalysis.Thesources

andthe

reasons

for

their

treatment

are

summarized

below.

OffshoreoilandgasproductionAsnotedearlier,theEPAinventoryprovidesverylimiteddataonoffshoreemissions,whichwerenotadequatetoapplythemethodologyusedforothersources.This

isanareainwhichfurtheranalysiswouldprobablyyieldadditionalopportunitiesforreduction.

CastirongasmainsCastironmainshavebeenidentifiedisasignificantemissionsource,howevertheyareprimarilylocatedincongestedurbanareaswherereplacementorrepair isveryexpensive,

reportedas$1millionto$3millionpermile.Thismakesforaveryexpensivecontroloptionbased

purelyonemissionreduction.Moreover,theseexpendituresmustbeapprovedbystateutility

commissions,whosepurviewtypicallydoesnotextendtoenvironmentalremediationofthistype.

Thatsaid,approximately3%ofcastironmainsarebeingreplacedeachyearforsafetyreasons,so

theemissionsaregraduallydeclining.Newtechnologiescouldreducethecostofreductioninthe

future.

EngineexhaustTheexhaustfromgasburningenginesandturbinescontainsasmallamountofunburnedmethanefromincompletecombustionofthefuel.Whileitisasmallpercentage,itis

significantinaggregate.Oxidationcatalystdevicesareusedtoreduceunburnedemissionsofother

hydrocarbonsintheexhaustbuttheyarenoteffectiveatreducingemissionsofmethaneduetoits

lowerreactivity.However,newcatalystsarebeingdeveloped,inpartfornaturalgasvehicles,which

maybeapplicabletothesesources.Thisisatopicforfurtherresearchandtechnologydeployment.

OthersourcesThereareadditionalcosteffectivemeasuresformethanereductionthathavebeenidentifiedbytheEPAGasSTARprogramandothers.Theyarenotincludedherebecausethisreport

focusesonlyonthelargestemittingsources.However,theiromissionshouldnotbetakento

indicatethatthemeasureslistedherearetheonlycosteffectivemethanereductionmeasures.


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4.AnalyticalResults4.1. DevelopmentofEmissionControlCostCurvesWiththe2018ProjectedBaselineestablishedandmitigationtechnologiesidentifiedandcharacterized

forthemajoremittingsectors,emissioncostreductioncurveswerecalculatedforavarietyofscenarios.

Themodeldevelopedforthistaskincludestheindividualsourcecategoriesforeachsegmentoftheoil

andgasindustrybyregion.Mitigationtechnologiescanbematchedtoeachsourcebyregionand/or

individualsourceapplied.Themodelcanalsospecifywhatportionofeachsourcepopulationthe

measureappliestoandwhetheritappliestonew(post2011),existing(asof2011),orallfacilities.The

modelcalculatesthereductionachievedforeachsourceandcalculatesthecostofcontrolbasedonthe

capitalandoperatingcosts,theequipmentlife,andwhereappropriate,thevalueofrecoveredgas.Key

globalinputassumptionsinclude:whetheraparticularsegmentisabletomonetizethevalueof

recovered

gas,

the

value

of

gas,

and

the

discount

rate/cost

of

capital.

A

construction

cost

index

is

used

toaccountforregionalcostdifferences,whichare13%to24%higherforcontinentalU.S.locations

otherthanthebaselineGulfCoastcosts.

TheresultsarepresentedprimarilyasaMarginalAbatementCostCurve(MACcurve),showninFigure

41. Thisrepresentationshowstheemissionreductionssortedfromlowesttohighestcostofreduction

andshowstheamountofemissionreductionavailableateachcostlevel.Theverticalaxisshowsthe

costperunitin$/Mcfofmethanereduced.Anegativecostofreductionindicatesthatthemeasurehas

apositivefinancialreturn,i.e.savesmoneyfortheoperator. Thehorizontalwidthofthebarsshowsthe

amountofreduction.Theareawithinthebarsisthetotalcostperyear.Theareabelowthehorizontal

axis

represents

savings

and

the

area

above

the

axis

represents

cost.

The

net

sum

of

the

two

is

the

total

netcostperyear.


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AnalyticalResults


Figure41 ExampleMACCurve

4.2.EmissionReductionCostCurvesThissectionpresentstheresultsofthecostcurveanalysis.Thecurvesrepresentdifferentviewsofa

potentialemissioncontrolscenarioin2018basedonmeasuresinstalledbetween2011and2018.The

emission

reduction

costs

are

the

annual

costs

per

Mcf

of

methane

reduced.

This

should

not

be

confused

withcostperMcfofnaturalgasproduced,whichisanentirelydifferentmetric.Inthecasesshownhere,

thetotalannualcostofreductionsdividedbytotalU.S.gasproductionislessthan$0.01/Mcfofgas

producedinallcases.

Thereareseveralcaveatstotheresults:

The2011EPAinventoryisthebeststartingpointforanalysis,butitisbasedonmanyassumptionsandsomeolderdatasources.Althoughtheinventoryisimprovingwithnewdata,itisdesignedto

beaplanningandreportingdocumentandisimperfect,especiallyatthedetailedlevel,fora

granularanalysisofthistype.

Emissionmitigationcostandperformancearehighlysitespecificandvariable.Thevaluesusedhereareestimatedaveragevalues.

Theanalysispresentsareasonableestimateofpotentialcostandmagnitudeofreductionswithinarangeofuncertainty.


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AnalyticalResults


Thebasecaseassumptionfortheresultsinthissectionassumesa$4/Mcfpriceforrecoveredgasanda

10%discountrate/costofcapitalforcalculatingthecostofcontrol. Additionalsensitivityand

alternativecasesareshowninAppendixA.

Figure42showsthenationalaggregateMACcurveforthebaselinetechnologyassumptionsbysource

category.Itshowsthereductionsachievablefromeachsourcewiththerelevan

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