quest annual summary 2017 rev7 · 2019-03-12 · quest continues to see operating efficiencies with...

QuestCarbonCaptureandStorageProject

ANNUALSUMMARYREPORT‐ALBERTADEPARTMENTOFENERGY:2017

March2018

DisclaimerThisReport,includingthedataandinformationcontainedinthisReport,isprovidedtoyouonan“asis”and“asavailable”basisatthesolediscretionoftheGovernmentofAlbertaandsubjecttothetermsandconditionsofusebelow(the“TermsandConditions”).TheGovernmentofAlbertahasnotverifiedthisReportforaccuracyanddoesnotwarranttheaccuracyof,ormakeanyotherwarrantiesorrepresentationsregarding,thisReport.Furthermore,updatestothisReportmaynotbemadeavailable.YouruseofanyofthisReportisatyoursoleandabsoluterisk.

ThisReportisprovidedtotheGovernmentofAlberta,andtheGovernmentofAlbertahasobtainedalicenseorotherauthorizationforuseoftheReports,from:

CanadianNaturalUpgradingLimited,ChevronCanadaLimitedand1745844AlbertaLtd.,asowners,andShellCanadaEnergyasoperator,fortheQuestProject

(collectivelythe“Project”)

EachmemberoftheProjectexpresslydisclaimsanyrepresentationorwarranty,expressorimplied,astotheaccuracyorcompletenessofthematerialandinformationcontainedherein,andnoneofthemshallhaveanyliability,regardlessofanynegligenceorfault,foranystatementscontainedin,orforanyomissionsfrom,thisReport.UndernocircumstancesshalltheGovernmentofAlbertaortheProjectbeliableforanydamages,claims,causesofaction,losses,legalfeesorexpenses,oranyothercostwhatsoeverarisingoutoftheuseofthisReportoranypartthereofortheuseofanyotherdataorinformationonthiswebsite.TermsandConditionsofUseExceptasindicatedintheseTermsandConditions,thisReportandanypartthereofshallnotbecopied,reproduced,distributed,republished,downloaded,displayed,postedortransmittedinanyformorbyanymeans,withoutthepriorwrittenconsentoftheGovernmentofAlbertaandtheProject.

TheGovernmentofAlberta’sintentinpostingthisReportistomakethemavailabletothepublicforpersonalandnon‐commercial(educational)use.YoumaynotusethisReportforanyotherpurpose.YoumayreproducedataandinformationinthisReportsubjecttothefollowingconditions:

anydisclaimersthatappearinthisReportshallberetainedintheiroriginalformandappliedtothedataandinformationreproducedfromthisReport

thedataandinformationshallnotbemodifiedfromitsoriginalform theProjectshallbeidentifiedastheoriginalsourceofthedataandinformation,whilethis

websiteshallbeidentifiedasthereferencesource,and thereproductionshallnotberepresentedasanofficialversionofthematerialsreproduced,

norashavingbeenmadeinaffiliationwithorwiththeendorsementoftheGovernmentofAlbertaortheProject

ByaccessingandusingthisReport,youagreetoindemnifyandholdtheGovernmentofAlbertaandtheProject,andtheirrespectiveemployeesandagents,harmlessfromandagainstanyandallclaims,demands,actionsandcosts(includinglegalcostsonasolicitor‐clientbasis)arisingoutofanybreachbyyouoftheseTermsandConditionsorotherwisearisingoutofyouruseorreproductionofthedataandinformationinthisReport.

YouraccesstoanduseofthisReportissubjectexclusivelytotheseTermsandConditionsandanytermsandconditionscontainedwithintheReportitself,allofwhichyoushallcomplywith.YouwillnotusethisReportforanypurposethatisunlawfulorprohibitedbytheseTermsandConditions.YouagreethatanyotheruseofthisReportmeansyouagreetobeboundbytheseTermsandConditions.TheseTermsandConditionsaresubjecttomodification,andyouagreetoreviewthemperiodicallyforchanges.IfyoudonotaccepttheseTermsandConditionsyouagreetoimmediatelystopaccessingthisReportanddestroyallcopiesinyourpossessionorcontrol.

TheseTermsandConditionsmaychangeatanytime,andyourcontinueduseandreproductionofthisReportfollowinganychangesshallbedeemedtobeyouracceptanceofsuchchange.

IfanyoftheseTermsandConditionsshouldbedeterminedtobeinvalid,illegalorunenforceableforanyreasonbyanycourtofcompetentjurisdictionthentheapplicableprovisionshallbeseveredandtheremainingprovisionsoftheseTermsandConditionsshallsurviveandremaininfullforceandeffectandcontinuetobebindingandenforceable.

TheseTermsandConditionsshall:(i)begovernedbyandconstruedinaccordancewiththelawsoftheprovinceofAlbertaandyouherebysubmittotheexclusivejurisdictionoftheAlbertacourts,and(ii)ensuretothebenefitof,andbebindingupon,theGovernmentofAlbertaandyourrespectivesuccessorsandassigns.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Executive Summary

Shell Canada Energy March 2018 Page i

Executive Summary ThisSummaryReportisbeingsubmittedinaccordancewiththetermsoftheCarbonCaptureandStorage(CCS)FundingAgreement–QuestProject,dated June24,2011betweenHerMajesty theQueeninRightofAlbertaandShellCanadaEnergy,asoperatoroftheQuestCCSfacility(Quest)andasagentforandonbehalfoftheAOSPJointVentureanditsparticipants,comprisingShellCanadaEnergy(60%),ChevronCanadaLimited(20%)and1745844AlbertaLimited(20%),asamended.Notethat,althoughShellCanadaEnergyhasdivestedits60%interestintheAOSPJointVenturetoCanadianNaturalUpgradingLimited,effectiveMay31,2017,ShellCanadaEnergycontinuestoholdtherightsandobligationsundertheCarbonCaptureandStorage(CCS)FundingAgreementatthedatehereof.

ThepurposeofQuestistodeploytechnologytocaptureCO2producedattheScotfordUpgraderandto compress, transport, and inject the CO2 for permanent storage in a saline formation nearThorhild,Alberta.Approximately1.2Mt/aofCO2willbecaptured,representinggreaterthan35%oftheCO2producedfromtheScotfordupgrader.

First injection of CO2 into injection wells 7‐11 and 8‐19 occurred on August 23, 2015 andcommercialoperationwasachievedonSeptember28,2015afterthesuccessfulcompletionofthethree performance tests outlined in Schedule F of the CCS Funding Agreement. In 2017, Questsurpassed2Milliontonnesof injectedCO2andwasrecognizedbytheGlobalCarbonCaptureandStorageInstitute(GCCSI)assettinganewrecordforthemostCO2sequesteredinacalendaryear.

Reservoirperformanceandinjectivityassessmentsthusfarindicatethattheprojectwillbecapableof sustaining adequate injectivity for the duration of the project life; therefore, no further welldevelopment should be required. MMV activities are focused on operational monitoring andoptimization.

Therewerenorecordablespills/releasestoair,soilorwaterwithintheQuestcaptureunitduringthe 2017 operating period. MMV data indicates that no CO2 has migrated outside of the BasalCambrianSands(BCS)injectionreservoirtodate.

Shellconductedanotheropenhouseforthelocalcommunity.Engagementwithlocalgovernmentscontinuedin2017toupdateofficialsonoperations.Engagementwithnumerousindustryandnon‐governmentassociationsforknowledgesharingalsocontinuedin2017.

Questhasexperiencedanumberofsuccessesinthisreportingperiod,including:

Sustained,safe,andreliableoperations

LowlevelsofchemicallossfromtheADIP‐xprocess

Significantly lower carryover of triethylene glycol (TEG) into CO2 vs. design withestimatedlossesontracktoberoughly5,800kgin2017vs.thedesignmakeuprateof46,000kgannually

Injection into the5‐35well continues tonot tobenecessarydue to strong injectivityperformance,whichresultsinsignificantMMVcostsavings

Strong evidence that Quest will sustain adequate injectivity for the duration of theprojectlife

Overallmaintenanceissueshavebeenminimal

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Executive Summary

Shell Canada Energy March 2018 Page ii

Sharingofbestpracticesbynetworkingwithotheroperatingfacilitiescontinuestohelpimprovemaintenancepracticesandprocedures

Strongintegratedprojectreliabilityperformancewithoperationalavailabilityat98.3%

Maintaininglocalsupportthroughtheextensivestakeholderengagementactivities

ContinuedparticipationoftheCommunityAdvisoryPanel(CAP)

InternationalengagementswiththeGlobalCCSInstitutetosupportpublicengagement,globalknowledgesharingactivitiesandnumeroustourstotheScotfordfacility

Continuedworkwith a United StatesDepartment of Energy‐funded entity to developanddeployMMVtechnologiesforuseonQuest

Milestoneof2milliontonnesofCO2injectedwasreachedinJune2017.

Operatingcostscontinuetobelowerthanforecasted.

Serializationof1,212,182creditsin2017(from2015and2016operatingyears)

Challengesforthisreportingperiodwereminoroperationalissues,including:

Lossofaminecirculationduetoleanaminechargepumptripsonlowsuctionpressures.

HighmoisturepipelinetripwhileplacingtheTEGcarbonfiltersysteminserviceaftercarbonfilterreplacement.

Questhasseenstrongreliabilityperformancethroughthereportingperiodtosafelyinject1.14MtofCO2in2017.Overallprojectinjectionhassurpassed2.6MtofCO2todate.RevenuestreamsgeneratedbyQuestwillremaintwofold:(i)thegenerationofoffsetcreditsforthenetCO2sequesteredandanadditionaloffsetcreditgeneratedfortheCO2captured,bothundertheSpecifiedGasEmittersRegulation;and(ii)$298millioninaggregatefundingfromtheGovernmentofAlbertaduringthefirst10yearsofOperationforcapturingupto10.8milliontonnes.In2017,thevalueoftheoffsetcreditwas$30/tonne.Quest continues to see operating efficiencies with the compressor given the more favourablesubsurfaceporespace.Thecompressorcontinuestooperateutilizing13‐15MWversus18MWasfulldesign.Quest provides employment for 14 permanent full time equivalent positions (FTEs) and anadditionalapproximately10FTEallocatedintoexistingpositions.Questgeneratedexpendituresof~$32millionin2017instaffing,MMV,maintenance,andvariablecoststotheeconomy.Questcontinues to receivesignificant international interest fromprojects inNorway,delegationsfrom Mexico and the GCCSi, various technical organizations, and presented at COP23 in Bonn,Germany.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Table of Contents

Shell Canada Energy March 2018Page iii

TableofContents1 OverallFacilityDesign ............................................................................................................. 1-1 1.1 DesignConcept............................................................................................................................ 1-1 1.2 DesignScope ............................................................................................................................... 1-1 1.3 ORMDesignFrameworkandProjectMaturity ........................................................................ 1-1 1.4 FacilityLocationsandPlotPlans ............................................................................................... 1-3 1.5 ProcessDesign ............................................................................................................................ 1-8

1.5.1 ProcessDescription ..................................................................................................... 1-10 1.6 ModularizationApproach ........................................................................................................ 1-14 2 FacilityConstructionSchedule .............................................................................................. 2-1 3 GeologicalFormationSelection ............................................................................................. 3-1 3.1 StorageAreaSelection ................................................................................................................ 3-1 3.2 GeologicalFramework ............................................................................................................... 3-3 3.3 BCSReservoirProperties ........................................................................................................... 3-5 3.4 EstimateofStoragePotential ..................................................................................................... 3-7 3.5 InjectivityAssessment ................................................................................................................ 3-7 3.6 RisktoContainmentinaGeologicalFormation ....................................................................... 3-8 4 FacilityOperations–CaptureFacilities ............................................................................... 4-1 4.1 OperatingSummary.................................................................................................................... 4-1

4.1.1 QuestAuditsandCreditSerialization .......................................................................... 4-1 4.2 Capture (Absorbers and Regeneration) ........................................................................................ 4-2 4.3 Compression ................................................................................................................................. 4-5 4.4 Dehydration .................................................................................................................................. 4-6 4.5 Upgrader Hydrogen Manufacturing Units.................................................................................... 4-6 4.6 Non-CO2 Emissions to Air, Soil or Water ................................................................................... 4-7 4.7 Operations Manpower .................................................................................................................. 4-7 5 FacilityOperations–Transportation ................................................................................... 5-1 5.1 PipelineDesignandOperatingConditions ............................................................................... 5-1 5.2 PipelineSafeguardingConsiderations ...................................................................................... 5-5 6 FacilityOperations - Storage and Monitoring ......................................................................... 6-1 6.1 StoragePerformance .................................................................................................................. 6-1 6.2 MMV Activities - Operational Monitoring .................................................................................. 6-5 6.3 WellsActivities ............................................................................................................................ 6-6

6.3.1 InjectionWells ............................................................................................................... 6-6 6.3.2 Monitorwells ................................................................................................................. 6-6 6.3.3 SurfaceCasingVentFlowandGasMigrationMonitoring .......................................... 6-8

7 Facility Operations - Maintenance and Repairs ...................................................................... 7-1 8 Regulatory Approvals ................................................................................................................ 8-1 8.1 RegulatoryOverview .................................................................................................................. 8-1 8.2 RegulatoryHurdles ..................................................................................................................... 8-1 8.3 RegulatoryFilingsStatus ........................................................................................................... 8-1 8.4 NextRegulatorySteps ................................................................................................................ 8-2 9 Public Engagement ..................................................................................................................... 9-1 9.1 BackgroundonProjectandConstructionConsultationandEngagement ............................. 9-1 9.2 StakeholderengagementfortheQuestCCSFacility ................................................................ 9-2

9.2.1 CommunityRelations .................................................................................................... 9-2

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Lists of Tables and Figures

Shell Canada Energy March 2018Page iv

9.3 CCSKnowledgeSharing ............................................................................................................. 9-4 10 CostsandRevenues ................................................................................................................ 10-1 10.1 CapexCosts ................................................................................................................................ 10-1 10.2 OpexCosts ................................................................................................................................. 10-2 10.3 Revenues ................................................................................................................................... 10-3 10.4 FundingStatus .......................................................................................................................... 10-4 11 ProjectTimeline ..................................................................................................................... 11-1 12 GeneralProjectAssessment ................................................................................................. 12-1 12.1 Indirect Albertan and Canadian Economic Benefits .................................................................. 12-3 13 NextSteps ................................................................................................................................. 13-1 14 References ................................................................................................................................. 14-1

ListofTables

Table 3-1: Assessment of the BCS for Safety and Security of CO2 Storage ............................................ 3-2 Table 3-2: Depositional Environment in LMS-BCS for the injection wells from the core data .............. 3-6 Table 3-3: Remaining capacity in the Sequestration Lease Area as of end 2017 ..................................... 3-7 Table 4‐1: Quest Operating Summary 2017 ............................................................................................ 4-1 Table 4-2: Energy and Utilities Consumption (Capture, Dehydration) .................................................... 4-3 Table 4-3: Typical Compressor Operating Data ....................................................................................... 4-5 Table 5-1: Pipeline Design and Operating Conditions ............................................................................. 5-1 Table 5-2: Pipeline Dimensional Data ..................................................................................................... 5-3 Table 5-3: Pipeline Fluid Composition .................................................................................................... 5-4 Table 6-1: Overall assessment of trigger events used to assess loss of containment in 2017 .................. 6-6 Table 8-1: Regulatory Approval Status .................................................................................................... 8-1 Table 9-1: 2017 Knowledge Sharing ........................................................................................................ 9-4 Table 10-1: Project Incurred Capital Costs (,000) .................................................................................. 10-1 Table 10-2: Project Operating Costs (,000) ............................................................................................ 10-2 Table 10-3: Project Revenues ................................................................................................................. 10-3 Table 10-4: Government Funding Granted and anticipated ................................................................... 10-4 Table 11-1: Project Timeline .................................................................................................................. 11-2

ListofFigures

Figure 1-1: ORM Phases with current Project Maturity. .......................................................................... 1-2 Figure 1-2: Project Facility Locations. ..................................................................................................... 1-4 Figure 1-3: Capture Unit Location Schematic. ......................................................................................... 1-5 Figure 1-4: BCS Storage Complex within the Regional Stratigraphy. ..................................................... 1-6 Figure 1-5: Project Components and Sequestration Lease Area. ............................................................. 1-7 Figure 1-6: Capture and Compression Process Design. ........................................................................... 1-9 Figure 2-1:ProjectConstructionSchedule. ........................................................................................... 2-2 Figure 3-1:Cross‐SectionoftheWCSBShowingtheBCSStorageComplex. ....................................... 3-4 Figure 3-2:SummaryofzonethicknessesforQuestSequestrationrightsinterval. .......................... 3-5 Figure 3-3: BCS Reservoir Properties. ..................................................................................................... 3-6 Figure 3-4: Ion Ration plot of BCS Formation brine waters .................................................................... 3-7 Figure 6-1: Quest Injection Totals: . ......................................................................................................... 6-2 Figure 6-2: Quest Injection Stream Content: Average injection composition for 2017. .......................... 6-2 Figure 6-3: The 8-19 Injection Well: Average daily P/T conditions. ....................................................... 6-3

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Table of Contents

Shell Canada Energy March 2018Page v

Figure 6-4: The 7-11 Injection Well: Average daily P/T conditions. ....................................................... 6-4Figure 6-5: Quest DMW pressure history before and during injection.....................................................6-7Figure 6-6: Quest 3-4 DMW pressure history...........................................................................................6-7Figure 6-7: SCVF Pressure and Flow rate summary graphs for IW 5-35, IW 7-11 and IW 8-19...........6-8

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Abbreviations

Shell Canada Energy March 2018 Page vi

Abbreviations

2D........................................................................................................................................2‐Dimensional3D.........................................................................................................................................3‐Dimensional4D.........................................................................................................................................4‐DimensionalACCO...................................................................................................AlbertaClimateChangeOfficeAER...............................................................................................................AlbertaEnergyRegulatorAEW.................................................................................................AlbertaEnvironmentandWaterAFN....................................................................................................................AlexanderFirstNationAGS................................................................................................................AlbertaGeologicalSurveyAOI.....................................................................................................................................AreaofInterestAOSP.........................................................................................................AthabascaOilSandsProjectARC................................................................................................................AlbertaResearchCouncilASLB................................................................................approvedsequestrationleaseboundaryASRD......................................................................AlbertaSustainableResourcesDevelopmentBCS.......................................................................................................................BasalCambrianSandsBHP.......................................................................................................................bottom‐holepressureBLCN.............................................................................................................BeaverLakeCreeNationCCS...........................................................................................................carboncaptureandstorageCEAA...............................................................................CanadianEnvironmentalAssessmentActCSU..............................................................................................................Commissioning&StartUpD51..................................................................................................................Directive51applicationD56..................................................................................................................Directive56applicationD65..................................................................................................................Directive65applicationERCB...................................................................................EnergyResourcesConservationBoardFEED...........................................................................................FrontEndEngineeringandDesignFEP............................................................................................................fractureextensionpressureFGR......................................................................................................................FlueGasRecirculationFID................................................................................................................FinalInvestmentDecisionGHG...............................................................................................................................greenhousegasesHBMP.......................................................................Hydrosphere&BiosphereMonitoringPlanHMUs................................................................................................hydrogenmanufacturingunitsHPLT.............................................................................................HighPressureLowTemperatureHVP..........................................................................................................................highvaporpressureInSAR............................................................................InterferometricsyntheticapertureradarLBV..................................................................................................................................linebreakvalveLMS............................................................................................................................LowerMarineSandLRDF......................................................................................................longrunningductilefractureMCS....................................................................................................................MiddleCambrianShaleMMV..........................................................................measurement,monitoringandverificationMSM.................................................................................................MicroseismicMonitoringArrayORM.................................................................................................OpportunityRealizationManualOSCA..................................................................................................................OilSandsConservationActPSA.................................................................................................................pressureswingadsorberRCM..............................................................................................ReliabilityCenteredMaintenanceRFA..........................................................................................RegulatoryFrameworkAssessmentROW.........................................................................................................................................right‐ofway

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Abbreviations

Shell Canada Energy March 2018 Page vii

SAP..............................Systems,Applications,Processes(EquipmentDatabaseSoftware)SLCN...............................................................................................................SaddleLakeCreeNationSTCC................................................................................................ShellTechnologyCentreCalgaryTEG.................................................................................................................................triethyleneglycolUMS....................................................................................................................UpperMarineSiltstoneVSP......................................................................................................................verticalseismicprofileWCSB.......................................................................................WesternCanadaSedimentaryBasinWIIP..................................................................................................................................waterinitiallyinplace

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 1: Overall Facility Design

Shell Canada Energy March 2018 Page 1-1

1 OverallFacilityDesign

1.1 DesignConceptTheScotfordUpgrader,operatedbyShellCanadaEnergy,asagentforandonbehalfoftheAthabascaOilSandsProject(AOSP)JointVentureanditsparticipants,comprisingCanadian Natural Upgrading Limited (60%), Chevron Canada Limited (20%) and1745844AlbertaLimited(20%),ispartofShell’sScotfordfacilitylocatednortheastofEdmonton.NotethatalthoughCanadianNaturalUpgradingLimitedisa60%owneroftheScotfordUpgrader,ShellCanadaEnergycontinuestoholdtherightsandobligationsundertheCarbonCaptureandStorage(CCS)FundingAgreement–QuestProject,datedJune 24, 2011, which are associatedwith that 60% interest. The design concept forQuest is to remove CO2 from the process gas streams of the three hydrogen‐manufacturing units (HMUs), within the Scotford upgrader facility. This is done byusing amine technology, dehydrating and compressing the captured CO2 to a dense‐phasestateforefficientpipelinetransportationtothesubsurfacestoragearea.

ThethreeHMUscomprisetwoidenticalexistingHMUtrainsinthebaseplantScotfordUpgrader and a third one constructed as part of the Scotford Upgrader Expansion 1Project,whichhasbeenoperationalsinceMay2011.

1.2 DesignScopeThedesignscopeforthefacilitiesincluded:

ModificationsonthethreeexistingHMUs

Modificationsonthethreeexistingpressureswingadsorbers(PSAs)

ThreeamineabsorptionunitslocatedateachoftheHMUs

AsinglecommonCO2amineregenerationunit(aminestripper)

ACO2ventstack

ACO2compressionunit

Atriethyleneglycol(TEG)dehydrationunit

ShellScotfordutilitiesandoffsiteintegration

CO2pipeline,laterals,andsurfaceequipment

Threeinjectionwells

1.3 ORMDesignFrameworkandProjectMaturityThe design framework followed by Quest is the standard Shell approach in projectdesign,calledtheOpportunityRealizationManual(ORM).TheORMprocessmanagesaprojectasitmaturesthroughitslifecyclefrominitialconcepttoremediationfollowingclosure.ORMdividesthislifecycleintostagesasshowninFigure1‐1.Deliverablesforeachphasearereviewedtoensureproperqualitybeforeproceedingtothenextphase.



Figure1‐1:ORMPhaseswithcurrentProjectMaturity.

QuesttechnicalprojectactivitiesintheDefinephasein2011includedtheengineeringwork required to deliver key project documents of this phase, including the BasicDesignEngineeringPackage(BDEP),theProjectExecutionPlan(PEP)andtheStorageDevelopmentPlan(SDP).

In September 2011, Shell completed the Define phase, which culminated with therequired value assurance review (VAR).TheVARexamined the status of theproject,including theDefine phase deliverables and concluded that the projectwas ready toproceedtothenextdecisiongate.

Under normal circumstances, the Final Investment Decision (FID) follows thesuccessfulconclusionoftheDefinephasepriortomovingtothenextphase.However,QuestatthatpointdidnothavetherequiredprojectprovincialandfederalregulatoryapprovalsthattheShellExecutiveCommittee(EC)setasaconditionforapprovingFID.Energy Resources Conservation Board (ERCB) regulatory hearing dates expected inNovemberin2011werescheduledforMarch2012delayingthepossibleapprovaldate.InDecember2011,Shellmadearisk‐baseddecisiontoproceedintotheExecutePhasebeforefinalregulatoryapprovalinordertoholdtotheprojectschedule.AfterreceiptoftheERCBDecisionReport, theShellExecutiveCommittee, followedbytheAOSPJointVenturepartners,approvedtheFIDoftheProjectinthesummerof2012.Afterformalreceiptofthevariousregulatoryapprovals,theformalannouncementofFIDwasmadeinearlySeptember.

Quest Status as of end Q4 2017



InJuneof2012,ShellconductedthefirstProjectExecutionReview(PER)asrequiredofthe project at that time. A second PERwas completed in June 2013 and a thirdwasconductedinJune2014.PER1examinedthestatusoftheproject,includingtheExecutephasedeliverablescompletedatthattimeaswellasreviewingtheoutputoftheearlyworks construction readiness review and concluded that the projectwas proceedingaccording to plan and ready to start earlyworks construction upon execution of thecontracts and receipt of the regulatory approvals. PER2 examined the status of theproject including the Execute phase deliverables and provided recommendations toQuest for continued success; theproject teamcompleted all recommendations. PER3wasconductedin2014andfocusedonthestatusoftheprojectasitproceededtowardsthe commissioning and startup phase; again, recommendations were made and theprojectteamcompletedallrecommendations.

The project technical activities in 2012 correspond with the Execute phase. Thisincluded the detailed engineering work required to deliver the approved‐for‐construction drawings, technical specification for the procurement of all equipmentandmaterialsandthemanagementofanychangestotheDefinephasedeliverables.

Theproject technical activities in2013also correspondwith theExecutephase.Thisincludedcompleting thedetailedengineeringworkrequired todeliver theapproved‐for‐construction drawings, delivering the approved for construction drawings,technical specification for the procurement of all equipment and materials and themanagementofanychangestotheDefinePhasedeliverables.

The Project technical activities in 2014 also correspond with the Execute Phase,specifically the constructionof thepipeline andwellsites, the fabricationofmodules,theinstallationofmodulesatScotford,andstick‐builtconstructionatScotford.

TheExecutephaseconcludedin2015afterthemechanicalcompletionofthefacilitiesinFebruaryof2015,followedbyasuccessfulcommissioningandstartup,completionofthecommercialsustainableoperatingtests,andsubsequentlyhandedovertoShellforoperationsonOctober1,2015.

TheOperatephaseoftheprojectofficiallycommencedinQ3of2015.QuestOperationssuccessfullycapturedandinjected2.62MtofCO2inthe7‐11and8‐19injectionwellstotheendof2017.

1.4 FacilityLocationsandPlotPlansQuestfacilitylocationsareshowninFigure1‐2:ProjectFacilityLocations.

The capture facility is situatedwithin the Scotford upgrader. The pipeline routing isshownasthedottedlineinFigure1‐2andthefinalwellcountandlocationsarelabeledappropriately.

ThecaptureunitislocatedadjacenttotwooftheScotfordupgraderHMUs.SeeFigure1‐3:CaptureUnitLocationSchematicforaschematicviewofthecaptureunitlocation.


Shell Canada Energy March 2018Page 1-4

Figure1‐2:ProjectFacilityLocations.



Figure1‐3:CaptureUnitLocationSchematic.

Extensiveworkwasdoneduring theDefinephase tovalidate theBCS formationCO2storagepropertiesandtoestablishtheoptimumstoragelocation.Figure1‐4showstheBCSstoragecomplex.

The figure shows the approved Sequestration Lease Area (SLA), formerly called theareaofinterest[AOI],whichhadadifferentboundaryforthestoragearea.Criteriaforthis selection included the BCS rock properties within the location, minimizing thenumberof legacywells intotheBCSstoragecomplex(toreduceriskofpotential leakpaths),andavoidingproximitytodenselypopulatedareas(tominimizethenumberoflandownerconsentsforthepipelineandinjectionwells).Section3containsadditionaldetailsontheselectionandpropertiesoftheBCSformation.



Figure1‐4:BCSStorageComplexwithintheRegionalStratigraphy.



Figure1‐5:ProjectComponentsandSequestrationLeaseArea.



Acriticalrequirementoftheprojectwasthatthestorageareanotbeimpededbyotherfuture CCS projects. To that end, pore space tenure was applied for by Shell to theProvince of Alberta immediately after CCS pore space regulationswere passed. Thistenure granted inMay 2011 for the exclusive use by the Quest operator of the BCSformation for theprojectwithin theSLA isdepicted inFigure1‐5.Thisexclusiveuseallows the Quest operator to store the design volumes of CO2 into the formationwithouttheriskofanotherCCSoperatorstoringCO2inproximitytotheproject,whichwouldraisetherequiredinjectionpressuresandthreatentheprojectobjectives.

1.5 ProcessDesignTheprocessflowschemefortheProjectisshowninFigure1‐6.



Figure1‐6:CaptureandCompressionProcessDesign.



1.5.1 ProcessDescription

CO2AbsorptionSection

Questcapturescarbondioxide from thehydrogen‐manufacturingunits (HMU). In theHMUs, lightgas(e.g.naturalgas)andsteamarereactedinasteammethanereformer(SMR) to form pure hydrogen and carbon dioxide. The impurities are removed inpressureswingadsorbers(PSA)andthepurehydrogenissentontotheresiduehydroconversionunit.ThecaptureprocessremovesthecarbondioxidebetweentheSMRandthePSA.

Amine absorbers located within HMU 1 (Unit 241), HMU 2 (Unit 242) and HMU 3(Unit441)treathydrogenrawgasathighpressureandlowtemperaturetoremoveCO2throughclosecontactwithaleanamine(ADIP‐X)solution.

The hydrogen raw gas enters the 25‐tray absorber below tray 1 of the column at apressureof approximately3,000kPa(g).Leanaminesolutionentersat the topof thecolumnonflowcontrol.

TheCO2absorptionreactionisexothermic,withthebulkoftheheatgeneratedwithintheabsorberremovedthroughthebottomofthecolumnbytherichamine.Richaminefrom the three absorbers is collected into a common header and sent to the amineregenerationsection.

Warm treated gas exits the top of the absorbers and enters the 9‐tray water washvesselsbelowtray1,whereacirculatingwatersystemisusedtocoolthetreatedgas.Warmwater is pumped from the bottom of the vessel and cooled in shell and tubeexchangersusingcoolingwaterasthecoolingmedium.Thecooledcirculatingwaterisreturnedtothewaterwashvesselabovetray6toachievethetreatedgastemperaturespecification. A continuous supply ofwashwater is supplied to the top of thewaterwash vessel in the polishing section. The purpose of the water wash is to removeentrained amine to less than 1ppmw; thereby protecting the downstream PSA unitadsorbentfromcontamination.

Acontinuouspurgeofcirculatingwater,approximatelyequaltothewashwaterflow,issentfromHMU1andHMU2totherefluxdrumintheamineregenerationsectionforuseasmakeupwatertotheaminesystem.ThepurgeofcirculatingwaterfromHMU3issenttotheexistingprocesssteamcondensateseparator,V‐44111.

AmineRegenerationSection

Rich amine from the three absorbers is heated in the lean/rich exchangersby cross‐exchangewith hot, lean amine from the bottomof the amine stripper. The lean/richexchangersareCompablocdesigntoreduceplotrequirements.Thehot,leanamineismaintained at high pressure through the lean/rich exchangers by a backpressurecontroller,whichreduces two‐phase flowin the line.Thepressure is letdownacrossthe2x50%backpressurecontrolvalvesandfedtotheaminestripper.

The two‐phase feed to the amine stripper enters the column through twoSchoepentoeter inlet devices, which facilitate the initial separation of vapour fromliquid. As the lean/rich amine flows down the trays of the stripper, it comes intocontactwithhot,strippingsteam,whichcausesdesorptionoftheCO2fromtheamine.



The amine stripper is equipped with 2 x 50% kettle reboilers that supply the heatrequiredfordesorptionofCO2andproducethestrippingsteamrequiredtoreducetheCO2partialpressure.Thelow‐pressuresteamsuppliedtothereboilersiscontrolledbyfeed‐forward flow from the rich amine stream entering the stripper and is trim‐controlledbyatemperaturesignalfromtheoverheadvapourtemperatureleavingthestripper.

The CO2 stripped from the amine solution leaves the top of the amine strippersaturatedwithwatervapouratapressureof54kPa(g).Thisstreamisthencooledbytheoverheadcondenser.Thetwo‐phasestreamleavingthecondenserenterstherefluxdrum,whereseparationofCO2vapourfromliquidoccurs.

Inadditiontothevapour–liquidstreamfromtheoverheadcondenser,therefluxdrumalsoreceivespurgewaterfromtheHMU1andHMU2waterwashvessels,aswellasknockoutwaterfromtheCO2compressionarea.Therefluxpumpsdrawwaterfromthedrumandproviderefluxtothestripperforcoolingandwashofentrainedaminefromthevapour.Columnrefluxflowisvariedtocontrolthelevelintherefluxdrum,andthepurgeofexcesswatertowastewatertreatmentismanagedviaflowcontrol.

CO2isstrippedfromtherichaminetoproduceleanaminebykettle‐typereboilersandcollectedinthebottomoftheaminestripper.Thehot, leanaminefromthebottomofthestripperispumpedtothelean/richexchanger,whereitiscooledbycross‐exchangewiththeincomingrichaminefeedfromtheHMUabsorbers.Theleanamineisfurthercooled in shell and tube lean amine exchangers.The lean amine is cooled to its finaltemperaturebytheleanaminetrimcoolers,whichareplateandframeexchangers.

A slipstreamof 25%of the cooled lean amine flow is filtered to remove particulatesfromtheamine.Asecondslipstreamof5%ofthefilteredamineisthenfurtherfilteredthroughacarbonbedtoremovedegradationproducts.Afinalparticulatefilterisusedforpolishingoftheamineandremovingcarbonfinesfromthecarbon‐bedfilter.

Thefilteredamineisthenpumpedtothethree‐amineabsorbersinHMU1,HMU2,andHMU3.

Anti‐FoamInjection

Ananti‐foam injectionpackage isprovided to supply apolyglycol‐basedanti‐foam totheamineabsorbersandaminestripper.Anti‐foamcanbeinjectedintotheleanaminelinesgoingtoeachoftheabsorbers,aswellastherichaminelinesupplyingtheaminestripper.

AmineStorage

Thetotalcirculatingvolumeofamineis315m3.Twoaminestoragetanks,alongwithanaminemake‐uppump,supplypre‐formulatedconcentratedamineasmake‐uptothesystem during normal operation. The concentrated amine is blended off‐site andprovidedbyanamine supplier.Theamine storage tanksare alsoused for storageofleanaminesolutionduringmaintenanceoutages.Thesizeof theaminestoragetanksprovidessufficientvolumefortheaminestrippercontentsduringanunplannedoutage.Permanentaminesolutionstorageisnotprovidedforthetotalamineinventory.Duringmajor turnarounds,when the entire systemneeds tobede‐inventoried, a temporarytank will be required for the duration of the turnaround. The amine system can be



rechargedwiththeleanaminesolutionusingtheamineinventorypump.Thispumpisalsobeusedtochargethesystemduringstart‐up.

Theaminestoragetanksareequippedwithasteamcoiltomaintaintemperatureinthetank.Anitrogenblanketingsystemmaintainsan inertatmosphere in the tank,whichpreventsdegradationoftheamine.Thestoragetanksareventedtotheatmosphere.

Compression

TheCO2 fromamine regeneration is routed to the compressor suctionbywayof thecompressorsuctionknockout(KO)drumtoremovefreewater.TheCO2compressorisan eight‐stage, integrally geared centrifugal machine. Increase in H2 impurity from0.67%to5%intheCO2increasestheminimumdischargepressurerequired(tokeepCO2inadense‐phasestate)toabout8,500kPa(gauge).

Cooling and separation facilities are provided on the discharge of the first sixcompressor stages.The condensedwater streams from the interstageKOdrums, areroutedbacktothestripperrefluxdrumtobedegassedandrecycledasmakeupwaterto theaminesystem.Thecondensedwater fromthecompressor fifthandsixthstageKOdrums and theTEG inlet scrubber are routed to the compressor fourth stageKOdrum.This routing reduces thepotential of a high‐pressure vapour breakthroughonthestripperrefluxdrumandreducestheresultingpressuredrops.TheseventhstageKOdrumliquidsareroutedtotheTEGflashdrumduetothelikelypresenceofTEGinthestream.

ThesaturatedwatercontentofCO2at36°Capproachesaminimumatapproximately5,000 kPa(a). Consequently, an interstage pressure in the 5,000 kPa(a) range isspecified for the compressor. This pressure is expected to be obtained at thecompressorsixthstagedischarge.Atthispressure,thewetCO2isaircooledto36°Canddehydratedbytriethyleneglycol(TEG)inapackedbedcontactor.

ThedehydratedCO2iscompressedtoadischargepressureintherangeof9,000kPa(g)to11,000kPa(g), resulting inadense‐phase fluid.Duringcommissioning in2015 thecompressordischargepressurewasinitiallyreducedfrom14MPato11.5MPaduetoissues with reverse rotation on shutdown. Testing during the 2017 turnaroundconfirmedthatitiscurrentlyabletoprovideadischargepressureashighas13.58MPa.Thedense‐phaseCO2iscooledinthecompressordischargecoolertoroughly43°C,androuted to theCO2pipeline.Thisdense‐phaseCO2 is transportedbypipeline from theScotfordUpgradertotheinjectionwells.

Dehydration

A lean triethylene glycol (TEG) stream at a concentration greater than 99%wt TEGcontacts thewet CO2 stream in an absorption column to absorbwater from the CO2stream.Thewater‐richTEGfromthecontactorisheatedandletdowntoaflashdrumthatoperatesatapproximately270kPa(g).ThispressureallowstheflashedportionofdissolvedCO2fromtherichTEGtoberecycledtothecompressorsuctionKOdrum.

TheflashedTEGisfurtherpreheatedandthewaterisstrippedintheTEGstripper.Thecolumn employs a combination of reboiling, and nitrogen stripping gas to purify theTEGstream.NitrogenstrippinggasisrequiredtoachievetheTEGpurityrequiredforthe desired CO2 dehydration because the maximum TEG temperature is limited to



204°C topreventTEGdecomposition.Strippedwater,nitrogenanddegassedCO2areventedtoatmosphereatasafelocationabovetheTEGstripper.

Though the system is designed tominimize TEG carryover, itwas estimated that 27ppmw of TEG will escape with CO2. Operation to date indicates that the number isactually<5ppmw.ThedehydratedCO2isanalyzedformoistureandcompositionattheoutletoftheTEGunit.

Pipeline

The pipeline design is a 12‐inch CO2 pipeline as per CSA Z662 transporting thedehydrated,compressed,anddense‐phaseCO2fromthecapturefacilitytotheinjectionwells.Alsoincludedarepiggingfacilities,linebreakvalves,andmonitoringandcontrolfacilities.Thelineisburiedtoadepthof1.5mwiththeexceptionofthelinebreakvalvelocations,whicharelocatedamaximumof15kmapart.

Adetailedrouteselectionprocesswasundertakenwiththeobjectiveto:

Limitthepotentialforlinestrikesandinfrastructurecrossings

AlignwiththeCO2storagearea

Useexistingpipelinerights‐of‐wayandotherlineardisturbances,wherepossible,tolimitphysicaldisturbance

Limitthelengthofthepipelinetoreducethetotalareaofdisturbance

Avoidprotectedareasandusingappropriatetimingwindows

Avoidwetlandsandlimitthenumberofwatercoursecrossings

Accommodate landowner and government concerns to the extent possible andpractical

TheoutcomeofthisprocessistheroutingshowninFigure1‐2.

The pipeline route extends east from Shell Scotford along existing pipeline rights ofwaythroughAlberta’sIndustrialHeartlandandthennorthofBruderheimtotheNorthSaskatchewanRiver. The route crosses theNorth SaskatchewanRiver and continuesnorth along an existing pipeline corridor for approximately 10 km, where the routeanglestothenorthwesttotheendpointwell,approximately8kmnorthoftheCountyofThorhild,Alberta.Thetotalpipelinelengthis64km.

ThispipelinecrossestheCountiesofStrathcona,Sturgeon,LamontandThorhild.

Thereare336crossingsbythepipeline:

55roadcrossings

4railroadcrossings

19watercoursecrossings

194pipelinecrossings

32cablecrossings

32overheadcrossing



CO2Storage

Thestoragefacilitiesdesignandconstructionactivitiesconsistof:

The drilling and completion of three injection wells equipped with fibre opticmonitoringsystems

Askid‐mountedmoduleoneachinjectionwellsitetoprovidecontrol,measurementandcommunicationforbothinjectionandMMVequipment

Thedrillingandcompletionofthreedeepobservationwells

TheconversionofRedwaterWell3‐4toaCookingLakepressuremonitoringwell

Thedrillingofninegroundwaterwells.

1.6 ModularizationApproachAkeyfeatureoftheFEEDworkfortheprojectwasthedecisiontouseamodularizationapproachfortheCO2captureinfrastructureforthebenefittoschedulingandcost.

The modularization approach for the project is to use Fluor Third GenerationModularSMdesignpractices.Theprojectisdesignedwithamaximummodulesizeof7.3m(wide)x7.6m(high)x36m(long)modulesthatareassembledintheAlbertaareaandtransportedbyroadtotheShellScotfordsitebytheAlbertaHeavyHaulcorridor.

ThirdGenerationModularSMexecutionisamodulardesignandconstructionexecutionmethodthatisdifferentfromthetraditionaltruckablemodularconstructionexecutionmethodsbecauselimitationsexisttothenumberofcomponentsthataretobeinstalledonto the truckablemodules. Themodules are transported and interconnected into acomplete processing facility at a remote location including all mechanical, piping,electricalandcontrolsystemequipment.

Themodule’sboundarieswerereflectedinthethree‐dimensionalmodelandmaturedthrough 30%, 60% and 90% model reviews of multi‐disciplinary teams as well assafety, operability and maintainability reviews. The weight and dimensions of eachmodel were accurately tracked through the process to ensure compliance with themaximumweightandsizerestrictionsfortheheavyloadcorridor.Thestructuralsteelmanufacturingand fabrication for themoduleswasbid,awardedandmanufactureofthesteelcommencedin2012.InAugustof2012,arequestforproposalwentouttofivepre‐qualified module yard contractors on the heavy load corridor. Proposals werereceived inOctoberandevaluatedthereafter.AwardrecommendationsweremadetoShell’scontractboardinmid‐January2013followedbyapprovalbytheJointVentureExecutive Committee late in January 2013. The contract was signed in February.Fabrications of the structural steel for themodules started in early February and inmid‐February,kickoffmeetingswereheldinthemoduleyardtostartthepreparationworktostartmodulepipefabricationandmoduleconstruction.ThemoduleassemblywascompletedandallmodulesweretransportedtositebymidJuly2014.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 2: Facility Construction Schedule


2 FacilityConstructionSchedule

Construction reachedmechanical completion on February 10, 2015with all A andBdeficienciescompletedthatwererequiredforcommissioningandstartup.OnFebruary20,alloftheCdeficiencies,whichwererequiredafterstartup,werecompleted.Fluor,the EPC contractor, demobilized by the end of February. In mid‐April, the project,CommissioningandStartUp(CSU)teamandUpgradermanagementsignedoffonthefirstphaseofProject toAssethandover,whichsignaledthenewfacilitieswerereadyfor startup. The 2015 Upgrader turnaround started in April, which facilitatedcompletion of the Quest scope by mid‐May. Scope items included the HMU 1 andcommon process ties, HMU 1 burner change out and FGR tie‐ins, and HMU 1 PSAcatalystchangeout.Uponcompletionoftheturnaround,theCSUteambeganexecutingtheir start‐upplan.The construction engineering teamcontinued to support theCSUteam throughout the startupand commercial operations tests. SeeFigure2‐1 for theactual construction schedule.Handover toScotfordOperations completed theprojectconstructionphase.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 2: Facility Construction Schedule


Figure2‐1:ProjectConstructionSchedule.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017

Section 3: Geological Formation Selection


3 GeologicalFormationSelection

3.1 StorageAreaSelectionAscreeningprocessresultedinapreferredstorageareathatwasinitiallyselectedforfurther appraisal and studies in 2010 and2011 by submitting an exploration tenurerequestwiththeregulatoronDecember16,2009.Thesubsequentprocessofstoragearea characterization comprised a period of intensive data acquisition, resulting instorageareaendorsementpriortosubmittingtheregulatoryapplicationsonNovember30, 2010 and culminating in the award of a Carbon Sequestration Leases by AlbertaEnergyonMay27,2011.

Storageareaselectionwasmainlybasedondata,analysesandmodelingofthetwoCO2appraisalwellswith supplementaldata from legacywells, seismic and study reports.OnesetofandthosecriteriainTable3‐1showsthepropertiesoftheBasalCambrianSands (BCS) are compared with storage area selection criteria for CCS projects wasdevelopedbytheAlbertaResearchCouncil(ARC).

The approved sequestration lease area (SLA), as defined by the approved CarbonSequestrationLeasesandpursuanttoSection116oftheMinesandMineralsAct,wasgranted to Shell, in May 2011, on behalf of the ASOP Joint Venture, by the AlbertaDepartmentofEnergy.




Table3‐1:AssessmentoftheBCSforSafetyandSecurityofCO2Storage

CriterionLevel No Criterion Unfavourable

PreferredorFavourable BCSStorageComplex

Critical 1 Reservoir‐sealpairs;extensiveandcompetentbarriertoverticalflow

Poor,discontinuous,faultedand/orbreached

Intermediateandexcellent;manypairs(multi‐layeredsystem)

Threemajorseals(MiddleCambrianShale[MCS],LowerLotsbergandUpperLotsbergSalts)continuousovertheentireSLA.Saltaquicludesthickenupdiptothenortheast.

2 Pressureregime

Overpressuredpressuregradients>14kPa/m

Pressuregradientslessthan12kPa/m

Normallypressured<12kPa/m

3 Monitoringpotential

Absent Present Present

4 Affectingprotectedgroundwaterquality

Yes No No

Essential 5 Seismicity High ≤Moderate Low6 Faultingand

fracturingintensity

Extensive Limitedtomoderate

Limited.Nofaultspenetratingmajorsealobservedon2Dor3Dseismic.

7 Hydrogeology Shortflowsystems,orcompactionflow,Salineaquifersincommunicationwithprotectedgroundwateraquifers

Intermediateandregional‐scaleflow

Intermediateandregional‐scaleflow‐salineaquifernotincommunicationwithgroundwater

Desirable 8 Depth <750‐800m >800m >2,000m9 Located

withinfoldbelts

Yes No No

10 Adversediagenesis

Significant Low Low

11 Geothermalregime

Gradients≥35°C/kmandlowsurfacetemperature

Gradients<35°C/kmandlowsurfacetemperature

Gradients<35°C/kmandlowsurfacetemperature

12 Temperature <35°C ≥35°C 60°C13 Pressure <7.5MPa ≥7.5MPa 20.45MPa14 Thickness <20m ≥20m >35m15 Porosity <10% ≥10% 16%




CriterionLevel No Criterion Unfavourable

PreferredorFavourable BCSStorageComplex

Desirable(cont’d)

16 Permeability <20mD ≥20mD AverageovertheSLA20‐1000mD

17 Caprockthickness

<10m ≥10m Threecaprocks:MCS21mto75mL.LotsbergSalt9mto41mU.LotsbergSalt53mto94m

SOURCE:CCSSiteSelectionandCharacterizationCriteria–ReviewandSynthesis:AlbertaResearchCouncil,DraftsubmissiontoIEAGHGR&DProgramJune2009:http://sacccs.org.za/wp‐content/uploads/2010/11/2009‐10.pdf

3.2 GeologicalFrameworkTheBCSisatthebaseofthecentralportionoftheWesternCanadaSedimentaryBasin(WCSB), directly on top of the Precambrian basement. The BCS storage complex isdefinedhereinastheseriesofintervalsandassociatedformationsfromthetopofthePrecambrianbasementtothetopoftheUpperLotsbergSalt(Figure1‐4).

TheBCSstoragecomplexincludes,inascendingstratigraphicorder:

PrecambriangranitebasementunconformableunderlyingtheBasalCambrianSands

Basal Cambrian Sands (BCS) of the Basal Sandstone Formation – the CO2 injectionstoragearea

Lower Marine Sand (LMS) of the Earlie Formation – a transitional heterogeneousclasticintervalbetweentheBCSandoverlyingMiddleCambrianShale

MiddleCambrianShale(MCS)oftheDeadwoodFormation–thickshalerepresentingthefirstmajorregionalsealabovetheBCS

UpperMarine Siltstone (UMS) likelyUpperDeadwood Formation – progradationalpackageofsiliciclasticmaterialmadeupofpredominantlygreenshalewithminorsiltsandsands

DevonianRedBeds–fine‐grainedsiliciclasticspredominantlycomposedofshale

Lotsberg Salts – Lower and Upper Lotsberg Salts represent the second and third(ultimate)seals,respectively,andaquicludetotheBCSstoragecomplex.Thesesaltpackages are predominantly composed of 100% halite withminor shale laminae.Theyareseparatedfromeachotherby50mofadditionalDevonianRedBeds.

The rocks comprising the BCS storage complex were deposited during the MiddleCambrian to Early Devonian directly atop the Precambrian basement. The erosionalunconformity between the Cambrian sequence and the Precambrian representsapproximately 1.5 billion years of Earth history. Erosion of the Precambrian surfaceduringthisintervallikelyresultedinarelativelysmoothbutoccasionallyrugosegentlysouthwestdipping(<1degree)topPrecambriansurface.WithintheSLA,theCambrian




clasticpackagespinchouttowardsthenortheast,whiletheDevoniansaltsealsthickentowards the northeast. For a cross‐section of the WCSB showing the regionallyconnectedBCSstoragecomplexinrelationtoregionalbafflesandsealingoverburden,seeFigure3‐1(theAOIistheformernamefortheSLA).TheSLAiswithinatectonicallyquietarea;nofaultscrosscuttingtheregionalsealswereidentifiedin2Dor3Dseismicdata.

Figure3‐1:Cross‐SectionoftheWCSBShowingtheBCSStorageComplex.

SW NE

Radway 8-19




3.3 BCSReservoirPropertiesNo new injection wells were drilled in this reporting period. Figure 3‐2 provides asummary of the formation thicknesseswithin the BCS storage complex and selectedoverlyingformationsuptothetopoftheQuestSequestrationLeaserightsforIW8‐19,IW5‐35andIW7‐11.

Figure3‐2:SummaryofzonethicknessesforQuestSequestrationrightsinterval.

WithregardstotheBCSreservoirproperties,goodagreementwasobservedbetweencoreanalysesandlogdataofBCSreservoirpropertiesasseeninFigure3‐3.




Figure3‐3: BCSReservoirProperties.Comparisonof logresponseover theBCS formationandthecorrespondingcoreanalysisresultsinallthreeinjectionwells.ThePorosity track (green arrows) shows very good correspondence between thecoreporosityandlogporosity.Thepermeabilitytrack(redarrows)showagoodagreementbetweenthelogandcorepermeabilityinIW5‐35,andagreementisbetterinIW7‐11.

Based on the IW 5‐35 and IW 7‐11 BCS cores, the depositional environment wasinterpretedtobeconsistentwithIW8‐19,asillustratedinTable3‐2

Table3‐2:DepositionalEnvironmentinLMS‐BCSfortheinjectionwellsfromthecoredata

DepositionalPaleo‐Environment

IW8‐19,thickness(m)



DistalBay 11* 5* 8*

ProximalBay 10 12 11TideDominatedBayMargin

(TDBM)25 30 17

TDBM(FluvialInfluenced) 4.5 2.4 13*Basedoncoredataonly–logdataindicatesthatthatDistalBayissignificantlythicker.

Consistencywasalsoobserved in thegeochemical compositionof theBCSFormationbrinefromIW5‐35andIW7‐11comparedtoIW8‐19,asillustratedinFigure3‐4.




Figure3‐4:IonRationplotofBCSFormationbrinewatersfromIW8‐19(sampledin2010),IW5‐35(sampledin2012)andIW7‐11(sampledin2013).

3.4 EstimateofStoragePotentialThereiscurrentlynoperceivedriskthatthecurrentprojectwillnotmeetstheinjectiontargets,asitbelievedthereissufficientstoragecapacityforthefullprojectvolumeof27MtofCO2.RefertotheAERAnnualReport(2017)Section3.5:ReservoirCapacityfordiscussion. The residual uncertainty in pore volume is unlikely to decrease muchfurtheruntilseveralyearsofinjectionperformancedataisattained,whichmaythenbeusedtocalibratetheexistingreservoirmodels.

Table3‐3:RemainingcapacityintheSequestrationLeaseAreaasofend2017

Year YearlyInjectionTotal RemainingCapacity

Pre‐injection ‐ 27MtCO2

2015 0.371Mt 26.629MtCO2

2016 1.108Mt 25.521MtCO2

2017 1.138Mt 24.383MtCO2

3.5 InjectivityAssessmentTheprojectwas designed for amaximum injection rate of about 145 t/hr into threewells. Since start‐up in 2015, injection rates have been up to 155 t/hr into two




injectionwells(the8‐19and7‐11wells).The8‐19wellhasbeeninjectingconsistentlyatabout70t/hrwhenpossiblewithverylittlepressurebuildup.Itisunlikelythatthethirdwell,5‐35,willbeneededtomeetinjectivityrequirements.

As well, injection stream compositions and variations (Table 5‐3) are within designscopeandhavenotimpactedcaptureorstorageoperations.

Therearenoconcernsonreactivityoftheimpuritiesorimpactonthephasebehavior.

It is therefore expected that the project will be capable of sustaining adequateinjectivityforthedurationoftheprojectlife;therefore,nofurtherwelldevelopmentiscurrentlynecessarytomaintaininjectivityrequirements.

3.6 RisktoContainmentinaGeologicalFormationPriortocommercialoperation,ninepotentialthreatstocontainmentwereidentified:

1) Migration along a legacy well, 2) Migration along an injection well, 3) Migrationalongadeepmonitoringwell,4)Migrationalongarockmatrixpathway,5)Migrationalongafault,6)Inducedstressre‐activatesafault,7)Inducedstressopensfractures,8)Acidicfluidserodegeologicalseals,and9)thirdPartyactivities.

Each was considered highly unlikely; but any of them are, in principle, capable ofallowingCO2tomigrateupwardsoutoftheBCSstoragecomplex.

Evaluation and integration of all available data‐to‐date (e.g. 2012‐2013 drillingcampaign,pre‐injectionphasemonitoring,injectionphasemonitoring,Gen‐5modellingoftheBCS)hasconfirmedthatthepressureincreaseintheBCSwillnotreacha levelsufficienttoliftBCSbrinetothebaseofthegroundwaterprotection(BGWP)zoneevenat the injection wells. Therefore, there is no risk of brine leakage impactinggroundwater unless there is a severe loss of conformance. BCS pressuremonitoringwill be used to ascertain if there is a loss of conformance that could give rise to apotentialthreatrelatedtobrineleakagefarinadvanceofanyimpactabovethestoragecomplex.At that time,MMVplanswouldbeupdatedappropriately.Even if therewassufficient pressure, dynamic leak path modelling indicates that due to the pressuredepletionoftheCookingLakeFormation,aswellasflowintootherdeepaquifers,BCSbrine cannot reach theBGWPzoneunless it flows along anopenmigrationpathwayunconnected to the Cooking Lake Aquifer. In addition, considering the sitecharacteristicsof thestoragecomplexcappedbytheUpperandLowerLotsbergSaltsFormations,wellsthatdonotpenetratethestoragecomplexposeverylittletonorisktocontainment.

Hence,ofallpotentialthreatsinvestigated,thekeythreattocontainmentattheQuestsite is “Migration along an injectionwell”, as three suchwells penetrate the storagecomplex. The risk of leakage, however, from the storage complex along a leakagepathwayintheinjectionwellsisconsideredverylow.

For further details on risk to containment, please refer to Section 3.1.3 of the 2017MMVplan[3].


Section 4: Facility Operations – Capture Facilities


4 FacilityOperations–CaptureFacilities

4.1 OperatingSummaryTheQuestCCSprojectfocusfor2017wastocontinuereliableandefficientcaptureandstorage of CO2 from operations. Table 4‐1 outlines the performance summary of thecaptureunitin2015,2016and2017.Adiscussionofthesummaryresultscanbefoundinthesubsequentunitdiscussions.

Table4‐1:QuestOperatingSummary2017

QuestOperatingSummary 2015Summary 2016Summary 2017Summary Units

TotalCO2Injected 0.371 1.11 1.138 MtCO2

CO2CaptureRatio 77.4 83.0 82.6 %

CO2EmissionsfromCapture,TransportandStorage

0.057 0.161 0.174 MtCO2

NetAmount(CO2Avoided) 0.314 0.947 0.964 MtCO2

Thefollowingisatimelineofsignificantoperationalmilestonesforthe2017calendaryear:

May16,2017:SuccessfulcompletionoffirstQuestturnaround. June11,2017:Reachedmilestoneof2milliontonnesinjectedsinceprojectstartup. November14,2017:Reachedmilestoneof1milliontonnesinjectedin2017.

4.1.1 QuestAuditsandCreditSerialization

TheQuestprojectunderwentvariousAuditandOffsetverificationsin2017,includingtheAlbertaEnergyInjectionCertificationaudit,AlbertaClimateChangeOffice(ACCO)OffsetAuditandACCOOffsetVerificationsin2017.

For2017, theQuestCarbonCapture andStorageProject (Quest) serialized a total of1,212,182 credits – 415,578 from 2015 and 796,604 from 2016 on the AlbertaEmissionOffsetRegistry:


Section 4: Facility Operations – CaptureFacilities


Quest Credits from 1st Crediting Period (2015)(August2,105toOctober31,2015) 166,450

Quest Credits from 2nd Crediting Period (2015/2016)(Nov1,2015toMar31,2016)

649,836

Quest Credits from 3rd Crediting Period (2016)(Apr1,2016toSept30,2016) 395,896

Subsequent to the completion of the verification of the 1st crediting period, AlbertaClimate Change Office (ACCO) assigned a third party auditor which resulted in twomaterial audit findings regarding Quest injection gas online analyzer and the wasteheatmethodology.Theresolutionof theonlineCO2analyzerhasbeenresolvedwhilethewasteheatmethodologyisstillinprogress.

Going forward, Shellwill beworkingwith ACCO on the transition from the SpecifiedEmittersGasRegulationtothenewCarbonCompetitivenessIncentiveRegulation.

4.2 Capture (Absorbers and Regeneration)

Solventcompositionwasontargetfor2017operationvs.thespecifiedformulationforADIP‐X from the design phase, and CO2 removal ratio performance has been aspredicted. The annual CO2 capture ratio was 77.4% for 2015, 83.0% for 2016 and82.6%in2017.ThemaincontributorstoperiodsofreducedCO2capturein2017wereasfollows:

Periods of lowered hydrogen production demand and trips in process units

outsideofQuest. Planned maintenance activities or trips in the Quest capture unit also

contributedtoperiodsofreducedcapture.Theseperiodsarelistedbelow:o May 7‐14: Quest spring turnaround to complete a compressor

inspection and exchanger cleaning. The capture unit was shut downduringthisperiod.

o May16: Questcompressortriptestingafter implementingMOCtore‐ratetheC‐24701compressorfrom12MPato13.58MPa.

o August25:FollowupQuestC‐24701compressorpinioninspectionandlubeoilnozzlereplacement.

o Nov 13‐14: Quest high moisture pipeline trip while placing the TEGcarbonfiltersysteminserviceaftercarbonfilterreplacement.




o November13:LossofaminecirculationduetoleanAminechargepumptriponlowsuctionpressure.

o December9:LossofaminecirculationduetoleanAminechargepumptriponlowsuctionpressure.

TheCO2stripperoperationhasbeenstable,and theCO2product sent to thecompressionunithasbeenontargetforpurity.Therearenoconcernsonreactivityoftheimpuritiesorimpact on the phase behavior. Performance has been as expected in terms of solventregeneration. Table 5‐3 in the transport section contains the average CO2 productcompositionfromthecaptureanddehydrationunits.Table4‐2providesasummaryoftheutility and energy sources consumed during the injecting period since start up, for the0.371,1.11,and1.14MtCO2capturedandinjectedin2015,2016and2017.

Table4‐2:EnergyandUtilitiesConsumption(Capture,Dehydration)

Energy and Utilities 2015 Usage 2016 Usage 2017 Usage Units

Electricity (Capture/Dehydration) 12300 32800 32600 MWhe

Low Pressure Steam 410 1263 1297 kT

Low Temperature High Pressure Steam 1.96 5.52 5.23 kT

Nitrogen 178 230 237 ksm3

Wastewater 24900 80900 61900 m3

Energy/Heat Recovered 33600 96260 98554 MWhth1

CO2 Emissions for the Capture Process 0.030 0.083 0.095 Mt CO2

Electricity,andsteamuseareapproximatelyontargetwithdesignspecificationswhenpro‐rated for actual CO2 throughput. Waste water was reduced in 2017 to further mitigateimpacts on the downstream carbon steel piping and the waste water treatment system.Nitrogen use is significantly lower than expected due to optimizations made in thedehydration unit. Nitrogen stripping gas flow to the TEG stripper was reduced to avoidover‐processing the TEG. In 2017 the operations team targeted approximately 50 ppmvwatercontenttothepipeline,stayingwithinthe84ppmvspec.Heatrecoveryinthedeminwaterheaters (cooling theCO2 stripper reboiler steamcondensate) is alsoapproximatelyontargetfromdesign.

Duringthelaterpartof2016,itwasobservedthatfoulingofthelean/richexchangerswasimpactingtherichamineinlettemperaturetothestripper.Atemperaturedropofabout2°Cwasobservedoverthecourseoftheyear.Asaresult,reboilerdutyincreased.Cleaningofthis exchangerwas completed in the 2017 spring turnaround. The exchangerwas backflushedbya3rdpartyvendorinanattempttoremoveanyfoulant,carbonorotherdebris.Theexchangercleaninghasresultedinaminordutyimprovementandstabilizationofthefoulingtrendresultinginthecolumninlettemperaturebeingmaintainedthrough2017.

1 e subscript denotes electrical energy, th subscript denotes thermal energy




Asuccessstory for theQuestunitoperation to‐datecontinues tobe the low levelsofchemicallossfromtheADIP‐xprocess.Aminelossesfromthecaptureunitreducedtonegligible after the initial commissioning/inventory and startup phases. In 2017 theaverageaminelosseswerelessthan1tonne/monthwithtotalamineconsumptionof8.2tonnes.

CO2emissionsforthecaptureprocessareprimarilythoselinkedtolowpressuresteamuse in the CO2 stripper reboilers (~67% of total capture emissions), and fromelectricityforequipmentinthecapturesystem(~24%ofcaptureemissions).

ThemostsignificantoperationalissueobservedsincestartuphasbeenfoamingoftheADIP‐X solution in the HMU absorbers, leading to tray flooding and short durationreduction in CO2 capture from the HMUs, with a small impact to stability in thehydrogenplantsthemselves.Thecausehasbeenattributedtoseveralinitiatingfactors:rapid changes in gas flows to the absorbers, carbon fines entrainment in the system,high gas rates to the absorbers and general system impurities. DCS control schemesimplemented in 2015 have been successful in mitigating some of these causes.However,thefrequencyoffilterchange‐outsintheleanaminecircuitduetocarryoverofcarbonfinesfromthecarbonfilterintotheleanaminecircuitcontinuedinthefirsthalfof2016.

InJuneof2016,theleanaminecarbonfilterwastakenofflineasatestruntoobservetheimpactonabsorberfoamingandmechanicalfilterchangeouts.Asamitigation,useoftheanti‐foamwassuspended,andaminequalitywasmonitored.Whenthefilterwastaken offline, therewere no foaming events, and the frequency of filter changeswasreduced.

The carbon filter remained offline until November 2017 when it was taken out ofservice to complete an inspection of the vessel internals, reload the filterwith freshcarbon and then place the filter back in service. The inspection of the carbon filterinternals was completed without any damage being discovered. The filter wasreloaded with new carbon and a 3rd party contractor was hired to complete ademineralizedwaterback flushtoremovecarbon fines fromthesystem. Thecarbonfilterwasbackflushedforapproximately7daysuntiltheamountofcarbonfinesbeingremovedbythevendor’sequipmentwasnegligible. The carbon filterwasplacedintoservicemid‐Novemberwiththenewcarbonload.

Pre‐filter change out lengths have not increased from the standard change outfrequencypriortothereloadhoweversomeminorfoamingeventshavebeennoticed.FoamingistypicalpostcarbonreloadintheotheramineunitsontheScotfordsiteandthis will bemonitored to determine if additional investigation is required. Anotheroperational issue noticed after placing the filter back in service is that there is apotential for vapour/Nitrogen used to displace the amine from the pre/ post filtersduring a filter change to be directed into the process. This has caused the P‐24602




aminechargepumps to tripon lowsuctionpressure. Procedural changeshavebeenmadetomitigatethisissueuntilpermanentvents,drainsandDCScontrolchangescanbeimplemented.

4.3 Compression The compressor operated at low discharge pressures during most of 2017, as theoperating strategy was to minimize pipeline pressure within system constraints toreducecompressionelectricitydemand.Table4‐3belowoutlinestheaverageoperatingconditionsforthereportingperiod.

Table4‐3:TypicalCompressorOperatingData

Compressor Characteristic

Average 2015

Operation

Average 2016

Operation

Average 2017

Operation Units

Suction Pressure 0.03 0.03 0.03 MPag

Discharge Pressure 9.6 10.0 10.1 MPag

Motor Electricity Demand 13.3 13.8 14.2 MWe

Inanon‐goingattempttoensurethehighestaccuracypossiblefromtheCO2analyzer,AT‐24702, barometric pressure compensation of the analyzer measurement wascompletedinFebruary2017usingapressuretransmitterintheCogenerationunit.Thechange was recommended by the analyzer vendor and was successful in ensuringanalyzer accuracy. A dedicatedbarometric pressure transmitterwas installed in theQuest analyzer building in April 2017. Data substitution due to analyzer inaccuracywassuspendedasofFebruary3rd,2017withonlyrawdatameasuredbytheanalyzerbeingsubmitted.A significant amount of workwas completed on the C‐24701 Quest CO2 compressorduring the spring turnaround. Orifice plates in the compressor blow off lines wereremoved allowing for additional gas to escape at a faster speed. The orifice plateremovalallowedfortheQuestcompressortobere‐ratedbackto13.58MPa,increasingoperational flexibility by allowing higher discharge pressures. The bull gear andpinionswerealsoinspectedintheMayoutage.Allwereinexcellentconditionbesidespinion#2which showed slight signsofwearon thenon‐loaded sideof the teeth. Asubsequent inspection completed on August 25th found that a single lube oil nozzlewasnotfunctioningproperly.Thelubeoilnozzlewassprayinganoilstreaminsteadofa mist leading to the pinion damage. The nozzle was replaced during the Augustinspectionwhichhasalleviatedthisdamagemechanism.Theinletguidevaneandfirststageimpellerwerealsoinspectedanddidnotshowanysignsoferosionwhichwasaconcern because of the large amount of liquids present in the compressor knockoutdrums. The onlymajor finding from the inspectionwas that the temporary start upscreen in the first stageof the compressorhad failedand required removal. Startupscreens remain in the other seven stages of the compressor and are planned forremovalatthefirstpossibleopportunity.




4.4 Dehydration

The dehydration unit performance continued to exceed expectations in 2017. Thesystemrequirementwastomeetthewinterwatercontentspecificationforthepipelineof 84 ppmv. Actual water content for 2017 was on average 46 ppmv, and this wasachievedat a lowerTEGpurity thandesign (99.6%vs.99.7%)whilemaintaining theoptimizedNitrgenflowratesdescribedinsection4.2.

CarryoverofTEGintotheCO2streamalsoappearstobesignificantlylessthandesign,with the estimated losses in 2017 being <6ppmw of the total CO2 injection stream,compared to the 27 ppmw expected in design. Dehydration unit losses of TEGwereroughly5,800kgannuallyfor2017vs.thedesignmakeuprateof46,000kgannually.

TheTEGpre‐filter,carbonfilterandpostfilterswerereplacedinconjunctionwiththeamine carbon filter in November 2017. The vessel was taken offline, unloaded,inspected,reloadedandthenplacedback inserviceafterademineralizedwaterbackflushtoensuretheremovalofcarbonfinesfromthesystem.Placingthefiltersectiononlinecausedahighmoisture tripof thesystem. This trip isdiscussed in the“QuestCO2DehydrationPerformance”document.

4.5 Upgrader Hydrogen Manufacturing Units

TheimplementationofFGR(fluegasrecirculation)technology,incombinationwiththeinstallation of low‐NOx burners has allowed all three HMUs tomeet their NOx levelcommitments without contravention in 2017 while operating with Quest online.OperationoftheFGRhasbeenbydirectflowcontroltoachievethedesiredNOxlevel.Installedcapacityof theFGRallowsoperationwithinawiderangeofNOxgenerationlevels,sothesystemhasbeenoperatedtomaximizefurnaceefficiency(lowFGRflow),whileensuringthatenoughFGRflowisroutedto theburners tomaintainNOx levelsclose to baseline pre‐Quest. For 2017, normalNOx emissionswithQuest operationalandFGRonlinehavebeenintherangeof:

HMU1:7‐50kg/h,limit76.5kg/h

HMU2:7‐40kg/h,limit76.5kg/h

HMU3:20‐110kg/h,limit130kg/h

WhentheFGRfantrips,NOx levelsarebelowthenewlimits listedabove,butexceedtheoldlimits,pre‐Quest,iftheCO2captureratioisnotreduced.

One of the most significant differences in operation of the HMUs after CO2 capture is areductioninreformerfuelgaspressure.FuelgaspressurereducesasincreasingamountsofCO2 are removed from the rawhydrogen stream, in turn reducing the volume of tail gasgeneratedinthePSAforuseasreformerfuel.Lowfuelgaspressurewasalimitingfactorfor




increased CO2 capture ratio when the HMUswent into production turndown because ofreductionsinhydrogendemandattheUpgrader.

TheflamestabilityinsidethereformingfurnaceappearedtobeinfluencedbyincreasedCO2capture rates (i.e. a change in fuel gas composition), resulting in a looser flame patternwhencomparedtonon‐Questoperationinearly2015.Ascaptureratiosareincreased,theimpacttoflamestabilityincreases.

Sincecommissioningin2015,hydrogenproductionlossesduetohydrogenentrainmentintheamineabsorbershavebeenlow,atroughly0.1%lossoftotalhydrogenproduction.Thisis indicated by the roughly 0.5 vol% hydrogen content in the CO2 stream sent to thepipeline.

TheUpgraderHMUshavebeenrelativelyunaffectedfromareliabilityperspectivewiththeadditionofCO2capturefacilities.Fromanefficiencyperspective,thehydrogenproductioncapabilityoftheunitsremainslargelyunchangedin2017withQuestoperating.Thelossofhydrogenvia entrainment in theCO2 absorbers and into theQuestpipelinemeetsdesignexpectationsandthereisanegligibledropinoverallhydrogenproductioncapacities.Fluegasrecirculationadditionto thereformercombustionairstreamisrunningbelowdesignexpectations. While the addition of the flue gas recirculation results in fuel efficiencyimprovementsinthereformer,NOxemissionsareslightlyelevatedfrombaseline.

4.6 Non-CO2 Emissions to Air, Soil or Water

InaccordancewithShell’sinternalguidelines,allspills–regardlessofsize–arerecordedfortrackingpurposes.Questdidnotexperienceanyleaksin2017withthethreetripsassociatedtoQuestresultinginonlyCO2emissions.

InAugust2016,a leakwasidentifiedinasectionofwastewaterpipinggoingfromtheQuestplottotheScotfordUpgraderWastewaterTreatmentPlant.LeaklocationwasintheUpgraderCogenerationUnit,outsidetheQuestplot.Wheninvestigated,theleakwasfoundtobeduetohighcorrosionratescausedbythelowpHofQueststripperrefluxwater.Pipinghassincebeenupgraded to 304 stainless steel. In 2017 to further mitigate impacts on the downstreamcarbonsteelpipingandthewastewatertreatmentsystematemporarycaustic injectionskidwas installed in Quest to increase the PH of the Quest stripper reflux water. A project isprogressingwhichwill evaluate all possible alternatives and determine the best solution topermanentlymitigatethelowPHwaterleavingtheunit.

4.7 Operations Manpower




TheQuestCCS facilitiesarecurrentlyoperated24hoursaday,7daysaweekby theScotford Upgrader operations team. The dayshift includes a control room operator,field operator for theQuest plot (capture, compression, dehydration), and a pipelineandwellsoperator. Inmid‐2016,majorstart‐upandcommissioning issueshadbeenresolved ormitigated (e.g. absorber foaming, compressor reverse rotation), and unitreliability was consistent. At this point, the decision was made to merge the Questcontrol room operator position with the existing operator position for the ScotfordUpgraderHydrogenManufacturingUnits.Nightshiftcoverageisprovidedbyacontrolroom operator and a field operator, with a pipeline and wells operator on‐call foremergencies.MaintenancesupporthasbeenintegratedintoexistingScotfordUpgradermaintenance department resources, and staff support (engineering, specialists,administration,andmanagement)hasbeenrolledintotheexistingteamsupportingthehydrogenmanufacturingunits.


Section 5: Facility Operations –Transportation


5 FacilityOperations–Transportation

5.1 PipelineDesignandOperatingConditionsPipelineoperationwasstableduringthereportingperiod.Table5‐1belowcomparesoperatingconditionstodesignvaluesfromtheengineeringphasesoftheproject.

Table5‐1:PipelineDesignandOperatingConditions

Characteristic Specification UnitsAverageOperatingData/

ActualLimitations OriginalDesign2015 2016 2017

General

PipelineInletPressure

Normal MPag 9.4 9.8 9.9 10

MaximumOperating MPag 12 12 13.58 14

MinimumOperating(basedonCO2criticalpressure7.38MPa)

MPag 8.5 8.8 8.7 8

Designmaximum MPag ‐ ‐ ‐ 14.8(at60°C)

PressureLossfromInlettoWellsite

Normal MPa 0.6 0.6 0.6 0.4(for3well

scenario)

Temperature CompressorDischarge °C 130 130 128 130

PipelineInletaftercooler °C 43 43 41 43

UpsetConditionatInlet °C ‐ ‐ ‐ 60

InjectionWell7‐11InletTemperature

°C 15 16 14

InjectionWell8‐19InletTemperature

°C 12 12 11

Flowrates NormalTransportRate Mt/a 1.04 1.11 1.14 1.2

Designminimum Mt/a ‐ ‐ ‐ 0.36

TotalTransported Mt 0.371 1.11 1.14 ‐

EnergyandEmissions

TotalElectricityforTransport(compression)

MWhe 41,527 119,426 121,593 ‐

TotalTransportEmissions(includescompression)

MtCO2eq

0.027 0.077 .078 ‐

ThepipelinehasbeenoperatedwithCO2inthesupercriticalphaseatthepipelineinlet(9.7MPag,43°C)andwithCO2 leavingthemainpipeline to thewellsites in the liquidphase(9.1MPag,15°C). .Thesetwophasesarecommonlylumpedtogetheras“dense




phase” in industry. The phase transition from supercritical phase to liquid occursroughlyinthe15‐30kmregiondowntheline,basedonafieldtemperaturesurveyin2015.Heattransferwiththesoil,aswasexpectedinthedesignphase,hascausedthemajorityofthetemperaturereductioninthepipeline.

CO2emissionsfromthetransportcomponentoftheoperationwereprimarilyfromtheelectricityusedtopowerthecompressor(99%oftotaltransportemissions).

In2016,methanol fuel cellswere installedateach linebreakvalve (LBV).These fuelcells provide supplemental charge to theLBVbatterybank so that there is sufficientpowerduringnighttimeandovercast conditions. Since installationof these fuel cells,fieldchargingoftheLBVbatteriesarenolongerneededandtherewerenonearmissoractualloss‐of‐powertripsontheCO2pipelinein2017.In2017,thefuelcellmethanolconsumptionwasoptimized,usingperformancedatacollectedfromwintermonths,bymodifyingfuelcellswitch‐onvoltage,absorptiontime,andmaximumchargetime.Solarcharging during daytime hours was also optimized by connecting the solar chargesenselinestothebatteriesandcompensatingforthevoltagedroplosses.Fouroutofsix methanol fuel cell units experienced issues in the internal reservoir due to anunknown manufacturing defect. The vendor has replaced four of the fuel cell unitsunderwarrantyandnofurtherissueshavebeenexperienced.

Pipelineandlaterals/welldimensionsas‐installedcanbefoundinTable5‐2.




Table5‐2:PipelineDimensionalData

MainFlowLineData

Characteristic Specification Units 2015‐2016Data ValuefromDesignPhaseorAs‐installed

Dimensions Length km ‐ ~64

Size inches,NPS

‐ 12

Wallthickness mm - 12.7(11.4+1.3corrosionallowance)

LateralsDataDimensions Length km ‐ 3laterals:~1,1.6and

3.8

Size inches,NPS

‐ 6

Wallthickness mm ‐ 7.9(6.6+1.3corrosionallowance)

Reservoirpressure MPag Refertosection6 22–33.3

Reservoirtemperature °C Refertosection6 63

Wellboretubingdiameter inches,NPS

‐ 3.5

Welldepth m ‐ 2,070

Fluid composition in the pipeline was very close to the design normal operatingconditionforthemajorityoftheoperatingperiod.Onaverage,entrainedcomponentssuchasH2andCH4arelowerthandesign.TheaverageoperatingconditionstodesignvaluesareavailableinTable5‐3.




Table5‐3:PipelineFluidComposition

Component ActualOperating2015(vol%)

ActualOperating2016(vol%)

ActualOperating2017(vol%)

DesignNormal

Composition

DesignUpsetComposition

CO2 99.45 99.38 99.46 99.23 95.00

H2 0.48 0.51 0.47 0.65 4.27

CH4 0.06 0.06 0.06 0.09 0.57

CO 0.02 0.02 0.01 0.02 0.15

N2 0 0 0 0 0.01

Total 100 100 100 100 100

CapacityfortheFuture

Designcapacityofthepipelinethroughputis1.2Mt/a.TheCO2pipelineisdesignedtoreceiveandtransportuptoanadditional2.2Mt/aofCO2,shouldtherebeacommercialoptiontoreceiveCO2volumes.

WaterContentandCO2PhaseChangeManagement

Pipeline operation since startup was below the winter water specification of 4 lb /MMscf(84ppmv).Theaveragefor2017was46ppmv.Atthislevel,hydrateformationisnotaconcernduringnormaloperation,andzerocorrosionisexpected.Flowtothepipeline is stoppedautomaticallywhen thewater content reaches8 lb/MMscf (168ppmv).

Thepipelinesystemiscurrentlyprotectedfromexcessivevapourgeneration,andrapidtemperaturereduction,whencomingoutofdense/liquidphaseduringoperationbyalowpressureshutdown,currentlysetto7MPag.

DesignLife

Designlifeforthepipelineandassociatedsurfacefacilities is fortheremaininglifeoftheScotfordUpgrader,approximately25years.

PipelineSteelGrade

Items that have been identified as a possible concern for CO2 pipelines include longrunningductilefracture(LRDF)andexplosivedecompressionofelastomers.

Shell Global Solutions, operating in Shell Technology Centre Calgary (STCC), hasperformed material testing in order to determine the appropriate elastomers tominimize explosive decompression and the appropriate grade of steelwith sufficienttoughnesstoresistLRDF.

Results fromtheLRDFtestingshowthatthetoughnessrequirements forthepipelineare quite achievable in commercially available steel grades, as verified by history.Specifically, CSAZ245.1Gr. 386Cat IIpipewouldneedaminimumwall thicknessof11.4mmpluscorrosionallowance(1.3mm),andaminimumtoughnessof60Jat–45°C.




5.2 PipelineSafeguardingConsiderations

LineBreakValves

AsperClass2 requirements forCSAZ662, linebreakvalves (LBVs)arespacedatnogreaterthan15kmintervals.TherearesixLBVsinthissystem.

Thelinebreakvalveshavebeenplacedinareasnearsecondaryroads,whichallowsforease of access by operations andmaintenance personnel. As the LBVs are located inpopulatedareas,theyarefencedforsecurity.Thefencingisstandard8‐footchainlinkwiththreestrandsofbarbedwireontop.

IntheeventofasingleLBVclosure,theLBVcomputerwillsendasignaltoallLBVstoclose, thusminimizing loss of containment. Closure of an LBV is expected to take30seconds from the open position to the fully closed position, thus minimizing thepressuresurge(causedbythekineticenergyofthefluid)atanLBV.

Afteremergencyshutdowndue toapipeline leakorruptureand followingrepairsoftheline,thedepressurizedsectionwillbebroughtuptotemperatureandpressurizedagain, slowly, by the line break bypass valves, which also serve as temperature‐controlledventsinthecaseofemergency.

PipelineLeakDetection

LeakdetectionisbasedupontheprincipleslaidoutinCSAZ662AnnexEaspertainingtoHVPlines.Leakdetectionisbasedonmaterialbalance.TheCoriolis‐typemassflowmeters at the Scotford boundary limit and at the wellhead are of custody transferaccuracy.

Automatedandmanual emergency shutdownsystemswere installedon thepipeline.Anautomatedshutdowninitiateswhenpressuretransmittersonthelineindicatealowpressure situation, or a high rate of change in pipeline pressure. Both pressuretransmittersatoneormoreLBVstationsmustindicateapressurebelowthetrippointtoinitiateanautomatedpipelineshutdown.

EmergencyshutdownscanbeinitiatedmanuallyfromeachofthewellsitesorfromtheScotford control room when pressure, temperature, and flow transmitters indicateupset conditions. The pipeline utilizes the ATMOS leak detection system that sensesflow,temperature,andpressurefluctuationstodeterminewhetherthereisapotentialfor a leak.Audible and visual alarms are generated at the ScotfordUpgrader controlroominresponsetoapotential leak.Emergencyoperatingproceduresareinplacetorespondtothesealarms.

CorrosionProtection

Following regulatory requirements and the Pipeline Integrity Management Plan,cathodic protection has been installed for the pipeline, including the laterals.Installationincludesthefollowing:

Impressedcurrentanodesandanodeleads

Impressedcurrentrectifiers

Calcinedpetroleumcokebreezeandbentonitechips




Ventpipesandanodejunctionboxes

Monitoringteststations

Thermiteweldsforpipeconnectionsandcoatingrepairatthoselocations

Temporarymagnesiumanodesatdesignatedteststations

Inspection

InDecemberof2016, theCO2pipelinewas inspectedusingan in‐line inspection tool(smart pig). The inspection was required as per commitments to Alberta EnergyRegulator (AER)andwasconductedbya thirdpartyvendor. InLine Inspection (ILI)wasdoneon100%ofthefirsthalf(34km)ofpipelinefromthelauncherattheQuestsurface facilities at Scotford to the receiver at LBV 3. The ILI was not conductedthroughthesecondlegofthepipelinesincethereiscurrentlynoflowtowellsite5‐35andpigreceiveratLBV‐6.

Uponthefirstlaunchoftheinspectiontool,thesmartpigwasnotabletoprogresspasttheisolationOrbitvalveinthepipeline.Thiswasduetoashortdrive‐cupsectionandrequired a Quest unit shutdown and de‐pressuring of the first 15 km of pipeline toLBV1forsaferetrieval.TheQuestunitoutagewas~4.1days(Dec2–6).Roughly600tonnesofCO2wasventedfromthepipeline,andthelostCO2captureopportunitydueto taking the outage was roughly 15,000 tonnes. A second run was successfullycompletedafterinspectiontooldrive‐endmodificationsweremade.

As per the results of the inspection, it has been concluded that there is no activeinternal CO2 corrosion in the pipeline. Five external wall loss anomalies related topipingfabricationwerefound.However,all fiveanomalieshadwallthicknessbeyondthe 1.3 mm corrosion allowance of pipeline design and the minimum fracturetoughness limits per the SGS report GS.10.52923. Using this information and ShellsPIMS (pipeline integrityManagement System), the next inspection using a smart pigwillbein2021.Dependentupontheseresultsthereispotentialtocompleteintegritydigstoconfirmthefindingsandassesswhetherornotrepairsarerequired.

Thefollowinginspectionandmonitoringactivitieshavealsobeenconductedtoensurepipelineintegrity:

Operatorroundsofthepipelineandwellsiteswithappropriatefrequency

Non‐destructiveexamination(ultrasonicthicknesstest)onabovegroundpipingtoidentifypossiblecorrosionofthepipeline

Internalvisualexaminationofopenpipingandequipmentevaluatedforevidenceofinternalcorrosionwhenpipelineisdownformaintenance.Thiswillbedoneduringroutinemaintenanceactivitieswhenpartsofthesurfacefacilitieswillbeaccessible.

Pipeline right‐of way (ROW) surveillance including aerial flights to check ROWconditionforgroundorsoildisturbancesandthirdpartyactivityinthearea


Section 6: Facility Operations - Storage and Monitoring


6 FacilityOperations - Storage and Monitoring

ThissectionprovidesanoverviewofthewellsandMMVactivitiesfortheoperationalyear2017.

6.1 StoragePerformanceInjectionofCO2intothe8‐19and7‐11wellsbeganonAug23,2015,andasofDec31,2017,about2.6MtCO2havebeeninjectedintothetwowellsasillustratedinFigure6‐1. TheinjectionstreamcompositionisdescribedindetailinTable5.3,andisshowninFigure6‐2.

Injectionintothe5‐35wellhasnotyetbeenrequiredforthefollowingreasons:

1) The 7‐11 and 8‐19 wells have adequate injection capacity between them for allavailableCO2.

2) Thedownholepressuregaugeatthe5‐35wellprovidesusefulinformationfortheBCSasadeepmonitorwell.Thiswillhelpcalibratethereservoirmodelforthefarfieldresponseoftheinjectionattheothertwowells.

3) ThelackofinjectionreducessomeoftheMMVrequirementsatthe5‐35wellsite,which in turn reduces MMV costs. For example: there was no need to record amonitorVSPsurveyin2016or2017,sincewithoutinjection,thereisnochangeinreservoirCO2saturationsatthatlocation.

Tosimplifytheexpectedpressureresponseatthe5‐35well, theinjectionatthe8‐19wellwasheldasconstantaspossibleatroughly70tonnes/hour,while the7‐11wellratesvariedtoaccommodatetheremainingCO2.

Asaresult,bytheendofDecember2017,about1.25MtofC02hadbeeninjectedintothe7‐11welland1.37MtofC02hadbeeninjectedintothe8‐19well.Figures6‐3and6‐4 show thedaily average flow rates andP/T conditions at 7‐11 and8‐19during theinjectionperiod.




Figure6‐1:QuestInjectionTotals:CumulativeCO2injectedintothewellsfromstart‐upthroughtotheendof2017(red).Theblueandgreylinesshowtheaveragehourlyflowratesintothetwoindividualinjectionwells.

Figure6‐2:QuestInjectionStreamContent:Averageinjectioncompositionfor2017.




Figure6‐3:The8‐19InjectionWell:AveragedailyP/Tconditionsatthewellheadanddown‐holeduringinjectiontotheendof2017.




Figure6‐4:The7‐11InjectionWell:AveragedailyP/Tconditionsatthewellheadanddown‐holeduringinjectionin2017.




6.2 MMV Activities - Operational Monitoring During2017,thefollowingMMVactivitieswereexecuted:

AtmosphereDomain:MonitoringofCO2 levelswithin theatmosphere continuedusingtheLightSourcetechnology.

Hydrosphere Domain: Four discrete sampling events (Q1, Q2, Q3, Q4) were executed. Project groundwater wells located on the 3 injection well pads were sampled on a quarterly basis. Landowner groundwaterwellswithin 1 km of the injectionwellpadsweresampledonaquarterlyorbiannualbasisdependentupon well location. Note that additional groundwater well testing/sampling was undertakeninconjunctionwiththeQ12ndmonitorVSPcampaign.Furtherdetails onthehydrospheremonitoringactivitiescanbefoundinAppendixA in [2].

BiosphereDomain:NoactivitiestookplaceregardingsoilgasandsoilsurfaceCO2

fluxmeasurements.

Geosphere Domain: The second monitor VSP campaign was executed in Q1around well pads 7‐11 and 8‐19. Monthly satellite image collection for InSARcontinued. Between January and August 2017, images were collected using twosatelliteframes.SinceSeptember2017,asingleframecenteredoverthe3injectionwell pads is used for image collection. A baseline 2D surface seismic surveywasalsoacquiredalongsidetheVSPcampaigninQ1(2DSEIS).

WellbasedMonitoring: ongoing data collection viawellhead gauges, downholegauges,downholemicroseismicgeophonearray,andDTSlightboxes.

AnewMMVplanwassubmittedandapprovedin2017.The2017MMVplanincludesatieredsystemtoreviewandassess theMMVdata.The focus in thisreportwillbeonTier 1 technologies. The latter form the basis for assessing whether there is anindication of loss of containment. Depending on the outcome of that assessment,furtheranalysisorinvestigationoftheTier2technologieswillbeundertaken,andthenifneededTier3technologieswillbeassessed.

Notriggereventswereidentifiedduring2017thatwouldindicatealossofcontainment(Table6‐1). Inotherwords,datato‐dateindicatethatnoCO2hasmigratedoutsideoftheBasalCambrianSands(BCS)injectionreservoirduring2017.

Data to‐date also indicate that CO2 injection within the BCS is conforming to modelpredictions,basedon:

Thetime‐lapseseismicmonitoringresultsindicatethatthesizeoftheCO2plumes,asmeasuredbythe2016monitor1VSPand2017monitor2VSP,ismuchsmallerthanthemaximumplumelengthspredictedfromtheGen4modelanditisclosertothetheoreticalminimum.This isanother indicationthatthereservoir isbehavingbetter thanexpected,andthat thedisplacementofbrinebytheCO2maybemoreeffectivethantheinitialmodellingpredicted.

Assessmentofthepressuredataindicatesthatthereservoirhasmorethanenoughcapacityforthefulllifeofthisproject.

FurtherdetailsoftheMMVactivitiesundertakenandobservationsmadeduring2017,canbefoundinthe6thAERAnnualStatusReport[2].




Table6‐1:Overallassessmentoftriggereventsusedtoassesslossofcontainmentin2017

6.3 WellsActivities

6.3.1 InjectionWells

In2017,thetwowellsoninjection(8‐19and7‐11)underwentroutineworkincludingaWIT (wellhead integrity testing ‐wellheadmaintenance and pressure testing), SIT(packer isolation test) and logging operations consisting of a tubing caliper log andhydraulic isolation log (PNX). The tubing caliper logs displayed negligible tubingcorrosion.Thehydraulicisolationlogsexhibitedgoodhydraulicisolation.

The 5‐35 well which has not been on injection to date underwent routine workincludingaWITandSIT.

InFebruary2017,arequestwasmade foranon‐routinesuspensionapproval for theIW5‐35asperAERDirective013:SuspensionRequirementsforWells.InMarch2017,temporary approval was obtained to suspend the well in the current configuration,conditionaltothewellnotbeingusedforCO2injection.

Figures6‐3and6‐4showthedailyaverageflowratesandP/Tconditionsat7‐11and8‐19duringtheinjectionperiod.

6.3.2 Monitorwells

Discrete pressure measurements were acquired in the Cooking Lake in DMW 7‐11,DMW8‐19andDMW5‐35throughMDT/XPTsamplingduringthe2012/2013drillingcampaign. Continuous pressure data in the Cooking Lake Formation via fourmonitoringwells,DMW7‐11,DMW8‐19,andDMW5‐35andthefartherfieldDMW3‐4hasbeenongoingsinceQ3,2015,asillustratedinFigures6‐5,6‐6.

Tier Technology ^ Trigger 2017

IW DHP Measuring greater than 26 Mpa

DMW DHPAnomalous pressure increase above

background levels

Tier 1 MSMSustained clustering of events with a spatial

pattern indicative of fracturing upwards

DTS Sustained temperature anomaly outside casing

Pulsed Neutron log Indication of CO2 out of zone

SCVFChange in geochemical composition indicating

presence of project CO2

Tier 1 ‐ when available VSP2DIdentification of a coherent and continuous

amplitude anomaly above the storage complex

SEIS3DIdentification of a coherent and continuous

amplitude anomaly above the storage complex not applicable yet

SEIS2DIdentification of a coherent and continuous

amplitude anomaly above the storage complex baseline survey executed in Q1

^ based on Table 4‐3 of the 2017 MMV Plan

Legend no trigger event

trigger event

not evaluated




Figure6‐5.QuestDMWpressurehistorybeforeandduringinjection.

Figure6‐6:Quest3‐4DMWpressurehistory.




6.3.3 SurfaceCasingVentFlowandGasMigrationMonitoring

Asrequired,annualtestingwascompletedin2016forSurfaceCasingVentFlow(SCVF)andGasMigration(GM)attheinjectionpads.ReportsweresenttoAERinJune2017.

TheSCVFflowtestresultsforbothIW5‐35andIW7‐11aresummarizedinFigure6‐7.MeasurementsattheIW5‐35wellareatsimilarlevelstothoseobservedinJune2016.ThemeasuredSCVFflowratereadingforIW5‐35inJune2017wasTSTM(toosmalltomeasure).AlthoughthereisanincreaseatIW7‐11SCVFbuilduppressure,theoveralllevel is still low. No gas was detected on the SCVFmeasurements on IW 8‐19 for asecondconsecutiveyear, indicating that thesurfacecasingvent flowon thiswellhasdeclinedtozero.ThecompositionalresultsindicatethattheSCVFandGMgasattheIWwellsispredominatelymethane

GasmigrationtestingasperthesuggestedmethodinAERDirective20,Appendix2wasperformedonbothwells. PreviouslythegasmigrationsobservedonIW5‐35andIW7‐11 occurred as bubbles in the well cellars. In June 2016, no gas bubbles wereobservedintheIW7‐11cellar;however,inJune2017thegasbubbleshadreappeared.TheIW7‐11gasmigrationisnowintermittent.GasbubbleswereobservedintheIW5‐35cellarinboth2016and2017.

In2017, thegasconcentrationmeasurementsat30cmwere takenusingan invertedfunnel and hose for the first time. As such the results obtained are not directlycomparable to historical measurements of whole air collected via methane metersuspended over cellar. 2017 method preferentially samples for lighter gases andresultedinLELmeasurementsinthe96‐98%LELrangewhere2016andearlierwherewhole air measurements were taken resulted in the 4.6‐31% LEL range. The gasmigration measurements further away from the well are generally very low with acouplerelativelyhighermeasurementsthatarestillbelowthemeasuredvaluesatthecellar.TheGasMigrationsstillhavevery limited impactandnopotential forconcernbeyondthelease.

Figure6‐7:SCVFPressureandFlowratesummarygraphsforIW5‐35,IW7‐11andIW8‐19.


Section 7: Facility Operations -Maintenance and Repairs


7 Facility Operations - Maintenance and Repairs

Review and approvals of maintenance plans ‐ including identification of keymaintenanceactivities,werecompletedinearly2017.Trainingplansandmaintenanceprocedures for the maintenance personnel are complete and have included vendortraining for key components (analysers, compressor). Wherever possible, Shell hasleveragedexistingprocesses,systemsandprocedurestofacilitateasmoothtransitionoftheQuestprojectintoScotfordroutinemaintenanceandoperations.

Sparepartsrequirementsbasedonvendor‐suppliedinformationhavebeenpurchased,withsuccessfuldelivery.Completionofoutstandingreliabilitycenteredmaintenance(RCM) studies has facilitated creation and population of SAP (equipment databasesystem).

All essentialmaintenance processeswere in place prior to start up and received theappropriateinternalapprovalstoallowtheteamtoadvancetothestartupphase.

Poststartup,inAugust,regularmaintenanceplansimplementedthroughSAPbasedonRCM reports for the capture facility, pipeline and wells have provided a steady andreliableoperation.

Maintenanceandrepairsduring2017areasfollows:

Aminecarbonfilterchangedoutandreplacedwithfreshcarbon.Inspectionofvesselcompleteandnoadditionalrepairsrequired.

Teg carbon filter changed out and replacedwith fresh carbon. Inspection ofvesselcompleteandnoadditionalrepairsrequired.

Temporary caustic skid in place and operational to maintain properdownstreamPHofcondensategoingtowastewatercarbonsteelpiping.

Replaced insulation soft covers with hard insulation in certain areas due tofreezingofinstruments.

Lean/rich amine exchanger back flushed to improve heat transfer. Removedandrepaired2”vaporlineon“A”exchangerthathadapinholeleak.

Repairedsealflushnippleonhighpressureaminechargepump.

Removedandreplaced70bullplugs/gasketsonE‐24707headduetoleaks

InstalledsuctionscreensonP‐24611coolingwaterpumps

Replacedlubeoilnozzleson2ndpinioninCO2compressorgearbox

Replaced1st stage startup suction screenwith post startup suction screen onCO2compressor. InspectioncompletetoIGV(inletguidevane)andfirststageimpeller.

Logic changesonDCS surrounding amine filter swings and amine autopumpstartstoavoidnuisancetrips.


Section 7: Facility Operations -Maintenance and Repairs


2017Maintenance

E‐24602ALeakboxremovedandnewpipinginstalled

Temporary caustic skid added to increase PH on condensate going towastewaterfromQuestrefluxdrum.

AI‐247002 CO2 analyzer accuracy lines upwith gas bomb analysis since newbarometriccompensationadded

LT‐246011guidedwaveelectronicsreplaced

Pipelinesmartpigsentdownthelineforinspectionandnodefectsfound

FT‐247004electronicsreplacement(CO2flowtopipeline)

Inspection of piping throughout Quest using UT for corrosioninformation/tracking

2017PipelineMaintenance

Wellsiteflowcontroller’spositioner’sreplacement

Maintenancetoimprovefuelcellreliabilityandpowerfluctuations

Replacementofsolarcontrollerstoreducecommunicationalarms

Pigging/lineinspection BorealLaserrepairsandmaintenanceasrequired Questtruckreplacementandmaintenanceasrequired Roadandsitegroundmaintenanceasrequired FullROWinspection,groundrepairandvegetationcontrol FuelcellreplacementunderwarrantyatLBV’s MMVbuildingHVACrepairs Identificationofwellsite#3drainageissuesandfuturerepairplan

Overallmaintenanceissueshavebeenminimalforanewconstructionstartup.Sharingof best practices by networking with other operating facilities continues to helpimprovemaintenancepracticesandprocedures.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 8: Regulatory Approvals


8 Regulatory Approvals

8.1 RegulatoryOverviewRegulatory submissions in 2017 followed the schedule set forth by the Approval.Regulatory approvals in 2017 addressed the ongoing operations and optimization ofsafeoperations.

8.2 RegulatoryHurdlesTherewerenosignificantregulatoryhurdlesin2017.In2017,newMMVandClosureplansweresubmittedandapproved,alongwiththeSpecialReportonInSAREfficacy.

8.3 RegulatoryFilingsStatusTable 8‐1 lists the regulatory approvals status relevant to the Project for the 2017reportingperiod.

Table8‐1:RegulatoryApprovalStatus

ApprovalorPermit RegulatorStatusandTimingofApproval/Permit

Comments

CO2InjectionandStorage

AERApprovalNo.11837CDirective13

AER SubmittedFeb24,2017 Requestfornon‐routinesuspensionforSCLTHORH5‐35‐59‐21

ShellQuestAERApprovalNo.11837C MMVPlanUpdate

AERandGOA

SubmittedFebruary23,2017ApprovedMay11,2017

RequirementtosubmitupdatedMMVPlaneverythreeyearsasrequiredbytheSequestrationLeaseApprovalfromAlbertaEnergy.

ShellQuestAERApprovalNo.11837CClosurePlanUpdate

AERandGOA

SubmittedFebruary27,2017ApprovedMay10,2017

RequirementtosubmitupdatedClosurePlaneverythreeyearsasrequiredbytheSequestrationLeaseApprovalfromAlbertaEnergy.

QuestCarbonCaptureandStorageProjectFifthANNUALSTATUSREPORT

AER SubmittedMarch30,2017ReceivedMarch30,2017

AnnualReport

ShellQuestAERApprovalNo.11837CInSAREfficacyReport

AER SubmittedMarch31st,2017 RequirementtosubmitaSpecialReportontheefficacyorInSARasperCondition16ofApproval11837C.

ShellCanadalimitedOilSandsProcessingplant(BitumenUpgrader)EnvironmentalProtectionandEnhancementAApprovalno.49587‐01‐00,asamended

AER SubmittedrenewalapprovalapplicationonOctober5,2016

ExpirydateofEPEAApproval49587‐01‐07hasbeenextended(2ndextension)toOct31,2018

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 8: Regulatory Approvals


8.4 NextRegulatoryStepsThe regulatory requirements will be focused on demonstrating compliance withexisting agreements. With ongoing operations, minor changes may be required toimproveoperationalefficiencywhileensuringsafeperformance.

Expectedsubmissionsfor2018include:

TheSixthAnnualStatusReporttoAER

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 9: Public Engagement


9 Public Engagement

9.1 BackgroundonProjectandConstructionConsultationandEngagement

Shellconductedathoroughpublicengagementandconsultationprogrambeginningin2008 in support of the Quest CCS project. Stakeholder engagement began withmeetings with regulatory agencies and local authorities before the formalcommencementof thepublicconsultationprocess forQuest.Regulatoryagenciesandlocal authorities provided input on the planned participant involvement program.Quest was publicly disclosed in October 2008 via an information booklet and newsrelease,followedbyapubliclyadvertisedopenhouseinFortSaskatchewanonOctober16,2008.

AnextensiveandopenconsultationprogramwasinitiatedinJanuary2010beforefilingproject applications in November 2010. The consultation program includedstakeholderssuchas:

Directlyaffectedlandownersandoccupantsalongthepipelinerouteandwithin450mofeithersideoftherightofway

Landownersandoccupantswithintheseismicactivityarea

Landownersandoccupantswithina5kmradiusofShellScotford

Municipaldistricts/localauthorities

Industryrepresentatives

Provincialandfederalregulators

Aboriginalcommunities

Face‐to‐face consultationwith landowners andoccupants along the route andwithinthe seismic activity area was undertaken and all were provided with a projectinformationpackage.Allstakeholderswereprovidedwithprojectupdatemailersandinvitations to open houses,whichwere also publicly advertised. The comprehensiveprojectinformationpackageincluded:

LetterintroducingShellandtheQuestCCSproject

Projectoverviewbooklet

Mapoutliningtheproposedroute

Pipelineconstructionandoperationbooklet

3Dseismicbackgrounder

ShellCCSDVD



WelcometoShellScotfordbrochure

Privacyinformationnotice

LetterfromtheChairmanoftheERCB

ERCBbrochureUnderstandingOilandGasDevelopmentinAlberta

ERCB publication EnerFAQs No. 7: Proposed Oil and Gas Development: ALandowner’sGuide

ERCB publication EnerFAQs No. 9: The ERCB and You: Agreements,CommitmentsandConditions

In response to landowner feedback, effortsweremade to accommodate stakeholderconcerns.Severalre‐routesof thepipelinewereundertakentoavoidtheBruderheimNatural Area and re‐route through the North Saskatchewan River in response tolandowner feedback. Overall, more than 30 pipeline re‐routes were made due tostakeholder feedback. During other consultation activities (such as open houses,community meetings, county council presentations), issues brought forward werevetted through the consultation team and mitigation measures determined, wherepossibleandappropriate.

While the Government of Alberta did not require consultation with aboriginalstakeholders, the federal government continued to engage aboriginal parties. Shellcontinued to engage the regulatory authority for aboriginal consultation, regardingongoing aboriginal engagement for the project. Provincial regulators advised thataboriginal consultationwasnot required for theproject. Shelladvisedprovincial andfederal regulators that itwouldcontinue toprovideproject information to interestedaboriginalstakeholdersandconsultwithpartiesuponrequest.

9.2 StakeholderengagementfortheQuestCCSFacilityUpon start‐up of the Quest CCS facility, stakeholder engagement focused on twostreams:communityrelationsandCCSknowledgesharing/publicawareness.

9.2.1 CommunityRelations

CommunitystakeholderengagementactivitiesforQuestin2016fellintothefollowingcategories:

1) Updatestomunicipalgovernments

2) Workingtoresolvepublicconcerns

3) ParticipationintheCommunityAdvisoryPanel(CAP)

4) Communityevents/Publicinformationsessions



MunicipalGovernmentUpdates

Annualupdatesweregiventotownandcountyauthoritiesattheircouncilsessionstoprovide the most recent project progress information. Specifically, updates wereprovidedtothefollowingmunicipalities:

January24,2017–StrathconaCounty February28,2017–FortSaskatchewan

Shell’supdatestotheabovecouncilswerewellreceived.Nomajorissueswereraisedspecific totheQuest facilityandquestionswereansweredimmediatelyat thecouncilsessions.

PublicConcerns

Shell has a comprehensive public concerns process that is designed to encouragecommunity feedback. Itdoesnot takea formalcomplaint foraconcerntobeenteredinto the process. A concern or query from an informal conversation would still becapturedtohelpShellunderstandthepulseoftheconcernsfromthecommunity.Theseconcernscanrangefromimpactfromouroperations–bothrealandperceived–allthewaytoinquiriesthatarenotattributabletoShell.In2017,Shellrecorded26concernsrelatedtotheQuestfacility.Thisrepresentsthetotalnumberofqueries/complaints–notthenumberofindividuals.

Most of the concerns from 2017 were related to soil quality due to pipelineconstructionandwaterrunofffromthe5‐35wellpad.

Shellrespondedtoalloftheindividualswhoraisedconcernsandputinactionplanstoaddressanyissuesthatwereidentified.

ParticipationonCommunityAdvisoryPanel(CAP)

To involve the public in the development of the MMV plan, a Community AdvisoryPanel (CAP) was formed in 2012. The CAP comprises local community membersincluding educators, business owners, emergency responders, and medicalprofessionalsaswellasacademicsandAERrepresentation.Themandateofthepanelisto provide input to theQuest Project on the design and implementation of theMMVPlan on behalf of the broader community and to help ensure that results from theprogramarecommunicatedinaclearandtransparentmanner.In2017,theCAPmetonMay11toreviewthelatestMMVdata.

PublicInformationSessionAnopenhousewasheldinThorhildCountyonFebruary27,2017togivecommunitymemberstheopportunitytomeetwithShell,learnmoreabouttheproject,andaskquestionsaboutQuest.TheopenhousewasheldatThorhildCentralSchoolwithitopentostudentsfrom1‐2:30p.m.andopentothecommunityfrom4‐8p.m.



9.3 CCSKnowledgeSharingGlobalinterestintoourexperiencewiththeQuestfacilitycontinuedtobehighin2017.As such, members of the Quest team attended or hosted numerous conferences,workshopsandtours.Thetablebelowgivesanoverviewofthe2017activities:

Table9‐1:2017KnowledgeSharing

2017Conferences/Workshops/Tours Date Location

RITECCSTechnicalWorkshop Jan‐18 Tokyo,Japan

RCSPReview Jan23‐27 Pittsburgh

DCForum Feb7‐8 Washington,DC

MMVPlanUpdate Feb23‐27 Calgary

QuestOpenHouse Feb‐27 Thorhild

ThorhildCouncilMeeting Feb‐28 Thorhild

ASES2017 Mar‐05 Calgary

UofC,GLGY581 Mar‐9,13 Calgary

Gener8Conference‐InsideEducation Mar‐10 Kananaskis

GeoConvention May‐11,16 Calgary

US‐Can‐MexTrilateral Mar28‐30 Pittsburgh

ChevronGorgonknowledgesharing Apr‐03 Virtual

CCUSConference April10‐12 Chicago

AcquistoreKnowledgeShare Apr‐19 Calgary

APEGASummitAwards Apr‐27 Calgary

AERReview‐MMVandClosurePlans Apr‐28 Calgary

CSLFMid‐YearMeeting May1‐3 AbuDhabi

ARBCCSProgramReview May‐08 Virtual

IEAGHGExCo May‐11 Edmonton

CAPMeeting May‐11 Thorhild

CleanEnergyMinisterial June6‐8 Beijing

GordonResearchConference Jun12‐15 Connecticut



IEAGHGMonitoringNetwork Jun13‐15 TraverseCity

IEAGHGSummerSchool July16‐22 Regina

UofCCFREFTeamVisit Aug‐02 Calgary

EAGE/SEGCCSResearchWorkshop Aug28‐31 Trondheim,Norway

EAGEEnvironmentalWorkshop Sep4‐7 MalmoSweden

MGSCMicroseismicReview Sep19‐21 Champaign,Illinois

MissionInnovation Sep26‐29 Houston,Texas

NDRC/ERIMissiontoAlberta Sep‐26 Scotford

GlobalCCSInstituteStudyTour Sep27‐28 Scotford

CCSInstituteSymposium Oct3‐5 Regina

AsianDevelopmentBank Oct‐06 Scotford

SPEAnnualTechnicalConference Oct9‐11 SanAntonio,TX

PCORMeeting Oct‐24 Plano,TX

ShellIntegratedDevelopmentConference Nov15 Houston,TX

AmericanGeophysicalUnion Dec11‐13 NewOrleans

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 10: Costs and Revenues


10 CostsandRevenues

ThemajorityofQuestspendisCanadiancontent;lessthan5%oftotalspendisforeigncurrency (USD and Euros). Foreign exchange rate is managed through treasury at adailyspotrate.

10.1 CapexCostsQuest reached commercial operation in Q4 2015 and while the asset switched tooperation, some remaining closeout capital transactions continued to flow through.Table 10‐1 reflects the project’s incurred costs to the end of 2017. The categoriesfollowthoseusedbyShelloverthelifeoftheprojecttotrackprojectcosts.Totalcapitalcosts comprise $790 million versus the original $874 million to reach commercialoperation onOctober 1, 2015. *Sustaining capital required to operate the venture infiscal2017hasbeenshowninaseparatecolumn.

Table10‐1:ProjectIncurredCapitalCosts(,000)

*Sustainingcapitalin2017consistsofequipmentpurchaseforpipelinereliabilitymonitoringandsitelaborcostsassociatedwithcapturefacilitiesoperationssimulatorcapitalinvestmentin2017.



10.2 OpexCostsOperating costs associated with the venture for the first two years of commercialoperationsareshowninthetablebelow.TheoverallforecastforOpexin2018rangesfrom$29to$34Million.

Table10‐2:ProjectOperatingCosts(,000)

CostCategoryOct1,2015– Dec

31,20162017

Jan1–Dec31Power 3,717.70 4,513.96Steam 8,414.46 8,834.50CompressedAir 67.67 62.59CoolingWater 427.95 389.81DirectLabourandPersonnelCosts 7,829.42 5,635.83MaintenanceMaterialsandTechnicalServices 969.42 942.63PropertyTax 2,003.72 2,000.28SequestrationOpex 7,052.85 6,797.59MMVafterOperations 1,690.41 1,655.74PostClosureStewardshipFund 272.07 264.28OtherWellCosts 431.49 442.12SubsurfaceTenureCosts 362.50 420.00Pipeline‐InspectionandPigging 145.78 340.49Amine 340.67 0.00Chemicals 20.35 97.92Vendorrebates ‐122.32 ‐100.36CorporateandOtherCosts 119.24 205.95Total 33,743.37 32,503.34

Notes:

1. Minimal lossofaminewasobserved in2017,hencenoadditionalexpenditurewasrequired.

2. In2017, $100,000CAD invendor rebateswere received forproject insurancepremiumrefunds.

3. Review of allocations to Quest will occur in 2018, with potential resultingupdatestopastoperatingyears.



10.3 RevenuesRevenuesreflectfundingaswellasCO2reductionCreditsreceiveduptoDecember31,2017.

TheCO2reductioncreditsreceivedduring2017consistof1,212,182tCO2eSerializedVerified EmissionReductions for the periodAugust 23, 2015 – September 30, 2016.Singleandadditionalcredits,valuedat$30/tonne,havebeenissuedandareincludedin the table below. As per the multi‐credit agreement signed with the Province ofAlberta, additional credits are expected one year after base credits are issued andreported in the period in which they are received. Pending third party verification,creditsforemissionsreductionsafterOctober1,2016willbeserializedandreportedin2018.

Table10‐3:ProjectRevenues

2009–2015 2016 2017 AggregateRevenuesForecastConstruction Operation Operation

Jan1,2009–Dec31,2015

Jan1,2016–Dec31,2016

Jan1,2017–Dec31,2017

Jan1,2018–Dec31,2025

RevenuesfromCO2Sold

$‐ $‐ $‐

TransportTariff $‐ $‐ $‐

PipelineTolls $‐ $‐ $‐

RevenuesfromincrementaloilproductionduetoCO2injection

$‐ $‐ $‐

Revenueforprovidingstorageservices

$‐ $‐ $‐

Otherincomes–AlbertainnovatesGrant,NRCanFunding&GoAFunding

$573,345,454.60 $29,451,643.52 $30,100,000.00 $238,448,356.48

CO2reductioncredits $3,330,800.00 $36,365,460.00 $465,600,000.00

$573,345,454.60 $32,782,443.52 $66,465,460.00 $704,048,356.48

ForecastAssumptions:• QuestProjectdoesnotenteraNetRevenuePositionbeforeSeptember31,2025• Estimate7.8MTCO2avoidedovernext8years• Doublecreditsreceived;eachCO2reductioncreditvaluedat$30

.



10.4 FundingStatusTodate, theProject has received a total of $6.3million from theAlbertaInnovatesprogram,whichhasconcluded.Questhasmetthecriteriaofallowableexpensesforthe$120millionNRCanfundingfromtheGovernmentofCanada,and90%ofthefundingwaspaidinAugust2012,withtheremaining10%holdbackreceivedaftercommercialoperation.FundingfromtheGovernmentofAlbertaCCSFundingAgreementof$15millionwasreceived inMay2012,$40million inOctober2012,$75million inApril2013,$100millioninOctober2013,$15millioninApril2014,$38millioninOctober2014,$15millioninMarch2015andafurther$149millionatCommercialoperationinOctober2015.Questhasnowbeenintheoperatingfundingphasefortwoyears.

FundingduringoperationsisdeterminedbythenettonnesofcarbondioxidesequesteredineachyearPursuanttosection4.2oftheFundingAgreement.

Table10‐4:GovernmentFundingGrantedandanticipated

GovernmentfundinggrantedthroughconstructionoftheQuestproject.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 11: Project Timeline


11 ProjectTimeline

The timeline for Quest is shown in Table 11‐1. The only departure from the projecttimeline is the advancement of the completion of the capture commercial operationtests. The tests were originally scheduled to run into Q4 2015, but all tests werecompletedbytheendofQ32015.

Forfurtherdetailsontheconstructionactivities,seeSection2,Figure2‐1.

The projected forecast for CO2 injected is as submitted in Schedule “C” ProjectedPaymentScheduleaftertheachievementofcommercialoperations.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 11: Project Timeline


Table11‐1:ProjectTimeline

Quest Project Gantt Chart ‐ Quarterly Timing

Q 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Venture

Venture Level Management

Project Economics

Venture Optimization

Risk Management

JV Updates, Communication

Stakeholder Management

Project Assurance

CCS Learning and Knowledge Sharing

Capture

Complete Basic Design Premises

Basic Design and Engineering

Detailed Engineering

Procurement

Construction

Commissioning and Startup

Commercial Operation Tests

Pipeline

Pipeline Routing Selection

Basic Engineering and Environmental Support

Detailed Engineering

Procurement

Construction


Quest Project Gantt Chart ‐ Quarterly Timing

Q 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Storage

Initial Site Appraisal

Seismic Data Acquisition and Assessmemt

Subsurface Modelling

MMV Definition and Planning

MMV Baseline Data Acquisition

Detailed Well Engineering

Procurement

Well Dril l ing and Completion


Regulatory

Bundled ERCB Application

Main Pipeline Application

Capture Facilties Amendment

Federal EA

Subsurface / Reservoir Approvals

Wells Approvals

2009 2010 2011 2012 2013

2009 2010 2011 2012 2013

Window End

2015

FID Funding Startup

Window End

2014

2014 2015

FID Funding Startup

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 12: General Project Assessment


12 GeneralProjectAssessment

The project schedule, as noted in Section 11,was largelymaintainedwith the actualachievement of commercial operation on September 28, 2015. Project developmentcostswereonbudget; the final capital costswereunderbudget. Operating costs for2017 were under budget as well based on lower power costs and operationalefficiencies.

ProjectSuccessesin2017:

OperationalMMVDataAcquisition

In2017continuedmonitoringoccurredincludingtheacquisitionandinterpretationofthesecondmonitorVSP.RoutineloggingandwellintegritytestingwasalsocompletedontheIWs.

InJune2017,Questreachedthemilestoneof2milliontonnesofCO2injected.

NetworkingwithinIndustry

Networking with external, operating facilities continued to help better identifymaintenance practices and procedures. Technical knowledge was also shared andgained through numerous technical conference presentations and workshopattendance.

StakeholderEngagement

StakeholdermanagementcontinuestobeapriorityforQuest.In2017,Shellcontinuedthe use of open houses/coffee sessions for community engagement. The communityadvisorypanelcontinuestobeavaluabletooltoshareinformationandcollectfeedbackfrom the community and key stakeholders. Although we have built on the strengthyearsofcommunityengagement,werealizethatwemustcontinuethisdialogue.

Quest continues to attract interest from various industries, government and non‐governmentorganizations.Shellattendedandprovidedinformationtoalargenumberoforganizationsatconferencesandmeetingsoverthecourseoftheyear.

ProvincialGovernmentMilestones

CriticaltotheQuestfundingfortheGovernmentofAlbertaisaseriesofmilestonesthathavebeenagreeduponwithinthefundingagreement,whichmeasuretheprogressoftheproject.FundingpaymentsarebasedonQuestcompletingthesemilestonesastheycomeup.Allmilestonestothispointhavebeenpassedasscheduled.

Continued fundingof theprojectoccursbyannual funding installmentpayments (forupto10years)andthroughcredits.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 General Project Assessment


EnvironmentalStewardship

TechnicalSuccessesIn 2017, the low levels of chemical loss from the ADIP‐x process continued, withsignificantlylowercarryoverofTEGintoCO2vs.designwithestimatedlossesontracktoberoughly5,800kgannuallyvs.thedesignmakeuprateof46,000kgannually.

Furthermore, implementation of FGR (flue gas recirculation) technology, incombinationwith the installation of low‐NOxburners has allowed all threeHMUs tomeettheirNOxlevelcommitmentswithoutcontravention in2017withthecapabilitytomaintainNOxlevelsslightlyelevatedfrompre‐Questbaseline.

Successfulcompressorinspection,triptestingandre‐ratingoftheC‐24701compressorfrom12Mpato13.58Mpaforincreasedoperationalflexibility.

Cleaning of the lean/rich exchangers during the 2017 spring turnaround resulted instabilization of the fouling trend and impacted rich amine inlet temperature to thestripper observed in 2016. This cleaning of the exchanger resulted in minor dutyimprovementandtemperaturemaintenanceinthecolumninletin2017.

The Lean Amine carbon filter was placed back in service in November 2017 afterinspectionandreloadingwithonlyminorfoamingeventsobserved.

On the subsurface side, injection into the 5‐35well continues not to be necessary tomeet injectivity requirements, resulting in a significant savings in MMV costs. Inaddition, theuncertainty in thecapacityof theBCSstoragecomplexhasbeen furtherreduced post‐injection. There is strong evidence to support the assessment of BCShavingmorethansufficientcapacity tostore therequiredvolumeforupto27MTofCO2 over the life of this project with negligible likelihood of fracturing, faultreactivation,orCO2leakage.

The second monitor VSP was completed in Q1 2017 as well as groundwater datasamplinginallquarters.

Strongintegratedprojectreliabilityperformancewithoperationalavailabilityat98.3%.

AnnualCO2captureratiowasmaintainedinQuests2ndfullyearofoperationsat82.6%.Injectioncertification,audits,offsetverificationscompleted,withserializationof2015and2016credits,registeredontheAlbertaEmissionOffsetRegistry.

Challengesin2017:

There have been minor operational challenges to Quest, but none that have beeninsurmountabletodate.Adescriptionofthesechallengesandactivitiesundertakentoaddressthemfollows.

TechnicalChallenges

High corrosion rates caused by the low pH of Quest stripper reflux water remain aconcerntotheScotfordUpgraderWastewaterTreatmentPlant.Sectionsofpipinghavebeenupgradedto304stainlesssteel(2016)withfurthermitigationenactedin2017by

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 12: General Project Assessment


theinstallationofatemporarycausticinjectionskidatQuesttoincreasethepHoftheQuestwater.

Loss of Amine circulation due to lean Amine charge pump trips on low suctionpressure. Temporary procedural changes are in place to address this issue until apermanentsolutionisimplemented.

12.1 Indirect Albertan and Canadian Economic Benefits Quest is an in integrated operation that spans upstream through to downstreamprocesses. In the development and construction of Quest, the project had over 2000peoplecontribute to itssuccess.Theseskilledcontributors included:Tradesworkers,Engineers, Geologists, Geophysicists, Technicians, Environmental professionals, LandSMEs,Administrativeprofessionals,andManagement.Atpeakconstruction,theprojecthadover800workersspanningaperiodofover2years.

Theprimarybenefits in thisreportingperiodhasbeenadditionalbusinessgeneratedwithCanadianandAlbertanthird‐partycontractorsforthefollowingactivities:

Fieldworkdonetomonitorthehydrospherepropertiesof thestorageareasurfaceandgroundwaterregions

Routinewellmaintenance,loggingandSCVFtesting

Ongoing benefits during operations for the local communities, Alberta, and Canadainclude:

Employmentfor~25FTEpeople.

Tax additions to the local governments of Strathcona County, Thorhild,Lamont,SturgeonCountyAlberta,andCanada.

At a municipal level, Strathcona County (and even broader, Alberta’sIndustrial Heartland) derives benefit from the international attention thatQuestgenerates.

Recognition by the international community of Canada and Alberta asleadersinCCSdeploymentthroughpolicy,regulation,andfunding.

Maintenanceandrepaircontractsaround$2‐4millionperyear.

Inadditiontotheabove,discussionsbeganin2014withtheUSDOEtoutilizeQuestasaprojecttodevelopanddeployadditionalMMVtechnologiestosupporteitherreducedtechnologycostorimprovedmonitoringforcontainmentsecurity.During2017,workwas completed to update and finalize a demonstration agreementwith a technologyprovider.PartnershipssuchasthiswiththeUSDOEwillassistinraisingtheprofileofQuestandemphasizetheLeadershipdemonstratedbyAlbertaandCanadainsupportofsustainabledevelopmentofresourcesthroughinnovation.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 13: Next Steps


13 NextSteps

TheongoingfocusforQuest,intoitsthirdyearofoperations,istomaintainreliableandefficientoperations.SustainableoperationsarenotonlycriticalinordertocontinuetomeettherequirementsofthefundingagreementwiththeGovernmentofAlberta,butalsotoaffirmthepositionofQuestasaninnovativeandachievabletechnologyontheglobalstage.

Questwillcontinuewiththefollowingactivitiestoenablethis:

Capture of operational issues and lessons learned in order to retaininstitutionalmemoryandfacilitateimprovementsinprocessesandprocedures.

EvaluatingpossiblealternativestodeterminethebestsolutiontopermanentlymitigatethelowPHwaterleavingtheQuest.

OngoingMMVactivitieswillbeconsistentwith theapproved2017MMVPlanupdate.

Reservoirmodelwillbeupdatedusingavailableoperationaldataasrequired.

Regulatory activities will focus on demonstrating compliance with existingagreements and work will begin to facilitate obtaining the reclamationcertificationfortheQuestpipelineinearly2018.

Public engagement activities will continue to ensure continued publicknowledgeandacceptanceofQuestoperations.TheCommunityAdvisoryPanelwill continue in 2018 to update the group on Quest activities with focus onsustainingreliableoperations.OngoingreportingwillcontinuetotheProvinceofAlbertainaccordancewiththerespectivefundingagreements.

Active knowledge sharing through publications and participation inconferences,workshops,andtoursinto2018.

WorkingwithACCOonthetransitionfromtheSpecifiedEmittersGasRegulationtothenewCarbonCompetitivenessIncentiveRegulation.

With the improvedoperatingperformance and economicperformance versusdesign,understandtherevenueandcost forecastbetter todetermine impactstotheNetRevenuestatement.

EvaluateopportunitiestointegraterenewablepowerwithQuest.

Quest Carbon Capture and Storage Project Annual Summary Report - Alberta Department of Energy: 2017 Section 14: References


14 References

[1] AER,2016,SHELLCANADALIMITED,QuestCarbonCaptureandStorageProject,FifthANNUALSTATUSREPORT,availableat:http://www.energy.alberta.ca/CCS/3848.asp

[2] AER,2017,SHELLCANADALIMITED,QuestCarbonCaptureandStorageProject,SixthANNUALSTATUSREPORT,willbeavailableat:http://www.energy.alberta.ca/CCS/3848.asp

[3] GOA,2017,SHELLCANADALIMITED,QuestCarbonCaptureandStorageProject,2017MMVPlan,willbeavailableat:http://www.energy.alberta.ca/CCS/3848.asp

quest annual summary 2017 rev7 · 2019-03-12 · quest continues to see operating efficiencies with...

Documents