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ReviewEORDosen : Ir Andry halim, MMSTT MIGAS, Balikpapan2006Lecture 12SecondaryRecovery(EOR)pressure & physicallymoving through theCh 8a - 2Immiscible FloodWaterfloodMaintains reservoir pressure & physically displaces oil with water moving through the reservoir from injector to producer.Gas InjectionMaintains reservoir displaces oil with gas reservoir from injectorto producer. Withoutdilute into oilTertiaryRecovery(EOR)developing miscibilityCh 8a - 3ThermalFloodingReduces Sorw by steam distillation and reduces oil viscosity.Chemical FloodingReduces Sorw by lowering water-oil interfacial tension, andincreases volumetric sweep efficiency by reducing the water-oil mobility ratio.Miscible FloodGas FloodingReduces Sorw by with the oil through a vaporizing or condensing gas drive process.Enhanced Oil Recovery (EOR) Goal of EOR processes is to mobilize "remaining" oil Achieved by enhancing oil displacement &volumetric sweep efficiencies- Oil displacement efficiency is improved by reducing oil viscosity (e.g., thermal floods) or by reducing capillary forces or interfacial tension (e.g., miscible floods)- Volumetric sweep efficiency is improved by developing more favorable mobility ratio between injectant & remaining oil-in-place (e.g., polymer floods, WAG processes) Important to identify remaining oil & mechanisms necessary to improve recovery before implementing EORCh 8a - 4EnhancedOilRecovery(EOR)Ch 8a - 5Most EOR screening values are approximations based on successful North American projects. These are not intended to be firm cut-offs, but rather approximate practical limitations. They do not take into account new technology or varying economic situations.Dr. Bruce DavisWaterfloodingInjectionStorage FacilitiesWellOil ZoneInjection Water12Ch 8a - 6Injection Water Separation and Production WellPump21WaterfloodingDescription Most widely used post-primary recovery methodWater injected in patterns or along the peripheryMechanisms That Improve Recovery Efficiency Water driveLimitations High oil viscosities - higher mobility ratios Heterogeneity such as stratification, permeability contrast, and fracturing can reduce sweep efficiencyChallenges Poor compatibility between injected water &reservoir may cause formation damage Subsurface fluid control to divert injected water &shut off undesirable produced fluidsCh 8a - 7WaterfloodingScreening ParametersGravityViscosity Composition Oil saturation Formation type Net thicknessAverage permeability Transmissibility DepthTemperature> 25 API< 30 cpnot critical> 10% mobile oil sandstone / carbonate not criticalnot critical (usually >10md)not critical not criticalnot criticalCh 8a - 8Surfactant/PolymerFloodingSolution FromWellInjectionStorage FacilitiesOil ZoneSurfactantPolymerSolutionDrive Water1234Ch 8a - 9Surfactant Inje Solution From Mixing Plantction Water Separation and Production WellPump4 3 2 1Surfactant/Polymer FloodingDescription Consists of injecting a slug containing water,surfactant, electrolyte (salt), usually a co-solvent(alcohol), & possibly a hydrocarbon (oil), followed by polymer-thickened waterMechanisms That Improve Recovery Efficiency Interfacial tension reduction (improvesdisplacement sweep efficiency) Mobility control (improves volumetric sweepefficiency)Ch 8a - 10Surfactant/Polymer FloodingLimitations Areal sweep more than 50% for waterflood is desired Relatively homogeneous formation High amounts of anhydrite, gypsum, or clays are undesirableAvailable systems provide optimum behavior within narrow set of conditionsWith commercially available surfactants, formation water chlorides should be < 20,000 ppm & divalent ions (Ca++ & Mg++) < 500 ppmChallenges Complex & expensive Possibility of chromatographic separation of chemicals High adsorption of surfactant Interactions between surfactant & polymer Degradation of chemicals at high temperatureCh 8a - 11Surfactant/Polymer FloodingScreening ParametersGravityViscosity Composition Oil saturation Formation type Net thicknessAverage permeability Transmissibility DepthTemperatureSalinity of formation brine> 25 API< 20 cplight intermediates> 20% PVsandstone> 10 feet> 20 md not critical< 8,000 feet< 225 F< 150,000 ppm TDSCh 8a - 12PolymerFloodingDrive WaterOil ZonePolymer Solution312Ch 8a - 13Polymer Injection Water Separation and ProductionSolution From Well Injection Storage Facilities WellMixing Plant Pump3 2 1Polymer FloodingDescriptionConsists of adding water soluble polymers to water before it is injected in reservoirMechanisms That Improve Recovery Efficiency Mobility control (improves volumetric sweep efficiency) Limitations High oil viscosities require higher polymer concentrationResults normally better if polymer flood started before water- oil ratio becomes excessively high Clays increase polymer adsorptionSome heterogeneity is acceptable, but avoid extensive fracturesIf fractures are present, crosslinked or gelled polymer techniques may be applicableCh 8a - 14Polymer FloodingChallenges Lower injectivity than with water can adversely affect oil production rates in early stages of polymer flood Acrylamide-type polymers loose viscosity due to sheer degradation, or it increases in salinity & divalent ions Xanthan gum polymers cost more, are subject to microbial degradation, & have greater potential for wellbore pluggingCh 8a - 15Polymer FloodingScreening ParametersGravityViscosity Composition Oil saturation Formation type Net thicknessAverage permeability Transmissibility DepthTemperature> 18 API< 200 cp not critical> 10% PV mobile oil sandstone / carbonate not critical> 20 md not critical< 9,000 feet< 225 FCh 8a - 16Miscible Gas Flooding (CO2Injection)InjectionWellInjectionStorage FacilitiesPipelineDriveWaterOilBank/MiscibleFrontCO2 and WaterZoneWaterflood Sor124Ch 8a - 173CO2 Injection Water Separation and Production WellFrom Pump or Recycle4 3 2 1Miscible Gas Flooding (CO2 Injection)Description Consists of injecting large quantities of CO2 (15%or more hydrocarbon pore volumes) in reservoir toform a miscible floodMechanisms That Improve Recovery Efficiency CO2 extracts the light-to-intermediate components from the oil, and, if pressure is high enough,develops miscibility to displace oil from reservoir(vaporizing gas drive) Viscosity reduction / oil swellingCh 8a - 18Miscible Gas Flooding (CO2 Injection)Limitations Very low viscosity of CO2 results in poor mobility control Availability of CO2Challenges Early breakthrough of CO2 causes problems Corrosion in producing wells Necessity of separating CO2 from saleable hydrocarbons Repressuring CO2 for recycling Large requirement of CO2 per incremental barrel producedCh 8a - 19Miscible Gas Flooding(CO2 Injection)Screening ParametersGravityViscosity Composition Oil saturation Formation type Net thicknessAverage permeability Transmissibility DepthTemperature> 27 API< 10 cpC5 -C20(C5 - C12)> 30% PVsandstone / carbonate relatively thinnot critical not critical> 2,300 feet< 250 FCh 8a - 20Miscible Gas Flooding(HydrocarbonInjection)Oil Bank /Miscible FrontHC and WaterZoneDriveWater421Waterflood SorCh 8a - 213HC Gas Injection Water Separation and Production WellInjection Well Injection Storage FacilitiesFrom PumpPipelineor Recycle4 3 2 1Miscible Gas Flooding(Hydrocarbon Injection)Description Consists of injecting light hydrocarbons throughreservoir to form a miscible floodMechanisms That Improve Recovery Efficiency Viscosity reduction / oil swelling / condensing orvaporizing gas driveCh 8a - 22Miscible Gas Flooding(Hydrocarbon Injection)Limitations Minimum depth is set by pressure needed to maintaingenerated miscibility Ranges from about 1,200 psi for LPG process to 3,000-5,000 psi for High Pressure Gas Drive, depending on the oilSteeply dipping formation is very desirable - permits gravity stabilization of displacement that normally has an unfavorable mobility ratioChallengesViscous fingering results in poor vertical & horizontal sweep efficiency Large quantities of expensive products required Solvent may be trapped & not recoveredCh 8a - 23Miscible Gas Flooding(Hydrocarbon Injection)Screening ParametersGravityViscosity Composition Oil saturation Formation type Net thicknessAverage permeabilityTransmissibilityDepth> 27 API< 10 cpC2 - C7> 30% PVsandstone / carbonate relatively thinnot critical not critical> 2,000 feet (LPG)> 5,000 feet (lean gas)> 250FTemperatureCh 8a - 24Nitrogen / Flue Gas FloodingInjectionInjectionWellStorage FacilitiesN2 andWater ZoneOil Bank/Miscible Front1Waterflood Sor24Drive WaterCh 8a - 253N2 Gas Injection Water Separation and Production WellFrom PumpPipelineor Plant4 3 2 1Nitrogen / Flue Gas FloodingDescription Consists of injecting large quantities of gas that may be miscible or immiscible depending on pressure & oil composition Large volumes may be injected because of low cost Nitrogen or flue gas are also considered for use as chase gases in hydrocarbon-miscible & CO2 floodsMechanisms That Improve Recovery Efficiency Vaporizes lighter components of crude oil &generates miscibility if pressure is high enough Provides gas drive where significant portion of reservoir volume is filled with low-cost gasesCh 8a - 26Nitrogen / Flue Gas FloodingLimitationsMiscibility can only be achieved with light oils at high pressures; therefore, deep reservoirs are neededSteeply dipping reservoir is desired to permit gravity stabilization of displacement, which has a very unfavorable mobility ratioChallenges Viscous fingering results in poor vertical & horizontalsweep efficiency Flue gas injection can cause corrosion Non-hydrocarbon gases must be separated fromsaleable gasCh 8a - 27Nitrogen / Flue Gas FloodingScreening ParametersGravityViscosity Composition Oil saturation Formation typeNet thickness> 24 API< 10 cpC1 - C7> 30% PVsandstone / carbonate relatively thin (not critical forpressure maintenance)not critical not critical> 4,500 feetnot critical(> 35 for nitrogen)Average permeabilityTransmissibilityDepthTemperatureCh 8a - 28Thermal(Steamflooding)Oil and Water ZoneNear Original ReservoirTemperatureSteam andCondensedWater ZoneHeated OilZoneHot WaterZone2431Ch 8a - 29Stack Gas Steam Injection Separation and Production WellScrubber Generator Well Storage Facilities4 3 2 1Thermal (Steamflooding)Description Consists of injecting 80% quality steam todisplace oil Normal practice is to precede & accompany steamdrive by cyclic steam stimulation ofwells (called huff and puff)producingMechanisms That Improve Recovery Efficiency Viscosity reduction / steam distillation Supplies pressure to drive oil to producing wellChallenges Adverse mobility ratio & channeling of steamCh 8a - 30Thermal (Steamflooding)LimitationsApplicable to viscous oils in massive, high permeabilitysandstones or unconsolidated sandsOil saturations must be high & pay zones should be > 20 ft thick to minimize heat losses to adjacent formationsLess viscous crude oils can be steamflooded if they dont respond to waterSteamflooded reservoirs should be as shallow as possible because of excessive wellbore heat lossesNot normally done in carbonate reservoirsSince about 1/3 of additional oil recovered is consumed to generate required steam, cost per incremental barrel of oil is highLow percentage of water-sensitive clays is desired for goodinjectivityCh 8a - 31Thermal (Steamflooding)Screening ParametersGravityViscosityCompositionRemaining oil< 35 API (10-35 API)> 20 cp (100-5,000 cp)not critical> 500 bbl / acre-ft (> 40-50% PV)sandstone> 20 feet> 200 md> 100 md ft / cp> 200-5,000 feet not criticalFormation typeNet thickness Average permeability Transmissibility DepthTemperatureCh 8a - 32ChDepth Limitation for EnhancedOilRecoveryMethods8a - 33sumpLimited by TemperaturePolymerFlue GasMiscibleDepth (ft)EOR Method 0 2,000 4,000 6,000 8,000 10,000Hydrocarbon- Deep Enough for Required PressureNitrogen and Deep Enough for Required PressureCO2 Flooding Deep Enough for Required PressureSurfactant/Polymer Limited by TemperatureAlkaline Preferred Zone Con High tionFire Flood Deep Enough for Required PressureSteam Drive Normal Range (Possible)RREW-4-2-EORMethodsVG1-33No Feas b eNo Feas b eNo Feas b eNo Feas b eNo Es ab shed L m sPreferred Oil Viscosity Ranges forEnhancedOilRecoveryMethodsCh 8a - 34Feasiblet li i itWaterflooded)DifficultGood FairDifficultt i lGoodMore DifficultGoodMore DifficultGoodMore DifficultMiscibleFlue GasCO2 FloodingPolymerDrainholes, etc.ExtractionOil Viscosity - Centipoise at Reservoir ConditionsEOR Method 0.1 1.0 10 100 1000 1,000 100,000 1,000,000Hydrocarbon- Very GoodNitrogen andVery GoodSurfactant/ VeryPolymer Good Fair Difficult t i l Alkaline Good Fair Very t i l Fire Flood May Not Be Possible Good t i lSteam Drive (Can Be GoodSpecial Thermal:Shafts, Fractures, Various Techniques PossibleMining and NotRREW-4-2-EORMethodsVG1-34Permeability Guides forEnhancedOilRecoveryMethodsCh 8a - 35Preferred ZonePolymer- Not Critical if UniformFlue GasPermeability (millidarcy)EOR Method 0.1 10 100 1000 10,000Hydrocarbon- - Not Critical ifMiscible UniformNitrogen andCO2 Flooding - High Enough For Good Injection Rates - Surfactant/Polymer Possible Preferred ZoneAlkaline Preferred ZoneFire Flood Preferred ZoneSteam Drive Preferred ZoneRREW-4-2-EORMethodsVG1-35Summary of ScreeningCriteriaforEORMethodsN.C. = Not Critical*Transmissibility >20 md ft/cp**Transmissibility > 100 md ft/cpCh 8a - 36Oil Properties Reservoir Characteristicsdsg Gas Injection MethoChemical FloodinThermalApplications of Light Oil Steam Flooding(LOSF) to Waterflooded Reservoirs Relatively new variation on more traditional heavy oil steam flooding EOR technique Mechanisms in LOSF similar to traditional steamflooding:-Viscosity reduction For given temperature rise, the viscosity decrease for more viscous heavy oil is much more significant than in lighter oilsSwelling The thermal expansion of light oils is greater than that for heavy oilsStripping of light ends Since more lighter components are present in the light oils, potential benefits from development of condensate zones is more significant in light oils than in heavy oils--Ch 8a - 37Applications of Light Oil SteamFloodingtoWaterflooded ReservoirsEffect of oilgravity on viscosityreduction withtemperatureu0u;!:!l200'010005010,.12 API. 'On100c....~....(oJ 1-..0..1>1.0100 200 300 400 .5010Tremperature, O:FApplications of Light Oil Steam FloodingtoWaterflooded ReservoirsSwelling effect isshown where heavier oil (60 lb/cu.ft) has significantly less swelling potential than a lighter oil (55 lb/cu.ft). .I'lie' 8, ~--~-\\'--t------"!"",;-----------t---.....~- ...._._II ......,""""1f-:::100(~ILoU~~ IUI2-----I:.:.."t----"r-oof1:ir--...,._-~ i_8Z9:~1 ---+----:~~'----_!!_~--~~-~......---- ..-.-.-.-.........~-II.1-I.:I,,0 6, t-----.......~---f/!!c:-Jlrih:_-_+-- ii_---t - :IZ,0 51~~~~~--~--~~~~_,-----r---~IU.JII ''0' IilH .5 g,DE:;NIS,IJY At 6,0[F' ,ANID ',R[ESSU-,REApplications of Light Oil Steam FloodingtoWaterflooded ReservoirsDistillation (or stripping of light ends) is morepronounced in lighter oils than in heavierThis makes creation of acondensate volume withsolventpropertiesmuchmorelikelyinlighteroils20 ":::J>45 .40 .35 .30 .~0 25Q)E"015105"00Applications of Light Oil Steam FloodingtoWaterflooded Reservoirs Waterflooding in light oil reservoirs generallyproduces good recovery efficiency- Pockets of oil bypassed because of oil trapping lower permeability regions through capillary mechanismsin Water is immiscible with oil & will cause a significantresidual oil saturation (25-35%) even in the waterswept parts of reservoir LOSF can reduce residual oil saturation in waterflood swept portions since steam acts more like a gas & leaves more of a residual oil saturation to gas rather than to water- This gas (steam) residual can be significantly lowerthan for waterCh 8a - 41Applications of Light Oil Steam FloodingtoWaterflooded Reservoirs LOSF has second potential benefit from the generation ofa condensate/solvent zone- This condensate/solvent can have miscible characteristics which allow it to extract residual oil from low porosity / low permeability regions of reservoir which were bypassed by water injection Offsetting the LOSF benefits- Concerns for initiating a relative high cost thermal process in a reservoir where waterflooding has reduced the remaining oil-in-place & left a high water saturation which can be an additional heat loss issue Careful attention must be paid to economicconsiderations and understanding the risks for LOSF inreservoiraCh 8a - 42