CHEMICAL EOR HOLDS A BRIGHT FUTUREConventional oil RF < 33%, worldwideMuch of it is recoverable by chemical methodsChemical methods are attractive:Burgeoning energy demand and high oil prices, most likely for the long-termField data proves chemical flooding is an effective way to recover residual oilAdvancements in technologiesBetter understanding of failed projectsNew chemical and processes open the door for new opportunities

THE CASE FOR CHEMICAL FLOODINGEscalating energy demand, declining reservesTwo trillion bbl oil remaining, mostly in depleted reservoirs or those nearing depletion Infill drilling often meets the well spacing requiredFewer candidate reservoirs for CO2 and miscibleOpportunities exist under current economic conditionsImproved technical knowledge, better risk assessment and implementation techniques

CHEMICAL EOR TARGET IN SELECTED COUNTRIES

Chemical Floods -CURRENT STATUS WORLDWIDE

Chemical Floods -PRODUCTION WORLDWIDE

CHEMICAL METHODSChemical EOR methods utilize: Alkaline Surfactants PolymerCombinations of such chemicals ASP (Alkaline-Surfactant-Polymer) floodingMP (Micellar-Polymer) floodingSS (Smart / Super Surfactant) flooding

OBJECTIVES OF CHEMICAL FLOODINGIncrease the Capillary Number Nc to mobilize residual oil Decrease the Mobility Ratio M for better sweepEmulsification of oil to facilitate production

Chemical Flooding -GENERAL LIMITATIONSCost of chemicalsExcessive chemical loss: adsorption, reactions with clay and brines, dilutionGravity segregationLack of control in large well spacingGeology is unforgivingGreat variation in the process mechanism, both areal and cross-sectional

ALKALINE FLOODINGProcess depends on mixing of alkali and oilOil must have acid componentsEmulsification of oil, drop entrainment and entrapment occurEffect on displacement and sweep efficienciesPolymer slugs used in some cases Polymer alkali reactions must be accounted Complex process to design

CHARACTERISTICS OF ALKALINE FLOODINGA solution of inorganic alkaline substance (NaOH, KOH) is injected into the reservoir.NaOH Na+ + OH- KOH K+ + OH- OH- + Acid hydrocarbon components SurfactantsIn-situ generated surfactants reduce interfacial tension and hence lowering Sor. May alter the wettability towards water wet.Help form emulsions near the displacement front.

Alkaline flooding -FIELD PERFORMANCE

Sheet1

Caustic Floods Field Projects

FieldSlug SizeCausticlb.CausticOil Satn.CausticOil Rec.

% PVConc. wt%per bbl PV% PVConsump.% PV

1Whittier80.20.06512.4-11.22

2Singleton82.00.5540-2

3N. Ward Estes154.92.826417.25

4L. A. Basin50.40.0730-

SURFACTANT FLOODINGVariationsSurfactant-Polymer Flood (SP)Low Tension Polymer Flood (LTPF)Adsorption on rock surfaceSlug dissipation due to dispersionSlug dilution by waterFormation of emulsionsTreatment and disposal problems

CHARACTERISTICS OF SURFACTANT FLOODINGA surface active agents which reduce interfacial tension at the oil-water interface. Formation of emulsionsThese are anionic compounds, where: Surfactant + Water (Inorganic Cation)++ + (hydrocarbon sulfonate anion)--They resist adsorptionMore stable than cationic surfactantsEasier and cheaper to manufacture

CHARACTERISTICS OF SURFACTANT FLOODINGWater salinity (specially divalent cations such as Ca++ and Mg++) play an important role in performance.Minimum interfacial tensions occurs at optimal salinity at which an optimum microemulsions is developed and the surfactant is equally soluble in water and oil.

Surfactant Flooding

InjectorProducerSURFACTANT FLOOD

InjectorProducerSURFACTANT FLOOD

InjectorProducerSURFACTANT FLOOD

InjectorProducerSURFACTANT FLOOD

InjectorProducerSURFACTANT FLOOD

InjectorProducerSURFACTANT FLOOD

InjectorProducerSURFACTANT FLOOD

InjectorProducerSURFACTANT FLOOD

SURFACTANT FLOODInjectorProducer

Surfactant FloodingDescriptionConsists of injecting a slug containing water, surfactant, electrolyte (salt), usually a co-solvent (alcohol), and possibly a hydrocarbon (oil), followed by polymer-thickened waterMechanisms That Improve Recovery EfficiencyInterfacial tension reduction (improves displacement sweep efficiency)Mobility control (improves volumetric sweep efficiency)

Surfactant FloodingLimitationsAreal sweep more than 50% for waterflood is desiredRelatively homogeneous formationHigh 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 and divalent ions (Ca++ and Mg++) < 500 ppmChallengesComplex and expensivePossibility of chromatographic separation of chemicalsHigh adsorption of surfactantInteractions between surfactant and polymerDegradation of chemicals at high temperature

Surfactant FloodingScreening ParametersGravity> 25 APIViscosity< 20 cpCompositionlight intermediatesOil saturation> 20% PVFormation typesandstoneNet thickness> 10 feetAverage permeability> 20 mdTransmissibilitynot criticalDepth< 8,000 feetTemperature< 225 FSalinity of formation brine< 150,000 ppm TDS

Surfactant flood -FIELD PERFORMANCEGlenn Pool Field, Oklahoma

POLYMER FLOODINGLoss to rock by adsorption, entrapment, salt reactionsLoss of injectivityLack of control of in situ advanceHigh velocity shear (near wellbore), ageing, cross-linking, formation pluggingOften applied late in waterflood

Polymer Flooding

CHARACTERISTICS OF POLYMER FLOODINGPolymer solutions have high viscosity, hence improve the mobility ratio.Some polymers are used for reducing the rock permeability due to their retention and viscoelastic properties. Hence, could be used as plugging agents for profile control.Increasing sweep efficiency.

Polymer FloodingDescriptionConsists of adding water soluble polymers to water before it is injected in reservoirMechanisms That Improve Recovery EfficiencyMobility control (improves volumetric sweep efficiency) LimitationsHigh oil viscosities require higher polymer concentrationResults normally better if polymer flood started before water-oil ratio becomes excessively highClays increase polymer adsorptionSome heterogeneity is acceptable, but avoid extensive fractures If fractures are present, crosslinked or gelled polymer techniques may be applicable

Polymer FloodingChallengesLower injectivity than with water can adversely affect oil production rates in early stages of polymer floodAcrylamide-type polymers loose viscosity due to sheer degradation, or it increases in salinity and divalent ionsXanthan gum polymers cost more, are subject to microbial degradation, and have greater potential for wellbore plugging

POLYMER RETENTIONPolymer solutions are retained mainly by adsorbtion and sometimes by pore trapping in reservoir rocks.Pore trapping is significant in low permeability rocks.Undesirable for polymer flood but desirable for profile control and thief zone plugging.Field observation indicates retention in the range of 7-150 g/m3 of rock.Acceptable retention level is less than 20 g/m3 of rock.Polyacrilamides show higher retention level than bio-polymer due to their ionic nature and shear thickening.

ESTIMATING POLYMER CONCENTRATIONPolymer concentrations depends on type and required solutions viscosity.Required viscosity is determined from maximum mobility ratio and shear rate.

ESTIMATING POLYMER CONCENTRATION

ESTIMATING POLYMER CONCENTRATION

ESTIMATING POLYMER SLUG SIZES

REQUIRED POLYMER SLUG SIZES

Polymer FloodingScreening ParametersGravity> 18 APIViscosity< 200 cpCompositionnot criticalOil saturation> 10% PV mobile oilFormation typesandstone / carbonateNet thickness not criticalAverage permeability> 20 mdTransmissibilitynot criticalDepth< 9,000 feetTemperature< 225 F

Polymer Flood - FIELD PERFORMANCESanand Field, India

Polymer Flood FIELD PROJECTS

ALKALINE-POLYMER FLOODDavid Field, Alberta

ASP: ALKALINE-SURFACTANT-POLYMER FLOODINGSeveral variations:ASPSAPPAS

Field tests have been encouragingSuccessful in banking and producing residual oilMechanisms was fully understood

Injected as premixed slugs or in sequence

ASP CHEMICAL CONTENTSAlkalineType of Alkaline for ASP is Sodium Hydroxide (NaOH) and Sodium Carbonate (Na2CO3)

SurfactantType of surfactant in ASP are:1. Alkyl Benzene Sulfonates2. Petroleum Sulfonates3. Lignosulfonates4. Petroleum Carboxylates5. Biologically Produced Surfactants

PolymerIn ASP flooding, types of polymer is Hydrolyzed Polyacrylamide (HPAM)

SCREENING CRITERIA ASP FLOODING Preferred for sandstones reservoir Reservoir Temperature less than 200 F Lower Ca++ and Mg++ contents Formation relatively homogeneous Oil Viscosity < 35 cp and API Gravity > 20 API Oil composition is light to intermediate components Oil Saturation > 35 % PV Average Permeability > 10 md Reservoir Depth less than 9000 ft.

ASP PILOT Daqing, China

MICELLAR FLOODINGUtilizes microemulsion and polymer buffer slugsMiscible-type displacementSuccessful in banking and producing residual oil Process Limitations:Chemical slugs are costlySmall well spacing requiredHigh salinity, temperature and clayConsiderable delay in responseEmulsion production

MICELLAR FLOODING PROCESSESChase water, to displace injected fluidsMobility taper, to achieve gradual decrease in viscosity of displacing fluids.Polymer slug, for mobility control. Micellar slug, to reduce the interfacial tension and hence lowering the residual oil saturation (Sor).Preflush solution, to precondition the reservoir and obtain optimal salinity.

MICELLAR FLOODING

MICELLAR FLOODING

MICELLAR FLOODING

MICELLAR FLOODING

ASP vs MICELLAR FLOOD -Lab Results Mitsue Oil Core FloodsEarlier oil breakthrough and quicker recovery in micellar flood

Micellar flood TYPICAL PERFORMANCEBradford Special Project No. 8

Micellar floods FIELD TESTS

ASP AND MP FIELD PROJECTS

Sheet1

Selected ASP and Micellar floods Field Projects

ASP FloodsDateGravitymfkRes. TDepthStage ofRec.Proj. Size,

FieldStartedAPIcp%mdCftAppln.%OOIPacre

1David, Alberta198622.634291400312490Tertiary21252

2West Kiehl, Wyoming1987241723350576630"20.7 (34.4 %OIP)106

3Gudong, China199241.3353750684173"13.4 (29.4 % OIP)766 acre

4Cambridge, Wyoming1993203118845567108"26.872

5Daqing, China199443928296372670"20 (23.9 % OIP)8.4

6Karamay, China1996338.818.767232224"24766

7Viraj, India200218.950304.5814265"18-24 exp68

Micellar Floods

Field

1Dedrick (IL) Marathon19621120200Secondary49.7 %OOIP2.5

2Robinson, 119-R (IL) Matathon196835-40619211221000Tertiary39 %OIP40

3Benton (IL) Shell19723.51790352100"29 %OIP160

4Robinson, 219-R (IL) Marathon197435-40621165221000"27-33 %OIP113

5Wichita, (TX) Mobil19752.32253321700"

SMART SURFACTANT (SS)Super EffectiveUltra-Low concentration required (0.02% - 0.3%)Provides ultra-low IFTSuper ConvenientNo alkali is requiredNo water treatment is requiredSuper Tolerant High TDS brineHigh divalent cationsHigh temperaturesSuper SavingsWater treatmentSludge disposalSurface equipmentPotential scale formationEquipment maintenance

Interfacial Tension- SMART SURFACTANT (SS)SS in High Salinity BrineTDS ~190,000ppm, Ca, Mg ~ 95,000 ppm Temp. ~ 50 C, API Gravity ~ 35SS in High TemperatureHeavy CrudeTDS ~ 250 ppm, Temp. ~ 100 C, API Gravity ~ 15

Chart1

0.00038

0.00022

0.001

0.00523

0.28

SS-B2550, WT%

IFT, mN/m

Sheet1

File Name:d/data/eor chemistry/eor19b.oxy

Purpose:

Martin Bravo sent the crude oil and water analysis for us to evaluate and recommend a surfactant for his

application.

BHT: 220 - 222 FSp.gr.-oil = 0.932 Brine = 1.0

Material4-1314-167-14-167-24-167-34-167-44-167-54-167-64-167-74-167-7

----------------------------------------------------------------- % ---------------------------------------------------------------------

Water4040---------------------

EB1025

CNP-11017.51010---2025252525

ORS-46HF32.580808050252525

ORS-48HF40---------------------

O-301010---20---255040---

4-153------10---------------25

Total100100100100100100100100100

AppearanceSl. Gelclearclearclearcleargelclearclear

SampleIFT, mN/m 5 minIFT, mN/m 15 minIFT, mN/m 30 minIFT, mN/m 60 min

2026B1.0*elongated

4-1311.0*0.01000.0024

repeat1.0*0.00200.0006

repeat1.0*0.00980.00530.00002

4-167-11.0*0.02700.0065

repeat1.0*0.02000.00390.0024

4-167-21.0*0.0180

4-167-31.0*ball

4-167-41.0*ball

4-1251.0*elongated

4-167-50.20.00080.0003

0.1elongated

4-167-60.20.0074 **0.0200

0.10.01100.00970.0062

repeat0.10.0011

4-167-70.0003

4-167-80.100.00020.00006

0.200.0004

0.050.0016

0.0250.0052

* The sample was measured wrong by adding 0.1g of the sample to 9.9 g water. This mistake

turn out to be good or if I measured correctly for 0.1% I would throw this sample out instead

** The oil droplet has "water like" round ball inside turning with the oil droplet. It's hard to take a reading.

%IFT

4-167-80.200.0004

0.100.0002

0.050.0010

0.0250.0052

0.010.280

Sheet1

0

0

0

0

0

Surfactant Concentration, wt%

IFT, mN/m

Sheet2

Sheet3

Chart1

0.03

0.006

0.0043

SS 6-105, % Wt.

IFT, mN/m

Sheet1

Water21212121

A/S202020

A/S/W9.6

A/S/A20

IMPROVED OIL RECOVERY BY ADSORPTION-DESORPTION IN CHEMICAL FLOODING

Journal of Petroleum Science & Engineering 2004

Temp50 C

Oil Visc15cps

NaOH1.00%

ORS-62HF0.20%

Water3.0 PV

A/S Slug1.5 PV

A Slug3.0 PV

Ext. Water3.0 PV

0.0530

0.0818

0.1020

0.1514

0.309

Oman

0.20.03

0.10.006

0.050.0043

OA-88 SP Chemicals63.196.319

Treatment Plant1.340.134

Utilities0.850.085

Fixes11.281.128

Others23.342.334

10

OA-88 SP Chemicals48.29

Treatment Plant2.26

Utilities1.22

Fixes15.88

Others32.35

100

Sheet1

21

2120

21209.6

212020

RECOVERY, %OOIP

Water

A/S

A/S/W

A/S/A

Sheet2

0

0

0

TEMP 50COil 15 CPSNaOH 1%ORS-62HF 0.2%Water 3.0 PVA/S Slug 1.5 PVA Slug 3.0 PVExt. Water 3.0 PV

(SURFACTANT CONC, %)(ASP SLUG SIZE)

So, %PV

0

0

0

0

0

0

0

0

0

0

SS 6-105, % Wt.

IFT, mN/m

IFT vs. SS 6-105 @ Various COnc.

Sheet3

InjectorProducerSMART SURFACTANT

InjectorProducerSMART SURFACTANT

InjectorProducerSMART SURFACTANT

InjectorProducerSMART SURFACTANT

InjectorProducerSMART SURFACTANT

InjectorProducerSMART SURFACTANT

InjectorProducerSMART SURFACTANT

SMART SURFACTANTInjectorProducer

Oil Recovery Comparisons

Recycling Surfactant EffluentResidual surfactant present in the effluentProcess identifies surfactant in effluent and recycles back to reservoirSavings on surfactant costsSavings on disposal and treatment costsRecovers additional oilSPE 84075

REASONS FOR FAILURELow oil prices in the past Insufficient description of reservoir geologyPermeability heterogeneitiesExcessive clay contentHigh water saturationBottom water or gas capFracturesInadequate understanding of process mechanismsUnavailability of chemicals in large quantitiesHeavy reliance on un-scaled lab experiments

SCALE-UP METHODSRequire:Knowledge of process variables or complete simulation descriptionModel experimentsScale-up of model results to fieldGreater confidence to extend lab results to field

RESULTS: PREDICTION vs ACTUAL

CHEMICAL EOR AND HEAVY OILApplicable methods:Surfactant flooding unsuccessfulAlkaline flooding unsuccessfulCO2 immiscible; cyclic stimulation Limited success with WAGProblems:Unfavourable mobility ratioGravity segregationRock-fluid reactions, chemical loss, dilutionLack of scaling criteria, inadequate simulationOften used where steam is not suitable

EOR SCREENING CRITERIA FOR CHEMICAL FLOODINGMost important: geology and mineralogyOil viscosity < 35 cpOil API gravity > 30 APIPermeability 100 mdPorosity 15%Temperature < 150 FDepth< 9,000 ftPressure not criticalOil saturation 45%Oil in place at process start 600 Bbl/acre-ftFormation sand stone preferredThickness 20-30 ft Stratification desirableClay content < 5%Salinity < 20,000 ppmHardness < 500 ppm Oil composition Light, intermediates & organic acids desirableNo bottom water or gas cap

COMPARISON OF CHEMICAL FLOODING USAGE

COMPARISON OF CHEMICAL FLOODING USAGE

COMPARISON OF CHEMICAL FLOODING USAGENote : ASP (Alkaline-Surfactant-Polymer); AP (Alkaline-Polymer) SP (Surfactant-Polymer)

Depth Limitation for Enhanced Oil Recovery Methods

Preferred Oil Viscosity Ranges for Enhanced Oil Recovery Methods

Permeability Guides for Enhanced Oil Recovery Methods

Oil Gravity Guides for Enhanced Oil Recovery Methods

Summary of Screening Criteria for IOR and EOR MethodsN.C. = Not Critical*Transmissibility >20 md ft/cp**Transmissibility > 100 md ft/cp

HOW TO PLAN A FLOOD ?Choose a process likely to succeed in a candidate reservoirDetermine the reasons for success or failure of past projects of the process Research to fill in the blanksDetermine process mechanismsDerive necessary scaling criteriaCarry out lab and simulation studiesField based researchEstablish chemical supplyFinancial incentives essential

HOW TO REACH SUCCESS ?Select the proper project Utilize the expertise of all involved Chemical optimizationCost efficiencyEvaluate the lab and simulation resultsSelect the best processStart the pilot project

DETAIL STUDY ACTIVITIESData colecting, evaluating and analysisReview and update the Geophysics and Geology Study previously and QCDetail Study of Reservoir EngineeringLaboratory Core Analysis (Routine and SCAL)Chemical Laboratory Flooding TestDetail Study of Production Engineering Reservoir SimulationEconomic AnalysisRecommendations

IMPLEMENTATION STEPSIntegrated Reservoir ModelGeological Model (Static Data)Production History (Dynamic Data)Fluid and Rock Properties (Laboratory Data)History MatchingValidating the Geological ModelPredicting the Present Fluid DistributionsForecasting Future PerformanceEvaluating the MethodOptimizing Injection Schemes

PROCESS EVALUATION- Compare field results with lab (numerical) predictions- Relative permeability changes ?- Mobility control ?- Fluid injectivity ?- Extent of areal and vertical sweep ?- Oil saturations from post-flood cores ?

COST OF CHEMICALSAs the oil prices rise, so does the cost of chemicals, but not in the same proportion

Typical Costs:Polymer - $3/lbSurfactant- $1.20/lbCrude oil - $60/bblCaustic - $0.60/lbIsopropanol- $20/gallonMicellar slug- $25/bbl

Process Efficiency: volume of oil recovered per unit volume (or mass) of chemical slug injected