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  • 2010 Chevron

    Ping Zhao, Sophany Thach, Varadarajan Dwarakanath, Taimur Malik, Will Slaughter

    Tenth U.S.China Oil and Gas Industry Forum

    September 15, 2010

    Prerequisites for Successful Implementation of Polymer/Surfactant/ASPFlooding in Oil Fields

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    Outline

    Background

    Polymer Selection and Evaluation

    Surfactant Selection, Evaluation and Manufacturing

    ASP Alkaline Surfactant Polymer

    Core Flood Results

    Summary

    2

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    Background

    Polymer Flooding: Poor performance in early pilots

    Surfactant Polymer (SP) flooding

    High production cost

    Poor field implementation

    Low recovery factor

    ASP flooding

    Small pilots

    Insufficient design work

    3

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    Favorable Reservoir Characteristics for Polymer Flooding

    High permeability; low heterogeneity; high porosity

    High remaining oil saturation; low residual oil saturation

    Low to moderate temperature

    Moderate salinity with low divalent concentration

    Low viscosity oil

    4

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    Characteristics of Polymers

    5-20 million Dalton partially hydrolyzed polyacrylamide(HPAM)

    Co-polymer of acrylamide (AM) and acrylic acid (AA); ~25-30% hydrolyzed

    Water soluble; used strictly for mobility control; shear-thinning

    Viscosity decreases with increased salinity and divalent concentration

    Further hydrolysis with increased temperature and pH; causes heightened sensitivity to divalent ions

    Susceptible to oxidative degradation in the presence of iron

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    Polymer Selection and Screening

    Identification of polymer

    Filterability and quality control

    Viscosity for possible salinity options

    Thermal/oxidative/shear stability

    Cost

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    Polymer Evaluation in Core Floods

    Polymer adsorption/retention

    Resistance Factor (RF) and Residual Resistance Factor (RRF)

    Effluent viscosities vs. shear rate

    Crude oil recovery, ROS, Sorw

    Polymer concentration and slug size

    TDS/Hardness

    Permeability, mineral/clay composition

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    Best Practices in Design and Optimization Using Simulation

    Amount of polymer (PV x ppm)

    Right equation for Polymer rheology

    Well locations

    Detailed reservoir description and petrophysics

    Misinterpretation of lab data

    Wrong/inadequate mechanisms in simulator

    Limitations of coarse grid blocks

    Need for multiple iterations between lab and simulation to validate simulator

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    Best Practices in Field Implementation

    Good polymer mixing equipment

    Effective and flexible filtration system

    Effective O2 scavenger and biocide

    Good polymer QA/QC from plant to injector

    Good working relationship with polymer supplier

    Early start of PF (well before WF maturity)

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    Current Potential and Limitations of SP/ASP

    With high oil price can increase the RF by 5-35% OOIP

    Works better in higher-perm reservoirs

    Cost-effective chemicals are available for EOR

    Extreme reservoir conditions

    Complex process

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    Surfactant Selection

    Phase Behavior

    Optimal salinity (S*)

    Optimum solubilization parameter (SP)

    Equilibration time

    Microemulsion viscosity

    IFT

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    Phase Behavior Experiment

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    Surfactant Evaluation in Core Floods

    Surfactant adsorption/retention

    Oil recovery, ROS, Sorc

    Surfactant concentration and slug size

    Permeability, mineral/clay composition

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    SP/ASP Technology Challenges

    Residual oil saturation target

    Chemical acquisition and cost

    Chemical QA/QC and mixing

    Reservoir mineralogy

    Pilot characterization (dynamic heterogeneity)

    Injection scheme

    Handling of emulsion/scale

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    Surfactant Manufacturing and Scale-up

    Stage 1: Surfactant Development Lab scale synthesis and analysis of surfactants

    Development of performance benchmark

    Stage 2: Scale-up of Surfactant Production Pilot plant and plant scale production of surfactants

    Test performance against benchmark

    Stage 3: Formulation Blending Optimal treat rates of each formulation component

    Stage 4: Delivery and Onsite Evaluation Performance assurance in the field

    15

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    ASP depends on high acid number in crude oil

    Sodium carbonate (vs. NaOH) was used as alkaline agent

    Success depends on balancing in situ soap with injected surfactant to yield low-IFT and correct phase behavior

    Emulsion/scale problems at producers can be costly

    ASP mechanistic simulation is possible for lab scale but not for pilot- or field-scale

    ASP Technology

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    Core Flood

    0.2PV 0.5PV 0.7PV 1.0PV

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    Polymer Core-Flood Results

    18

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    Surfactant-Polymer Core-Flood Results

    19

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    ASP Core-Flood Results

    20

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    Summary Polymer Flooding

    Polymer flooding has made the greatest stride of all chemical EOR processes (Daqing)

    Commercial PF in average reservoirs recovers ~ 10% OOIP

    Recovery Factor can be twice as high (20-30% 00IP) with early implementation in high-quality reservoirs

    Using high concentration and large pore volume of polymer leads to high Recovery Factor

    Polymers are commercially available for temperature < 200 F

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    Summary SP/ASP

    The amount of surfactant used in ASP is significantly lower than that used in SP

    Recent large ASP projects showed large recoveries (Avg.~22% OOIP) factors

    The use of sodium carbonate (vs. NaOH) as alkaline agent has significantly reduced alkali consumption though this consumption and scaling remains difficult field issues

    With high-acid-number oil, sodium carbonates significantly reduce the IFT minimum and widen the range with low IFT

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    Current Status of Chemical EOR

    RecoveryFactor

    % OOIP

    ChemicalCost

    $/bbl

    Incr. oil

    RecentTechnologyAdvances

    Polymer Low High 2-10

    Surfactant

    PolymerHigh Medium 15 -30

    AlkaliSurfactant

    PolymerVery High Low-Med 5-15

    Polymer Low High 2 -10

    Surfactant

    PolymerHigh Medium 15 -30

    AlkaliSurfactantPolymer

    Very High Low-Med 5 -15

    RecoveryFactor

    % OOIP

    Tech.Maturity

    ProcessComplexity

    ChemicalCost$/Bbl.

    Incr. Oil

    Recent TechnologyAdvances

    5 -15Avg. 11

    11 - 35Avg. 20

    15 - 30Avg. 22

    1) Commercial projectsoutside the U.S.

    2) New, better polymers at the cost of 20 years ago

    3) RF higher than prev. thought

    1) New surfactants for high TDS/hardness

    2) More robust and effectivedesigns

    3) Mechanisms well understood

    4) Fast and mechanistic simulators

    1) Many small but successfulfield trials

    2) Na2CO3 improves processefficiency and robustness

    3) Chemical cost greatly reduced

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    Questions?

    24

    Questions?

    Prerequisites for Successful Implementation of Polymer/Surfactant/ASPFlooding in Oil Fields OutlineBackgroundFavorable Reservoir Characteristics for Polymer FloodingCharacteristics of PolymersPolymer Selection and ScreeningPolymer Evaluation in Core FloodsBest Practices in Design and Optimization Using SimulationBest Practices in Field ImplementationCurrent Potential and Limitations of SP/ASPSurfactant SelectionSlide Number 12Surfactant Evaluation in Core FloodsSP/ASP Technology ChallengesSurfactant Manufacturing and Scale-upSlide Number 16Core FloodPolymer Core-Flood ResultsSurfactant-Polymer Core-Flood ResultsASP Core-Flood ResultsSummary Polymer FloodingSummary SP/ASPCurrent Status of Chemical EORQuestions?