© 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

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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

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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

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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

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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

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Surfactant-Polymer Core-Flood Results

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ASP Core-Flood Results

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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 at½ 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?

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Questions?