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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
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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?