Success in Surfactant EOR: Avoid the Failure Mechanisms

1. Success in Surfactant EOR: Avoid the Failure Mechanisms George J. Hirasaki Petroleum Engineering, Texas A&M November 9, 2010

2. Requirements for Surfactant EOR • Ultra-Low IFT • Mobility Control • Transport Across Reservoir

3. Phase Behavior of Anionic Surfactant, Brine, and OilReed and Healy, 1977

4. Interfacial Tension Correlates with the Volume Ratios in the MicroemulsionHealey, Reed, and Stenmark, 1975

5. Capillary Number Required for Displacement Depends on WettabilityStegemeier, 1975 Waterfloods

6. A successful ASP Process Dolomite sand pack 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.65 0.70 0.75 0.90 1.50 Injected Pore Volumes 0.2% NI, 0.5 PV,2% NaCl, 1% Na2CO3, 5000ppm polymer,MY4 crude oil (19cp)

7. Displacement profiles with ASP and foam drive

8. Layered sandpack with 19:1 permeability contrast about half-swept with water only but about completely swept with surfactant-alternated-gas (SAG)

9. 0.05% TDA-4PO/0.3M Na2CO3, aged, 90 md, Soi=0.71, Sor=0.51 0.05% Blend/0.3M Na2CO3, aged, 122 md, Soi=0.68, Sor=0.38 0.05%Blend/0.3M Na2CO3, 40 md, Soi=0.82, Sor=0.70 50 40 30 Oil Recovery, %OOIP 20 10 0 0.01 0.1 1 10 100 1000 Time, days Oil Recovery by Gravity Drainage 0.05% Blend/ 0.3M Na2CO3 9 months in F.B.

10. Conditions Favorable or Challenging for Surfactant EOR Favorable Challenging High salinity Low or high temperatures Carbonate Anhydrite Oil-wet Low permeability Fractured Low Sorw Off shore Do research • Low – moderate salinity • Moderate temperature • Clean sandstone • No anhydrite (CaSO4) • Water-wet • Med - high permeability • Homogeneous • High Sorw • On shore • Do ASP flood ASAP

11. Challenges to Ultra-Low IFT (1/4) • System becoming over-optimum because • Mixing with higher salinity formation brine • Ion exchange with clays • Dissolution of anhydrite • Live oil different from STO; GOR dependent • Oil/water ratio is parameter in ASP

12. Clays Act Like an Ion-Exchange Bed and Micelles as Mobile Ion-Exchange MediaHirasaki, 1982; Gupta, 1980

13. Challenges to Ultra-Low IFT (1/4) • System becoming over-optimum because • Mixing with higher salinity formation brine • Ion exchange with clays • Dissolution of anhydrite • Live oil different from STO; GOR dependent • Oil/water ratio is parameter in ASP

14. Optimal salinity of alkaline surfactant system is function of surfactant concentration and water/oil ratio

15. Optimal salinity correlates with soap/surfactant ratio

16. Simulations show high recovery possible with combinations of injected salinity and system soap/surfactant ratio Soap/(Soap+Surfactant)

17. Challenges to Ultra-Low IFT (2/4) • Injected under-optimum because • Surfactant precipitation at optimal salinity • Polymer separates at optimal salinity • Surfactant retention high at optimal salinity • Soap generated in situ with ASP

18. There is synergism in blending surfactants.

19. Challenges to Ultra-Low IFT (2/4) • Injected under-optimum because • Surfactant precipitation at optimal salinity • Polymer separates at optimal salinity • Surfactant retention high at optimal salinity • Soap generated in situ with ASP

20. Phase behaviors of different ASP solutions after 1 week

21. Challenges to Ultra-Low IFT (2/4) • Injected under-optimum because • Surfactant precipitation at optimal salinity • Polymer separates at optimal salinity • Surfactant retention high at optimal salinity • Soap generated in situ with ASP

22. Concentration profiles show soap/surfactant ratio passing across optimal with resulting ultra-low IFT 0.5 PV 1.0 PV Surfactant Soap Soap/surfactant IFT Oil saturation

23. Challenges to Ultra-Low IFT (3/4) • Salinity gradient versus constant salinity • Constant salinity can have divalents change • Mineral dissolution • Ion exchange • Salinity gradient dependent on mixing

24. Mixing with Formation Water and Polymer Drive Govern Transport Across FormationNelson, 1981

25. Surfactant is Retarded by High Salinity Ahead of Slug and Mobilized by Low Salinity Behind SlugHirasaki, 1983, Nelson, 1982

26. Challenges to Ultra-Low IFT (3/3) • Minimum IFT not ultra-low; >10-2mN/m • Low solubilization ratio • Poor surfactant activity • To much co-solvent, e.g. alcohol • Minimum IFT based on transient value

27. Minimum Dynamic IFT

28. Challenges to Mobility Control • Polymer gels • Polymer degradation • Bio- or thermal degradation of xanthan • Shear degradation of polyacrylamide, PAM • Chemical degradation of PAM • Oxygen • Iron • Free radicals • Polymer-surfactant interactions • Colloidal interaction • Addition of high MW oil • Surfactant in middle phase, polymer in excess brine • Microemulsion with viscosity

29. Challenges to Mobility Control (2/2) • Viscous emulsions and gels • Usually associated with over-optimum conditions • Liquid crystal – low temperature, possible need for alcohol • Linear versus branched surfactant (e.g., IOS, i-TD, N67) • Reservoir wettability • Underestimate reservoir heterogeneity • Foam destabilized by oil

30. Transport Across Reservoir (1/2) • Chemical stability • Hydrolysis of sulfate surfactant • Polymer stability • Alkali consumption • Anhydrite (calcium sulfate) can consume alkali • Clays exchange divalent and hydrogen ions • Surfactant retention • Partition into oil phase (over-optimum) • Adsorption on rock (opposite charge) • Sandstone versus carbonate • Redox potential; siderite, pyrite • Alkali can reduce adsorption and sequester divalent ions • Nonionic for carbonate formation

31. Alkali (Na2CO3) reduces adsorption of surfactant on calcite Surfactant: NI Blend without alkali 5% NaCl 3% NaCl with ~1% Na2CO3 5% NaCl 3% NaCl

32. Comparisons of Anionic Surfactant (CS330+TDA-4PO 1:1) and Nonionic Surfactant (Nonylphenol-12EO-3PO) Adsorption on DOLOMITE Powder

33. Comparisons of Anionic Surfactant (CS330) and Nonionic Surfactant (Nonylphenol-12EO-3PO) Adsorption on SILICA Powder

34. Transport Across Reservoir (2/2) • Filtration and plugging • Injected surfactant solution must be clear • Nonionic surfactant may be added • Scaling with divalent, bicarbonate, and sulfate • Softening, chelating, or inhibiting scale • Polymer – iron interactions • Filtration plugging scales with volume/area • Produced emulsions • Modify emulsion breaking

35. Bottle Tests: Cationic and Amphoteric Surfactants (50 ppm) & Demulsifier A (50 ppm) 21 hours equilibration 1 2 3 4 5 1 – No added chemicals 4 – Demulsifier A + Cocobetaine 2 – Demulsifier A + C8TAB 5 – Demulsifier A + Octylbetaine 3 – Demulsifier A + capryl/capraamidopropyl betaine C8TAB diluted to 2.5wt% in water, Amphoterics diluted to 5wt.% in water, and Demulsifier A diluted to 5 wt.% in Heavy Aromatic Naphtha.

36. Conclusions • Low tension, mobility control, and transport across reservoir are required for success. • Surfactant EOR must be tailored for specific reservoir conditions. • Some reservoirs are ideal for ASP. • Some reservoirs are challenging. • Over sight of a failure mechanism may result in failure of the process.

37. Polymer Surfactant interaction paper with Tham

38. Show over-optimum system followed by low salinity

39. Ultra-low, equilibrium IFT over wide salinity range possible with Na2CO3

40. Sweep efficiency with SAG, WAG, and waterflood as function of PV liquid injected

41. 0.5% N67-7PO&IOS, 2% NaCl 2.5% Phase Separation Precipitation 2.0% Clear Multi-Phase Region Concentration 1.5% 1.0% 2 CaCl 0.5% 1-Phase Region 0.0% 1:4 1:2 1:1 2:1 4:1 9:1 N67-7PO IOS N67-7PO S:IOS-15/18 (w/w) NI Surfactant Blends Improve Calcium Tolerance

42. Lower-phase microemulsion at 2% NaCl has an oil-rich layer of colloidal dispersion

43. Buoyancy Contributes to MobilizationPennell, Pope, Abriola, 1996