12/2/2010. Success in Surfactant EOR: Avoid the Failure Mechanisms

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

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

3 12/2/2010 Phase Behavior of Anionic Surfactant, Brine, and Oil Reed and Healy,

4 Interfacial Tension Correlates with the Volume Ratios in the Microemulsion Healey, Reed, and Stenmark,

5 Capillary Number Required for Displacement Depends on Wettability Stegemeier, 1975 Waterfloods 5

6 A successful ASP Process Dolomite sand pack 0.2% NI, 0.5 PV, 2% NaCl, 1% Na 2 CO 3, 5000ppm polymer,my4 crude oil (19cp) Injected Pore Volumes 6

7 Displacement profiles with ASP and foam drive 7

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

9 Oil Recovery by Gravity Drainage 9 months in F.B % Blend/0.3M Na 2 CO 3, aged, 122 md, Soi=0.68, 0.05% Blend/ Sor= M Na 2 CO 3 Oil Recovery, %OOIP % TDA 4PO/0.3M Na 2 CO 3, aged, 90 md, Soi=0.71, Sor= %Blend/0.3M Na 2 CO 3, 40 md, Soi=0.82, Sor= Time, days 9

10 Conditions Favorable or Challenging for Surfactant EOR Favorable Low moderate salinity Moderate temperature Clean sandstone No anhydrite (CaSO 4 ) Water wet Med high permeability Homogeneous High S orw On shore Do ASP flood ASAP Challenging High salinity Low or high temperatures Carbonate Anhydrite Oil wet Low permeability Fractured Low S orw Off shore Do research 10

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 11

12 Clays Act Like an Ion-Exchange Bed and Micelles as Mobile Ion-Exchange Media Hirasaki, 1982; Gupta,

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 13

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

15 Optimal salinity correlates with soap/surfactant ratio Optimal NaCl Conc., % NI Blend WOR=1 (TC Blend) WOR=3 (TC Blend) WOR=10 (TC Blend) NI blend TC Blend 0 1.E-02 1.E-01 1.E+00 1.E+01 Soap/Synthetic surfactant Mole Ratio 15

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

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 17

18 There is synergism in blending surfactants. %NaCl IOS Multi-Phase Region 1-Phase Region * * * * 1:1 4:1 9:1 N67 N67:IOS (w/w) Phase boundary Clear solution 2 clear phases Precipitation Cloudy solution * Cloudy after 9 months. 18

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 19

20 Phase behaviors of different ASP solutions after 1 week 20

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 21

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 22

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 23

24 Mixing with Formation Water and Polymer Drive Govern Transport Across Formation Nelson,

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

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

27 Minimum Dynamic IFT 1.E+00 Dynamic IFT of fresh oil and 0.2%NI-1%Na 2 CO 3-1%NaCl 1.E-01 IFT, mn/m 1.E-02 1.E-03 1.E Time, minutes 27

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 28

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 29

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 30

31 Alkali (Na 2 CO 3 ) reduces adsorption of surfactant on calcite Adsorption Density, 10-3 mmol/m without alkali 5% NaCl 3% NaCl Surfactant: NI Blend with ~1% Na 2 CO 3 5% NaCl 3% NaCl Residual Surfactant Concentration (mmol/l) 31

32 Comparisons of Anionic Surfactant (CS330+TDA-4PO 1:1) and Nonionic Surfactant (Nonylphenol-12EO-3PO) Adsorption on DOLOMITE Powder 1.2 Anionic surfactant on dolomite without alkali, plateau=83 Å 2 /molecule 1.0 Adsorption Density(mg/m 2 ) Nonionic surfactant on dolomite plateau=714 Å 2 /molecule Anionic surfactant with Na 2 CO 3 (0.2M,0.3M,0.4M) plateau = 830 Å 2 /molecule Residual Surfactant Concentration(Wt%) 32

33 Comparisons of Anionic Surfactant (CS330) and Nonionic Surfactant (Nonylphenol-12EO-3PO) Adsorption on SILICA Powder 0.9 Adsorption Density(mg/m 2 ) Nonionic surfactant on silica Plateau 184 Å 2 /molecule. CS330 on silica 5000 Å 2 /molecule Residual Surfactant Concentration(Wt%) 33

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 34

35 Bottle Tests: Cationic and Amphoteric Surfactants (50 ppm) & Demulsifier A (50 ppm) 21 hours equilibration No added chemicals 4 Demulsifier A + Cocobetaine 2 Demulsifier A + C 8 TAB 5 Demulsifier A + Octylbetaine 3 Demulsifier A + capryl/capraamidopropyl betaine C 8 TAB diluted to 2.5wt% in water, Amphoterics diluted to 5wt.% in water, and Demulsifier A diluted to 5 wt.% in Heavy Aromatic Naphtha. 35

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. 36

37 Polymer Surfactant interaction paper with Tham 37

38 Show over optimum system followed by low salinity 38

39 Ultra low, equilibrium IFT over wide salinity range possible with Na 2 CO 3 1.E+01 1.E+00 Without Na2CO3 With 1% Na2CO3 IFT(mN/m) 1.E-01 1.E-02 1.E-03 1.E Salinity(% NaCl) 39

40 Sweep efficiency with SAG, WAG, and waterflood as function of PV liquid injected SAG fg=2/3, Sweep Efficiency SAG WAG Waterflood SAG fg=2/3, SAG fg=4/5, SAG fg=2/3, SAG fg=3/4, SAG fg=2/3, SAG fg=1/3, SAG fg=1/2, WAG fg=4/5, PV's of Liquid Injected WAG fg=3/4, WAG fg=2/3, WAG fg=1/2, Water fg=0, 4 40

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

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

43 Buoyancy Contributes to Mobilization Pennell, Pope, Abriola, 1996 N N 2N N sin N N N 2 2 T Ca Ca B B Ca B u ow ow w w cos gkkrw cos 43