Rhodia/Poweltec Visosifying Surfactant for Chemical EOR EOR Workshop “Mario Leschevich”, 3-5 Nov. 2010 Mikel Morvan, Guillaume Degré, Rhodia Alain Zaitoun, Jérôme Bouillot, Poweltec.

Contents Introduction to viscosifying surfactants for EOR Rhodia and Poweltec methodology: application to synthetic field cases Viscosity measurements Fluid propagation tests Core flood tests Viscosifying surfactant: application to field case Conclusion

Introduction to viscosifying surfactants for EOR Introduction to surfactant mesophases in aqueous solutions Packing Parameter (P) = VH/(lc.a0) Spherical micelles P ~ 1/3 Cylindrical micelles P~ 1/3 to ½ (Wormlike micelles or Hexagonal phases) Lamellar phase P ~ 1 Molecular dimension, concentration and environment determine (T, S) mesophases sequences

Typical surfactant flooding Introduction to viscosifying surfactants for EOR Rheological properties of surfactant micelles in aqueous solutions Spherical Micelles Cylindrical Micelles Low viscosity Newtonian fluid Entanglements Analogy with polymer Typical surfactant flooding (S, SP, ASP) L  1 m Viscosifying surfactant as an alternative approach to SP & ASP flooding Breakage/recombination dynamic F = volume fraction G0: Elastic modulus t: Relaxation time

Introduction to viscosifying surfactants for EOR Cryo-TEM image of wormlike micelles in aqueous solution Presence of giant micelles of ≈ 5nm in diameter. A structure is visible, since they appear mostly in parallel configuration, with an inter particle distance 15 to 20nm.

Contents Introduction to viscosifying surfactants for EOR Rhodia and Poweltec methodology: application to synthetic field cases Viscosity measurements Fluid propagation tests Core flood tests Viscosifying surfactant: application to field case Conclusion

Rhodia & Poweltec methodology: application to synthetic field cases Solubility Rheology Injectivity Viscosifying surfactant formulation Coreflood RHODIA POWELTEC Adsorption Oil Recovery Chemistry selection Millifluidic screening tests Petrophysic experiments

Rhodia & Poweltec methodology: application to synthetic field cases Principle of high-throughput screening for viscosity measurements developed at Rhodia LOF Formulation composition (surfactant & salt concentrations) are imposed thanks to syringe pumps Formulation viscosity is determined by pressure drop measurement viscosity (cP) Surfactant solution Saturated salt sol Water Capillary (length L, radius R) Viscosity Shear rate Map viscosity performance versus reservoir brine variations prior to full characterization using traditional rheometer

Viscosity measurements applied to various reservoir cases 0.1 0.3 0.5 0.7 0.9 50 100 150 200 concentration (% w/w ) Abs. viscosity (cP) 0.1 0.2 0.3 0.4 0.5 20 40 60 80 concentration (% w/w ) Abs. viscosity (cP) Viscosity measurements applied to various reservoir cases Salinity (g/L TDS) T (°C) 32°C 51°C 200 80°C 96 90°C 6 Field 3 Field 2 Field 1 Shear rate: 4 s-1 0.1 0.2 0.3 0.4 0.5 20 40 60 80 concentration (% w/w ) Abs. viscosity (cP) 0.1 0.3 0.5 0.7 0.9 100 200 300 400 500 concentration (% w/w ) Abs. viscosity (cP) Our viscosifying surfactants are salt tolerant (including divalent ions) with favorable impact of high brine concentration 9

Flow curve measurements in one reservoir condition Viscosity measurements Flow curve measurements in one reservoir condition Shear thinning behavior indicates that a decrease of shear rates lead to an increase of viscosity. Required surfactant concentration is thus reduced

Rhodia & Poweltec methodology: application to synthetic field cases A miniaturized core flood test has been developed to measure fluid propagation in single-phase condition Principle of miniaturized core flood test developed at Rhodia LOF 5 cm Syringe pump Capillary viscometer Pressure sensor core This miniaturized test can be used prior to full coreflood study to pre-screen performances of new surfactant formulations.

Rhodia & Poweltec methodology: application to synthetic field cases An illustration of permeability measurement from (Q, DP) curve Syringe pump Porous media Injectivity in porous media DPcore DPcapillary Imposed flow rate Capillary Adsorption Q = 5 mL/min Q = 4 mL/min Q = 3 mL/min Q = 2 mL/min Q = 1 mL/min k Patmosph.. Millifluidic set-up used to measure mobility & permeability reduction

Rhodia & Poweltec methodology: application to synthetic field cases Background on mobility & permeability reduction Mobility Reduction pressure drop during viscosifying surfactant slug injection at q cm3/h D P Visco. Surf Rm = D pressure drop during initial brine injection at q cm3/h P Initial brine Permeability Reduction pressure drop during brine injection after viscosifying surfactant slug at q cm3/h D P = Brine - After visco surf. Rk D P Initial brine pressure drop during initial brine injection at q cm3/h Mobility Reduction is also called “Resistance Factor RF” Permeability Reduction “Residual Resistance Factor RRF”

Fluid propagation tests Example of flow behavior in representative porous media (Clashach sandstone) using miniaturized core flood test Rheometer  Bulk viscosity Viscosity in porous media  injection in cores impose Q and measure DP C2 C1 Miniaturized core data Bulk rheology Capillary bundle model Mean pore radius Darcy’s Law Flow rate Q Shear rate Pressure drop viscosity DP Flow in porous media match bulk rheology Good propagation of viscosifying surfactant in porous media

Core flood tests Representative porous media: synthetic core Darcy’s law 1cm Surfactants solution is injected in water saturated cores to evaluate propagation properties in porous media Surfactants solution is injected in oil saturated cores to measure oil recovery efficiency (additional oil after water flooding)

Permeability Reduction is close to Rkw=1, showing no core damage Core flood tests Porous media: clashach sandstone core Kw = 1133 mD at 50°C – Injection brine: sea water Mobility and permeability reduction measurements in monophasic conditions Mobility Reduction values match bulk rheology: product has a good injectivity Permeability Reduction is close to Rkw=1, showing no core damage

Core flood tests: oil recovery efficiency Core flood sequence Results Core - Clashach sandstone: Porosity:  = 0.18 Pore radius (est.): Rp = 3.4 µm Water permeability: Kw = 1133 mD at 50°C Residual oil saturation: Sor = 0.49 (hoil = 4.2 cp @50°C) (before injecting surfactant) Sor reduction: 12% Fluid formulation: Injection brine: sea water (39 g/L TDS) Surfactant concentration: 3 g/L Temperature: 50°C No Sor reduction with HPAM Protocol Saturation with oil until Swi Water injection until Sor Surfactant injection Oil recovery measurement

Contents Introduction to viscosifying surfactants for EOR Rhodia and Poweltec methodology: application to synthetic field cases Viscosity measurements Fluid propagation tests Core flood tests Viscosifying surfactant: application to field case Conclusion

Viscosifying surfactant: application to field case Temperature: T = 51°C Permeability: k ~ 1 – 2 D Oil viscosity @ 51°C : h = 100 - 200 cP Brine concentration: 6.2 g/L TDS Reservoir conditions Select best viscosifying surfactant that matches reservoir characteristics Compare recovery performance with polymer flooding Methodology

Viscosifying surfactant: application to field case Absolute viscosity measurements in reservoir conditions show that same viscosity (20 cP - 10 s-1) as selected for HPAM solution (0.09%w/w) is obtained at a concentration of 0.3%w/w.

Viscosifying surfactant: application to field case Thermal stability of surfactant solution Fluid formulation Surfactant concentration 0.3% w/w Temperature T = 51°C Brine concentration: 6.2 g/L TDS Oxygen content < 50 ppb Viscosity measured at 50°C at low shear rate (10s-1) Anaerobic ageing of surfactant solution shows that no viscosity loss is observed over one month - On going ageing

Regular polymer flooding (HPAM) experiment Viscosifying surfactant: application to field case Regular polymer flooding (HPAM) experiment Reservoir core plug No Sor reduction is observed after HPAM injection

Oil recovery experiments after polymer injection (HPAM) Viscosifying surfactant: application to field case Oil recovery experiments after polymer injection (HPAM) Reservoir core plug Injection of a 0.3%w/w surfactant solution after HPAM has mobilized a significant fraction of the residual oil saturation (+16% OOIP)

Evaluation of viscosifying surfactant in synthetic field case Simulation Evaluation of viscosifying surfactant in synthetic field case Five Spot Pattern (1 Injector 4 Producers) Multilayer Reservoir, Strong vertical heterogeneity Reservoir thickness = 10 m Comparison between Waterflood Polymer Flood Viscosifying Surfactant Flood

Evaluation of viscosifying surfactant in synthetic field case Simulation Evaluation of viscosifying surfactant in synthetic field case

Simulation Evaluation of viscosifying surfactant in synthetic field case  Recovery Factor RF @ 6 years RF @ 11 years Water flood 33 % 39 % Polymer flood 40 % 46 % Viscosifying surfactant 50 % 56 %

Contents Introduction to viscosifying surfactants for EOR Rhodia and Poweltec methodology: application to synthetic field cases Viscosity measurements Fluid propagation tests Core flood tests Simulation Viscosifying surfactant: application to field case Conclusion

Conclusion Specific millifluidic tools have been developed to screen viscosifying surfactants from Rhodia Following performances have been measured for viscosifying surfactants in different conditions Viscosity at low concentration: 0.1 to 0.5% w/w Sor reduction in coreflood DSw = 10 to 20% (hoil at least 100 cps) High temperature / high salinity tolerance Shear thinning / recombination dynamics (Unlike Polymer) Limited surface facility Capex required Perspectives Pursue experiment on field case reservoir: adsorption measurements, additional oil recovery tests, simulation and extrapolation at pilot scale to evaluate economics