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

2. 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

3. 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

4. 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

5. 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.

6. 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

7. 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

8. 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

9. 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

10. 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

11. 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.

12. 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

13. 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”

14. 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

15. 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)

16. 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

17. 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 = (hoil = 4.2 (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

18. 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

19. Viscosifying surfactant: application to field case
Temperature: T = 51°C
Permeability: k ~ 1 – 2 D
Oil 51°C : h = 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

20. 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.

21. 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

22. 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

23. 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)

24. 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

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

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

27. 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

28. 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