1) The document discusses using viscosifying surfactants for enhanced oil recovery (EOR). It introduces surfactant mesophases and how their rheological properties can increase fluid viscosity. 2) Rhodia and Poweltec's methodology for developing and testing viscosifying surfactant formulations is described. This includes measuring viscosity under reservoir conditions, fluid propagation tests in porous media, and core flood tests to evaluate oil recovery. 3) An example application to a field case demonstrates good thermal stability of a surfactant formulation and its ability to further increase oil recovery compared to polymer flooding alone.

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

2. 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. 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. 4
• 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 µm
Viscosifying surfactant as
an alternative approach to
SP & ASP flooding
Breakage/recombination dynamic
..)5.21()( +Φ+=Φ sηη
Φ = volume fraction
τη 00 G≈ G0: Elastic modulus
τ: Relaxation time
Introduction to viscosifying surfactants for EOR

5. 5
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.
Cryo-TEM image of wormlike micelles in aqueous solution
Introduction to viscosifying surfactants for EOR

6. 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. 7
Rhodia & Poweltec methodology: application to synthetic
field cases
Solubility Rheology Injectivity
Viscosifying
surfactant
formulation
Coreflood
RHODIA
POWELTEC
Injectivity Adsorption Oil Recovery
Chemistry selection
Millifluidic
screening tests
Petrophysic
experiments

8. 8
• Principle of high-throughput screening for viscosity measurements
developed at Rhodia LOF
• Formulation composition (surfactant & salt concentrations) are imposed thanks to
syringe pumps
QL
RP
8
4
π
η
∆
=Viscosity3
. 4
R
Q
π
γ =Shear rate
• Formulation viscosity is determined by pressure drop measurement
Capillary (length L,
radius R)
ΔP
Pressure sensor
heating
ΔP
Pressure sensor
heating
Formulation
Mixing
Measure
Q1
Q2
Q3
Surfactant
solution
Saturated
salt sol
Water
[Ca
2+
] (g/L)
[surfactant](%w/w
)
0 5 10
0.1
0.15
0.2
0.25
0.3
0.35
5
10
15
20
viscosity(cP)
Map viscosity performance versus reservoir brine variations prior
to full characterization using traditional rheometer
Rhodia & Poweltec methodology: application to synthetic
field cases

9. 9
Viscosity measurements
0 0.1 0.2 0.3 0.4 0.5
0
20
40
60
80
concentration (% w/w
)
Abs.viscosity(cP)
0 0.1 0.2 0.3 0.4 0.5
0
20
40
60
80
concentration (% w/w
)
Abs.viscosity(cP)
0.1 0.3 0.5 0.7 0.9
0
50
100
150
200
concentration (%w/w
)
Abs.viscosity(cP)
0.1 0.3 0.5 0.7 0.9
0
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
Salinity (g/L TDS)
T (°C)
0
32°C
51°C
200
80°C
96
90°C
6
Field 3
Field 2
Field 1
Field 3
Shear rate: 4 s-1
Viscosity measurements applied
to various reservoir cases
9

10. 10
Flow curve measurements in one reservoir condition
10
-2
10
-1
10
0
10
1
10
2
10
3
10
0
10
1
10
2
10
3
10
4
shear rate (s
-1
)
viscosity(cP)
0.9%
0.7%
0.5%
0.3%
0.1%
Shear thinning behavior indicates that a decrease of shear rates lead to an
increase of viscosity. Required surfactant concentration is thus reduced
Viscosity measurements

11. 11
• Principle of miniaturized core flood test developed at Rhodia LOF
Syringe pump
Porous media
Injectivity, porous media
∆Pcore∆Pcapillary
Imposed flow rate
Capillary
Adsorption
Syringe pump
Porous media
Injectivity, porous media
∆Pcore∆Pcapillary
Imposed flow rate
Capillary
Adsorption
5 cm
Syringe pump
Capillary
viscometer
Pressure sensor
Pressure sensor
core
• A miniaturized core flood test has been developed to measure fluid
propagation in single-phase condition
• 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

12. 12
• An illustration of permeability measurement from (Q, ∆P) curve
Syringe pump
Porous media
Injectivity in porous media
∆Pcore∆Pcapillary
Imposed flow rateCapillary
Adsorption
0 2 4 6
0
50
100
150
200
250
300
Q (mL/min)
∆P(mbar)
0 100 200 300
0
50
100
150
200
250
300
time (s)
pressure(mbar)
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
Rhodia & Poweltec methodology: application to synthetic
field cases

13. 13
Mobility Reduction is also called “Resistance Factor RF”
pressure drop during viscosifying
surfactant slug injection at q cm3
/h
pressure drop during initial brine
injection at q cm3
/h
 Mobility Reduction
Background on mobility & permeability reduction
Permeability Reduction “Residual Resistance Factor RRF”
Visco. Surf
P
P
Rm
∆
∆
=
pressure drop during brine
injection after viscosifying
surfactant slug at q cm3
/h
pressure drop during initial
brine injection at q cm3
/h
 Permeability Reduction
Initial brine
Brine - After visco surf.
P
P
Rk
∆
∆
=
Initial brine
Rhodia & Poweltec methodology: application to synthetic
field cases

14. 14
• 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 ∆P
10
0
10
2
10
4
10
0
10
1
cisaillement (s-1
)
viscosite,Rm
C2
C1
Miniaturized core data
Bulk rheology
Flow in porous media match bulk rheology
Good propagation of viscosifying surfactant in porous media
Fluid propagation tests
Φ
=
k
r
8
Mean pore radius
Sr
Q
=γ
Darcy’s Law
Flow rate
Q
Shear rate
Pressure drop viscosity
∆P
Water
Surf
Water
Surf
m
P
P
R
η
η ..
=
∆
∆
=
Capillary bundle model

15. 15
• Representative porous media: synthetic core
• 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)
Core flood tests
pH
BYPASS
CALIBRATED
Porous medium
INJECTION
WATER
CHEMICAL
SOLUTION
PUMP
spectro
∆P
UPSTREAM DOWNSTREAM
CAPILLARY
∆P
∆PTOTAL LENGTH
∆P
pH
BYPASS
CALIBRATED
Porous medium
INJECTION
WATER
CHEMICAL
SOLUTION
PUMP
spectro
∆P
UPSTREAM DOWNSTREAM
CAPILLARY
∆P
∆PTOTAL LENGTH
∆P
kS
QL
P
η
=∆
Darcy’s law
1cm

16. 16
• Porous media: clashach sandstone core
• Kw = 1133 mD at 50°C – Injection brine: sea water
Mobility and permeability reduction measurements in monophasic conditions
Water
Surf
m
P
P
R
∆
∆
=
.
.
.
BeforeSurfbrine
AfterSurfbrine
k
P
P
R
−
−
∆
∆
=
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

17. 17
Core flood sequence
Core - Clashach sandstone:
• Porosity: φ = 0.18
• Pore radius (est.): Rp = 3.4 µm
• Water permeability: Kw = 1133 mD at 50°C
• Residual oil saturation: Sor = 0.49
(ηoil = 4.2 cp @50°C) (before injecting
surfactant)
Fluid formulation:
• Injection brine: sea water (39 g/L TDS)
• Surfactant concentration: 3 g/L
• Temperature: 50°C
Protocol
1. Saturation with oil until Swi
2. Water injection until Sor
3. Surfactant injection
4. Oil recovery measurement
Results
Sor reduction: 12%Sor reduction: 12%
No Sor reduction with
HPAM
No Sor reduction with
HPAM
Core flood tests: oil recovery efficiency

18. 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. 19
Viscosifying surfactant: application to field case
• Temperature: T = 51°C
• Permeability: k ~ 1 – 2 D
• Oil viscosity @ 51°C : η = 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

20. 20
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.
10
-1
10
0
10
1
10
2
10
0
10
1
10
2
10
3
shear rate (s-1
)
viscosity(cP)
0.5%
0.4%
0.3%
0.2%
0.1%
HPAM 0.09%
Viscosifying surfactant: application to field case

21. 21
• Thermal stability of surfactant solution
Viscosity measured at 50°C
at low shear rate (10s-1
)
0 20 40
0
0.2
0.4
0.6
0.8
1
time (days)
η/η0
Surfactant concentration 0.3% w/w
Temperature T = 51°C
Brine concentration: 6.2 g/L TDS
Oxygen content < 50 ppb
Fluid formulation
Anaerobic ageing of surfactant solution shows that no viscosity
loss is observed over one month - On going ageing
Viscosifying surfactant: application to field case

22. 22
Regular polymer flooding (HPAM) experiment
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Water Saturation Sw
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
After polymer injection
Initial kr (oil)
Initial kr (water)
OilRelativePermeabilitykro
WaterRelativePermeabilitykrw
Drop of water mobility
Krw = 0,131
Krw = 0,02
No Sor reduction is observed after HPAM injection
Reservoir core plug
Viscosifying surfactant: application to field case

23. 23
Oil recovery experiments after polymer injection (HPAM)
Injection of a 0.3%w/w surfactant solution after HPAM has mobilized a
significant fraction of the residual oil saturation (+16% OOIP)
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Water Saturation Sw
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Initial kr (oil)
After TAV flush (water)
After TAV flush (oil)
Initial kr (water)
OilRelativePermeabilitykro
WaterRelativePermeabilitykrw
Drop of water
mobility
Mobilization of extra
oilKrw = 0.131
Krw = 0.02
Reservoir core plug
Viscosifying surfactant: application to field case

24. 24
Simulation
• 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

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

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

27. 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. 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 ∆Sw = 10 to 20% (ηoil 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