Fractured carbonates: a methodology to evaluate surfactant performances for wettability alteration
M. Morvan, M. Chabert (Rhodia)
R. Tabary, B. Bazin (IFPEN)
32nd Annual IEA EOR
Symposium & Workshop
• Introduction•Carbonate reservoirs
•Background on wettability
• Methodology
• Results
• Conclusion
• Perspectives
2
Contents
Carbonate reservoirs
Bratton, T. et al., Oilfield review, 4, 2006. Hirasaki & Zhang, SPE 88365
Porous
matrix
Fracture No water imbibition in matrix:� High water cuts
� Low secondary recovery
RPC
γα −
OIL-WETTypical carbonate reservoir
Vugs
• Half of the world’s reserves. Often fractured. 80 % are oil-wet
• Hydrophobic layer of adsorbed naphthenics and asphaltenes
• Our goal: covering of hydrophobic layer by surfactants (Wettability alteration)
Background on wettability
• “Ability of a fluid to spread on a surface in presence of a second immiscible phase”.
• Physical-chemistry:
• Spreading parameter: S= γOS – (γOW+ γWS)
• Petrophysics: USBM / Amott
• Comparison of energies needed to displace oil / water in a rock
• Comparison of saturations after spontaneous / forced displacements
owγ
γγθ
-cos
ws os=
Young’s law
Partial
spreading
In most
practical
cases
Total
spreading γOS
γOW
γWS
Substrate
Water
Oil
S < 0Substrate
Oil
WaterS> 0
• Introduction•Carbonate reservoirs
•Background on wettability
• Methodology
• Results
• Conclusion
• Perspectives
5
Contents
Methodology
• Contact angle measurements
• High throughput screening (HTS):
• Automated contact angle / model surface
• Fine screening on representative surfaces
• Calcite crystals (Iceland spar) treatment
• Manual contact angle measurements
• Petrophysics application tests:• Amott / USBM
2
form°
10 form°
>1000 formulations
T° / salinity
dependence
Contact angle measurements
• Direct screening of surfactant solutions:
• Under white oil (dodecane)
• On a hydrophobic surface (θWATER > 90°)
• Wettability alteration:
θAQ.SOL°/OIL>90° � θAQ.SOL°/OIL < 90°
• Effect of oil / water interfacial tension (γOW)
• γOW << 1 mN/m: total wetting possible
S= γOS – (γOW+ γWS)
• γOW decrease: initial wettability amplified
OIL
AQ. SOL°
HYDROPHOBIC SURFACE
θ
In our configuration: θ decrease = wettability alteration
θ
γγγγOWθ’γγγγ OW
γOS – γWS < 0
Oil-wet
γOS – γWS > 0
Water-wet
1-1 0
OW
WSOS
γ
γγθ
−=cos
High throughput contact angle
• Automated contact angle:
• Using inkjet printer
• Controlled atmosphere / temperature
• Model hydrophobic surface
• Polystyrene (PS), θ Water/Oil = 150°
• Deposition under oil
• Computerized image analysis (θ and IFT)
• Gains:
• 20 samples per hour, reproducible
• “In-drop” formulation OIL
Hydrophobic surface
1 µL aqueous droplets
OIL
Hydrophobic surface
1 µL aqueous droplets
OIL
Hydrophobic surface
1 µL aqueous droplets
OIL
Hydrophobic surface
1 µL aqueous droplets
Representative surfaces
• For fine contact angle screening
• Calcite treatment method:
• 1 month, 70°C, 30 bars, Lagrave crude oil.
• Surface hydrophobization:
• In air: θNATIVE ~ 40° � θTREATED ~100°
• Under white oil:
θNATIVE ~ 95° θTREATED ~160°
Native calcite Treated calcite
• Introduction•Carbonate reservoirs
•Background on wettability
• Methodology
• Results
• Conclusion
• Perspectives
10
Contents
Screening results
• 2 formulations chosen:
• Rhodia brand products
• Formulation 1:
• Good wettability alteration
• Rather low IFT γOW = 0.5 mN/m
• Formulation 2:
• Moderate wettability alteration
• Rather high IFT γOW = 3 mN/m
• Comparable surfactant effects on calcite and PS
• Screening method validated
• 2 different formulations: understanding of effects due to IFT and wettability
alteration
PS Treated calcite
BRINE(NaCl 20 g/L)
150°/160°
F1 95°/85°
F2130°/130°
Petrophysics
• Complete Amott/USBM tests:
• Fissure free Lavoux limestone core (Φ=0.23 – k = 45 mD)
• Core restoration: Lagrave treatment � uniformly oil-wet
• Forced displacements carried out using surfactants solutions
• Analysis based on Amott-Harvey indexes
WI = WWI – OWI
• Inverse Bond number
NB-1 > 5
� spontaneous displacements driven by capillarity
CWOR
CWSPW
SS
SSWWI
−
−=
CWOR
SPOOR
SS
SSOWI
−
−=
gh
kN
ow
Bρ
γ
∆
Φ
=−4.0
1
Capillary Pressure Pc
Water Saturation Sw
1
23
4
Spontaneous imbibition
• Formulation 2, slight wettability alteration and large IFT:
• Most efficient for spontaneous imbibition
• Formulation 1 (large wettability alteration and low IFT):
• Weak spontaneous imbibition by capillarity
0
1
2
3
4
5
6
7
8
9
0 1 10 100 1000 10000
Time (h)
Oil production (%)
Brine
Form° 1
Form° 2
Capillary Pressure Pc
Water Saturation Sw
1
23
4
Spontaneous drainage
• Both formulations alter wettability after being forced into the core
• Oil poorly penetrates in cores being exposed to surfactant formulation as opposed to
the one only exposed to brine
• Invasion of the porous media is the important factor
0
5
10
15
20
25
30
35
0 1 10 100 1000
Time (h)
Aqueous phase Production (%)
Brine
(oil wet)
Form° 1
Form° 2
Capillary Pressure Pc
Water Saturation Sw
1
23
4
Amott indexes
• Starting from an initially highly oil-wet core:
• Both formulations yield intermediate wettability
• Formulation 2 (γOW = 3 mN/m) most efficient: spontaneous imbibition
• Formulation 1 (γOW = 0.5 mN/m) modifies wettability if forced into the core
-0.610.03-0.01WI
0.650.140.09OWI
0.040.160.08WWI
Core 3
Brine
(20 g/L)
Core 2
Form° 2 (F2)
Core 1
Form° 1 (F1)
• Introduction•Carbonate reservoirs
•Background on wettability
• Methodology
• Results
• Conclusion
• Perspectives
16
Contents
Conclusion
• Correlation between contact angle and Amott:
• Both IFT and contact angle must be taken into account
• Formulations with low contact angle will give good Amott/USBM results if IFT
remains relatively high (>mN/m).
• Wettability is altered provided formulations enter the porous media.
• Corresponding methods to be applied at field scale:
• Cyclic wettability alteration (static approach using Huff & Puff)
• Develop innovative solutions to improve surfactant penetration in matrix
during flooding process
• Introduction•Carbonate reservoirs
•Background on wettability
• Methodology
• Results
• Conclusion
• Perspectives
18
Contents
Perspectives to address heterogeneous reservoirs
• Micro-model approach to investigate surfactant flooding in heterogeneous media
• We have design a dual porosity micro-model in silanized glass wafer
• Numerical algorithm was used to generate a network of randomly oriented channels
Fracture
9 µm
90 µm
65 µm
400 µm
Matrix
Mircomodel during a drainage
experiment
Autocorrelation function
of big network
Perspectives to address heterogeneous reservoirs
• Illustration of chemical combination in dual porosity network
• First step: oil drainage from the large pore network after injection of a first chemical
solution penetrating preferentially the larger pores
• Second step: oil drainage from smaller pore network after injection of a second chemical
solutions diverted into the smaller network
Step 1: invasion of large pores network Step 2: invasion of smaller pores network
Acknowledgments
H. Bodiguel (Bordeaux University)
R. Koetitz (Rhodia)
L. Neau, S. Gautier (IFPEN).
Text
22 � Speaker � Presentation title � 0000/00/00