fractured carbonates: a methodology to evaluate surfactant...

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



• 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


OIL

Hydrophobic surface


OIL

Hydrophobic surface


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



• 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


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


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)



• 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



• 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

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fractured carbonates: a methodology to evaluate surfactant...

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