Viscosifying Surfactants for Chemical EOR

M. Morvan , G. Degré (Rhodia)J. Bouillot & A. Zaitoun (Poweltec)R.S. Al-Maamari & A.R. Al-Hashmi (SQU) H.H. Al-Sharji (PDO)

32nd Annual IEA EOR Symposium & Workshop

• Introduction

• Integrated workflow

•Technology positioning

• Field case

• Conclusion

2

Contents

Investigate surfactant formulations providing reserve increase

Surfactants(Displacement efficiency)

Surfactants(Displacement efficiency)

Polymers(Sweep efficiency)

Polymers(Sweep efficiency)

Time

~30%

Ultimate recovery

Time

~50%

Higher final recovery Faster recovery

Water floodSurfactant flood

Water floodPolymer flood

~30%

Ultimate recovery

3

Background in Chemical EOR

Simulation (H. Bodiguel, LOF)

M= 0,01 M= 100

Fingering Homogeneous front

Water + Surfacant

rP

γ2=∆

100 µµµµm

Trapped oil

Micromodel at LOF

• Rheological properties of micellar structures in aque ous solutions

Spherical Micelles Cylindrical Micelles

Low viscosityNewtonian fluid

Entanglements(analogy with polymer)

Typical EOR surfactant formulations

L ≈≈≈≈ 1 µµµµm

Viscosifying surfactant as an alternative approach to polymer & surfactant polymer flooding

Breakage/recombination dynamic

..)5.21()( +Φ+=Φ sηηΦ Φ Φ Φ = volume fraction

τη0

0 G≈G0: Elastic modulusττττ: Relaxation time

Introduction to viscosifying surfactants for EOR

+

• Introduction

• Integrated workflow

•Technology positioning

• Field case

• Conclusion

5

Contents

An integrated workflow

High Throughput Screening (HTS) tools have been developed to demonstrate surfactant solubility in reservoir conditions (brine, temperature). Classical ageing tests have been implemented to investigate thermal stability.

Millifluidic set-up have been designed to investigate fluid propagation in porous media in comparison with bulk flow properties & measure surfactant retention.

Petrophysic experiments are used to measure increase in oil recovery and surfactant adsorption in cores

Lab-scale simulations are required before up-scaling and injection strategy definition – Physics from SARIPCH

implemented to full field simulators

Coreflood Validation

Simulation

A whole set of capabilities are required for techno logy positioning

Surfactant solubility & stability

Flow properties

• Robotic platform used to determine surfactant solub ility versus salt & temperature

High Throughput method for solubility measurement

• Robotic microplates filled with surfactant solutions• Light transmission measurements with grey scale for solubility

screening: surfactant and salt concentrations, temp erature

Salt

Salt

Salt

Salt conc

conc

conc

conc.. ..

SolubleSolubleSolubleSoluble InsolubleInsolubleInsolubleInsoluble

Surfactant concentrationSurfactant concentrationSurfactant concentrationSurfactant concentration

Principle of miniaturized core flood test developed at Rhodia LOF

Syringe pump

Porous mediaInjectivity, porous media

∆Pcore∆Pcapillary

Imposed flow rate

CapillaryAdsorption

Syringe pump

Porous mediaInjectivity, porous media

∆Pcore∆Pcapillary

Imposed flow rate

CapillaryAdsorption

5 cm

Syringe pumpCapillaryviscometer

Pressure sensor

Pressure sensorcore

• A millifluidic device has been developed by Rhodia t o measure fluid propagation and adsorption in porous media

This miniaturized test is used prior to full corefl ood study to pre-screen performances of surfactant formulations

Flow properties of viscosifying surfactants

• Bulk rheology is measured using stress controlled rh eometer

• Introduction

• Integrated workflow

•Technology positioning

• Field case

• Conclusion

9

Contents

Viscosity measurements

Our viscosifying surfactants are salt tolerant (including divalent ions) with

favorable impact of high brine concentration

10

Salinity (g/L TDS)

T (°C)

0

51°C

200

85°C

966

Field 2

Field 1

Field 3

Shear rate: 4 s-1

• Viscosity performances have been evaluated in various conditions of salinity (6 to 200 g/L) and temperature (51°C to 85°C )

• Viscosity of tens of cP is measured for concentration between 0.1%w/w and 0.5%w/w

0 0.1 0.2 0.3 0.4 0.50

20

40

60

80

concentration (%w/w

)

Abs

. vis

cosi

ty(c

P)

0 0.1 0.2 0.3 0.4 0.50

20

40

60

80

concentration (%w/w

)

Abs

. vis

cosi

ty(c

P)

0.1 0.3 0.5 0.7 0.90

50

100

150

200

concentration (%w/w)

Abs

. vis

cosi

ty(c

P)

0.1 0.3 0.5 0.7 0.90

50

100

150

200

concentration (%w/w)

Abs

. vis

cosi

ty(c

P)

0.1 0.3 0.5 0.7 0.90

100

200

300

400

500

concentration (%w/w)

Abs

. vis

cosi

ty(c

P)

0.1 0.3 0.5 0.7 0.90

100

200

300

400

500

concentration (%w/w)

Abs

. vis

cosi

ty(c

P)

• Favorable impact of salinity on viscosity is observed

96 2000

20

40

60

80

salinity (g/L TDS)

rela

tive

vis

cosi

ty

T = 85°C

C = 0.3%w/w

Thermal stability• Anaerobic ageing tests are performed to evaluate thermal stability of the viscosifying surfactants.

• Ageing of two surfactant systems at two temperatures (51°C and 90°C) and various salinities (6, 32 and 97 g/L) are performed with oxygen content less tha n 50 ppb.

• Stability is evaluated by measuring viscosity as a function of time .

0 50 100 1500

0.2

0.4

0.6

0.8

1

1.2

time (days)

η /η 0

surf. A - TDS = 6 g/L

surf. B - TDS = 6 g/L

surf. A - TDS = 97 g/L

surf. B - TDS = 97 g/L

0 50 1000

0.2

0.4

0.6

0.8

1

1.2

time (days)

η /η 0

surf. A - TDS = 32 g/L

surf. A - TDS = 96g/L

surf. B - TDS = 96g/L

T = 51°C[02] < 10 ppb T = 90°C

[02] < 50 ppb

No degradation is observed over 4 months at T = 51°C and T = 90°C

Glove box test Sealed ampoules

• Example of flow behavior in representative porous m edia (Clashachsandstone) using miniaturized core flood test desig n by Rhodia

Rheometer ���� Bulk viscosity

Viscosity in porous media ���� injection in coresimpose Q and measure ∆∆∆∆P

100

102

104

100

101

cisaillement (s-1)

visc

osi

te, R

m C2

C1

Miniaturized core dataBulk rheology

Flow in porous media matches bulk rheologyGood propagation of viscosifying surfactant in porou s media

Fluid propagation in synthetic cores

Φ= k

r8

Mean pore radius

Sr

Q=γ&

Darcy’s Law

Flow rate

Q

Shear rate

Pressure drop viscosity

∆PWater

Surf

Water

Surfm

P

PR

ηη .. =

∆∆

=

Capillary bundle model

• Viscosifying surfactant flood versus polymer flood• Claschach core: ΦΦΦΦ = 0.18 - k = 1.1 Da – Temperature: 50°C • Fluid formulation in sea water - Oil viscosity: 4.2 cp at 50°C

Coreflood tests

0 2 40

20

40

60

80

100

120

time

Sa

tura

tion

(%

)

Sw=1 Swi Sor

Noadditional

oil

HPAM (C= 0.3 g/L, ηηηη = 1.7 cP)

Viscosifying surfactant (C = 3 g/L, k=1.1 D, ηηηη = 1.7 cP)

∆∆∆∆Sor = 13% OOIP

0 2 40

20

40

60

80

100

120

time

Sa

tura

tion

(%

)

water oil water polymer

Sw=1 Swi Sor

water oil water surfactant

Additional oil

100 80

20

5248

5248 100 85

15

5743

6832

• Introduction

• Integrated workflow

•Technology positioning

• Field case

• Conclusion

14

Contents

Viscosifying surfactant: field case

Reservoir conditions•Temperature: T = 51°C

• Permeability: k ~ 1 – 5 D (Sandstone)

• Crude oil viscosity at 51°C : ηηηη = 530 cP

• Brine concentration: 6.2 g/L TDS

Methodology•Select best viscosifying surfactant that matches reservoir characteristics:

- Viscosity

- Adsorption

- Injectivity

• Evaluate performance in reservoir conditions

- Adsorption

- Oil recovery efficiency

10-2

10-1

100

101

102

100

101

102

103

shear rate (s-1

)

ab

solu

te v

isco

sity

(cP

)Chemistry selection: viscosity performance

0.5%w/w

10-2

10-1

100

101

102

103

100

101

102

103

shear rate (s-1

)a

bso

lute

vis

cosi

ty (

cP)

0.4%w/w

0.3%w/w

0.2%w/w

0.1%w/w

HPAM 0.09%w/wHPAM 0.09%w/w

1%w/w

0.8%w/w

0.6%w/w

0.4%w/w

0.2%w/w

Surfactant A Surfactant B

18 cP0.4%w/wSurf. B

22 cP0.3%w/wSurf. A

20 cP0.09%w/wHPAM

Vicosity (7s -1)ConcentrationSolution

• Adsorption is measured using mini Clashach cores (L ~ 5 cm, d = 1.3 cm, k ~ 1 -2 D).

• Adsorption is determined by measuring delay of surf actant front. Capillary rheometer is used to detect the surfactant front at the outle t of the core.

0 2 4 6 8 10 12 140

20

40

60

80

100

120

V

∆ P

core

pc

m

CVVAds 0).( −

=

∆Pbrine

∆Psurf

C = 0

C = C0

Vc

Outlet surfactant front

Co: Sufactant concentrationmcore : Mass of the core

∆P∆P

Syringe pump

Porous media

Injectivity

corecapillary

Capillary

Adsorption

Imposedflow rate

Adsorption test

Chemistry selection: reduced adsorption

• Chemistry, process and formulation routes have been studied to reduce surfactant adsorption with no impact on viscosity p erformance

0 2 4 60

500

1000

1500

2000

2500

Ad

sorp

tion

(µ

g/g

)Adsorption measurements in monophasic

conditions using mini-core test

Surf. A

Surf. B

Proc. A

Proc. B

Proc. A

Proc. B

Proc. B + additive

Selected chemical

Viscosifying surfactant: oil recovery efficiency

Surfactant (kw = 2D, C = 0.4%w/w)

0 2 40

20

40

60

80

100

120

time

satu

ratio

n (

%)

∆∆∆∆Sor

=

20% OOIP

Sw=1 Swi Sor

water oil water surfactant

Adsorption = 500 µg/g

100

8614

6238

7921

Sor reduction with viscosifying surfactant :

20% OOIP

Sor reduction with viscosifying surfactant :

20% OOIP

Standard injection protocol

• Introduction

• Integrated workflow

•Technology positioning

• Field case

• Conclusion

20

Contents

Conclusion• Following performances have been measured for this patented technology in different conditions

• Viscosity at low concentration: 0.1 to 0.5%w/w

• Sor reduction in coreflood ∆Sw = 10 to 20% OOIP (ηoil up to 500 cPs)

• High temperature / high salinity tolerance

• Shear thinning / recombination dynamics (Unlike Polymer)

• Limited surface facility required

• Perspectives

• Pursue experiment on field case reservoir:

- Optimization of injection strategy

- Simulation and extrapolation at pilot scale to evaluate economics

• Explore more severe conditions (low permeability, high temperature...)