Visosifying Surfactant for Chemical EOR EOR Workshop “Mario Leschevich”, 3-5 Nov. 2010 Mikel...

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

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

• Rheological properties of surfactant micelles in aqueous solutions

Spherical Micelles Cylindrical Micelles

Low viscosityNewtonian 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

..)5.21()( s

= volume fraction

00 G G0: Elastic modulus: Relaxation time


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


6

Contents







• Conclusion

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

• 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 Viscosity

3

. 4

R

Q

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

MeasureQ1

Q2

Q3

Surfactantsolution

Saturated salt sol

Water

[Ca2+

] (g/L)

[sur

fact

ant]

(% w

/w)

0 5 100.1

0.15

0.2

0.25

0.3

0.35

5

10

15

20

visc

osit

y (c

P)

Map viscosity performance versus reservoir brine variations prior to full characterization using traditional rheometer


9

Viscosity measurements

0 0.1 0.2 0.3 0.4 0.50

20

40

60

80

concentration (%w/w

)

Abs

. vis

cosi

ty (

cP)

0 0.1 0.2 0.3 0.4 0.50

20

40

60

80

concentration (%w/w

)

Abs

. vis

cosi

ty (

cP)

0.1 0.3 0.5 0.7 0.90

50

100

150

200

concentration (% w/w)

Abs

. vis

cosi

ty (

cP)

0.1 0.3 0.5 0.7 0.90

100

200

300

400

500

concentration (% w/w)

Abs

. vis

cosi

ty (

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

Flow curve measurements in one reservoir condition

10-2

10-1

100

101

102

103

100

101

102

103

104

shear rate (s-1

)

visc

osit

y (c

P)

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

• Principle of miniaturized core flood test developed at Rhodia LOF

Syringe pump

Porous mediaInjectivity, porous media

PcorePcapillary

Imposed flow rate

CapillaryAdsorption

Syringe pump

Porous mediaInjectivity, porous media

PcorePcapillary

Imposed flow rate

CapillaryAdsorption

5 cm

Syringe pumpCapillaryviscometer

Pressure sensor

Pressure sensorcore

• 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.


12

• An illustration of permeability measurement from (Q, P) curve

Syringe pump

Porous mediaInjectivity in porous media

PcorePcapillary

Imposed flow rateCapillaryAdsorption

0 2 4 60

50

100

150

200

250

300

Q (mL/min)

P

(mba

r)

0 100 200 3000

50

100

150

200

250

300

time (s)

pre

ssu

re (

mb

ar)

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

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

PRm

=

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

PRk

=

Initial brine


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 coresimpose Q and measure P

100

102

104

100

101

cisaillement (s-1

)

visc

osit

e, R

m C2

C1

Miniaturized core dataBulk rheology

Flow in porous media match bulk rheologyGood propagation of viscosifying surfactant in porous media

Fluid propagation tests

kr

8

Mean pore radius

Sr

Q

Darcy’s Law

Flow rate

Q

Shear rate

Pressure drop viscosity

PWater

Surf

Water

Surfm

P

PR

..

Capillary bundle model

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

INJ ECTION WATER

CHEMICALSOLUTION

PUMP

spectro

PUPSTREAM DOWNSTREAM

CAPILLARY

P

PTOTAL LENGTHP

pH

BYPASS

CALIBRATED

Porous medium

INJ ECTION WATER

CHEMICALSOLUTION

PUMP

spectro

PUPSTREAM DOWNSTREAM

CAPILLARY

P

PTOTAL LENGTHP

kS

QLP

Darcy’s law

1cm

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

Surfm

P

PR

.

.

.

BeforeSurfbrine

AfterSurfbrinek P

PR

Mobility Reduction values match bulk rheology: product has a good injectivityPermeability Reduction is close to Rkw=1, showing no core damage

Core flood tests

17

Core flood sequence 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 = 0.49

(oil = 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

Protocol1. 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

Contents







• Conclusion

19

Viscosifying surfactant: application to field case

• Temperature: T = 51°C

• Permeability: k ~ 1 – 2 D

• Oil viscosity @ 51°C : = 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

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

100

101

102

100

101

102

103

shear rate (s-1

)

visc

osit

y (c

P)

0.5%

0.4%

0.3%

0.2%

0.1%

HPAM 0.09%


21

• Thermal stability of surfactant solution

Viscosity measured at 50°C at low shear rate (10s-1)

0 20 400

0.2

0.4

0.6

0.8

1

time (days)

/0

Surfactant concentration 0.3% w/wTemperature T = 51°CBrine concentration: 6.2 g/L TDSOxygen content < 50 ppb

Fluid formulation

Anaerobic ageing of surfactant solution shows that no viscosity loss is observed over one month - On going ageing


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

1After polymer injection

Initial kr (oil)

Initial kr (water)

Oil

Rel

ativ

e P

erm

eab

ilit

y k

ro

Wat

er R

elat

ive

Per

mea

bil

ity

krw

Drop of water mobility

Krw = 0,131

Krw = 0,02

No Sor reduction is observed after HPAM injection

Reservoir core plug


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

1Initial kr (oil)After TAV flush (water)After TAV flush (oil)Initial kr (water)

Oil

Rel

ativ

e P

erm

eab

ilit

y k

roW

ater Relative P

ermeab

ility krw

Drop of water mobility

Mobilization of extra oilKrw = 0.131

Krw = 0.02

Reservoir core plug


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

Simulation


26

Recovery Factor RF @ 6 years RF @ 11 years

Water flood 33 % 39 %

Polymer flood 40 % 46 %

Viscosifying surfactant 50 % 56 %

Simulation


27

Contents






• Simulation


• 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 Sw = 10 to 20% (oil 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

Visosifying Surfactant for Chemical EOR EOR Workshop “Mario Leschevich”, 3-5 Nov. 2010 Mikel...

Documents

Transcript of Visosifying Surfactant for Chemical EOR EOR Workshop “Mario Leschevich”, 3-5 Nov. 2010 Mikel...