Simulation of combined low salinity

and surfactant injection

Arne Skauge1, Gro Kallevik1, Zhaleh Ghorbani1 and Mojdeh Delshad2

1. CIPR, Centre for Integrated Petroleum Research, U of Bergen, Norway

2. U. of Texas at Austin, Texas, USA

IEA EOR Workshop & Symposium 18-20 Oct. 2010

Tuesday: 15:15-15:40

Swi (SW) Sor (SW) Sor (LS) Sor (LSS)

B7 0,23 0,35 0,29 0,09

B2 0,22 0,28 0,04

K=600 mD

Berea cores aged with North Sea crude oil for 10 weeks at 90C

Saturation development during waterflood and surfactant flooding

IonConcentration

(ppm)

Ca2+ 471

Mg2+ 1 329

K+ 349

Na+ 11 159

Cl- 20 130

HCO3- 142

SO42- 2 740

LS

5000 ppm NaCl

SW

IFT

SW-oil: 23,5 mN/m

LS-oil: 16,5 mN/m

LSS-oil: 0,012 mN/m

Retention: 0,2 0,3 mg/g

00,002

0,004

0,006

0,008

0,01

0,012

0 5 10 15 20pv injected

Sa

lin

ity

(N

a+

(g

/l))

Eclipse Results

experimental data

SW LS

Oil production

Mixing of the brine due to both hydrodynamic mixing (dispersion) and two-phase prod

Matched by increase in the numerical dispersion (fewer grid blocks)

Case: SW to Sor than LS (dSo = 6 s.u.)

Salt concentration in effluent brine

0,000

0,002

0,004

0,006

0,008

0,010

0,012

0,00 2,00 4,00 6,00

pv injected

Sa

lin

ity

Na

, g

/l

0

0,002

0,004

0,006

0,008

0,01

0,012

0 5 10 15 20

pv injected

Sa

lin

ity

(N

a+

(g

/l))

Eclipse Results

experimental data

B2 waterflood with LSProducing first connate water (SW)

B7 waterflood with SWfollowed with LS water

Na+ 11 159 ppm (SW)

Na+ 1982 ppm (LS)

05

10

15

20

25

30

35

40

45

0 1 2 3 4 5 6 7

PV Injected

Dif

fere

nti

al

pre

ssu

re [

mb

ar]

0

10

20

30

40

50

60

70

0 1 2 3 4 5 6

PV Injected

Oil R

ecovery

[%

]

0

5

10

15

20

25

30

35

40

45

0 1 2 3 4 5 6

PV Injected

dP

[m

ba

r]B2 waterflood with LS

0

10

20

30

40

50

60

0 1 2 3 4 5 6 7

PV injected

Oil

Rec

ove

ry [

%]

B7 waterflood with SW

Less two-phase production with LS, (more water wet)but higher dp at endpoint saturation (more water wet (lower krw)

(or reduced permeability)

Fluids rock interactions

Mg2+ is strongly retained in the aged cores during the course of low salinity water injections.

Continuous elution of Ca2+ from the core samples is most likely due to the calcite dissolution.

0.00.51.01.52.0

2.53.03.54.04.55.05.56.0

6.57.07.58.0

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0Volume produced water phase [PV]

mc

um

/m0 f

or

Mg

2+a

nd

Ca

2+

B1 Mg2+B1 Ca2+B6 Mg2+B6 Ca2+

B1: core aged with crudeB6: core without aging with crude

Permeability reduction:

Change in wettability or release of fines?

Irregularities in pressure drop profiles could be associated with accumulation of fines in pore constrictions and/or clay swelling.

More pronounced turbidity in the effluent from the unaged core (B6) higher quantity of fine particles

100

150

200

250

300

350

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0Volume injected [PV]

DP

[m

bar]

B5B6

0

10

20

30

40

50

60

70

80

90

100

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5Volume produced water phase [PV]

Tra

nsm

itta

nce [%

]

B5B6

Not aged

aged

Capillary number relationship

Garnes, Mathisen, Scheie, Skauge, Capillary Number Relations for Some North Sea Reservoir Sandstones," SPE 20264, (1990)

LS and SW flood

LS-S without preflush

LS-S with LS preflush

Wettability alteration Alteration of wettability due to changes in salinity

Fines migration Detachment of clay particles from rock surface

Dissolution of minerals

Multicomponent ionic exchange (MIE) Destabilization of bonding between clay surface

and polar components in crude

Low Salinity Waterfloodpossible mechanisms

Wettability alteration (possible) Alteration of wettability due to changes in salinity

Fines migration (possible) Detachment of clay particles from rock surface

Dissolution of minerals (yes, Ca2+ generated)

Multicomponent ionic exchange (MIE) (??) Destabilization of bonding between clay surface and

polar components in crude

Low Salinity Waterfloodmost likely mechanisms

Observations

Network model approach

Wettability alteration coupled to salinity

Fines migration (blocking and diversion)

Simulation continuum scale

Inverse method history match of waterfloods (SW or LS)

- Generate kr and Pc

UTCHEM low salinity model

ECLIPSE low salinity model

tune on relperm after change in salinity

UTCHEM surfactant

ECLIPSE surfactant

Multiscale modelling of low salinity and surfactant

Network approach

Wettability change (analogue to relperm

shift) gives a fair match, but .

so does fines migration (blocking and

diversion) with reduction in absolute

permeability without change in water

relperm

010

20

30

40

50

60

0 1 2 3 4 5 6 7

PV injected

Oil R

ecovery

[%

]

Experimental data

history match

0

5

10

15

20

25

30

35

40

45

0 1 2 3 4 5 6 7

PV Injected

Dif

fere

ntia

l pre

ssur

e [m

bar]

Experimental Data

history match

B7 waterflood with SW

History match using Sendra

00,1

0,2

0,3

0,4

0,5

0,6

0,7

0,8

0,9

1

0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8

Water saturation

Rel

ativ

e p

erm

eab

ility

OIL

WATER

OIL

WATER

0,0001

0,001

0,01

0,1

1

0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8

Water saturation

Rel

ativ

e p

erm

eab

ility

OIL

WATER

OIL

WATER

-0,6

-0,4

-0,2

0

0,2

0,4

0,6

0,8

1

1,2

1,4

1,6

0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8

Water Saturation

Pc

[Psi

a]

B7 waterflood with SW

Derived relperm and Pc

Simulation Approach:UTCHEM Wettability Alteration Model

Two set of

Relative permeability curves

Capillary pressure curves

Interpolation originalfinalactual 1

injectedinitial

gridblockinitial

CC

CC

55

55

UTCHEM simulations: SW flood LS flood

0

10

20

30

40

50

60

70

0 2 4 6 8 10 12 14 16 18PV Injected

Oil

Rec

ove

ry [

% ]

Experimental data

Included wettability alteration

Best Fit

1st step:

SSW flood

2nd Step:

LS flood

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Water saturation

Rel

ativ

e P

erm

eab

ility OIL

WATER

LS floodSSW

flood

B7

Simulation Approach: Eclipse

Get estimate of the initial set of relative permeabilities and capillary pressures by use of Sendra

Brine Tracking option

Salinity can modify brine properties

Low Salinity option

Simulation Approach:Eclipse Low Salinity option

Two sets of relative permeability and capillary pressure curves

F1 and F2 is weighting factor

HriLriri kFkFk 11 1

HcijL

cijcij PFPFP 22 1

Eclipse Simulations: SW flood LS flood

0

2

4

6

8

10

12

0 5 10 15 20 25 30 35 40 45 50 55 60 65Time [hour]

Dif

fere

nti

al P

ress

ure

[m

bar

]

Experimental Data

Eclipse Best Fit

SSW Flood LS Flood

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Water Saturation

Rel

ativ

e P

erm

eab

ility

OIL

WATER SSW

flood

LS

flood

-10

0

10

20

30

40

50

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Water saturation

Cap

illar

y P

ress

ure

[m

bar

]

SSW

flood

LS

flood

0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 35 40 45 50 55 60 65Time [hour]

Dif

fere

nti

al P

ress

ure

[m

bar

]

Experimental Data

Eclipse Best Fit

SSW Flood LS Flood

0

2

4

6

8

10

12

0 5 10 15 20 25 30 35 40 45 50 55 60 65Time [hour]

Oil

Rec

ove

ry [

mL]

Experimental Data

Eclipse Best Fit

SSW Flood LS Flood

High Salinity Connate WaterLow Salinity Brine Injection

Two set relative permeability and

capillary pressure curves

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Water Saturation

Rel

ativ

e P

erm

eab

ility

OIL

WATER

Assumed for

high salinty

connate water

LS flood

Best Fit Eclipse

simulation

-40

-30

-20

-10

0

10

20

30

40

50

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8Water Saturation

Ca

pill

ary

Pre

ssu

re [

mb

ar]

Assumed for

high salinty

connate water

LS flood Best

Fit Eclipse

simulation

High Salinity Waterflood followed by Low Salinity Brine Injection

Two set relative permeability and

capillary pressure curves

0

2

4

6

8

10

12

0 2 4 6 8 10 12 14 16 18 20

Time [hours]

Oil

Rec

ove

ry [

mL]

Experimental data Test 1 Test 2

0

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0.04

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Weighing Factor F

Salt

Co

nse

ntr

atio

n [

g/cc

]

Test 2 Test 1

LSHS

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20

Time [hours]

Dif

fere

nti

al P

ress

ure

[m

bar

]

Experimental data Test 1 Test 2

WBT

Strong sensitivity to the weighing factor

Lookup

table

What if we only used one set of

relperm and Pc?

Eclipse Simulations: LS flood

One set relative permeability curves

0

2

4

6

8

10

12

0 2 4 6 8 10 12 14 16 18 20

Time [hours]

Oil

Rec

ove

ry [

mL]

Experimental data

Best Fit

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20Time [hours]

Dif

fere

nti

al P

ress

ure

[m

bar

]

Experimental data

Best Fit

WBT

Low Salinity Surfactant Flooding

Surfactants targets the residual oil by reducing IFT

Advantages in low salinity environment Combined effect (low salinity effects at low IFT)

May reduce re-trapping of mobilized oil

Reduced adsorption / retention

More low cost surfactants available

Surfactant: 1wt% surfactant, 1wt% isoamyl alcohol

Simulation Approach:UTCHEM Surfactant flooding

Type II(-) (water external microemulsion)

Surfactant properties

Surfactant adsorption

IFT

Microemulsion viscosity

Microemulsion phase behaviour

UTCHEM Simulations: LS flood LS surfactant flood

0

10

20

30

40

50

60

70

80

90

100

0 1 2 3 4 5 6 7 8 9 10 11 12 13PV injected

Oil

Rec

ove

ry [

%]

Experimental Data Best Fit LS-S flood on Core B2

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Water saturation

Rel

ativ

e p

erm

eab

ility OIL

WATER

Initial :

High Salinity

Connate Water

Wetting

Condition

Final:

Low Salinity

Water Wetting

Condition

1st step LS flood

2nd step LS-S flood

Conclusions 1

Wettability transitions (change in relative permeability and capillary pressure towards more water wet) are able to match oil recovery and differential pressure in core flood with salinity change

Warning: Non-unique match so no mechanisms is thereby confirmed

Increased differential pressure and sometimes gradually increasing towards the end of the low salinity flood may be due to lowering of absolute permeability (fines migration?)

Use of only one set of relative permeability with change in Sor can give a fair history match, and including absolute permeability reduction improves the match further

Underlying mechanisms for the low salinity process is likely more complex than only wettability alteration model

Conclusions 2

More experimental information is needed to distinguish between possible low salinity mechanisms

Surfactant flooding at low salinity show better results than expected from the capillary number relationship

Injection of surfactant in combination with low salinity brine has been proved to be a very effective oil recovery method

Thank you for your attention

Acknowledgement

to the PETROMAKS program

at the Norwegian Research Council