Simulation of combined low salinity and surfactant injection
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Transcript of Simulation of combined low salinity and surfactant injection
-
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
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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
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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