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Laboratory Investigations for CO2 Based EOR
George J. Hirasaki
Dept. of Chemical and Biomolecular Engineering Rice University
CO2 for EOR as CCUS November 19-21, 2013
Challenges Facing CO2 EOR
• Availability of CO2
• Minimum miscibility pressure (MMP) • Asphaltene deposition • Mobility control
– Low viscosity of CO2, viscous fingering
– WAG
– Gravity segregation – Heterogeneities – Foam mobility control
• Adsorption
Viscosity of CO2 and Reservoir Fluids
0.01
0.1
1
10
CO2 @ CP Brine 40 API Oil 30 API Oil
Vis
cosi
ty,
cp
Displacement Fronts for Different Mobility Ratios and Injected Pore Volumes
Habermann, B., 1960
Gravity Segregation with WAG
Stone, H.L., 1982
What is the effect of geological heterogeneity on EOR?
Layered sandpack model with 20:1 permeability Contrast
Li, et al, SPEJ, 2010
WAG fg =2/3
1.0 TPV
0.0 TPV
2.0 TPV
3.0 TPV
4.0 TPV
5.0 TPV
6.0 TPV
fg =0 water only
7
Waterflood and WAG Waterflood or WAG, 4 psi; Sweep is only a function of liquid injected
WAG fg =2/3
1.0 TPV
0.0 TPV
2.0 TPV
3.0 TPV
4.0 TPV
5.0 TPV
6.0 TPV
fg =0 water only
8
Waterflood and WAG Waterflood or WAG, 4 psi; Sweep is only a function of liquid injected
Layered sandpack with 19:1 permeability contrast about half-swept with water only but about completely swept with surfactant-
alternated-gas (SAG)
0.0 TPV
0.2 TPV
0.4 TPV
0.6 TPV
0.8 TPV
1.0 TPV
SAG, 6 psi, fg=1/3 Water only, 4 psi
Li, et al, SPEJ, 2010
Layered sandpack with 19:1 permeability contrast about half-swept with water only but about completely swept with surfactant-
alternated-gas (SAG)
0.0 TPV
0.2 TPV
0.4 TPV
0.6 TPV
0.8 TPV
1.0 TPV
SAG, 6 psi, fg=1/3 Water only, 4 psi
Li, et al, SPEJ, 2010
Fracture
Small pore network
Micro-fractures or vuggy rock
ΔP
Impermeable rock
How does foam displace oil from heterogeneous, oil-wet, fractured system?
Inj.
Pre-flood drain
Prod.
Camera view 1 mm 50 μm depth
oil-wet
1 mm
20 μm pore
throats
100μm pore
throats
-370μm
Charles Conn, 2013
Air & Water no surfactant
https://drive.google.com/file/d/0BwZmYz9LHrmoSHFZc1Y2ZkF3QzA/edit?usp=sharing
Water 0.05 mL/hr, Air 150 mbar
CONTROL
Pre-flood (pink = paraffin oil)
Post-flood (thick dark lamellae = air, thin lamellae = aqueous)
Air & Water no surfactant
CONTROL
1% AOS:LB, Seawater ionic strength (NaCl) AOS14-16 : LB
1 : 1 https://drive.google.com/file/d/0BwZmYz9LHrmoa1dwcVJDZDNHcEk/edit?usp=sharing
Surfactant 0.05 mL/hr, Air 150 mbar (good foamer)
BASE CASE
1% AOS:LB, Seawater ionic strength (NaCl) AOS14-16 : LB
1 : 1
Pre-flood (pink = paraffin oil)
Post-flood (thick dark lamellae = air, thin lamellae = aqueous)
BASE CASE
Diagram of the high temperature and high pressure core flooding setup
Pumps System
All wetting materials are Hastelloy Alloys, which can work under high P, T, salinity and low pH.
Leyu Cui, 2013
Apparent Viscosity of CO2 Co-Injected with Water or Non-Ionic Surfactant Solution in Dolomite Core
0
20
40
60
80
100
0 0.5 1 1.5 2 2.5 3
Ap
pa
ren
t V
isc
os
ity /
cp
total PV
L24-22
water
80% quality
Leyu Cui, 2012
Apparent Viscosity of WAG or SAG
0
20
40
60
80
100
0 1 2 3
Ap
pa
ren
t V
isc
os
ity /
cp
PV
L24-22waterSeries2Series3
Leyu Cui, 2012
Apparent Viscosity of CO2 Displacing Water or Non-Ionic Surfactant Solution in Dolomite Core
0
20
40
60
80
100
0 0.5 1 1.5 2 2.5 3
Ap
pa
ren
t V
isc
os
ity /
cp
total PV
water
L24-22
Leyu Cui, 2012
C12/Brine and CO2 Foam at 120 °C and 3400 psi
60% Foam Quality
0
10
20
30
40
50
0
20
40
60
80
100
0 1 2 3 4 5 6 7
Pre
ssu
re
Gra
die
nt
/ p
si/f
t
Ap
par
en
t vi
sco
sity
/cp
TPV
Co-injection
WAG
MPG µ*=84.47 cp
0
10
20
30
40
50
0
20
40
60
80
100
0 1 2 3 4 5 6
pre
ssu
re
grad
ien
t/p
si/f
t
Ap
par
en
t V
isco
sity
/ c
p
TPV
co-injectionWAGMPG
50% Foam Quality
µ*=59.14 cp
Leyu Cui, 2013
Comparison of viscosity at 20 and 120 °C for C12/Brine and CO2 Foam
krw0=0.5; krg0=0.1768; S_wc=0.33; S_gr=0.2; nw=2.8; ng=1.1; (Bennion, 2008)
µw=0.2381 cp; µg=3.935×10-2 cp;
epdry=10000 Leyu Cui, 2013
Transport of surfactant is limited by adsorption on rock
• Adsorption of anionic surfactant is generally lower on sandstone compared to carbonate
• Adsorption on nonionic surfactant is generally lower on carbonate compared to sandstone
• Nonionic surfactant has cloud-point limitation at higher temperature
• Cationic or nonionic/cationic surfactant has potential for carbonate formation at high temperature
Surfactant Adsorption is Dependent on Surfactant/Mineral Interaction
Conclusions
• CO2 EOR can be improved by foam mobility control to improve reservoir sweep
• Foam improves sweep in layered systems
• Surfactant must be matched with reservoir parameters to limit surfactant adsorption
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