Wettability Alteration and Foam
Mobility Control in a Layered 2-D
Heterogeneous System
SPE 141462
Presented
2011 Rice Consortium on Processes in Porous Media
2011 International Symposium on Oilfield Chemistry
Robert F. Li, George J. Hirasaki, and Clarence A. Miller, SPE, Rice University;
and Shehadeh, K. Masalmeh, SPE, Shell Technology Oman
April 2011
Outline
• Introduction
• Wettability Alteration and Gravity Drainage
in a Layered Heterogeneous 2-D System
• Foam Stability in Presence of Crude Oil
• Foam Mobility Control in a Layered
Heterogeneous System
• Conclusions
Introduction
Focus/Problem to Be Solved
• Heterogeneity – 19:1 Permeability Contrast
• Injected Water Bypass
• Rock Wettability – Oil-Wet
• High Remaining Oil Saturation
in the Tight Layer
Solutions
• Wettability Alteration
• Foam Mobility Control
Wettability Alteration and Gravity Drainage
in an Oil-Wet 2-D System
Silica Surface Treatment with CTAB
½ CMC CTAB (hexadecyltrimethylammonium bromide) was used for wettability alteration
Contact Angle Measurement
Zeta Potential
Silica
Flour
Zeta
Potential
(mV)
Untreated
-53.9±1.5
CTABTreated
29.2±3.1
Conductivity 2.37~2.46 mS/cm,
1% wt solid in 0.02 mol/L NaCl.
Wettability Alteration and Gravity Drainage
in a CTAB-Treated Oil-Wet 2-D System
Waterflood, 2% NaCl, 5 ft/D (~0.1 psi), Cumulative Recovery: 49.1% original oil-in-place (OOIP)
4.0 PV (Pore Volume)
Most oil in the lower layer was retained by capillary pressure (oil-wet)
Alkaline/Surfactant flood, 0.2% NI, 2% NaCl, 1% Na2CO3, 1ft/D
0.5 PV
NI is a blend of 4:1 (wt/wt) Neodol 67-7PO blending with internal olefin sulfonate IOS 15-18
Shut in at 0.5 PV
Gravity and Capillary Pressure Driven Counter-Current Flow
Dimensionless Time for Gravity Drainage
Richardson, J.G. et al., JPT 1971;
Trans., AIME, 251.
tDg
tD,Pc
Real
Real
Day 0
0
0
Day 3
53
0.5
Day 6
107
1.0
Day 10
178
1.6
Day 42
748
6.7
Dimensionless Time for Capillary Pressure
Ma, S., et al., J. Pet. Sci. & Eng.
18 (1997) 165-178.
Recovery as a Function of Dimensionless Times
Normalized Recovery
Recovery vs. Dimensionless Time of Gravity Drainage
1
0.8
Analytical Solution
Experiment
0.6
0.4
0.2
0
0.001
0.01
0.1
1
10
100
1000
Dimensionless Time, tDg
Recovery vs. Dimensionless Time of Capillary Pressure
1
Recovery
0.8
0.6
Experiment
Aronofsky model, VSWW
0.4
0.2
0
0.001
0.01
0.1
1
10
Dimensionless Time, tD,Pc
100
1000
Aronofsky, J.S..et al.,
Trans. AIME 213,1958
Foamflood
0 TPV
0.2 TPV, IOS 15-18
0.7 TPV, IOS 15-18
1.0 TPV, Air
History of Oil Recovery
cumulative recovery
waterflood
NI
0.9
foamflood
Shut-in for 42 days after NI
Recovery Efficiency
1
oil cut
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0
1
2
3
4
5
Total PV's of Fluid Injection
6
7
8
Foam Stability in the Presence of Crude Oil
Adding Lauryl Betaine as a Foam Booster
NI, IOS15-18 in Foam Drive
142 darcy; constant pressure ~1.2 psi/ft; 1% Na2CO3, 2% NaCl; 0.2% NI no polymer; 0.5% IOS15-18 in foam drive
NI
Air
NI
0.1 0.2 0.3
Liquid PV 0.1
0.2
Total PV
Air
NI
Air
IOS Air IOS Air
IOS Air
IOS
Air
IOS Air
IOS
0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7
0.3
0.4
0.5
0.6
0.7
0.8
0.9
Qualitative Foam Stability Test with NIB-Blends
Without Oil
NI only
5:1 NI:B
With SME Crude, WOR=1
1:1 NI:B
1:2 NI:B
1:3 NI:B
NI only
5:1 NI:B
1:1 NI:B
1:2 NI:B
1:3 NI:B
All vials contain 0.5% Lauryl Betaine (except NI only),1% Na2CO3 and 3.5% NaCl
NIB (1:2 NI:B), and IB (10:1 IOS:B) in Foam Drive
193 darcy; 1% Na2CO3, 3.5% NaCl; 0.25% NI, 0.5% lauryl betaine; 0.5% IOS15-18 and 0.05% lauryl betaine in foam drive
NIB NIB Air NIB Air IB
Air IB
Air IB
Air IB
Air IB
Air IB
Air
TPV 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7
Liquid PV 0.1 0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
5ft/D SAG, fg=0.5, injection under constant pressure gradient ~1.4 psi/ft
Effluent
Cumulative Recovery and Apparent Viscosity
Cumulative Recovery
Cumulative Recovery of Residual Oil
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
1:2 NI:LB & 10:1 IOS15-18:LB
NI & IOS15-18
0
0.5
1
1.5
2
2.5
3
3.5
Apparent Viscosity (cp)
Total PV's
Apparent Viscosity
35
30
1:2 NI:B & 10:1 IOS15-18:B
NI & IOS15-18
25
20
15
10
5
0
0
0.5
1
1.5
2
Total PV's
2.5
3
3.5
NIB alone in Achieving Both Low IFT and Foam Mobility Control
Foam Apparent Viscosity in an Oilfree 1-D Sand Column
Apparent Viscosity (cp)
350
300
NIB
250
AOS16-18
NI
200
150
100
50
0
0
0.5
1
1.5
2
2.5
Total PV's
NIB and AOS was injected at 20 ft/D with fg=2/3;
Black curve with NI foam was injected at 0.5 psi/ft with fg=0.5.
3
3.5
4
NIB (1:2 NI:B) Only
174 darcy; 1% Na2CO3, 3.5% NaCl; 0.25% NI, 0.5% lauryl betaine
NIB NIB Air NIB Air NIB Air NIB Air NIB Air
Trapping Number
[1]
0-0.2 TPV, low-rate NIB,
Gravity Number
/
>3
[2]
0-0.2 TPV, low-rate NIB, Ng= 7.0 >>1
0.3 TPV, high-rate Air,
Ng= 0.09 <<1
0.4 TPV, high-rate NIB, Ng= 0.10 <<1
TPV 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1
Liquid PV 0.1
0.3
0.4
0.5
0.6
5ft/D SAG, fg=0.5, constant pressure gradient ~1.4 psi/ft
Effluent
[1] Pope, G.A., et al., SPE Reservoir Eval. and Eng. 2000 3(2) 171-178
[2] Hirasaki, G. J., SPEJ , 1975, 39-50
Cumulative Recovery:
97% from Residual Oil
NIB (1:2 NI:B) Only in Secondary Recovery
164 darcy; 1% Na2CO3, 3.5% NaCl; 0.25% NI, 0.5% lauryl betaine
NIB NIB Air NIB Air NIB Air NIB Air NIB Air NIB Air NIB
…
TPV 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4
Liquid PV 0.1
0.3
0.4
0.5
0.6
0.7
0.8
5ft/D
SAG, fg=0.5, constant pressure gradient ~2.8 psi/ft
Effluent
Cumulative Recovery 99.6% of Residual Oil
1.8
1.0
AOS16-18 Only in Secondary Recovery
156 darcy; 1% Na2CO3, 2% NaCl; 0.5% AOS16-18 (alpha olefin sulfonate)
0 PV
0.7 PV
1.4 PV
0.3 PV
1.0 PV
1.7 PV
1.9 PV
0.6 PV
1.3 PV
• Early gas break-through leading to poor sweep
• Cumulative Recovery 69% OOIP – worse than waterflood
Foam in Presence of SME Oil in the Micro Model
NI without Betaine
NI with Betaine
Weak Foam Mobility M  k / μ
• Continuous gas channels – increased
gas relative permeability
• No lamellae – reduced apparent
viscosity
Strong Foam Mobility M  k / μ
• Trapped gas bubbles – reduced gas
relative permeability
• Lamellae and bubble trains – increased
apparent viscosity
• Possible pseudo-emulsion films –
keeping oil drops from entering gas/water
surface
Foam Mobility Control
in a Layered Oil-Wet System
Foam Mobility Control in an Oil-Wet Layered System
34:1 permeability ratio between upper and lower layers
CTAB-Treated, Oil-Wet, waterflood
Untreated, Water-Wet, waterflood
0 PV
0.1 PV
0.2 PV
0.3 PV
0.4 PV
0.5 PV
1.0 PV
• In the oil-wet sandpack, capillary pressure retained most oil in the lower tight layer.
• In the water-wet sandpack, spontaneous imbibition displaced most oil from lower layer.
Foam EOR in a Layered Oil-Wet Heterogeneous System
Oil-Wet; Permeability Ratio 34:1
CTAB-Treated Oil-Wet Silica, NIB, SAG, fg=1/3
1% Na2CO3, 3.5% NaCl; 0.25% NI, 0.5% lauryl betaine
Waterflood remaining
condition
1.0 PV
2.0 PV
3.5 PV
• Remaining Sor_w= 61.5%
• Recovered by Foam: 88.7% of waterflood remaining oil
Conclusions
•
In an oil-wet 2-D heterogeneous sandpack with 19:1 permeability contrast,
waterflood recovered only 49.1% OOIP. After NI was injected gravity- and
capillary pressure-driven, vertical, counter-current flow occurred during a
42-day system shut-in. This and a subsequent foamflood recovered 89.4%
of the waterflood remaining oil. Overall recovery (waterflood+ASF) was
94.6% OOIP.
•
NI alone is not a good foaming agent. The addition of lauryl betaine made
NIB (NI:B=1:2) a strong foaming agent with and without SME crude oil,
and a good IFT reducing agent.
•
In an oil-wet, layered sandpack with 34:1 permeability contrast, NIB foam
was able to mobilize and recover remaining oil from the lower, lowpermeability layer.
Acknowledgment
• The financial support of Shell
International E&P B.V. is gratefully
acknowledged.
• Shell is also acknowledged for
donation of the 2-D sandpack and the
glass micro model.
Back-up Slides
2-D CTAB-Treated Silica Sandpack Oilflood
Arrows show locations of injection ports
0.1 PV
0.5PV
1.0PV
16.6PV
•Injection rate: 5 ft/D. Soi=62.4%
Movie…
Day 42
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
36
37
38
Movie of Foamflood…
0.0 TPV,
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
2.0
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
3.0
TPV Air
IOS
Effluent from Foamflood
0.1
IOS
0.2
IOS
0.3
Air
0.4
IOS
0.5
IOS
0.6
Air
0.7
IOS
0.8
IOS
0.9
Air
1.0 TPV
IOS
1.1
IOS
1.2
Air
1.3
IOS
1.4
IOS
1.5
Air
1.6
IOS
1.7
IOS
1.8
Air
1.9
IOS
2.0
IOS
TPV
2.1
Air
2.2
IOS
2.3
IOS
2.4
Air
2.5
IOS
2.6
IOS
2.7
Air
2.8
IOS
2.9
IOS
3.0
Air
TPV
Foam Apparent Viscosity
Low, because of oil breaking foam
Apparent Viscosity (cp)
4.5
4
IOS
3.5
IOS
3
2.5
2
1.5
1
Air
0.5
0
0
0.5
1
1.5
2
Total PV
2.5
3
3.5
Introduction of Foam Flow in Porous Media
Gas injected into 0.5% IOS15-18
1 mm
Viscosity with IOS15-18 and Lauryl Betaine Blends
in 1% Na2CO3 and 3.5% NaCl
7
7.5:1
6
6.7:1
Viscosity (cp)
5
10:1
4
IOS:betaine
15:1
3
2
5:1
IOS only
1
0
Cloudy
10:1 AOS:B was picked because it had highest viscosity as a clear single phase solution
NIB (1:2 NI:B) Only
Cumulative Recovery: 97% from Residual Oil
Fraction of Recovered SME
Cumulative Recovery from Residual
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0
1
2
Total PV's
3
4
NIB (1:2 NI:B) Only
Apparent Viscosity
Apparent Viscosity (cp)
60
50
40
30
20
10
0
0
0.2
0.4
0.6
0.8
Total PV's
1
1.2
1.4
1.6
NIB in a Secondary Recovery Process
NIB (1:2 NI:B) Only in Secondary Recovery
Cumulative Recovery 99.6% from Residual Oil
Cumulative Recovery and Oil-Cut
cumulative recovery from OOIP
oil cut
1
% Recovery from OOIP
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0
0.5
1
1.5
Total PV's
2
2.5
NIB (1:2 NI:B) Only in Secondary Recovery
Foam was not as strong as NIB in the tertiary recovery process due to higher initial oil saturation
Apparent Viscosity (cp)
Apparent Viscosity
9
8
7
6
5
4
3
2
1
0
0
0.5
1
1.5
Total PV's
2
2.5
3
CTAB-Treated Silica, NIB, SAG, fg=1/3
Injection Rate (ft/D)
Pressure Gradient
Pressure Gradient
(psi/ft)
3
2.5
2
1.5
1
0.5
0
0
1
2
3
Injection Rate
500
400
300
200
100
0
0
2
Cumulative Recovery from
Waterflood Remaining Oil
14
12
10
8
6
4
2
0
4
Total PV's
6
Fraction of Recovered SME
Apparent Viscosity (cp)
Apparent Viscosity
2
6
Total PV's
Total PV's
0
4
1
0.8
0.6
Remaining Sor_w= 61.5%
EOR: 88.7% of
waterflood remaining oil
0.4
0.2
0
0
1
2
3
Total PV's
4
5
Untreated Silica, NIB, SAG, fg=1/3
Overall 88 darcy; Permeability ratio 36:1; 1% Na2CO3, 3.5% NaCl; 0.25% NI, 0.5% lauryl betaine
0.1 PV
0.5 PV
1.0 PV
1.5 PV