Surfactant/Polymer Flood of
Midland Farms Dolomite Core D6
Gary Pope
David Levitt
Adam Jackson
Jon Holder
The University of Texas at Austin
CPGE
Outline
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CPGE
Objective
Phase behavior formulation
Core flood design
Results
Conclusions
Objectives
• Achieve initial oil saturation and residual
oil saturation to water similar to MF
reservoir values and at similar pressure
gradients
• Recover 90% of waterflood residual oil
with surfactant and polymer
• Achieve low surfactant retention
CPGE
Phase Behavior and Surfactant
Formulation
Criteria:
• Low viscosity
• Low interfacial tension
• High solubilization ratio
• Short equilibration time
[Photo]
0.75% N67-7PO, 0.25% IOS C1518, 2% SBA
(WOR 1:1) with MF3 at 38C after 6 days
Scan from 2 - 6%
Equilibration time ~ 12 (days)
Solubilization, s* = 12 (cc/cc)
CPGE
Solubilization and Optimal
Salinity
DOE-201: 0.75% N67-7PO, 0.25% IOS-1518, 2% SBA, 0.01% Na2CO3 w/ M F3 @ 38C
Oil Sol. Ratio af ter 4 Days
Water Sol. Ratio af ter 4 Days
25.0
Solublization Ratio (cc/cc) .
Solubilization (cc/cc)
20.0
15.0
10.0
5.0
0.0
0.0
CPGE
0.5
1.0
1.5
Electrolyte concentration (w t%)
Na+
2.0
2.5
HPAM Polymer
• Hydrolyzed Polyacrylamide (HPAM)
• Flopaam 3330S from SNF Floeger
Viscosity vs Concentration of HPAM (Flopaam 3330S)
12
Salinity = 4% NaCl
Temperature = 38C
Viscosity (cp)
10
Shear Rate = 69.5 sec-1
8
6
4
2
0
0
CPGE
500
1000
1500
HPAM Concentration (ppm)
2000
2500
HPAM Polymer
Viscosity vs Shear Rate of HPAM (Flopaam 3330S)
Viscosity (cp)
100
Salinity = 4% NaCl
Temperature = 38C
1500 ppm Flopaam 3330S
10
1
0.01
CPGE
0.1
1
10
Shear Rate (sec-1)
100
1000
HPAM Polymer
Viscosity vs Salinity for HPAM (Flopaam 3330S)
40
35
1500 ppm Flopaam 3330S
Temperature = 38C
Shear Rate = 69.5 sec-1
Viscosity (cp)
30
25
20
15
10
5
0
0
CPGE
1
2
3
Salinity, wt% NaCl
4
5
Midland Farms Dolomite Core
Design and Configuration
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 = 0.18
kbrine= 166 md
kro = 0.40
krw = 0.03
Swi= 0.26
Sorw= 0.39
Formation Brine:
6.1% TDS
(8:1 NaCl:CaCl2)
CPGE
Core D-6 Configuration and tap/segment naming scheme
Well 629 D=4824ft
Segment 1
Well 629 D=4824ft
Segment 2
In
out
Inlet segment: 5 cm
Tap 1
Middle segment.: 19.2 cm
Outlet segment: 5 cm
Tap 2
Flow direction
All flooding was performed in a gravity stable manner
Injected Fluids
Pore Volumes
CPGE
Mixture
0.8
0.75% N67[7PO], 0.25% IOS C1518, 2% SBA
0.02% Na2CO3, 4.45% NaCl
1500 ppm Flopaam 3330S
0.2
2% SBA
3.05% NaCl
1500 ppm Flopaam 3330S
1.5
1.93% NaCl
1200 ppm Flopaam 3330S
Oil Flood Pressures
CPGE
Water Flood Pressures
CPGE
Sulfate Detected in Produced
Formation Brine
Effluent Sample
1
Sulfate
Concentration (ppm)
1268
2
1686
3
2094
4
2615
Samples taken from tubes preceding oil breakthrough
CPGE
Oil Recovery Results
Cumulative Oil Recovery and Fractional Flow of Oil for D-6
Free Oil = 90% Oil from Emulsion = 5%
100%
0.45
% Oil Recovered
80%
0.40
70%
0.35
60%
0.30
50%
0.25
40%
0.20
30%
0.15
20%
0.10
10%
0.05
0%
0.00
CPGE
surf actant breakthrough
0.20
0.40
0.60
0.80
1.00
1.20
Pore Volumes
1.40
1.60
1.80
0.00
2.00
Oil Cut
90%
0.50
% Rec, D-6
fo
Surfactant Recovery Results
Surfactant Retention: 0.43 mg/g
Flood D-6 Surfactant Recovery: Cumulative and
Concentration
0.8 PV slug of 0.75% APS 16-17 [7PO], 0.25% IOS C15- 18, 2% SBA,
1500ppm Flopaam 3330S, Te mpe rature = 38 C
100%
C umulative Recovery
Surfactant C oncentration
18000
80%
16000
70%
14000
60%
12000
50%
10000
40%
8000
30%
6000
20%
4000
10%
2000
0%
0.0
CPGE
0
0.5
1.0
1.5
Pore Volume s
2.0
2.5
3.0
Surfactant Concentration
[ppm]
Percent Surfactant Recovered
90%
20000
Surfactant/Polymer Pressure Results
Pressure vs Pore Volumes of Surfactant and Polymer Flood
Oil Break Through
Polymer/SBA Drive Started
Polymer Drive 1 Started
Polymer Drive 2 Started
Surfactant Break Through
30
25
Channel 1
Channel 2
Channel 3
Channel 4
Channel 5
Channel 6
Pressure [psi]
20
15
10
5
0
0.0
CPGE
0.2
0.4
0.6
0.8
1.0
1.2
Pore Volume s
1.4
1.6
1.8
2.0
Out
Mid
In
Mid
Out
Whole
Post-flood Polymer Assessment
Polymer Resistance Factor (Rf):
Rf = (DPp/DPw)q, Sw = 23/0.3 = 87
Polymer Permeability Reduction Factor (Rk):
Rk = Rf / (mp/mw) = 87/(5.5/0.911) = 14.5
Previous core flood indicated:
Rk = 2
(Prior HPAM used 2000 ppm Alcomer 60RD)
CPGE
Conclusions
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CPGE
Cumulative oil recovery of 95%
Sorc = 0.01
High oil recovery in a dolomite without sodium carbonate
50% of the surfactant was recovered
No plugging occurred
Anhydrite is present in core
Sodium carbonate can not be used
Polymer concentration may be reduced