Transcript Jose

Consortium on Process in porous Media
Foam experiments at high temperature
And high salinity
José López
Maura Puerto
Clarence Miller
George Hirasaki
03/14/2011
1
Outline:
•Oil properties and oil preparation:
IFT
Viscosity of simulated live crude oil
•Salinity issues in the system:
Analysis of synthetic bines
•Foam experiments:
 Surfactants used
 Apparatus description
 Mapping corefloods
 Foam results
 Foam with crude oil
2
Part I
OIL PROPERTIES AND OIL
PREPARATION
Crude oil needs to be free of contaminants and should simulate live oil
3
IFT measurements to screen contaminated samples
Dead crude oils IFT at 25°C
SGB(25°C/25°C)=1.0353 ( 5 % NaCl)
50
IFT (dyne/cm)
40
Crude 1
Crude 2
Crude 3
Crude 4
30
20
Oil-Brine
IFT range *
10
0
0
100
200
300
400
500
Time (min)
The crude oils must be free of surface active materials such as emulsion
breaker, scale inhibitor, or rust inhibitor. A simple test to verify
contamination of the oil samples is to measure the interfacial tension
(IFT) of crude oil with synthetic brine **
* John R. Fanchi Principles of Applied Reservoir Simulation 3 rd edition 2006 Elsevier
** G. Hirasaki and D.L. Zhang, "Surface Chemistry of Oil Recovery from Fractured, Oil-Wet, Carbonate
Formations," SPEJ (June 2004) 151-162.
1.65 mm
Vdrop=0.0608 cm3
4
Simulated live crude oil
Iso-octane was used for making a simulated live oil, i.e., with the same viscosity at
reservoir temperature, as suggested by Nelson (1983).
However, adding isooctane to the dead crude oil produced precipitation of asphaltenes.
Ratios of crude oil:isooctane ranging from 4:1 to 9:1 at room temperature show
immediate precipitation of asphaltenes.
Cyclohexane was mixed at room temperature with minimal precipitation of asphaltenes.
Then this solvent was used to modify the viscosity of the dead crude oil to obtain
simulated live crude oil with the same viscosity of the live crude oil.
Dead crude oil
Live crude oil
Adapted from Core Laboratories, Inc
Page 10 of 15, File: RFL 81350 (Dallas, TX)
5
Viscosity of mixtures of dead crude oil and Cyclohexane
measured in the falling sphere viscometer at 113.9 °C
IRS
Dead crude Oil
 = 2.8 cP
Cyclohexane
The mol fraction of (Crude 1) dead crude oil to match the viscosity of live crude oil is
0.59. This experiment was conducted in a sealed falling sphere viscometer. The mol
fraction was calculated using a molecular weight for the crude oil of 303 kg/kg-mol
ln   x 1 ln  1  x 2 ln  2  x 1 x 2  A  B ( x 1  x 2 ) 
A=2.614,B= - 0.89
Lopez et al Viscometer for Opaque, Sealed Microemulsion Samples, SPE 121575 (2009)
IRS : inductive ring sensors
Every experimental point is the
Average of 20 measurements
Precision error less than 3%
6
Results of the simulated live crude oil
Dead crude oil mass percentage 83.7%, the rest is cyclohexane.
Viscosities at 114 °C
Oil
Molar mass
(g/mol)
Viscosity
(cP)
Pressure
(Psia)
Rice Simulated live
crude oil
212.7
2.8
14.7
170.2
2.0
14.7
Live crude oil
176.3
2.8
3514.7
Dead crude oil
303 (*)
8.3
14.7
(16.3% Cyclohexane)
Simulated 2 LCO
(30% Cyclohexane)
Cyclohexane 16.3% mass = 18.7% volume = 41.25% mol
(*) Via Benzene point depression (Core Labs)
7
Remarks of part I
Crude oils are free of surface active materials such as emulsion
breaker, scale inhibitor, or rust inhibitor.
Dead crude oil was mixed with cyclohexane to match viscosity
of the live crude oil.
8
Part II
SALINITY OF BRINES USED IN THE
EXPERIMENT
Brines should be under saturated in order to prevent precipitation
9
Incremental solubility of CaSO4 (ScaleChem)*
For synthetic formation brine
3.50
3.00
Incremental solubility (g/kgw )
2.50
Sea Water SChem
2.00
FB
1.50
1.00
0.50
0.00
0
-0.50
50
100
150
Temperature (°C)
-1.00
Temperature
of experiments
94°C
•The sea water has an equivalent of 1.6147 g of CaS04 per kilogram of water (*)
•The formation brine has an equivalent of 0.718 g of CaSO4 per kilogram of water (*)
•Incremental solubility is the additional CaSO4 needed to saturate the brine
10
Part III
FOAM EXPERIMENTS
11
Experimental set up
N2
Relief
valve
Surfactant
pump
Porous media
holder
Second
section
First
section
Gas flow
controller
P
E
Pressure
transducer
P
P
E
E
N2
P
E
Heat in
Oven
Thermocouple
T
Heat out
12
SURFACTANTS
Triton X-200, Alkyl Aryl poly (ethylenoxy) sulfonate
C9H19
(-O-C2H4)8.6-SO3- Na+
Hydrophilic surfactant
C20-24 IOS, Internal Olefine sulfonate
Hydroxyalkane Sulfonates +
SO3-Na
│
R-CH2-CH2- CH –CH -CH2-CH2-R’
│
OH
CH3(CH2)n(CH2)2CH(SO3Na)CH(OH)(CH2)2(CH2)mCH3
CH3
|
+
Alkene Sulfonates
SO3-Na
│
R-CH2 – CH-CH= CH-CH2-R’
n+m=14
Lipophilic surfactant
CH3
|
H3C— C —CH2 — C —
|
|
CH3
CH3
Triton X-100
— (OCH2CH2) 9.5 OH
Octylphenol ethylene oxide condensate
13
Initial foam experiments
Objective: Understand how foam performs with and without oil
Using surfactant blends with aid of mapping corefloods concept
14
ExpNo.
Crude Oil
Surfactant
Solution
Brine
Triton to IOS
ratio
SW
100-0
Injection rate
of liquid
(ft/day)
Foam injection
(L/G) ratio
2 PV of foam
1
No
27-7
Variable
Gas
2
Yes
SW
70-30
20
3.25 PV of aqueous
surfactant
2.85
Foam
¼ PV of aqueous surfactant
3
Yes
FB
60-40
20
1.33
Foam
5 (*)
Yes
FB
90-10
3-17
¼ PV of aqueous
surfactant
Foam
0.74
¼ PV of aqueous surfactant
6
Yes
FB-SW
50-50
70-30
3
Foam
0.83
Gas-Brine
3/4 PV of aqueous
surfactant
7
Yes
SW
50-50
6-12
Foam
1.13
15
Stronger foam
100
80
40
30
20
10
0
100 1
0
90
80
Desirable
•Surfactant propagation
• Foam formation
6
20
30
7
High oil recovery
Low oil
recovery
50
60
30
Type II
70
20
Undesirable
80
10
90
0
100
0
10
20
30
40
50
60
70
Formation Brine →
80
90
→
40
C 20-24 IOS
3 40
60
50
5 10
Type I
70 2
Triton X 200 →
90
← Sea Water
70
60 50
100
16
Oil recovery comparison
100
% Residual Oil recovery
90
80
70
60
50
Exp 6
40
FB-SW
SW
SW
SW
FB
FB
Exp 7
30
Exp 2
20
Exp 5
10
Exp 3
0
0
1
2
3
4
5
6
7
8
9
Pore volumes of aqueous phase produced
10
17
Remarks from previous foam experiments
•Stronger foam was generated when Triton
X-200 to IOS ratio was higher
•Stronger foam was generated at lower
salinity
•Higher oil recoveries were obtained when
injection composition was in the Type I
region and far from injecting at formation
brine .
•Foam is weaker when crude oil is present
•Phase behavior map (surfactant blend –
brine blend) can be used to plan core flood
experiments
18
New foam experiments
Objective: Understand how foam performs with new formulations
19
SURFACTANTS for Rice Formulation
Avanel S70
C12-15H25-31 (-O-C2H4)7-SO3- Na+
Hydrophilic surfactant
C20-24 IOS, Internal Olefine sulfonate
Hydroxyalkane Sulfonates +
SO3-Na
│
R-CH2-CH2- CH –CH -CH2-CH2-R’
│
OH
CH3(CH2)n(CH2)2CH(SO3Na)CH(OH)(CH2)2(CH2)mCH3
+
Alkene Sulfonates
SO3-Na
│
R-CH2 – CH-CH= CH-CH2-R’
n+m=14
Lipophilic surfactant
20
90°C
Avanel S70
100
100
90
80
70
Sea Water
60
50 40
IOS 0342
30
20
10
0
0
90
10
80
20
Bø
Bø
70
30
Dilution path
60
40
50
50
Type II
40
60
30
70
20
80
10
90
0
100
0
10
20
30
40
50
60
70
80
90
100
Formation Brine
21
New Rice Blend
Surfactant at 1% in sea water: Avanel S70 / C20-24 IOS (60/40)
Inlet →
←First Section
←Second section
Second
section
25
70
First
section
Pressure Gradient (Psi/ft)
20
60
55
15
50
10
45
40
5
Inlet gage pressure (Psi)
65
35
0
30
0
0.5
1
1.5
2
2.5
3
3.5
4
4.5
5
Liquid injected PV
Foam was generated at selected test conditions in both zones, 94°C
22
Foam Experiment (Effect of liquid flow )
100
1000
G/L=20
G/L=5
G/L= 10
10
G=5 sccm
1
0
0.5
Liquid flow rate
1
cm3/min
1.5
Apparent viscosity (cP)
Pressure gradient psi/ft
Surfactant Avanel S70 C20-24 IOS (60:40) at 1% mass in sea water using gas N2
G/L= 10
G/L=5
G/L=20
G=5 sccm
100
10
0
0.5
1
1.5
Liquid flow rate cm3/min
The first and the second sections were able to produce strong foam, the exception was for a
flowrate of 0.25 cm3/min of liquid, producing only foam in the first section of the sand pack.
Gas flow rate is reported in sccm.
Liquid superficial velocities were in the range from 2.8 to 11.5 ft/day
23
Foam Experiment (Effect of gas flow )
Surfactant Avanel S70- C20-24 IOS (60:40) at 1% mass in sea water using gas N2
1000
30
25
G/L=5
20
L=1
15
10
G/L=2.5
5
0
0
5
10
G/L=5
G/L=20
G/L=10
15
Gas flow rate cm3/min
20
25
Viscosity (cP)
Pressure gradient psi/ft
35
G/L=10
G/L=20
G/L=2.5
L=1
100
10
0
5
10
15
20
25
Gas flow rate cm3/min
The first and the second sections were able to produce strong foam, the
exception was for a flowrate of 0.25 cm3/min of liquid, producing only foam
in the first section of the sand pack.
24
Case: Cutting the liquid flow rate (verification of importance of liquid rate)
70
60
10
50
8
40
6
30
First section
4
2
Second section
20
Inlet gage pressure
10
Inlet gage pressure (psi)
Pressure drop (psi) in a 6 in section
12
Second
section
First
section
0
0
250
270
290
310
330
350
370
390
time (min)
1
Gas flowrate
(sccm)
5
0.8
4
Gas
phase
Aqueous
phase
0.6
3
2
0.4
0.2
1
0
Liquid flow rate
cm3/min
6
0
250
270
290
310
330
350
370
390
Time (min)
1 Liquid PV = 116 min @ 0.5 cm3/min
25
Effluent of the foam generated with the New Rice Blend.
26
Remarks from new foam experiments
•New Rice Blend produced strong foam at
1% mass in sea water through silica sand.
27
Acknowledgements
Consortium on Process in porous Media
PEMEX
Roberto Rocca Fundation
ITESM
28
End
29
Backup slides
30
Conditions Experiment 7
•
•
•
•
Initial residual oil (20%)
Absolute permeability 132.7 darcy
KW,RO=35.0 darcy (rel perm 0.24)
KO,IW=86.73 darcy (rel perm 0.65)
31
Experiment 6
Oil Recovery Exp 6
0
C 20-24 IOS →
Triton X 200 →
100
100
0
0
Formation Brine →
32
100
Experiment 6
100
90
Injection of surfactant
↙
0.5 cm3/ min
70
Coinjection of N2
(1.5 scm3/min)
and surfactant mixture
↙
(0.5 cm3/min)
50
0
100
Triton X 200 →
60
40
30
C 20-24 IOS →
% Residual Oil recovery
80
100
0
0
20
Formation Brine →
Surfactant
↙ Breakthrough
before this point
10
0
0
0.5
1
1.5
2
2.5
Pore volumes of aqueous phase produced
3
3.5
33
100
Experiment 6
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0
1
0.8
N2 (sccm)
0.6
aqueous cm3/min
0.4
Conc %
cm3/min, sccm
flow of components in the injection
0.2
Surf Conc %
0
0
5
10
15
20
25
30
Pore volumes of liquid produced
4.5
Pressure gradient psi/ft
4
3.5
3
2.5
2
Upper taps
1.5
Lower taps
1
0.5
0
0
5
10
15
20
Pore volumes of liquid produced
25
30
34
Experiment 6
flow of components in the injection
1
0.8
N2 (sccm)
0.6
aqueous cm3/min
0.4
Conc %
cm3/min, sccm
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0
0.2
Surf Conc %
0
0
5
10
15
20
25
30
4.5
180
4
160
3.5
140
3
120
2.5
100
Upper taps
2
80
Lower taps
1.5
60
1
40
0.5
20
0
0
0
Triton X 200 →
0
100
C 20-24 IOS →
100
0
0
Formation Brine →
100
Apparent viscosity (cP)
Pressure gradient psi/ft
Pore volumes of liquid produced
5
10
15
20
Pore volumes of liquid produced
25
30
35
Injection
Volume quality
G real
cm3/min
1.180
1.520
2.469
2.469
3.292
4.390
2.469
1.317
0.988
G
sccm
5
5
5
10
15
20
10
5
2.5
L
cm3/min
1
0.5
dP/dz
psi/ft
23
18
G/(G+L)
0.541312
0.752426
P gage
psi
69
65
0.25
0.5
0.75
1
dP/dz
3
26
30
28
0.908066
0.831612
0.814469
0.814469
40
80
90
90
1
1
1
dP/dz
24
20
12
0.711761
0.568404
0.496915
80
75
50
36
Synthetic Lab Brine
SI
pH=6.65, Alk=3.66 mg/dm3 as HCO32
1.5
1
0.5
0
-0.5
-1
-1.5
-2
CaCO3
CaSO4
MgCO3
NaCl
25
85
100
104
110
120
T (ºC)
P > 2 atm
37