Transcript Saif Al-Sayari

The influence of wettability and
carbon dioxide injection on
hydrocarbon recovery
Saif Al Sayari
Martin J. Blunt
Outline
• Objective
• The influence of wettability on
–
–
–
–
Electrical resistivity
NMR
Pc
Kr
• Pore scale modelling
• Efficacy of CO2 injection for hydrocarbon recovery
– Tertiary HC gas injection
– Tertiary WAG injection
– Tertiary CO2 Injection
Objectives
• Evaluate the influence of wettability
• Compare the results with numerical predictions using
pore-scale modelling where the pore space has been
imaged using micro-CT scanning.
• Assess CO2 injection in carbonate oil fields.
Conventional core analysis
• Sandpack
– Porosity ~ 34%
– Permeability ~ 35 Darcy
• Sandstone – Fontainebleau
– Porosity ~ 9 %
– Permeability ~ 140 mD
• Carbonate – Middle East
– Porosity ~ 28 %
– Permeability ~ 7 mD
MICP
• Mercury injection capillary pressure is employed:
• to describe the pore-size distribution
• to draw drainage capillary pressure that can be used to compare to other
methods such as the porous plate method .
120
Carbonate SN 4
Capillary pressure, Pc (psi)
Distribution Functions vs Log Pore Throat Size
1
0.9
Distribution Functions
0.8
0.7
0.6
0.5
80
40
0.4
0.3
0.2
0.1
0
0.001
0.01
0.1
1
Log Pore Throat Radius (Microns)
10
100
0
0.00
0.20
0.40
0.60
0.80
Water saturation, Sw (frac.)
1.00
Influence of wettability
Knowledge of the wettability of a reservoir rock and its
influence on petrophysical properties is a key factor for
determining oil recovery mechanisms and making
estimates of recovery efficiency.
We combine in one study the effects of wettability on
multiphase flow parameters, looking at capillary
pressure, relative permeability, electrical properties and
NMR.
Wettability Influence: Electrical Resistivity
1000
Carbonate SN 4 - 5
Resistivity index, RI
100
10
Water wet
Oil-wet
n (drainage)
2.33
2.67
Drainage (Oil-wet)
n (imb.)
2.39
2.72
Series2
n (forced imb.)
2.66
3.25
Imb. (Oil-wet)
Forced Imb. (Oil-wet)
Drainage (Water-wet)
Series2
Imb (Water-wet)
Forced Imb (Water-wet)
1
0.01
0.10
Water saturation, Sw (frac.)
1.00
Wettability Influence: Capillary Press.
120
Carbonate sample:
Pc (Oil-wet vs. Water wet)
Very similar samples
(Pore throat distribution)
Sample No. 4
Sample No. 5
40
1
0 .9
0 .8
0
0.00
0.20
0.40
0.60
0.80
1.00
0 .7
Distribution Functions
Capillary pressure, Pc (psi)
80
-40
0 .6
0 .5
0 .4
0 .3
-80
0 .2
0 .1
-120
0
0 .0 0 1
Water saturation, Sw (frac.)
0 .0 1
0 .1
1
10
Log Pore Throat Radius (Microns)
10 0
Wettability Influence: Relative Perm.
Steady-state relative permeability for carbonate sample at water-wet
condition. The sample is then aged in crude oil and elevated temperature
and the relative perm. will be conducted again
ISSM kro
ISSM krw
Inj.Face krw
Inj.Face kro
1
Carbonate SN 1
0.9
Relative permeability
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0.0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation, frac.
0.7
0.8
0.9
1.0
Laboratory – pore scale
Core
Rock Properties
Porosity
Permeability
Formation Factor
Capillary Pressure
Relative Permeability
NMR Response
Relative Permeability, SPE84550
Micro-CT
Network
Porosity
Permeability
Formation Factor
NMR Response
Porosity
Permeability
Formation Factor
Capillary Pressure
Relative Permeability
NMR Response
Capillary Pressure
Pore-scale modeling:
- Complementary to SCAL, for the determination of single and multiphase flow properties.
- Looking at trends where data is lacking, different rock types, wettability and three-phase flow
NMR – Results Sandpacks
Sand pack - LV60B
0.4
Experimental
LV60A
Experimental
Micro-CT
Network
Micro-CT
0.3
Network
Frequency
Normalized Amplitude
1
0.1
LV60A
0.2
0.1
0.01
0
0
1000
2000
3000
10
Time (ms)
100
1000
10000
T 2 (ms)
Sand pack - F42B
0.4
Experimental
F42B
Micro-CT
Experimental
Micro-CT
Network
0.3
Network
Frequency
Normalized Amplitude
1
0.1
F42B
0.2
0.1
0
0.01
0
1000
2000
Time (ms)
3000
10
100
1000
T 2 (ms)
10000
NMR – Results Carbonats
Carbonate (2)
1000
Capillary Pressure (KPa)
Capillary Pressure (C22)
800
Network:
Experimental
Tuned Network
Tuned Berea
Pores:
Throats:
600
12,349
26,146
400
Simulation Parameters
200
Diffusion Coefficient:
2.07x10-9m2/s (Vinegar, 1995)
Bulk Relaxivity:
3.1s
Surface Relaxivity:
2.8μm/s
Number of walkers:
2,000,000
0
0.0
0.2
0.4
0.6
0.8
1.0
Sw
Comparison of the experimental capillary pressures of carbonate
C22 with simulation results from a tuned Berea network.
1
0.25
Experimental
Simulation
Experimental
Simulation
C22
0.2
Frequency
C22
Normalized Amplitude
(Vinegar, 1995)
0.1
0.15
0.1
0.05
0.01
0
0
500
1000
Time (ms)
1500
2000
10
100
1000
T2 (ms)
10000
NMR – Results Carbonats
Carbonate (3)
Network:
1000
Capillary Pressure (C32)
Capillary Pressure (KPa)
800
Tuned Berea
Experimental
Pores:
Throats:
Tuned Network
12,349
26,146
600
400
Simulation Parameters
200
Diffusion Coefficient:
2.07x10-9m2/s (Vinegar, 1995)
Bulk Relaxivity:
3.1s
Surface Relaxivity:
2.1μm/s
Number of walkers:
2,000,000
0
0.0
0.2
0.4
0.6
0.8
1.0
Sw
Comparison of the experimental capillary pressures of carbonate
C32 with simulation results from a tuned Berea network.
1
0.5
Experimental
Simulation
C32
Experimental
Simulation
0.4
Frequency
C32
Normalized Amplitude
(Vinegar, 1995)
0.1
0.3
0.2
0.1
0
0.01
0
500
1000
Time (ms)
1500
2000
10
100
1000
T2 (ms)
10000
Efficacy of CO2 injection
Reservoir condition core flooding test have commenced
using a composite core plug from a producing field from the
Middle East. Reservoir temp. ~ 250 oF and press. ~ 4000 psi
After flooding the sample with brine, vertical flooding sequence has
been applied:
•
Tertiary Gas flood.
•
Tertiary Water Alternating Gas.
•
Tertiary CO2 injection.
Efficacy of CO2 injection
• Oil produced
from waterflooding
Secondary
Brine Injection was 42%
Oil Recovery, HCPV frac.
0.50
0.40
0.30
0.20
0.10
0.00
0.0
0.5
1.0
Brine Injected (PV)
1.5
2.0
Tertiary Gas injection
Tertiary
HC Gas
Injection
• Oil produced
from gas
flooding
was 82%
Oil Recovery, HCPV frac.
1.00
0.90
0.80
0.70
0.60
0.50
0.40
2.0
2.5
3.0
Gas Injected (PV)
3.5
4.0
Tertiary WAG injection
• Oil produced Tertiary
from WAG
flooding was 80%
WAG Injection
Oil Recovery, HCPV frac.
1.00
0.90
0.80
0.70
0.60
0.50
0.40
2.0
2.5
3.0
Brine-Gas Injected (PV)
3.5
4.0
Tertiary CO2 injection
Tertiary CO2 flooding
• Oil produced from CO2 flooding was 96%
Oil Recovery, HCPV frac.
1.00
0.90
0.80
0.70
0.60
Injection of
CO2 stopped
0.50
0.40
2.0
2.5
3.0
Gas Injected (PV)
3.5
4.0
Efficacy of CO2 injection
• Comparison between different tertiary flooding
methods
1.00
Secondary Brine Injection
Oil Recovery, HCPV frac.
Tertiary Gas
0.80
Tertiary WAG
Tertiary CO2
0.60
0.40
0.20
0.00
0.0
0.5
1.0
1.5
2.0
2.5
Brine-Gas Injected (PV)
3.0
3.5
4.0
The influence of wettability and
carbon dioxide injection on
hydrocarbon recovery
Saif Al Sayari
Martin J. Blunt