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Validation of Models Simulating Capillary and Dissolution Trapping During Injection and Post-Injection of CO2 in Heterogeneous Geological
Formations Using Data from Intermediate Scale Test Systems (FE0004630)
Abdullah Cihan
Lawrence Berkeley National Laboratory
U.S. Department of Energy
National Energy Technology Laboratory
Carbon Storage R&D Project Review Meeting
Developing the Technologies and Building the
Infrastructure for CO2 Storage
August 21-23, 2012
Research Team
Tissa Illangasekare, Luca Trevisan, Elif Agartan, Hiroko Mori
Colorado School of Mines
Jens Birkholzer, Quanlin Zhou and Marco Bianchi
Lawrence Berkeley National Laboratory
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Presentation Outline
Benefit to the Program
Project Overview
Technical Status
Task 2 – Intermediate-scale laboratory testing of
capillary and solubility trapping in homogeneous and
heterogeneous systems
Task 3 – Evaluation of whether existing modeling
codes can capture the processes observed in the
laboratory, and developments of the constitutive
models based on the findings
Accomplishments to Date
Project Summary - Findings and Future Plans
Appendix
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Benefit to the Program
Overall Project Goals
Improve/develop and validate models by using the data
generated in intermediate-scale laboratory test systems
simulating capillary and dissolution trapping under
various heterogeneous conditions.
Design injection strategies, predict storage capacities and
efficiency for field-scale geological systems by using the
improved numerical tools
The findings will meet objectives of Program research to develop
technologies to cost-effectively and safely store and monitor CO2
in geologic formations and to ensure storage permanence.
Developed approach and technologies in this project specifically
contribute to the Carbon Storage Program’s effort of supporting
industries’ ability to predict geologic storage capacity to within +/-
30 percent.
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Knowledge gaps and
research questions
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Heterogeneity and Capillary Trapping
In naturally heterogeneous formations, injected scCO2 will preferentially
migrate into higher permeability zones and pool under the interface of the
confining low permeability layers due to capillary barrier effects (very high
entry pressure).
Low permeability
High permeability
Pooling
Injection
Knowledge gaps exist on how the
heterogeneity influences capillary
trapping of CO2.
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Heterogeneity and Dissolution Trapping
Dissolution of CO2 in heterogeneous systems can
be enhanced due to increases in interfacial areas
between water and supercritical CO2.
Knowledge gaps exist on how the heterogeneity
influences dissolution trapping of CO2.
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Capillary Trapping
How do heterogeneities and connectivity (spatial continuity of
different permeability zones) affect entrapment efficiency of scCO2 in
deep geological formations?
How well the existing continuum-based models and the constitutive
models capture multiphase flow behavior of scCO2 /brine in deep
formations?
Dissolution Trapping
What are the effects of heterogeneity on dissolution and density-
driven fingers?
Can dissolution of CO2 in heterogeneous systems be enhanced due to
increases in interfacial areas between water and supercritical CO2?
Research Questions
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Task 1 – Project Management and Planning
Task 2 – Generate data in intermediate scale test tanks
simulating capillary trapping and dissolution affected by
heterogeneity
Task 2.1 – Small tank experiments
Task 2.2 – Large tank experiments
Task 3 – Evaluate whether the existing modeling codes can
capture processes observed in the test tanks, and improve
existing models based on findings
Project Objectives and Tasks
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x
y
0.5 1 1.5 2 2.5 3 3.5 4 4.5
0.2
0.4
0.6
0.8 0.9
0.75
0.6
0.45
0.3
0.15
Wetting FluidSaturation
Time = 1 day
A multi-scale experimental testing
and modeling
Size (cm to basin scale)
Mo
de
l D
ime
nsio
n
S
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
x
y
0.02 0.04
-0.04
-0.02
Exp
eri
me
nt D
ime
nsio
n
LBNL
Field
Scale
Pc (Pa)
Co
nn
ec
tiv
ity
1000 1500 2000 2500 30000
0.2
0.4
0.6
0.8
Primary Drainage
Main Wetting
Approach
Intermediate-Scale
1 to ~ 10 m
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10
10 20 30 40 50 60 70
x-coordinate (cm)
0
10
20
30
40
50
z-coord
inate
(cm
)
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
interface
NA
PL s
atu
ration
Experimental Methods
Automated transient and spatially
distributed saturations using x-ray
attenuation
Aqueous sampling to determine
dissolved plume concentrations, and
core destructive sampling from
low permeability zones
Core destructive sampling to determine
final entrapment saturations.
Measurement of multiphase model parameters (capillary pressure-
saturation-relative permeability relationships)
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Task 2 – Experimental Studies
Selection of materials and fluids
Dimensional analysis (Bo, Ca, density and viscosity ratio, Ra number)
Small test systems in fluid/fluid media and small sand tanks
(28cmx15cm)
Small tank experiments (28cmx15cm and 92cmx1.2m)
Capillary trapping in homogeneous and simple heterogeneous
packing (8 experiments completed)
Analyses of density-driven finger developments in homogeneous and
heterogeneous packing (4 experiments completed)
Capillary trapping in highly heterogeneous systems (in progress)
Capillary and dissolution trapping (homogeneous and heterogeneous
packing)
Large tank experiments (4.9mx1.2m)
Capillary trapping (in progress)
Capillary and dissolution trapping
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Material and Fluid Selection
Laboratory investigation of scCO2 migration without high
pressure can be conducted using analogous fluids having
similar density and viscosity contrasts as scCO2 – brine
phases under sequestration conditions
Dimensionless
Numbers
scCO2-brine
@ Typical
Reservoir
Conditions
Soltrol220-
glycerol/water
@ 20C, 1 atm
Water in
Propylene
Glycol @ 20C,
1 atm
Methanol in
glycerol/water
@ 20C, 1 atm
Bond # ~ 10-7 - 10-8 ~10-6- 10-7 ~10-6- 10-7 ~10-6- 10-7
Capillary # ~ 10-5 - 10-8 ~10-6- 10-7 ~10-7- 10-8 ~10-7- 10-8
Viscosity Ratio ~ 0.05 - 0.2 ~0.074 ~0.017 ~0.07
Density Ratio ~ 0.2 – 0.8 ~0.66 ~0.9 ~0.6
nw TuCa
g kBo
nw
w
nw
w
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Testing of the Scaling Approach
scCO2-water system
Test Fluids
Identical results can be obtained if the same
dimensionless numbers are chosen for the geometrically
similar two systems (Shook et al., 1992; Gharbi et
al.,1998).
1
10
100
1000
10000
400
600
800
1000
1200
1400
0 20 40 60 80 100
visc
osi
ty (
cP)
den
sity
(kg
/m3
)
glycerol percent by mass
density
viscosity
Glycerol/water mixture at
ambient conditions
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14 74 cm
52
cm
8 cm 8 cm
gra
ve
l
Sand #30
10 cm
11 cm
8 c
m
Sand #110
Sand #205 cm
55 cm
25
cm
Mariotte bottle
(constant
pressure)
Constant head
10 cm
11 cm
2.3
cm
Small Tank Experiments For Capillary Trapping in
Homogeneous and Heterogeneous Systems
Injected fluid: Soltrol 220
Displaced fluid: Glycerol-Water mixture (80%-20% w/w)
A total of 8 small tanks experiments with both homogeneous and
heterogeneous packing completed.
Plume injection and plume configuration recorded.
Soil samples removed and the fluids extracted to determine final
entrapment saturations.
Bottom plate
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Small Tank Experiments for Capillary
Trapping in Mildly Heterogeneous Systems
Can models that use macroscopic multiphase parameters capture the flow
and entrapment behavior ?
Are the relative permeability models generated from retention functions
adequate?
What are the effects of injection rates (entrapment zone development and
final entrapment saturations) ?
Does the final entrapment depend on rate of injection?
Heterogeneous with a continuous
high-permeability layer
T1=6hr30min
T2=72hr
0.22
0.19 0.13 0.13
T1=8hr30min
T2=90hr30min
0.180.160.13
0.200.16
Heterogeneous with a discontinuous
high-permeability layer
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Small Tank Experiments in Highly Heterogeneous Systems (in progress)
x
y
0.2 0.4 0.6 0.8
0.05
0.1
0.15
0.2
0.25
0.3
KSX
1.1E-10
3E-11
2E-11
x
y
0.2 0.4 0.6 0.8
0.05
0.1
0.15
0.2
0.25
0.3
S0.85
0.75
0.65
0.55
0.45
0.35
0.25
0.15
0.05
A computer-generated
realistic heterogeneous aquifer
3 3 3 3 2 2 3 3 1 1 1 3 3 3
3 3 3 3 3 3 3 3 3 3 3 1 1 3
3 2 2 3 3 3 1 1 1 1 3 3 3 3
3 3 3 3 2 1 2 2 2 2 3 3 3 3
3 3 3 3 3 3 1 2 2 3 3 2 2 2
2 2 2 2 3 3 3 3 1 1 1 1 1 3
3 3 3 3 3 3 3 3 3 2 2 3 3 3
3 3 3 3 2 2 1 3 3 3 3 3 3 3
WE
LL
Simplified for packing
Very fine sand
(Cap rock)
red (#30) Coarse
green (#50) Medium
blue (#70) Fine
Repair of X-ray systems will be
completed at the end of August
For phase
saturation
measurement
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Small-Tank Experiments: Heterogeneity effect on density-driven fingering (water/propylene glycol )
Fingering is dampened out by heterogeneity
From high permeability medium to low permeability
medium, finger flow is replaced by bulk flow
#45/#50
#50/#70
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Problems encountered in early design of the 16ft large tank experiment were
mostly resolved
Large Tank Experiments (in progress)
Well configuration => non-wetting phase
moves upward inside the well; only top
portion of the screen injects Soltrol into
the aquifer (reduced vertical sweep)
Difficulties to avoid preferential pathway
between confining layer and gasket
# 8
#110 + #250
# 8
#50/70
Constant head B.C.
Constant head B.C.
Previous Current Setup for the Large Tank
Experiments
With groundwater flow
4.88 m
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Task 3 – Modeling
Guiding the laboratory experiments
Injection rate and period, sampling frequency, different packing
configurations, and effect of different boundary conditions; i.e.,
constant head versus no flow.
Testing continuum models and upscaling methodologies
Verify models (numerical codes solving classical two-phase flow
equations) based on experimental measurements in homogeneous
and heterogeneous experiments
Test/develop constitutive models for accurate prediction of the CO2
entrapment
Utilize improved modeling and up-scaling tools to predict the
effective capillary and dissolution trapping at actual reservoir
conditions and large scale CO2 storage scenarios
Design injection strategies to optimize CO2 trapping.
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Model Testing
Small tank experiment in a mildly heterogeneous domain
with a continuous high-permeability zone – During Injection
VG-Mualem & Corey Relative perm. from Previous
Results in Air-water Exp.
systems
2 hr
7.5 hr
Time
0.2 0.4 0.6 0.8
0.2 0.4 0.6 0.8
S
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
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Model Testing
Small tank experiment in a mildly heterogeneous domain with a
discontinuous high-permeability zone – During Injection
1 hr
2 hr
6 hr
Time
x
y
0.2 0.4 0.6 0.8
0.2
0.4
0.6
x
y
0.2 0.4 0.6 0.8
0.2
0.4
0.6
x
y
0.2 0.4 0.6 0.8
0.2
0.4
0.6S
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
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T1=6hr30min
T2=72hr
0.22
0.19 0.13 0.13
Saturation distributions at the end of the experiments
Two-phase model results with hysteresis effects
Model Testing
x
y
0.2 0.4 0.6 0.8
0.2
0.4
0.6S
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
T1=8hr30min
T2=90hr30min
0.180.160.13
0.200.160.13
0.18 0.16
0.16 0.20
Simple Heterogeneous Packing
S
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
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Development of a Theoretical Hysteresis Model
1
, ,
1
( ) 1 ; , 1,2, ,jm m
d d
nw c m i ij ik d m c
i j i k i
S P f p p P P m n
, , , ,
1
1
Represents the fraction of pores filledwith non-wetting phase at the endofdrainage
' 1 ; , , 1, ,1
' 1
in iw w
nw c m nw c n i ij ik d m c m
i m j m k j
lnd d
i i il ik
l i k i
S P S P f p p P P m n n
f f p p
Drainage
Pc (Pa)
Co
nn
ec
tiv
ity
1000 1500 2000 2500 30000
0.2
0.4
0.6
0.8
Primary Drainage
Main Wetting
Imbibitions
1 2
1 2, , ,
n
n
r r r
f f f
Volume Fractions
Void Sizes
SW
Pc
(Pa
)
0 0.2 0.4 0.6 0.8 1
4000
6000
8000
10000
FLOW REVERSAL - 1
FLOW REVERSAL - 2
FLOW REVERSAL - 3
FLOW REVERSAL - 4
FLOW REVERSAL - 5
FLOW REVERSAL - 6
Connectivity parameters are
obtained from measured
capillary pressure-saturation
curves or computer-generated
pore network models
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Preliminary Results Verification of the Hysteresis Model
Water Content
Pc
(Pa
)
0 0.1 0.2 0.3 0.4
3000
4500
6000
7500
Model
Experiment (Computer-generated)
Primary Drainage
Main Wetting
0.00E+00
2.00E-02
4.00E-02
6.00E-02
8.00E-02
1.00E-01
1.20E-01
1.40E-01
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9
With computer-
generated data
With laboratory experiments in
LV60 sand with Octane/brine
(Pentland et al. 2010)
Model
Non-wetting phase saturation
(at the end of injection)
Re
sid
ua
l sa
tura
tio
n
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Modeling in the Large Tank and Effect of Heterogeneity
Four-Facies Case, Sands #30, #50, #70, #110
Time (days)
Ma
ss
(kg
)
0 2 4 6 8 10 12 140
2
4
6
8
10
4 facies- R1
4 facies- R2
4 facies- R3
SOIL NUMBER
PR
OB
OF
CO
NN
EC
TIV
ITY
1 2 3 40
0.2
0.4
0.6
0.8
1
Realization-1
Realization-2
Realization-3
Control Volume
More mass retained in Realization-
2 as a result of less connectivity of
higher-permeability zones
Higher k Lower k
Large-scale capillary entrapment
affected by connectivity!
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Model Simplification Through Upscaling
0.5 1 1.5 2 2.5 3 3.5 4 4.5
0.2
0.4
0.6
0.8
S
0.6
0.5
0.4
0.3
0.2
0.1
0.5 1 1.5 2 2.5 3 3.5 4 4.5
0.2
0.4
0.6
0.8
S
0.34
0.28
0.22
0.16
0.1
Sw
Pc
(Pa
)
0 0.2 0.4 0.6 0.8 10
5000
10000
15000
20000
25000
30000
Sw
kw
x,k
wy
,k
nx
,k
ny
0 0.2 0.4 0.6 0.8 1
10-31
10-26
10-21
10-16
10-11
kwx
kwy
knx
kny
Effective
Constitutive
Relationships
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Accomplishments to date
Task 2 – Experiments in intermediate-scale Selected and tested surrogate fluids
Small tank experiments completed for testing capillary trapping and
density-dependent fingers in homogeneous and simple heterogeneous
systems
Initiated large tank experiments for capillary trapping
Task 3 – Modeling Developed a multiphase flow solver (based on the Finite Volume
method) for analysis of the experimental data and new constitutive
models and non-equilibrium mass transfer
Simulated the two-phase flow in small tank experiments and compared
the model results with experimental data
Developed a new code for analyzing heterogeneity: Computes
connectivity based on invasion percolation algorithm. This code also
involves algorithms to upscale two-phase flow parameters.
Developed a new hysteresis model and tested against few data sets
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Project Summary
Findings The numerical model based on the classical two-phase flow
theory was able to capture the main features observed
during the migration of the CO2 surrogate fluid in the small
tanks
Incorporating hysteresis effects into the numerical models
required for accurate prediction of post-injection capillary
entrapment.
Intermediate-scale heterogeneity (existence of lower and
higher permeability zones) enhances the capillary
entrapment.
Density-driven convective mixing in highly heterogeneous
formations may not be important.
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Project Summary
Future Efforts Obtain quantitative data on temporal and spatial
saturation changes using the X-ray system
Complete measurements of relative permeability of the
sands in separate homogeneous column tests
Update the model results in the small tank with measured
relative permeability curves in separate homogeneous
column tests
Intermediate-scale heterogeneous experiments and
models involving both capillary and dissolution trapping.
Improve the numerical models by incorporating the
validated constitutive models
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Questions?
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Appendix: Organization and Gantt Charts
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Task 1.0 – Project Management and Planning
Illangasekare
(PI/PD)
CSM Team
(experiments)
LBNL team
(modeling)
Luca Trevisan
(PhD student)
Cihan
Birkholzer Zhou
coordination coordination
Elif Agartan
(PhD student)-
partial
Hiroko Mori
(MS student)-self
Sakaki
Bianchi
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Updated Time Line
Task BP 1 BP 2 BP 3
Tanks assembly and setup
Experimental methods
Homogenous immiscible
Homogenous miscible
Heterogeneous
immiscible
Heterogeneous miscible
Modeling
February 2012 November 2010
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Appendix: Bibliography
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Backup Slides
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Capillary
trapping
Dissolution
trapping
Mineralization
Leakage
Injection
Deep geologic formation
Goal
Maximize
Minimize/
Prevent
Maximize
Maximize
Select site with
least potential
and risk
Strategy
Use
heterogeneity
to increase total
CO2 trapping/
water interfacial
area
Design Strategy
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Physically based theory for predicting entrapment
In conventional multiphase flow modeling approaches, residual
non-wetting phase content are either calculated based on
empirical relationships or fitted from experimental data.
There is no physically based theory predicting entrapment of CO2
in homogeneous and heterogeneous systems.
Pore scale
Water
CO2
Ca
pil
lary
Pre
ss
ure
Saturation
CO2 injection
CO2 drainage
Capillary entrapment
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38
12 hours later 1 day later 5 days later 1 week later
Coarse Sand
Medium Sand
Fine Sand
Rayleigh
Number
Small Tank Experiments: Density-driven fingering and
(water/propylene glycol) in homogeneous domains
Rayleigh Number for scCO2-brine @ Typical Reservoir
Conditions ~ 6 - 103
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39
Heterogeneity and Capillary Trapping
Entrapment efficiencies of CO2 (defined as the total mass trapping
per unit volume of the formation) in relatively homogeneous and
highly heterogeneous systems can be quite different. Knowledge
gaps exist on how the heterogeneity influences capillary
entrapment of CO2.
Cap rock
Injection
Homogeneous Heterogeneous
Fine soil Fine soil
Coarse soil Random
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Small Tank Experiments for Capillary Trapping
A total of 8 small tanks experiments with
both homogeneous and heterogeneous
packing completed.
Plume injection and plume configuration
recorded.
Soil samples removed and the fluids
extracted to determine final entrapment
saturations.
Goal is to generate a data set for
validation of models to simulate
macro-scale processes of capillary
entrapment
Small tank (90 cm x 60 cm x 5.6 cm)
Mariotte bottle with Soltrol 220
on an automated balance
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Large Tank Experiments: Design and assembly
of large tanks for confined conditions
4 ft
5 cm
X-ray attenuation
For phase saturation
measurement
Ports for aqueous
sampling
Sloping capping layer
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Conceptual Model :
Near-Pore-Scale Macroscopic Invasion Percolation
Problem domain discretized into a grid (two- or three-dimensional) with a chosen critical
“throat” or critical “pore”, rm, values assigned to each grid block for nonwetting or
wetting fluid invasion (Glass et al., 2001, WRR)
A grid block contains a small void space characterized with a rm value.
x (m)
y(m
)
0 0.01 0.02 0.03 0.04 0.05-0.05
-0.04
-0.03
-0.02
-0.01
0
x (m)0 0.01 0.02 0.03 0.04 0.05
No Trapping
Drainage path Imbibitions path
2,
c a w
m
Young Laplace Equation P P Pr
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Development of Constitutive Models
Using Pore Connectivity
Drainage
Assumptions:
During drainage, the largest pores drain first
During wetting, the smallest pores fill up first
2,
c a w
m
Young Laplace Equation P P Pr
1 11 1
1 2 12 11 1 22 2
1
2 1
i p f
i p p f p f
11
12 22
5 / 6
1, 54 / 60
p
p p
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Development of A Theoretical Hysteresis Model
11
12 22
13 23 33
1 2 3
d
d d
d d d
d d d
n n n
p
p p
p p p
p p p
1 2
1 2, , ,
n
n
r r r
f f f
,
, 1 1, 1
, 2 1, 2 2, 2
,1 1,1 2,1
w
n n
w w
n n n n
w w w
n n n n n n
w w w
n n n
p
p p
p p p
p p p
Volume Fractions
Pore Sizes
Connectivity for the
Drainage Paths
Connectivity for the
Imbibitions Paths
x
y
0.02 0.04
-0.04
-0.02
x
y
0.02 0.04
-0.04
-0.02
Large Pores
Small Pores
Small Pores
Large Pores
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0.22
0.19 0.13 0.13
With hysteresis S
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
No hysteresis effects
Model Testing
A Small Tank Experiment – Post-Injection
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T1=6hr30min
T2=72hr
0.22
0.19 0.13 0.13
Saturation distributions at the end of the experiments
Two-phase model results with hysteresis effects
Model Testing
x
y
0.2 0.4 0.6 0.8
0.2
0.4
0.6S
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
T1=8hr30min
T2=90hr30min
0.180.160.13
0.200.160.13
0.18 0.16 0.16 0.20
Heterogeneous Packings
S
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
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Near-Pore Scale Invasion Percolation (sand#30)
Dependence of Residual Saturation on
Maximum Saturation
Wetting Phase
Non-wetting Phase
Trapped Non-
wetting Phase
Smax=0.40 Sr=0.11
End of Drainage End of Imbibitions
Smax=0.84 Sr=0.17
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Wetting Phase
Non-wetting Phase
Trapped Non-
wetting Phase
Smax=0.40 Sr=0.11
End of Drainage End of Imbibitions
Smax=0.84 Sr=0.17
Pentland et al. 2010, SPE
Results show that the residual non-wetting phase saturation is strongly function of the saturation at the end of injection
Non-wetting phase saturation
(at the end of injection)
Dependence of Residual Saturation on
Maximum Saturation R
esid
ua
l sa
tura
tio
n
Near-Pore Scale Invasion Percolation (sand#30)