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Transp Porous Med (2012) 91:459–478
DOI 10.1007/s11242-011-9854-2
An Experimental Study of CO2Exsolution and Relative
Permeability Measurements During CO2Saturated
Water Depressurization
Lin Zuo ·Samuel Krevor ·Ronald W. Falta ·
Sally M. Benson
Received: 1 April 2011 / Accepted: 25 August 2011 / Published online: 16 September 2011
© Springer Science+Business Media B.V. 2011
Abstract Dissolution of CO2into brine is an important and favorable trapping mecha-
nism for geologic storage of CO2. There are scenarios, however, where dissolved CO2may
migrate out of the storage reservoir. Under these conditions, CO2will exsolve from solution
during depressurization of the brine, leading to the formation of separate phase CO2.For
example, a CO2sequestration system with a brine-permeable caprock may be favored to
allow for pressure relief in the sequestration reservoir. In this case, CO2-rich brine may be
transported upwards along a pressure gradient caused by CO2injection. Here we conduct an
experimental study of CO2exsolution to observe the behavior of exsolved gas under a wide
range of depressurization. Exsolution experiments in highly permeable Berea sandstones
and low permeability Mount Simon sandstones are presented. Using X-ray CT scanning, the
evolution of gas phase CO2and its spatial distribution is observed. In addition, we measure
relative permeability for exsolved CO2and water in sandstone rocks based on mass balances
and continuous observation of the pressure drop across the core from 12.41 to 2.76MPa. The
results show that the minimum CO2saturation at which the exsolved CO2phase mobiliza-
tion occurs is from 11.7 to 15.5%. Exsolved CO2is distributed uniformly in homogeneous
rock samples with no statistical correlation between porosity and CO2saturation observed.
No gravitational redistribution of exsolved CO2was observed after depressurization, even
in the high permeability core. Significant differences exist between the exsolved CO2and
water relative permeabilities, compared to relative permeabilities derived from steady-state
drainage relative permeability measurements in the same cores. Specifically, very low CO2
and water relative permeabilities are measured in the exsolution experiments, even when the
CO2saturation is as high as 40%. The large relative permeability reduction in both the water
and CO2phases is hypothesized to result from the presence of disconnected gas bubbles in
L. Zuo (B
)·S. Krevor ·S. M. Benson
Department of Energy Resource Engineering, Stanford University, Palo Alto, CA 94305, USA
e-mail: linzuo@stanford.edu
R. W. Falta
Department of Environmental Engineering and Earth Sciences, Clemson University, Clemson, SC 29634,
USA
123
460 L. Zuo et al.
this two-phase flow system. This feature is also thought to be favorable for storage security
after CO2injection.
Keywords CO2exsolution ·Relative permeability ·CT scanning
1 Introduction
In geologic carbon sequestration, compressed carbon dioxide (CO2) gas is injected into geo-
logical formations at depths where the hydrostatic pressure is above the critical pressure to
take advantage of the high density of supercritical CO2(e.g., 610 g/l at 12.41 MPa, 50 ◦C).
However, even deep in the subsurface, the density of CO2is still much less than water or
typical brines (∼1100 g/l). This makes the injected CO2subject to a strong upward buoyancy
force. Many studies have been conducted on CO2migration in storage reservoirs, evaluat-
ing CO2plume development in a two-phase flow systems; the effects of permeability and
capillary pressure barriers on CO2migration; and strategies to minimize unfavorable CO2
movement (Hesse et al. 2006;Silin et al. 2008;Riaz et al. 2006;Juanes et al. 2006;Saadatpoor
et al. 2010;Benson and Hepple 2005;Benson and Cole 2008;Zhang et al. 2004).
Efforts have also focused on the fate of dissolved CO2in the storage reservoir (King and
Paterson 2005;Leonenko and Keith 2008;Hassanzadeh et al. 2007;Farajzadeh et al. 2007). In
particular, studies have demonstrated that gravitational instability resulting from the slightly
higher density of CO2saturated brine compared to brine without CO2(about 1–2%) will lead
to the development of natural convection currents. These convection currents can accelerate
plume dissolution and improve storage security. Much less effort has focused on the fate of
dissolved CO2if it moves upward due to injection-induced pressure gradients between the
storage reservoir and the overburden.
Carbon dioxide solubility in water is high and increases approximately linearly with
pressure until the supercritical pressure is reached (Fig. 1,Duan and Sun 2003). At 12.41MPa
and 50◦C, in pure water, the mole fraction of dissolved CO2approaches 2.3% (mass fraction
of 5.4%). The high solubility of CO2in water is favorable for long-term sequestration since
dissolved CO2is no longer subject to upward buoyancy forces. As a result, solubility trap-
ping is even more secure than structural trapping. Although estimates of the time needed for
complete dissolution vary from 100’s to 10,000’s years (Riaz and Tchelepi 2008), depend-
ing on the permeability, geometry, temperature, and salinity of sequestration sites, in many
cases a substantial fraction of injected CO2will eventually dissolve in the subsurface. While
dissolved CO2presents a better storage security, risks of leakage still exist. If CO2saturated
brine is depressurized, the solubility of CO2decreases and CO2exsolves from solution,
expands and forms a separate phase as the fluid pressure continues dropping. This scenario
is most likely to occur by vertical upward movement of CO2saturated fluids, triggered by
an upward pressure gradient, either from overpressure from injection in deeper formations
or from underpressure of ground water due to pumping in a shallower formation. Carbon
dioxide saturated water could permeate seals that are impermeable to the CO2phase in a
two-phase system. To understand the risks associated with CO2exsolution, this study seeks
to observe the formation of exsolved CO2during depressurization and to assess the mobility
of the CO2and water under these conditions.
There is a large body of knowledge about an analogous occurrence in oil reservoirs:
the process of solution gas drive. Gas bubbles exsolve from oil, grow, and accumulate
when the reservoir pressure drops below the bubble point during primary depletion. The
physical mechanisms of bubble formation (nucleation) and bubble growth in porous media
123
CO2Exsolution and Relative Permeability Measurements 461
Fig. 1 CO2solubility in water at
50◦C versus pressure (Duan and
Sun 2003)
0 5 10 15 20
0
0.5
1
1.5
Pressure, MPa
CO2 solubility, mol CO
2/kg water
are well studied in the context of solution gas drive. When pressure decreases, transient
gas “nuclei” appear homogenously by thermal fluctuations (Wilt 1989). Firoozabadi and
Kashiev (1996) proposed an “instantaneous nucleation” model for a sudden step change
decrease in pressure and assume that in a given time the number of bubbles formed only
depends on the supersaturation, the porous medium and fluid properties. Then all bubbles
grow by diffusion. There is another theory about bubble formation in a porous medium pro-
posed by Yortsos and coworkers (Li and ortsos 1993;Li and Yortsos 1995;Satic et al. 1995).
They concluded that the most plausible nucleation mechanism in a porous medium with slow
rate of pressure decline is “heterogeneous nucleation,” or “progressive nucleation,” which
postulates various sites on solid surfaces become activated and bubbles arise once the local
gas mass concentration is big enough to overcome the local capillary pressure. They also
found the final nucleation fraction is a power law of the decline rate. El Yousfi et al. (1997)
conducted CO2–water exsolution experiments in micro models with various pressure drops
and concluded that the nucleation is “instantaneous” compared to the long depletion time,
but bubbles form only when the pressure drop is big enough to balance the capillary force,
which is more similar to “progressive nucleation.” Arora and Kovscek (2003) developed
mechanistic bubble population balance models with bubble rate equations for both theories.
They found both models matched well with experimental data for light and heavy oils. In
the progressive nucleation model, the nucleation period was relatively short compared to the
total depletion time, which is consistent with the observation of El Yousfi et al. (1997).
Many experiments have been conducted to understand the flow properties of micro bubbles
in solution gas drive. An important parameter identified in these experiments is the critical
gas saturation. The critical gas saturation is defined as the minimum gas saturation at which
evolved micro bubbles start behaving as a separate phase. In other words, the system enters a
two-phase flow regime once the gas saturation grows above the critical gas saturation. Before
approaching the critical gas saturation, the concept of simultaneous flow of oil and micro
bubble gas in solution, referred to as “foamy oil,” was first introduced by Smith (1988), but
later rejected by experimental observations. Experiments show no gas production until the
critical gas saturation is exceeded. After this, the gas flow is intermittent. Reported critical
gas saturation values range from 1 to 40% in various experiments (Firoozabadi 2001)andthe
characteristics of porous media, the properties of fluids and the depletion rate are key causes
for the wide spread of reported values. Lower critical gas saturation values are observed
with less viscous oils and with slower pressure decline rates (Li and Yortsos 1995). Low
123
462 L. Zuo et al.
gas relative permeabilities were measured (10−6–10−4) around the critical gas saturation in
a system of exsolved gas and oil by Tang and Firoozabadi (2003), and Firoozabadi (2001)
further concluded it is the high oil viscosity that contributes to the significant gas mobility
reduction.
Although solution gas drive provides a reasonable analogy for CO2exsolution, there are
significant differences in both fluid properties and the research focus. The high viscosity of
oil is thought to be a major factor in solution gas drive mobility reduction. Heavy oil viscosity
varies from 103to 105cP while water has viscosity around 0.55cP at 50◦C. The interfacial
tension between oil and gas ranges from 0.1 to 5 ×10−5N/cm, depending on temperature,
pressure, and oil composition, but the interfacial tension is an order of magnitude greater
for CO2–water systems (e.g., 33 ×10−5N/cm for water and CO2at 50◦C and 12.41 MPa,
Georgiadis et al. 2010). Compared with oil/gas, in a CO2/water system, the work needed to
form a spherical nucleus is thus larger and a lower nucleation rate in the CO2–water system
is expected for the same degree of super-saturation compared to the oil–gas system. Once
micro bubbles are formed, they are expected to be comparatively more mobile due to the low
viscosity of water. Besides these differences in fluid properties, petroleum engineers have a
much shorter time horizon of interest than CO2storage engineers.
In this study, several CO2exsolution experiments are conducted in four distinct rock
samples, three Berea sandstones and one Mount Simon sandstone, with X-ray CT scanning.
Both rapid and slow depressurizations are applied to achieve CO2exsolution from CO2sat-
urated water. Exsolved CO2and water relative permeability curves in sandstone rocks are
measured for the first time. Vertical migration and redistribution of CO2micro bubbles were
also evaluated after equilibration.
2 Methodology
CO2exsolution in a porous media is produced by lowering the pore pressure through the
extraction of fluids from a closed volume. Exsolution was first observed by applying rapid
pressure drops. Later, a slow depressurization approach was used to measure the critical
gas saturation and the exsolved CO2and water relative permeabilities in sandstone rocks.
After the slow depressurization experiments, the core was sealed to self-equilibrate and
the migration and re-distribution of CO2during the equilibration was evaluated to support
measurements of mobility. The impact of sub-core heterogeneities is also investigated by
correlating porosity and CO2saturation.
2.1 Experiment and Equipment Description
The experimental setup used for these experiments was designed to conduct steady-state
measurements of relative permeability for the CO2–water system (Perrin and Benson 2010).
Modifications were made to accommodate these experiments and are described below. The
experimental apparatus is shown in Fig. 2and consists of the following components: an
aluminum core holder surrounded with two electric heaters to maintain the rock sample at a
constant temperature during the experiment (50◦C is used for these experiments); a confining
pressure pump, connected to the core holder to provide a confining pressure outside the rock
sample which is kept 2.76 MPa higher than the pore pressure; a two-phase separator with
an ultrasonic transducer for fluid–fluid interface measurement; a backpressure pump serving
as a reservoir to regulate the pressure of the whole system; two dual-pump systems, one
for water and one for CO2, each including two pumps attached with a set of programmable
123
CO2Exsolution and Relative Permeability Measurements 463
two-phase
separator
R
R
CO2Cylinder
CO2water
back
pressure
pump
core holder confining
pressure
pump
heater
R
pressure transducer
manual valve
electric valve
relief valve
check valve
RR
RR
CO2Cylinder
RR
Fig. 2 Experimental Setup for background scans and CO2saturated water preparation
electric valves that synchronize pulling of one pump and refilling of the other to maintain a
constant flow; and a heater to warm fluids before entering the core holder. Logs of all pumps
and the separator are collected automatically. More detailed information about the setup can
be found in Perrin and Benson (2010).
Rock samples are 2 inches (∼5cm) in diameter and vary in length, porosity, and per-
meability (Table1). Before the experiments, Berea sandstone samples are fired at 700◦Cto
stabilize the clay fraction. The Mount Simon rock sample is not fired to preserve the original
flow properties of the rock. Then the core is triple wrapped in (1) heat-shrinkable Teflon
sleeve, (2) nickel foil to prevent diffusion of CO2, and (3) a second Teflon sleeve. A viton
rubber sleeve separates the core from the confining fluid used to maintain realistic stresses
in the rock (2.75 MPa overpressure for these experiments).
An X-ray CT scanner is used to scan rock samples for measurements of porosity and
CO2saturation by density difference (Akin and ovscek 2003). 2D images can be taken at
a minimum interval of 1 mm along the length of the rock sample and re-constructed as a
3D image. The X-ray scanner is set at a 200 mA current, 120 kV voltage, and 25 cm DFOV
protocol. The resolution of each 2D image is 490 ×490 microns per pixel.
2.2 Experiment Methods and Data Processing
By extracting fluids from the water-saturated rock, the pore pressure is reduced from an ini-
tial value of 12.41MPa, resulting in a reduction in CO2solubility, triggering the exsolution
of CO2. Two rates of depressurization were used in separate experiments. In one group of
experiments, after the water saturated rock sample containing dissolved CO2was prepared,
a rapid pressure drop was applied to the rock sample, after which time multiple X-ray CT
images of the fluid-saturated rock could be made. These experiments were used to investigate
the spatial distribution of exsolved CO2in the porous media.
In a second set of experiments, a slow depressurization was applied to measure the rela-
tive permeability curves of exsolved CO2and of water. With this information, comparisons
123
464 L. Zuo et al.
Tab le 1 Experiment arrangement
Experiment # Rock sample characteristics Depressurization
approaches
Intermediate pressure
stages
1 Berea sandstone
homogeneous
k=266 mD;
∅=18.7%;
9.52 cm in
length
Rapid 9.65 MPa, 6.89MPa,
5.52 MPa
2 Berea sandstone
heterogeneous
k=439 mD;
∅=21.0%;
15.24 cm in
length
Rapid 6.89 MPa
3 Berea sandstone
homogeneous
k=963–1066 mD;
∅=22.7%;
10.16 cm in length
Slow: 0.01, 0.1,
2 ml/min
8.27 MPa, 5.52MPa
4 Same as #3 Same as #3 Slow: 0.1, 2, 10ml/min N/A
5 Mount Simon
sandstone
homogeneous
k=15.7mD;
∅=23.9%;
9.04 cm in
length
Slow: 0.1, 8 ml/min N/A
could be made with standard core flooding experiments and solution gas drive experiments
performed by other groups. In the experiments, after the initial pressure drop, the core is
sealed to observe the evolution of the gravity capillary equilibrium. Also, porosity and CO2
saturation distributions are compared to study any sub-core scale correlation, since a positive
correlation was found in core flooding experiments indicating a strong influence of sub-core
scale heterogeneities on flow properties (Perrin and Benson 2010).
Four different rock samples of two rock types are used to understand the influence of rock
properties, such as permeability, porosity, and heterogeneity, on the exsolution phenomena.
Two homogenous Berea sandstone samples and one heterogeneous Berea sandstone sample
with various permeabilities and porosities are used. One Mount Simon sandstone sample
with relatively low permeability is also chosen. Capillary pressure curves using a mercury
injection porosimeter are obtained before the experiments for prediction of gravity capillary
equilibrium and comparisons with experimental observations. Rock samples and different
depressurization approaches used are listed in Table 1.
2.2.1 Background X-ray CT Scans and Preparation of CO2Saturated Water
An X-ray CT scan of the dry rock core is taken before injecting CO2gas to displace air. A
series of scans are taken with the core fully saturated with CO2at various pressures, covering
the range over which the experiments will occur. The core is then depressurized to atmo-
spheric pressure. Next, at least ten pore volumes of fresh water are flowed through the rock
sample. The system is then re-pressurized while continuing to flow water so that residual
CO2is dissolved and all of the pore space is filled with water. The absolute permeability of
the rock sample is then determined by measuring the pressure drop across the core over a
range of flow rates. A background scan of the core saturated with water is taken when the
pore pressure reaches 12.41 MPa. Fluid flow is then stopped and the rock sample is isolated
by closing valves at both ends of the core holder.
To prepare CO2saturated water at elevated temperatures and pressures, CO2and water are
circulated together in a loop that bypasses the core. The system is operated continuously for
123
CO2Exsolution and Relative Permeability Measurements 465
pressure transducer
manual valve
check valve
core holder
confining
pressure
pump
back
pressure
pump
two-phase
separator
a
core holder
confining
pressure
pump
back
pressure
pump
pressure transducer
manual valve
check valve
two-phase
separator
b
Fig. 3 Experimental Setup for depressurization (arapid depressurization, bslow depressurization)
at least 12 h to establish equilibrium between CO2and water. Since the fluids are circulated
in a closed system, the volume of CO2lost due to dissolution can be calculated from a mass
balance based on logs of the backpressure pump, water pumps, CO2pumps, and the two-
phase separator. Demonstration that equilibrium between the fluids is achieved is determined
when the volume of separate phase CO2in the system stabilizes. Also, any possible leakage
can be easily identified if the volume of CO2in the system decreases over the experiment.
Once the CO2and water are equilibrated, valves isolating the core holder are re-opened
and CO2saturated water is flooded through the core displacing fresh water. After pumping
at least ten pore volumes of CO2-saturated water through the core, a scan is taken of the rock
filled with the CO2saturated water. Because the CO2saturated water is denser than pure
water, about 1% at 5% CO2mass fraction (Ohsumi et al. 1992), the average CT numbers
observed are around one to two Hounsfield unit larger (i.e., more dense) than the values from
the pure water scan and show a 0.6–1.2% bulk density increase. After the scan, the fluid flow
is stopped and the rock sample is sealed by closing all of the valves.
2.2.2 Depressurization
During the exsolution experiments the pressure is decreased from 12.41 to 2.76MPa, while
maintaining a constant temperature of 50◦C. Gas saturation in the core does not continue
increasing after the pressure drops below 2.76MPa. As a result, 2.76MPa is chosen as the
minimum pressure. In some experiments, the pressure drop is halted at several intermediate
pressure stages to allow for equilibration of the distribution of fluids in the core. To depres-
surize the system, a closed route is formed including the core holder, the backpressure pump
and the two-phase separator.
Two different configurations are used. In one configuration, fluids are withdrawn as fast as
possible from both ends of the rock sample (rapid depressurization, ∼1 MPa/min, Fig. 3a). In
a second configuration, fluids are withdrawn from one end of the core holder at a sequence of
constant rates (slow depressurization, ∼20 kPa/min, Fig. 3b). The sequence of constant rates
is applied to keep the rate of pressure drop relatively constant. In both configurations, the
confining pressure is maintained in the range of 1.38–2.76 MPa above the pore pressure by
manually reducing the pressure in the confining pressure pump. Scans are taken during the
depressurization process. Once the pore pressure drops to a desired intermediate pressure,
the fluid removal is stopped, the core holder is sealed and multiple CT scans are taken.
123
466 L. Zuo et al.
2.2.3 Data Collection and Processing
Flow rates, pressures, and fluid volumes in the pumps and the pressures at each end of the
core holder are recorded every 3s. The interface height in the two-phase separator is recorded
every 2 1 s.
The CT scanner creates 2D images with CT values in Hounsfield unit. These CT values
are linearly transformed from linear attenuation coefficients which are defined as −1000 for
air and 0 for water at standard conditions. As a result, CT
water =0, CT
air =−1000. To
obtain porosity, since the average grain CT value is unknown, two scans are used: a dry scan,
when the rock sample is dry and filled with air, and a water saturated scan, when the rock
sample is fully saturated with water at the reservoir conditions. The porosity is calculated:
φ=CT
water/rock −CT
air/rock
CT
water −CT
air
(1)
To determine CO2saturation, three scans are needed: a CO2scan, when the rock sample is
fully saturated with CO2at the reservoir conditions, a solution scan, when the rock sample
is fully saturated with the dissolved CO2–water solution at the reservoir conditions, and an
experiment scan, when the rock sample is filled with exsolved CO2and water at the same
pressure as the CO2scan. CO2scans are taken at 9.65, 8.27, 6.89, 5.52, and 2.76MPa. The
pixel-scale CO2saturation of an experiment scan is calculated:
SCO2=CT
solution/rock −CT
exp
CT
solution/rock −CT
CO2/rock
(2)
Core-average CO2saturations are calculated using core-average CO2CT numbers interpo-
lated from existing CO2scans with an exponential fit. Slice-average CO2saturations are
calculated using slice-average CO2CT numbers from existing CO2scans. For pixel-scale
porosity values and CO2saturations, ten individual scans are taken for each scan used in
the formulas. Then, each pixel CT number is an average of all ten scans. By doing this, the
random error of CT scanning is reduced to ±2% for each calculated pixel value. The random
error of slice-average and core-average CO2saturations is less than ±0.1%.
2.2.4 Relative Permeability Measurements
Measurements of exsolved CO2and water relative permeabilities in sandstone rocks are con-
ducted based on the multiphase modification of Darcy’s Law. With fluids withdrawn from
one end of the core holder, a simple mathematical formula can be derived for relative per-
meability calculations (Tang and Firoozabadi 2003). With this method, the fluid properties
are assumed to be constant across the rock sample. In the experiments, the average pore
pressure is on the order of 1 MPa while the pressure gradient across the core is on the order
of 1–10 kPa and variation in fluid properties, such as density, viscosity and interfacial tension
due to pressure gradients across the core are small. Another requirement for this calculation
is that there is no significant CO2saturation gradient across rock sample. The validity of this
assumption is demonstrated by observations of the saturation, except in the case of low CO2
saturation. Given the rock sample dimensions, fluid properties and the absolute permeability,
two parameters are needed to calculate relative permeabilities: the flow rate of each phase
and the pressure drop across the rock sample. The pressure drop across the core is measured
directly by a pressure transducer at each end of the core holder. To measure flow rates, two
scans are needed, one at time t1, one at time t2. The average water flow rate between t1and
t2is:
123
CO2Exsolution and Relative Permeability Measurements 467
0 20 40 60 80 100
0.18
0.185
0.19
0.195
0.2
Slice Index
Porosity
a
0 50 100 150
0.2
0.205
0.21
0.215
0.22
Slice Index
Porosity
b
Fig. 4 Slice-averaged porosity for the homogeneous rock sample (a) and the heterogeneous rock sample (b)
qw=Sw1−Sw2
t2−t1
·Vp(3)
and the average CO2flow rate between t1and t2is calculated based on fluids’ properties at
time t2:
qCO2=SCO2,1·ρCO2,1/ρCO2,2+Sw1·/ρCO2,2−SCO2,2
t2−t1
·Vp(4)
where Vpis the pore volume and [CO2mass/water volume] is the CO2solubility change
between p1(t1)and p2(t2). This formula accounts for the expansion of the CO2originally in
place and additional exsolved CO2.
To start the measurement, the back pressure pump is set at a low and constant volumetric
withdrawal rate. The pore pressure of the rock sample and the pressure drop across the rock
sample are recorded every 3s. At first, the pressure drops very quickly due to the low com-
pressibility of water. Once exsolved CO2forms, the withdrawal rate is increased to maintain
a relatively constant pressure drop rate (∼20 kPa/min).
3Results
3.1 Evidence for the Development of Exsolved Phase
One homogeneous Berea sandstone and one heterogeneous Berea sandstone (Fig. 4)were
used to conduct exsolution experiments using the rapid depressurization approach. The pore
pressure was dropped to a specified pressure and then the rock sample was sealed and moni-
tored for 6–24 h to observe equilibration of exsolved CO2under the influence of gravity and
capillary forces after which the depressurization process started again.
Significant amounts of exsolved CO2are observed in these experiments (Fig. 5). The
highest CO2saturations in both experiments reached over 40% due to solubility reduction
and CO2expansion as the pressure drops.
CO2saturation gradients are observed, especially in the heterogeneous rock sample.
Saturation gradients in the homogeneous rock sample are most likely caused by prefer-
ential flow out of one end of the core holder rather than equal flow from both ends during the
depressurization process. The heterogeneity of rock samples also contributes to the variable
CO2saturation (Fig. 6). The low porosity portion in the middle of the heterogeneous sample
appears to have formed a flow barrier and amplified the flow preference. Compared with
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468 L. Zuo et al.
0 20 40 60 80 100
0
0.1
0.2
0.3
0.4
0.5
Slice Index
CO2 Saturation
2.76MPa, 0min & 6hrs
5.52MPa, 0min & 8hrs
6.89MPa, 8hrs
6.89MPa, 0min
9.65MPa, 5hrs
9.65MPa, 0min
a
2.76MPa, 0min & 6hrs
5.52MPa, 0min & 8hrs
6.89MPa, 8hrs
6.89MPa, 0min
9.65MPa, 5hrs
9.65MPa, 0min
2.76MPa, 0min & 6hrs
5.52MPa, 0min & 8hrs
6.89MPa, 8hrs
6.89MPa, 0min
9.65MPa, 5hrs
9.65MPa, 0min
2.76MPa, 0min
2.76MPa, 24hrs
6.89MPa, 6hrs
6.89MPa, 0min
b
0 50 100 150
0
0.1
0.2
0.3
0.4
0.5
Slice Index
CO2 Saturation
2.76MPa, 0min
2.76MPa, 24hrs
6.89MPa, 6hrs
6.89MPa, 0min
Fig. 5 Slice-averaged CO2saturation under various pore pressures and equilibration times for the homoge-
neous rock sample (a) and the heterogeneous rock sample (b)
Fig. 6 3D reconstructed porosity and CO2saturation images: aporosity of the homogeneous rock sample;
bporosity of the heterogeneous rock sample; cCO2saturation of the homogeneous rock sample at 2.76 MPa;
dCO2saturation of the heterogeneous rock sample at 2.76 MPa
the results from the homogeneous rock sample which has the same experimental setup, the
CO2saturation gradients in the heterogeneous rock sample appear to mostly come from the
sub-core scale heterogeneities.
3.2 Mobility of Exsolved Phase
The homogeneous Berea sandstone core and a core from the Mount Simon sandstone were
used to carry out exsolution experiments with slower depressurization rates. One experiment
was conducted in a Berea sandstone with intermediate pressure stages of 8.27 and 5.52MPa,
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CO2Exsolution and Relative Permeability Measurements 469
Fig. 7 Mean pore pressure and
the pressure drop in experiment
#3 around the critical gas
saturation. The critical gas
saturation was determined by the
onset of large pressure drop
fluctuation, shown by arrow
Pressure drop
Pore pressure
11:02 11:31 12:00 12:28 12:57 13:26 13:55
500
1000
1500
2000
2500
3000
3500
Pressure Drop/ Pa
time/ hours
6
x 106
Mean Pore Pressure/ Pa
5.5
5.6
5.7
5.8
5.9
Pressure drop
Pore pressure
Fig. 8 Pore pressure versus CO2
saturation during the
depressurization
0 0.1 0.2 0.3 0.4
1
3
5
7
9
11
13
CO2 Saturation
Pore Pressure/ MPa
exp #3
exp #4
exp #5
and another experiment was a repetition of the previous one but with a sequence of higher
withdraw rates and without intermediate pressure stages. A third experiment was conducted
in the much less permeable Mount Simon sandstone without intermediate pressure stages.
3.2.1 Relative Permeability
In experiment #3, the critical point where the gas bubbles become mobile appeared around
12:20, corresponding to a CO2saturation of 11.7% (Fig. 7). In the depressurization pro-
cess, the critical gas saturation is determined from the onset of amplified fluctuations in the
pressure drop across the rock sample. In experiment #4 and #5, the critical gas saturations
were 15.5 and 11.9%, respectively.
Comparing experiments #3 and #4, it can be seen that the higher withdrawal rates lead to
higher gas saturations since water is more mobile and more water is withdrawn out of the
core at higher withdrawal rates (Fig. 8). The pressure drop across rock samples (Fig. 9)and
flow rates (Figs. 10,11) are used to compute relative permeabilities in different rock samples
(Fig. 12).
During depressurization, the rate of pore pressure decrease slowed as more gas exsolved.
The pressure gradient across the samples increased as gas saturation increased until the
critical gas saturation was reached. After the critical saturation was reached, the pressure
gradient across the sample remained relatively constant. The critical gas saturations corre-
sponding to the turning points in the pressure gradients curves, ∼12%, match well with the
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470 L. Zuo et al.
Fig. 9 Pressure drop across the
rock sample versus CO2
saturation during the
depressurization
0 0.1 0.2 0.3 0.4
100
101
102
103
104
105
CO2 Saturation
Pressure Differential/ Pa
exp #3
exp #4
exp #5
Fig. 10 Water flow rate versus
CO2saturation during the
depressurization
0 0.1 0.2 0.3 0.4
10-3
10-2
10-1
100
CO2 Saturation
Water Flow Rate/ cc/min
exp #3
exp #4
exp #5
Fig. 11 Exsolved CO2flow rate
versus CO2saturation during the
depressurization
0.1 0.15 0.2 0.25 0.3 0.35 0.4
10-4
10-3
10-2
10-1
100
CO2 Saturation
CO2 Flow Rate/ cc/min
exp #3
exp #4
exp #5
transient pressure data, 11.7–15.5%, where when gas bubbles became mobile, as evidenced
by the increased amplitude of pressure fluctuations. Flow rates of water and exsolved CO2
increased as CO2saturation grew, but exhibited large fluctuations.
The relative permeability data show very low mobility of both exsolved CO2and water.
For the exsolved CO2phase, the relative permeability is in a range of 10−5–10−3for CO2
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CO2Exsolution and Relative Permeability Measurements 471
10
10
10
10
Relative Permeability
b
-6
-4
-2
0
#4
k
#4
kk
0.6
k
kw
kg
0.7 0.8 0.9 1
Water Saturation
c
a
Fig. 12 Exsolved CO2and water relative permeability curves in sandstone rocks: aexperiment #3; bexper-
iment #4; cexperiment #5
saturations of 10–40% (Fig. 12). For the water phase, the relative permeability drops rapidly
as CO2exsolves, and continues dropping to less than 0.1 as the CO2phase becomes mobile.
3.2.2 Porosity, CO2Saturation, and Saturation Redistribution
Positive correlations between porosity and CO2saturation are often observed in standard
core flooding experiments in both homogenous and heterogeneous rock samples at reservoir
conditions (Perrin and Benson 2010;Krause et al. 2011). The spatial distribution of CO2is
shown to be highly influenced by sub-core scale heterogeneity. It is of interest to investigate
whether such influence on CO2distribution also exists in a system undergoing gas exsolution.
If such a correlation does not exist, it further suggests that different factors are controlling
the distribution of fluid phases in the rock.
No significant correlation is observed between porosity and CO2saturation in experiment
#3 immediately after the pore pressure drops to 2.76 MPa (Fig. 13). Therefore, it appears
that CO2is exsolved from solution uniformly regardless of the variation of porosity. This
indicates that sub-core scale heterogeneities and flow processes do not have an important
influence on the CO2saturation distribution during exsolution of CO2from water in a porous
media.
After the pore pressure drops to 2.76 MPa, the core holder is sealed and maintained at a
constant temperature of 50◦C for 260 h for equilibrium. There is a good statistical correlation
between CO2saturation before and after equilibrium (Fig. 14). The correlation coefficients,
r2, of the regression lines are 0.805, 0.822, and 0.791 for slice #30, #50, and #70, respectively.
This indicates little re-distribution of CO2is occurring over the 260-h period. The lack
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472 L. Zuo et al.
CO2 Saturation
0.16
0.35
0.45
0.55
0.65
0.18
Porosity
#30
0.2 0.22
CO2saturation
0.16 0.18
Porosity
#50
0.2 0.22
CO2Saturation
0.16 0.18
Porosity
#70
0.2 0.22
0.35
0.45
0.55
0.65
0.35
0.45
0.55
0.65
Fig. 13 Scatter plots of porosity and CO2saturation at CT slices #30, #50, and #70 in experiment #3. CO2
saturation was measured immediately after the pore pressure dropped to 2.76MPa
Fig. 14 Scatter plots of the initial CO2saturation immediately after depressurization to 2.76 MPa, and the
CO2saturation measured 260 h after the pore pressure dropped at CT slices #30, #50, and #70 in experiment
#3
of fluid re-distribution further supports the very low mobility observed during the relative
permeability measurements.
3.2.3 Gravity Effect on CO2Saturation Distribution
No vertical CO2gradient is observed, even after 260h of equilibration (Fig. 15). CO2
saturation at each height is obtained by averaging the center 16 pixels horizontally on the
corresponding averaged images. The similarity in CO2saturation between 100 and 260h
after depressurization demonstrates that the saturation is changing very slowly, if at all. These
curves are compared to the saturation distribution calculated for a homogeneous core allowed
to achieve gravity–capillary equilibrium. The calculation is based on the measured capillary
pressure curve (Fig. 16) and assumes that the gravity capillary equilibrium is reached:
hgρ =Pc(Smax)−Pc(Smin)(5)
where his the height of the rock sample, ρ is the density difference between water and CO2
at 2.76 MPa; Smax and Smin are the top and bottom CO2saturation, and a linear distribution
is assumed in between.
Under these conditions, if the CO2is mobile, a 5% vertical saturation gradient is expected.
The lack of a vertical saturation gradient indicates that the CO2phase is not sufficiently
interconnected and mobile enough to reach gravity capillary equilibrium over the observed
time period, despite the high permeability of the core.
123
CO2Exsolution and Relative Permeability Measurements 473
Height/ mm
50
40
30
20
10
0
50
40
30
20
10
0
50
40
30
20
10
0
0.4
CO2 Saturation CO2 Saturation CO2 Saturation
0.45
#30
0.5 0.4 0.45 0.5
0.4 0.45 0.5
Height/ mm
100 hrs
260 hrs
#50
calculation
Height/ mm
#70
Fig. 15 Vertical CO2distribution versus height as equilibrium processed 100h (blue curves) and 260 h (red
curves) after the pore pressure dropped to 2.76 MPa at CT slices #30, #50, and #70 in experiment #3
Fig. 16 Capillary pressure curve
measured using mercury
orosimetry for the homogeneous
Berea sandstone used in
experiment #3
4 Discussion
4.1 Mobility of Exsolved CO2
The relative permeabilities from exsolution experiments are compared to relative permeabil-
ities measured using a standard steady-state method on the same cores (Krevor et al. 2011).
The exsolved CO2relative permeability is far lower than the CO2phase relative permeability
measured during drainage (Fig. 17). This indicates that in a system undergoing CO2exsolu-
tion, the use of traditional drainage relative permeability curves to describe the CO2phase
will lead to large overestimations of the mobility of exsolved CO2. The significant reduction
in both water and CO2mobility observed in these experiments could be favorable for storage
security after injection. The exsolved gas may form a permeability barrier, preventing further
CO2migration or even blocking possible leakage paths.
The measured exsolved CO2relative permeability is in the same range of that observed in
solution gas drive experiments with methane and various heavy oils (Tang and Firoozabadi
2003;Tang et al. 2006). However, the argument that in solution gas drive the viscosity of
heavy oil is largely responsible for significant gas mobility reduction is not relevant in the
case of CO2exsolution, since water is much less viscous than heavy oil and CO2and methane
have similar viscosities at reservoir conditions.
Instead, it appears that the dispersed morphology of the exsolved CO2phase causes
the mobility reduction. Under normal two-phase flow conditions during drainage, both the
non-wetting phase (CO2in this case) and wetting phase are continuous. In addition, CO2
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474 L. Zuo et al.
0.2
0.4
0.6
0.8
Relative Permeability
a
0.4
0
1
0.2
0.4
0.6
0.8
0
1
Exsolution water
Drainage CO2
Exsolution CO2
Drainage water
0.6
Water Saturation Water Saturation
0.8 1
Relative Permeability
b
0.6 0.7 0.8 0.9 1
Exsolution water
Drainage CO2
Exsolution CO2
Drainage water
Fig. 17 Comparison between relative permeability curves of xsolved CO2and water and standard steady-state
core flooding experiments (aBerea sandstone; bMount Simon sandstone)
occupies a network of the largest interconnected pores, thus leading to moderate relative
permeabilities (Silin et al. 2010). In the case of exsolved CO2, the non-wetting phase is
largely discontinuous, with individual gas bubbles that are poorly aggregated. In part, the
low mobility of CO2can be attributed to the lack of a continuous phase. In addition, a
significant of fraction of the CO2is likely to be trapped in the mid to small size pores, where
the pressure needed to overcome the capillary forces to move through the pore throats is too
large. Even as large exsolved CO2phase saturations are achieved, the relative permeability
remains low, suggesting that only a small fraction of the exsolved CO2forms a continuous
phase while most remains disconnected. As a result, the exsolved CO2phase may be trapped
at saturations much higher than expected from traditional drainage-imbibition multiphase
flow theory and exhibits similar immobility as a residual phase caused by imbibition. We
hypothesize that is the widely distributed, disconnected gas bubbles, and not the high viscosity
of the wetting phase, that is main cause of low gas mobility in this case.
Before the CO2bubbles become mobile, the flow resistance to water caused by exsolved
CO2increases exponentially with CO2saturation (Fig. 9). This suggests that a trapped CO2
phase is occupying the pore spaces and reducing the accessible flow paths for water. Once
the critical saturation is reached, the pressure drop no longer increases with CO2saturation.
This indicates that the increasing volume of CO2phase in the pore space does not further
block the flow of water. We hypothesize that when the CO2phase saturation is low, dispersed
bubbles occupy the space close to pore throats and have a significant impact on water flow.
Once the critical saturation is reached and bubbles become mobile, pore throats are opened
and closed intermittently due to intermittent bubble flow. This explains the pressure drop
plateau in Fig. 9and the gas flow as a discontinuous phase.
4.2 Representativeness and Errors of Measured Relative Permeability
These relative permeability measurements are based on the slow depressurization method,
which withdraws fluids from only one end of the core (Tang and Firoozabadi 2003). The
calculation is based on a simple mathematical derivation, which assumes constant rock and
fluid properties. In these experiments the fluid properties vary by less than 10% (e.g., at
pore pressure ≥2.76 MPa; pressure drop across the core ≤0.2 MPa corresponding to a CO2
density change ≤8.5%, a CO2viscosity change ≤0.3%). Gas saturation gradients during
depressurization are small (e.g., in experiment #5, CO2saturation varies from 0.09 to 0.15 at
5.76 MPa and from 0.33 to 0.4 at 2.82 MPa). Given the unique flow geometry of this method
123
CO2Exsolution and Relative Permeability Measurements 475
for measuring relative permeability, with no flow at the upstream boundary gradually in-
creasing to 100% flow at the downstream boundary, the question arises as to whether the
measurements could be unduly biased by heterogeneities in the core. For these experiments,
this is unlikely because all of the relative permeability measurements are made using com-
paratively homogenous cores (experiments #3, #4, and #5) with no obvious bedding planes
or sub-core scale heterogeneity.
Another question regarding the representativeness of these measurements stems from
the potential for rock/water/CO2reactions to alter the permeability of the rock during the
experiments. While the composition of both rocks is dominated by quartz, minor amounts of
feldspar, calcite, siderite, and dolomite could dissolve when in contact with CO2saturated
brine and thus alter the permeability of the rock. Since geochemical reactions are not the
focus of this study, the composition of the produced water is not monitored to evaluate
the extent of mineral dissolution. However, permeability measurements before and after
the experiments demonstrate that the effect of geochemical reactions on permeability is
small. The permeability of the Berea core used for two consecutive experiments (#3 and
#4) increased from 963 to 1066 mD. The permeability of the Mount Simon core changed
from 7 mD (a separate core flooding experiment prior to these experiments) to 15.7 mD prior
to exsolution experiment #5. In all cases multiphase flow properties are calculated using
the most up-to-date permeability in corresponding experiments to minimize the influence of
possible mineral dissolution.
A final issue regarding the low relatively permeabilities observed for both phases is whether
they would persist over long time periods and under forced flow conditions. While not an
exhaustive study of this issue, we did inject a solution of CO2-equilibrated water into the Mt.
Simon core at the end of the exsolution period and found that the low relative permeability
to brine remained unchanged for more than 120 pore volumes, at which point we stopped the
experiment. It would be of great interest to further investigate whether the phase mobility
measured in flows driven mainly by exsolution and gas expansion is different from pressure
gradient driven flows dominated by viscous forces. Not only could the relative permeability
be measured under these conditions, but also information about the stability of the exsolved
CO2could be obtained. If the exsolved CO2phase establishes a very stable low relative per-
meability to water and itself that persist under a forced flow condition, it would be a favorable
feature for geological sequestration projects, since once exsolution occurs somewhere, the
exsolved gas will increase the flow resistance in that region and hamper further upward flows
or even block the flow path. It would be important to study whether such a negative feedback
exists in CO2exsolution phenomenon.
Flow rates of water and exsolved CO2are calculated from mass balances using X-ray
CT images with errors less than ±1%. The largest errors in these experiments come from
the measured pressure drop across the rock. Average pressure drops between scans are used
for relative permeability calculations despite the large variations shown in Fig. 6.Arela-
tive variation of 20% from the average value is common in pressure drop measurements
and 50% in some extreme data points. However, the errors in pressure drop do not have a
significant influence on the relative permeability curves as the relative permeability varies
over two orders of magnitude while the inaccuracy in pressure drops could only affect the
relative permeability by a maximal factor of 2. In general, measurements taken in a lower
permeability rock sample with higher withdrawal rates improve the accuracy of the pressure
gradient measurements.
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476 L. Zuo et al.
5 Conclusions
A series of exsolution experiments have been conducted to understand the phenomenon of
CO2exsolution associated with depressurization. Conclusions drawn from these experiments
are:
1. A significant amount of CO2exsolves from solution as pore pressure drops. The CO2
saturation increases up to 45% as the pressure drops from 12.41 to 2.76 MPa at a constant
temperature of 50◦C. The experiments demonstrate the possible exsolution scenario and
the occurrence of a gas phase as a CO2saturated brine moves upward.
2. The critical gas saturation during CO2exsolution is recorded as 11.7–15.5%, depending
on the depressurization rates and rock types. The recorded critical gas saturation values
are within the range summarized by Firoozabadi (2001), 1–40%, from solution gas drive
experiments with various oil/gas systems. A higher expansion rate results in a higher
critical gas saturation. This is also consistent with observations from solution gas drive
studies.
3. CO2exsolves uniformly throughout the core and there is no statistical correlation between
CO2saturation and porosity. This differs greatly from the observations of core flood-
ing experiments co-injecting CO2and water, in which a positive correlation was found
between saturation and porosity (Perrin and Benson 2010;Krause et al. 2011). The
differing observations can be understood from the differing mechanisms (exsolution vs.
flow) leading to the presence of CO2in the pore space. In the case of exsolution, CO2
comes out of solution without regard for the pore structure, whereas in multiphase flow,
pore structure is the dominant feature determining the distribution of fluids.
4. No vertical re-distribution of CO2saturation was observed during equilibration due to
the low mobility of gas phase. The expected capillary gravity equilibrium is shown not to
develop within 260h after the initial pressure drop, even in high permeability cores. This
also indicates that gas bubbles were not aggregated enough to have sufficient pressure
gradients along the vertical dimension of the ganglia to re-distribute.
5. Low water and exsolved CO2relative permeabilities are recorded in sandstone rocks.
The water relative permeability drops significantly once CO2exsolved and remained less
than 0.1 after the critical gas saturation is reached. The CO2relative permeability is very
low, 10−5to 10−3,evenwhenthexsolved CO2saturation increases to over 40%. The low
CO2mobility is consistent with observations from gas solution drive experiments which
had reported gas relative permeability of 10−4to 10−6(Tang and Firoozabadi 2003;
Tang et al. 2006). The high viscosity of oil is considered the main cause of gas mobility
reduction in the gas drive process but it is not the case in CO2exsolution as water is
much less viscous. Also no comparably large liquid phase mobility reductions have been
reported in solution gas drive experiments. The high interfacial tension between water
and CO2and the discontinuous CO2phase are the most significant contributors to the
mobility reduction in both the water and CO2phases.
6. The significant reduction in both water and CO2mobility could be favorable for storage
security by preventing CO2migration. Studies over much longer time periods than the
260 h reported here need to be carried out to determine if these low mobilities could
persist over years to decades.
Acknowledgments This study was funded by the US Environmental Protection Agency, under EPA STAR
Grant Number: 834383, and the Global Climate and Energy Project at Stanford. The authors would also like
to thank the anonymous reviewers for the many helpful comments about the manuscript.
123
CO2Exsolution and Relative Permeability Measurements 477
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