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© JCRM All rights reserved.
Volume 7, Number 1, August 2011, pp.25-31
[Issue paper]
A new flow pump permeability test applied on supercritical CO2 injection to
low permeable rocks
Yasuhiro MITANI*, Ardy ARSYAD*, Hiro IKEMI*, Kataru KUZE*, and Shiro OURA*
* Department of Civil and Structural Engineering, Graduate School of Engineering, Kyushu University, Fukuoka 819-0395, Japan
Received 08 12 2010; accepted 02 08 2011
ABSTRACT
This study aims to investigate the permeability and storativity characteristics of sedimentary rocks injected with supercritical
CO2. Recent development of CO2 storage in sedimentary rocks requires knowledge of CO2 behavior in deep underground
characterized as geological layers with low hydraulic gradient, high pressure and high temperature. Therefore, we developed a
new flow pump permeability test, so that the test will be able to reproduce similar physical condition of deep underground where
CO2 behaves in supercritical state. The injection of supercritical CO2 was conducted on a cored Ainoura sandstone saturated with
water. A numerical simulation based on the theoretical analysis of flow pump permeability test incorporating Darcy’s law for two
phases flow was also undertaken in order to interpret the experimental results especially to examine the relative permeability and
saturation of the saturated water and supercritical CO2 including the specific storage of the sandstone during supercritical CO2
injection. It is observed that, supercritical CO2 apparent to spend a very long time in flowing through the sandstone pores. The
specific storage of the sandstone increases due to the displacement of the saturated water by incoming supercritical CO2. Very slow
process of supercritical CO2 migration in the sandstone pores might be caused by the low hydraulic gradient employed in the
experiment and the effect of capillary pressure functioning as such capillary trapper. These results indicate low permeable rocks
could become an effective storage of supercritical CO2. This study also shows that a new developed flow pump permeability test
has been able to work with supercritical CO2 injection to low permeable rocks.
Keywords: supercritical CO2, flow pump permeability test, low permeable rocks, permeability, specific storage
1. INTRODUCTION
It is generally believed that increase of atmospheric CO2
emission has become a major contributing factor of a gradual
raise of the earth’s temperature, popularly known as global
warming. Recently, the methods of reducing atmospheric CO2
emission have been developed including carbon capture and
geological storage (CCS). The CCS is a process of separating
CO2 emission from large stationery sources such as industrial
plants and power stations, compressing to supercritical state
and then transporting via pipelines to suitable geological
formations such as unmineable coal beds, deep saline aquifer,
and depleted oil and gas reservoirs as long-term sequestration
of CO2 (IPCC, 2005). So far, the CCS has been considered as
the most promising option to reduce atmospheric CO2
emission among the others options such as mineral
carbonation, which is costly to undertake, and ocean storage
that would have severe impact on ocean environment (IPCC,
2005).
The CCS has been developed based on the experience of
CO2 injection in enhanced oil recovery (EOR) commonly
applied in petroleum industries. Since oil and gas reservoirs
remain available worldwidely, though unevenly distributed to
many countries, the CCS is still prospective to be
implemented in near future. In Japan with lack of oil and gas
reservoirs, however, the investigation of alternative
geological formation as CO2 storage is necessary. Therefore,
sedimentary rocks are currently investigated as potential
geological CO2 storage. This requires knowledge of
sedimentary rock capacity for storing CO2 (Bachu et al.,
2007) and the examination of its reliability with respect to
potential environmental impact (Benson, 2005; Lei and Xue,
2009).
A number of researchers have conducted the investigation
of CO2 behavior in sedimentary rocks in a core scale model.
Suekane et al. (2005) examined the supercritical CO2
behavior in a glass bead as porous media containing water by
using magnetic resonance image (MRI). Xue and Lei (2006)
investigated CO2 migration in sandstone by utilising P-wave
26 Y. MITANI et al. / International Journal of the JCRM vol.7 (2011) pp.25-31
velocity measurement. Later, Shi et al. (2007, 2009)
investigated CO2 migration in water-saturated sandstone by
applying seismic monitoring and computerized tomography
(CT) scan. However, seismic method may not be able to
reasonably image the distribution of CO2 and to estimate CO2
saturation accurately due to its fundamental physical
limitation (Lumley et al., 2008).
In this study, we developed a new flow pump
permeability test to investigate the behavior of supercritical
CO2 in low permeable rocks. The method was introduced by
Olsen et al., (1985), which has been able to determine
permeability characteristics of low permeable rocks (Zhang et
al., 1998). However, several developments are needed in
order to enhance the method’s ability of creating similar
physical conditions of deep underground for storing CO2,
expected to located in the depth of 800 – 1200 meters
(Johnson et al., 2004), where CO2 performs as supercritical
fluid. Moreover, the development of the method is needed so
that the method can work within very low hydraulic gradient
due to the groundwater flow in deep underground is generally
laminar (Bachu et al., 1994).
2. A NEW DEVELOPED LABORATORY SYSTEM OF
FLOW PUMP PERMEABILITY TEST
Physical characteristic of CO2 depends on its temperature
and pressure. In several existing CO2 injection fields, it is
found that the temperatures and pressures of CO2 when
injected to the fields are beyond the critical point of 31.1°C
and 7.39 MPa (Figure 1) indicating CO2 acts in supercritical
phase (Sasaki et al., 2008). Therefore, the new laboratory
system of flow pump permeability test must be able to
reproduce such similar physical condition in which the phase
of supercritical CO2 can be maintained during the experiment.
Figure 1. CO2 phases in the existing CO2 injection fields
(After Sasaki et al., 2008).
2.1 Temperature controllers on experiment equipments
The main problem in the laboratory system in dealing
with supercritical CO2 is the vulnerability of the system to the
effect of external and internal temperature. This would have
consequence of unstable CO2 phase during the experiment.
Therefore, the entire laboratory system was isolated from
external temperature change. All the equipments were placed
in a thermostatic chamber controlled with air conditioning
(Figure 2). In case of internal temperature effect induced by
laboratory measurement heat, the pressure vessels and pipes
including syringe pumps were double insulated and
connected to hemathermal circulation tanks and bath
temperature controller, so their temperature changes can be
minimized as low as possible (Figures 3 and 4). Furthermore,
the temperature of rock specimen was also controlled with
heater bars and thermo coupler (Figures 6). A remote control
system was set up to monitor and control the syringes pump
from outside laboratory. Data acquisition system and a data
logger connected to the computer outside the chamber were
installed so that the measurement can be undertaken remotely
and the temperature changes due to human disturbance can be
avoided (Figure 5).
Figure 2. Thermostatic Chamber.
Figure 3. (a) Bath temperature controller and (b) hemathermal
circulation tank.
Figure 4. (a) Syringe pumps and (b) hemathermal circulation
controller.
Figure 5. Schematic diagram of the new developed flow
permeability test.
(a) (b)
(a) (b)
0
2.5
5
7.5
10
12.5
15
17.5
20
-130 -80 -30 20 70 120
Temperature (C)
Pressure (MPa)
supercritical state
Alberta, Canada
Gippsland Australia
Nagaoka, Japan
Sleipner, North Sea
Liquid Phase
Gas Phase
Solid Phase
Critical point
Triple point
Y. MITANI et al. / International Journal of the JCRM vol.7 (2011) pp.25-31 27
2.2 Confining and pore pressure on a rock specimen
The rock specimen used in the experiment was Ainoura
Sandstone obtained from Sasebo, near Nagasaki Prefecture
Japan. The sandstone, with the dimension of 300 × 300 × 150
mm, was drilled and cut to be a cylinder. By horizontal
milling machine, the specimen was shaped on the top and
bottom edge even with surface grinding. Its final dimension
is a cored cylinder with a 50 mm diameter and 100 mm high
following the ISRM standard that the height of rock specimen
is twice to its diameter. The porosity and specific gravity of
the sandstone is 12.6% and 2.88 respectively. Strain gauge
devices were installed to measure lateral and longitudinal
strain of the specimen during CO2 injection (Figure 6a).
However, due to this installation, fluid leakage might be
occurred. Therefore, silicon was coated with 5 mm thickness
on the opening points of the rubber sleeve that cover the rock
specimen (Figure 6b). The specimen was placed in a Tri-axial
test container (Figure 6c).
(b) (c)
Figure 6. (a) Schematic diagram of the rock specimen; (b)
rock specimen with thermo coupler, heater, temperature
sensors; (c) Tri-axial container.
2.3 Initial condition set up in the experiment
Before injecting CO2 to the rock specimen, initial
conditions of temperatures, confining and pore pressure were
generated. The temperature of syringe pump, pipes and
pressure vessels were loaded at 35°C, 36°C, and 38°C
respectively. Those temperatures were maintained by a tank
temperature controller connected to the pipes, and
temperature circulation controller linked to the triaxial
container-syringe pumps. After the temperature becoming
stable, the confining pressure of 20 MPa and the pore
pressure of 10 MPa were applied on the specimen. Purified
water was injected to the specimen with the flow rate of 3
µl/min. The hydraulic pressures across the specimen were
measured using the pressure gauges installed in the upstream
and downstream of the rock specimen. After reaching a
steady state, the intrinsic permeability of the specimen can be
determined, accounted for 2.31×10-17 m2, on the basis that the
viscosity of water at the temperature of 35°C is 7.195x10-4
Pa.s.
3. INJECTION OF SUPERCRITICAL CO2
Supercritical CO2 was injected to the rock specimen with
the same initial condition and flow rate of the pure water
injection. The upstream and downstream pressures were
again measured during the injection. The measurement result
shows that the upstream and downstream pressure increase
gradually over the time (Figure 7). It is also shown that the
differential pressure between the upstream and downstream
over a certain time of period appears to increase transiently
and then reaching a steady state. Afterward, it decreased to a
certain level (Figure 8). Based on its pattern, the differential
pressure performs three stages of behavior. First, at the
beginning of the injection, the differential pressure increased
sharply, and then reached a constant level (Stage 1). Second,
the differential pressure increase again and then being
constant from the period of 175 to 225 hours (Stage 2).
Finally, the differential pressure decreased gradually until the
end of experiment at 565.9 hours (Stage 3).
9
10
11
12
13
14
15
16
0 100 200 300 400 500 600
Upstream
Downstream
Figure 7. Measured downstream and upstream hydraulic
pressures during supercritical CO2 injection.
0
0.05
0.1
0.15
0.2
0.25
0.3
0 100 200 300 400 500 600
Experiment
Confirmed Experiment
Time (Hours) Figure 8. Measured differential hydraulic pressures across the
rock specimen.
(a)
3
2
1
Time (hours)
28 Y. MITANI et al. / International Journal of the JCRM vol.7 (2011) pp.25-31
4. NUMERICAL ANALYSIS USING THE FLOW PUMP
PERMEABILITY TEST ANALYSIS FOR TWO
PHASES FLOW
We conducted a numerical analysis to investigate
permeability characteristics of the rock specimen during the
CO2 injection. The flow pump permeability test was
introduced by Olsen et al. (1985) due to such conventional
methods (the constant and falling head test) is time
consuming in measuring the permeability of low permeable
rocks. Theoretical analysis of the flow pump permeability test
was developed by Morin and Olsen (1987) by analysing the
transient response obtained from the test to determine
permeability and storage capacity of rock. Later, Esaki et al.
(1996) and Song et al. (2004) improved the accuracy of the
analysis by incorporating the compressibility of pump
equipment.
In this study, the mathematical model of flow pump
permeability test incorporating Darcy’s law for two phases
flow was developed. The mathematical expressions of the
model can be specified as following:
Governing equation
02
2
=∂∂
+
−∂∂
t
H
gKkk
S
z
H
w
ww
nw
nwnw
s
µρ
µρ
(1)
Initial condition
( ) 00, =zH Lz ≤≤0 (2)
Boundary conditions
( ) 0,0 =tH 0≥t (3)
( )
KAkk
tQ
z
tLH
w
w
nw
nw
i
+
=∂
∂
µµ
)(, 0>t (4)
In which
( ) ( )tLHCdtqdttQ e
tt
i ,
00
−= ∫∫
( ) ( )t
tLHCqtQ ei ∂
∂−=
,
So, the Eq. (4) can be expressed as
( )( )
KAkk
t
tLHCq
z
tLH
w
w
nw
nw
e
+
∂∂
−=
∂∂
∴
µµ
,
, 0>t
We assumed that total flow entering the rock specimen is
the accumulation of CO2 flow and saturated water flowing at
time t minus the volume absorbed within the compressible
flow pump test system per unit time interval. This system
includes the entire space of the flow pump cylinder, the space
in the lower pedestal, and the tubing connecting the flow
pump to the test cell. During the flowing CO2 into the rock
specimen, gravitational effect and chemical process may
occur are neglected.
Here,
H = hydraulic pressure at z in the specimen, Pa,
z = vertical distance along the specimen, m,
K = intrinsic permeability of the specimen, m2,
t = time from the start of the experiment, s,
kw = relative permeability of water,
knw = relative permeability of CO2,
L = the length of the specimen, m,
µw = dynamic viscosity of water, Pa.s,
µnw = dynamic viscosity of CO2, Pa.s,
ρw = density of water, kg/m3,
ρnw = density of CO2, kg/m3,
g = gravitational acceleration, ms-2,
A = the cross-sectional area of the specimen, m2,
Qi(t) = flow rate into the upstream end of specimen at
time t, m3/s,
Ce = storage capacity of the flow pump system, i.e., the
change in volume of the permeating fluid in
upstream permeating system per unit change in
hydraulic head, m3/MPa, and
Ss = specific storage of specimen, m-1
To solve the mathematical model, Laplace transform was
employed, so the model can be expressed as follows:
( )
( )
+
+
+−
−
+
= ∑∞
=0
2
2
2
11cos
sinexp
2n
nnn
nn
sw
ww
nw
nwnw
w
w
nw
nw
i
LLL
ztS
gKkk
L
z
KAkk
LQH
δδββδβ
ββµρ
µρ
µµ
(5)
In which δ = 0.101792Ce/(ASs) and βn are the roots of the
following equation
( )δβ
β2
1tan =L (6)
The hydraulic gradient distribution within specimen can
be further derived by differentiating the Eq. (5) with respect
to the variable z:
( )( )
( )
+
+
+−
−
+
= ∑∞
=0
2
2
2
11cos
cosexp
21
,n
nnn
nn
sw
ww
nw
nwnw
w
w
nw
nw
i
LLL
ztS
gKkk
LKA
kk
LQtzi
δδββδβ
ββµρ
µρ
µµ
(7)
It is impossible to determine analytically the parameter
knw, kw, Ss and Ce in the Eq. (7) based on the experimental
results of hydraulic gradient across the specimen versus time.
Therefore, in order to estimate those parameters, the
parameter identification method was employed as this method
is generally used in system engineering (Astrom and Eykhoff,
1971; Pister, 1978; Liu and Yao, 1978; Weng and Zhang,
1991; Esaki et al. 1996). The parameters can be
back-calculated by minimizing the following error function:
( )( ) ( )2/1
1
2
,,,*,,
−= ∑
=
M
j
jCSkkj tzitzieswnw
ε (8)
The error values, ε, is a least squares reduction of the
discrepancy between the M hydraulic gradient i(z,ti)*
measured at time tj and the corresponding data i(z,ti) obtained
by the theoretical analysis. The minimization algorithm
employed in solving the Eq. (8), which is non-linear function
of knw, kw, Ss, and Ce, requires mathematical iterative
procedures (Esaki et al., 1996).
As relative permeability is a function of saturation, the
Y. MITANI et al. / International Journal of the JCRM vol.7 (2011) pp.25-31 29
saturation of CO2 and saturated water flowing through the
rock specimen can be determined by utilizing a correlation
model of relative permeability and saturation such as Van
Genuchten (1980) and Corey model (1954). The
determination of CO2 and the saturated water saturation based
on the obtained relative permeabilities in the numerical
analysis could become alternative approach to indirect
saturation measurement in the rock specimen instead of using
CT scan, which is costly to undertake in the developed
laboratory system. In this study, the saturation of CO2 and the
saturated water were estimated based on Van Genuchten
model, as following:
[ ]( )2
/111
−−=
mme
aew SSk
(9)
( ) ( )wrwrwe SSSS −−= 1/ (10)
( ) ( ) mme
benw SSk
2/111 −−= (11)
Se is effective saturation, Sw is water saturation, Swr is residual
saturation of water (0.05), a and b are rock specific
parameters, assumed to be 1/2 and 1/3 respectively, m is the
shape factor of specimen of 0.77. Such rock parameters used
in this study are typical parameters for two phases flow
simulation for supercritical CO2 injection into subsurface
condition (Helmig, 1997, Sasaki et al., 2008). These
parameters also have shown a good fit with recently
published relative permeability for several sandstone
formations in Alberta with a range of porosity and
permeability (Bennion and Bachu, 2005, 2006).
The numerical simulation result is shown in Table 1.
Generally, the simulated hydraulic gradient is well agreement
with the experimental results (Figure 9). A small peculiar
result of the experimental hydraulic gradient in the injection
period of about 180 hours is neglected as a confirmed
experiment conducted later shows similar tendency with the
numerical results, refers back to Figure 8.
It must be worthy to investigate the accuracy of the
numerical simulation results. This is because the parameters
obtained from the numerical simulation might yield poor
results (Zhang et al., 2000). As Tokunaga and Kameya (2003)
suggested that the numerical simulation is reliable if the ratio
of the obtained storage capacity of the pump to the obtained
specific storage of the specimen is lower than 0.3. In our case,
it is found that the ratio, r, between the storage capacity of the
pump to specific storage of the specimen is very small,
accounted for 0.009 which is clearly less than the maximum
margin of 0.3. Thus, the specific storage obtained from the
numerical simulation is acceptable.
5. DISCUSSION
Based on the numerical simulation results, it can be
suggested that, at the beginning of the CO2 injection (0 – 60
hours injection or Stage 1), the differential pressure between
the upstream and downstream of the rock specimen increase
transiently and reaching a steady state. At this period, the
relative permeability of CO2 is very low while that of water is
still high (Figure 10). It is indicated that the saturated water
still dominates the rock specimen pores whereas just a few
fractions of CO2 can reach the rock specimen (Figure 12).
This would imply that CO2 is very slow to penetrate the rock
specimen pores. CO2 flows through a syringe pipe that
connects the syringe pump and the rock specimen. The
syringe pipe contains of water prior to CO2 injection. When
CO2 is injected, it flows and displaces the water in the pipe
before reaching the specimen. The interaction between CO2
and water in the syringe pipe may result in such dissolution of
CO2 into water. As a consequence, the pressure of CO2
towards the rock specimen is interrupted leading to such slow
process of CO2 penetrating the rock specimen pores. This
result is similar to what Sasaki et al., (2008) found that the
injection pressure of CO2 would drop a little bit when CO2
dissolves to saturated water. Xue and Lei (2006) suggested
that dissolution of CO2 into water will reduce the viscosity of
CO2 resulting in such energy lost and slowdown penetration
in rock. This result would be significant in understanding the
effect of groundwater on the CO2 migration in low permeable
rocks.
0
50
100
150
200
250
300
0 100 200 300 400 500 600
Measured
Simulated
Time (hours) Figure 9. Measured and simulated hydraulic gradient across
the specimen versus time.
Table 1. Parameters obtained from the numerical simulations
Time
(hours)
Ce
(m3/MPa)
Ss
(1/m)
kw knw
0 1.0×10-6 5×10-4 1 0
60 1.0×10-5 5×10-4 0.74 0.0042
225 1.1×10-5 3×10-2 0.713 0.032
275 1.1×10-5 9.8×10-2 0.633 0.057
350 1.1×10-5 1.9×10-1 0.54 0.087
450 1.1×10-5 1.9×10-1 0.45 0.119
600 1.1×10-5 1.9×10-1 0.42 0.163
In Stage 2 (60 – 220 hours injection), the differential
pressure increased sharply again before leveling off. In this
period, the relative permeability of the CO2 increases whereas
that of the water decreases (Figure 10). The result indicates
that, at this period the CO2 has been able to breakthrough the
rock specimen and displace the water in the pores. As the
CO2 begins to displace the water, the pores seem to retain the
water until the CO2 pressure can exceed such pore-water
holding pressure. This might be well agreement to what
Richardson et al. (1952), and Dana and Skoczylas (2002)
suggested as capillary end effect or capillary pressure effect,
which occurs on two phases flow in sandstone. As long as the
CO2 pressure can overpass the capillary pressure, more CO2
can penetrate and more water fractions displaced out from the
pores (Figure 12). It can be suggested that capillary pressure
1
2 3
30 Y. MITANI et al. / International Journal of the JCRM vol.7 (2011) pp.25-31
may become barrier for CO2 to flow due to very low
hydraulic is expected to occur in deep underground.
In Stage 3 (220 – 600 hours), the differential pressure
decreases gradually until the experiment ended due to the
increasing hydraulic pressure in the specimen approaching
the confining pressure. In this period, the CO2 seems to take
longer time to achieve steady state. Until the end of the
experiment, the CO2 saturation is estimated at around 45%.
Water fractions are still trapped inside the specimen pores
while the CO2 continuing to flow through specimen pores
(Figure 12). This is due to very small flow rate of CO2
injected to the rock specimen. In addition, low viscosity of
CO2 compared to that of the water may yield fingering on
front flow of CO2 causing such very slow penetration.
The numerical simulation also shows the specific storage
of the rock specimen and the compressible storage of the
pump during the CO2 injection increase (Figure 11). It is clear
that the specific storage increase significantly in the Stage 2,
which is the period of CO2 begin to displace the water in the
pores. The increase of the specific storage of the specimen is
due to the density of CO2 lower than that of the saturated
water. As CO2 displacing the saturated water in the pores,
larger volume of the pores can be occupied by CO2. As a
result, the capacity of the specimen storing the CO2 becomes
larger. The injection of CO2 to the rock specimen also
enlarges the compressible storage of the pump employed in
the experiment. This is because CO2 in supercritical state is
more compressible than the saturated water leading to the
larger increase of volume of the pump piston as CO2 injected
to the rock specimen.
6. CONCLUSIONS
This paper has investigated the behavior of supercritical
CO2 injected to a cored sandstone using a new developed
flow pump permeability test. Numerical simulations were
performed based on theoretical analysis of the flow pump
permeability incorporating Darcy’s Law for two phases flow
in order to interpret the experimental results especially to
determine the permeability and storativity of the sandstone
injected with supercritical CO2. It has been observed that,
CO2 in supercritical state apparent to be time consuming in
flowing through the sandstone pores. During the CO2
injection, the relative permeability of water decreases
whereas that of CO2 increases. In addition, the specific
storage of the rock specimen and the compressible storage of
the pump increase driven by the displacement of the saturated
water to CO2 in the sandstone pores. Very slow process of the
displacement is caused by very low hydraulic gradient
employed in the injection and the capillary pressure that
functions as a trapper for CO2. These results indicate low
permeable rocks could become an effective geological
storage for supercritical CO2. This study also shows that a
new developed flow pump permeability test has been able to
work with supercritical CO2 injection to low permeable rocks.
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0
0.2
0.4
0.6
0.8
1
0 100 200 300 400 500 600
Van Genuchten model
Van Genuchten model
Corey model
Corey model
Time (Hours)
Supercritical CO2
Saturated water
Figure 10. Relative permeabilities of the saturated water and
CO2 versus time during CO2 injection.
0
0.05
0.1
0.15
0.2
0
2 10-6
4 10-6
6 10-6
8 10-6
1 10-5
1.2 10-5
0 100 200 300 400 500 600
Ss
Ce
Time (Hours)
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