© 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

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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

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