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International Journal of Greenhouse Gas Control 78 (2018) 117–124
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International Journal of Greenhouse Gas Control
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Viability of foam to enhance capillary trapping of CO2 in saline aquifers—An
experimental investigation
Abdulrauf Rasheed Adebayo
Center for Integrative Petroleum Research, College of Petroleum Engineering and Geosciences, King Fahd University of Petroleum & Minerals, Saudi Arabia
CO2 sequestration
Foam stability
Trapped gas
Electrical resistivity
Foam stabilizer
Capillary trapping is one of the quickest mechanism by which carbon dioxide (CO2) is trapped during geological
sequestration. It is also of the most immediate importance because a significant fraction of the injected CO2 can
be stored and rendered immobile in the event of a leak. Many research papers have been published in the past
decade focusing on improving capillary trapping of CO2 during geological sequestration. In this study, a different
approach was investigated, which involved the use of colloidal materials to enhance capillary trapping of CO2
during sequestration in saline aquifers. A suite of reservoir condition laboratory experiments was conducted on
some selected reservoir rock samples saturated with synthetic brine to mimic actual saline aquifers. A foaming
agent (0.025% wt. nonionic surfactant) was dissolved in the brine. Foams were then generated in the rock
samples by alternate injection of gas and brine using a coreflooding setup. An electrical resistivity measuring tool
attached to the setup was used for real-time and in-situ tracking of pore-scale events such as gas movement,
capillary trapping of gas, and the stability of the trapped gas. Both Nitrogen (N2) and CO2 gases were investigated and the results showed a tremendous increase in the amount of trapped N2 and CO2 gases when foams
were applied compared to gas injection without foams. However, low interfacial tension between CO2 and the
surfactant solution affected the viability of foams in trapping CO2. Nevertheless, the use of CO2 foam stabilizers
is promising in addressing this challenge. The methodology described in this paper can be used to test the
efficiency of a variety of CO2 foam stabilizing agents that may be developed.
1. Introduction
Gasenhanced oil recovery (EOR) is the most commonly used EOR
method. It involves the use of gases such as N2, CO2, and hydrocarbon
gas to improve oil displacement. A major setback of this method is early
gas breakthrough in the production well brought about by gravity
override or gas channeling through high permeability layers instead of
the low permeability oil zones. Because foams have plugging characteristics, they are recommended to address this setback (Bernard and
Holm, 1964; Wang, 1984). When injected into a porous rock, foams
plug some of the high permeability pores and divert the injected gas to
low permeability zones. They can be injected into a porous rock in three
major ways namely by co-injection of surfactant solution with gas at a
defined ratio, continuous foam injection, and by surfactant alternating
gas injection (SAG). SAG injection is the most preferred because of
several advantages. There is a minimal contact of CO2 and water with
surface facilities compared to dual injection or continuous foam injection where contact between CO2 and water can cause severe corrosion
of surface facilities. Furthermore, SAG has more injectivity than continuous injection and co injection. In SAG method, slugs of surfactant
solution and gas are injected alternatingly into a porous medium resulting in in-situ generation of foams in the porous medium. The generated foam traps gases in liquid films and reduces gas mobility (AlMossawy et al., 2013). The foams flow as micro gas bubbles dispersed
in the continuous liquid phase and separated by liquid lamellae. The
diameter of the micro gas bubbles are in the range of 50–1000 μm. The
liquid film separating the gas bubbles can make some gas flow path
discontinuous (Gauglitz et al., 2002). During flow in a porous medium,
foam is partitioned into three main fractions namely, trapped foam
bubbles, flowing foam bubbles, and free continuous gas phase (Persoff
et al., 1989).
The main challenge of foams in oil and gas applications is their
instability at high temperature, high pressure, and high salinity. There
is thus an extensive research interest towards improving the stability of
CO2 under such conditions. Some researchers have tested the use of
nanoparticles to improve the interfacial tension of foam lamellae (e.g.
Farhadi et al., 2016; Guo and Aryana, 2016; Emrani and Nasr-El-Din,
2017a). Some others have suggested the mixture of CO2 with Nitrogen
(e.g. Siddiqui and Gajbhiye, 2017). Others tested the use of polymers
with nanoparticles (e.g. Ali and Selby, 1986; Emrani and Nasr-El-Din,
E-mail address:
Received 5 March 2018; Received in revised form 15 July 2018; Accepted 3 August 2018
1750-5836/ © 2018 Elsevier Ltd. All rights reserved.
International Journal of Greenhouse Gas Control 78 (2018) 117–124
A.R. Adebayo
2017b). There is also an idea of generating CO2 foam by either co-injecting or alternately injecting an aqueous dispersion of nano-silica
followed by CO2 injection. The foams generated this way are believed
to have better stability than the surfactant based foams (Enick and
Olsen, 2012; Worthen et al., 2013; Yu et al., 2014). Most of these research works have focused on improving the stability of foams particularly CO2 foams and a tremendous success has been reported in this
regard. However, the methodology of testing the foam stabilizers varies
among researchers. Most importantly, the testing are not always performed in a foam flow mode in a porous media. Other challenges associated with foam applications in oil and gas exploration have been
described extensively in the literature (Rogers and Grigg, 2000;
Talebian et al., 2014).
There is a growing interest in optimizing the volume of CO2 sequestered in geological formations such as saline aquifer and depleted
oil and gas fields. Capillary trapping is one of the main mechanism by
which CO2 is trapped during geological sequestration. It is also the
quickest and of the most immediate importance because a significant
fraction of the injected CO2 can be stored in this way and rendered
immobile even in the event of a leak (Juanes et al., 2006). Other mechanisms by which the injected CO2 is trapped include solubility
trapping, structural trapping, and mineral trapping. A significant
number of research papers exist in the literature on factors that affect
capillary trapping of CO2. Niu et al. (2015) investigated the effect of
variation in pressure, temperature, and brine salinity on residual trapping of CO2 in Berea sandstones. Reynolds et al. (2014) studied the
effect of viscosity ratio and IFT under a capillary dominated flow regime of the CO2/brine system in a Bentheimer sandstone sample.
Herring et al. (2016) used X-ray tomographic imaging to study the effect of cyclic injection of CO2 with water in enhancing CO2 trapping.
Some other related experimental studies include the work of Wang et al.
(2012) and Kazemifar et al. (2016) who investigate residual trapping
behavior of supercritical CO2 using two dimensional micromodels
(quasi-2D flow). Other authors investigated through simulation the
effect of flow rate/capillarity on the multiphase flow of CO2/brine (Kuo
and Benson, 2013; Kuo et al., 2011; Spiteri et al., 2005; Juanes et al.,
2006, 2010; Kumar et al., 2005).
The ability of foams to plug some pore throats and make a significant part of the injected gas phase immobile has often been downplayed obviously due to lack of interest in gas trapping in EOR processes. However, in CO2 sequestration where trapping of the injected
gas is the major objective, this important foam characteristic can be
effectively utilized. However, the gas trapping capability of foams is
also dependent on the stability of the foams. The absence of oil and high
salinity brine in saline aquifer makes foam application in CO2 sequestration application more viable. A simulation study by Obi and Blunt
(2006) and Al Sofi et al. (2013) showed that foam injection by SAG
method improved CO2 sequestration efficiency. Few experimental
works were also carried out on foam application for CO2 sequestration
in the light of mobility control and retention of applied foam stabilizing
agents (such as nanoparticles) in porous medium (e.g. Uemura et al.,
2016; Rognmo et al., 2017). However, they did not highlight the significant capillary trapping of CO2 and the stability of the trapped CO2
associated with the process. In view of the progress made thus far in the
synthesis and application of CO2 foam stabilizing agents, there is a need
to develop a simplistic and yet accurate laboratory method to test those
agents with respect to their ability to stabilize foam and also to immobilize and permanently trap injected CO2. In this study, a new experimental procedure is introduced to help evaluate the viability and
stability of CO2 foam for enhancing capillary trapping of CO2 for geological storage in saline aquifers. The method is based on a systematic
and cyclic injection of gas and foaming agent (e.g. surfactant solution)
using core flooding set up incorporated with electrical resistivity measuring tool to track in-situ gas saturation and gas trapping. The method
allows for quantitative evaluation of both trapped and mobile gas. It is
simple, quick and inexpensive. It will also be useful for screening
Table 1
Sample properties.
surfactant and surfactant stabilizing agents for CO2 sequestration.
2. Materials and methods
Rock samples were extracted from outcrop formations that is representative of underground rock formations. Two rock types were
extracted representing high and low permeability carbonate formations, out of which a total of three cylindrical subsamples were extracted. The samples were labelled, cleaned, and characterized for
petrophysical properties as given in Table 1. The samples were cleaned
with methanol by reflux extraction using a Soxhlet apparatus. Since the
samples are outcrop samples, only methanol was used to flush the pores
at 80 °C for three days in order to remove all salt deposits that may be
present. The samples were subsequently dried in a vacuum oven at
60 °C for another two more days. They were then saturated with either
brine or a surfactant solution by vacuum saturation method. The surfactant solution was prepared by dissolving 0.025% wt. of a non-ionic
ethoxylated fluorocarbon surfactant in a synthetic brine of 54,000 ppm
salt concentration. The surfactant served as the foaming agent. A high
purity nitrogen (99.99%) and carbon dioxide (99.99%) gas were also
used as the gas phases.
A high pressure high temperature core flooding apparatus depicted
in Fig. 1 was used for this study. A hydrostatic core holder held the
sample that was pre-saturated with surfactant solution. The core holder
was then loaded in the high pressure high temperature cell capable of
applying a maximum temperature of 150 °C and a maximum confining
pressure of 15,000 psi. Two high-pressure fluid accumulators were used
to store the surfactant solution and gas at the experimental conditions.
The setup also has a syringe pump capable of injecting fluids at a
constant injection rate in the range of 0.001 cc/min–30 cc/min or a
constant injection pressure range of 10 psi–10,000 psi. A resistivity
meter was connected between the sample inlet and outlet to continuously measure the electrical resistivity across the sample. The pre
saturated samples were further flushed with either brine (for water
alternating gas, WAG, experiments) or surfactant solution (for SAG
experiments) at a rate of 0.5 cc/min under a backpressure of 1450 psi
and a confining pressure of 2200 psi. The essence of flushing was to
remove any trapped gas from the pores of the sample and in the case of
SAG, to allow all surfactant adsorption process to be completed before
the start of experiments. The oven temperature was also gradually
raised to 45 °C during the flushing process, which continued until 2
pore volume (PV) of surfactant solution had been injected. A thermodynamic equilibrium had also been attained at this point as was observed from the steady state pressure drop and electrical resistivity
measurements. SAG experiments were then conducted by starting with
gas injection at a constant rate of 0.5 cc/min until about 0.2 PV of gas
was injected after which gas injection was terminated and 0.2 PV of
surfactant solution was injected as the chase liquid to complete the first
cycle. The next cycle began by injecting another 0.2 PV of gas followed
by another 0.2 PV of surfactant solution. The cyclic injection continued
for about 5 cycles. All core flooding measurements were transmitted in
real time to a computer station at an interval of five seconds, which
allowed the experiments to be closely monitored.
International Journal of Greenhouse Gas Control 78 (2018) 117–124
A.R. Adebayo
Fig. 1. Core flooding apparatus.
attributed to the dissolution of the trapped CO2 into the flowing water
(foam decay). The dissolution and/or flow of the trapped CO2 is however at a lower rate compared to the flow rate of the mobile CO2 (Sgm).
In the last cycle (cycle 5), water injection was prolonged and CO2 saturation was monitored during the prolonged water flow. It can be seen
that the trapped CO2 continued to dissolve into the flowing water. The
first slope can be converted to the flow rate of the mobile gas (Qmg)
while the second slope can be converted to CO2 dissolution rate or flow
rate of the trapped gas when it starts to flow (Qtg ) using the relations
given in Eqs. (2) and (3). The average mobile CO2 flow rate (Qmg ) was
estimated as 0.5 cc/min, which also corresponds to the pump injection
rate of 0.5 cc/min. The trapped CO2 flow rate (Qtg ) was estimated as
approximately 0.1 cc/min, which is much lower than the pump injection rate. This means that for every 0.5 cc of brine flowing past the
pores per minute, 0.1 cc of the trapped CO2 is released or dissolved into
the flow stream.
3. Results and discussions
In the discussions of the results, foam will be referred to using the
following terminologies: trapped foam, which represents the gas bubbles that are trapped in the pores of the porous medium; flowing foam,
which represents the mobile gas bubbles; and mobile gas, which represents both the flowing foam and free gas phase. The free gas phase
emerges when some bubbles rupture (or coalesce) and release the encapsulated gases to form a free gas phase. The resistivity measurements
during coreflooding were converted to saturation values using Archie
(1942) equation shown in Eq. (1).
Sw = ⎛ o ⎞
⎝ Rt ⎠
Where Sw is water saturation, Ro is the electrical resistivity of a rock
when it is saturated with water, Rt is the electrical resistivity of the rock
when it is partially saturated with water, n is the saturation exponent of
the rock. The saturation exponent, ‘n’ was experimentally derived from
multiple measurements with a value of 1.18 ± 0.02 while the saturation values reported below are with uncertainty of ± 0.02. The uncertainty in the pressure drop measurements was also estimated as ±
0.01 psi.
The in-situ gas saturation during WAG is investigated using sample
1, which is a low permeability carbonate sample. In CO2-WAG, the
brine used did not contain the foaming agent (surfactant). The objective
is to compare the gas saturation pattern in a CO2-WAG with that in a
CO2-SAG in order to highlight the effect of foam in CO2 trapping behavior. The in-situ CO2 saturation during CO2-WAG in sample 1 is
shown in Fig. 2. As can be observed in the figure, the cumulative CO2
saturation (Sg) increased from cycle 1 to cycle 2 and remained constant
in the remaining cycles. In each cycle, CO2 saturation decreased during
water injection and continued to decrease with more water injection. It
can be observed that the saturation decrease in each cycle has two
desaturation slopes. It is interpreted that the first slope represents the
mobile CO2 foam being displaced by the water. This slope ends at a
saturation point marked as Sgt, which is interpreted to mean the trapped
CO2 saturation. The difference between the cumulative total gas (Sg)
and the cumulative trapped gas (Sgt) is the saturation of the mobile gas
(Sgm). A new desaturation slope begins from Sgt and continues to decline. This second slope is interpreted to represent the start of flow of
the trapped CO2 (i.e. secondary flow). This secondary flow is also
Qmg =
Qtg =
× Vp
1st slope
× Vp
2nd slope
Where, Vp is the sample pore volume in cubic cm (cc), Qmg is the flow
rate of the mobile fraction of the foam (cc/min), Qtg is the rate (cc/min)
at which the trapped gas is dissolved and/or dislodged into the flowing
water. In the case of foam injection in Fig. 3, Qtg represents rate of decay
of the trapped foam.
In Fig. 3, the effect of foam on gas mobility and trapping is investigated in sample 2. It can be observed in this sample that the cumulative CO2 saturation (Sg) increased significantly from Sg1 = 0.33 in
cycle 1 to Sg2 = 0.42 in cycle 2, and then further increased to
Sg3 = 0.61 in cycle 3. This value of cumulative CO2 saturation was then
maintained in the subsequent cycles (i.e. Sg4 and Sg5 = 0.61). However,
in the previous sample (Fig. 2), where a foaming agent was not added to
the brine, the cumulative CO2 saturation increased from Sg1 = 0.37 in
cycle 1 and reached the peak in cycle 2 (Sg2 = 0.54). Hence, between
cycle 1 and cycle 3, the added foam caused 82% increase in the cumulative CO2 saturation compared to 49% increase when foam was not
present. The sharp growth in the cumulative CO2 and cumulative
trapped gas is attributed to the pore-plugging characteristic of the foam.
As mentioned earlier, gas trapping is a very significant pore level
International Journal of Greenhouse Gas Control 78 (2018) 117–124
A.R. Adebayo
Fig. 2. CO2-WAG in low permeability rock – sample 1.
phenomenon during foam flow in porous media. Once foam bubbles
plug pore throats, a fraction of the foam bubbles is trapped while another fraction is displaced by the injected surfactant solution. The injected surfactant solution bypassed the trapped foam bubbles by finding
alternate flow channels. When the flowing fraction of the foam is
completely displaced by the surfactant solution, the flow channel of the
foam phase becomes discontinuous. As a result of this, the trapped foam
fraction may remain permanently trapped by the bypass mechanism. In
the event that the foam bubble collapse in the life of the CO2 project,
the encapsulated CO2 will be released as a free gas phase. The released
CO2 gas may remain trapped or become dissolved in the flow stream
during the continuous flow of underground water.
Long term CO2 trapping is hampered by the very low IFT between
the foaming agent and the CO2. Because of the low IFT, CO2 easily
dissolves into the thin liquid film that encapsulate the CO2 thereby
rupturing the foam (a process called foam decay or coalescence). As the
foam bubbles decay, some of the encapsulated CO2 dissolved in the flow
stream, while some flowed as a free gas phase. The rate of foam decay is
represented by the second slope in Fig. 3 and estimated using Eq. (3).
Foam decay rate was estimated to be approximately 0.1 cc/min. This
means that 0.1 cc of the encapsulated CO2 is being released from the
foam every minute as the trapped foam decays. The flow rate of the
mobile gas fraction of the foam was also estimated from the first slope
in Fig. 3 using Eq. (2). The average mobile gas flow rate in this experiment (Fig. 3) was 0.2 cc/min compared to 0.5 cc/min in the previous experiment (Fig. 2) where foam was absent. The difference is due
Fig. 3. CO2-SAG in low permeability rock – sample 2.
International Journal of Greenhouse Gas Control 78 (2018) 117–124
A.R. Adebayo
Fig. 4. N2-SAG in low permeability rock – sample 2.
Fig. 5. CO2 SAG in high permeability rock – sample 3.
injection method that can prevent or retard the decay of CO2 foam will
involve equilibrating or saturating the CO2 with surfactant solution
prior to injection into a porous medium.
Nitrogen foam is generally known to be very stable as reported in
the literature (e.g. Farajzadeh et al., 2009). The result of another SAG
experiment conducted on sample 2 using N2 foam at the same experimental conditions as the CO2 foam is presented in Fig. 4. It can be seen
that the cumulative N2 saturation (Sg) continued to increase from cycle
1 (0.45) to cycle 5 (0.71). Similarly, the trapped N2 saturation (Sgt) also
increased continuously from cycle 1 (0.34) to cycle 5 (0.60). In Fig. 4,
there is no second desaturation slope as was the case in CO2 flow (in
Figs. 2 and 3). This is because N2 is not soluble in the surfactant solution
at the same experimental condition. As a result, a constant trapped gas
to the effect of foam, which trapped more gas bubbles and subsequently
reduced the mobility of the flowing gas bubbles. In Fig. 3, the mobile
gas flow rate in the first cycle was approximately 0.2 cc/min in both
cycle 1 and 2 and progressively increased to 0.8 cc/min in cycle 3, 4,
and 5. The increasing flow rate of the mobile gas fraction is as a result
of the increasing free gas phase as the trapped foam undergo coalescence. Since the free gas phase is more mobile that the foam, the resultant rate of the mobile gas increased. Furthermore, gravity override
further enhances the resultant flow rate of the mobile gas. As observed
in Fig. 3, the foam continued to decay until the entire trapped CO2 was
removed from the sample and the water saturation (or surfactant solution) reached 100% again. An efficient CO2 foam-stabilizing agent
will retard the decay rate of the foam or prevent foam decay. Another
International Journal of Greenhouse Gas Control 78 (2018) 117–124
A.R. Adebayo
Fig. 6. N2 SAG in high permeability rock – sample 3.
Fig. 9. CO2-SAG in Low permeability Sample 1.
Fig. 7. Pressure drop during cyclic injection of surfactant and gas for all experiments.
Fig. 10. Comparison of N2-SAG and CO2-SAG in high permeability Sample 3.
N2-SAG experiments on a high permeability rock sample (sample 3,
with permeability of 227 mD). The cumulative gas saturation and cumulative trapped gas saturations for this sample (shown in Figs. 5 and
6) did not appear to significantly increase from one cycle to the other in
both CO2-SAG and N2-SAG as was the case in the low permeability
samples in Figs. 3 and 4. Since permeability is a direct function of pore
throat size, it can be inferred that the relatively larger pore throats in
the high permeability sample could not retain the foam bubbles for a
long time after they were plugged. Hence the foam flowed soon after
they plug the sample. Khatib et al. (1988) reported that the limiting
Fig. 8. Comparison of N2-SAG and CO2-SAG in low permeability Sample 2.
saturation ensued even after several pre volumes of surfactant injection.
A strong CO2 foam-stabilizing agent is thus required and expected to
yield a saturation profile similar to that in Fig. 4.
The effect of rock permeability on capillary trapping of CO2 and N2
using foam was also investigated by conducting another CO2-SAG and
International Journal of Greenhouse Gas Control 78 (2018) 117–124
A.R. Adebayo
of the foam.
5) The presented laboratory method showed that electrical resistivity
measurements can be used to monitor and measure capillary trapping of CO2, CO2 foam decay, solubility of CO2 in flowing brine, and
dislodgement of trapped gas in-situ and in real time during foam
flow in a porous medium and at reservoir conditions. It will also be
useful for screening surfactant and surfactant stabilizing agents for
CO2 sequestration.
capillary pressure (i.e. the capillary pressure above which foam bubbles
coalesce or rupture) in low permeability rock is higher than the limiting
capillary pressure in high permeability rock. Their observation therefore explains why foam bubbles could not sustain pore plugging in the
high permeability sample (in Figs. 5 and 6) as they did in the low
permeability samples. However, It was reported by some earlier researchers (e.g. Bernard and Holm, 1964; Raza, 1970) that foam plugging is more in high permeability rocks than in low permeability rocks.
Farajzadeh et al. (2015) also showed that the limiting capillary pressure
of foam is higher in low permeability rock than in high permeability
rocks. However, in terms of apparent viscosity, they argued that foam
apparent viscosity increases as permeability increases. Khatib et al.
(1988) tried to reconcile these differences by speculating that gas mobility can have a decreasing or increasing function of permeability
because different mechanisms affect foam stability and texture. Foam
mobility is also strongly affected by surfactant type, surfactant concentration, foam quality, flow rate and others. Siddiqui et al. (1997)
also suggested that apparent viscosity concept alone cannot explain the
variation of foam mobility with permeability. Identifying the effects of
each of this factors is critical to a successful foam application.
For reference on the pressure drop behavior during cyclic injection
of gas and surfactant, the pressure drop measurements for all the experiments described above have been combined in Fig. 7.
Figs. 8–10 show that the cumulative gas saturation and cumulative
trapped gas saturation do not increase linearly with the number of injection cycles. In the low permeability samples (sample 1 and 2), the
saturation increase is steep at the early cycles and stabilized in the cycle
where no additional foam was trapped. Further injection of gas and
surfactant beyond this cycle did not increase the cumulative and
trapped gas saturation. In the high permeability sample (sample 3), the
saturation only increased from cycle 1 to cycle 2 and remained constant
throughout the remaining cycles. The ability of the foam to cause a
continuous increase in the amount of cumulative and trapped gas as the
injection cycle is increased is a function of the strength and stability of
the foam, and the capillary pressures in the rock sample. A stronger
foam will invade and displace the surfactant solution from the smaller
pores, which have higher capillary pressures.
The author is grateful to the College of Petroleum Engineering and
Geosciences at the King Fahd University of Petroleum & Minerals for
the financial support under project number SF 17002. The author also
gratefully acknowledges the fruitful discussions with Dr. Mazen Kanj of
the center for integrative petroleum research. Rahul Salin Babu is also
acknowledged for his assistance in the experiments. Finally, the anonymous reviewers are appreciated for their insightful comments, which
improved the quality of this paper.
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4. Conclusions
A suite of laboratory experiments has been presented to evaluate the
prospect of using foam to enhance capillary trapping of CO2 during
geological sequestration. The effect of both N2 and CO2 foams on capillary trapping of gas during water flow in high and low permeability
samples was investigated. The following conclusions are made from this
1) Foams can plug a significant fraction of the pores in a porous
medium, which can subsequently cause a significant trapping of the
injected gas. The ability of the foam to plug rock pores is a function
of the foam strength and the capillary pressures in the rock. It was
shown in this study that foam bubbles are stronger in low permeability samples than in high permeability samples, a confirmation of
the report of Khatib et al (1988). However, this does not negate the
fact that foam bubbles first plug high permeability rock formation
and then subsequently divert flow into low permeability zones.
2) Foams enhance capillary trapping of both N2 and CO2. However,
CO2 foams are short lived because they are unstable. Their instability is caused by the high solubility of CO2 bubbles in the liquid
film encapsulating them.
3) The use of CO2 foams stabilizers will increase the strength of the
foam bubbles and enhance capillary trapping during sequestration.
4) Cumulative gas and cumulative trapped gas saturation increased
with the number of injection cycle. However, they do not increase
linearly but somewhat similar to a logarithmic function. The extent
of increase in the gas saturation depend on the strength and stability
International Journal of Greenhouse Gas Control 78 (2018) 117–124
A.R. Adebayo
Siddiqui, M.A., Gajbhiye, R.N., 2017. Stability and texture of CO2/N2 foam in sandstone.
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