1. 1
PAPER 2007-119
Performance of CO2 Huff-and-Puff
Process in Fractured Media
(Experimental Results)
F. TORABI, K. ASGHARI
University of Regina
This paper is to be presented at the Petroleum Society’s 8th Canadian International Petroleum Conference (58th Annual Technical
Meeting), Calgary, Alberta, Canada, June 12 – 14, 2007. Discussion of this paper is invited and may be presented at the meeting if
filed in writing with the technical program chairman prior to the conclusion of the meeting. This paper and any discussion filed will
be considered for publication in Petroleum Society journals. Publication rights are reserved. This is a pre-print and subject to
correction.
Abstract
In this study, the performance and efficiency of CO2 huff-
and-puff process for improving oil recovery and subsequent
storage of CO2 in fractured porous media is examined and the
results of experimental tests are presented. The experimental set
up consisted of a high-pressure stainless steel cell made
specially to hold a cylindrical core with spacing around it to
simulate fractures surrounding matrix. The matrix was
saturated with normal decane, which was used as oil during
these experiments. Total six sets of huff-and-puff experiments,
using CO2 as solvent, were conducted for pressures of 250, 500,
750, 1000, 1250, and 1500 psi. Each set of the huff-and-puff
experiments were conducted by injecting CO2 in fracture system
surrounding the core (injection step). Then, the system was
shut-in for a period of 24 hours to allow CO2 to diffuse from
fracture into the oil in matrix (soaking period step). At the end
of soaking period, the pressure was released and the oil
production was measured (production step). The above cycle
was repeated until no more oil was produced. The results
obtained show that CO2 huff-and-puff process improves the oil
production from fractured reservoirs, significantly. These
results also indicate that the oil recovery is higher for huff-and-
puff experiments conducted at higher pressures.
Introduction
Implementing huff-and-puff processes, through utilizing
various miscible and immiscible solvents, for improving oil
recovery from oil reservoirs has been tested by various
researchers through laboratory investigations, as well as field
tests. Most of the works reported, either in the laboratory or
field trials, are limited to the conventional single porosity
reservoirs. Cyclic CO2 injection was originally proposed as an
alternative to cyclic steam stimulation for heavy oil reservoirs.
However, it has found wide applications in light–oil reservoirs
(1)
. An immiscible CO2 huff-and-puff pilot project was carried
out by Turkish Petroleum Corporation in Camurla Field that has
a heavy crude oil of 11-12 o
API (2)
.The laboratory tests,
reservoir studies, and design of injection and production
facilities were done by IFP (Institute François du Petrole). The
results of this early application of huff-and-puff immiscible CO2
project were not economical in all stages due to the lack of
equipments and some field problems. However, significant
reduction in the oil viscosity and interfacial tension resulted in
improving oil recovery in some stages of this project. Also,
there was an evidence of dissolution of calcium carbonate by
PETROLEUM SOCIETY
CANADIAN INSTITUTE OF MINING, METALLURGY & PETROLEUM
2. carbonic acid which resulted in improving permeability.
Another study by Monger and Coma showed that waterflood
residual oil can be displaced by CO2 huff-and-puff process in a
light crude oil Berea core (3)
. They also pointed out that, there is
less sensitivity to the soak period, and operating at the
minimum miscibility pressure (MMP) is not critical to the
ultimate recovery. Later on, an evaluation of CO2 huff-and-puff
tests on 28 wells in Texas by Haskin and Alston confirmed that
soak time period has not significant impact on the oil recovery
under immiscible condition (4)
. It has been shown that oil
saturation is one of the main parameters influencing the ultimate
oil recovery in immiscible CO2 cyclic injection. This is mainly
due to the fact that, below MMP, a small amount of CO2 is
dissolved in the oil. Therefore, CO2 must contact a large amount
of oil for better recovery (5)
. The results of a study in the Crooks
Gap Field, Wyoming, show that during huff-and-puff
immiscible CO2 injection, the potential of scale formation is
higher than for the miscible case (6)
. This is mainly due to the
fact that under immiscible conditions more CO2 is available for
dissolving into the water and forming carbonic acid (7)
.The
carbonic acid then dissolves minerals such as calcium and
enhanced permeability. However, during production as pressure
drops and CO2 is released from the solution, calcium carbonate
could precipitate in the reservoir or near the wellbore, leading to
blockage of some of the pathways available for flow of oil and
its production. An evaluation study of a South Louisiana CO2
huff-and-puff test has shown that, such a process can
significantly alter the saturation distribution and reduce water
cut in wells that are producing substantial amounts of water (8)
.
In the watered-out horizontal wells, it has been shown that shut-
in time and total gas injection volume have less impact on the
ultimate recovery compare to injection rate and injection time
during huff-and-puff process (9)
. This is slightly in contrast with
the results presented by Hosking et. al which concluded that
larger CO2 volumes recover more incremental oils. However,
However, the results reported for horizontal wells are based on
a parametric study and didn’t address the type of gas that was
used in huff-and-puff process. Gas relative permeability is
another parameter that plays an important role in oil recovery
under CO2 huff-and-puff process (10)
. Overall, selecting the right
reservoir for implementing CO2 huff-and-puff process is a
crucial step, and there are several studies addressing the
screening criteria for selecting suitable reservoir candidates for
CO2 huff-and-puff projects (11,12)
.
From the results of different studies, it can be concluded
that the mechanisms contributing to improve the oil recovery
under CO2 huff-and-puff injection include: reduction in oil
viscosity and interfacial tensions, oil swelling, vaporization of
lighter components of oil by CO2 and reduction of relative
permeability to water and gas during the production step, due to
hysteresis (13)
.
As mentioned earlier most of the above studies are limited
to conventional non-fractured porous media and there is a
serious lack of studying the potential and performance of using
miscible/immiscible CO2 for implementing huff-and-puff
process in fractured reservoirs. This paper presents the results of
an experimental study on the feasibility of cyclic injection of
CO2 in a fractured laboratory set up under both immiscible and
miscible conditions. Also, effects of initial oil in place and
matrix permeability have been investigated. Results indicate
that, CO2 miscible or near miscible huff-and-puff process can
improve the ultimate oil recovery in fractured system containing
light oil, significantly. In addition, matrix permeability has a
great impact on the recovery factor.
Laboratory Study
Materials
Two Berea cores of the same size with different
permeabilities were used in this experiment. The permeabilities
of these cores were measured using a PDK-400 laser
permeameter at 10 different points. The average permeabilities
of these cores were determined as 100 md and 1000 md. Table 1
presents dimensions and other characteristics of the cores used
during this study. A stainless steel high-pressure core holder
was made to keep the core in place. There is abut 0.5cm space
between inner diameter of the core holder and the core. This
spacing represents fractures surrounding the matrix. This space
is slightly more at above and bottom of the core allowing
installation of two Teflon made holders which helps to keep the
core vertically in the centre. Both holders were made in such
away to allow fluid flow between internal wall of the core
holder and external surface of the core as well as at the top and
bottom. Also, inside the core-holder caps were conical shape to
allow all fluids drain during production.
Pure normal decane and 99.99% pure carbon dioxide were
used as oil and injected solvent, respectively. The viscosity and
density of nC10 were 0.99 cP and 0.73 gr/cc at room conditions,
respectively. Experiments were conducted at constant
temperature of 35 o
C. Prior to the experiments, the first contact
miscibility pressure (FCM) and multi-contact miscibility
pressure (MMP) of CO2-nC10 system were determined using
CMG-WINPROP™ software. According to the simulation
results, first-contact miscibility pressure of these two fluids at
35 o
C is 1062.5 psi, while multi-contact miscibility can be
achieved at 1058.4psi. In addition, changes in viscosity and
density of nC10 as a function of amount of CO2 dissolved in the
oil was investigated under miscible condition. Figures 1 and 2
show variations in viscosity and density of nC10 as a function
of dissolved CO2. As it is shown, CO2 injection reduces the
viscosity of nC10, significantly. However, density of nC10
slightly increases after CO2 injection at miscible conditions. It is
expected that the fluid in fracture system will be denser that the
oil at operating pressures greater than MMP. Under these
conditions, it is expected to have less recovery at pressures
exceeding MMP for this system. As part of this study the effect
of PVT characteristics of oil/CO2 system on the performance of
CO2 huff-and-puff process in fractured media has been studied,
and results are reported.
Experimental Set-up
Figure 3 shows the schematic of experimental set-up used in
this study. The setup consists of 2 syringe pumps, one CO2
cylinder, highly sensitive digital pressure gauge connected to a
computer, temperature controller, back pressure valve,
production separator, and high-pressure stainless steel core
holder. A separate vacuum setup was used to vacuum and
saturate the core prior to each experiment. Since the maximum
pressure of the CO2 cylinders is 900 psi, two high-pressure
ISCO syringe pumps, 500cc each, were used to pressurize the
system at the beginning of each run. The core holder was placed
on a stand in a temperature controlled air-bath. To ensure
uniform temperature inside the air-bath, two fans were installed
at two corners of the air-bath. A high-pressure production
separator was used to collect the production from the bottom of
the core holder, while the pressure of the cell was decreased
slowly from the top.
2
3. Experimental Procedure
Prior to conducting each experiment at each pressure under
investigation, the core was dried, weighed and vacuumed for 3
days. After that, it was saturated with nC10 and allowed to
remain under saturation for 24 hours for maximum saturation.
Then, the core was removed and weighed and returned to the
core holder immediately. The weight of saturated core was
compared with the weight of dry core and oil in-place was
calculated using the value of the density of nC10. This was
done to ensure that the core had reached to its maximum
saturation. Since experiments were conducted at six different
pressures for each core, above procedure was repeated 6 times
for each core. Comparison of the results obtained for saturating
the core indicated that the results were almost the same (less
than 0.25 percent difference among six saturations). All
saturation processes were done at 35 o
C and this temperature
was kept constant throughout all stages of experiments.
The first set of experiments started with Core B,
permeability and porosity 100 md and 17.67%, respectively.
After the core was saturated with nC10, the core was allowed to
produce under gravity drainage for 24 hours at atmospheric
pressure. It was observed that there was no production under
these conditions. This was mainly because the capillary pressure
was higher than the fluid head inside the core.
As impurities might affect the results of these experiments,
in each stage, initially air was removed from the system by
introducing CO2 into the cells at very low flow rate to displace
the air from entire system. The injection rate was controlled to
avoid force displacement of fluid from the core. After that, CO2
was introduced into the fracture until it reached 250 psi. To
reduce the Joule Thompson effect and sudden reduction in gas
temperature during injection, a heating wrap was placed around
injection line. (See Figure 3). Then inlet valve was closed
allowing the core to produce under gravity drainage at 250 psi
for 24 hours. After 24 hrs, CO2 was released from the top of the
system at proper rate. CO2 was allowed to pass through a
separator and any flashed fluid was collected. Production from
the bottom of the core holder was collected and added to the
flashed oil from the separator and weighed, carefully. This
concluded one cycle of huff-and-puff experiment at 250 psi. For
the subsequent cycles, the system was pressurized to 250 psi
and experiment was repeated until the oil recovery became less
than 1%. The cycle at which the oil recovery became less than
1% of the initial oil in-place was deemed as the last cycle of
huff-and-puff experiment at that pressure, which led to
terminating that set of experiments. The next set of experiments
was started with drying and saturating the core, and repeating
the above procedure at a higher pressure, i.e. 500, 750, 1000,
1250, and 1500 psi.
After the above set of experiments was completed, another
core with higher permeability was chosen, and above procedure
was repeated. The goal of this experiment was to determine the
effect of the permeability of the matrix on the performance of
CO2 huff-and-puff process.
The range of pressures investigated covers both the
immiscible and miscible conditions for the CO2/nC10 system.
Results and Discussion
Effects of operating pressure and permeability of the matrix
on the performance of CO2 huff-and-puff recovery process in
fractured porous media were investigated. Injection of CO2 at
low pressure, i.e. immiscible condition, was compared with near
miscible and miscible cases. Also, effect of injection pressure
on recovery factor above the minimum miscibility pressure
(MMP) has been examined. Other parameters, such as effect of
matrix permeability and initial oil in place, have been
investigated as well.
Effect of operating pressure
Figure 4 shows the ultimate recovery factor of CO2 huff-and-
puff process for a 100 md core as a function of variety of
operating pressures after several cycles of cyclic injection of
CO2. Also, the recovery factor after 1st
cycle of operating at
above pressures is presented. Comparison between the recovery
factors at different pressures clearly shows that oil production is
increased drastically when the conditions change from
immiscible to near miscible at 1000 psi operating pressure. The
results indicate that recovery factor has increased from about
48% at 750 psi to near 94% at 1000 psi. The same trend, though
less pronounced, is observed for the oil production after the first
cycle of oil production. An increase of 9% to18% of recovery
factor for the first cycle was observed for miscible compared to
immiscible conditions. Both curves in Figure 4 show that
injection at a pressure higher than MMP has no strong effect on
the ultimate recovery. However, injection at near miscible or
slightly above MMP, has great impact on the recovery factor.
The results presented in Figure 5 show that while at immiscible
condition increasing injection pressure from 250 psi to 750 psi
can increase the recovery factor by only 14%, injection at
miscible condition (1250 psi) can increase the recovery factor
by a factor of nearly 2. In addition, Figure 5 shows that, less
number of cycles is needed when conducting miscible CO2
huff-and-puff processes in fractured environment. Since the
total numbers of cycles under miscible conditions are 5, a
comparison between recovery factors of first 5 stages of all
pressures is presented in Figure 6. As mentioned before, the
recovery factors in first 5 cycles under miscible conditions are
more than double compared to the conditions below miscibility.
However, there are only 3 percents of increase in recovery
factor when pressure increased from near miscible (1000psi) to
fully miscible conditions (1250psi). Also, comparison between
the values of recovery at 1250 psi and 1500 psi shows that
recovery factor at 1500 psi decreased slightly. It is believed that
the small decrease at 1500 psi is due to the increase in CO2
density and viscosity at higher pressures, as presented in
Figures 1 and 2.
Effect of matrix permeability and oil in-place
In order to investigate the effect of matrix permeability on
performance of CO2 huff-and-puff process at different
pressures, another Berea core with higher permeability, i.e.
1000 md, was used. Specifications of this core are tabulated in
Table 1. The same set of Huff-and-puff experiments were
conducted for this core, and the oil recovery measured at
various pressures is presented in Figure 7. Once again, the range
of operating pressures tested covers both immiscible and
miscible conditions for CO2/nC10 system. In addition, a
comparison was done between recovery factor of the low and
high permeability cores at different conditions through Figures
8,9 and 10. As it shown, recovery factor of the higher
permeability core sample is relatively higher at conditions
below and near miscibility. However, at miscible conditions and
above that, there is no significant difference in the recovery
factors. Therefore, at miscible conditions, higher permeability
does not have a clear benefit to CO2 huff-and-puff miscible
process.
3
4. Conclusion
1. CO2 huff-and-puff process can be used as an
effective means of improving the recovery factor in
fractured reservoirs.
2. Recovery factor of miscible CO2 huff-and-puff
process is considerably high in fractured reservoir.
3. Injection at a pressures much higher than minimum
miscibility pressure does not increase oil recovery
significantly.
4. Below and near miscible condition, production rate
and recovery factor is higher in high permeable
cores.
5. At miscible condition, permeability has not
significant impact on recovery factor of CO2 huff-
and-puff process.
Acknowledgements
The authors acknowledge the financial support provided for
this research by the Petroleum Technology Research Centre,
Regina, and the Faculty of Graduate Studies and Research at the
University of Regina.
NOMENCLATURE
φ = porosity
k = permeability [md]
PV = Pore volume [cm3
]
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4
5. Fig.1-Density of nC10-CO2 Mixture vs. CO2 Mole Fraction
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
0.00 0.20 0.40 0.60 0.80 1.00
CO2 Composition (mole fraction)
LiquidnC10-CO2MixtureDensity(gr/cc)
P=1065 psi P=1500 Psi
Figure 1. Density of mixture of nC10 and CO2 as a function of CO2 mole fraction
Fig.2-Viscosity of nC10-CO2 Mixture vs. CO2 Mole
Fraction
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.00 0.20 0.40 0.60 0.80 1.00
CO2 Composition (mole fraction)
LiquidnC10-CO2MixtureViscosity
(cP)
P=1065 psi P=1500 psi
Figure 2. Viscosity of mixture of nC10 and CO2
5
