Abstract
Chemical Enhanced Oil Recovery (EOR) processes
received more attentions nowadays. Crude
Terephthalic Acid (CTA) as a chemical compound is
used for flooding here as an alternative to the
traditional hydrolyzed polyacryl amide (HPAM).
Crude Oil samples from an Iranian oil field were used
during the flooding tests. Sand packed models using
two different sizes of sand mainly 50 and 100 meshes
were employed in this investigation. A comparison
between water flooding and CTA flooding as a
secondary oil recovery process revealed that the
recovery was improved by 10% when CTA was used.
The effect of various injection rates and different
concentration of chemical solutions on the recovery
factor have been checked. Besides, experimental
results improved the surfactant behavior of the CTA
solution in water. Moreover, at tertiary state, Sodium
Dodocyl Sulfate (SDS) as an anionic surfactant was
flooded. Experiments showed that recovery factor
increased by 5% OOIP while using SDS.
Keywords: Chemical flooding - EOR- CTA-SDSSand
packed model
Introduction
Polymers can typically be added to the injection
water flooded through a reservoir to achieve IOR. The
purpose of this additive is to block ‘highways' for the
injection water in the reservoir in order to change and
optimize flow patterns. With the other technique,
surfactants (detergents) are added to injection water to
‘wash out' more oil in the reservoir.
More specifically, polymers increase sweep efficiency
by improving the mobility ratio. Surfactants, for their
part, enhance microscopic recovery by reducing
capillary forces in addition to boosting sweep
efficiency. Conventional polymers help to raise the
viscosity of the injection water, whilst surfactants
reduce interfacial tension between oil and water.
Petroleum engineers used polymer solutions so that it
can sweep the more area of oil-bearing reservoir and it
can delay the breakthrough time as well. during a
standard water flood, breakthrough time relatively
come up fast and water fingering take place into the oil
front because of high mobility of water relative to oil,
therefore its sweep efficiency will be low [3-4].
Polymer is added to injecting water so that it can
increase the viscosity of solution because of its high
molecular weight and as a result of that, the fingering
effect will be reduced and the sweep efficiency can be
improved [5]. Hydrolyzed poly acryl amide (HPAM)
and xantan gum as synthetic and natural polymer
respectively, are usually used in polymer flooding both
in field and in pilot projects. In 1964, Pye and Sandi
established the fact that polymer flooding can increase
oil recovery compared to water flooding, they
expressed that partially hydrolyzed poly acryl amide
(HPAM) can reduce the mobility of displacing water
with increasing its viscosity and improve the sweep
efficiency of flooding process [6]. Fouling and Wang
(2006) used high concentration of HPAM polymer
solution during flooding studies for Canadian oil field
and illustrated the promising effect of HPAM to
increasing recovery factor to around 21% of the
originally oil in place [7-8].Alkaline-surfactantpolymer
(ASP) flooding is studied by Zhang and
Halliburton (2006) during the EOR process of a
Chinese oil field and improved effect of combination
compared to polymer flooding lonely [9]. Kotlar and
Selle (2007) studied the influence of combination of
polymer (mobility control agent), surfactant (reducing
IFT agent) and a small bi-functional molecule
(increasing solubility agent and reducing salinity
effect) during flooding to enhance oil recovery factor
and deduced that oil recovery can be increased by 20%
OOIP [10]. Tabary and Bezin (2007) investigated the
improved oil recovery techniques and remarked that
chemical process plays an important role in recovering
upswept oil by improving the mobility ratio and
reducing residual oil saturation during processes such
as polymer flooding, surfactants polymer flooding (SP)
and alkaline / surfactant /polymer (ASP).Basically
surfactants reduce the interfacial tension between oil &
water and mobilize the residual oil saturation [11]. In
2007 Lakatos and Toth studied the viscoelastic
surfactants as mobility - control agents to enhance oil
recovery. Their experiments showed that the
viscoelastic surfactant could be replaced by traditional
mobility control agents because they could reduce IFT
and control the mobility ratio simultaneously [12].
Crude Terephtalic Acid (CTA) was used in this study
as a macro monomer that can increase water viscosity
because it belongs to polyesters family with relatively
high molecular weight. In addition, SDS was selected
to flood in tertiary state in order to wash out the
residual oil after polymer flooding through the sand
packed model.
CTA Specifications
CTA which is an abbreviation for "Crude
Terphitalic Acid" is one isomer of the three phthalic
acids. It is mostly used as a commodity chemical,
substantially as a beginning compound for making of
polyester (specifically PET) which its property given
in table 1. Addition to good solubility of CTA, it is
stable in high temperature around 2800C. It has the
chemical formula C6H4 (COOH) 2 (Figure1) and
known as 1, 4-benzenedicarboxylic acid as well. CTA
can enhance the viscosity of water when is augmented.
Therefore, it can be a candidate during chemical
flooding process to improve oil recovery factor.
SDS Specifications
Sodium dodecyl sulfate (SDS or NaDS) or sodium
lauryl sulfate (SLS) is an anionic surfactant with
molecular formula C12H25SO4Na. The molecule has a
tail of 12 carbon atoms, attached to a sulfate group,
giving the molecule the amphiphilic properties
required of a detergent (figure 2). SDS is probably the
most researched anionic surfactant compound. Sodium
lauryl sulfate can solve trapped oil in porous media
and therefore, found an extended usage in reservoir
engineering field. The critical micelle concentration
(CMC) in pure water at 25°C is 0.0082 M, and the
aggregation number at this concentration is usually
considered to be about 50. The micelle ionization
fraction (a) is around 0.3 (or 30%).
Experimental set up
To investigate the polymer-surfactant EOR process,
a sand packed column was employed in this study. A
glassy column with inside diameter of 2.5 cm and
height of 25 cm was used as the sand pack holder. Two
metallic meshed distributors were positioned on the
both ends of the column. The entrance and exit parts of
the model were equipped with flanges and valves to
control the flooding rate. Silicate sand with mesh
numbers 50 and 100 are selected as porous media.
First, the sand was washed and allowed to dry in free
air for 2 days. Then, it was poured into the sand pack
gradually and was packed well. When the sand pack
holder became full, the end flange was closed and then
was connected to a CO2 storage tank and the CO2 was
allowed to flow through the sand pack for about 15
minutes to completely expel the entrapped air. Then it
was flooded with water and during water flooding the
permeability of the sand pack was measured employing
a constant water head. The water-flooded sand pack
was then flooded by oil using a very precise syringe
pump and 4 to 5 pore volumes of the oil was allowed to
pass through it. At this time the sand pack has been
representing an oil reservoir that has connate water and
ready to test (figure 3). Various CTA solutions were
injected in secondary state until no more oil would
leave the model and during the test, the volume of oil
and polymer solution which were going out the model
and also the time of depletion were recorded. At the
tertiary state, SDS was flooded until no more oil could
leave the model and recovery factor was calculated for
SDS flooding as well.
CTA Helpfulness
In order to find out how well the CTA will do, a
comparison between it and water is made during
flooding process and the result are shown on figure 4.
As one can see, the CTA flooding has more recovery
factor around 10 percent against pure water injection.
Besides, because of the production of CTA near the
Iranian oil field; it is opted for this study during
flooding processes. Water flooding can be replaced by
CTA flooding in secondary stage because during of
tests, there are neither signs of adsorption on sand
surface nor reduction of absolute permeability.
Experiments
Crude Oil samples from an Iranian oil field are
selected to be used during the flooding tests. CTA
solutions were produced in concentrations of 100,250
and 500 ppm. Because of low solubility of CTA in
ambient temperature, the solutions were heated up to
700 C while it was stirred. Fortunately, the solutions
would have been uniform and stable during the tests.
In efforts to investigate the effect of solution viscosity
on recovery factor, three different concentrations were
prepared. Table2 shows the solution properties.
Experiments were performed as previously described.
Solutions with different concentrations were injected
in a constant rate (0.2cc/min) and four tests were done
in constant concentration (250 ppm) at different rates
(0.2, 0.6, 0.8, and 1 cc/min). Table 3 illustrates the
characterizations of experiments. In tertiary state, SDS
are injected in constant concentrating (2500 ppm) and
various flow rate to obtain the effect of flow rate on
effectiveness of SDS flooding in tertiary state.
IFT reduction property of CTA
In order to check the IFT reduction property of
CTA solution, after preparing the model a 250 ppm
solution of HPAM was injected in secondary stage
until no more oil can leave the model and then a
solution of CTA with 250 ppm concentration was
injected in tertiary state. Experiment showed that the
250 ppm solution of CTA increased the viscosity of
water up to 2.5 cp which is less than the HPAM, but it
could recover more oil from the sand packed model
around 3 %( figure 5). Therefore, this may be
attributed to surfactant behavior of CTA. In addition
theoretically CTA belongs to polyester groups which
make soap foam when solve in water.
Effect of concentration of injecting
solution on recovery factor
Injections of CTA solution with three
concentrations were done. Injections were doing until
no more oil could leave the model. It is expected that
the solutions with more concentration can recover
further original oil in place from the sand packed
model. During these tests, SDS was injected in
constant concentration (2500 ppm) as well. The results
of injection with various concentrations are shown on
figure 6. Since more viscous solution will displace oil
across the model ideally and invade more area of the
model, the breakthrough time will delay and the
viscous fingering effect will be mitigated. Therefore,
the recovery factor and sweep efficiency will rise. The
results from the experiments, also, verify this physical
concept
Effect of injection rate on recovery
factor
CTA and SDS were flooded at three rates of
injection in order to find out the relation of flooding
rate and recovery factor. Injecting of high rate solution
which expected to bypass the bulk of oil can also
impose more pressure drop on porous medium.
Therefore, the fingering effects may further be
observed as well as coning phenomenon will be
included because of unbalancing between gravitational
forces and viscous forces at high rates. The results are
exhibited in figure 7. Since high rate of injection cause
to sweep less area of model and also, the movement of
solution through the model is more longitudinal, the
breakthrough time will decrease and recovery factor
will reduce as well.
Salinity effect on efficacy of solution
Generally proved that the concentration of anionic
compounds such as Na+, Ca2+ and Mg2+ have some
effects on flooding processes which are imposed on oil
reservoirs to improve recovery factor. Salinity which
specially means concentration of Na+ has a drawback
on Hydrolyzed Polydacryl Amide (HPAM) efficiency
during polymer flooding and reduces the its
helpfulness, therefore HPAM should be used for such
reservoirs which have low brine concentration.
However, CTA shows resistance against salinity up to
2500ppm. Figure 8 illustrates a comparison between
Dow Pusher 500 polyacrylamide and CTA solutions
related to effect of Nacl concentration on their
viscosity [4]. Hence, CTA could be a suitable
candidate for polymer flooding processes of reservoirs
with high salinity concentration processes of reservoirs
with high salinity concentration.
Effect of temperature on effectiveness
of CTA
Adequate temperature ranges in which polymers
remain stable without degradation are very sensitive to
types of polymer. It is believed that most polymers will
be decomposed at high temperatures and so miss their
applicability. Reservoirs with temperature higher than
3000 F should usually be avoided for using
polyacrylamide because it loses their viscofying
property at that temperature. Our experiments showed
that CTA could sustain temperature up to 2500 c
without missing its property for the reason that it is
contained of benzoic loop in its structure which is very
stable.
Results and discussion
This study concerns chemical flooding process to
improve oil recovery using CTA and SDS as a polymer
and surfactant agent respectively. A sand packed model
is used to investigate the impact of various parameters
on ability of CTA and SDS to recover more oil
during flooding process. Experiments are designed to
study effects of injection rate, concentration,
temperature and salinity on flooding processes. In
addition, the IFT property of CTA is checked as well.
Taking every thing into the consideration, the
following deductions are obtained:
Nomenclature:
