Journal of Petroleum Science and Engineering 135 (2015) 484–497
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Journal of Petroleum Science and Engineering
journal homepage: www.elsevier.com/locate/petrol
A novel chemical additive for in-situ recovery of heavy oil using
waterflooding process
Omid Mohammadzadeh a,n, Ioannis Chatzis b,1, John P. Giesy c,d,e,f
a
DBR Technology Center – Schlumberger, Edmonton, AB, Canada
Department of Chemical Engineering – University of Waterloo, Waterloo, ON, Canada
c
Department of Veterinary Biomedical Sciences and Toxicology Centre – University of Saskatchewan, Saskatoon, SK, Canada
d
Department of Zoology and Center for Integrative Toxicology – Michigan State University, East Lansing, MI, USA
e
School of Biological Sciences – University of Hong Kong, Hong Kong, China
f
State Key Laboratory of Pollution Control and Resources Reuse, School of the Environment, Nanjing University, Nanjing 210046, PR China
b
art ic l e i nf o
a b s t r a c t
Article history:
Received 10 June 2015
Received in revised form
29 September 2015
Accepted 8 October 2015
Chemical-assisted waterflooding is injection of specialty chemical(s) along with water to enhance the
productivity through a series of mechanisms. There are several mechanisms responsible for increased
ultimate recovery of such a process compared to the traditional waterflooding process including in-situ
emulsification of oil, conformance control and treatment of adverse mobility ratio, reduction of Interfacial Tension (IFT) between the in-situ oil and the injecting phase, and wettability modification to facilitate recovery of oil by enhanced relative permeability values. Although chemical-assisted waterflooding has been applied since the early 20th century, it has not been until recently that applicability of
this process has been tested for recovery of heavy oil using preliminary macro-scale as well as pore-scale
studies. A new chemical technology (i.e. IPC Technology as referred in this paper) has been developed. A
proprietary mixture of surfactants is used in several techniques associated with surface extraction as well
as in-situ recovery of heavy oil and bitumen. This formulation of solvents and surfactants is reusable, low
foaming, non-flammable, not acutely toxic and non-carcinogenic. A systematic study, based on a series of
coreflood tests, was designed and conducted to assess efficacy of IPC in the ultimate recovery of different
types of oils by use of IPC-assisted waterflooding. Effects of IPC on IFT between oil and IPC solutions at
different brine salinities/hardnesses and IPC concentrations were determined. Compatibility of IPC with
different brine hardnesses and salinities was determined. IPC technology was particularly effective in
recovering heavy oil. The performance of IPC as an additive during waterflood at elevated temperature
for recovery of heavy oil was also investigated. For this particular purpose, thermal stability tests were
conducted to determine the threshold temperature below which the formulation is thermally stable.
When production performance of IPC-assisted waterflood was compared with alkali flooding and a
commercial surfactant, IPC gave superior ultimate recovery.
& 2015 Elsevier B.V. All rights reserved.
Keywords:
Chemical-assisted waterflooding
Coreflood
Interfacial tension
Salinity
Thermal stability
1. Introduction
A recent estimate of recoverable oil and bitumen, using primary and commercially-proven Enhanced Oil Recovery (EOR)
technologies in Canada, is about 178 billion barrels, with oilsands
production contributing about 85% to the total (NEB, 2006). Although these are significantly large reserves, they are considered
to be only a fraction of the total available resources, which is estimated to be more than 1.5 trillion barrels (NEB, 2004). The
n
Corresponding author.
E-mail address: omohamma@uwaterloo.ca (O. Mohammadzadeh).
1
Present address: Kuwait University, Kuwait.
http://dx.doi.org/10.1016/j.petrol.2015.10.009
0920-4105/& 2015 Elsevier B.V. All rights reserved.
largest deposits are located in the Western Canada Sedimentary
Basin (WCSB). The significant difference between recoverable reserves and available in-situ resource estimates is the amount of oil
and bitumen for which there is no proven, commercially viable
EOR technology for extraction.
Chemical flooding is an EOR technique that involves injecting
slugs of dilute chemicals into a formation to increase microscopic
(i.e. pore-level) and macroscopic (i.e. sweep) efficiencies of the
displacement process. Three main classes of chemicals are typically used: (1) alkalis; (2) surfactants and (3) polymers. Several
other types of chemicals, such as scale inhibitors and co-solvents,
can also be added to the formulation if necessary. Each class of
chemical has a different primary purpose when added to the
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
formulation of the chemical “slug” injected. The main purpose of
adding alkali to the injected water is to generate surfactants in situ
upon contact with the reservoir oil through saponification of the
natural acids that exist in the oil phase. Surfactants, added at the
surface or generated in situ, reduce IFT between oil and water,
hence mobilizing the oil phase which is trapped in porous media
by capillary forces.
The concentration of active surfactants in the injected water is
usually between 0.05 and 2 wt%, depending on the type of chemical, its cost and design parameters of the EOR process. It is typically necessary to reduce IFT by three to four orders of magnitude, attaining 10 2–10 3 mN/m, to achieve significant reduction
in residual oil saturation. At least two other mechanisms, not directly related to reduction of IFT, can also contribute to increasing
recovery of oil by use of flooding with surfactants. Wettability
modification and in-situ emulsification of oil as a result of the
presence of chemical provide flow conformance and favorable
mobility ratios especially when more viscous oils comprise the
displaced phase. Sandstone reservoirs are typically naturally water-wet. However, sandstone formations containing heavy oil are
often found to have neutral or mixed wettability. Some chemicals
have the ability to change the wettability of formation rock
through chemical reactions, ion exchange or adsorption mechanisms. Changes in wettability lead to changes in the pore-scale fluid
distribution patterns and relative permeability to oil and water,
and often results in re-mobilizing previously trapped oil. In-situ
emulsification of oil can also reduce the residual oil saturation,
hence facilitates increased oil flow towards the production wells
(Chatzis et al., 1983; Somasundaran and Hanna, 1979; Johnson,
1976; Mayer et al., 1983; Shah et al., 2010).
Initial wettability of the porous structure and any further
changes due to the presence of surface active agents in the chemical flood significantly affect performance of EOR processes
(Morrow , 1990). Vijapurapu and Rao (2003) performed an experimental study on the effect of chemical flood and brine on
spreading and adhesion behavior of the crude oil on dolomite
surfaces. Anionic surfactants change the wettability of the calcite
surface to intermediate/water-wet condition compared to that of
the cationic surfactants (Seethepalli et al., 2004). Mechanisms responsible for changes in wettability have been described following
a chemical EOR process in carbonates (Wu et al., 2006). Effect of
pore wettability on pore-scale mechanisms of oil recovery as well
as on the topology of the trapped wetting and non-wetting phases
through dilute surfactant flooding of porous structures have been
described with different wettability conditions (Jamaloei and
Kharrat, 2010a and 2010b).
One limitation of surfactant-based EOR processes is sensitivity
to salinity of the reservoir fluids as well as that of the injected
flood. Several studies have been performed to study effects of
salinity on performance of surfactant flooding. There have also
been studies of effects of divalent ions on IFT values (Bansal and
Shah, 1978a; Kumar et al., 1984). Effects of optimum salinity and
divalent ions on IFT and surfactant phase retention have also been
investigated (Bansal and Shah, 1978b; Glover et al., 1979; Gupta
and Trushenski, 1979). IFT values were found to be proportional to
concentrations of divalent ions in connate water and it has also
been demonstrated that optimum salinity is not constant in brines
containing divalent ions. Because of interactions between divalent
ions and petroleum sulfonates, precipitation followed by re-dissolution of the precipitates at higher concentrations of the surfactant occurred (Celik et al., 1982). Evolution of precipitates, due
to contact of petroleum sulfonate with divalent-ions in connate
water, might also result in greater recovery factor of the surfactant
flooding (Agharazi-Dormani et al., 1990).
The objective of this study was to evaluate enhancement of
recovery of different types of oil by use of a proprietary chemical
485
additive during waterflooding process. Although different mechanisms contribute to enhanced productivity of chemical-assisted waterflooding, the focus in this paper is on the ability of the
IPC formulation to reduce IFT between in-situ oil and the displacing phase. Incremental oil recovery associated with this chemical
was also compared against those of two commercial chemical
additives through a series of coreflood tests.
2. Materials and methods
The IPC formulation (Patent US 2013/0157920 A1) is a proprietary, liquid cleaning, degreasing, and disinfecting concentrate
composition, comprised of: (1) caustic soda in a range of about
0.181% to about 5.45% by volume; (2) a de-emulsifier in a range of
about 0.028% to about 9.09% by volume; (3) an alkyl glucoside
surfactant of about 0.090% to about 7.27% by volume; (4) a
phosphated alkyl ethoxylate surfactant of about 0.028% to about
1.81% by volume; (5) a tridecyl alcohol surfactant in a range of
about 0.363% to about 9.09% by volume; (6) a non-polar bonding
agent of about 0.028% to about 1.81% by volume; and, (7) water
forming the remainder percentage by volume. The IPC formulation
used as an additive during waterflooding, was characterized to
describe its bulk physical properties and partitioning behavior in
aqueous and oleic phases, and thermal stability. These tests were
complemented with a set of tests to evaluate recovery of different
types of oils by IPC-assisted waterflooding. Compatibility of IPC
with brines of various salinities and hardnesses was investigated.
Interfacial tension between oils and solutions of IPC in brine was
measured. Once these parameters had been optimized, a series of
1D coreflood tests were conducted to determine overall effectiveness of IPC in producing the original oil in place (OOIP).
2.1. Physical properties of IPC
Density and viscosity of IPC were determined at ambient
pressure and three temperatures. To understand how the IPC
mixture partitions between aqueous and oleic phases, bench-top
volumetric tests at ambient temperature were conducted. For
volumetric partitioning tests, measured volumes of heavy oil,
deionized water, toluene, and IPC were added to a 100 mL centrifuge test tube and mixed by vigorous shaking until a homogeneous phase was formed, then centrifuged for 30 min. Volumes
were measured and photographs were taken. However, the volumetric partitioning tests were inconclusive.
2.2. Thermal stability of IPC
The maximum use temperature of a chemical is an approximate threshold temperature value at which it begins to decompose. A series of tests including Thermal Gravimetric Analysis
(TGA), Differential Scanning Calorimetry (DSC), Simulated Distillation (SD) and Carbon Number Distribution (CND) determination were used to characterize IPC. The TGA and DSC tests can
determine the onset and degree of thermal degradation and the
SD test determine the volatility of the chemical. The CND test can
determine the range and relative amounts of each carbon unit
from C1 to C30 þ (or possibly C60 þ ) in IPC. Since these thermal
stability tests cannot determine if the effectiveness of IPC is diminished at elevated temperatures, other tests were used to assess
several EOR processes at elevated temperatures. For the purpose of
chemical-assisted waterflooding, effectiveness as a function of
temperature was assessed based on optimizing parameters such as
IFT and coreflood tests.
One SD test using a Gas Chromatographic (GC) technique and a
CND calculation was attempted in this study. In addition, two TGA
486
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
and two DSC tests were conducted on IPC. For the latter two tests,
baseline tests with empty pans and with local carrier water used
to manufacture the chemical were also conducted and then used
to correct the thermal stability threshold values. Samples were
heated from ambient room temperature at a nominal rate of 5 °C/
min. One of the TGA tests and one of the DSC tests were conducted
under a Nitrogen atmosphere so that thermal decomposition into
volatile constituents by pyrolysis could be detected. The other two
tests were conducted under air, and indicated the temperatures at
which portions of the sample are oxidized.
2.3. Evaluation of IPC as an additive in waterflooding process using
coreflood tests
Efficacy of IPC as an additive during waterflooding process was
determined using 1D coreflood tests. For this purpose, compatibility of IPC with several mixtures of brine with different ionic
concentration/salinity/hardness was studied. Solutions were inspected visually for incompatibility. Samples were stored in an
oven at constant temperature and were observed periodically for
at least one month. Studies were focused on reduction in IFT between displacing and displaced phases. Therefore, relevant tests
were designed and conducted to quantify the effectiveness of IPC
in reducing IFT between brine and oil. Three different oils, light oil
(A), medium oil (B) and heavy oil (C), were used in this study
(Table 1). The reason for testing three types of oil is that IPC, due to
its PH, has the potential to interact with components of mediumand high-viscosity oils to further reduce IFT in-situ and this effect
can be specific to the type of oil studied. To evaluate stability and
integrity of reduction of IFT, these tests were repeated after several
durations of ageing. During the oil preparation stage, the dead oil
samples were cleaned by centrifugation. The cleaned dead oils
were then characterized in terms of density and viscosity at typical
reservoir temperature as well as total acid number. For each oil
sample, two similar fresh brine solutions, one for IFT test and
another for assessing repeatability after ageing, were prepared,
followed by making IPC in brine solutions. Three concentrations of
IPC (2, 10, and 30 wt%) prepared in a 1 wt% NaCl brine were tested.
The IFT values between individual oils and IPC solution in brine
were measured by use of the Spinning Drop method. In addition, a
baseline measurement of IFT between brine and oil in the absence
of IPC was conducted for each oil type using the Pendant Drop
technique. All measurements were repeated using the other batch
of IPC in brine solution which was aged at constant temperature
and the results were compared with the original data obtained
using fresh solutions.
To evaluate the effect of salinity of brine on reduction of IFT,
three additional tests were performed with light oil A by use of a
Table 1
Properties of oils used in IFT measurement tests.
Density, kg/m3
Viscosity, mPa s
Acid number (mg
KOH/g)
a
Measured at 25 °C.
Temperature (°C) Light Oil
A
Medium Oil
B
Heavy Oil
C
15 °C
20 °C
40 °C
806.4
802.7
794.7
948.5
942.1a
932.1
986.9
983.7
971.5
15 °C
20 °C
40 °C
2.37
2.15
1.83
928
737a
150
22,800
12,500
1620
0.07
1.20
1.13
2 wt% IPC in brines with 0.5, 2, and 4 wt% NaCl concentration.
Some other additional tests, one with medium oil B and one with
heavy oil C, each with 2 wt% IPC solution in 4 wt% brine, were also
conducted. Stability of IPC solution in maintaining reduced IFT
values and the effect of ageing on reduction of IFT were evaluated
by repeating these measurements for medium-viscosity oil B as
well as heavy oil C with IPC solutions that had been aged for a
period of six weeks. All these measurements were conducted at
20 °C.
One dimensional coreflood tests were conducted to assess the
effectiveness of the IPC formulation in increasing ultimate recovery of oil through displacement during waterflooding. Five
coreflood tests were conducted with a variety of oil types at ambient temperature and one coreflood with heavy oil at an elevated
temperature. In the first coreflood test, heavy oil C with the
greatest viscosity was used in an IPC-assisted waterflood at 21 °C.
In the second coreflood, a commercial alkaline material was used
to recover heavy oil C at room temperature (21 °C). In the third
coreflood, recovery of heavy oil C with the aid of a commercial
surfactant flood was determined at room temperature. Coreflood
tests 2 and 3 were conducted for comparison with the results of
coreflood test 1 in which IPC was used as the chemical additive. In
coreflood tests 4 and 5, IPC-assisted waterflooding was used to
recover light oil A and medium-viscosity oil B at temperatures
between 20–30 °C. In the last coreflood test, IPC was used as the
chemical additive to recover heavy oil C at an elevated temperature of 200 °C.
A complete coreflood test was composed of initial waterflood
stage, followed by chemical flood stage and an extended waterflood. A shut-in period for soaking was also considered after the
chemical flood. A mixture of synthetic silica sand and a reservoir
sand from a heavy oil field, mixed in equal proportions, was used
to simulate the porous media. The sand was packed in confinement lead core sleeves measuring 30.5 cm (i.e. one foot) long by
3.81 cm (i.e. 1.5 in.) diameter, and then was placed in the overburden vessel (i.e. core holder) and was confined under differential overburden pressure. The dry core was then saturated with
CO2, evacuated and was subsequently checked for possible leaks.
The core was then saturated with 4 wt% NaCl brine solution to
measure initial pore volume and porosity. During the brine flow
tests, the absolute single-phase permeability to brine was measured. Each core was then saturated with dead oil and was aged
for a period of at least three weeks at room temperature to allow
for chemical equilibration between brine, oil and rock. The core
prepared for the elevated temperature test (i.e. test # 6) was aged
at 200 °C. Conditions were then adjusted to an operating pressure
of 2,500 kPa, overburden pressure of 5,000 kPa and a pre-determined operating temperature. Finally, different flood stages
including initial waterflood using 4 wt% NaCl brine, followed by
subsequent chemical flood and a prolonged waterflood were
conducted during which data were collected including oil and
water production as a function of fluid injected, injection and
production pressures as well as pressure drop across the core. The
4 wt% NaCl brine concentration was selected based on the results
of compatibility tests and IFT measurement tests.
3. Results and discussion
3.1. Physical properties of IPC formulation
The density of IPC is similar to those of many oil reservoir
brines at the temperatures studied (Table 2). Kinematic viscosity of
IPC at the same temperatures is also presented (Table 2). The dynamic viscosity of IPC is approximately 3 cP at standard conditions
of one atmosphere pressure and 15 °C, which is approximately
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
487
Table 2
IPC density and viscosity at different temperatures.
Temperature (°C)
Density (Kg/m3)
Viscosity (cSt)
15
25
40
1067.4
1065.3
1058.1
2.79
2.56
2.24
3 times that of water under similar conditions. It was assumed that
IPC exhibits Newtonian behavior although it was not tested for
non-Newtonian behavior. This seems a valid assumption considering the fact that most dilute solutions, especially when mixed
with water, exhibit Newtonian behavior.
Amounts of IPC partitioned into the oil phase as a function of
chemical ratios were measured in bench-top volumetric partitioning tests. In conclusion, although IPC partitioned into the oleic
phase for some of the mixing ratios, the tendency of IPC to partition correlated neither with the water/chemical volume ratio,
nor with the oilþ toluene per chemical volume ratio used in these
partitioning tests.
Fig. 2. Derivative TGA signals of samples of IPC under Nitrogen and air.
3.2. Thermal stability of IPC
Thermograms of the two TGA tests are shown (Fig. 1). The
majority of the sample vaporized just below 100 °C as a volatile
solvent or solvent mixture. The remaining material appeared to be
stable at temperatures greater than 200 °C, above which the
sample began to lose weight at a rate that gradually increased with
temperature until the rate peaked around 310 °C. This event can be
seen more clearly in Fig. 2 which shows the time derivative of the
signals shown in Fig. 1. The derivative of the TGA signal taken
under air was similar, except that it showed weight loss peaking at
a lower temperature of about 265 °C, which is consistent with the
oxidation of paraffinic hydrocarbons. There was essentially no
weight change above 360 °C, but only about 1.5 wt% of the sample
was remained at this temperature condition. The sample amount
that was left behind appeared to be a white, crystalline mineral.
The peaks that appear in Fig. 2 just above 100 °C and at 150 °C are
thought to be due to the irregular vaporization, because they were
not reproduced on the trace under air, and are therefore not
significant.
DSC response to IPC was determined under both Nitrogen and
air atmospheres (Fig. 3). Except at temperatures near 300 °C under
air, the responses were endothermic, either because of heat absorption through evaporation, or as an indication of the normal
heat capacity of a material being heated. The exothermic peak
around 305 °C corresponds to the oxidation peak seen by TGA
(Fig. 1). An attempt was made to isolate the effects produced by
the non-aqueous components, by subtracting the thermal analysis
signals that were observed for the carrier water samples from
those taken for the chemical samples. The results, which are
presented in Figs. 4 and 5, revealed that a substantial amount of
IPC that boiled off below 100 °C was not water. The overall
Fig. 1. TGA traces of samples of IPC under Nitrogen and air.
Fig. 4. Difference in TGA traces of water and IPC under Nitrogen.
Fig. 3. DSC traces of samples of IPC under Nitrogen and air.
488
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
Table 4
Results of IPC compatibility tests with different brines.
Brine # 5 vol% IPC @
22 °C
50 vol% IPC @ 5 vol% IPC @
22 °C
75 °C
50 vol% IPC @
75 °C
1
Cloudy (bottom 2.5 mL)
Cloudy (bottom 2 mL)
Cloudy (bottom 32 mL)
Clear
cloudy (bottom 26 mL)
Cloudy (bottom
2.5 mL)
Cloudy (bottom
2 mL)
Cloudy (Crystalline,
90% vol.)
Clear
Cloudy (2 phase)
2
3
4
5
Fig. 5. Difference in DSC traces of water and IPC under Nitrogen.
conclusion of these tests is that any surface active agent in IPC
formulation will begin to degrade at temperatures greater than
220 °C. If the EOR processes involve any form of steam injection,
then at best IPC could be used only in the shallower oilfields in
which pressures are less and the saturated steam temperature is
near or below 200 °C; otherwise, these surface active agents will
not survive long enough to be effective in the heated region of the
oil reservoir.
3.3. IPC – brine compatibility and stability
The purpose of these tests was to determine chemical compatibility and stability of IPC in common oilfield brines solutions.
Two concentrations of IPC, 5% and 50%, were tested with five
brines of various mineral contents (Table 3). Each test was conducted at two different temperatures: room temperature (22 °C)
and 75 °C. Test vials were observed for a period of 1.5 months.
Results for compatibility and stability tests are provided (Table 4).
Four of the five brines showed signs of incompatibility. Brines with
the greatest salinity and hardness levels (brine #3 and #5) had the
most severe precipitation (Figs. 6 and 7). Precipitates formed immediately upon contact of IPC with these two brines and did not
significantly change with time. The mixture of IPC with brine #3
emitted a strong ammonia smell. Increasing the concentration of
IPC increased the amount of solid precipitate in the highly saline
brines #3 and #5, and slightly decreased the amount of solid
precipitate in the brines of lower salinity (#1 and #2). This is likely
because the amount of precipitate-forming ions is limited in the
less saline brines. The amount of precipitate at room temperature
was similar to that of the elevated temperature at similar levels of
Table 3
Brine analysis.
Parameters
Unit
Brine #1 Brine #2 Brine #3 Brine #4 Brine #5
Bicarbonate
Chloride
PH
TDS
Calcium
Magnesium
Potassium
Sodium
Barium
Iron
Manganese
Sulfate
mg/L
mg/L
PH units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
–
11143
18288
65
80
–
7000
–
–
–
–
1130
8900
7.93
16300
57
85
50
6000
0.09
0.05
0.02
760
–
106000
5.78
295000
7080
1020
3700
90200
1.7
48
2.7
540
–
3047
5020
14
0
0
1959
–
–
–
–
794
48500
7.07
82600
1800
930
670
27300
35.8
1.1
1.1
2
Cloudy (bottom 4 mL)
Cloudy (bottom 4 mL)
Cloudy (bottom 10 mL)
Clear
cloudy (bottom 10 mL)
Cloudy (bottom 4 mL)
Cloudy (bottom 4 mL)
Cloudy (bottom 6 mL)
Clear
cloudy (bottom 10 mL)
brine concentration; however, the nature of the precipitate was
different. The precipitate in the 50 vol% solution of IPC with brine
#3 had a crystalline structure after a period of 1.5 months at 75 °C.
The solid precipitate in the 50 vol% solution of IPC with brine #5
formed two phases after a week at 75 °C. Brine #4 appeared to be
compatible with IPC, likely due to its low content of divalent ions
(Ca2 þ and Mg2 þ ).
In order to check which ions in brine solutions are responsible
for severe solid precipitation in the presence of IPC, four solutions
of 5 vol% IPC in various single-salt brines – sodium bicarbonate,
magnesium chloride, calcium chloride and sodium chloride – were
prepared (Table 5). Precipitation occurred in solutions that contained divalent ions (Fig. 8). Therefore, it can be concluded that IPC
is incompatible with brines of medium and high hardness when
divalent ion concentrations are greater than 150 ppm. It is possible, however, that slightly acidic or alkaline conditions could improve the tolerance of IPC to the divalent ions.
3.4. IFT Measurements for IPC solutions in Brine and Oil
The purpose of these tests was to evaluate IPC for its ability to
lower IFT values between brine and oil (Tables 6–8 and Figs. 9–18).
For all types of oil used in this study, a typical trend in IFT vs. IPC
concentration is observed: addition of IPC to the binary of water–
oil system decreased the IFT value from its original value (i.e. in
the absence of chemical). However, the observed trend was not
monotonic, and an optimum value of chemical concentration was
found in which IFT reached a minimum. This trend was expected
because IPC is a formulation containing surface active agent(s) so
that addition of IPC to the solution will decrease IFT between
chemical solution and oil. Reduction in IFT as a result of the presence of IPC was more significant with greater viscosity crude
compared to the lighter oils. An increase in salinity of brine up to
4 wt% NaCl also led to greater reduction in IFT values, which
means that optimal salinity of brine with the employed oil types is
greater than 1 wt%. For both medium-viscosity and heavy oils,
there was an apparent optimal concentration of IPC between 0 and
10 wt% at which IFT reached a local minimum. It is possible that
this optimal concentration of IPC chemical is even lower than
2 wt%. The typical concentration range for surfactants in field
chemical EOR projects is from 0.05 to 2 wt%, with most of applications utilizing between 0.1 and 0.3 wt% of active surfactant.
In the case of light oil at a constant level of brine salinity, the
greater the chemical concentration, the smaller the IFT. Technically, it is better to use the maximum chemical concentration, but
this might not be economical. Considering the typical values of IFT
needed for a successful chemical-assisted waterflood test (i.e.
0.01–0.001 mN/m or even less), even the IFT value at the maximum concentration of IPC (i.e. 0.41 mN/m) is not sufficient to
achieve desired values. It is important to consider that just one of
the mechanisms responsible for the effectiveness of chemical-
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
489
Fig. 6. Compatibility tests of IPC with brine #3 (after 1.5 months).
assisted waterflooding, i.e. reduction in IFT value as a result of
addition of chemical, is discussed in this paper. Considering these
results, IPC was not successful in achieving the desired IFT even at
the maximum concentration used when light oil A was used in the
measurements. The employed brine concentration of 1 wt% NaCl
was not the optimum salinity for lowering IFT.
Reducing IFT beyond that of brine–oil mixture by use of IPC was
totally different when intermediate-viscosity oil B and heavy oil C
were used. When these oils were tested against IPC in brine solutions with different chemical concentrations, an optimum
amount of IPC in brine was obtained that caused the largest decrease in IFT. Considering the intermediate-viscosity oil B, it was
determined that an IPC solution of 2 wt% in brine was optimal
Table 5
Compatibility of IPC with single-salt brines.
Brine
2 wt%
NaHCO3
1 wt% MgCl2
1 wt% CaCl2
2 wt%
NaCl
5 vol% IPC @
20 °C
Clear
Cloudy (bottom
12 mL)
Cloudy (bottom
30 mL)
Clear
with a minimum IFT of 0.38 dynes/cm. However, IFT was still
greater than the target value for a chemical-assisted waterflood of
0.01–0.001 mN/m or less. In this particular test, salinity of brine
(i.e. 1 wt% NaCl) was not optimal. When another test was conducted with a brine composed of 4 wt% NaCl, it was determined
Fig. 7. Compatibility tests of IPC with brine #5 (after 1.5 months).
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Table 8
IFT values for heavy oil C with fresh and aged brine solutions.
NaCl concentration in brine
(wt%)
1.0
1.0
1.0
1.0
4.0
IPC concentration in brine solution (wt%)
0
2
10
30
2
IFT (mN/m)
Fresh
brine
solution
Fresh brine
solution
(repeated
tests)
Brine solution aged
for
6 weeks
58.25
0.14
0.61
0.40
0.07
–
0.20
0.55
0.48
0.03
–
0.41
0.58
0.74
0.11
Fig. 8. Compatibility tests of IPC with single salt brines at 22 °C.
Fig. 9. Effect of IPC concentration on dynamic IFT data for light oil A with 1 wt%
NaCl brine at 20 °C.
Table 6
IFT values for light oil A with fresh IPC in brine solutions.
NaCl concentration in brine,
wt%
IPC concentration in brine solution, wt%
IFT, mN/m
1.0
1.0
1.0
1.0
0.5
2.0
4.0
0
2
10
30
2
2
2
15.74
1.11
0.77
0.41
0.96
0.96
0.83
Table 7
IFT values for medium-viscosity oil B with fresh and aged IPC in brine solutions.
NaCl concentration
in brine (wt%)
1.0
1.0
1.0
1.0
4.0
IPC concentration in
brine solution (wt%)
0
2
10
30
2
IFT (mN/m)
Fresh brine
solution
Brine solution
aged for
6 weeks
16.72
0.38
0.65
0.52
0.34
–
0.45
0.65
0.45
0.32
that IPC performed slightly better at greater brine salinity compared to the lesser salinity. For the heavy oil C which has viscosity
in the range of crude in Lloydminster heavy oil reservoirs, IPC
worked efficiently and the drop observed in IFT compared to the
other two previous cases was greatest. The IFT obtained between
heavy oil C and 2 wt% IPC solution in 1 wt% NaCl brine was the
smallest value obtained (i.e. 0.14 dynes/cm). Similar to the cases of
light and intermediate-viscosity oil, the brine salinity was not
optimum as far as the effectiveness of IPC in lowering IFT is concerned. When similar concentrations of IPC were tested in the
Fig. 10. Effect of brine salinity on dynamic IFT data for light oil A with brine solutions at constant IPC concentration of 2 wt% at 20 °C.
Fig. 11. Equilibrium IFT vs. IPC concentration for light oil A.
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
Fig. 12. Equilibrium IFT vs. brine salinity for light oil A.
Fig. 13. Effect of brine salinity and IPC concentrations on dynamic IFT data for
medium-viscosity oil B (fresh IPC in brine solutions).
491
Fig. 15. Effect of brine salinity and IPC concentration on dynamic IFT data for heavy
oil C (fresh IPC in brine solutions).
Fig. 16. Effect of brine salinity and IPC concentration on dynamic IFT data for heavy
oil C (aged IPC in brine solutions).
Fig. 14. Effect of brine salinity and IPC concentration on dynamic IFT data for
medium-viscosity oil B (aged IPC in brine solutions).
presence of greater salinity (i.e. 4 wt% NaCl), the IFT was reduced
by 50%.
Repeatability of IFT results was checked. Measurements of IFT
were repeated after 6 weeks of ageing. It was expected to see similar or slightly lower values after this ageing period. Except for
two single measurements, i.e. heavy oil C with chemical concentrations of 2 and 30 wt% which showed an unusually large
increase in IFT after aging, the expected trend was observed and
the difference in IFT values before and after ageing was within 5–
7% of the original values. The “rule of thumb” for chemical EOR is
that a two-fold decrease in IFT results in approximately a 10% increase in ultimate recovery of oil. It is typically desired to have IFT
Fig. 17. Equilibrium IFT values versus IPC concentration for medium-viscosity oil B.
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O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
Table 10
IFT values for solutions of several commercial surfactants with heavy oil C.
Chemical name
IFT, mN/m
Ethomen 18–25
Rhodacal DSB
N-85
Bio-Terge PAS-8 S
Arquad T-50
1.86
2.40
0.96
2.84
0.22a
a
Fig. 18. Equilibrium IFT values versus IPC concentration for heavy oil C.
values in the range of 10 2–10 3 mN/m or less. According to this
estimate and results of IFT reduction only, IPC could be considered
for chemical EOR in a field containing heavy oil “C”, depending on
the salinity of in-situ brine. IFT reduction with oil types “A” and “B”
was not sufficient to the extent of providing significant benefits
through the reduction of capillary forces. However, it is possible
that improvement in oil recovery could still be achieved through
oil emulsification and/or alteration of formation wettability by the
use of IPC as an additive.
3.5. Coreflood experiments
Six core displacement experiments were conducted. Some details about properties of rock and fluid are listed (Table 9). Three
oils were used: light oil A, medium-viscosity oil B and heavy oil C
(Table 1). Five coreflood tests were conducted at ambient temperature and one experiment was conducted at 200 °C. To compare performance of IPC to other commercial products that are
currently being used in EOR processes, two baseline coreflood
experiments were conducted: one with a mixture of two alkali
materials (sodium carbonate and sodium hydroxide) and the other
one with a commercial surfactant, Arquad T-50, that was selected
from among five different commercial surfactants based on their
after 70 min, IFT increased to 0.68 mN/m.
ability to reduce IFT between brine and oil (Table 10). One additional surfactant was also tested and found to be effective in reducing IFT. However, it was not used in the coreflood experiments
because it had not been used in the EOR processes in the past.
Results of the core displacement experiments are provided (Tables 11 and 12, Figures 19–28).
The greatest incremental recovery over the initial waterflood
was 16.4% of OOIP for heavy oil C in the ambient temperature
coreflood when IPC was used (RUN #3, Table 11, Figs. 19 and 20).
This oil also had the least IFT with IPC solution in brine. About 4.5%
OOIP of additional oil was also recovered in the coreflood with
medium-viscosity oil B in RUN # 2 when IPC was added to the
injection mainstream (Table 11, Figs. 19 and 20). Practically, no
additional oil was recovered in the corefloods with light oil A (RUN
#1 with a minor enhancement of only 0.68% of OOIP in incremental oil recovery) and the one at elevated temperature of 200 °C
with heavy oil C (RUN #6 with a minor enhancement of 1.48%
OOIP in incremental oil recovery) in the presence of IPC as an
additive (Table 11, Figs. 19 and 20). Failure in recovering more oil
in these two corefloods was likely due to the fact that the initial
waterflood recovery associated with these two tests was very
great. In the former test, the great initial waterflood recovery is
due to very small value of in-situ oil viscosity whereas in the latter
case, it was due to reduced viscosity of heavy oil as a result of
heating. Therefore, the remaining oil saturations, and consequently relative permeability to oil, at the beginning of the chemical flooding stage were significantly less compared to the other
coreflood tests.
The greatest ultimate recovery factor was observed in RUN #6
(i.e. 56.96% of OOIP) in which in-situ viscosity of heavy oil was
significantly reduced with the aid of thermal heating and the fact
that microscopic sweep efficiency was also enhanced with the
presence of IPC in the injection mainstream due to reducing the
IFT value (Table 11 and Fig. 19). The coreflood test with heavy oil C
at ambient conditions was affected more by addition of IPC to the
injecting phase during the chemical flooding stage of the process,
with an incremental oil recovery of 16.4% of OOIP, followed by
corefloods using medium-viscosity oil B, heavy oil C at elevated
temperature, and light oil A with incremental oil recovery values
of 4.5%, 1.48%, and 0.68% of their associated OOIP values, respectively (Fig. 20).
Table 9
Rock and fluid properties for the coreflood experiments.
Test No.
Oil
1
Light oil A
2
Medium oil B
3
Heavy oil C
4
Heavy Oil C
5
Heavy Oil C
6
Heavy Oil C
Brine
Chemical
Temperature, °C
Core length, cm
Core diameter, cm
Initial permeability, mD
Porosity, %
4 wt% NaCl
2 wt% IPC
22
30.8
3.81
7.2
38.76
2 wt% IPC
22
31.3
3.81
7.8
40.5
2 wt% IPC
22
30.9
3.81
7.4
36.2
1 wt% Na2CO3 þ 1 wt% NaOH
22
31.3
3.81
6.3
36.43
1 wt% Arquad T50
22
30.9
3.81
5.4
35.78
2 wt% IPC
200
30.7
3.81
5.1
41.1
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
493
Table 11
Recovery efficiency of coreflood tests with IPC as an additive.
Process stage during coreflood
Initial oil saturation stage
Initial waterflood stage
Chemical flood stage
Extended waterflood stage
Light oil A
Medium oil B
Heavy oil C
So
% OOIP recovered
So
% OOIP
So
% OOIP recovered
So
% OOIP recovered
0.622
0.320
0.319
0.316
0.0
48.48
48.76
49.16
0.847
0.629
0.615
0.591
0.0
25.7
27.4
30.2
0.940
0.833
0.685
0.678
0.0
11.4
27.1
27.8
0.690
0.294
0.287
0.284
0.00
55.48
56.55
56.96
Table 12
Performance comparison of IPC to commercial surfactant Arquad T-50 and alkaline
additives using 1D coreflood experiments with heavy oil C.
Process stage
during
coreflood
IPC
So
Initial oil saturation stage
Initial waterflood stage
Chemical flood
stage
Extended waterflood stage
% OOIP
recovered
Heavy oil C at 200 °C
Alkaline
Arquad T-50
So
So
% OOIP
recovered
% OOIP
recovered
0.940
0.0
0.910
0.0
0.937
0.00
0.833
11.4
0.817
10.3
0.826
11.79
0.685 27.1
0.695 23.7
0.729 22.13
0.678 27.8
0.693 23.8
0.722 22.97
Two coreflood experiments, both with heavy oil C, were conducted with typical chemical additives that have been used in
chemical EOR processes: (1) RUN #4 with alkali (2 wt% solution of
the 1:1 mixture of sodium carbonate and sodium hydroxide) as an
additive, and (2) RUN # 5 with a commercial surfactant “Arquad
T-50” as an additive which was selected from among five different
surfactant chemicals based on the achieved reduction in IFT value
(Table 10). Production performance results of these two corefloods
are listed in Table 12 and plotted in Figs. 21 and 22. Both of these
two additives resulted in significant incremental oil recovery (i.e.
11.18% of OOIP for Arquad T-50 assisted waterflood in RUN #5 and
13.5% OOIP for alkali flooding in RUN #4). However, the coreflood
test with IPC as an additive (i.e. RUN #3 with an incremental oil
recovery of 16.4% of OOIP) exhibited superior performance compared to these two chemical additives at similar operating conditions and rock and fluid properties (Table 12 and Figs. 21 and
22).
For each particular coreflood test, results of instantaneous recovery factor, in terms of produced percentage of OOIP as a
function of PV injected, are plotted along with pressure drop
across the core for different production stages including initial
waterflood, chemical flood, and prolonged waterflood stages associated with each core displacement test (Figs. 23–28). The incremental recovery plots, during the chemical flooding stages associated with all these tests, correlate very well in dimensionless
time, in terms of pore volume injected, with an increase in pressure drop across the cores. This behavior indicates that additional
volumes of oil were being mobilized and transported through the
core towards the producing end as soon as chemical was injected
into the mainstream, i.e. commencement of chemical flooding
stage, in each particular coreflood test. In general, the pressure
drop plots across the core for all six coreflood tests are in good
agreement with the incremental recovery plots, i.e. the greater the
incremental recovery value is, the greater is the moving average
value of the pressure drop plot at that particular process time (i.e.
pore volume injected).
4. Conclusion
A number of tests including thermal stability, physical properties determination, compatibility of IPC with brine, IFT measurement and coreflood displacement experiments were conducted to
determine the effectiveness of IPC for chemical-assisted waterflooding process. The following conclusions are obtained:
1. About 80 wt% of the chemical was lost by 85 °C in an open
system of TGA testing unit. However, the weight-loss trend of
the chemical was almost stable at higher temperature range up
Fig. 19. Effect of oil type on recovery efficiency of IPC-assisted waterflood during full life of the coreflood.
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O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
Fig. 20. Effect of oil type on recovery performance of IPC-assisted waterflood during chemical flood stage of the coreflood experiments.
Fig. 21. Effect of chemical additive on recovery performance of chemical-assisted waterflood using heavy oil C during the full life of the coreflood tests.
Fig. 22. Effect of chemical additive type on recovery efficiency of chemical-assisted waterflood to recover heavy oil C during chemical flood stage of the coreflood
experiments.
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
Fig. 23. Oil recovery and pressure drop along the core during full life of coreflood #1 to recover light oil A using IPC-assisted waterflood.
Fig. 24. Oil recovery and pressure drop along the core during full life of coreflood #2 to recover medium-viscosity oil B using IPC-assisted waterflood.
Fig. 25. Oil recovery and pressure drop along the core during full life of coreflood #3 to recover heavy oil C using IPC-assisted waterflood.
495
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O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
Fig. 26. Oil recovery and pressure drop along the core during full life of coreflood #4 to recover heavy oil C using alkaline assisted waterflood.
Fig. 27. Oil recovery and pressure drop along the core during full life of coreflood # 5 to recover heavy oil C using Arquad T50 surfactant assisted waterflood.
Fig. 28. Oil recovery and pressure drop along the core during full life of coreflood # 6 to recover heavy oil C using IPC-assisted waterflood at elevated temperature of 200 °C.
O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497
2.
3.
4.
5.
6.
until 220 °C. It is concluded that any surface-active agents in IPC
will begin to degrade at temperatures greater than a threshold
temperature of 220 °C.
IPC formulation, in its original form, has densities similar to oil
reservoir brines and viscosities about three times greater than
water at the same temperature and pressure conditions. IPC can
be used as an agent to avoid the adverse mobility ratio during
waterflooding of heavy oil reservoirs by making the injecting
displacing phase more viscous, and at the same time, it can be
used as a surfactant to reduce the interfacial tension. All these
characteristics have the potential to improve oil recovery with
the aid of IPC-assisted waterflooding.
From the IFT measurement tests, it was found that IPC was
equally or more effective in reducing IFT values at concentration
of 2 wt% than at greater concentrations, suggesting that the
optimal concentration of IPC may be lower than 2 wt%. Lesser
IFT were achieved in tests in which 4 wt% NaCl concentration
was present in brine samples, and therefore optimal salinity for
IPC chemical was above 1 wt% Total Dissolved Solid (TDS) for
the brine and oil samples tested. This is a positive result, since
most of the heavy oil reservoirs (for which the IPC appears to be
effective) have brines with salinities in the range of 40,000–
100,000 ppm.
Coreflood displacement experiments and IFT measurements
indicated that IPC can be very effective in improving heavy oil
displacement efficiency in ambient temperature (22 °C) conditions in which the greatest incremental oil recovery was
achieved (i.e. 16.4% of OOIP). However, the application of IPC at
elevated temperature of 200 °C with the same oil did not show a
significant improvement on oil recovery after injection of over
one pore volume of chemical solution due to the fact that the
initial waterflood stage recovered most of the oil and the remaining oil saturation in the core was low at the time when the
chemical flood was started.
IPC was moderately effective in recovering additional oil in the
coreflood experiment with medium-viscosity oil B. In total, 4.5%
of incremental OOIP was recovered after the expiry of the
chemical flood as well as that of the extended waterflood stages.
This number can be significant if applied to the field; however,
results of 1D coreflood experiments cannot be directly upscaled
to the field conditions. Additional work, such as larger scale
experiments, a larger variety of oils and numerical simulation
will need to be tested before any practical trend can be observed with certainty.
The amount of oil recovery using IPC was compared with those
obtained by alkali and a commercial surfactant flooding when
heavy oil C was used. These results, along with the typically
achieved incremental recovery values associated with surfactant-type chemical additives lead to the conclusion that IPC
does have a potential in chemical EOR applications for in situ
recovery of heavy oil.
497
Acknowledgment
The research was supported by a Grant from Western Economic
Diversification Canada (Project # 411342) and Enterprise Saskatchewan (Project # 411347). The authors wish to acknowledge
the support of an Instrumentation Grant from the Canada Foundation for Infrastructure. JP Giesy was supported by the Canada
Research Chair program and the Einstein Professor Program of the
Chinese Academy of Sciences.
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