Vol.2, No.5, 450-456 (2010) Natural Science
http://dx.doi.org/10.4236/ns.2010.25055
Wettability alteration by magnesium ion binding in
heavy oil/brine/chemical/sand systems—analysis of
hydration forces
Qiang Liu1, Ming-Zhe Dong2*, Koorosh Asghari1, Yun Tu3
1Faculty of Engineering, University of Regina, Regina, Canada;
2Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, Canada;
*Corresponding Author:
3Institute for Chemical Process and Environmental Technology, National Research Council, Ottawa, Canada
Received 17 November 2009; revised 13 January 2010; accepted 28 February 2010.
ABSTRACT
In laboratory sandpack tests for heavy oil re-
covery by alkaline flooding, it was found that
wettability alteration of the sand had a signifi-
cant impact on oil recovery. In this work, a
heavy oil of 14 API was used to examine the
effect of organic acids in the oil and water che-
mistry on wettability alteration. From interfacial
tension measurements and sand surface com-
position analysis, it was concluded that the
water-wet sand became preferentially oil-wet by
magnesium ion binding. The presence of Mg2+ in
the heavy oil/Na2CO3 solution/sand system in-
creased the oil/water interfacial tension. This
confirmed the hypothesis that magnesium ion
combined with the ionized organic acids to form
magnesium soap at oil/water interface. Under
alkaline condition, the ionized organic acids in
the oil phase partition into the water phase and
subsequently adsorb on the sand surfaces. The
analysis of sand surface composition sugg-
ested that more ionized organic acids adsorb-
ed on the sand surface through magnesium ion
binding. The attachment of more organic acids
on the sand surface changed hydration forces,
making the sand surface more oil-wet.
Keywords: Wettability Alteration; Alkaline Flooding;
Magnesium Ion Binding; Interfacial Tension;
Organic Acids
1. INTRODUCTION
Wettability plays an important role in determining the
distribution and flow of fluids in the pores of a reservoir
[1]. Whether the pore surface of reservoir rock is water-
wet or oil-wet is determined by the thickness of the wa-
ter film between the rock surface and the oil [2]. For
very thick films, the system is stable and remains water-
wet. If it is unstable, the film will break, resulting in
direct contact of oil to the rock surface and adsorption of
polar components on pore walls. The stability of a thick
water film is dependent on the magnitude of the disjoin-
ing pressure. The disjoining pressure that tends to disjoin
or separate the oil/water and water/rock interfaces are
identified as a combination of van der Waals, electro-
static and hydration forces. The van der Waals forces are
attractive, while electrostatic forces are repulsive be-
tween the interfaces. The hydration forces can be either a
hydrophilic effect for a surface such as clean quartz or a
hydrophobic effect for a surface with an organic coating.
If the magnitude of repulsive forces is greater than the
attractive forces, the water film is stable, and the surface
remains water-wet.
The hydrophobic effect of hydration forces can be
caused by the adsorption of polar compounds that were
originally in crude oils [3-5]. These compounds have a
polar end and a hydrocarbon chain. The polar end con-
tacts the rock surface and the hydrocarbon chain exposes
to the liquid phase, making the surface more oil-wet [6].
Some of the polar compounds are soluble in water so
that they can diffuse through the thin water film to ad-
sorb onto the rock surface [7]. It has been found that,
even when a surface active compound has a very low
solubility in water, it could reach the solid surface by
diffusion through the water film [8]. This will make the
attractive force greater and the water film could be
drained to result in an oil-wet surface.
Kowalewski et al. [9] conducted wettability tests us-
ing Berea sandstone, brine (NaCl) and n-decane with
different concentrations of hexadecylamine. The wet-
tability of the sandstone samples was changed from wa-
ter-wet to neutral due to the adsorption of hexade-
cylamine on the rock surface. Ashayer et al. [10] studied

Q. Liu et al. / Natural Science 2 (2010) 450-456
451
451
the influence of surfactant molecules (alkyl ether car-
boxylic acid) on wetting phenomena with a glass mi-
cromodel. It has been found that the solid surface attracts
the polar head group of the surfactant molecules and the
tail of the surfactant is free at the water/glass interface.
The attractive force between the hydrophobic tail of the
surfactant and the oil chain causes the formation of a
“hydrophobic bond”, which changes the wettability of
the surface from water-wet to oil-wet. Buckley et al. [11]
believed that when the brine phase contained divalent
cations, wettability could be altered by ion binding me-
chanism. The divalent ions combined the oil with min-
eral surface, making the mineral less water-wet.
Wettability alteration is one of the mechanisms of en-
hanced oil recovery by alkaline flooding. Cooke et al.
[12] studied wettability in alkaline flooding in glass mi-
cro-model by acidic oils and formation waters. They
observed that the wettability of the matrix of the glass
micro-model changed from strongly water-wet to pref-
erentially oil-wet after alkaline flooding. They believed
that the wettability alteration was caused by the adsorp-
tion of ionized acids onto the solid surface.
Waterflooding of heavy oil reservoirs exhibits very poor
sweep efficiency mainly due to a adverse mobility ratio
and water channeling [13]. Ma et al. [14] conducted
channeled sandpack flood tests of alkaline flooding for a
Western Canadian heavy oil sample. It was found that
wettability alteration of sand led to oil re-distribution,
blockage of existing water channel in porous media and
improvement in oil recovery. Liu et al. [15] studied wet-
tability alteration in a heavy oil/water/sand system by
analyzing the electronic forces at oil-water and water-
sand interfaces through ζ-potential measurements. They
found that the presence of either Na2CO3 or Mg2+ alone
in the water phase could not induce wettability alteration.
When the water phase contained both Na2CO3 and Mg2+,
the water-wet sand became preferentially oil-wet by
magnesium ion binding. The reduction in zeta ()-po-
tential at both oil-water and water-sand interfaces due to
the addition of Mg2+ to the heavy oil/Na2CO 3 solu-
tion/sand system confirmed the combination of Mg2+ and
ionized organic acids at the oil/water interface. They
concluded that the reduction of repulsive electrostatic
forces between oil drops and sand surfaces contributed
to the wettability change of the sand from water-wet to
oil-wet.
The objective of this paper is to examine the contribu-
tion of hydration forces at oil-water interface to the wet-
tability alteration in the heavy oil/water/sand system
used by Liu et al. [15]. The magnesium ion binding was
investigated by measuring oil-water interfacial tension
(IFT) and water surface tension and analyzing sand sur-
face composition. These results provide insight into the
partition of polar compounds in heavy oil/water system
and their adsorption onto the sand surface as well as the
relation between the magnesium ion binding and wet-
tability alteration.
2. EXPERIMENTAL
In this study, micro-slide and micro-model tests were
conducted to observe wettability alteration during the oil
displacement process. Heavy oil/brine interfacial ten-
sions and surface tension of water phase were measured
for different systems to investigate the interactions be-
tween heavy oil, brine and sand. Sand surface composi-
tions under different conditions were analyzed to evalu-
ate the adsorption of polar substances onto sand surface
after oil/water/sand interaction. All tests were conducted
at ambient temperature (22  0.5C) except specified.
2.1. Materials
A heavy oil of 14API collected from a reservoir in
Alberta, Canada was used in this study. The oil sample
was centrifuged at 10,000 rpm at 35C for two hours to
remove water and solids. The viscosity, density and acid
numbers of the oil were analyzed and are shown in Ta-
ble 1. The oil had a viscosity of 1,800 mPas and a den-
sity of 0.964 g/cm3 at 22C.
In this study, the effect of divalent ions (mainly Ca2+
and Mg2+) on the wettability of the sand in oil/brine/sand
system was examined. Solution of 1.0 wt% NaCl in de-
ionized water other than the formation brine was used as
water phase for the anaysis of hydration forces [15].
MgCl2 was added to adjust Mg2+ concentration in water
phase. Na2CO3 was used to neutralize the organic acids
(polar compounds) in the oil.
Varsol (a commercial solvent containing kerosene as
the main component) and ethanol were used to clean the
micromodel. The sand used in this work was from U.S.
Silica Company and was originally water-wet.
2.2. Wettability Tests with Micro-Slide and
Micro-Model
In this paper, two methods are employed to examine the
wettability of a solid surface in porous media: mi-
cro-slide test and micro-model test. For the details of the
micro-slide and micro-model tests, readers are referred
to a previous work by Liu et al. [15].
Micro-slide tests were conducted for observing the
wettability of sands in different oil/alkaline solution sys-
tems. The oil and water were equilibrated for 50 hours
Table 1. Viscosity, density and acid number of the heavy oil
sample.
Acid number, mg KOH per gram of
sample
Viscosity,
mPas Density,
g/cm3 Strong Weak Total
1,800 0.964 0.89 0.43 1.32

Q. Liu et al. / Natural Science 2 (2010) 450-456
452
and separated for micro-slide tests. Sand was added into
the water phase for adsorption for 50 hours and sepa-
rated for preparing the micro-slide models. Then a
monolayer of the sand was sandwiched between two
micro-slides and saturated with the equilibrium oil phase.
The equilibrium water phase was introduced to the mo-
del for an imbibition-type displacement of oil.
A glass micro-model was used to conduct alkaline
flooding. The transparent nature of the micro-model al-
lows the pore-scale multi-phase displacement and wet-
tability of the pore surfaces to be visually observed [16].
The displacement procedure for a micro-model test was
as follows:
1) Saturate the micromodel with the water phase (1.0
wt% NaCl);
2) Inject the heavy oil or kerosene;
3) Conduct waterflood (1.0 wt% NaCl) for two pore
volumes (PV);
4) Conduct alkaline flood by injecting 0.20 wt%
Na2CO3 in brine with or without Mg2+ for one PV.
Microphotographs were taken at different stages of
the displacement tests to observe the wettability of the
pore surface.
2.3. IFT Measurement
The spinning drop tensiometer (Model 510, Temco, USA)
was employed to measure the water surface tension and
oil/water interfacial tension. For surface tension meas-
urement, an air bubble was injected into a glass tube
filled with a water solution; for IFT measurement, an oil
droplet was injected into the glass capillary tube. The
IFTs and surface tensions are determined using the fol-
lowing equation:
327 )(1042694.3 D
dh
   L/D ≥ 4 (1)
where σ is interfacial tension (dyne/cm), 
h is the density
of heavy (outer) phase (g/cm3),

d is the density of light
(drop) phase (g/cm3),
 is rotational velocity (rpm), D is
measured drop width (diameter) (mm), and L is the
length of the oil drop (mm).
2.4. Analysis of Sand Surface Composition
In the heavy oil/brine/sand systems, some of the ionized
organic acids in the oil phase will partition into the water
phase and subsequently adsorb on the sand surface. The
adsorption of ionized organic acids on the sand surface
was investigated by analyzing the surface compositions
of the sand before and after it was brought to contact the
water phase. Because the sand surface was easily con-
taminated by oil drops in the water phase, the sand was
equilibrated with the heavy oil/brine system as follows.
1) The water phase was equilibrated with the heavy oil;
2) The water phase was filtered to remove oil droplets
before it was mixed with the sand; 3) The sand sample
was mixed with the water phase for two weeks for ad-
sorption; 4) The sand was separated from the water us-
ing a stainless steel sieve and dried in an oven at 60C
for one hour. The compositions of the top 7-nm surface
layer of the sand was analyzed by using a Kratos AXIS
Ultra X-Ray photoelectron spectrometer (XPS), equip-
ped with a hemispherical analyzer, a delay line detector,
charge neutralizer and monochromated Al Kα X-ray
source.
3. RESULTS AND DISCUSSION
3.1. Onset Na2CO3 and Mg2+ Concentrations
for Wettability Alteration
In the previous wettability study by Liu et al. [15], the
heavy oil was equilibrated with water phases of different
compositions by adding Na2CO3 or NaOH to react with
the organic acids in the oil and CaCl2 and MgCl2 to ad-
just Ca2+ or Mg2+ in the water phase. It was found that
the presence of Na2CO3 and Mg2+ could cause wettabil-
ity alteration in the heavy oil/water/sand systems. In
order to examine the effect of Na2CO3 and Mg2+ on wet-
tability alteration, micro-slide tests were conducted with
various Na2CO3 and Mg2+ concentrations.
Table 2 shows the results of micro-slide tests at dif-
ferent Na2CO3 concentrations with or without the pres-
ence of Mg2+. No wettability alteration was observed for
the samples of Series A, which contained only Na2CO3.
In the presence of 100 mg/L Mg2+, wettability alteration
occurred when Na2CO3 concentration reached a specific
value; 0.10 wt% for Series B in which 100 mg/L Mg2+
was added after the water phase was equilibrated with
the oil; 0.20 wt% for Series C in which 100 mg/L Mg2+
was added before the water phase was equilibrated with
the oil.
The onset Mg2+ concentration for wettability altera-
tion was investigated by using micro-slide tests with
0.20 wt% Na2CO3 and various Mg2+ concentrations
(named as Series D in Table 3). Magnesium ions were
added into the water phase before oil-water equilibration.
As shown in Table 3, wettability alteration was initiated
at a concentration of 50 mg/L Mg2+.
3.2. Effect of Organic Acids on Wettability
Alteration
To investigate the effect of organic acids in oil on wet-
tability alteration, two micro-model tests were conducted
to observe wettability alteration during alkaline flooding
displacement. In one test, the heavy oil was used; in the
other test, kerosene was used as the oil phase which was
free of organic acids. The same water phase (1.0 wt%
NaCl + 0.20 wt% Na2CO3 + 100 mg/L Mg2+) was used
for both tests.
Figure 1 shows the pore-level microphotographs of
the micro-model taken during the test with the heavy oil,

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Table 2. Wettability of sand in microslide tests at different Na2CO3 concentration with or without the presence of Mg2+.
Na2CO3 concentration, wt%
Test series Method of Mg2+ addition 0.020 0.050 0.10 0.20 0.50
A No Mg2+ No No No No No
B 100 mg/L Mg2+ added after water equilibrated with oil No No Yes Yes Yes
C 100 mg/L Mg2+ added before water equilibrated with oil No No Partial Yes Yes
Note: Yeswettability alteration; Nono wettability alteration; Partialpartial wettability alteration.
Table 3. Effect of Mg2+ on wettability in microslide tests, Na2CO3: 0.20 wt% (Test series D).
Concentration of Mg2+, mg/L 0 10 20 50 100 200
Wettability alteration No No No Yes Yes Yes
showing oil and water distribution at different displace-
ment stages. Water films between the oil and the pore
walls exist before the injection of alkaline solution. After
alkaline flooding, oil films exist between the water and
pore walls, indicating that the pore walls have became
preferentially oil-wet. The oil/water menisci in Figures
1(b) to 1(d) are convex to the oil phase, suggesting that
the glass pore is oil-wet. It is also shown from the dis-
tribution of oil and water phase in the pores that the
glass model has become preferentially oil-wet. The re-
sults in Figure 1 are consistent with those in micro-slide
tests.
Figure 2 shows the wettability of glass pores at dif-
ferent stages of the micro-model test with kerosene. The
glass pores remained water-wet after alkaline flooding.
The difference between crude oil and kerosene is that the
heavy oil contains organic acids and kerosene does not.
The results of the two micro-model tests suggest that the
organic acids in the oil phase are the origin of wettability
alteration in alkaline flooding.
3.3. Heavy Oil/Brine/Sand Interactions
As reviewed in the introduction, hydration forces can
have a hydrophobic effect for a surface with an organic
coating. In this section, the effect of heavy oil/brine/sand
interaction on the hydration forces is investigated. The
samples of Series A through D listed in Tables 2 and 3
were used for the following measurements and tests.
3.3.1. IFT Variation Caused by the Presence of
Mg2+
The combination of magnesium and ionized organic
acids deactivate the ionized acids at the oil/water inter-
face and, therefore, increases the oil/water interfacial
tension. To see the interaction of Mg2+ and ionized or-
ganic acids at oil/water interface, interfacial tensions of
the heavy oil and water phase were measured for sys-
tems with and without Mg2+. Figure 3 shows the inter-
facial tensions as a function of Na2CO3 concentration for
two water solutions: one did not contain Mg2+ and the
other contained 20 mg/L Mg2+. The addition of Na2CO 3
in the water phase reduced the IFT of the heavy oil and
water from its original value (approximately 25 dyne/cm)
to 2.13, 1.12, and 0.38 dyne/cm at 0.02, 0.05, and 0.1
wt% Na2CO3, respectively. In the presence of 20 ml/L
Mg2+, the IFTs were raised to 12.0, 7.5, and 4.5 at the
above three Na2CO3 concentrations, respectively, and to
approximately one order magnitude higher at Na2CO3
concentrations between 0.1 and 0.5 wt%. Figure 4
shows the IFT of the heavy oil and brine at 0.20 wt%
Na2CO3 and different Mg2+ concentrations. The IFT was
increased dramatically with Mg2+ concentration between
0 to 20 mg/L and then increased slightly with Mg2+ con-
centration in the water phase. This indicates that the sur-
face activity of the ionized organic acids was decreased
significantly by the presence of Mg2+. The divalent
cation, Mg2+, could be concentrated at the oil/water in-
terface; therefore, only 20 mg/L Mg2+ could make the
ionized organic acids incapable in reducing the IFT be-
tween the oil and water.
The dynamic IFTs of the heavy oil with three water
samples of Series D (0, 5, and 10 mg/L Mg2+) were also
(a) (b)
(c) (d)
Figure 1. Pictures of one location of micromodel at four stages
of oil displacement process. Oil phase: heavy oil, Na2CO3
concentration in alkaline slug: 0.20 wt%, Mg2+ concentration
in water: 100 mg/L. (a) After water flooding; (b) after alkaline
flooding; (c) 50 hours after alkaline flooding; (d) 150 hours
after alkaline flooding.

Q. Liu et al. / Natural Science 2 (2010) 450-456
454
(a) (b)
(c) (d)
Figure 2. Pictures of one location of micromodel at four stages
of oil displacement process. Oil phase: kerosene, Na2CO3 con-
centration in alkaline slug: 0.20 wt%, Mg2+ concentration in
water: 100 mg/L. (a) After water flooding; (b) after alkaline
flooding; (c) 50 hours after alkaline flooding; (d) 150 hours
after alkaline flooding.
0.1
1
10
100
00.10.2 0.3 0.40.5 0.6
Na
2
CO
3
concentration (wt%)
IFT (dyne/cm)
Without Mg2+
20 mg/L Mg2+
Figure 3. Interfacial tensions of heavy oil/water as a
function of Na2CO3 concentration for cases of without
and with 20 mg/L Mg2+ in the water phase. Na2CO3
concentration: 0.20 wt%.
0. 1
1
10
100
050100 150200
Mg
2+
concentration (mg/L)
IFT (dyne/cm)
Figure 4. Interfacial tensions of heavy oil/water as a
function of Mg2+ concentration. Na2CO3 concentra-
tion: 0.20 wt%.
measured and are shown in Figure 5. The system with-
out Mg2+ exhibited dynamic IFT behavior and the other
two systems with Mg2+ did not show the dynamic be-
havior within the measurement error. This indicates that
the magnesium soaps were rapidly formed at the
oil/water interface by magnesium ion binding.
3.3.2. Partition of Organic Acids into Water
Phase
When organic acids in the oil phase are ionized in alka-
line condition, they become more hydrophilic and capa-
ble to partition into water phase. In the water phase, they
will have opportunities to contact, attach to and change
the wettability of the sand surface. The presence of
Na2CO3 and/or Mg2+ can affect the partitioning of the
ionized organic acids and change the surface tension of
the water phase. Investigating the surface tension of wa-
ter can provide useful information on the partitioning of
ionized organic acids.
Surface tensions of water samples of Series A and B
were measured to investigate the effect of Na2CO3 and
Mg2+ on partitioning of the acids into the water phase.
The results are shown in Figure 6. For Series A (without
Mg2+), surface tension decreased with Na2CO3 concen-
tration. Surface tension was reduced to approximately 47
0.1
1
10
100
0 102030405060
Time (minute)
IFT (dyne/cm)
0 mg/l Mg2+
5 mg/l Mg2+
10 mg/l Mg2+
Figure 5. Dynamic interfacial tensions of heavy
oil/water with different Mg2+ concentrations. Na2CO3
concentration: 0.20 wt%.
40
45
50
55
60
0.01 0.11
Na
2
CO
3
concentration (wt%)
Surface tension (dyne/cm)
Series A
Series B
Figure 6. Surface tensions of equilibrium water phase
as a function of Na2CO3 concentration. Oil/water ratio:
1/1, Series A: no Mg2+, Series B: 100 mg/L Mg2+ in
equilibrium brine.

Q. Liu et al. / Natural Science 2 (2010) 450-456
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455
dyne/cm at 0.10 wt% Na2CO3. This is the result of the
formation of ionized organic acids and their partitioning
into the water phase. These ionized organic acids in the
water phase could not be detected with the two-phase
titration method [17], indicating that only little of ion-
ized organic acids were in the water phase. For Series B,
containing 100 mg/L Mg2+ in the equilibrium water
phase, surface tension was higher than that of Series A at
Na2CO3 concentrations higher than 0.02 wt%. This is
because the ion binding that deactivated the surface ac-
tivity of the ionized organic acids in the water phase.
The surface tension of 1.0 wt% NaCl brine was meas-
ured to be 73.0 dyne/cm. After 1.0 wt% NaCl brine
(without Na2CO3 or Mg2+) was equilibrated with the
heavy oil (oil/water volume ratio = 1:1), no further re-
duction in surface tension of the water phase was ob-
served within the experimental error. This suggests that
no organic acids in the oil phase partitioned into the wa-
ter phase. This behavior can be explained by the fact that
organic acids in the oil phase were not ionized and were
more hydrophobic. If the organic acids in the oil do not
partition into the water phase, there will be no adsorption
of organic acids on the surface of sand which is wa-
ter-wet and covered with water. This is why the sand
surface remained strongly water-wet in Test 1 listed in
Table 2.
3.3.3. Adsorption of Ionized Organic
Acids on Sand Surface
In a heavy oil/brine/sand system, the adsorption of ion-
ized acid onto sand surface affects hydration forces,
making the sand surface more hydrophobic or more
oil-wet [2]. In order to investigate the effect of the ion-
ized organic acids on sand surface wettability, sand sur-
face compositions were analyzed for five sand samples,
one of which was the original sand. The other four sam-
ples, labeled S1, S2, S3 and S4, were equilibrated with
water phase of different chemical compositions before
surface composition analysis as follows: the water phase
with 0.02 wt% Na2CO3 in Series A was used for S1; the
water phase with 0.02 wt% Na2CO3 and 100 mg/L Mg2+
in Series B was used for S2; the water phase with 0.5
wt% Na2CO3 in Series A was used for S3; and the water
phase with 0.5 wt% Na2CO3 and 100 mg/L Mg2+ in Se-
ries C was used for S4. For the above four sand samples,
only the wettability of sand sample S4 changed from
water-wet to oil-wet.
Seven elements were analyzed and the results are
shown in Table 4. The change in the element percentage
on the sand surface of samples S1–S4 was the indication
of the adsorbed substances. The adsorption of ionized
organic acids and Na2CO3 changed the percentage of
carbon (C) and oxygen (O) while the adsorption of NaCl
and MgCl2 from water phase increased the percentage of
chloride (Cl), sodium (Na), and magnesium (Mg).
The mole ratio of C/O on the sand surface is also
listed in Table 4. The C/O mole ratio of the original sand
was 0.40 and it increased from Samples S1 to S4. There
are two sources for C/O ratio change on sand surface:
adsorbed Na2CO3 and ionized organic acids. The C/O
mole ratio for the compound of Na2CO3 is 33% which is
lower than that of the original sand, showing that
Na2CO3 adsorption on the sand surface from a water
solution lowers the C/O mole ratio. The ionized organic
acids are polar compounds with a high molecular weight
and a long organic carbon chain. Because of that, they
are expected to have a much higher C/O mole ratio [4,
12]. The adsorption of organic compounds on sand sur-
face will provide more carbons. It is believed that the
high carbon content and high C/O mole ratio on sand
surface for S1 to S4 are the result of the adsorption of
ionized organic acids on the sand surface.
When a higher Na2CO3 concentration is applied in the
water phase that is in contact with the oil phase, more
organic acids will be ionized. Some of the ionized acids
will subsequently partition into water, and adsorb onto
the sand surface. The adsorption of ionized organic acids
on sand surface is the reason for the higher C/O mole
ratio in Sample S3 (0.5 wt% Na2CO3) than in Sample S1
(0.02 wt% Na2CO3). Table 4 shows that Sample S4 has a
much higher C/O mole ratio than Sample S3, indicating
that much more ionized organic acids attached on the
sand surface for Sample S4 than for Sample S3. There
was 100 mg/L Mg2+ in water phase for Sample S4 and
no Mg2+ for Sample S3. The presence of Mg2+ increased
the adsorption of ionized organic acids onto the sand
surface. This indicates that wettability alteration of S4 is
caused by the magnesium binding mechanism in the
heavy oil/brine/sand system. Through the ion binding of
Mg2+, more ionized organic acids in the aqueous phase
attached to the sand surface. The hydrophobic tail of the
surfactant on sand surface was more easily contacted by
oil. The hydration forces became unfavorable for sus-
taining the water film between the oil and sand surface.
It was concluded from the previous work [15] that the
Table 4. Sand surface element analysis (mole percent) and mole ratio of C/O.
Element C O Cl Si Al Na Mg C/O
Original sand 20.9 51.0 N/D 18.7 7.4 0.5 N/D* 0.40
S 1 24.4 45.8 0.8 18.8 7.7 2.2 N/D 0.41
S 2 29.3 43.4 0.5 16.8 6.9 1.1 1.6 0.68
S 3 30.7 42.6 0.5 16.3 6.1 3.9 N/D 0.72
S 4 63.6 26.3 0.2 5.8 2.0 1.2 0.9 2.42
* N/Dnot detectable

Q. Liu et al. / Natural Science 2 (2010) 450-456
456
negative charges at both the oil/water and water/sand
interfaces were reduced by the Mg2+ ion binding, weak-
ening the repulsive forces between the two interfaces.
The changes of both electrostatic forces and hydration
forces contributed to the wettability alteration in the
heavy oil/brine/sand system.
4. CONCLUSIONS
In this study, the mechanism of wettability alteration in a
heavy oil/alkaline solution/sand system was investigated
by analyzing the hydration forces, which revealed the
following conclusions.
The presence of either Na2CO3 or Mg2+ alone in water
could not induce wettability alteration. When water con-
tained both Na2CO3 and Mg2+, wettability of the solid
could be altered from water-wet to preferential oil-wet.
Wettability of sand was altered from water-wet to pref-
erential oil-wet by the Mg2+ ion binding mechanism.
Under alkaline conditions, magnesium concentration of
~50 mg/L could cause wettability alteration.
The heavy oil-water interfacial tension was greatly
increased due to the combination of Mg2+ and the ion-
ized organic acids at the oil/water interface. The analysis
of sand surface composition showed significant increase
in carbon content and C/O ratio in sand top surface layer
due to the adsorption of magnesium soap of the organic
acids. These results are consistent with the reduction in
surface charges at both the oil/water and water-sand in-
terfaces obtained in a previous study. The magnesium
ion binding reduced both electrostatic and hydration
forces at the oil/water and water/sand interfaces and
caused wettability alteration of sand surface.
Water phase surface tension data showed that the ion-
ized organic acids can partition into the water phase.
Through the Mg2+ ion binding, the ionized organic acids
in the aqueous phase attached to the sand surface. The
attachment of the organic acids on the sand surface de-
creased the hydration forces, making the sand surface
more oil-wet.
5. AKNOWLEDGEMENTS
Acknowledgment is extended to the Petroleum Technology Research
Centre (PTRC), Murphy Oil Company Ltd., the Natural Sciences and
Engineering Research Council (NSERC) of Canada, and the Canada
Foundation for Innovation (CFI) for their financial support for this
work. The authors wish to express their thanks to Murphy Oil Com-
pany Ltd. for providing the oil and brine samples.
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