energies
Article
Enhancing Oil Recovery from Chalk Reservoirs by a
Low-Salinity Water Flooding Mechanism and
Fluid/Rock Interactions
Aly A. Hamouda * and Sachin Gupta
Department of Petroleum Engineering, University of Stavanger, 4036 Stavanger, Norway;
[email protected]
* Correspondence: [email protected]; Tel.: +47-51-832-271
Academic Editor: Alireza Bahadori
Received: 7 February 2017; Accepted: 17 April 2017; Published: 22 April 2017
Abstract: Different Low Salinity Waters (LSWs) are investigated in this work to understand the role
of some ions, which were recognized from our previous work and the literature for their effect on
wettability alteration. Different flooding stages were followed. The primary stage was by injecting
synthetic seawater (SSW) and the secondary stage was with SSW diluted by 10 (LSW 1:10) and 50
(LSW 1:50) times, single and two salt brines, such as Na2 SO4 , MgCl2 , and NaCl+MgCl2 at 70 ◦ C. The
flooding sequence was due to that most of the fields in the North Sea were flooded with seawater. Two
flooding rates were followed, 4 PV/day (PV = Pore Volume) and 16 PV/day in all the experiments.
One of the observations was the increase of the pH during the flooding with LSW and single salt
brines. The increase of the pH was attributed to mineral precipitation/dissolution as the results
of ionic interactions. The effluent ion concentrations measured to understand the most likely oil
recovery mechanisms. The results showed that the higher the SSW dilution the slower the oil recovery
response. In presence of SO4 2− , Ca/Mg, higher oil recovery. The exchange between Ca/Mg, was
in line with field observations. A geochemical simulation was done for a comparison with the
experimental data.
Keywords: low salinity flooding; oil recovery; chalk; calcium; magnesium; sulfate
1. Introduction
During the early life of a reservoir, the hydrocarbons are extracted using the reservoir’s natural
energy. As the pressure of the reservoir depletes, there is a need of maintain the reservoir pressure
by means of some external help. Water injection has been proven to be an economical and effective
secondary recovery method. Over the last decade, low salinity water (LSW) flooding has been
considered as a viable Enhanced Oil Recovery (EOR) method. Several Lab experiments has been
performed, which show a significant increase in oil recovery in chalk from LSW after the injection of
high salinity water/brine.
Low Salinity Water Flooding is one of the emerging EOR techniques for wettability alteration in
carbonate reservoirs. This technique is widely popular because of ease of injection into oil-bearing
formations, its efficiency in displacing light to medium gravity crude oil, and low capital and operating
cost, all of which lead to favorable economics compared to other EOR methods [1]. Initially, extensive
laboratory studies have been conducted on sandstone rocks after producing 15% additional oil from a
Kansas oil field [2]. The increase in oil recovery from sandstone rocks was found to be in the range of
5–20% of OOIP as reported in several studies [3–6].
Low Salinity Water Flooding was first attempted by [7], at the University of Wyoming. Since
then both laboratory experiments and various field tests had shown that injecting modified water can
Energies 2017, 10, 576; doi:10.3390/en10040576
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Energies 2017, 10, 576
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help increase oil recovery. A number of low salinity water flooding mechanisms have been proposed,
i.e., fine migration (dispersion of rock minerals), pH increase, double layer expansion effect and
wettability alteration, including adsorption of SO4 2− with co-adsorption of Ca2+ and replacement of
Ca2+ by Mg2+ on chalk surface because of increase in ion reactivity at higher temperature [8], but a
concise mechanism which conforms to the LSW effect is still debatable. Based on whatever has been
published so far in the literature, the mechanisms are mainly related to the presence of clay minerals,
oil composition, and presence of formation water. Concentration of divalent ions (Ca2+ , Mg2+ , SO4 2− )
and salinity level of high saline water in range of 1000 ppm–3000 ppm also play an important role in
LSW effects [9].
This work is focused mainly on observing the effects of the type and concentration of ions on the
increase in secondary recovery. From the experiments it has shown that the injection of water/brine
with modified composition alters the wettability and enhances the oil recovery. These effects are linked
to exchange of effective ions (Ca2+ , Mg2+ , SO4 2− ) from/to the reservoir surface and brine. This work is
concerned towards secondary injection of brine containing only a single ion (Mg2+ /SO4 2− ) and brines
diluted in proportion of 1:10 and 1:50. Carbonate samples were recovered from the Bu-Hasa field in
Abu Dhabi from the experiments observed by [10]. They observed an optimum concentration of SO4 2−
at which highest recovery is obtained, which was 47 ppm.
This work also contributes towards confirming the best possible dilution ratio of SSW to observe
optimum oil recovery. In addition, all the experiments were performed at 25 bar and 70 ◦ C/90 ◦ C.
SSW is used as primary injection brine and brines with different monovalent and divalent cations
were used as secondary injection brines. Effluent’s pH, pressure drop, and oil recovery were measured.
Ion tracking results were obtained by ion chromatography and analyzed to assess the ion exchange
between rock and brine.
2. Experimental
2.1. Materials
2.1.1. Porous Media
Stevens Klint (Denmark), chalk with an average permeability of 3.9 ± 0.5mD is used as the porous
media for the experiments. Similar cores were created from the same rock. Stevens Klint chalk is
stratigraphically comparable to the interval including the uppermost Tor formation and the lower
Ekofisk formation in North Sea chalk reservoirs. All the core details such as, porosity, initial water
saturation (swi ), Residual Oil Saturation (sor ) etc. are given in Table 1.
Table 1. Properties of cores saturated with Model Oil (n-decane+stearic acid, SA) and Crude Oil X from
the North Sea.
Oil Used in
Saturation of
Cores
Model Oil
(n-decane +
stearic acid, SA)
Crude Oil X
Core
Length
(cm)
Diameter
(cm)
swi
(%)
sor (%)
Pore Volume
(mL)
Porosity
(%)
Flooding Sequence of
Brines in the Core
1
2
4
7
8
5
6
5.92
6.01
5.95
6.00
6.00
6.008
6.00
3.78
3.78
3.78
3.78
3.78
3.78
3.78
23
21
22.3
21.8
28.5
19.01
21.1
24.4
35.8
32.2
40.2
23.1
32.5
38.4
34.23
34.23
31.94
34.8
33
32.50
34.50
51.8
51.8
50.12
52.22
50.99
50.55
52.04
SSW/SO4 (1:10)
SSW/Mg (1:10)
SSW/SO4 (1:50)
SSW/Mg+Na (1:10)
SSW/Mg (1:10) at 90 ◦ C
SSW/LSW (1:10)
SSW/LSW (1:50)
2.1.2. Oil
For experiments both crude oil and model oil were used. Model-oil—a mixture of n-decane and
stearic acid—was used for the flooding experiments. The concentration of stearic acid in n-decane
is 0.005 mole/L. n-Decane was supplied by Chiron AS (Trondheim, Norway) at 99% purity. Aldrich
Energies 2017, 10, 576
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(Oslo, Norway) supplied stearic acid at 98.5% purity. Stearic acid acts as a natural surfactant and it
is present in crude oils. The physical properties of synthetic oil are given in Table 2. A crude oil X,
of a composition given in Table 3, is used for experiments. The Acid Number (AN) and Base Number
(BN) for this crude oil is 0.06 KOH/g and 0.60 KOH/g, respectively. The physical properties and
composition of the crude is given in Tables 2 and 3.
Table 2. Physical Parameters of Model Oil (n-decane + Stearic acid, SA) and Crude Oil.
Property
Temperature
Model Oil (n-decane + 0.005M SA)
Crude Oil X
0.73
0.705
0.67
0.41
0.7827
0.7009
0.7537
0.4976
◦C
Density (g/cc)
Dynamic Viscosity (cP)
20
50 ◦ C
70 ◦ C
70 ◦ C
Table 3. Composition of Crude Oil X.
Components
Mole Fraction
i-C5
n-C5
C6
C7
C8
C9
C10
1.79 × 10−5
0.000117
0.002371
0.013287
0.039608
0.062886
0.881712
2.1.3. Brines
Synthetic seawater (SSW) was used in the initial saturation of core and also as a primary injection
brine in the flooding sequence. As a secondary brine, brines with different ionic composition were
prepared and injected. Overall, six such modified brines are prepared, with different salt concentrations
and dilution ratios, in distilled water (DW). The compositions of all the brines are given in Table 4.
Table 4. Ion compositions in SSW and LS Brines used in secondary injection.
Ions/Brine
HCO3 −
Cl−
SO4 2−
Mg+2
Ca+2
Na+
K+
TDS (ppm)
TDS (g/L)
Ionic Strength
pH
SSW
LSW 1:10
LSW 1:50
(mole/L)
(mole/L)
(mole/L)
0.002
0.525
0.024
0.045
0.013
0.45
0.01
33,388
33.33
0.657
7.83
0.0002
0.0525
0.0024
0.0045
0.0013
0.045
0.001
3338.8
3.33
0.0657
7.32
0.00004
0.0105
0.00048
0.0009
0.00026
0.009
0.0002
667.76
0.667
0.01314
6.74
Mg+Na
SO4 2− Brine
SO4 2− Brine
Mg2+ Brine
1 to 10
1 to 10
1 to 50
1 to 10
(mole/L)
(mole/L)
(mole/L)
(mole/L)
0.0024
0.00048
0.0493
0.009
0.0045
0.0045
0.0403
0.0046
0.00092
2785
2.78
0.0538
5.85
336.2
0.336
0.007
7.12
67.24
0.067
0.0014
6.74
423
0.423
0.0135
6.11
2.1.4. Core Preparations and Flooding
The chalk cores were first dried at 100 ◦ C for at least 48 h to remove all water that might be
present in the pore spaces. Cores were then saturated with SSW using a vacuum setup. The initial
water saturation was established at 25 bar and 50 ◦ C. The saturated brine cores were flooded with
the synthetic oil or crude oil X at different injection rates (0.02–0.2 mL/min) to establish initial water
saturation for the core, swi (range 21−25%) and then aged for 2 weeks at 50 ◦ C. Once the cores had
synthetic oil or crude oil X at different injection rates (0.02–0.2 mL/min) to establish initial water
saturation for the core, swi (range 21−25%) and then aged for 2 weeks at 50 °C. Once the cores had
aged, they were flooded with different LS brines at 70 °C/90 °C to perform the main experiment. The
confining pressure was set at 25–30 bar, to simulate reservoir conditions and give a good seal between
Energies 2017, 10, 576
4 of 16
the heat-shrinkable
plastic sleeve and core and the outlet pressure was set at 9–10 bar.
For all the
flooding experiment, the cores were weighed before and after to check for any discrepancy between
aged, they
were flooded
with different
LS brines at 70 ◦ C/90 ◦ C to perform the main experiment. The
the measured
volumes
and calculated
saturations.
confining pressure was set at 25–30 bar, to simulate reservoir conditions and give a good seal between
Each
core was flooded for at least 4 PV (PV = pore volume) at the low flow rate of 4 PV/day, and
the heat-shrinkable plastic sleeve and core and the outlet pressure was set at 9–10 bar. For all the
then restflooding
4 PV ofexperiment,
brine wasthe
flooded
at the
highbefore
flow rate
of 16
These
flow rates
were chosen
cores were
weighed
and after
to PV/day.
check for any
discrepancy
between
to: (1) closely
resemble
ratesand
at calculated
the reservoir,
(2) compare the results obtained from the experiments
the measured
volumes
saturations.
Each
was floodedearlier
for at least
(PVeliminate
= pore volume)
at the low flow
of 4 PV/day,
and
performed in
thecore
laboratory
[11]4 PV
and
the capillary
endrate
effect.
The schematic
of
then
rest
4
PV
of
brine
was
flooded
at
the
high
flow
rate
of
16
PV/day.
These
flow
rates
were
chosen
system is shown in Figure 1. The pressure drop across the core was measured by the pressure gauge,
to: (1) closely resemble rates at the reservoir; (2) compare the results obtained from the experiments
and recorded
using the Labview program. The effluent samples were collected after a preset interval,
performed in the laboratory earlier [11] and eliminate the capillary end effect. The schematic of system
using a sample
Middleton,
WI, USA).
valuesbyofthe
the
effluent
wereand
measured
is shownchanger
in Figure(Gilson,
1. The pressure
drop across
the coreThe
waspH
measured
pressure
gauge,
using a Mettler
meterprogram.
(Mettler-Toledo,
at intervals.
The ion
tracking
recordedToledo
using thepH
Labview
The effluent Hong
samplesKong)
were collected
after a preset
interval,
usingfrom the
sample measured
changer (Gilson,
Middleton,
WI, USA).
The pH values
of the effluent were
measured using Scientific,
a
effluent awere
using
an Dionex
ICS-3000
chromatograph
(ThermoFisher
Mettler
Toledo
pH
meter
(Mettler-Toledo,
Hong
Kong)
at
intervals.
The
ion
tracking
from
the
effluent
Waltham, MA, USA). Data were processed after the analyses using the Chromeleon (Dionex)
program.were measured using an Dionex ICS-3000 chromatograph (ThermoFisher Scientific, Waltham, MA,
USA). Data were processed after the analyses using the Chromeleon (Dionex) program.
Figure 1. Schematic of the flooding system.
Figure
1. Schematic of the flooding system.
3. Results and Discussion
3. Results and Discussion
In this work results were measured and analyzed during secondary injection of low salinity (LS)
In this
work
were
measured and analyzed during secondary injection of low salinity (LS)
brines
and results
single salt
brines.
brines and single salt brines.
3.1. Oil Recovery from Secondary Flooding with LS
All the
cores
were flooded
with SSW
a primary injection fluid and then flooded with different
3.1. Oil Recovery
from
Secondary
Flooding
withasLS
LS brines as secondary injection fluid. In Figure 2, oil recoveries after injection of LSWs, single and
salts brine
into
the cores
are shown.
cores wereinjection
flooded with
two
injection
rates: 4 PV/day
All two
the cores
were
flooded
with
SSW asThe
a primary
fluid
and
then flooded
with different
andinjection
16 PV/dayfluid.
(0.36 mL/min).
in oil recovery
by SSW may
be duesingle
to
LS brines(0.09
as mL/min)
secondary
In FigureThe
2, differences
oil recoveries
after injection
of LSWs,
and
the differences in the pore size distribution of the different cores. The lower swi for cores #2, #5, #6, #7
two salts brine into the cores are shown. The cores were flooded with two injection rates: 4 PV/day
and #4 compared to the others (Tables 1 and 2) may indicate the differences in the core composition.
(0.09 mL/min)
and 16 PV/day (0.36 mL/min). The differences in oil recovery by SSW may be due to
Ultimate recoveries after secondary flooding were: LSW 1:10 (52.9), LSW 1:50 (51.1), SO4 1:10 (68.2),
the differences
theMg70C
pore size
of the
different
cores.(%The
lower sw
coresThe
#2, #5, #6,
SO4 1:50 in
(58.4),
(54.6),distribution
Mg90C (67.6) and
Mg+Na
(48.5) brines
oil recovery)
at 4i for
PV/day.
incremental
oil
recoveries
after
the
secondary
flooding
may
be
summarized
as:
LSW
1:10
(1),
LSW
1:50
#7 and #4 compared to the others (Tables 1 and 2) may indicate the differences in the core
(0.2), SO
SO4 1:50 (2.3),
(0.11), Mg90
(1.1) and
Mg+Na
(%LSW
oil recovery).
4 1:10 (3.8),
composition.
Ultimate
recoveries
afterMg70
secondary
flooding
were:
LSW(0.5),
1:10brines
(52.9),
1:50 (51.1), SO4
Energies 2017, 10, 576
5 of 16
1:10 (68.2), SO4 1:50 (58.4), Mg70C (54.6), Mg90C (67.6) and Mg+Na (48.5) brines (% oil recovery) at 4
PV/day. The incremental oil recoveries after the secondary flooding may be summarized as: LSW
Energies 2017, 10, 576
5 of 16
1:10 (1), LSW 1:50 (0.2), SO4 1:10 (3.8), SO4 1:50 (2.3), Mg70 (0.11), Mg90 (1.1) and Mg+Na (0.5), brines
(% oil recovery). After switching the injection rate to 16 PV/day, no extra recovery was observed in
any of
the studied
cases, except
with
LSW 1:10,
gave a 1.9%
increase in
After
switching
the injection
rate to
16 PV/day,
no which
extra recovery
was observed
in recovery.
any of theFigure
studied2
showsexcept
that initial
slopes
of the
oil gave
recovery
curves
are in
different.
This
may2 be
because
pore
size
cases,
with LSW
1:10,
which
a 1.9%
increase
recovery.
Figure
shows
that the
initial
slopes
distributions
of the
cores
not exactly
same.
carbonate
be of two types:
or
of
the oil recovery
curves
areare
different.
This may
be The
because
the porecould
size distributions
of the calcite
cores are
aragonite.
not
exactly same. The carbonate could be of two types: calcite or aragonite.
LSW 1:10
60
SSW
4PV/day
50
Oil Recovery (%OOIP)
LSW 1:50
2.6 more PV were
injected in case of
LSW1:50 than LSW
1:10 to get an
increase of 0.2% in
recovery from
50.9% to 51.1%
40
SSW
16PV/day
30
20
10
LSW
4PV/day
0
0
4
8
LSW
16PV/day
12
(A)
Brine PV injected
SO4 1:10
Oil Recovery (%OOIP)
80
16
SO4 1:50
70
60
50
40
SSW
16PV/day
30
LS Brine
4PV/day
SSW
4PV/day
20
10
LS Brine
16PV/day
0
0
4
8
12
(B)
Oil Recovery (%OOIP)
Brine PV injected
Mg 70C
80
Mg+Na
16
Mg 90C
60
40
LS Brine
16PV/day
LS Brine
4PV/day
SSW
16PV/day
SSW
4PV/day
20
0
0
4
8
Brine PV injected
Figure 2. Cont.
12
(C)
16
Energies 2017, 10, 576
Energies 2017, 10, 576
6 of 16
6 of 16
Figure 2. Cont.
SO4 1:10
Oil Recovery (%OOIP)
80
Mg 70C
Mg+Na
70
60
50
40
30
20
SSW
4PV/day
10
LS Brine
4PV/day
SSW
16PV/day
LS Brine
16PV/day
0
0
4
8
Brine PV injected
12
(D)
16
Figure 2.
2. Comparison
Comparison of
of Oil
Oilrecovery
recoveryasasaafunction
functionofofPV
PVafter
after
flooding
with
SSW
primary
Figure
flooding
with
SSW
as as
primary
fluidfluid
and
and
different
secondary
injection
fluid
(LSW
and
LS
brines):
(A)
LSW
(1:10
&
1:50);
(B)SO
(1:10
&
different secondary injection fluid (LSW and LS brines): (A) LSW (1:10 & 1:50); (B) SO4 (1:104 &
1:50);
4 1:10, Mg70C & Mg+Na.
1:50);
& 90C),
Mg+Na;
(D)SO
(C)
Mg(C)Mg(70C
(70C & 90C),
Mg+Na;
(D) SO
4 1:10, Mg70C & Mg+Na.
Figure 2A demonstrates a slightly slower recovery response. For example, the response time for
Figure 2A demonstrates a slightly slower recovery response. For example, the response time for
LSW 1:50 compared to LSW 1:10, (circled in the figure) was an extra 2.6 PV to reach a recovery of
LSW 1:50 compared to LSW 1:10, (circled in the figure) was an extra 2.6 PV to reach a recovery of 0.2%,
0.2%, i.e., from 50.9% to 51.1%. In [12], using a CMG-GEM reservoir simulator, a delay caused by the
i.e., from 50.9% to 51.1%. In [12], using a CMG-GEM reservoir simulator, a delay caused by the highest
highest dilution, LSW (1:25), was observed. Figure 2B shows higher recovery by flooding with SO4
dilution, LSW (1:25), was observed. Figure 2B shows higher recovery by flooding with SO4 1:10 (68.2%)
1:10 (68.2%) than that in the case of SO4 1:50, similar to the response observed by flooding with LSW
than that in the case of SO4 1:50, similar to the response observed by flooding with LSW 1:10 and 1:50.
1:10 and 1:50.
Comparison of oil recoveries from flooding with Mg salt brine (at 70 ◦ C & 90 ◦ C) and Mg + Na salt
Comparison of oil recoveries from flooding with Mg salt brine (at 70 °C & 90 °C) and Mg + Na
brines is shown in Figure 2C. Oil recovery was highest in case of Mg90 (67.6%) and lowest in case of
salt brines is shown in Figure 2C. Oil recovery was highest in case of Mg90 (67.6%) and lowest in case
Mg+Na brine (48.5%). This difference in oil recoveries may be due to differences in the affinity of Ca2+
of Mg+Na brine (48.5%). This difference in oil recoveries may be due to differences in the affinity of
and2+ Mg2+ ions
towards surface at different temperatures [13]. Figure 2B–D shows a higher oil recovery
Ca and Mg2+ ions towards surface at different temperatures [13]. Figure 2B–D shows a higher oil
in case of SO4 1:10 (68.2%) compared to Mg70C (54.68%) and Mg+Na (48.5%). The reason, which may
recovery in case of SO4 1:10 (68.2%) compared to Mg70C (54.68%) and Mg+Na (48.5%). The reason,
explain this difference in oil recovery, is ion interaction, which is explained later in this paper.
which may explain this difference in oil recovery, is ion interaction, which is explained later in this
Pressure drop curves for the floodings are shown in Figure 3. During the flooding, pressure drop
paper.
peaks were observed at various flooding PVs. From Figure 3A,B at the start of SSW flooding pressure
Pressure drop curves for the floodings are shown in Figure 3. During the flooding, pressure drop
drop (dP), at 4 PV/day, reached a peak of 1.8(0.69) and 1.5(1.3) bar (PV) for LSW 1:10 and LSW 1:50,
peaks were observed at various flooding PVs. From Figure 3A,B at the start of SSW flooding pressure
respectively. The observed pressure drop peaks were stabilized at almost same point, i.e., 0.62 (3.8) for
drop (dP), at 4 PV/day, reached a peak of 1.8(0.69) and 1.5(1.3) bar (PV) for LSW 1:10 and LSW 1:50,
LSW 1:10 and 1:50. When the rate was increased to 16 PV/day, dP increased to 1.3 (4.9) and 2.3 (4.6)
respectively. The observed pressure drop peaks were stabilized at almost same point, i.e., 0.62 (3.8)
bar (PV) for LSW 1:10 and 1:50, respectively, after that dP stabilized at 1.33 (6.7 PV) for LSW 1:10 and
for LSW 1:10 and 1:50. When the rate was increased to 16 PV/day, dP increased to 1.3 (4.9) and 2.3
1:50. Pressure drop, dP, stabilizes when the rock/fluid interaction reaches equilibrium.
(4.6) bar (PV) for LSW 1:10 and 1:50, respectively, after that dP stabilized at 1.33 (6.7 PV) for LSW 1:10
Figure 3C at the beginning of SSW flooding at 4 PV/day pressure drop reached a peak of 1.33 (0.59)
and 1:50. Pressure drop, dP, stabilizes when the rock/fluid interaction reaches equilibrium.
and 2.064 (0.9) bar (PV) for SO4 brine 1:10 and 1:50, respectively. dP fluctuated and then stabilized at
Figure 3C at the beginning of SSW flooding at 4 PV/day pressure drop reached a peak of
1.13 (2.8) and 1.14 (2.7) bar (PV), respectively for SO4 1:10 and 1:50. When the rate was increased to 16
1.33(0.59) and 2.064(0.9) bar (PV) for SO4 brine 1:10 and 1:50, respectively. dP fluctuated and then
PV/day, dP spiked up to 2 (4.1) and 5 (4.2) bar (PV), after that dP stabilized at 1.9 (5) and 4 (5.5) bar
stabilized at 1.13(2.8) and 1.14(2.7) bar (PV), respectively for SO4 1:10 and 1:50. When the rate was
(PV) respectively for SO4 1:10 and 1:50. Due to less calcite dissolution with SO4 1:10 than SO4 1:50,
increased to 16 PV/day, dP spiked up to 2(4.1) and 5(4.2) bar (PV), after that dP stabilized at 1.9(5)
the pressure drop is lower in the case of SO4 1:10 than with SO4 1:50. At 16 PV/day less fluctuations in
and 4(5.5) bar (PV) respectively for SO4 1:10 and 1:50. Due to less calcite dissolution with SO4 1:10
dP were observed during flooding with SO4 1:10 and 1:50. Constant dP may reflect constant resistance
than SO4 1:50, the pressure drop is lower in the case of SO4 1:10 than with SO4 1:50. At 16 PV/day less
to the flow of brine, hence, a decrease in the sweep efficiency in the pores. This was also reflected in oil
fluctuations in dP were observed during flooding with SO4 1:10 and 1:50. Constant dP may reflect
recovery curves. When brine was switched to SO4 brine at a rate of 4 PV/day, less fluctuations were
constant resistance to the flow of brine, hence, a decrease in the sweep efficiency in the pores. This
observed in case of SO4 1:50 than SO4 1:10. dP stabilized roughly at 0.3 bar after 0.7 PV (equivalent to
was also reflected in oil recovery curves. When brine was switched to SO4 brine at a rate of 4 PV/day,
a total of 8.7 PV from start) and 1 bar after 1 PV (equivalent to a total of 9 PV from start) respectively
less fluctuations were observed in case of SO4 1:50 than SO4 1:10. dP stabilized roughly at 0.3 bar after
for SO4 1:10 and 1:50.
0.7 PV (equivalent to a total of 8.7 PV from start) and 1 bar after 1 PV (equivalent to a total of 9 PV
from start) respectively for SO4 1:10 and 1:50.
Energies 2017, 10, 576
7 of 16
Energies 2017, 10, 576
7 of 16
LSW
4PV/day
LSW
16PV/day
SSW
16PV/day
(A)
3
dP, Bar
2.5
2
LSW 1:50
SSW
16PV/day
SSW
4PV/day
LSW
16PV/day
LSW
4PV/day
1.5
1
0.5
0
0
4
8
12
(B)
PV
6
SO4 1:10
dP, Bar
5
SSW
4PV/day
4
SO4
4PV/day
SSW
16PV/day
3
SO4 1:50
SO4
16PV/day
2
1
0
0
4
8
12
(C)
PV
3.5
Mg 70C
3
2.5
dP, Bar
Mg 90C
SSW
4PV/day
Mg
4PV/day
2
1.5
SSW
16PV/day
1
Mg
16PV/day
0.5
0
0
4
8
PV
Figure 3. Cont.
12
(D)
Energies
2017,
10, 576
Energies
2017, 10,
576
8 of 168 of 16
Figure 3. Cont.
7
6
5
dP, Bar
SSW
16PV/day
SSW
4PV/day
Mg+Na
Mg+Na
4PV/day
4
3
2
Mg+Na
16PV/day
1
0
0
4
8
PV
12
16
(E)
Figure 3. Pressure drop across the core during Primary secondary injection of SSW and different LS
Figure 3. Pressure drop across the core during Primary secondary injection of SSW and different LS
brines, respectively as a function of the flooded PV of brines: (A) LSW 1:10, (B) LSW 1:50, (C) SO4 1:10
brines, respectively as a function of the flooded PV of brines: (A) LSW 1:10, (B) LSW 1:50, (C) SO4 1:10
and 1:50, (D) Mg70C and Mg90C, (E) Mg+Na.
and 1:50, (D) Mg70C and Mg90C, (E) Mg+Na.
Three main observations were made from injection of LSWs and SO4 brines (1:10 and 1:50):
Three
main fluctuations
observations
were
made at
from
injection
of4LSWs
and
SO4case
brines
(1:10
and
1:50):
(1) Higher
were
observed
16 PV/day
than
PV/day
in the
of LSW
1:10
and
1:50
(1)
(2)
(3)
flooding. This may mean occasional resistance to the flow, hence a possible increase of the sweep
Higher
fluctuations were observed at 16 PV/day than 4 PV/day in the case of LSW 1:10 and
efficiency.
1:50
flooding.
This of
may
mean
occasional
resistance
to the
flow,
a possible
increase
(2) The magnitude
dP was
higher
in case of
dilution ratio
1:50
thanhence
1:10, this
is perhaps
due to of
a the
2+
sweep
efficiency.
higher availability of Ca promoting precipitation of sulfate salt over the limit if diverting flow
increasing the
The magnitude
oftrapped
dP wasoil.
higher in case of dilution ratio 1:50 than 1:10, this is perhaps due to a
(3) Higher
recovery of
in the
case
of dilution precipitation
ratio 1:10 than 1:50,
which salt
has also
in the case flow
higher
availability
Ca2+
promoting
of sulfate
overbeen
theobserved
limit if diverting
of
sulfate
salt
single
brine
flooding
may
support
the
above
point
(2).
In
[14],
several
dilutions
of LSW
increasing the trapped oil.
were investigated and concluded that the dilution of 1:10 gave the best incremental oil recovery.
Higher recovery in the case of dilution ratio 1:10 than 1:50, which has also been observed in the
Figurebrine
3D,E flooding
Mg brinemay
was support
injected at
°C and
90 °C
and
+NaCl brine
case Similarly,
of sulfate from
salt single
the70above
point
(2).
InMgCl
[14], 2several
dilutions
was
injected
as
a
secondary
injection
fluid.
From
Figure
3D,E
at
the
beginning
of
SSW
flooding
at 4
of LSW were investigated and concluded that the dilution of 1:10 gave the best incremental
PV/day pressure drop reached a peak of 1.33(0.98), 1.7(0.58) and 2.42(0.46) bar (PV) for Mg70, Mg90
oil recovery.
and Mg+Na, respectively. After some fluctuations, dP stabilized at 1.1(2.3), 1.14(1.1) and 2.11(1.84)
bar (PV), respectively
for3D,E
Mg70,
Mg90
andwas
Mg+Na.
When
was90
increased
16 PV/day,
dP
◦ C andto
Similarly,
from Figure
Mg
brine
injected
at the
70 ◦rate
C and
MgCl
2 +NaCl brine
spiked up 1.9(3.8), 3(3.91) and 5.9(3.8) bar PV, and it stabilized at 1.7(5.8), 2.2(6.05) and 3.9(5.8),
was injected as a secondary injection fluid. From Figure 3D,E at the beginning of SSW flooding at
respectively, for Mg70, Mg90 and Mg+Na. At 16 PV/day much less fluctuation in dP was observed
4 PV/day pressure drop reached a peak of 1.33(0.98), 1.7(0.58) and 2.42(0.46) bar (PV) for Mg70, Mg90
than at 4 PV/day. When brine was switched to LS (Mg70, Mg90 & Mg+Na) brines at a rate of 4 PV/day,
and Mg+Na,
respectively.
After some
dPcases.
stabilized
1.14(1.1)
andof
2.11(1.84)
dP showed
smaller fluctuations
thanfluctuations,
SSW in all the
In caseatof1.1(2.3),
Mg70, the
magnitude
dP was bar
(PV), constant
respectively
for
Mg70,
Mg90
and
Mg+Na.
When
the
rate
was
increased
to
16
PV/day,
spiked
(Figure 3D) and dP stabilized roughly at 0.3 bar after 2.86 PV (equivalent to a total ofdP
10.86
up 1.9(3.8),
3(3.91)
and
5.9(3.8)
bar
PV,
and
it
stabilized
at
1.7(5.8),
2.2(6.05)
and
3.9(5.8),
respectively,
PV from start), 0.56 bar after 1 PV (equivalent to a total of 9 PV from start) and 1.2 bar after 2.04 PV for
Mg70,(equivalent
Mg90 andtoMg+Na.
16 PV
PV/day
muchrespectively
less fluctuation
in dP
wasand
observed
at When
4 PV/day.
a total ofAt
10.04
from start)
for Mg70,
Mg90
Mg+Na than
brines.
waswas
increased
to 16 to
PV/day,
dP rose
to 1.2(12),
2.05(11.83)
and at
3.11(11.8)
bar4 (PV),
respectively,
Whenrate
brine
switched
LS (Mg70,
Mg90
& Mg+Na)
brines
a rate of
PV/day,
dP showed
for fluctuations
Mg70, Mg90 than
and Mg+Na,
no cases.
fluctuations.
PV/day,the
0.11,
1.1 and 0.5%
increases
in
smaller
SSW in with
all the
In caseAtof4 Mg70,
magnitude
of dP
was constant
recovery
were
obtained,
respectively,
for
Mg70,
Mg90
and
Mg+Na
brines.
Since
there
was
no
increase
(Figure 3D) and dP stabilized roughly at 0.3 bar after 2.86 PV (equivalent to a total of 10.86 PV from
in pressure drop at 16 PV/day of LS brine injection, no resistance in flow occurred, hence less flow
start), 0.56 bar after 1 PV (equivalent to a total of 9 PV from start) and 1.2 bar after 2.04 PV (equivalent
diversion. This could be the reason of no additional oil recovery at higher rate. The highest oil
to a total of 10.04 PV from start) respectively for Mg70, Mg90 and Mg+Na brines. When rate was
recovery was observed in case of Mg90 (67.2%) brine than Mg70 (54.6%) and Mg+Na (48.5%) brines.
increased Figure
to 16 PV/day,
dP pH
rose
to 1.2(12),
2.05(11.83)
and 3.11(11.8)
bar
respectively,
for Mg70,
4 shows the
effluents
during
SSW flooding
(up till 8 PV
the(PV),
flooding
was with SSW,
Mg90from
and8Mg+Na,
with
no
fluctuations.
At
4
PV/day,
0.11,
1.1
and
0.5%
increases
in
recovery
PV on the flooding was done with low salinity waters, single and combined ions). In general,were
obtained,
respectively,
for Mg70,
Mg90an
and
Mg+Na
brines.
was no
increase
pressure
low salinity
water flooding
showed
increase
of pH.
ThisSince
is in there
agreement
with
the pH in
results
in [15].
drop observed
at 16 PV/day
of LS brine injection, no resistance in flow occurred, hence less flow diversion. This
could be the reason of no additional oil recovery at higher rate. The highest oil recovery was observed
in case of Mg90 (67.2%) brine than Mg70 (54.6%) and Mg+Na (48.5%) brines.
Figure 4 shows the pH effluents during SSW flooding (up till 8 PV the flooding was with SSW,
from 8 PV on the flooding was done with low salinity waters, single and combined ions). In general,
Energies 2017, 10, 576
9 of 16
low salinity water flooding showed an increase of pH. This is in agreement with the pH results
observed
in2017,
[15].10, 576
Energies
9 of 16
9.5
SO4 1:10
Mg 70C
SO4 1:50
LSW 1:10
LSW 1:50
Mg+Na
Mg 90C
9
pH of Effluents
8.5 10, 576
Energies 2017,
8
SSW
4PV/day
9.5
SO4 1:10
7.5
pH of Effluents
Mg 70C
SO4 1:50
LSW 1:10
LSW 1:50
Mg+Na
Mg 90C
9
SSW
4PV/day
7 8.5
SSW
16PV/day
8
6.5
6
9 of 16
SSW
16PV/day
16PV/day
4PV/day
7.5
0
4
7
8
12
Brine PV injected
16PV/day
4PV/day
6.5
16
6effluent pH by flooding with SSW, LSW 10, LSW 50, SO42− (1:10
2+ (70
Figure
4. The
1:50)&and
Mgand
Figure
4. The
effluent
pH by flooding with SSW, LSW 10, LSW 50, SO4 2− &
(1:10
1:50)
Mg2+
0
4
8
12
16
and
90C),
Mg+Na
brine.
(70 and 90C), Mg+Na brine.
Brine PV injected
In the case of 4 PV flooding with Mg2+ (70 and 90C), Mg+Na and LSW 10 showed almost the
2+ (70 and 90 ◦ C), Mg+Na and LSW 10 showed almost
In
thepH
case
of 4However,
PV flooding with
Mgsingle
same
(≈7.8).
with
brines
SOLSW
4 (1:10
and
1:50) and LSW 50, were shown
Figure
4. The effluentflooding
pH by flooding
with SSW,
LSW 10,
50, SO
42− (1:10 & 1:50) and Mg2+ (70
the same
pH
(and
≈7.8).
However,
single
SO4 (1:10
andincreased
1:50) and
LSW
50, were
to give
a higher
pH
at a flooding
rate of 4 with
PV/day.
Whenbrines
the flooding
rate was
to 16
PV/day,
90C),
Mg+Na
brine. flooding
shown
give
a higher
pH at
a flooding
of 4trend.
PV/day.
When the
flooding
increased
thetopH
of the
individual
brines
shows arate
distinct
The highest
value
was for rate
LSWwas
50 (highest
≈ to
2+ (70 and 90C), Mg+Na and LSW 10 showed almost the
theby
case
of4 (1:10
4 PV flooding
with Mg(≈8.9).
8.79) followed
SO
& 1:50)brines
having
is interesting
observe
that value
the pHwas
for the
16 PV/day,
theInpH
of
the
individual
shows
aItdistinct
trend.toThe
highest
for Mg
LSW 50
same pH (≈7.8). However, flooding with single brines SO
4 (1:10 and 1:50) and LSW 50, were shown
(70 and
90°C) have theby
lowest
(≈7.8).1:50)
When
the Na(+≈
was added
to Mg2+, the pH
of Mg+Na
brine
(highest
≈to8.79)
SO4 pH
(1:10
having
It israte
interesting
to to
observe
that
the pH
give afollowed
higher pH at a flooding
rate&
of 4 PV/day.
When the8.9).
flooding
was increased
16 PV/day,
showed
a
higher
pH
trend
reaching
(≈8.33).
Although
Mg
(70
and
90°C)
display
an
increasing
trend,
◦
+
2+
for the Mgthe
(70
90individual
C) havebrines
the lowest
pH (≈trend.
7.8). When
the value
Na was
wasforadded
Mg ,≈ the pH of
pHand
of the
shows a distinct
The highest
LSW 50to(highest
+2+Na+ brine. This may indicate that
the highest
value was
≈ 47.8,
which
is having
less than
in the
case of Mgto
◦ C)
8.79) showed
followed
by
(1:10
& 1:50)
(≈8.9).
It(is
observeMg
that(70
the and
pH for
Mgdisplay an
Mg+Na brine
a SO
higher
pH
trend
reaching
≈interesting
8.33). Although
90the
+
addition
of
Na+
as
in
the
case
of
Mg+Na
brine
enhanced
the
interaction
theofcalcite
surface,
due
(70 and 90°C) have the lowest pH (≈7.8). When the Na was added to Mg2+with
, the pH
Mg+Na
brine
+2
increasing trend, the highest value was ≈ 7.8, which is less than in the case of Mg2+ +Na+ brine. This
to theshowed
increased
the CaCO
3 solubility
This
may beMg
confirmed
by the
levelanofincreasing
Ca ions,trend,
as shown
a higher
pH trend
reaching [16].
(≈8.33).
Although
(70 and 90°C)
display
may indicate
that
addition
Na+
as in
thethan
case
brine
the interaction
the highest
valuealmost
wasof
≈ 7.8,
islevel
less
inof
the
casecase
of Mg
brine.
This
may
indicate
that with the
by Figure
5, having
thewhich
same
as
that
inMg+Na
the
of+2+Na
Mg2++enhanced
(90°C).
Increasing
temperature
calcite
surface,
due
to the
increased
the CaCO
solubility
[16]. Thiswith
may
confirmed
by the level
2+ and
addition
of Na+
as inprocess
the casebetween
of Mg+Na
brine
thebe
calcite
surface, due
3enhanced
increases
the
exchange
Ca
Mg2+. the interaction
2+ ions, as shown 2+
to the
3 solubility
[16].almost
This maythe
be confirmed
by the
of Ca2+ ions,
asincreased
shown the
by CaCO
Figure
5, having
same level
as level
that ofinCa
the
case of Mg (90 ◦ C).
Figure 5, having almost the same level as that in the case of Mg2+ (90°C).
Increasing
Increasingby
temperature
increases the exchange
process
between Ca2+ and
Mg2+ . temperature
2+
2+
LSW 1:50
Mg+Na
Mg 90C
100
SO4 1:10
10
Concentration relative to SSW
Concentration relative to SSW
increases
exchange
Ca and
Mg1:10
.
SO4the
1:10
Mgprocess
70C between
SO4 1:50
LSW
Mg 70C
SO4 1:50
LSW 1:10
LSW 1:50
Mg+Na
100
A) Calcium
1 10
0.1
Mg 90C
A) Calcium
1
0.01 0.1
0.001 0.01
0
0.001
4
0
8
4
Brine PV8 Injected
Brine PV Injected
Figure 5. Cont.
12
12
16
16
Energies 2017,Energies
10, 576
2017, 10, 576
10 of 16
10 of 16
Concentration relative to SSW
Figure 5. Cont.
10
B) Magnesium
1
0.1
0.01
0.001
0.0001
0
4
8
12
16
Concentration relative to
SSW
Brine PV Injected
100
SO4 1:10
Mg 70C
SO4 1:50
LSW 1:10
LSW 1:50
Mg+Na
10
Mg 90C
C) Sodium
1
0.1
0.01
0.001
0
4
8
12
16
Concentration relative to
SSW
Brine PV Injected
100
D) Carbonate
10
1
0.1
0
4
8
12
16
Concentration relative to
SSW
Brine PV Injected
10
E) Sulfate
1
0.1
0.01
0.001
0
4
8
12
16
Brine PV Injected
Figure 5. Dimensionless ion concentrations (ratio of the ions from the effluent to corresponding ion
in SSW) as a function
PV: (A) calcium, (B)
magnesium,
(C) sodium,
(D) effluent
carbonateto
and
(E) sulfate.
Figure 5. Dimensionless
ionofconcentrations
(ratio
of the ions
from the
corresponding
ion in
SSW) as a function of PV: (A) calcium, (B) magnesium, (C) sodium, (D) carbonate and (E) sulfate.
3.2. Ion Tracking from Secondary Flooding by LS Brines
Dimensionless ion concentration is estimated as the ratio between the measured ion concentrations
in effluents to the ion concentration in SSW. The first 8 PVs, represent flooding with SSW (Figure 5),
except [Ca2+ ], [Mg2+ ] and [SO4 2− ]. When the water was switched to LSW brines, [Na+ ] declined at a
rate of 0.035, 0.18, 0.039, 0.05, 0.38, 0.1, and 0.06 mol/L PV respectively for SO4 1:10, Mg70, SO4 1:50,
LSW 1:10, LSW 1:50, Mg+Na and Mg90 brine. Compared to other ions [Na+ ] declined at the highest
rate. Decline in sodium due to dilution was also observed in [17]. As stated earlier the effect of added
Energies 2017, 10, 576
11 of 16
sodium salt to magnesium brine enhanced the dissolution of calcium carbonate, hence increased the
calcium ion concentration.
This is interesting to see that Mg+Na brine did not affect the oil recovery. This may support that
the main mechanism of LSW is by enhancing sweep efficiency due to fines, i.e., dissolution of calcium
carbonate alone does not contribute to the main mechanism unless the sulfate is present. Certainly it
alters the wettability to more water wet [13].
Flooding with LS brines [SO4 2− ] has become <1, Figure 5 (sulfate). This showed that there may be
processes like sulfate adsorption and dissolution of CaSO4 are taking place. Rate of decline for [Ca2+ ]
was about 1.5, 1.3, 1.11 and three times greater than [SO4 2− ] in effluents during SO4 1:10 and 1:50, LSW
1:10 and 1:50 flooding. Faster decline of [Ca2+ ] may indicate less contribution by calcium in CaSO4
dissolution formed during establishment of the initial water saturation with SSW [15].
SO4 2− concentration of about 50 times dilution of SSW, gave the highest recovery [10]. However,
in this work diluted SO4 1:10 gave higher recovery than that for SO4 1:50. This may supports the notion
that sweep efficiency contributes greatly to enhancing oil recovery by LSW. Wettability alteration by
sulfate ions was observed in [13]. Double layer expansion associated with LSW contributes to the
overall Ca2+ /SO4 2− interaction.
Recovery results were compared by flooding Na2 SO4 , NaCl, and MgCl2 brines as secondary
mode [18]. They suggested that low salinity brine enriched in (SO4 2− ) and depleted in monovalent
ions is suitable in oil recovery. [SO4 2− ] decline rate was faster in case of Mg+Na brine flooding
(0.005 mol/L·PV) than SO4 1:10 (0.002 mol/L·PV), which supports that the effect of Na+ in enhancing
the Ca2+ available.
The observed increase of the pH as well as concentration of carbonate may be expressed by the
following equation [19]:
alkalinity = 2[CO32− ] +[ HCO3− ] +[OH − − [ H +
(1)
Average value for [HCO3 − ] after LSW flooding, reached to two and five times the SSW for LSW
1:10 and 1:50, respectively. For all the brines [HCO3 − ] stabilizes after 10 PV, i.e., after 2 PV of LS
brine injection to a value of five times the SSW. After injecting LS brines, a continuous increase in
concentration of bicarbonate ions was observed. Dissolution of calcite may be expressed by [20]:
CaCO3 + H2 O → Ca2+ + HCO3− + OH −
(2)
In [13], it was reported that calcite dissolution causes lattice instability, hence producing fines.
The flow of fines with injected brine increases the flow resistance and enhances sweep efficiency.
Calcite dissolution increases calcium concentration available that may react with SO4 2− and possible
precipitate CaSO4 depending on the solubility product at the specific conditions.
Calcite dissolution is not the only reason for the increase in [Ca+2 ]. Ion exchange between Ca/Mg
affects the [Mg2+ ] and [Ca2+ ] in the effluents. For example, in case of flooding with Mg90, [Mg2+ ]
stabilizes at 0.03[Mg+2 ]ssw after 11.68 PV at 4 PV/day but when the rate increased to 16 PV/day,
[Mg2+ ] increased to 0.11[Mg+2 ]ssw at 12.33 PV and declined to 0.04[Mg2+ ]ssw at 14.28 PV with a rate
of 0.001 mol/L PV. Exchange between Ca/Mg was also indicated in case of flooding with LSW 1:10,
LSW 1:50, Mg+Na, and SO4 1:10 brine. At 16 PV/day [Mg2+ ] increased to 0.01(13 PV), 0.05(12.2 PV),
0.04(14 PV) and 0.02(12.1 PV) for LSW 1:10, LSW 1:50, and Mg+Na brine, respectively.
Comparisons between simulated and experimental ion concentrations relative to SSW are shown
in Figure 6A–E. Simulation was done at the switching point from SSW to secondary flooding by LSW
1:10, LSW 1:50, SO4 1:10, SO4 1:50 and Mg brines mainly for calcium, magnesium and sulfate ions. For
the ease of comparison, the simulation was run at 6 PV. The declining trends of the simulation data for
LSW 1:10 & 1:50 and Mg brine are shown in Figure 6A,B,E.
Energies 2017, 10, 576
12 of 16
the ease of comparison, the simulation was run at 6 PV. The declining trends of the simulation data
12 of 16
for LSW 1:10 & 1:50 and Mg brine are shown in Figure 6A,B,E.
Energies 2017, 10, 576
Figure 6. Cont.
Energies 2017, 10, 576
Energies 2017, 10, 576
13 of 16
13 of 16
Figure 6. Cont
Figure 6. Comparison between experimental (points) and simulated (lines) ion concentrations relative
Figure 6. Comparison between experimental (points) and simulated (lines) ion concentrations relative
to SSW of Ca2+
, Mg2+ , SO 2− and Na+ : (A) LSW 1:10, (B) LSW 1:50, (C) SO 1:10, (D) SO4 1:50 and
Mg
to SSW of Ca2+, Mg2+, SO42− 4and Na+: (A) LSW 1:10, (B) LSW 1:50, (C) SO4 1:10, (D)4 SO4 1:50 and (E)
(E)
Mg
brine.
brine.
general,the
the simulated
simulated ion
those
of of
thethe
experimental
datadata
except
InIngeneral,
ion concentrations
concentrationsare
arelower
lowerthan
than
those
experimental
except
forcalcium
calciumions
ions where
where there
there is
in in
thethe
case
of of
sulfate
ionsions
maymay
be be
for
is aa good
good match.
match.The
Thediscrepancy
discrepancy
case
sulfate
explained
by
dissolution
of
the
possibly
formed
calcium
sulfate
during
establishment
of
the
initial
explained by dissolution of the possibly formed calcium sulfate during establishment of the initial
watersaturation
saturation(sw
(swi)) and
and subsequent
the
case
of of
magnesium,
thethe
reason
is not
water
subsequentaging
agingofofthe
thecores.
cores.InIn
the
case
magnesium,
reason
is not
i
understood,
however
the
simulation
model
(Phreeqc
Interactive
3.3.7)
predicted
formation
of
understood, however the simulation model (Phreeqc Interactive 3.3.7) predicted formation of dolomite,
2+. The trend in all the data and the simulation agrees. Figure 6C,D show
dolomite,
i.e.,ofremoval
Mgtrend
i.e.,
removal
Mg2+ . of
The
in all the data and the simulation agrees. Figure 6C,D show the
the comparison between simulated and experimental relative ion concentrations for SO4 brines (1:10
comparison between simulated and experimental relative ion concentrations for SO4 brines
(1:10 and
and 1:50). Only Na2SO4 salt was injected as a secondary brine, so in addition to active ions (Ca2+, Mg2+,
1:50).2−Only +Na2 SO4 salt was injected as a secondary brine, so in addition to active ions (Ca2+ , Mg2+ ,
SO4 ). [Na ] was also compared. For both cases, the decline trend and equilibrium concentrations for
SO4 2− ). [Na+ ] was also compared. For both cases, the decline trend and equilibrium concentrations
calcium and sodium (Figure 6C,D) match well with the simulation data, except for calcium where the
for calcium and sodium (Figure 6C,D) match well with the simulation data, except for calcium where
starting points for the experiments are lower than in the simulation.
the starting
points results
for the(Figure
experiments
are lower
than
in the simulation.
Oil recovery
2) showed
that SO
4 1:10 (68.2%OOIP) and Mg90 (67.9%OOIP) gives
Oil
recovery
results
(Figure
2)
showed
that
SO
1:10
(68.2%OOIP)
anddata
Mg90
(67.9%OOIP)
gives
4
the highest oil recovery than all other injected secondary brines.
Simulation
matches
for all the
the
highest
oil
recovery
than
all
other
injected
secondary
brines.
Simulation
data
matches
for
divalent ions for SO4 and Mg brine (Figure 7), except the equilibrium concentration for calcium all
the
divalent
for
SO4 (1.007
and Mg
brine
(Figure
7), Mg
except
the
equilibrium
concentration
forofcalcium
−7) is lower
(Figure
7A) ions
for SO
4 brine
× 10
than
brine
(3.46
× 10−4). Lower
[Ca2+] in case
SO4
−7 ) is lower than Mg brine (3.46 × 10−4 ). Lower [Ca2+ ] in case of
(Figure
7A)
for
SO
brine
(1.007
×
10
brine could be due
4 to exchange between Ca/Mg ions.
SO4 brine could be due to exchange between Ca/Mg ions.
Energies 2017, 10, 576
Energies 2017, 10, 576
14 of 16
14 of 16
Figure7.7.Comparison
Comparisonbetween
betweenexperimental
experimental(points)
(points)and
andsimulated
simulated(lines)
(lines)ion
ionconcentrations
concentrationsrelative
relative
Figure
SSWfor
forSO
SO
andMg
Mgbrines:
brines:(A)
(A)calcium,
calcium,(B)
(B)magnesium
magnesiumand
and(C)
(C)sulfate.
sulfate.
4 1:10
and
totoSSW
4 1:10
2+2+ion
andMg
Mg
ionmay
may
also
be reflected
inexperimental
the experimental
Ion
between Ca
Ca2+2+ and
Ionexchange
exchange between
also
be reflected
in the
results.results.
Higher
2+
2+
2+
2+
Higher
concentration
of
Mg
and
lower
concentration
of
Ca
in
SO
4 brine than Mg brine (Figure
concentration of Mg and lower concentration of Ca in SO4 brine than Mg brine (Figure 7A,B)
7A,B)
showed
Ca/Mg
exchange
is more
prominent
SO41:10
1:10brine.
brine. Figure
showed
that that
Ca/Mg
ionion
exchange
is more
prominent
ininSO
Figure 7C
7Cshows
showslower
lower
4
2−
2−
experimental
4 ]2−in SO4 brine than in the experimental and simulation [SO4 2
]−in
Mg
brine.
experimental[SO
[SO
]
in
SO
brine
than
in
the
experimental
and
simulation
[SO
]
in
Mg
brine.
4
4
4
Adsorption
of
sulfate
and
precipitation
of
calcium
sulfate
on
chalk
surface
causes
a
lower
amount
Adsorption of sulfate and precipitation of calcium sulfate on chalk surface causes a lower amountofof
calcium
calciumand
andsulfate
sulfateininthe
theeffluents.
effluents.Adsorption
Adsorptionofofsulfate
sulfateon
onthe
thechalk
chalksurface
surfaceleads
leadstotoalteration
alterationofof
the
thewettability
wettabilitytowards
towardsmore
morewater-wet.
water-wet.
4.4.Summary
Summaryand
andConclusions
Conclusions
The
Themechanisms
mechanismsrelated
relatedtotothe
theincrease
increaseininoil
oilrecovery
recoveryinincarbonate
carbonatereservoirs
reservoirsare
arestill
stillnot
not
completely
explainable.
A
series
of
experiments
were
performed
for
this
study
to
test
the
low
salinity
completely explainable. A series of experiments were performed for this study to test the low salinity
effects
effectsininchalk
chalkreservoirs.
reservoirs.Core
Corewere
wereflooded
floodedwith
withSSW
SSWand
andmodified
modifiedbrines
brines(single
(singlesalt
saltbrines
brinesand
and
LSWs)
primaryand
and
secondary
injection
respectively.
Results obtained
these
LSWs) as primary
secondary
injection
fluids,fluids,
respectively.
Results obtained
from thesefrom
experiments
experiments
support the observations
by other
researchers.
Based on the
experimental
and
support the observations
made by othermade
researchers.
Based
on the experimental
and
numerical results
numerical
results we
conclude the following:
we can conclude
the can
following:
(1)
(1) Experimentally
Experimentallyititisisconcluded
concludedthat
thatoiloilrecovery
recoveryresponse
responsetime
timedepends
dependson
onthe
theion
iondilution
dilutionfactor
factor
ofofthe
brine.
LSW
1:10
gives
earlier
response
than
the
LSW
(1:50).
the brine. LSW 1:10 gives earlier response than the LSW (1:50).
(2) Divalent Ions have an effect in wettability alteration. Ca/Mg contributes largely in enhancing the
(2) Divalent Ions have an effect in wettability alteration. Ca/Mg contributes largely in enhancing
sweep efficiency. But this effect increases in presence of SO42−. Highest
recovery is obtained while
the sweep efficiency. But this effect increases in presence of SO4 2− . Highest recovery is obtained
flooding with SO4 brine than any other brine which shows that the presence of sulfate ion may
while flooding with SO4 brine than any other brine which shows that the presence of sulfate ion
contribute to the wettability alteration.
may contribute to the wettability alteration.
(3) Increase in ion concentrations of Mg2+ and Ca2+ in the later part of modified brine injection
confirms ion exchange between the ions and thus precipitation of magnesium.
Energies 2017, 10, 576
(3)
(4)
(5)
15 of 16
Increase in ion concentrations of Mg2+ and Ca2+ in the later part of modified brine injection
confirms ion exchange between the ions and thus precipitation of magnesium.
10 times SSW dilution ratio gives the best outcome. This is also in agreement with the case of
single salt brine injection. For SO4 1:10 dilution, higher recovery was obtained compared to that
with SO4 1:50.
Pressure drop in the secondary flooding may indicate fine migration during injection of single salt
brine and LSW, though fines were not observed in the effluent samples during our experiments.
This may be due to size of the particles being too small to be observed or the migration took place
in the core, fines were trapped and the pressure was not high enough to overcome the trapping
resistance of the particles.
Acknowledgments: The authors acknowledge the technical help in our laboratory by Krzysick Nowicki during
experimental work. We also acknowledge the excellent help for data monitoring and equipment calibration from
Kim Andre Nesse Voland and Svein Myhren. This research is funded by University of Stavanger as part of master
thesis work of Sachin Gupta.
Author Contributions: Sachin Gupta performed the experiments collected and analyzed the experimental data.
The work supervision and geochemical simulations were done by Aly A. Hamouda.
Conflicts of Interest: The authors declare no conflict of interest.
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