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Effect of Rock Mineralogy and Oil Composition on Wettability Alteration and Interfacial Tension by Brine and Carbonated Water Mohammad Alqam, Sidqi Ahmed Abu-Khamsin, Abdullah S Sultan, Taha Okasha, and Hasan O. Yildiz Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b04143 • Publication Date (Web): 30 Jan 2019 Downloaded from http://pubs.acs.org on February 3, 2019
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Energy & Fuels
Effect of Rock Mineralogy and Oil Composition on Wettability Alteration and Interfacial Tension by Brine and Carbonated Water
1 2 3 4 5
Mohammad H. Alqama, b *, Sidqi A. Abu-Khamsinb, Abdullah S. Sultanb, Taha M. Okashaa, and Hasan O. Yildiza
6 7 8 9 10 11
a
12
Abstract
Saudi Aramco, Dhahran, 31311 Saudi Arabia Department of Petroleum Engineering, KFUPM, Dhahran, 31311 Saudi Arabia * Corresponding author b
13
Wettability has a significant impact on flow of oil during enhanced oil recovery (EOR) and profound effect on fluids
14
distribution in oil fields. Mechanisms that influence the interaction between the injected water and the components of
15
crude oil in the presence of carbonate rock sample were investigated. The main objectives of this study were to investigate
16
the role of both rock mineralogy and the compositions of various oils as a function of asphaltenes content on the
17
destabilization of the aqueous film separating the oil from substrate rock surface of carbonate using aqueous phases such
18
brine and carbonated water. The contact angles as a function of time were measured using brine and carbonated water
19
and two types of crude oils on four types of rock samples. Once the exact contact angle has been determined, the
20
compositions of various oils, based on asphaltenes contents, were characterized to investigate the role of oil composition
21
on the destabilization of the aqueous film separating the oil from rock surface. Interfacial tensions of brine and crude oils
22
were also measured. Four types of rock samples from carbonate reservoirs, with different compositions, selected based
23
on XRD results were: (1) 100% Dolomite D (100), (2) 100% Calcite C (100), (3) 67% Dolomite + 33% Calcite (D67 +
24
C33), and (4) 37% Dolomite + 63% Calcite (D37 + C63). Two types of crude oil were used based on asphaltenes content
25
obtained using SARA analysis. The contents of asphaltenes for the crude-1 and crude-2 were 11.6 and 6.4 wt% and
26
represented as (I-11.6) and (II-6.4), respectively. In this study, crude oil/brine/carbonate systems showed that (D37 +
27
C63) gave the lowest contact angle value of 67o with 6.4 wt% of asphaltenes content (II-6.4), and D (100) gave the highest
28
contact angle of 136o with 11.6 wt% of asphaltenes content (I-11.6). Brine was used as external phase on both tests. On
29
the other hand, using carbonated water as external phase, contact angle was decreasing from 97.6o (D67 + C33) to 75.5o
30
(D37 + C63) for mixed Dolomite/Calcite systems. Decreasing Dolomite content in mixed Dolomite/Calcite systems
31
caused shift in contact angle from oil negative intermediate wet to weakly water wet regardless of saturating fluid phase.
32
Also, using the adhesion tension approach, in defining surface wettability, shows as contact angle values were decreasing,
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adhesion tension was shifting to positive directions as degree of water wetness was increasing. This behavior was mainly
2
due to the effect of type-II crude oil.
3
The novelty of this study stems from studying the effect of rock mineralogy based on Dolomite and Calcite distribution
4
and oil composition based on asphaltenes content in wettability alteration using aqueous phases such as brine and
5
carbonated water. The results of both contact angle and IFT were implemented in adhesion tension using Thomas Young
6
equation (Adamson, 1982) as an alternative approach in defining surface wettability. This study will provide a better
7
understanding of mineralogy/fluid/ interaction which is very crucial in the optimization of water injection and wettability
8
reversal during enhanced oil recovery process.
9 10 11
Keywords: Contact angle; Interfacial tension; Wettability; Carbonate rock, Carbonated water,
12 13
1. Introduction
14
Wettability describes the tendency of a fluid to adhere or adsorb to a solid surface in the
15
presence of another immiscible fluid. It can be described as a measure of the affinity of the
16
rock surface for the oil or water phase (Amott, 1959). Hydrocarbon recovery by water injection
17
is governed by viscous capillary forces, by the original fluid saturations and saturation history.
18
Complexity of oil fields in terms of lithology and fluids composition result in wide variations
19
of interfacial and contact angle parameters. The capillary pressure-saturation relation has
20
importance in determining several reservoir properties, like irreducible water saturation,
21
transition zone thickness, oil column height, and pore size distribution (Rose and Bruce, 1949;
22
and Jennings, 1987). Wettability is a major factor controlling the location, flow, and
23
distribution of fluids in a reservoir. Wettability affects all types of core analyses, including
24
capillary pressure, relative permeability, waterflood behavior, and electrical properties
25
(Anderson, 1986; Craig, 1971). The state of water-wetness occurs when the rock surface is
26
wetted by water while the state of oil-wetness occurs when the rock surface is wetted by oil.
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The contact angle is usually measured through the denser liquid phase and ranges from 0o to 2 ACS Paragon Plus Environment
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180º. Contact angle is the best and fast quantitative method whenever pure fluid and artificial
2
cores are used (Anderson, 1986). USBM (Donaldson, 1981) and Amott (1959) methods
3
measure the average wettability of the core. These two methods are superior to contact angle
4
whenever we have native or restored state. The rate of imbibition as being qualitative method
5
is the most widely used because of its short time of duration. NMR and dye-adsorption are
6
preferred methods for measuring the fractional wettability. Currently, there is no available
7
method to determine the mixed wettability. Yang et al. (2010) performed several contact angle
8
measurements to determine the wettability of a crude oil−brine−rock system with dissolution
9
of CO2. They found that wettability alteration was likely to happen when CO2 was injected in
10
an oil reservoir and was expected to significantly affect the rate and amount of oil recovery.
11
Morrow (1990) discussed the wettability and its effect on oil recovery. The study addressed
12
that the wettability other than very strong water wet is gaining wider acceptance. Various
13
techniques for measuring wettability have been reviewed. The study found that adhesion
14
behavior of crude oil is pH dependent. He also mentioned that the optimum oil recovery is
15
achieved when the wettability in neutral. Okasha et al. (2007) conducted a comprehensive
16
survey on wettability alteration on carbonated rock samples obtained from Saudi reservoir over
17
fifty years. Buckley (1998) has indicated the presence of four main components which
18
influence the crude oil/brine/rock system. These are mainly: a) Polar interaction b) Surface
19
precipitation, c) Acid/base interaction and d) Ion binding. Thomas and Clouse (1989)
20
conducted study on the behavior of silicate and carbonate reaction with polar compounds. They
21
have found that the carbonate at basic condition is positively charged and has the tendency to
22
attract the negatively charged acidic group.
23 24
Rock wettability alteration has been observed in carbonate formations but an integrated approach
25
to address this phenomenon is lacking especially when CO2 is injected below its critical pressure. 3 ACS Paragon Plus Environment
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The effect of underlying factors such as oil composition and rock minerology on wettability
2
alteration are not well understood.
3
This study intends to fill this gap by investigating the influence of two types of crude oil,
4
having different asphaltenes content (wt%), on four types of rock samples using both brine and
5
carbonated water. The investigation will include polar interaction based on asphaltenes content
6
and surface precipitation. The study will also attempt to understand what the most important
7
combinations of rock mineralogy and oil composition on wettability alteration. The pendant
8
drop technique has been adopted to measure interfacial tension and contact angle for wettability
9
characterization. In this study, effect of rock mineralogy based on Dolomite and Calcite
10
distribution and of oil composition based on asphaltenes content in wettability alteration using
11
aqueous phases such as brine and carbonated water were investigated on carbonate rock
12
samples. The results of both contact angle and IFT were implemented in adhesion tension
13
using Thomas Young equation (Adamson, 1982) as an alternative approach in defining surface
14
wettability.
15
3. Materials and methods
16
3.1. Materials
17
Brine with TDS of 57, 670 ppm and carbonated water (200 cc liquid CO2 mixed with 800
18
cc of brine at initial pressure of 2000 psi) were used as the aqueous phase in all contact angle
19
measurements. Brine was filtered using a filter of 0.54 micron prior to the course of contact
20
angle measurements. The viscosity of the brine was measured to be 1.141 cp, and the density
21
was 1.039 g/cm3 at room temperature. The viscosity of the carbonated water was measured to
22
be 0.785 cp, and the density was 0.994 g/cm3 at room temperature. In the tests, crude oils of
23
type-I (I-11.6) and type-II (II-6.4) were used as oleic phase and differentiated based on their
24
asphaltenes contents (Table-1). The viscosity of (I-11.6) was 50.400 cp, and the density was
25
0.900 g/cm3. The (I-11.6) crude oil was found to contain 38.5 wt % saturates, 31.9 wt % 4 ACS Paragon Plus Environment
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aromatics, 18.0 wt % resins, and 11.6 wt % asphaltenes. The viscosity of (II-6.4) was 14.467
2
cp, and the density was 0.874 g/cm3. This type of crude oil was found to contain 39.3 wt %
3
saturates, 32.4 wt % aromatics, 21.9 wt % resins, and 6.4 wt % asphaltenes. The four
4
components of the SARA analysis data for both oils are shown in Table 1. The main
5
controlling factor in altering the wettability is the asphaltenes contents. Therefore, our main
6
focus in this study is the content of asphaltenes in the crude oil.
7
Table 1: SARA analysis of the two types of oils Saturate, (wt%)
Oil Type
Aromatic, (wt%)
Resin, (wt%)
Asphaltenes, (wt%)
Type-I
38.5
31.9
18
11.6
Type-II
39.3
32.4
21.9
6.4
8 9
Interfacial tensions between brine and both (I-11.6) and (II-6.4) oil were 12.89 and 23.63
10
dynes/cm, respectively at ambient condition. The brine physical properties and its composition
11
are listed in Table 2 and 3, respectively. Table 2: The physical properties of the brine
12 13
Temperature, oC
Viscosity, mpa.s
Density, g/cm3
14 25
1.039
1.141
15 16 17 18 19 20 21 22 23
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Surface Tension, dynes/cm 73.5
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Table 3: Brine Composition
3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Ions
Symbol
Brine (ppm)
Sodium
Na+
56.113
Calcium
Ca2+
43.204
Magnesium
Mg2+
32.507
Sulfate
SO2-
30.297
Chloride
Cl-
19.915
Bicarbonate
HCO-3
14.852
TDS
57,670
Ionic Strength (mol/L)
1.146
25 26 27
The physical properties of oil phases for Type-I and Type-II oils are listed in Table 4 and Table 5, respectively.
28 29 30 31 32 33 34
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Table 4: The physical properties of type-I crude oil (API: 23)
1 Temperature, oC
Density, g/cm3
Viscosity, mpa.s
Surface Tension, dynes/cm
Interfacial Tension, dynes/cm
25
0.900
50.400
28.01
12.89
30
0.898
43.204
27.87
11.83
35
0.896
32.507
27.63
11.25
40
0.894
30.297
27.49
11.02
50
0.887
19.915
26.41
10.28
60
0.881
14.852
25.92
8.93
2 3 4
Table 5: The physical properties of type-II crude oil (API: 28) Temperature, oC
Density, g/cm3
Viscosity, mpa.s
Surface Tension, dynes/cm
Interfacial Tension, dynes/cm
25
0.874
14.467
26.98
23.63
30
0.872
13.223
26.60
22.95
35
0.869
11.761
26.15
22.50
40
0.867
10.532
25.76
21.90
50
0.862
9.045
25.10
21.40
60
0.856
7.195
24.95
20.79
5 6
Four families of rock samples, from carbonate reservoirs with different compositions
7
selected based on XRD results in order to investigate the effect of rock mineralogy on 7 ACS Paragon Plus Environment
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1
wettability, were used as porous media in this study: (1) 100% Dolomite D (100), (2) 100%
2
Calcite C (100), (3) 67% Dolomite + 33% Calcite (D67 + C33), and (4) 37% Dolomite 37% +
3
63% Calcite (D37 + C63). In this manuscript, * symbol denotes samples were saturated and
4
aged with oil, and ** symbol represents that rock and oil are obtained from different
5
formations. (Oil was obtained from formation A, on the other hand, rock sample obtained from
6
formation B). In the experiments, the sample D*(100) was the only sample that saturated and
7
aged with oil, and other samples were saturated with brine and aged with oil. All the contact
8
angle experiments were conducted with brine (or carbonated water) as external phase and oil
9
as droplet phase. The size of each core plug was used in contact angle measurements
10
approximately 3.41 mm in thickness and 25.28 mm in diameter. The XRD results of four
11
families of rock samples are listed in Table 6.
12 13 14
Table 6: The XRD results of four families of rock samples Rock Type
15 16 17
Calcite
Dolomite
Anhydrite
Gypsum
Fluorite
Halite
Celestine
Quartz
(Wt.%)
(Wt.%)
(Wt.%)
(Wt.%)
(Wt.%)
(Wt.%)
(Wt.%)
(Wt.%)
D(100)
0
100
0
0
0
0
0
0
C(100)
100
0
0
0
0
0
0
0
(D67+C33)
33
67
0
0
0
0
0
0
(D37+C63)
63
37
0
0
0
0
0
0
3.2. Methods
18
Two small sister disks were cut from the main rock sample and surface grinded to prepare one
19
for contact angle measurements and the other for XRD mineralogical analysis. Since it is well-
20
known in the literature that the surface roughness has an effect on contact angle measurements, in
21
this study, SEM (scanning electron microscopy) technique was used in examination of the disks in 8 ACS Paragon Plus Environment
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Energy & Fuels
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order to minimize the effect of surface roughness. The morphological images showed that all the
2
selected disks compromised of irregular-shaped microscopic particles with no major difference in
3
their microstructures.
4
First of all, all the rock sample disks were washed by mild soap solution and then rinsed
5
thoroughly with de-ionized-distilled water and ethanol. After drying the samples in an oven
6
for 48 hours, the samples were saturated with synthetic brine or oil under vacuum for 24 hours.
7
All the samples were then aged under oil for 24 hours regardless of the saturating fluid
8
(brine/oil). Next, the samples were placed in the contact angle cell, and brine (or carbonated
9
water) was introduced as an external phase. Finally, oil droplet was released from pendant
10
drop towards the face of the solid surface to perform contact angle measurements (Fig.1). The
11
contact angles were measured through denser phase (brine), and the results were tabulated in
12
Tables-7 and 8 for type-I and type-II crude oil, respectively.
13
Figure 1: A cross-sectional view of contact angle cell
14 15
Eventually, the results of both contact angle and IFT were implemented in adhesion tension,
16
given by Thomas Young’s equation (Adamson, 1982), as an alternative approach in defining surface
17
wettability. 9 ACS Paragon Plus Environment
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1
𝐴𝑇 = 𝜎𝑤𝑜 cos 𝜃
2
Where, 𝐴𝑇 is adhesion tension, 𝜎𝑤𝑜 is interfacial tension between oil and brine, and 𝜃 is contact
3
angle.
4 5
4. Results and discussion
6
All the contact angles measurements were done on crude oil/brine/carbonated water/reservoir
7
rock systems.
8
4.1. Effect of rock mineralogy on contact angle
9
Four families of rock samples from carbonate reservoirs with different compositions
10
selected based on XRD results (Table 6) were used in this study: (1) 100% Dolomite D(100),
11
(2) 100% Calcite C(100), (3) 67% Dolomite + 33% Calcite (D67 + C33), and (4) 37% Dolomite
12
+ 63% Calcite (D37 + C63).
13
In type-I/brine/Dolomite I-D*(100) system, the type-I crude oil was used as saturating and
14
aging fluid of the rock and then for droplet phase. The highest contact angle was measured as
15
136.1o at 25 oC. However, changing only the saturating phase to brine and keeping the same
16
oil for aging and droplet phase on the same system I-D**(100), resulted on contact angle
17
reduction to 127.9o at 25 oC. The degree of oil wetness was decreasing with water film on the
18
disk. Changing the system to type-I/brine/Calcite I-C (100) system, the lowest contact angle
19
measured was 88.5o at 25 oC (Fig. 2). However, if the rock sample was obtained from a
20
different formation, I-C**(100), the degree of oil wetness was increasing to 110.7o at 25 oC
21
and becoming oil wet (see Table 7 and Fig. 2). When comparing I-C**(100) to I-C (100), the
22
rock and the oil samples were obtained from different formations in the case of I-C**(100),
23
while for the case of I-C (100), the rock and the oil samples were obtained from the same
24
formation. This might explain the difference in the contact angle measurements for these two
25
systems. Also, calcite from the same formations, as the oil, had a tendency to be water wet. 10 ACS Paragon Plus Environment
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However, the calcite had more tendency to be oil wet if rock and oil samples were obtained
2
from different formations.
3
In the case of I-C** (100) and I-D** (100), the degree of wetness was fallen into oil wetting
4
side not a dramatic change in wetting, but the oil wetness was higher in the dolomite rock. So,
5
we can conclude that regardless the rock mineralogy the degree of wetness will be towards oil
6
wet.
7 8
9 10 11
Table 7: Type-I oil: The contact angle and adhesion tension @ 25oC Rock Type
I-D* (100)
I-(D37+C63)
I-D**(100)
I-C**(100)
I-(D67+C33)
I-C(100)
ϴ
136.1
128.80
127.9
110.7
92.7
88.5
Cos ϴ
-0.72
-0.63
-0.61
-0.35
-0.05
0.03
IFT, σ
12.89
12.89
12.89
12.89
12.89
12.89
AT
-9.28
-8.08
-7.91
-4.55
-0.60
0.34
*: Rock sample saturated with oil **: The rock and oil are obtained from different formation (Type-I)
11 ACS Paragon Plus Environment
Energy & Fuels
Pure Systems 180 II-C(100)
160
Contact Angle, Degree
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Page 12 of 22
II-D**(100)
II-C**(100)
I-C(100)
140
I-D**(100)
I-C**(100)
136.1
127.9
120
I-D*(100)
110.7
100 82.3
87.8
91.9
88.5
II-C**(100)
I-C(100)
80 60 40 20 0 II-C(100)
II-D**(100)
I-D**(100)
I-C**(100)
I-D*(100)
Rock Families 1 2 3
Figure 2: Effect of contact angle using pure calcite and dolomite rock system
4
In this study, we used the terminology adopted by Jadhunandan and Morrow (1995), to
5
differentiate the level of intermediate wetting. If two phases (oil and brine) are having mutual
6
affinity to wet the surface, positive intermediate is defined as the degree of water wetness is
7
greater than the degree of oil wetness. On the other hand, negative intermediate is defined as
8
the degree of oil wetness is greater than the degree of water wetness. It was concluded on pure
9
calcite systems that once the oil and rock samples obtained from the same formation regsrdless
10
of the oil source, the degree of wetting was considered to be as positive intermediate towards
11
water wetting.
12
Using the brine as saturating and oil as aging fluid of the rock and keeping the type-1 crude
13
oil as droplet phase, on type-I/brine/Dolomite/Calcite mixed systems of the same formation,
14
(D37 + C63) had 128.8o and (D67 + C33) was 92.7o at 25 oC. The degree of oil wetness was
15
decreasing with increasing dolomite content in the mixed Dolomite/Calcite system (Fig. 3 and
16
Table 7). 12 ACS Paragon Plus Environment
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1
Mixed Systems
180 II: Type-II Oil
I: Type-I Oil
160 140
Contact Angle, Degree
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Energy & Fuels
128.8
120 100 80
92.7 71.6
67.2
60 40 20 0 (D67+C33)
2 3
Rock Families
(D37+ C63)
Figure 3: Effect of contact angle using mixed rock system
4
Using the Type-II crude oil as the aging and droplet phase, the pure Calcite II-C (100) solid
5
surface from the same formation as type-II oil gave a contact angle of 82.3o (positive
6
intermediate wet). Once the rock and oil were obtained from the different formations, II-
7
C**(100) gave a contact angle of 91.9o (negative intermediate wet). The change in wettability
8
stage was occurred due to mother source of the calcite which obtained from the higher
9
asphaltenes content formation.
10
Using the type-II/brine/Dolomite/Calcite mixed systems with the rock samples obtained
11
from different formation, the contact angle values of (D67 + C33) and (D37 + C63) were both
12
water wet at 71.6o and 67.2o, respectively. The main cause for the increasing the degree of
13
water wetness was due to the decreasing in the dolomite content in the mixed Dolomite/Calcite
14
system (Fig. 3 and Table 8).
15 16
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1 2 3
4 5 6
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Table 8: Type-II oil: The contact angle and adhesion tension @ 25oC Rock Type
II-C**(100)
II-D**(100)
II-C(100)
II-(D67+C33)
II-(D37+C63)
ϴ
91.9
87.8
82.3
71.6
67.2
Cos ϴ
-0.03
0.04
0.13
0.32
0.39
IFT, σ
23.63
23.63
23.63
23.63
23.63
AT
-0.78
0.92
3.16
7.46
9.16
** The rock and oil obtained from different formation source (Type-II) 4.2. Effect of oil composition on contact angle
7
If the droplet phase of oil composition was changed from type-I to type-II using pure
8
Dolomite: D (100) solid surface from the same formation and using brine (saturating and
9
external phase) system, the contact angle was shifted from I-D** (100) 127.9o as being oil wet
10
to II-D** (100) 87.8o as positive intermediate (Jadhunandan and Morrow (1995)), respectively
11
(Fig. 2). This showed that effect of oil composition based on asphaltenes content had a major
12
role in wettability alteration from oil wetness towards intermediate wet. In case of pure Calcite,
13
C (100) solid surface from the same formation and using brine (saturating and external phase)
14
system keeping the same conditions above (Fig. 2), the contact angle was changed from I-
15
C**(100) 110.7o as being weakly oil wet to II-C(100) 82.3o positive intermediate, respectively.
16
The shift in intermediate wetness from I-C (100) 88.5o to II-C** (100) 91.9o was shown in
17
Fig. 2. Both rock substrate samples were obtained from the same formation source but oil
18
droplet phase was changed from the type-I to type-II crude oil, respectively. This result can be
19
explained as changing the oil composition is more pronounced on altering the wettability than
20
keeping the same mother source of oil.
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If the aging phase was brine and oil droplet phase was changed from type-I to type-II in
2
oil/brine/mixed Dolomite/Calcite (D37 + C63) solid systems, provided the rock obtained from
3
the same formation source, the contact angle values were shifted from oil wet of 128.8o to
4
water wet of 67.2o, respectively. This result showed that oil with higher asphaltenes content
5
(Type-I, 11.6) had greater effect on oil wetness than that with low asphaltenes content (Type-
6
II, 6.4). The presence of the polar materials in the crude oil namely, resins and asphaltenes,
7
have profound effect on wettability alteration. Type-II oil has higher percentage of aromatics
8
and resins compared to Type-I oil and has also a greater power for dissolving asphaltenes
9
(Buckley, 1996) consequently reduce the asphaltenes content and ultimately results on
10
wettability reversal (see Table 1). However, the saturate has no effect on solvation of
11
asphaltenes. Due to the difference of asphaltenes contents on these two types of oil, the
12
contact angle has been shifted from oil-wet as shown for type-I to water-wet for type-II oil.
13
So, the role for the effect of asphaltenes in crude oil towards wettability alteration is governed
14
by the presence or absence of polar materials in crude oil (Al-Mahamari and Buckley, 2003).
15
The summary results of pure and mixed systems for both oil types are presented in Fig. 4.
15 ACS Paragon Plus Environment
Energy & Fuels
180 160
Mixed and Pure Systems II-(D37+ C63)
II-(D67+C33)
II-C(100)
II-D**(100)
II-C**(100)
I-(D67 +C33)
I-C**(100)
I-D**(100)
I-(D37+C63)
I-D*(100)
127.9
120
128.8
110.7
100 82.3
80
I-C(100)
136.1
140
Contact Angle, Degree
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 16 of 22
67.2
87.8
91.9
88.5
92.7
71.6
60 40 20 0
Rock Families
1 2 3 4
Figure. 4. Effect of contact angle using both pure and mixed rock system. 4.3. Effect of contact angle and adhesion tension on wettability
5
Contact angle is a fast and reliable technique in measuring the wetting tendency in two
6
immiscible fluids acting on a solid surface. Interfacial tension (IFT) can also play a greater role in
7
wetting. On the other hand, implementing the composite effect (both contact angle and IFT) of
8
adhesion tension in Thomas Young equation is an alternative approach in defining surface
9
wettability.
10
As contact angle values were decreasing, adhesion tension was shifting from negative to
11
positive directions as degree of water wetness was increasing (Table 8). This behavior was
12
mainly due to the effect of type-II crude oil. This phenomena might be explained owing to the
13
low content of asphaltenes (II-6.4) in type-II crude oil (Table 1). As contact angle values were
14
increasing, adhesion tension was shifting from positive to negative directions as degree of oil
15
wetness was increasing (Table 7). This behavior was mainly due to the effect of type-I crude 16 ACS Paragon Plus Environment
Page 17 of 22
1
oil. Similarly, this might be explained as a result of having comparatively high content of
2
asphaltenes (I-11.6) in type-I crude oil. It is also noted that IFT value obtained from type-I oil
3
(12.89 dyne/cm) is lower than that of from type-II (23.63 dyne/cm). The summary results for
4
adhesion tensions obtained in this study are presented in Fig. 5. Mixed and Pure Systems
15 II-C**(100)
II-D**(100)
II-C(100)
II-(D67+C33)
II-(D37+C63)
I-(D37+C63)
I-D**(100)
I-C**(100)
I-(D67+C33)
I-C(100)
10
I-D* (100)
9.16 7.46
Adhesion tension, dynes/cm
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
5 3.16 0.92
0.34
0 -0.6
-0.78
-5
-10
-4.55
-8.08
-7.91
-9.28
-15
5 6 7 8
Rock Families
Figure. 5. Effect of adhesion tension on wettability. 4.4. Effect of carbonated water on contact angle
9
Carbonated water (200 cc liquid CO2 mixed with 800 cc of brine at initial pressure
10
of 2000 psi) was used as the aqueous phase in all contact angle measurements. Effect
11
of pressure was investigated on type-I/carbonated water/Dolomite D*(100) system. On
12
pure Dolomite D* (100) solid surface saturated with type-I oil, the contact angle values
13
were increasing from 111.2o to 135.5o with decreasing pressure from 2500 to 500 psig,
17 ACS Paragon Plus Environment
Energy & Fuels
1
respectively with constant temperature of 25 oC. On the other hand, contact angle was
2
decreasing from 97.6o (D67 + C33) to 75.5o (D37 + C63) at 2000 psi and 25 oC for
3
mixed Dolomite/Calcite systems (Fig. 6). Decreasing Dolomite content in mixed
4
Dolomite/Calcite systems caused shift in contact angle from oil negative intermediate
5
wet to weakly water wet regardless of saturating fluid phase. Further investigations
6
need to be conducted in the future with carbonated water using additional rock and oil
7
samples in order to draw a solid conclusion.
8
Carbonated Water @ 25oC 180
I-(D37+ C63) P=2000 psi
I-(D67+ C33) P=2000 psi
I-D*(100) P=2500 psi
I-D*(100) P=500 psi
160 135.5
140
Contact Angle, Degree
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 18 of 22
120
111.2 97.6
100 80
75.5
60 40 20 0 I-(D37+ C63) P=2000 psi
I-(D67+ C33) P=2000 psi
I-D*(100) P=2500 psi
I-D*(100) P=500 psi
Rock Families 9 10 11 12
Figure. 6. Effect of contact angle using carbonated water
13
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Energy & Fuels
1 2
5. Conclusions
3
Based on the results presented in this work, the following conclusions are obtained:
4
(1) The contact angle for the type-I crude oil ranges from 127.9o on Dolomite D** (100)
5
to 88.5o on Calcite C (100). In the mixed Dolomite/Calcite system, the contact angle
6
values of (D67 + C33) and (D37 + C63) were measured at 92.7o and 128.8o,
7
respectively. The degree of oil wetness was decreasing with increasing dolomite
8
content.
9
(2) The contact angle for the type-II crude oil ranges from 87.8o on Dolomite D** (100) to
10
82.3o on Calcite C (100). Low contact angle values were obtained with mixed
11
Dolomite/Calcite systems of (D67 + C33) and (D37 + C63) as 71.6o and 67.2o,
12
respectively.
13
(3) Using crude oil with lower asphaltenes content (from type-I to type-II) on Dolomite
14
D(100) solid surface will cause a shift of contact angle from 127.9o as being oil wet to
15
87.8o positive intermediate wet, respectively.
16
(4) As contact angle values were increasing, adhesion tension was shifting to negative
17
directions as degree of oil wetness was increasing. This behavior was mainly attributed
18
to type-I crude oil.
19
comparatively high content of asphaltenes (I-11.6) in type-I crude oil.
Similarly, this might be explained as a result of having
20
(5) Using carbonated water as external phase, on pure Dolomite D*(100) solid surface
21
saturated with type-I oil, the contact angle values were increasing from 111.2o to 135.5o
22
with decreasing pressure from 2500 to 500 psig, respectively. Further investigations
23
need to be conducted in the future with carbonated water using additional rock and oil
24
samples in order to draw a solid conclusion.
25
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Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
1 2
Nomenclature
3
𝐴𝑇
Adhesion tension, dynes/cm
4
Contact angle, o
5
Interfacial tension, dynes/cm
6
D (100)
pure dolomite sample
7
C (100)
pure calcite sample
8
(D67 + C33)
Rock sample having 67% dolomite and 33% calcite
9
(D37 + C63)
Rock sample having 37% dolomite and 63% calcite
10
SARA
11
*
Oil-aged rock surface
12
**
The rock and oil sample obtained from different formation source (Oil: “A” formation,
13
Saturates, aromatic, resin and asphaltenes
Rock: “B” formation)
14 15
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1
Energy & Fuels
Acknowledgements
2
I would like to thank both the KFUPM and the management of the EXPEC Advanced
3
Research Center for utilizing its various facilities during the course of this study. My gratitude
4
goes to Hussain Al-Jeshi who helped me during the lab testing.
5 6 7 8 9 10
References
1- Adamson, A.W., 1982. Physical chemistry of surfaces 4th ed., John Wiley & Sons, Inc., 433–437.
11
2- Al-Maamari, R.S.H. and J.S. Buckley, 2003. Asphaltene Precipitation and Alteration
12
of Wetting: the Potential for Wettability Changes during Production, SPE 59292,2000
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SPE/DOE IOR Symposium, Tulsa, OK, U.S.A., 2-5 Apr.; SPE REE (Aug.) 210-14.
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3- Amott, E., 1959. Observations Relating to the Wettability of Porous Rock, Pet. Trans.
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AIE, Vol. 216, pp. 156-162. 4- Anderson, W.G., 1986.
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5- Buckley, J.S, 1996. Mechanisms and Consequences of Wettability Alteration by Crude
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Edinburgh, UK.
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6- Buckley, J.S., Y. Liu, and S. Monsterleet, 1998. Mechanisms of Wetting Alteration by Crude Oils, SPEJ (March) 3, 54-61. 7- Craig, F. F., 1971. The Reservoir Engineering Aspects of Water flooding, SPE Monograph 3, Richardson, TX.
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8- Donaldson, E.E. and Croker, M.E., 1980. Characterization of the crude oil polar
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compound extract. Bartlesville Energy Tech. Cent., Rep. DOE/BETC/RI-8-/5, U.S.
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9- Donaldson, E.E., 1981. Oil-water-rock wettability measurement. Preprints, Am. Chern. Soc., Div. Pet. Chern. I, (3), 110-122.
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10- Jadhunandan P. P and Morrow, N.R, 1995. Effect of Wettability on Water flood
32
Recovery for Crude-Oil/Brine/Rock Systems. Paper (SPE 22597) first presented at the 21 ACS Paragon Plus Environment
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1991 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, October
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6-9.
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11- Jadhunandan, P.P. and Morrow, N.R., 1991. Spontaneous imbibition of water by crude oil/brine/rock systems. Insitu 15(4), 319–345. 12- Jennings, J. B., 1987. Capillary Pressure Techniques: Application to Exploration and Development Geology AAPG Bulletin: Vol. 71 No. 10, October, 1196. 13- Morrow, N. R., 1990. Wettability and its Effect on Oil Recovery. JPT (December) 1476 – 1484.
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Measurements in the Arab-D Carbonate Reservoir. SPE 105114. 15th SPE Middle East
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Oil and Gas Show and Conference held in Bahrain International Exhibition Centre,
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Kingdom of Bahrain, March 11-14.
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15- Rose, W. and Bruce, W.A., 1949. Evaluation of capillary pressure in Petroleum Reservoir Rock, Pet. Trans; AIME, May 1949, 127.
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