Effect of Rock Mineralogy and Oil Composition on Wettability


Jan 30, 2019 - Saudi Aramco, Dhahran 31311, Saudi Arabia. ‡. Department of Petroleum .... rock samples obtained from the Saudi reservoir over 50 yea...
0 downloads 0 Views 429KB Size


Subscriber access provided by TULANE UNIVERSITY

Fossil Fuels

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

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 22 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

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,

1 ACS Paragon Plus Environment

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

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.

27

The contact angle is usually measured through the denser liquid phase and ranges from 0o to 2 ACS Paragon Plus Environment

Page 2 of 22

Page 3 of 22 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

1

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

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

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

Page 4 of 22

Page 5 of 22 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

1

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

5 ACS Paragon Plus Environment

Surface Tension, dynes/cm 73.5

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

Page 6 of 22

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

6 ACS Paragon Plus Environment

Page 7 of 22 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

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

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

Page 8 of 22

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

Page 9 of 22 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

1

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

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

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

Page 10 of 22

Page 11 of 22 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

1

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

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 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

Page 13 of 22

1

Mixed Systems

180 II: Type-II Oil

I: Type-I Oil

160 140

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

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

13 ACS Paragon Plus Environment

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 3

4 5 6

Page 14 of 22

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.

14 ACS Paragon Plus Environment

Page 15 of 22 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

1

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

18 ACS Paragon Plus Environment

Page 19 of 22 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

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

19 ACS Paragon Plus Environment

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

20 ACS Paragon Plus Environment

Page 20 of 22

Page 21 of 22 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

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

13

SPE/DOE IOR Symposium, Tulsa, OK, U.S.A., 2-5 Apr.; SPE REE (Aug.) 210-14.

14

3- Amott, E., 1959. Observations Relating to the Wettability of Porous Rock, Pet. Trans.

15 16

AIE, Vol. 216, pp. 156-162. 4- Anderson, W.G., 1986.

Wettability Literature Survey-Part-1: Rock-oil-brine

17

interactions and the effects of core handling on wettability. J. Pet. Technol., 38(10):

18

1125-1138.

19

5- Buckley, J.S, 1996. Mechanisms and Consequences of Wettability Alteration by Crude

20

Oil, PhD Thesis, Department of Petroleum Engineering, Heriot-Watt University,

21

Edinburgh, UK.

22 23 24 25

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.

26

8- Donaldson, E.E. and Croker, M.E., 1980. Characterization of the crude oil polar

27

compound extract. Bartlesville Energy Tech. Cent., Rep. DOE/BETC/RI-8-/5, U.S.

28

DOE.

29 30

9- Donaldson, E.E., 1981. Oil-water-rock wettability measurement. Preprints, Am. Chern. Soc., Div. Pet. Chern. I, (3), 110-122.

31

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

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

1991 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, October

2

6-9.

3 4 5 6 7 8

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.

9

14- Okasha, T.M, Funk, J.J, and Al-Rashidi, H.N., 2007. Fifty Years of Wettability

10

Measurements in the Arab-D Carbonate Reservoir. SPE 105114. 15th SPE Middle East

11

Oil and Gas Show and Conference held in Bahrain International Exhibition Centre,

12

Kingdom of Bahrain, March 11-14.

13 14

15- Rose, W. and Bruce, W.A., 1949. Evaluation of capillary pressure in Petroleum Reservoir Rock, Pet. Trans; AIME, May 1949, 127.

15

16- Thomas, M.M. and Clouse, J.A., 1989. Thermal analysis of compounds adsorbed on

16

low-surface-area solids. Part 1. Measurement and characterization by TGA.

17

Thermochim. Acta. 140, 245.

18

17- Yang, Y., Van Dijke, M and Yao J., 2010. Efficiency of Gas Injection Scenarios for

19

Intermediate Wettability: Pore Network Modeling. Paper presented at the International

20

Symposium of the Society of Core Analysts, Halifax, Nova Scotia, Canada, and

21

October 4-7.

22

22 ACS Paragon Plus Environment

Page 22 of 22