The mutual effects of injected fluid and rock during imbibition in the process of low and high salinity carbonated water injection into carbonate oil reservoirs

The mutual effects of injected fluid and rock during imbibition in the process of low and high salinity carbonated water injection into carbonate oil reservoirs

Journal Pre-proof The mutual effects of injected fluid and rock during imbibition in the process of low and high salinity carbonated water injection i...

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Journal Pre-proof The mutual effects of injected fluid and rock during imbibition in the process of low and high salinity carbonated water injection into carbonate oil reservoirs

Iman Nowrouzi, Abbas Khaksar Manshad, Amir H. Mohammadi PII:

S0167-7322(19)35176-1

DOI:

https://doi.org/10.1016/j.molliq.2019.112432

Reference:

MOLLIQ 112432

To appear in:

Journal of Molecular Liquids

Received date:

14 September 2019

Revised date:

8 December 2019

Accepted date:

30 December 2019

Please cite this article as: I. Nowrouzi, A.K. Manshad and A.H. Mohammadi, The mutual effects of injected fluid and rock during imbibition in the process of low and high salinity carbonated water injection into carbonate oil reservoirs, Journal of Molecular Liquids(2018), https://doi.org/10.1016/j.molliq.2019.112432

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© 2018 Published by Elsevier.

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The mutual effects of injected fluid and rock during imbibition in the process of low and high salinity carbonated water injection into carbonate oil reservoirs

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Iman Nowrouzi, a Abbas Khaksar Manshad, b * Amir H. Mohammadi a,*

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Discipline of Chemical Engineering, School of Engineering, University of KwaZulu-Natal, Howard College Campus, King George V Avenue, Durban 4041, South Africa b

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Department of Petroleum Engineering, Abadan Faculty of Petroleum Engineering, Petroleum University of Technology (PUT), Abadan, Iran

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*: Corresponding authors email addresses: A. Khaksar Manshad: [email protected], [email protected] AND A.H. Mohammadi: [email protected]

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Abstract - During water injection into oil reservoirs, interactions occur between injected water and the reservoir rock. The interactions are enhanced when dissolved carbon dioxide (CO2) is

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used in injectable fluid in enhanced oil recovery (EOR) processes, especially in carbonate reservoirs. With the dissolution of CO2 in water, carbonic acid is formed. The formed acid reacts with the carbonate salts in the rock (calcium carbonate and magnesium carbonate) and dissolves them. The dissolution causes a change in the properties of the rock, including wettability, porosity and permeability. In this study, variations of porosity, permeability, rock mass and wettability during carbonated water imbibition were measured based on direct measurements of porosity, permeability, rock weight and contact angle. In addition, changes in the concentration of calcium, magnesium and bicarbonate ions from the dissolution of carbonate rocks in injected 1

Journal Pre-proof water were measured by sampling and titration of water. The experiments were carried out at a constant temperature and the pressure parameter was considered to be variable in order to investigate its effect on the cases discussed. The effect of base fluid salinity was investigated in two salinities equal to the initial salinity and salinity from the dilution of seawater. The carbonated water imbibition in oil-saturated plugs yields 48, 56, 69 and 75 percent, at pressures of 500, 1000, 1500, and 2000 psi, respectively, and low salinity resulted from the dilution of

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seawater as the base fluid. In addition to the dependence of changes in rock parameters on the

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pressure and salinity of the base fluid, the results show that porosity variations, permeability and,

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most importantly, wettability of the rock are so much that they can be effective in activating the

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process of the imbibition and increasing its power in oil production.

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Keywords - Carbonated water; Imbibition; Wettability alteration; Rock dissolution; Chemical

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Enhanced Oil Recovery (CEOR).

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1. Introduction Carbonated water injection is one of the methods for enhanced oil recovery (EOR). The dissolved CO2 in water changes both the physical and chemical properties of water. The chemical changes are based on reactions between CO2 and water, followed by the formation of carbonic acid. The interactions between the injectable phase and the rock and reservoir fluid

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become more intense with the formation of carbonic acid and the pH drop. Effective variations in the method of carbonated water injection, such as interfacial tension (IFT) reduction of water and

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oil [1, 2], dissolution and wettability alteration of the reservoir rock to hydrophilicity [3-5], crude

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oil swelling due to CO2 mass transfer from water to oil [6, 7], increasing the water viscosity [8,

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9] and reducing the viscosity of oil [10, 11] are among those that can have a physical or chemical

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origin. The weak performance of CO2 penetration is one of the common problems in the CO2 injection process. To reduce this problem, carbonated water injection technology was introduced

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[12]. The benefits of the carbonated water injection method from the various mechanisms make

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it a powerful method for increasing sweep efficiency. Esene et al. found it more effective than conventional CO2 injection, water flooding, and water alternating gas injection methods [13].

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The CO2 remains soluble during the transfer from the injectable phase to the oil. By dissolving CO2 in oil, the viscosity of the oil decreases, and the volume of oil increases, which increases the relative permeability of oil and thus increases the final recovery factor compared to the ordinary flooding test. In the process of carbonated water flooding, the miscibility is not one of the main objectives, as a result, there are fewer restrictions for reservoir conditions and type of oil. In addition, the ease of separating CO2 and water in the wells, the easy transportation of injected fluid, and the possibility of performing other third-party enhancement techniques thereafter, are other operational advantages of this method [3]. In fractured carbonate reservoirs, gravity 3

Journal Pre-proof drainage is the main mechanism of production at the initial stage, but in increasing the volume of these reservoirs by chemical water injection, the imbibition plays a more effective role. The porosity and permeability in this type of reservoir create a limitation for the injection of any chemical water. For example, in water injection in the traditional way due to poor penetration of injected water in the oil-wet Matrix, it is possible for water to enclose surrounding the matrix through the high permeable gaps, and when it cannot penetrate into the matrix, it traps oil into it.

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In addition to not activation of the imbibition mechanism, it also eliminates gravity. However, in

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carbonated water injection, based on cases such as the transfer of CO2 from water to oil and oil

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swelling, availability of the higher carbonated water content than the ordinary water [9,13],

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followed by the presence of carbonated water in lower layers, there is possibility of carbonated water penetration in matrix, alteration of matrix wettability and reduction of interfacial tension of

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water and oil in the matrix, and subsequently decrease of capillary pressure and performing the

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process of imbibition. In addition, carbonated water injection agents have other benefits that have been welcomed. For example, with the formation of a low concentration of carbonic acid in

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the wells, together with alkaline minerals such as calcium, potassium and barium, the

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surrounding formation of wellbore is corroded and a kind of lateral acidizing takes place, which causes the injectivity increase to the well, which this is effective both in carbonate formations and in sand formations [14]. Similarly, in the presence of a large number of bicarbonates in the mineral structure of the oil-containing formation, the acidity of carbonated water can cause dissolution and increase the utilization of wells [15, 16]. A lot of research has been done on carbonated water injection, especially in recent years, which suggests that by changing the parameters that affect the production of oil, high recovery of crude oil is achievable in this method. Table 1 shows a review of recent studies on the carbonated water injection, broken

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Journal Pre-proof down by the mechanisms and parameters studied. However, some cases, such as carbonated water imbibition at high pressures and temperatures with direct observation of the results, have been less investigated, given the harsh conditions of these experiments. Investigation of rock and fluid interactions due to carbonated water reactions at reservoir conditions, as well as their dependence on pressure and salinity of the base fluid have not been systematically investigated and most studies are limited to oil production by carbonated water flooding and investigations of

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mechanisms of injectable fluid and oil mass transfer. The rock dissolution mechanism plays an

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important role in EOR, especially in carbonate reservoirs. These reservoirs mainly have low

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porosity and permeability, and increased porosity and permeability by rock dissolution can have

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a significant impact on production under carbonated water imbibition. Dissolution of rock minerals causes clogged and unilateral clogged cavities to come together so that in addition to

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releasing trapped oil, it prepares a channel for production. Determination of rock dissolution is

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possible by measuring the direct changes in porosity, permeability and weight of the rock. On the other hand, water-soluble minerals increase the concentration of the respective ions, which can

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measure the dissolution intensity. In this study, oil production under carbonated water imbibition

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at constant temperature of 75 °C and various pressures in the range of 500-2000 psi and the effect of carbonated water during this process on the reservoir rock and subsequently the effect of carbonate rocks on injected water by conducting tests, contact angle, porosity and permeability alteration and rock weight along with measurement of the concentration of calcium, magnesium and bicarbonate ions following the dissolution of rock in carbonated water have been investigated.

2. Experimental section 5

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2.1.

Materials

The saline water of the Persian Gulf as a base fluid for carbonated water was used. Seawater analysis is presented in Table 2. The dead crude oil of the Karanj reservoir located in southwestern Iran with the composition according to Table 3 and API = 32.02 and an acidity of 3.7 mg KOH/g oil sample was used. Carbonate rock was sampled from the outcrops of Asmari

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Formation in Khuzestan, Iran. The rock was carbonate containing 61% dolomite and 39% calcite. Fig. 1 shows the XRD and SEM analyzes of the rock. The gases of nitrogen and CO2

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purchased from Abughaddareh Industrial Gases Co., Iran, with a purity of 99.99 mole% were

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used. Toluene and Acetone, with a purity of 99.9 mole%, produced from MP-Biomedicals

Equipment

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2.2.1. Imbibition cell

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2.2.

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(Netherlands) were used.

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An imbibition cell made of stainless steel 316 was specially designed with the ability to withstand high pressure and temperatures to perform the experiments. A narrow, high-density compartment was calibrated in the imbibition cell, and the produced oil can be calculated from the groove in which it was created and resilient to the glass, and its volume was calculated. Another similar groove is placed exactly against the graded groove so that it is easy to observe and read the volume of oil collected by using a light source. At the bottom and top of the inlet and outlet duct, there is a high-pressure line to be connected to which, carbonated water can be injected. This imbibition cell can withstand pressure up to 2000 psi and temperature up to 180 °C and has a precision of ±0.1 cm3 according to its grading. The imbibition cell is shown in Fig. 2. 6

Journal Pre-proof When high-pressure CO2 is present in the system, it must be ensured that CO2 is not discharged during the test. In addition to constant pressure checking, the O-rings should be suitable for acidic environments and high temperatures and pressures. Therefore, F-grade Viton O-rings (DuPont Co., USA) were used in the imbibition container.

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2.2.2. Carbonated water supply system

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To generate carbonated water at high temperatures and pressures, a system includes a

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cylinder and piston made of resistant steel, connected to the bottom by a high-pressure line to an oil hydraulic pump and connected to the top of the gas cylinder is used. The cylinder has two

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upper and lower valves. The system is located in an oven with a temperature accuracy of 0.1 °C.

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A valve is placed on the line connected to the CO2 cylinder. The water solution is poured into the cylinder and then CO2 gas is added. After adding CO2 to the inlet valve, the pressure of the

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system is increased by pushing the piston by a manual hydraulic pump and controlled by a

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pressure gauge mounted on the cylinder and manual hydraulic pump connection line. In this

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case, carbonated water is transferred to the cell. The uncertainty of the barometer is 0.5% full scale. This system was used to supply carbonated water in the imbibition experiments as shown in Fig. 3. To measure the porosity and permeability of the carbonate sample, a porosity measurement device with the commercial name of Porosity-90-102 was used and the Fars EOR Technologies Co. Iran made Gasperm-90-101 permeation device was used for the permeability measurement. The porosity device calculates the porosity using the helium gas flow and, based on Boyle’s law, calculates the permeability with respect to the Darcy equation and the passage of helium gas from the porous environment of the core.

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2.2.3. Contact angle measurement device IFT400 device according to the schematic of Fig. 4 was used for the contact angle tests. IFT400 has two manually syringe pumps, one of which pumps the bulk solution into a hollow cell and the other is connected to a metal needle and pumps the drop fluid. The hollow cell has

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two glass windows facing each other and a thermal jacket. There is a light source in front of one

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of the windows and a camera is against the other window. The camera is connected to a

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computer and reports images taken from the drop-bulk system. The software of the device draws a baseline showing the cross-section of the rock surface and two tangent lines on either side of

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the drop and reports the left, right and mean contact angles with an uncertainty of 0.2-0.5°. The

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cell temperature is controlled by a thermometer and a PID controller with an uncertainty of ±0.3 °C. The cell pressure is also regulated by the manual pumps and is displayed with a barometer

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with a 0.5 full-scale uncertainty.

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3. Experimental procedure The imbibition experiments were carried out by the container and the system was executed in accordance with Fig. 3 at 75 °C. For each of the base fluids (seawater with a primary concentration as high saline water and 20 times diluted seawater), each dilution was performed by adding 100ml of distilled water to 1 liter of seawater. These experiments were carried out with four oil-saturated plugs at 500, 1000, 1500, and 2000 psi, and the production was recorded in time intervals of 1 day. These eight experiments continued to achieve the production of oil from the plugs by the imbibition mechanism and continuously until the production became 8

Journal Pre-proof steady. Other experiments were done similarly to measure rock parameter changes such as porosity, permeability and weight, as well as the properties of injectable fluid such as calcium, magnesium and bicarbonate ions, but were discrete. That is, at 3-day intervals after the discharge of pressure from the fluid in the chamber, sampling and analysis were carried out by titration to determine the changes in the ions, and the porosity and permeability tests were taken from the target plug. At each stage after the necessary tests, the pressure and temperature conditions

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returned to the initial conditions. In the second series, which was designed to change the

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properties of rock and injected water, clean and oil-free cores were used. To study the wettability

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alteration of the contact angle tests, IFT400 was used. Carbonate sections were cut. Then the

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cross-sections were polished. After removal of the produced dust by the high-pressure nitrogen gas, they remained in toluene for 1 day to eliminate the fatty acids resulting from contact with

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the hands. It was then aged for a month in the crude oil of the sample at 70 °C to achieve initial

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hydrophobicity [3]. The contact angle tests for carbonated water with a salinity of the initial concentration of seawater and the salinity of 20 times dilution were carried out after three days

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remaining of sections in carbonated water at a constant temperature of 75 °C and pressures of

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500, 1000, 1500 and 2000 psi. Fig. 5 shows the experimental procedure flowchart. The sources of error in this study fall into two categories. The first is due to the repeatability of the tests and the second is due to the methods. For example, in sampling and measuring changes in dissolved ions in injectable water, in addition to the titration error, some water-soluble ions may precipitate due to pressure discharge during sampling and over time. Immediate measuring of the samples taken at each step can reduce this error.

4. Results and discussion 9

Journal Pre-proof Table 4 shows the characteristics of the used plugs and the imbibition fluid corresponding to each one. Fig. 6 shows the curve of the percentage of oil production from carbonated water in the oil saturation plugs in terms of the curve. Tables 5, 6, and 7, respectively, indicate porosity variations, permeability and rock masses and Figs. 7-9 show the tables’ data as curves. Tables 8, 9 and 10 show the changes in Ca2+, Mg2+ and HCO3- ions and Figs. 10, 11 and 12 demonstrate these results in the form of graphs. Finally, Table 11 and Fig.

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13 show the degree of change in the contact angle of oil droplets on the aged rock in carbonated

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water. Fig. 6 shows the results of the oil production of carbonated water imbibition from oil-

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saturated plugs, which shows that the final rate of production at constant temperature is highly

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dependent on the pressure and salinity of the base fluid. In these experiments, final production at 75 °C at 500, 1000, 1500, and 2000 psi, when seawater with a primary concentration used as a

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carbonated base fluid, was 43, 51, 57 and 62%, respectively while these values for carbonated

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water with salinity of 20 times dilution of seawater were 48, 56, 69 and 75 percent, respectively. In addition, reaching the final production and stopping production, as it is clear in Fig. 6 by

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horizontalization of the curves, is achieved in these 8 cases after 16 to 22 days. A review of CO2-

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free saline imbibition water studies normally takes longer than 30 days. The dramatic reduction in the effective time of the imbibition and its increase in speed can occur due to increased pressure and activation of the soluble CO2 mechanisms. As mentioned earlier, the incremental production values in these experiments were recorded at 1-day intervals and the first one was recorded after 1 day of the experiment. Although production is very important in early times, the production in these trials before a day was negligible and this could be due to the hydrophobicity of the plugs at the beginning of the experiment. Fig. 7 for porosity variations and Fig. 8 for permeation variations of the samples indicate an increase in both parameters proportional to the

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Journal Pre-proof pressure and salinity and, of course, the remaining time. According to Fig. 7, the porosity increases at a constant temperature of 75 °C at 500, 1000, 1500, and 2000 psi for high saline carbonated water was 8, 11, 13 and 17%, respectively, and at 12, 15, 16 and 19% after a 15-day remaining of samples in the solution, at the end of the fifth step of sampling. The increase in permeability was also shown in Fig. 7 at a constant temperature of 75 °C at 500, 1000, 1500, and 2000 psi for high-salinity carbonated water of 8, 10, 13 and 16%, respectively, and at 12, 14, 16

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and 21% after 15 days of immersion of the samples in solution. After 15 days, the weight loss of

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the specimens shows the highest weight loss at a constant temperature of 75 °C, at 2000 psi, and

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for a sample immersed in carbonated water, has occurred with a low salinity of 20 times dilution

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of seawater. The graphs in Fig. 9, in addition to the direct weight loss report, shows the ratio of

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sample weight at each sample to the sample's initial weight. The concentration of Ca2+, Mg2+ and HCO3- ions is subject to change as a consequence of

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CO2-water-carbonate rock reactions. Water analysis at each stage of the imbibition experiments

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shows that the concentration of these ions increases over time. However, this increase in the early stages is more than the final stages. The concentrations of calcium ion according to Fig. 10

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at the first, second, third, fourth and fifth stages of low-saline carbonated water at 75 °C and the highest pressure of 2000 psi were 2340, 2110, 1810, 1550 and 1070 ppm, respectively, and 1890, 1550, 1300, 1010 and 820 ppm for imbibition carbonated water, respectively. A trend that shows although the cumulative concentration of calcium ion at the end of the fifth stage is more than all stages, at each step, the concentration decreases from the previous stage, which is correct for all pressures and salinity of carbonated water. Similar to the trend, there is also a change in the concentration of magnesium ions and bicarbonates in injected water. For magnesium ions, for example, in the first, second, third, fourth and fifth stages of low-saline carbonated water at 75

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Journal Pre-proof °C and 2000 psi, it is 3150, 2810, 2380, 1870 and 970ppm, respectively, for highly saline imbibition carbonated water was obtained 2100, 1840, 1150, 970 and 680 ppm, respectively. For bicarbonate ions, according to Fig. 12, in the first, second, third, fourth and fifth stages, lowsaline carbonated water at a temperature of 75 °C and a pressure of 2000 psi were 3140, 2620, 2060, 1610 and 1090 ppm, respectively for highly saline carbonated water imbibition was obtained in 1910, 1620, 1190, 850 and 590ppm, respectively. In the overview of Figs 10-12, we

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find that the dissolution time of the rock increases, while the dissolution rate is higher in the

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early times than in the late stages. This trend can be justified by increasing the aqueous

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concentration of dissolved minerals and decreasing the volume of soluble minerals in the rock. In

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addition, the amount of magnesium ions at the end of the experiment is higher than calcium ions. This is justified by the initial composition of the rock and the ratio of dolomite to calcite (61:39).

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The behaviors and trends proportional to salinity and pressure are justified by the reactions of

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dissolved CO2 and water and then carbonated water and rock. These reactions have been developed in the following paragraphs due to the shared mechanisms of wettability alteration and

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oil production under imbibition.

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As stated earlier, the aging time of the oil-wet sections in carbonated water is considered to be a three-day period. The reason for not examining the angle of contact over a longer period was that the surface of the rock was overused, roughened and contact angle values face an error because the contact angle was measured with the IFT400 device, which requires the flat and polished surface of the rock. The curve of the contact angle in Fig. 13 indicates that the crosssectional variation is moderately and strongly hydrophilic. The contact angle of the oil droplet on the low-saline carbonated water at 75 °C and 500, 1000, 1500 and 2000 psi after three days were 47.52, 41.86, 33.07 and 24.16° respectively, and for the remaining sections in highly saline

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Journal Pre-proof carbonated water were 64.13, 58.06, 50.41, and 43.90 degrees, respectively. In the fractured reservoirs, the process of imbibition in the matrix is one of the most important mechanisms of production. The capillary pressure is an effective factor in the process of imbibition, and this parameter is related by the relation 1 to the wettability, contact angle and interfacial tension [29]: 𝑃𝑐 =

2𝜎𝑐𝑜𝑠𝜃

(1)

𝑟

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In which, Pc is the capillary pressure in Pa, σ is the interfacial tension in mN/m, θ is the

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contact angle in degrees, and r is the capillary radius in meters.

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The capillary imbibition phenomenon is normally investigated under the influence of

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capillarity and gravity forces. Injections can also be considered if the water is injected into the reservoir. In fact, under imbibition production in fractured reservoirs is affected by two

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components of wettability alteration, and interfacial tension [30]. The alteration in wettability in

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the matrix results in a positive bonding of the capillary, causing the oil to be displaced by capillary forces [31]. In order to carry out the spontaneous imbibition process and the outflow of

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oil by water from the matrix, the matrix wettability should be oriented from the hydrophobic to

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the hydrophilic. In this study, contact angle tests were used to indicate an alteration in wettability. The contact angle on the polished cross-section, although is not representative of the porous media surface within the matrix, is generally accepted. The imbibition dependence on wettability also shows that more production in this process occurs at a reduced contact angle. Therefore, it can be said that the maximum imbibition is obtained when the contact angle is low [29, 32]. The wettability alteration of rock by carbonated water is likely to occur due to the dissolution of the rock by carbonic acid. The formation of carbonic acid according to Equations 2

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Journal Pre-proof and 3 also results from Equations 4, 5 and 6 of carbonate dissolution in injected water [4, 5, 33, 34]: 𝐻2 𝑂 (𝑙) + 𝐶𝑂2 (𝑎𝑞) ↔ 𝐻2 𝐶𝑂3 (𝑎𝑞) (2) 𝐻2 𝐶𝑂3 (𝑎𝑞) ↔ 𝐻 + (𝑎𝑞) + 𝐻𝐶𝑂3− (𝑎𝑞)

(4)

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𝐻2 𝑂 (𝑙) + 𝐶𝑂2 (𝑎𝑞) + 𝐶𝑎𝐶𝑂3 (𝑠) ↔ 𝐶𝑎(𝐻𝐶𝑂3 )2 (𝑎𝑞)

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(3)

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𝐻2 𝑂 (𝑙) + 𝐶𝑂2 (𝑎𝑞) + 𝑀𝑔𝐶𝑂3 (𝑠) ↔ 𝑀𝑔(𝐻𝐶𝑂3 )2 (𝑎𝑞)

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(5)

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𝐻2 𝑂 (𝑙) + 𝐶𝑂2 (𝑎𝑞) + 𝐶𝑎𝑀𝑔 (𝐶𝑂3 )2 (𝑠) ↔ 2𝐻𝐶𝑂3− (𝑎𝑞) + 𝑀𝑔2+ (𝑎𝑞) + 𝐶𝑎2+ (𝑎𝑞)

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(6)

These reactions control the dissolution of minerals in carbonate rocks. Equations 4, 5, and

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6, occur during the reaction of carbonic acid obtained from the previous step with the rock,

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respectively, and are related to the reaction of calcite, magnesite and dolomite with carbonic acid. The importance of Equations 2 and 3 is the same for all carbonated water injection processes, but the significance of Equations 4, 5 and 6 are related to the reservoir rock. For example, in Equation 4 faced with the dominant calcite rock reservoir due to the frequency of the primary reaction material calcite is more important. The formation of carbonic acid reduces the pH of the water, which is proportional to the pH of the solution with:

pH  A[ log 10 ( X )]  B

(7)

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Journal Pre-proof where, x is the molar fraction of CO2 in carbonated water, and A and B are calculated empirically [35]. In addition to carbonated water mechanisms in wettability alteration, low and high salinity water mechanisms and their effect on carbonated water mechanisms are also important. As noted, high salinity reduces the solubility of CO2 in water, which can weaken the mechanisms

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of carbonated water in the wettability alteration. The high-salinity water ion-exchange mechanism and the removal of fatty acids absorbed by the rock surface have more validity in the

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wettability alteration of carbonate rock. For example, in this mechanism, the SO42- anion present

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in seawater reduces the positive charge surface area and increases the ability of cations to

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approach the carboxylic acid adsorbed on the rock. As the concentration of divalent cation Mg2+

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in the water increases, the ability of the cations to remove carboxylic acid, which is absorbed by the negative head of the rock, increases and more hydrophilicity of the rock is obtained [36, 37].

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But salt-in effect and dissolution of carbonate rock are stronger in wettability alteration of

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carbonate rock at low salinity. Salt-in effect facilitates the diffusion of surface-active agents from the solvent at low salt concentration [38]. In other words, at low salinity, the solubility of

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different types of hydrocarbons adsorbed on the rock surface increases in the aqueous solution. Another strong mechanism that occurs at low salinity is related to the reactions that dissolve the rock at its surface (according to Equations 8 and 9) that release some of the OH- ions from these reactions. As the salinity declines, this mechanism is strengthened and wettability is more likely to become hydrophilic [39, 40]. 𝐶𝑎𝐶𝑂3 (𝑠) ↔ 𝐶𝑎2+ (𝑎𝑞) + 𝐶𝑂32− (𝑎𝑞)

(8)

𝐶𝑂32− + 𝐻2 𝑂(𝑙) ↔ 𝐻𝐶𝑂3− (𝑎𝑞) + 𝑂𝐻 − (𝑎𝑞)

(9)

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Journal Pre-proof The porosity is gradually increased during the process, which is consistent with the dissolution and reduction of the weight of the cores; if the container pressure decreases, the thrust mechanism of the dissolved gases will be dominant, the dissolved ions will be removed from the inside of the cavities and increase the permeability but if the formation of precipitates is precipitated, the ions will precipitate and will cause the throat of the cavity to be closed and thus will reduce the permeability. Here, for both porosity and permeability parameters, an increasing

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trend has occurred. The solubility of minerals itself has a complex affinity to temperature and

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pressure. The carbonate solubility increases with increasing acidity of the fluid, and CO2 at high

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pressures provides the necessary acidity. If the pressure drops, CO2 is released from the solution

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and causes the pH to rise, resulting in the formation of calcite sedimentation, which means that when the cylinder pressure is discharged for fluid sampling and the tests of porosity and

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permeability, calcite deposition is possible. One way to prevent the deviation of titration data

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from the actual amount of the dissolved ions is to test the fluid sample quickly and not have the opportunity to precipitate, it is even better to prevent temperature drop as calcite can also be

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deposited due to temperature drop. It can be seen that the calcium carbonate solubility increases

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with increasing pressure, therefore, according to the results, the concentration of calcium ions in water increases with increasing pressure. Always a combination of factors is effective in the CO2 solubility in produced water. The lower temperature near the surface increases the solubility level, while lower pressure at the near-surface causes the CO2 to be released and compensates the effect of the temperature drop. Almost always, CO2 emissions are more effective because of the pressure drop. Generally, with increasing temperature, the effect of increasing CO2 pressure on calcium carbonate solubility decreases.

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Journal Pre-proof Salt solutions that do not have mutual ions (ions of calcium or carbonate) affect calcium carbonate solubility. These salts increase the ionic strength of the product and thus affect the activity coefficient of calcium and bicarbonate ions. With increasing sodium chloride concentration, calcium carbonate solubility increases. At higher concentrations of sodium chloride, calcium carbonate solubility begins to decrease. The optimum concentration of the ionic solution is also dependent on the pressure. Factors affecting the solubility of calcium

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carbonate also affect magnesium carbonate solubility. Like calcium carbonate, the magnesium

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carbonate solubility increases with increasing partial pressure of CO2 on water and decreases

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with partial pressure reduction of CO2. The solubility of magnesium carbonate decreases with

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increasing temperature and in contrast to the effect of uncommon ions, it is similar to calcium carbonate. The solubility of magnesium carbonate in distilled water is 0.233 g/liter, which is

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almost four times higher than calcium carbonate solubility. The obtained values from the change

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in the concentration of ions are due to the dissolution of rock in acidic water, and these minerals have little solubility in water with no dissolved CO2. The control of the pressure and temperature

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in the laboratory, which was carried out to avoid CO2 emissions, is of particular importance in

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the reservoir, and as it was said, this could lead to the deposition of minerals and serious damage to the formation, which requires further investigation. It makes sense for sediment control. In addition to the effect of pressure and temperature changes on the change in the concentration of CO2 in carbonated water, when carbonated water is adjacent to oil, due to the greater solubility of CO2 in oil relative to water, a mass transfer of gas occurs from water to oil which leads to an increase in pH and can affect the dissolution of dissolved minerals. Carbonated water injection has some limitations in different conditions of the reservoir such as heterogeneity, wettability and fluid properties, despite its features and advantages. 17

Journal Pre-proof Heterogeneity alone does not affect carbonated water performance, but on wettability, studies have shown that mixed water-wet primary wettability has greater efficiency in both carbonate and sandstone formations. Regarding the salinity of the formation water, it can be said that increasing salinity weakens the carbonated water yield, hence the salinity of the formation water can create limitations. In the case of reservoir oil, according to previous studies, the mechanism of oil swelling in reservoirs with lighter oils is stronger than viscous oils. These interpretations

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suggest that none of the critical conditions of the rock and reservoir fluid poses significant

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limitations for the carbonated water injection method, but some mechanisms undermine this

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method [41]. Operational parameters such as temperature, pressure and injection rate also affect

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carbonated water performance. The effects of temperature and pressure have been well developed in this study and other studies (References [42- 45]). In summary, it can be deduced

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that increasing temperature will result in a decrease in CO2 solubility and subsequently a

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decrease in recovery which is quite the opposite for pressure. However, there may be restrictions on the equipment and injection pumps. Regarding the temperature of the injectable fluid, the

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temperature compatibility with the temperature of the reservoir can be determined. Concerning

effective [41].

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injection rates, according to past research, it can be said that lower injection rates are more

5. Conclusion and Recommendation Carbonated water imbibition tests were carried out in oil saturation plugs, contact angles, porosity variations, permeability and rock weight, and calcium, magnesium and bicarbonate ions were measured to investigate the interaction of rocks and injectable fluids. According to this: 18

Journal Pre-proof •

Carbonated water can activate the mechanism of imbibition in the matrix rock, which is due to effects such as wettability alteration and rock dissolution.



The relatively good efficiency of the carbonated water imbibition process was achieved in oil-saturated plugs. The highest values at 75 °C at 500, 1000, 1500 and 2000 psi pressure when seawater with initial concentration was used as a base fluid of the

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carbonated water was 43, 51, 57, and 62 percent, respectively, where these values for carbonated water with salinity of 20 times dilution of seawater were 48, 56, 69 and 75

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percent, respectively.

Carbonated water imbibition production at constant temperature depends on the pressure

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and salinity of the base fluid. In addition, the effective duration of carbonated water

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imbibition is much lower than saltwater, which indicates the greater carbonated water

The contact angle values are in the hydrophilic range, which can provide an introduction

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power in performing the imbibition mechanism.



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to the activation of the imbibition mechanism. The dissolution of the rock is evident in the carbonated water imbibition process, which increases the calcium, magnesium and bicarbonate ions in the injected water. •

Porosity and permeability during carbonated water imbibition increases as well, which can affect the process of imbibition and better exit of oil out of the matrix.



The experiments in this study do not cover sedimentation problems of dissolved minerals in carbonated water, while they are very important. It is suggested that these issues be considered and developed in future researches.

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References [1] Manshad, A.K., Olad, M., Taghipour, S.A., Nowrouzi, I. and Mohammadi, A.H., 2016. Effects of water soluble ions on interfacial tension (IFT) between oil and brine in smart and carbonated smart water injection process in oil reservoirs. Journal of Molecular Liquids, 223, pp.987-993.

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[2] Nowrouzi, I., Manshad, A.K. and Mohammadi, A.H., 2018. Effects of dissolved binary ionic

ro

compounds and different densities of brine on interfacial tension (IFT), wettability alteration, and

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contact angle in smart water and carbonated smart water injection processes in oil reservoirs.

re

Journal of Molecular Liquids, 254, pp.83-92.

[3] Manshad, A.K., Nowrouzi, I. and Mohammadi, A.H., 2017. Effects of water soluble ions on

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wettability alteration and contact angle in smart and carbonated smart water injection process in

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oil reservoirs. Journal of Molecular Liquids, 244, pp.440-452.

ur

[4] Luquot, L. and Gouze, P., 2009. Experimental determination of porosity and permeability

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changes induced by injection of CO2 into carbonate rocks. Chemical Geology, 265(1), pp.148-

[5] Ross, G.D., Todd, A.C., Tweedie, J.A. and Will, A.G., 1982, January. The dissolution effects of CO2-brine systems on the permeability of UK and North Sea calcareous sandstones. In SPE Enhanced Oil Recovery Symposium. Society of Petroleum Engineers. SPE-10685-MS. [6] Riazi, M. and Golkari, A., 2016. The influence of spreading coefficient on carbonated water alternating gas injection in a heavy crude oil. Fuel, 178, pp.1-9.

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Journal Pre-proof [7] Lashkarbolooki, M., Riazi, M. and Ayatollahi, S., 2018. Experimental investigation of dynamic swelling and Bond number of crude oil during carbonated water flooding; Effect of temperature and pressure. Fuel, 214, pp.135-143. [8] Bando, S., Takemura, F., Nishio, M., Hihara, E. and Akai, M., 2004. Viscosity of aqueous NaCl solutions with dissolved CO2 at (30 to 60) °C and (10 to 20) MPa. Journal of Chemical &

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[9] McBride-Wright, M., Maitland, G.C. and Trusler, J.M., 2014. Viscosity and density of aqueous solutions of carbon dioxide at temperatures from (274 to 449) K and at pressures up to

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mechanism leading to improved oil recovery by carbonated water injection. Journal of Industrial

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and Engineering Chemistry, 45, pp.22-32.

[11] Shu, G., Dong, M., Chen, S. and Hassanzadeh, H., 2016. Mass transfer of CO2 in a

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carbonated water–oil system at high pressures. Industrial & Engineering Chemistry Research,

[12] Esene, C., Zendehboudi, S., Shiri, H. and Aborig, A., 2019. Deterministic tools to predict recovery performance of carbonated water injection. Journal of Molecular Liquids, p.111911. [13] Esene, C., Zendehboudi, S., Aborig, A. and Shiri, H., 2019. A modeling strategy to investigate carbonated water injection for EOR and CO2 sequestration. Fuel, 252, pp.710-721. [14] Srivastava RK, Huang SS, Dong M., 2000. Laboratory investigation of Weyburn CO2 miscible flooding. J Can Pet Technol, 39(2), pp. 41–51.

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improvment

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CO2-Enriched

Water

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EUROPEC/EAGE Conference and Exhibition, 8-11 June, Amsterdam, the Netherlands, 2009: Amesterdam, Netherland. SPE-121170-MS. [16] Kislyakov, Y. P., Kovalenko, K. I., Babalyna, G. A., 1967: ‘‘Treatment of well-Bore Area of Injection Wells with Carbonated Water’’, Neft Khoz, Vol. 45, No. 4 P. 41-44.

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Carbonated Water’’, ING Petrol, Vol. 10, No. 1, P. 17-21.

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[17] Kraus, A. D., Mendoza, C. M. and Cortes, M. C., 1970: ‘‘Injection of Acidulated Water of

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[18] Ruidiaz, E.M., Winter, A. and Trevisan, O.V., 2018. Oil recovery and wettability alteration

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Production Technology, 8(1), pp.249-258.

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in carbonates due to carbonated water injection. Journal of Petroleum Exploration and

[19] Seyyedi, M., Sohrabi, M. and Farzaneh, A., 2015. Investigation of rock wettability alteration

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by carbonated water through contact angle measurements. Energy & Fuels, 29(9), pp.5544-5553.

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[20] Seyyedi, M., Mahzari, P. and Sohrabi, M., 2018. A comparative study of oil compositional variations during CO2 and carbonated water injection scenarios for EOR. Journal of Petroleum

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Science and Engineering, 164, pp.685-695. [21] Seyyedi, M., Sohrabi, M., Sisson, A. and Ireland, S., 2018. Quantification of oil recovery efficiency, CO2 storage potential, and fluid-rock interactions by CWI in heterogeneous sandstone oil reservoirs. Journal of Molecular Liquids, 249, pp.779-788. [22] Foroozesh, J. and Jamiolahmady, M., 2018. The physics of CO2 transfer during carbonated water injection into oil reservoirs: From non-equilibrium core-scale physics to field-scale implication. Journal of Petroleum Science and Engineering, 166, pp.798-805.

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Journal Pre-proof [23] Bakhshi, P., Kharrat, R., Hashemi, A. and Zallaghi, M., 2018. Experimental evaluation of carbonated waterflooding: A practical process for enhanced oil recovery and geological CO 2 storage. Greenhouse Gases: Science and Technology, 8(2), pp.238-256. [24] Adiputra, E., Mucharam, L. and Rahmawati, S.D., 2018. Experimental Evaluation of Carbonated Water Injection to Increase Oil Recovery Using Spontaneous Imbibition. In Selected

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Topics on Improved Oil Recovery (pp. 33-44). Springer, Singapore.

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[25] Honarvar, B., Azdarpour, A., Karimi, M., Rahimi, A., Afkhami Karaei, M., Hamidi, H., Ing, J. and Mohammadian, E., 2017. Experimental Investigation of Interfacial Tension Measurement

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and Oil Recovery by Carbonated Water Injection: A Case Study Using Core Samples from an

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Iranian Carbonate Oil Reservoir. Energy & Fuels, 31(3), pp.2740-2748.

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[26] Mahzari, P., Tsolis, P., Sohrabi, M., Enezi, S., Yousef, A.A. and Eidan, A.A., 2018.

pp.285-296.

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Carbonated water injection under reservoir conditions; in-situ WAG-type EOR. Fuel, 217,

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[27] Lashkarbolooki, M., Riazi, M. and Ayatollahi, S., 2018. Effect of CO2 and crude oil type on

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the dynamic interfacial tension of crude oil/carbonated water at different operational conditions. Journal of Petroleum Science and Engineering, 170, pp. 576-581. [28] Hamouda, A.A. and Bagalkot, N., 2018. Experimental Investigation of Temperature on Interfacial Tension and its Relation to Alterations of Hydrocarbon Properties in a Carbonated Water/Hydrocarbon System. International Journal of Chemical Engineering and Applications, 9(2), pp. 58-63.

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Journal Pre-proof [29] Qi, Z.Y., Wang, Y.F. and Xu, X.L., 2014. Effects of interfacial tension reduction and wettability alteration on oil recovery by surfactant imbibition. In Advanced Materials Research (Vol. 868, pp. 664-668). Trans Tech Publications. [30] Cuiec, L., Bourbiaux, B., Kalaydjian, F., 1994. Oil recovery by imbibition in lowpermeability chalk. SPEFE, 200– 208. SPE-20259-PA. [31] Hirasaki, G. and Zhang, D.L., 2004. Surface chemistry of oil recovery from fractured, oil-

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wet, carbonate formations. Spe Journal, 9(02), pp.151-162. SPE-88365-PA.

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[32] Bi, Z., Zhang, Z., Xu, F., Qian, Y. and Yu, J., 1999. Wettability, oil recovery, and interfacial

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tension with an SDBS–dodecane–kaolin system. Journal of Colloid and Interface Science,

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214(2), pp.368-372.

[33] Bathurst, R.G., Carbonate sediments and their diagenesis. Vol. 12. 1972: Elsevier.

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[34] Sayegh, S.G., Krause, F.F., Girard, M. and DeBree, C., 1990. Rock/fluid interactions of

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carbonated brines in a sandstone reservoir: Pembina Cardium, Alberta, Canada. SPE formation evaluation, 5(04), pp.399-405. SPE-19392-PA.

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[35] Peng, C., Crawshaw, J.P., Maitland, G.C., Trusler, J.M. and Vega-Maza, D., 2013. The pH

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of CO2-saturated water at temperatures between 308K and 423K at pressures up to 15MPa. The Journal of Supercritical Fluids, 82, pp.129-137. [36] Zhang, P., Tweheyo, M.T. and Austad, T., 2007. Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk: Impact of the potential determining ions Ca2+, Mg2+, and SO42−. Colloids and Surfaces A: Physicochemical and Engineering Aspects, 301(1-3), pp.199-208. [37] Nowrouzi, I., Manshad, A.K. and Mohammadi, A.H., 2019. Effects of concentration and size of TiO2 nano-particles on the performance of smart water in wettability alteration and oil

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Journal Pre-proof production under spontaneous imbibition. Journal of Petroleum Science and Engineering, 183, p.106357. [38] Nowrouzi, I., Manshad, A.K. and Mohammadi, A.H., 2020. Effects of Tragacanth Gum as a natural polymeric surfactant and soluble ions on chemical smart water injection into oil reservoirs. Journal of Molecular Structure, 1200, p.127078.

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[39] Nowrouzi, I., Manshad, A.K. and Mohammadi, A.H., 2019. Effects of ions and dissolved

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carbon dioxide in brine on wettability alteration, contact angle and oil production in smart water

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and carbonated smart water injection processes in carbonate oil reservoirs. Fuel, 235, pp.1039-

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[40] Esene, C., Onalo, D., Zendehboudi, S., James, L., Aborig, A. and Butt, S., 2018. Modeling

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investigation of low salinity water injection in sandstones and carbonates: Effect of Na+ and

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SO42−. Fuel, 232, pp.362-373.

[41] Esene, C., Rezaei, N., Aborig, A. and Zendehboudi, S., 2019. Comprehensive review of

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carbonated water injection for enhanced oil recovery. Fuel, 237, pp.1086-1107.

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[42] Nowrouzi, I., Manshad, A.K. and Mohammadi, A.H., 2020. Effects of TiO2, MgO and γAl2O3 nano-particles on wettability alteration and oil production under carbonated nano-fluid imbibition in carbonate oil reservoirs. Fuel, 259, p.116110. [43] Nowrouzi, I., Manshad, A.K. and Mohammadi, A.H., 2019. Effects of TiO2, MgO, and γAl2O3 nano-particles in carbonated water on water-oil interfacial tension (IFT) reduction in chemical enhanced oil recovery (CEOR) process. Journal of Molecular Liquids, 292, p.111348.

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Journal Pre-proof [44] Nowrouzi, I., Manshad, A.K. and Mohammadi, A.H., 2019. Effects of dissolved carbon dioxide and ions in water on the dynamic interfacial tension of water and oil in the process of carbonated smart water injection into oil reservoirs. Fuel, 243, pp.569-578. [45] Nowrouzi, I., Manshad, A.K. and Mohammadi, A.H., 2019. Effects of ions and dissolved carbon dioxide in brine on wettability alteration, contact angle and oil production in smart water and carbonated smart water injection processes in carbonate oil reservoirs. Fuel, 235, pp.1039-

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Journal Pre-proof Table 1: Summary of recent studies on carbonated water injection. authors

material

experiments

parameters

mechanisms

results

2017

Ruidiaz et al. [18]

Amott–Harvey, core-flooding

Rock type, brine concentration and pressure

Wettability alteration

2015

Seyyedi et al. [19]

Contact angle

Rock type and Pressure

Wettability alteration

Oil recovery can be directly associated with wettability alteration and it is dependent on the parameters examined Contact angle dependence to pressure but no specific relationship.

2018

Seyyedi et al. [20]

Crude oil with an API of 28, dolomite and limestone Crude oil with an API of 26.16, Quartz, Mica, and Calcite Crude oil with an API of 20.87,

Micromodel and PVT rigs

Oil composition

CO2 transfer

2017

Seyyedi et al. [21]

Core Flood

Secondary and tertiary recovery factor

CO2 transfer

2016

Manshad et al. [1]

Crude oil with an API of 20.8, seawater, sandstone Crude oil with an API of 31.14, smart water

Pendant drop IFT

IFT reduction

IFT reduction of 4-45 % dependence on pressure, temperature and dissolved ions.

2018

Nowrouzi et al. [2]

Crude oil with an API of 31.14, smart water, carbonate rock

Pendant drop IFT and contact angle

IFT reduction and wettability alteration

Diluted seawater+CO2 can reduce IFT and contact angle more than initial concentration.

2017

Manshad et al. [3]

Crude oil with an API of 31.14, smart water, carbonate rock

Contact angle

Wettability, rock solution

Rock wettability altered to strongly water-wet and it depends on pressure and temperature.

2018

Foroozesh, and Jamiolahmady [22]

n-decane, Sandstone

Coreflood

Brine composition, concentration, pressure, temperature Brine composition, concentration, pressure, temperature Brine composition, concentration, pressure, temperature Rate of injection

CO2 transfer

2016

Riazi and Golkari [6]

Crude oil with an API of 24.46

Pendant drop IFT

Pressure and temperature

IFT reduction

2018

Bakhshi et al. [23]

Coreflood

Wettability condition, salinity and crude oil and rock types

CO2 diffusion and transfer

2018

Adiputra et al. [24]

Imbibition

Soaking time and pressure

CO2-water-rock reactions

0–37% oil recovery.

2017

Honarvar et al. [25]

2types of crude oil with an API of 33.8 and 22.2, sandstone and carbonate Crude oil with an API of 42.25, 2types of sandstone Crude oil with an API of 31.56, carbonate rock

At Equilibrium Number of higher than 0.2, the system can achieve the equilibrium state during CWI. IFT reduction depends on pressure, temperature and time. More effectiveness in secondary mode.

Pendant drop IFT and coreflood

Salinity and composition of brines

IFT

2018

Mahzari et al. [26]

Live-oil, Carbonate rock

Coreflood

Reservoir condition

CO2-water-rock reactions

2018

Lashkarbolooki et al. [7]

Crude oil with an API of 21.5

Pendant drop

Pressure, temperature and

Oil swelling

Maximum oil recovery of 21.75%, 61.63%, and 52.58% was achieved with conventional WF, SCWI, and TCWI, respectively. 26% higher recovery in CWI as a secondary injection than seawater injection. As the pressure increases, the oil swelling rate increases but

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The remaining oil after CO2 injection is heavier than the primary oil, while the remaining oil has a lower viscosity Very high efficiencies occur in both secondary and tertiary CWI.

Journal Pre-proof time Lashkarbolooki et al. [27]

2types of crude oil with API of 20.5 and 35,

Pendant drop IFT

Oil type, Pressure, temperature and time

IFT reduction

2018

Hamouda and Bagalkot [28]

n-decane

Pendant drop IFT

Pressure, temperature and time

IFT reduction

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2018

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there is no clear trend with temperature changes. IFT of crude oil/CW and solubility of CO2 in the aqueous phase as functions of temperature and pressure. The IFT at 35 °C was smaller than at 45 °C, and beyond this pressure, the IFT at 35 °C was bigger than at 45 °C, up to a certain pressure.

Journal Pre-proof Table 2: Seawater analysis. Potassium Sodium Magnesium Calcium Sulfate Chloride Bicarbonate

TDS PH

[ppm]

[ppm]

[ppm]

[ppm]

[ppm]

[ppm]

92.43

7337

936

1920

6892.8

11340

183

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[ppm]

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[ppm] 7.67 33194

Journal Pre-proof Table 3: Crude oil analysis. C6

C7

C8

C9

C10

C11

C12+

Total

9.26

9.35

7.87

8.52

7.23

5.39

44.61

100.00

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Component C1 C2 C3 iC4 nC4 iC5 nC5 Molar 0.00 0.77 2.16 0.76 2.44 0.84 0.80 Percent Molecular weight =232 Molecular weight of C12+ =392 Specific gravity of C12 [email protected] 15.55 °C =0.9669 Saturation pressure of reservoir fluid @ 60.6 °C =18.58 MPa

31

Journal Pre-proof Table 4: Specifications of the used plugs. Por. ±0.2 [%]

Total VP [cm3]

Mass of dry samples±0.0001 [g]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

11.97 10.45 12.97 10.91 13.29 11.62 16.04 10.89 9.81 12.14 15.70 11.58 13.69 11.35 12.76 12.44

13.64 13.32 14.56 12.73 16.91 13.18 15.09 13.25 12.29 14.46 17.01 15.92 14.87 13.65 15.83 14.06

8.55 8.35 9.12 7.98 10.60 8.26 9.46 8.30 7.70 9.06 10.66 9.98 9.32 8.55 9.92 8.81

140.6429 141.5717 139.3796 140.7645 138.2617 141.5598 137.7415 140.1276 138.1369 137.9473 135.2591 136.5718 138.2937 140.6346 139.8402 137.5392

Mass of oilsaturated plugs±0.0001 [g] 145.8608 146.5127 144.9869 145.3854 145.1497 146.6739 143.6863 145.1725 -

Soi [%]

OOIP [cm3]

Imbibition fluid, P[psi]

70.53 68.38 7105 66.92 75.09 71.55 72.62 70.24 -

6.03 5.71 6.48 5.34 7.96 5.91 6.87 5.83 -

LSCW, 500 LSCW, 1000 LSCW, 1500 LSCW, 2000 HSCW, 500 HSCW, 1000 HSCW, 1500 HSCW, 2000 LSCW, 500 LSCW, 1000 LSCW, 1500 LSCW, 2000 HSCW, 500 HSCW, 1000 HSCW, 1500 HSCW, 2000

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Perm. ±0.5 [md]

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Plug No.

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The length of all plugs is 5.5cm and the initial water saturation is zero.

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Initial 12.29 14.46 17.01 15.92 14.87 13.65 15.83 14.06

Porosity ± 0.2 [%] Step2 Step3 12.93 13.20 15.52 15.85 18.54 18.92 17.87 18.58 15.57 15.77 14.39 14.84 17.04 17.53 15.40 16.22

Step1 12.86 15.43 18.21 17.46 15.45 14.31 16.76 14.94

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Pressure [psi] 500 1000 1500 2000 500 1000 1500 2000

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High salinity

Low salinity

Table 5: Porosity variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

33

Step4 13.65 16.22 19.51 18.82 16.04 15.10 17.78 16.45

Step5 13.76 16.61 19.79 19.02 16.12 15.24 17.91 16.50

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Initial 9.381 12.14 15.70 11.58 13.69 11.35 12.76 12.44

Permeability ± 0.5 [md] Step2 Step3 10.22 10.52 12.85 13.21 16.95 17.31 13.02 13.34 14.16 14.46 11.81 12.27 13.62 14.17 13.46 13.99

Step1 10.19 12.70 16.81 12.72 14.03 11.78 13.46 13.27

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Pressure [psi] 500 1000 1500 2000 500 1000 1500 2000

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Low salinity

Table 6: Permeability variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Step4 10.61 13.56 17.75 13.81 14.68 12.47 14.34 14.27

Step5 10.98 13.81 18.23 14.03 14.80 12.51 14.48 14.42

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Initial 138.1369 137.9473 135.2591 136.5718 138.2937 140.6346 139.8402 137.5392

Mass ± 0.0001 [g] Step2 Step3 137.0971 135.7615 135.2127 134.8117 132.3670 131.5166 133.3403 131.4151 136.8365 136.2442 138.8205 138.4219 137.5611 137.0718 134.9780 134.5801

Step1 136.8926 136.0324 133.0018 133.6094 137.2025 139.2770 137.9490 135.5848

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Pressure [psi] 500 1000 1500 2000 500 1000 1500 2000

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Low salinity

Table 7: Rock weight variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Step4 135.3939 134.1302 130.9342 131.0086 136.1402 137.9829 136.6713 133.9875

Step5 134.9212 133.7511 130.3054 130.4954 136.0341 137.9211 136.2485 133.5072

Journal Pre-proof

Step1 1030 1450 1920 2340 950 1350 1620 1890

ΔC=C2-C1 [ppm] Step3 Step4 540 360 950 640 1320 1130 1810 1550 470 310 760 410 1020 870 1300 1010

Step2 850 1210 1640 2110 630 1190 1330 1550

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Pressure [psi] 500 1000 1500 2000 500 1000 1500 2000

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Low salinity

Table 8: Calcium ion variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Step5 170 480 790 1070 110 230 580 820

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Step1 2440 2650 2910 3150 1120 1420 1810 2100

ΔC=C2-C1 [ppm] Step3 Step4 1530 650 1670 780 1940 640 2380 1870 670 520 890 630 1070 850 1150 970

Step2 2290 2310 2520 2810 950 1050 1220 1840

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Pressure [psi] 500 1000 1500 2000 500 1000 1500 2000

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Low salinity

Table 9: Magnesium ion variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Step5 240 470 630 940 210 330 460 680

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Step1 1300 2130 2650 3140 660 940 1150 1910

ΔC=C2-C1 [ppm] Step3 Step4 860 510 1420 940 1820 1370 2060 1610 310 220 540 430 830 530 1190 850

Step2 1020 1770 2130 2620 520 760 950 1620

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Pressure [psi] 500 1000 1500 2000 500 1000 1500 2000

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Low salinity

Table 10: Bicarbonate ion variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Step5 310 440 820 1090 150 270 410 590

Journal Pre-proof Table 11: Contact angle values in high and low salinity carbonated water after three days at 75 °C and various pressures. Sea-water 1000 1500 58.06 50.41

20-times diluted sea-water 500 1000 1500 2000 47.52 41.86 33.07 24.16

2000 43.90

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Brine Pressure [psi] CA [degree]

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Figure 1: XRD and SEM analyzes of the used carbonate rock.

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Figure 2. High-pressure and high-temperature imbibition cell.

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Figure 3: Schematic of the carbonated water supply system required for imbibition experiments.

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Figure 4: The schematic of contact angle measurement device. 1: aqueous solution pump, 2: droplet fluid pump, 3: light source, 4: rock thin section, 5: hollow cell, 6: metallic needle, 7: HDD camera, 8: computer with related software, 9: high-pressure steel line.

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Figure 5: Flowchart of the experimental procedure.

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Figure 6: Oil recovery values in high and low salinity carbonated water imbibition process at 75 °C and various pressures.

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Figure 7: The curves of porosity variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Figure 8: The curves of permeability variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Figure 9: The curves of rock weight variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Figure 10: Calcium ion variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Figure 11: Magnesium ion variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Figure 12: Bicarbonate ion variations in high and low salinity carbonated water imbibition at 75 °C and various pressures.

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Figure 13: The curves of contact angle values resulting from the drop of oil on the cross-section of aged rock in high and low salinity carbonated water after three days at 75 °C and various pressures.

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Authors’ contribution: Iman Nowrouzi: Research student Amir H Mohammadi: Supervisor

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Abbas Khaksar: Co-Supervisor

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The authors state that there is no conflict of interest

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Journal Pre-proof Graphical abstract 3500 low-salinity,500psi

3000

low-salinity,1000psi 2500 2000

low-salinity,2000psi

1500

high-salinity,500psi high-salinity,1000psi

500 0 3 Time Intervals

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Highlights 

Variations of porosity, permeability, rock mass and wettability during carbonated water discharge were measured.



The experiments were performed based on direct measurements of porosity, permeability, rock weight and contact angle. Changes in the concentration of calcium, magnesium and bicarbonate ions were

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The results show the dependence of changes in rock parameters on the pressure and

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salinity of the base fluid.

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Porosity variations, permeability and, most importantly, wettability of the rock are found

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