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Article

Experimental and Numerical Evaluation of CO2-Induced Wettability Alteration in Carbonate Reservoir CCUS

Petroleum Department, Colorado School of Mines, Golden, CO 80401, USA
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Author to whom correspondence should be addressed.
Energies 2025, 18(20), 5529; https://doi.org/10.3390/en18205529
Submission received: 31 August 2025 / Revised: 5 October 2025 / Accepted: 8 October 2025 / Published: 20 October 2025

Abstract

This study presents both laboratory measurements and numerical modeling of wettability alterations following carbon dioxide (CO2) injection in limestone carbonate reservoirs. Both synthetic and crude oil systems were evaluated using a Drop Shape Analyzer (DSA-100) to quantitatively measure the contact angle and interfacial tension (IFT) on limestone core samples under ambient and reservoir conditions. The results demonstrated that carbonated brine significantly reduced the IFT (2.0–4.1 dynes/cm) and contact angle (11.9–16.0°), indicating a shift toward more water-wet conditions, compared with the modest reductions in contact angle achieved with standard brine (1.6–6.7°). Synthetic fluid systems containing naphthenic acid initially exhibited stronger oil-wet behavior but also experienced wettability alterations when exposed to CO2. A previously developed compositional reservoir simulation model, which was based on assumed relative permeability endpoints, was revised to incorporate the experimental findings of this study as a supporting tool. Incorporating the experimental wettability alteration effect of CO2 in the numerical model by a 5.2% reduction in the residual oil saturation (the relative permeability endpoint) caused 2% increase in the oil recovery factor and 12% improvement in the CO2 utilization efficiency (9780 standard cubic feet per stock tank barrel (SCF/STB) vs. 8620 SCF/STB). Overall, this work provides critical laboratory validation and supports by numerical simulation that CO2-induced wettability alteration is a key mechanism underpinning CO2-based enhanced oil recovery (EOR) and carbon capture, utilization, and storage (CCUS) deployment in limestone carbonate formations.

1. Introduction

1.1. Background

A substantial fraction of global hydrocarbon reserves reside in carbonate reservoirs, which are characterized by reduced porosity, natural fractures, and mixed wettability [1]. CO2 injection has been an accepted method for increasing oil recovery in carbonate reservoirs in the U.S. since the 1980s [2]. Miscible CO2 flooding improves oil recovery through CO2 injection at or above the minimum miscibility pressure (MMP). The dissolution of CO2 in the reservoir oil reduces the flow resistance by volume expansion and a reduction in viscosity [3]. The CO2’s miscibility with oil also reduces the interfacial tension, which results in an enhancement of the mobility of the oil [4].
CO2 interacts with limestone carbonate through its calcite, dolomite, and anhydrite minerals [5]. This interaction may alter the permeability, porosity, pore structure, and fluid composition [6]. CO2 injection also causes chemical alteration of the properties of carbonate rock, which is escalated by variations in pressure and temperature [7].

1.2. Wettability Alteration

Upon the injection of CO2, reactions with the minerals in the carbonate rock occur, potentially leading to precipitation and the formation of mineral scales and subsequently modifying the reservoir rock’s properties. As noted by Rosenbauer et al. [8], the initial interaction causes the dissolution of CO2, which results in the formation of carbonic acid, and additional reactions between the carbonic acid and brine generate bicarbonates. Bicarbonate ions interact with divalent cations (calcium, magnesium, and ferrous iron ions), leading to the precipitation of carbonate minerals [9].
Wettability is the tendency of a fluid to adhere to a solid surface in the presence of another immiscible fluid. The immiscible fluid with the stronger (preferential) adhesion to the surface is the wetting phase [10]. Wettability is measured by the contact angle that is obtained at the interface between a solid surface and a fluid [11]. For instance, if an oil droplet on a rock surface that is submerged in brine exhibits a contact angle of less than 30°, this indicates strong water-wet conditions for the rock, whereas angles ranging from 30° to 90° imply preferential water-wet conditions. An angle of 90° is considered neutral. Angles between 90° and 150° signify a favoring of oil-wetness, while angles from 150° to 180° suggest strong oil-wet conditions [12]. Carbonate reservoirs tend to have heterogeneous, non-uniform wettability that can be referred to as fractional wettability [13]. Fractional wettability is a product of variation in the rock’s chemical composition in pores, which leads to the spatial distribution of wettability [10]. Mixed wettability is a specific type of fractional wettability where oil-wet surfaces provide continuous pathways via larger pores, while smaller pores maintain water-wet conditions. Additionally, when the rock exhibits no significant preference for either oil or water, the system is classified as having neutral (or moderate) wettability [13].
Wettability is affected by brine, oil composition, mineralogy, saturation history, temperature, and pressure. The wettability of carbonates often varies from moderate to mostly oil wet. Carbonates are positively charged due to the presence of Ca2+ in their formation brine. The carboxylic acid in crude oil is negatively charged and adsorbs onto the positively charged carbonate surface, creating an oil-wet system [14]. As a result, oil is trapped in the matrix due to negative capillary forces. When CO2 is injected, the interaction with brine forms carbonic acid (H2CO3). The dissociation of carbonic acid into bicarbonate and hydrogen ions leads to a pH reduction, while the interaction of bicarbonate ions with the carbonate surface results in mineral dissolution (Figure 1).
Capillary trapping is directly related to the capillary pressure and relative permeability characteristics of the reservoir. The capillary pressure is a function of the interfacial tension (IFT) and wettability, as determined by contact angle measurements [15]. The interfacial tension is affected by the temperature and pressure in systems comprising CO2, brine, and crude oil. The increase in both temperature and pressure results in a decrease in interfacial tension, driven by the enhanced solubility of CO2 in brine, thus improving the miscibility of CO2 with oil [16,17].
Studies were performed [18] to examine the impact of CO2 flooding on the wettability of dolomite cores from West Texas. The cores exhibited three wettability states—intermediate oil-wet, intermediate, and intermediate water-wet—and differences in their relative permeability were examined following CO2 flooding to assess the wettability of the rock. The results indicated that the cores displayed a more water-wet condition, suggesting that minerals were extracted from the rock surface as a result of CO2 flooding.
An experiment was conducted by Jackson et al. [19] to understand the effect of CO2 flooding on rock wettability. The results demonstrated that wettability is a critical element influencing the efficiency of flooding. Under water-wet conditions, gravitational forces controlled flooding, but under oil-wet conditions, flooding was dictated by viscous (fingering) forces. Optimal recovery was achieved through gravitational forces combined with continuous CO2 intake. In another laboratory study [20], potential alterations in wettability in tight limestone cores were investigated in terms of the changes in relative permeability during CO2 flooding. The results demonstrated that CO2 flooding made the limestone cores more water-wet, which is favorable for EOR performance.
IFT is a result of the forces acting on the interface between two immiscible phases. It is defined as the force at the boundary of a specific phase that preserves its cohesiveness. In a system comprising CO2, brine, and crude oil, the IFT is affected by both temperature and pressure. An increase in temperature decreases the IFT by enhancing the solubility of CO2 in brine, thereby disrupting the interface between the phases. Such an effect will enhance CO2′s miscibility, specifically under reservoir conditions [16]. At increased temperatures, CO2 lowers the IFT efficiently, resulting in a mobility enhancement and oil recovery improvement. As the pressure increases, the solubility of CO2 in brine increases, leading to a further reduction in IFT [17]. Such behavior is more relevant when the condition of CO2 is supercritical.
The IFT is determined by solving the nonlinear Young–Laplace equation. This equation expresses the differential pressure between gravity and surface tension on a curved interface. The pendant drop method involves solving the Young–Laplace equation numerically to determine the interfacial tension from the shape of a static droplet within a gravitational field [21]. Further studies on numerically determining the IFT are presented in [22].

1.3. Objective of Study

The objectives of this study are to experimentally investigate the impact of CO2 injection on wettability alteration in carbonate reservoirs and assess its implications for CO2-WAG (Water-Alternating-Gas) and carbon capture, utilization, and storage (CCUS) design. An experimental study was conducted using both synthetic- and crude-oil systems under reservoir conditions. The primary objective was to validate the assumption that CO2 exposure alters wettability through the IFT and contact angle changes. To demonstrate the implications for enhanced oil recovery (EOR) and CO2 utilization, the experimentally derived wettability parameters were incorporated into a previously developed numerical reservoir simulation model [23].
The novelty of this work lies in experimentally quantifying CO2-induced wettability alterations in carbonate cores under reservoir conditions, across both synthetic- and crude-oil systems, and embedding these findings into a reservoir simulation workflow. This approach provides a quantified benchmark for residual oil saturation (oil relative permeability endpoint), recovery factor, and CO2 utilization efficiency that can directly guide CCUS and CO2-WAG design in carbonate formations.

2. Materials and Methods

This section will outline the experimental procedure for evaluating the wettability-altering effects of CO2-enriched brine in carbonate reservoirs. A series of laboratory tests were performed to measure the contact angle and IFT using a Drop Shape Analyzer (DSA-100, manufactured by KRÜSS GmbH, Hamburg, Germany) [24] under ambient and reservoir conditions. Measurements were carried out on Indiana Limestone core disks that were aged in various hydrocarbon fluid systems, including synthetic fluid and crude oil.

2.1. Core Preparation

We used the XRD estimated mineralogy of Indiana Limestone reported in the literature [25]. Indiana Limestone is a clean limestone. The initial porosity and permeability of the samples were measured using the Core Measurement System (CMS-300, manufactured by Core Lab, Houston, TX, USA). The permeability and porosity ranges are shown in Table 1. The measurement procedure was as follows:
  • A 12-inch core was divided into several 2-inch core plugs for the measurement of porosity and permeability utilizing the Core Measurement System (CMS-300).
  • The core plugs were dried in an oven at 240 °F for 24 h.
  • After drying, each core plug’s diameter and length were measured with a digital caliper, and the bulk volume and grain density were recorded by weighing.
  • The CMS-300 system was used to determine the porosity and gas permeability through helium expansion and gas flow techniques. The operational procedure was as follows:
    • Verification of gas supply, followed by opening the nitrogen valve and then the helium valve.
    • Execution of a helium leak test.
    • Input of the core sample dimensions and confining pressure of 1500 psia into the software and the insertion of core sample into the measurement holder.
    • Calibration to determine the pore volume, porosity, and permeability.
This workflow promoted precise and consistent measurement of the core properties in a controlled laboratory environment. Table 1 shows the porosity and permeability measurements of the core samples. The results range from 19.3 to 23.6 millidarcies for permeability and from 14.76 to 15.92% for porosity.
Prior to the experiment, all core disks underwent a standardized aging procedure to replicate reservoir exposure conditions. The steps were as follows:
  • The core disks were first trimmed to 1.5 inches in diameter and 0.5 inches in length to fit in the Drop Shape Analyzer (DSA-100).
  • The disks underwent Soxhlet extraction, initially with toluene for 24 h to eliminate organic contaminants, followed by methanol for another 24 h to remove residual water and reduce potential clay swelling.
  • After cleaning, the samples were vacuum-dried for 24 h to eliminate any trapped air.
  • The disks were centrifuged at 3000 rpm for 24 h while immersed in brine to achieve full brine saturation.
  • The core disks were centrifuged at 3000 rpm for 24 h while fully immersed in each hydrocarbon fluid systems. Disks from all core samples were distributed among the fluid systems to maintain consistency and reduce sample bias.
  • The core disks were left in the oven for 6 weeks at 240 °F to complete the aging process.

2.2. Fluid System Compositions

This section describes the fluid systems used in the experiment. Phase envelope calculations were conducted to verify that the chosen pressure and temperature for the study (240 °F and 5000 psia) were within the single-phase, miscible region required for miscible CO2 injection scenarios for each CO2–oil system.
Four fluid systems with distinct viscosities were selected to evaluate the effect of fluid viscosity on wettability and interfacial behavior. Systems studied in this experiment included synthetic hydrocarbon fluids (with and without naphthenic acid) and crude oil samples diluted with 10% and 50% n-pentane. We aimed to examine the impact of the IFT and contact angle in the presence of brine and carbonated brine. The measured viscosities are shown in Table 2.
The synthetic-fluid system was formulated to replicate the composition of a light-oil reservoir fluid. Two variations were prepared: one without naphthenic acid, and another containing naphthenic acid. This approach was chosen to investigate the influence of acidic components on wettability in comparison to a system without acidic components. In the preparation of the acidic synthetic-fluid system, 0.2 mol% of n-pentane (n-C5) was removed from the mixture and substituted by 0.2 mol% naphthenic acid. The detailed chemical compositions of both fluid systems (with and without naphthenic acid) are presented in Table 3.
Figure 2 illustrates the effect of CO2 on the phase envelope of the synthetic-fluid system without naphthenic acid. The introduction of CO2 caused a noticeable expansion and shift in the phase envelope. Comparable behavior was noted in the system containing naphthenic acid.
Figure 3 illustrates the effect of CO2 on the phase envelopes of the crude oil systems. The phase envelopes of the crude oil systems diluted with 10% and 50% n-pentane are shown, respectively, in Figure 3a,b. The introduction of CO2 resulted in an expansion and shift in the phase envelope in both systems, demonstrating enhanced miscibility under the specified test conditions.

2.3. Experimental Design and Setup

The Drop Shape Analyzer (DSA-100) shown in Figure 4 was used to measure both the contact angle and IFT. The range of contact angle measurements was 1 to 180 degrees, with an accuracy of 0.1 degrees. The measurement range of the IFT was 0.01 to 1000 dynes/cm, with an accuracy of 0.01 dynes/cm. The pendant drop method was employed to measure the IFT, while the captive droplet method was utilized for contact angle measurements. A droplet of the fluid system was distributed in the surrounding phase for IFT measurements. For contact angle measurements, a droplet was placed on a core disk of Indiana Limestone. The experiment can be summarized as follows:
  • Viscosity measurement: The viscosities of the four fluid systems were measured at ambient conditions using a rotational viscometer (Section 2.2). The results are presented in Table 2 (Section 2.2).
  • pH Measurement: The surrounding brine phase’s pH was measured using the colorimetric method with pH indicator paper:
    -
    The pH of the surrounding brine phase (50,000 ppm salinity with sodium chloride) was 7.6.
    -
    The pH of the surrounding carbonated brine phase (50,000 ppm salinity with sodium chloride) was 4.5.
  • Preparation of carbonated brine: The carbonated brine was prepared by mixing the brine with CO2 gas (supplied from a pressurized tank). The carbonation process was carried out immediately prior to each experimental measurement to ensure proper, consistent, and reliable measurements at ambient temperature. The carbonated brine was then immediately transferred to an isolated storage tank that was connected to the experimental chamber.
  • Rock characterization: The porosity and permeability of the Indiana Limestone core disks were measured using the Core Measurement System (CMS-300); the details are provided in Table 1 (Section 2.1).
  • Core aging: The core disks were aged in contact with each fluid system for six weeks at 240 °F in sealed containers to simulate long-term exposure under reservoir conditions (see Section 2.1 for details).
  • IFT measurements: The IFT was measured using the pendant drop method for each of the four fluid systems while in contact with both brine and carbonated brine under both ambient and reservoir conditions.
  • Contact angle measurements: Fluid-system droplets were placed on a core disk surrounded by the designated surrounding phase, and the contact angle was measured using the captive droplet method under both ambient and reservoir conditions.

2.4. Experimental Measurement Procedures

The DSA-100 system measures contact angles by analyzing a sessile droplet positioned on a solid surface. The instrument utilizes the Young–Laplace equation to fit the droplet profile. The contact angle (θ) is the angle created between the tangent to the droplet at the contact point of the fluids and the solid surface. The drop shape fitting algorithm employed by the DSA-100 adjusts surface tension, gravitational influences, and droplet volume, thereby ensuring precise measurements even for larger or non-ideal droplet geometries. The captive droplet method is visualized in Figure 5.
IFT was determined using the pendant drop method with the DSA-100 system. The system captures a high-resolution image of a droplet that is suspended in a surrounding fluid and applies a numerical fit of the droplet profile by the Young–Laplace equation. Figure 6 provides a visual of the IFT measurement. The DSA-100 software identifies the drop shape and calculates the IFT.

2.5. Repeatability and Quality Control

Replications were conducted for both the IFT and contact angle measurements to ensure the reliability and repeatability of our data. Each fluid system was tested under both ambient and reservoir conditions, with replicates (n) varying from 2 to 5 per case. Variation in the number of replicates was due to the complexity of the systems and the stability issues caused mainly by the pressure maintenance procedures. For each set of replicates, the mean, standard deviation (SD), and coefficient of variation (CV) were calculated to evaluate the consistency of the measurements.
Under all measurement conditions, CV values consistently stayed below 5%, indicating a significant level of experimental consistency. The low coefficients of variation confirm the reliability of the experimental setup and validate the repeatability of both the contact angle and IFT measurements. (The DSA-100 has a precision of ±0.1° for contact angle measurements and ±0.01 dynes/cm for IFT, thereby reinforcing the reliability of the data obtained.)
A stabilization period of no less than one hour was implemented prior to conducting measurements under reservoir conditions to ensure experimental integrity. During this period, the temperature, pressure, and droplet geometry were monitored to ensure equilibrium. Measurements were rejected and repeated with a different core disk if an internal valve limitation resulted in pressure fluctuations or a sudden pressure drop. These quality control criteria ensured that only fully stabilized and consistent data were accepted for analysis.

3. Results

The experimental results are presented in this section. Section 3.1 summarizes the measured data and provides visualizations, while additional images for each case, obtained using the DSA-100 system, are presented in Appendix A. Section 3.2 briefly introduces a numerical model of CO2 injection into a light-oil, carbonate reservoir, which was developed in a previous study [23]. In Section 3.3, the experimental measurements of this study are transferred into the numerical model by shifting the endpoints (residual fluid saturations) of the relative permeability curves. A shift in residual oil saturations is critical for oil mobilization and demonstrates the wettability alteration effect of CO2. The results are compared with those where the effect of CO2 to alter wettability alteration (the shift in relative permeability endpoints) is not taken into consideration. For both cases, the curvature of the relative permeability curves remained the same but the endpoints were modified. The comparisons of the results are used to quantify the improvements in the EOR and CCUS efficiency of CO2 injection caused by the increased water-wetness of the carbonate reservoir.

3.1. Visualization of Results

IFT measurements of all fluid systems are shown in Table 4. The measurements are presented in terms of the mean ± SD, CV, and n, demonstrating the consistency and reliability of the measurements. Appendix A provides representative images of IFT measurements that have been captured during the experiments. It can be clearly observed that there is a reduction in IFT in all fluid systems under reservoir conditions in comparison to ambient conditions. This is because the increased temperature and pressure causes enhanced interaction between fluids. For the synthetic fluid with naphthenic acid surrounded by brine, an IFT reduction of 3.32 dynes/cm was observed. On the other hand, crude oil diluted with 50% n-pentane and surrounded by brine showed a moderate reduction of 1.35 dynes/cm.
Figure 7 illustrates the IFT values for all fluid systems under reservoir conditions, contrasting brine (blue bars) with carbonated brine (red bars) as the surrounding phase. In each system, the black error bars indicate the SD from replicate measurements. Across all fluid types, carbonated brine consistently exhibits lower IFT values than the surrounding brine phase. This confirms the enhanced capacity of CO2-enriched brine to reduce interfacial tension at the oil–water interface. The narrow error bars (SD) reflect good experimental repeatability. The interface boundary between the two fluids has been disrupted, and thus, a reduction in IFT is observed. This outcome is a result of increased pressure and temperature (to represent the reservoir conditions). These trends validate the role of carbonated brine in improving oil’s mobility by lowering the IFT under reservoir conditions, which is advantageous for EOR. Further interpretation of these trends and their implications for EOR and CCUS will be provided in the Discussion.
Table 5 presents a summary of the contact angle measurements for all fluid systems under both ambient and reservoir conditions. The mean ± SD, CV, and n in Table 5 indicate the consistency and reliability of the measurements. Appendix A provides representative images of contact angle measurements that were captured during the experiments. Under ambient conditions, the synthetic fluid with naphthenic acid demonstrated a higher contact angle than the system without naphthenic acid, suggesting a more oil-wet condition. For instance, under ambient conditions, the contact angle of synthetic fluid with naphthenic acid was 75.6 ± 0.20° in brine and 78.9 ± 2.4° in carbonated brine, in comparison to 58.6 ± 0.77° in brine and 66.8 ± 2.61° in carbonated brine for synthetic fluid without naphthenic acid. The addition of naphthenic acid parallels the polarity of the carboxylic groups that are frequently present in crude oil. Under the initial conditions prior to CO2 interactions, the acid–base interactions of positively charged carbonate cause attachment of oil components on the rock surface, thus resulting in a more oil-wet condition [14]. In addition, the synthetic fluid with naphthenic acid demonstrated a larger reduction in the contact angle than that in the system without naphthenic acid surrounded by a carbonated brine phase. When CO2 is introduced, the interaction with brine forms carbonic acid and eventually bicarbonate, which reduces the pH. These reactions cause further chemical interactions with the carbonate surface, resulting in mineral dissolution that detaches the oil component and leading to more water-wet conditions [9].
Under reservoir conditions, all fluid systems showed a reduction in contact angle, indicating a wettability alteration toward more water-wet conditions. All fluid systems with carbonated brine as a surrounding phase had a greater contact angle reduction than those with brine, indicating a stronger shift toward water-wet conditions. A reduction in contact angle indicates a larger shift toward water-wet conditions, which is related to lower capillary forces acting on the interface. The synthetic fluid containing naphthenic acid and surrounded by carbonated brine exhibited a contact angle reduction of 16.0°, whereas that surrounded by brine exhibited a reduction of only 6.7°. A similar trend was observed in the system without naphthenic acid, where the contact angle in carbonated brine decreased by 12.8°. This underscores the role of CO2 dissolution in shifting wettability towards more water-wet conditions, particularly in the presence of naphthenic acid.
Between synthetic fluids and crude-oil systems, the crude oil had markedly more oil-wet behavior initially, as indicated by the larger contact angles under ambient conditions. Crude oil diluted with 10% n-pentane had an initial contact angle of 168.1 ± 1.35° in brine, while the initial contact angle of the equivalent synthetic-fluid system without acid was 58.6 ± 0.77°. Despite this initial condition, carbonated brine still induced substantial wettability shifts in the crude oil systems. For example, the contact angle of crude oil diluted with 50% n-pentane decreased by 12.2° in carbonated brine compared with only 3.6° in brine. Similarly, the contact angle of the crude oil with 10% n-pentane was reduced by 12.7° in carbonated brine and 3.9° in brine.
Figure 8 illustrates the contact angle measurements for all tested fluid systems under ambient and reservoir conditions. Each line represents the change in contact angle, with solid lines denoting brine systems and dashed lines denoting carbonated brine systems. Representative contact-angle images are provided in Appendix A. For carbonated brine as the surrounding phase (dashed lines), a greater decline in contact angle between ambient and reservoir conditions can be observed for all fluid systems in comparison to that for brine as the surrounding phase (solid lines). This indicates that carbonated brine consistently provides greater contact angle reductions toward more water-wet conditions, regardless of the fluid type. On the other hand, the solid lines representing the brine surrounding phase were relatively flat in all fluid system, indicating a limited change in wettability in comparison to that for the carbonated brine surrounding phase.
Figure 9 shows the relationship between the interfacial tension and contact angle measurements using the experimental results under reservoir conditions. Carbonated brine systems exhibited both lower IFT and contact angles for all fluid systems, indicating a greater alteration in wettability in comparison to brine systems.

3.2. Numerical Model: Purpose of Experimental Validation

This section briefly introduces a previously developed numerical model [23], which will be used here to demonstrate the impact of wettability alterations on the EOR and CCUS performance of CO2 injection. This is a compositional model employing a single, five-spot pattern to simulate an EOR and CCUS application in a limestone reservoir, for which the Indiana Limestone used in the experiments is a good analog. The relative permeability relations used in the original model [23] are shown by the black lines in Figure 10 and correspond to a mixed-wet system with 30% residual-oil and irreducible-water saturations. The red lines are intended to illustrate the wettability alteration effect of CO2 by reducing the endpoint when the saturation exceeds 50%. The remaining oil saturation was assumed to decrease from an initial value of 30% to 25% under the influence of CO2.
The following section outlines the methodology for incorporating experimental measurements into the modification of relative permeability endpoints. Endpoints of the relative permeability were only adjusted to reflect the CO2-induced wettability alteration, while the shapes of the relative-permeability curves were retained from the base case. (A complete determination of relative permeability relations would require core flooding experiments, which were not in the scope of the present work.)

3.3. Transfering Experimental Results to Numerical Simulation

The effect of IFT on relative permeability was investigated by Amaefule and Handy [27] by cores during flooding experiments, and the following correlation was developed between the residual oil saturation and the shift in the relative permeability end points:
S o r ( σ ) S o r ( σ o ) = f σ σ o = f N c o N c
In Equation (1), σ is the newly estimated IFT,   σ o is the reference IFT, N c o is the reference capillary number, and N c is the newly estimated capillary number. S o r ( σ ) is the estimated S o r at the new IFT, and S o r ( σ o ) is the S o r at the reference IFT.
The capillary number N c is defined by
N c = υ w μ w ϕ σ o w
where υ w , μ w , and ϕ are the velocity (ft/day), viscosity (cp), and porosity (fraction) of the water, respectively, and σ o w represents the IFT between the oil and water ( d y n e s / c m ). N c plays an important role in residual oil saturation calculations based on the following relations:
S o r ( σ ) =   S o r ( σ o )       N c < N c o
S o r ( σ ) = S o r ( σ o ) N c o N c 0.5213               N c   N c o
Similarly, for the residual water saturation,
S w r ( σ ) = S w r ( σ o )       N c < N c w o
S w r ( σ ) = S w r ( σ o ) N c w o N c 0.1534               N c   N c w o
In Equations (5) and (6), S w r ( σ ) is the estimated S w r at the new IFT and S w r ( σ o ) is the S w r at the reference IFT.
It was assumed that σ corresponded to the case with carbonated brine as the surrounded phase, while σ o corresponded to brine as the surrounding phase. The capillary number was calculated based on the assumptions in Table 6, and the experimental IFT results for crude oil with 50% n-pentane were incorporated into the correlation. This allowed us to predict the residual oil saturation and irreducible oil saturation endpoints for carbonated brine based on the above correlation.
Table 7 shows the relative permeability endpoint shifts, calculated from the correlation by using the experimental results reported in this study. It is shown that wettability alteration caused by CO2 creates a reduction of 5.2% in the S o r endpoint and 1.6% in the S w r endpoint. The relative permeabilities when re-plotted based on these endpoints are shown in Figure 11. The relative permeabilities in Figure 11 display the expected behavior based on the demonstrated effect of the endpoint shift in Figure 10 (Section 3.1).
A simulation was performed to assess the effect of the relative permeability endpoint shift on the gross utilization ratio (GUR) and recovery factor (RF) of WAG-CO2. The GUR and RF are defined, respectively, by
G U R = C O 2   ( i n j e c t e d   M S C F ) I n c r e m e n t a l   o i l   ( p r o d u c e d   S T B )
R F = 100 × I n c r e m e n t a l   o i l   ( p r o d u c e d   S T B ) O r i g i n a l   o i l   i n   p l a c e   ( S T B )
Figure 12a shows the GUR estimates with and without including a permeability endpoint shift in the simulations. The recovery factors RFs of the cases with and without the relative permeability shift are shown by the black and red lines, respectively in Figure 12b. In Figure 12a, the GUR for the case with no relative permeability shift is higher than that with a shift (9780 SCF/STB vs. 8620 SCF/STB). This means that a higher CO2 usage efficiency (higher GUR by 12%) is estimated if the wettability alteration effect of CO2 is not considered (no adjustment of the relative permeability endpoints). From an EOR perspective, the 2% RF increase shown in Figure 12b occurs because wettability alteration reduces the residual oil saturation and increases the amount of recoverable hydrocarbons.

4. Discussion

The experimental results presented in this work clearly demonstrate that CO2-enriched brine induces significant wettability alterations in core disks of limestone, reflected by notable reductions in both IFT and the contact angle across all tested fluid types (synthetic- and crude-oil systems with and without naphthenic acid).
The observed reduction in IFT for carbonated brine (Figure 7) plays a major role in improving the microscopic displacement efficiency by promoting wettability alterations toward more water-wet conditions. A reduction in the IFT indicates a weaker interface between the surrounding phase (carbonated brine) and oil, leading to more miscible conditions, which is more favorable for displacement of oil [4,5]. This trend is consistent with the experimental findings [15], which demonstrated a progressive decline in IFT as the CO2 pressure increased beyond 5 MPa, confirming that the dissolution of CO2 in brine can significantly lower the IFT and potentially modify wettability under reservoir conditions.
The correlation between IFT reduction and S o r , presented in Equations (1)–(6), is also consistent with the experimental findings [27], which indicate that endpoint residual saturations demonstrate strong linear relationships with the logarithm of Nc. This relationship suggests that lower IFT values improve oil displacement through a change in wettability.
Our contact angle measurements validated the mechanism of wettability alteration, demonstrating that exposure to carbonated brine led to markedly reduced contact angles, especially under reservoir conditions. This facilitates a shift from mixed-wet to predominantly water-wet conditions, leading to enhanced oil mobilization and decreased S o r . Morrow [28] highlighted that alterations in wettability, as indicated by the changes in the IFT and contact angle, play a crucial role in influencing the capillary pressure, film stability, and, consequently, oil recovery. Increased water-wetness, characterized by lower contact angles, generally enhances the displacement efficiency, particularly in carbonate reservoirs, where wettability often varies spatially.
The strong initial oil-wet behavior of the synthetic-oil system with naphthenic acid, compared with that without naphthenic acid, is attributed to the polarity of the acidic components, which is analogous to the polarity of the carboxylic groups that are often present in crude oil [14]. These functional groups have demonstrated a tendency to adsorb onto carbonate surfaces, enhancing oil-wetness via acid–base interactions. Buckley [28] demonstrated that such interactions are dominant in carbonate reservoirs, particularly when the oil phase has a high acid number and low base number. This observation was also verified in this study by the higher contact angles recorded in the fluid system with naphthenic acid.
Buckley [29] also noted that acidic oils tend to have initial oil-wet conditions, while having considerable potential for wettability alteration. This is confirmed with our findings that carbonation caused a more significant decrease in contact angles in the systems with naphthenic acid, suggesting a greater transition toward water-wetness in CO2-enriched environments.
From an EOR efficiency perspective, this study has demonstrated that the CO2 GUR is lowered and the RF is increased due to the favorable wettability conditions created by carbonated brine. Lower S o r was consistently linked to decreased IFT and increased water-wetness, resulting in more efficient oil displacement per unit volume of CO2 injected. This is consistent with the findings that CO2 dissolution in brine significantly reduces the IFT [15], and there is a strong correlation between S o r and Nc [23].
In the laboratory study presented in this paper, the impact of CO2 injection on the interfacial tension and contact angle was evaluated over a short experimental period. However, this effect will be present for a long time in field applications due to the presence of CO2 in water and their interaction, which yields carbonic acid and bi-carbonate acid, resulting in precipitation of divalent cations that aid in wettability alteration. This is consistent with previous studies, which have shown that prolonged CO2 exposure in carbonate reservoirs leads to continuous geochemical interactions, including mineral dissolution, secondary precipitation, and gradual changes in pore structure [8,9]. These processes can reinforce the wettability alteration trends observed in short-term experiments and promote additional reductions in IFT and contact angle. Eyinla et al. [7] reviewed the long-term effects of CO2–brine–rock interactions, noting that mineral dissolution and petrophysical changes in carbonates can influence the storage capacity and displacement efficiency. These observations are consistent with the trends seen in our simulations.

5. Conclusions

This experimental study demonstrated that carbonated brine significantly alters wettability in carbonate reservoirs by notable reductions in the IFT and contact angle. The following are the key conclusions of this work:
  • Carbonated brine reduced the contact angle by 16.0–11.9° and interfacial tension by 2.0–4.1 dynes/cm, while standard brine caused only modest changes (1.6–6.7° and 1.3-3.32 dynes/cm but at a higher initial IFT. These measurements confirm wettability shifts under reservoir conditions.
  • Synthetic fluid containing naphthenic acid exhibits more oil-wet behavior initially, with a contact angle of 75.6 ± 0.20° in brine, compared with 58.6 ± 0.77° for synthetic fluid without naphthenic acid. This favorable shift is attributed to the adsorption of the acidic group from the carbonate surface, which enhances oil-wetness.
  • Synthetic fluid with naphthenic acid also exhibits a greater wettability shift toward water-wetness when exposed to carbonated brine (a reduction of 16° vs. 12.8° in systems without naphthenic acid). Furthermore, naphthenic acid promotes alterations in wettability, which is consistent with the observed increase in acidity in our crude oil measurements.
  • A clear correlation between IFT reduction and contact angle decrease was observed, validating that CO2-induced wettability alterations lead to more water-wet conditions.
  • Incorporating experimental wettability measurements into the reservoir simulation model resulted in a 5.2% reduction in residual oil saturation, 2% increase in recovery factor, and 12% improvement in CO2 utilization efficiency (9780 in comparison to 8620 SCF/STB).
The laboratory study provided supporting material for interpreting the EOR and sequestration efficiency of CO2-WAG in carbonate formations by numerical modeling.

Author Contributions

Conceptualization, M.A.-G.; Methodology, M.A.-G.; Software, M.A.-G.; Validation, M.A.-G.; Formal Analysis, M.A.-G.; Writing—Original Draft Preparation, M.A.-G.; Writing—Review and Editing, E.O., H.K. and M.A.-G.; Supervision, E.O. and H.K. All authors have read and agreed to the published version of the manuscript.

Funding

This work is a part of Mr. Mohammad Al-Ghnemi’s PhD research at Colorado School of Mines, sponsored by Kuwait Petroleum Corporate (KPC)–Kuwait Oil Company (KOC).

Data Availability Statement

The original contributions presented in this study are included in the article; further inquiries can be directed to the corresponding author.

Acknowledgments

The authors would like to thank Surtek Inc. for providing the core sample used in this study, along with supporting the aging of one batch of cores.

Conflicts of Interest

The authors declare no conflicts of interest.

Appendix A

Figure A1. Interfacial tension (IFT) measurements of synthetic oil system without naphthenic acid under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
Figure A1. Interfacial tension (IFT) measurements of synthetic oil system without naphthenic acid under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
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Figure A2. Interfacial tension (IFT) measurements of synthetic oil system with naphthenic acid under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
Figure A2. Interfacial tension (IFT) measurements of synthetic oil system with naphthenic acid under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
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Figure A3. Interfacial tension (IFT) measurements of crude oil diluted with 50% n-pentane under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
Figure A3. Interfacial tension (IFT) measurements of crude oil diluted with 50% n-pentane under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
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Figure A4. Interfacial tension (IFT) measurements of crude oil diluted with 10% n-pentane under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
Figure A4. Interfacial tension (IFT) measurements of crude oil diluted with 10% n-pentane under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
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Figure A5. Contact angle measurements of synthetic oil system without naphthenic acid under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
Figure A5. Contact angle measurements of synthetic oil system without naphthenic acid under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
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Figure A6. Contact angle measurements of synthetic oil system with naphthenic acid under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
Figure A6. Contact angle measurements of synthetic oil system with naphthenic acid under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
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Figure A7. Contact angle measurements of crude oil diluted with 50% n-pentane under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
Figure A7. Contact angle measurements of crude oil diluted with 50% n-pentane under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
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Figure A8. Contact angle measurements of crude oil diluted with 10% n-pentane under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
Figure A8. Contact angle measurements of crude oil diluted with 10% n-pentane under varying conditions: (a) ambient brine, (b) reservoir brine, (c) ambient carbonated brine, and (d) reservoir carbonated brine.
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The appendix table below provides the conversions from the oil-field units used in this study to the consistent SI units.
Table A1. Conversion from oil-field to SI units.
Table A1. Conversion from oil-field to SI units.
QuantityField UnitSI UnitConversion
Interfacial TensionDynes/cmmN/m1 dynes/cm = 1 mN/m
Contact Angledegrees (°)degrees (°)Same unit
PressurepsiaMPa1 psia = 0.006895 MPa
Temperature°F°C(°F − 32) × 5/9
Lengthinch (in.)cm1 in. = 2.54 cm
Lengthfoot (ft)m1 ft = 0.3048 m
Volumecm3 (cc)m31 cc = 1 × 10−6 m3
VolumeSTB (Stock Tank Barrel)m31 STB = 0.158987 m3
Gas VolumeSCF (Standard Cubic Foot)m31 SCF = 0.0283168 m3
Utilization RatioSCF/STBm3/m3(SCF × 0.0283168)/(STB × 0.158987)
Permeabilitymd (millidarcy)m21 md = 9.869 × 10−16 m2
ViscositycPPa·s1 cP = 0.001 Pa·s
Velocityft/daym/s1 ft/day = 3.598 × 10−6 m/s
Capillary NumberDimensionlessDimensionlessSame

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Figure 1. (a) Oil components adsorb onto the positively charged carbonate surface in the presence of brine. (b) Injected CO2 alters the wetting conditions of the carbonate reservoir.
Figure 1. (a) Oil components adsorb onto the positively charged carbonate surface in the presence of brine. (b) Injected CO2 alters the wetting conditions of the carbonate reservoir.
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Figure 2. Effect of CO2 mixing with synthetic fluid without naphthenic acid.
Figure 2. Effect of CO2 mixing with synthetic fluid without naphthenic acid.
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Figure 3. Effect of CO2 mixing with crude oil: (a) crude oil system diluted with 10% n-pentane; (b) crude oil system diluted with 50% n-pentane.
Figure 3. Effect of CO2 mixing with crude oil: (a) crude oil system diluted with 10% n-pentane; (b) crude oil system diluted with 50% n-pentane.
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Figure 4. Schematic of Drop Shape Analyzer (DSA-100) [26].
Figure 4. Schematic of Drop Shape Analyzer (DSA-100) [26].
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Figure 5. Contact angle measurement using DSA-100 (captive droplet method).
Figure 5. Contact angle measurement using DSA-100 (captive droplet method).
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Figure 6. IFT measurement using DSA-100.
Figure 6. IFT measurement using DSA-100.
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Figure 7. Interfacial tension values of all systems under reservoir conditions for surrounding phases of brine and carbonated brine.
Figure 7. Interfacial tension values of all systems under reservoir conditions for surrounding phases of brine and carbonated brine.
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Figure 8. Contact angle measurements of all systems under ambient and reservoir conditions and using both brine and carbonated brine.
Figure 8. Contact angle measurements of all systems under ambient and reservoir conditions and using both brine and carbonated brine.
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Figure 9. Correlation between IFT and contact angle across all fluid systems and brine types under reservoir conditions.
Figure 9. Correlation between IFT and contact angle across all fluid systems and brine types under reservoir conditions.
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Figure 10. Relative permeability curves for the (a) oil–water system and (b) liquid–gas system. The curves illustrate the impact of the wettability shift on relative permeability endpoints. krw: water relative permeability; kro: oil relative permeability; krg: gas relative permeability.
Figure 10. Relative permeability curves for the (a) oil–water system and (b) liquid–gas system. The curves illustrate the impact of the wettability shift on relative permeability endpoints. krw: water relative permeability; kro: oil relative permeability; krg: gas relative permeability.
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Figure 11. Relative permeability curves for the (a) oil–water system and (b) liquid–gas system. The curves illustrate the impact of the wettability shift on Sor and Swr endpoints only. krw: water relative permeability; kro: oil relative permeability; krg: gas relative permeability.
Figure 11. Relative permeability curves for the (a) oil–water system and (b) liquid–gas system. The curves illustrate the impact of the wettability shift on Sor and Swr endpoints only. krw: water relative permeability; kro: oil relative permeability; krg: gas relative permeability.
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Figure 12. (a) Utilization ratios in both scenarios (with and without relative permeability shift); (b) system’s cumulative production in both scenarios.
Figure 12. (a) Utilization ratios in both scenarios (with and without relative permeability shift); (b) system’s cumulative production in both scenarios.
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Table 1. Core Measurement System (CMS-300) results for core samples.
Table 1. Core Measurement System (CMS-300) results for core samples.
Core SampleLength [inch]Diameter
[inch]
Dried
Weight [g]
Pore
Volume [cc]
Porosity
[%]
Permeability
[md]
11.921.49118.28.24115.0324
21.991.49126.38.59415.1519.3
31.981.49126.78.34714.7623.6
41.971.48123.38.87915.9223.4
Table 2. Measured viscosities of fluid systems.
Table 2. Measured viscosities of fluid systems.
Fluid SystemViscosity (cP)
Synthetic Hydrocarbon Fluid—Without Naphthenic Acid0.52
Synthetic Hydrocarbon Fluid—With Naphthenic Acid0.54
Crude Oil—Diluted with 50% n-Pentane3.5
Crude Oil—Diluted with 10% n-Pentane12.2
Table 3. Compositions of synthetic fluid systems.
Table 3. Compositions of synthetic fluid systems.
Synthetic Fluid Composition Without Naphthenic AcidSynthetic Fluid Composition with Naphthenic Acid
ComponentMole %Mole %
n-C50.190.188
n-C80.490.49
n-C100.320.32
Naphthenic Acid--0.02
Table 4. Interfacial tension (IFT) measurements for various fluid systems under ambient and reservoir conditions. Values are presented as mean ± standard deviation. CV: coefficient of variation; n: number of replicates. IFT reduction is calculated as the difference between ambient and reservoir mean values.
Table 4. Interfacial tension (IFT) measurements for various fluid systems under ambient and reservoir conditions. Values are presented as mean ± standard deviation. CV: coefficient of variation; n: number of replicates. IFT reduction is calculated as the difference between ambient and reservoir mean values.
Fluid SystemSurrounding PhaseIFT Under Ambient ConditionsCVReplicatesIFT Under Reservoir
Conditions
CVReplicatesIFT Reduction
[dynes/cm]%n[dynes/cm]%n[dynes/cm]
Synthetic Fluid with Naphthenic AcidBrine System34.1 ± 0.692330.78 ± 0.61.933.32
Carbonated Brine System29.9 ± 0.551.88427.13 ± 0.511.8942.77
Synthetic Fluid without Naphthenic AcidBrine System39.47 ± 0.391336.5 ± 0.320.8832.97
Carbonated Brine System35.81 ± 0.561.57234.65 ± 0.611.7621.16
Crude oil diluted with 50% n-pentaneBrine System20.95 ± 0.572.71319.6 ± 0.231.241.35
Carbonated Brine System16.11 ± 0.120.74415.49 ± 0.312.0140.62
Crude oil diluted with 10% n-pentaneBrine System22.89 ± 0.331.4520.9 ± 0.190.951.99
Carbonated Brine System20.0 ± 0.472.36418.13 ± 0.2631.4541.87
Table 5. Contact angle measurements under ambient and reservoir conditions for various fluid systems. Values are reported as mean ± standard deviation. CV: coefficient of variation; n: number of replicates. Contact angle reduction is calculated as the difference between ambient and reservoir means.
Table 5. Contact angle measurements under ambient and reservoir conditions for various fluid systems. Values are reported as mean ± standard deviation. CV: coefficient of variation; n: number of replicates. Contact angle reduction is calculated as the difference between ambient and reservoir means.
Fluid SystemSurrounding PhaseContact Angle Under Ambient Conditions CV ReplicatesContact Angle Under Reservoir Conditions CV ReplicatesContact Angle Reduction
°%n°%n°
Synthetic Fluid with Naphthenic AcidBrine System75.6 ± 0.2010.27368.9 ± 0.590.7736.7
58.0 ± 0.4580.79353.7 ± 2.354.3734.3
Carbonated Brine System78.9 ± 2.43.04362.9 ± 1.732.75316
Synthetic Fluid without Naphthenic AcidBrine System58.6 ± 0.771.32256.9 ± 0.931.6331.7
Carbonated Brine System66.8 ± 2.613.9254.0 ± 1.803.3412.8
Crude oil diluted with 50% n-pentaneBrine system165.3 ± 0.450.273163.3 ± 1.210.7442
165.1 ± 1.310.793161.5 ± 1.130.733.6
168.6 ± 0.60.353166.1 ± 0.150.0932.5
Carbonated brine system157.8 ± 1.731.13145.8 ± 1.491312
156.8 ± 0.560.354144.7 ± 0.660.45412.1
155.2 ± 5.03.23133.2 ± 9.126.8222
Crude oil diluted with 10% n-pentaneBrine system168 ± 1.350.84164.1 ± 0.070.0423.9
169.6 ± 0.330.194168.0 ± 0.370.2241.6
Carbonated brine system155 ± 2.921.883142.3 ± 1.951.37312.7
158.9 ± 1.041.043147.0 ± 1.10.75311.9
Table 6. Data used in capillary number calculations.
Table 6. Data used in capillary number calculations.
PropertyUnit
Velocity5 ft/day
Viscosity0.001 Pa.s
IFT for Brine (Experimental)19.63 dynes/cm
IFT for Carbonated Brine (Experimental)15.25 dynes/cm
Capillary Number (Brine)7.52 × 10−5
Capillary Number (Carbonated Brine)1.08 × 10−4
Table 7. Correlation of relative permeability endpoints determined using experimental results.
Table 7. Correlation of relative permeability endpoints determined using experimental results.
PropertyOriginalCarbonated Brine EffectEffect
Sor0.30.248−0.052
Swr0.30.283−0.016
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Al-Ghnemi, M.; Ozkan, E.; Kazemi, H. Experimental and Numerical Evaluation of CO2-Induced Wettability Alteration in Carbonate Reservoir CCUS. Energies 2025, 18, 5529. https://doi.org/10.3390/en18205529

AMA Style

Al-Ghnemi M, Ozkan E, Kazemi H. Experimental and Numerical Evaluation of CO2-Induced Wettability Alteration in Carbonate Reservoir CCUS. Energies. 2025; 18(20):5529. https://doi.org/10.3390/en18205529

Chicago/Turabian Style

Al-Ghnemi, Mohammad, Erdal Ozkan, and Hossein Kazemi. 2025. "Experimental and Numerical Evaluation of CO2-Induced Wettability Alteration in Carbonate Reservoir CCUS" Energies 18, no. 20: 5529. https://doi.org/10.3390/en18205529

APA Style

Al-Ghnemi, M., Ozkan, E., & Kazemi, H. (2025). Experimental and Numerical Evaluation of CO2-Induced Wettability Alteration in Carbonate Reservoir CCUS. Energies, 18(20), 5529. https://doi.org/10.3390/en18205529

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