Simulation of Low-Salinity Water-Alternating Impure CO₂ Process for Enhanced Oil Recovery and CO₂ Sequestration in Carbonate Reservoirs

Abstract

This study investigates the combined effects of impurities in CO₂ stream, geochemistry, water salinity, and wettability alteration on oil recovery and CO₂ storage in carbonate reservoirs and optimizes injection strategy to maximize oil recovery and CO₂ storage ratio. Specifically, it compares the performance of pure CO₂ water-alternating gas (WAG), impure CO₂-WAG, pure CO₂ low-salinity water-alternating gas (LSWAG), and impure CO₂-LSWAG injection methods from perspectives of enhanced oil recovery (EOR) and CO₂ sequestration. CO₂-enhanced oil recovery (CO₂-EOR) is an effective way to extract residual oil. CO₂ injection and WAG methods can improve displacement efficiency and sweep efficiency. However, CO₂-EOR has less impact on the carbonate reservoir because of the complex pore structure and oil-wet surface. Low-salinity water injection (LSWI) and CO₂ injection can affect the complex pore structure by geochemical reaction and wettability by a relative permeability curve shift from oil-wet to water-wet. The results from extensive compositional simulations show that CO₂ injection into carbonate reservoirs increases the recovery factor compared with waterflooding, with pure CO₂-WAG injection yielding higher recovery factor than impure CO₂-WAG injection. Impurities in CO₂ gas decrease the efficiency of CO₂-EOR, reducing oil viscosity less and increasing interfacial tension (IFT) compared to pure CO₂ injection, leading to gas channeling and reduced sweep efficiency. This results in lower oil recovery and lower storage efficiency compared to pure CO₂. CO₂-LSWAG results in the highest oil-recovery factor as surface changes. Geochemical reactions during CO₂ injection also increase CO₂ storage capacity and alter trapping mechanisms. This study demonstrates that the use of impure CO₂-LSWAG injection leads to improved oil recovery and CO₂ storage compared to pure CO₂-WAG injection. It reveals that wettability alteration plays a more significant role for oil recovery and geochemical reaction plays crucial role in CO₂ storage than CO₂ purity. According to optimization, the greater the injection of gas and water, the higher the oil recovery, while the less gas and water injected, the higher the storage ratio, leading to improved storage efficiency. This research provides valuable insights into parameters and injection scenarios affecting enhanced oil recovery and CO₂ storage in carbonate reservoirs.

1. Introduction

Carbonate reservoirs are particularly significant, as they hold over 60% of the world’s remaining conventional oil reserves and contribute to more than 30% of global daily oil production [1]. However, the main challenge in extracting oil from carbonate reservoirs is the significant amount of residual oil either adsorbed onto the rock surface or trapped within the pore spaces. The wettability of carbonate rocks, which promotes oil adsorption in the presence of water, combined with the complex rock matrix, complicates oil recovery [1]. Therefore, employing enhanced oil recovery (EOR) methods that improve the wettability of the carbonate rock could significantly boost oil recovery from these reservoirs [2].

Among various EOR strategies [3,4,5,6,7,8], the gas injection method, particularly carbon dioxide-enhanced oil recovery (CO₂-EOR), has been recognized as an effective way for both carbon capture, utilization, and storage (CCUS) and improved oil recovery by displacing residual oil toward production wells. CO₂-EOR adapts the injection of CO₂ into depleted reservoirs to maximize the oil recovery through various mechanisms, including reduction in viscosity, interfacial tension (IFT), and oil swelling [9,10,11]. Moreover, CO₂-EOR can affect the complex pore structure of carbonate reservoirs by geochemical reaction with CO₂-rock interaction. Minerals in carbonate reservoirs are highly reactive [12], which results in geochemical reactions between CO₂, reservoir fluids, and minerals during CO₂-EOR. These interactions can lead to changes in the physical and chemical properties of the reservoir [12,13,14,15].

To overcome these challenges and improve the sweep efficiency, the water-alternating gas (WAG) injection technique has been introduced [16]. This method involves the sequential injection of water and gas into the reservoir at specific cycles. The alternating cycles of water and gas injection enhance the sweeping of oil across both the upstream and downstream sides of the reservoir [17]. This approach improves oil recovery on a macroscopic level by the cyclic sweeping nature of WAG.

Carbonate reservoirs present distinct difficulties for EOR because of their complex pore structures and varying wettability characteristics. To overcome these obstacles and reduce environmental impacts, the combined use of CO₂ injection in WAG and low-salinity WAG (LSWAG) methods has attracted considerable interest [18,19]. Low-salinity water injection (LSWI) is regarded as a cost-effective and environmentally sustainable alternative to traditional EOR methods [20]. The hybrid CO₂-LSWAG injection technique has shown potential in boosting oil recovery and reducing operational expenses. The effectiveness of this hybrid approach and the specific mechanisms driving improved recovery are still under discussion [4,21]. Several factors affect the success of CO₂-LSWAG injection, including CO₂ solubility in brine, rock composition, brine salinity, and composition, WAG parameters, and wettability. Wettability changes resulting from the interactions between CO₂, low-salinity water, and the rock surface are widely recognized as key factors [22,23]. Incorporating the changes in wettability along with the shift in relative permeability curves, this study examines the improved mobility of both water and oil, thereby enhancing EOR performance and CO₂ storage.

The CO₂ stream captured from industrial or anthropogenic sources often contains impurities such as O₂, N₂, H₂S, CH₄, water, and Ar [24,25,26]. Numerous studies have explored how impurities affect different aspects of CO₂-EOR. Previous research performed a 2D compositional simulation to investigate the effects of impure CO₂ on EOR and CCS performance [27,28]. The results indicated that impurities in the CO₂ stream influenced the miscibility of oil–gas mixtures, sweep efficiency, displacement efficiency, interfacial tension, and the reduction in oil density in varying degrees. The compression of the CO₂ stream is also affected by the composition of the stream [29]. Due to the lack of previous research on the impact of impurities in the CO₂ stream on geochemical reactions in carbonate reservoirs, this study aims to investigate the effects of these impurities [30,31].

Previous studies have focused on the performance evaluation of the WAG method with CO₂-LSWAG for enhancing oil recovery (

Table 1. Overview of the findings from recent relevant literature (○: included, ×: not included).

Literature	Geochemistry	LSWI	Impure CO2	CO2 Storage	Carbonate Reservoir
Nassabeh et al. [8]	×	○	○	×	○
Seo et al. [28]	×	×	○	○	×
AlRassas et al. [17]	×	×	×	○	○
Adegbite et al. [4]	×	○	×	×	○
Lee et al. [32]	×	×	○	○	×
Cui et al. [33]	○	×	×	○	×
Chaturvedi et al. [34]	×	○	×	○	×

). This study aims to evaluate the performance of pure CO₂-LSWAG and impure CO₂-LSWAG with geochemistry compared to original WAG methods for enhancing oil recovery and CO₂ sequestration. Extensive simulation studies have been conducted to gain a comprehensive understanding of EOR and CO₂ storage potential of impure CO₂ and pure CO₂ injection in LSWAG methods. With these results, the study also performs an optimization of the WAG injection scenario, such as gas and water injection rate, to maximize the oil recovery and CO₂ storage ratio.

2. Materials and Methods

2.1. CO₂-Enhanced Oil Recovery

At reservoir conditions, CO₂ exists in a supercritical phase with a density slightly lower than that of oil and a low viscosity ranging from 0.03 to 0.1 cp [35]. When supercritical CO₂ is mixed with oil, it reduces viscosity and interfacial tension while causing oil swelling. Although the viscosity of supercritical CO₂ is notably higher than in its gaseous phase, it remains exceptionally low compared to oil viscosity, leading to the fingering effect [36]. Additionally, early CO₂ breakthrough reduces sweep efficiency. To overcome these problems, the WAG method has gained popularity as an alternative to CO₂ flooding. WAG enhances oil recovery by alternating water and gas injections, which mitigates gravity override and improves sweep efficiency.

CO₂ purity is also an essential factor in evaluating the performance of CO₂-EOR. The efficiency of CO₂-EOR can be determined according to the purity of the CO₂ stream captured from the flue gas. Impurities like CH₄, SO₂, O₂, and N₂ increase minimum miscible pressure (MMP), while H₂S and intermediate hydrocarbons reduce MMP [32]. Two CO₂ gas streams using the same flue gas through different compression and purification methods result in different CO₂ purities [37]. Since the flue gas composition was the same across the two CO₂ stream models, each model was analyzed with distinct compression and purification processes using the same flue gas.

Table 2. The composition of the injected gas stream [32].

Composition	Pure CO2	Impure CO2
CO2 (% v/v)	100	77.4
Ar (% v/v)	-	3.19
N2 (% v/v)	-	11.4
O2 (% v/v)	-	7.96
SO2 (ppm)	-	200

summarizes the gas compositions used in the modeling.

2.2. Geochemical Reaction

In this study, the simulation assumes instantaneous equilibrium for aqueous reactions due to their rapid kinetics, while a kinetic model is necessary to account for the reaction rate and time to equilibrium for mineral reactions [33,38,39,40]. In this study, 13 reactions are considered to represent hydrocarbon solubility and aqueous, mineral, and exchange reactions, as listed in

Table 3. Chemical reactions included in the simulation.

Hydrocarbon solubility
${\mathrm{C}\mathrm{O}}_{2\left(\mathrm{o}\right)}\leftrightarrow {\mathrm{C}\mathrm{O}}_{2\left(\mathrm{g}\right)}\leftrightarrow {\mathrm{C}\mathrm{O}}_{2\left(\mathrm{a}\mathrm{q}\right)}$	(R1)
${\mathrm{C}\mathrm{O}}_{2\left(\mathrm{a}\mathrm{q}\right)}+{\mathrm{H}}_2\mathrm{O}\leftrightarrow {\mathrm{H}}^{+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$	(R2)
Aqueous reactions
${\mathrm{C}\mathrm{a}\mathrm{S}\mathrm{O}}_4\leftrightarrow {\mathrm{C}\mathrm{a}}^{2+}+{\mathrm{S}\mathrm{O}}_4^{2-}$	(R3)
${\mathrm{M}\mathrm{g}\mathrm{S}\mathrm{O}}_4\leftrightarrow {\mathrm{M}\mathrm{g}}^{2+}+{\mathrm{S}\mathrm{O}}_4^{2-}$	(R4)
${\mathrm{N}\mathrm{a}\mathrm{S}\mathrm{O}}_4\leftrightarrow {\mathrm{N}\mathrm{a}}^{2+}+{\mathrm{S}\mathrm{O}}_4^{2-}$	(R5)
${\mathrm{C}\mathrm{a}\mathrm{C}\mathrm{O}}_3+{\mathrm{H}}^{+}\leftrightarrow {\mathrm{C}\mathrm{a}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$	(R6)
${\mathrm{M}\mathrm{g}\mathrm{C}\mathrm{O}}_3+{\mathrm{H}}^{+}\leftrightarrow {\mathrm{M}\mathrm{g}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$	(R7)
${\mathrm{C}\mathrm{a}\mathrm{H}\mathrm{C}\mathrm{O}}_3^{+}\leftrightarrow {\mathrm{C}\mathrm{a}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$	(R8)
${\mathrm{M}\mathrm{g}\mathrm{H}\mathrm{C}\mathrm{O}}_3^{+}\leftrightarrow {\mathrm{M}\mathrm{g}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$	(R9)
${\mathrm{N}\mathrm{a}\mathrm{H}\mathrm{C}\mathrm{O}}_3^{+}\leftrightarrow {\mathrm{N}\mathrm{a}}^{+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$	(R10)
Mineral reactions
$\mathrm{C}\mathrm{a}\mathrm{l}\mathrm{c}\mathrm{i}\mathrm{t}\mathrm{e}+{\mathrm{H}}^{+}\leftrightarrow {\mathrm{C}\mathrm{a}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$	(R11)
Ion exchange reactions
${\mathrm{N}\mathrm{a}}^{+}+{\displaystyle \frac{1}{2}}\left(\mathrm{C}\mathrm{a}-{\mathrm{X}}_2\right)\leftrightarrow {\displaystyle \frac{1}{2}}{\mathrm{C}\mathrm{a}}^{2+}+(\mathrm{N}\mathrm{a}-\mathrm{X})$	(R12)
${\mathrm{N}\mathrm{a}}^{+}+{\displaystyle \frac{1}{2}}\left(\mathrm{M}\mathrm{g}-{\mathrm{X}}_2\right)\leftrightarrow {\displaystyle \frac{1}{2}}{\mathrm{M}\mathrm{g}}^{2+}+(\mathrm{N}\mathrm{a}-\mathrm{X})$	(R13)

.

The dissolution rates of soluble hydrocarbons are rapid, allowing them to be in assumed thermodynamic equilibrium at given pressure, composition, and temperature conditions. Consequently, the solubilities of these components are modeled using the concept of thermodynamic phase equilibrium. The soluble hydrocarbon components have identical fugacity across the oleic, gaseous, and aqueous phases. For instance, CO₂, at equilibrium in reaction R1, exhibits equal fugacity in all three phases, as illustrated by Equation (1).

$$f_{ig}\left(P,y_{ig},T\right)\equiv f_{io}\left(P,y_{io},T\right)\equiv f_{iw}\left(P,y_{iw},T\right)\mathrm{f}\mathrm{o}\mathrm{r} i=1,\dots ,N_c$$

(1)

where $f_{ig}$, $f_{io}$, and $f_{iw}$ are the fugacities of the vapor, oil, and aqueous phase; $y_{ig}$, $y_{io}$, $y_{iw}$ are mole fractions of component $i$ in the vapor, oil, and aqueous phase. $N_c$ is the number of soluble hydrocarbon components. The fugacities ($f_{ig}$, $f_{io}$) of soluble hydrocarbon components in the gas and oil phases are determined by the Peng–Robinson equation of state (EOS). For calculating aqueous reactions, the following equations are used. This model is calculated using the Debye–Hückel equation to compute the activity coefficients, as presented in Equation (5) [39,41]. Also, the ionic strength in Equation (7) is calculated using Equation (8).

$$Q_a=K_{eq,a}$$

(2)

$$Q_a={\prod }_{k=1}^{n_{aq}}{a}_k^{{\nu }_{ak}}\mathrm{f}\mathrm{o}\mathrm{r}k=1,\dots ,n_{aq}$$

(3)

$$a_k={\gamma }_k{C}_{kw}\mathrm{f}\mathrm{o}\mathrm{r}k=1,\dots ,n_{aq}$$

(4)

$$\log {\gamma }_k={\displaystyle \frac{A_{\gamma }{z}_k^2\sqrt{I}}{1+{\dot{a}}_k{B}_{\gamma }\sqrt{I}}}+\dot{B}I$$

(5)

$$I={\displaystyle \frac{1}{2}}\sum _{k=1}^{n_{aq}}{C}_{kw}{z}_k^2$$

(6)

where $Q_a$ represents the activity production of aqueous reaction $a$; $K_{eq,a}$ denotes the chemical equilibrium constant for aqueous reaction $a$; $a_k$ is the activity of ion $k$; ${\nu }_{ak}$ is the stoichiometric coefficient of ion $k$; $n_{aq}$ is the number of ions involved in the aqueous reaction; ${\gamma }_k$ is the activity coefficient of ion $k$; $C_{kw}$ is the concentration of ion $k$ in the formation water; $A_{\gamma },B_{\gamma },$ and $\dot{B}$ are temperature-related parameters; ${\dot{a}}_k$ is the dimensionless parameter for ion $k$; $I$ represents the ionic strength; and $z_k$ is the charge number of ion $k$.

2.3. Low-Salinity Water Injection

Many studies have shown that the control of ion composition of injected brine can increase oil production. Several mechanisms were proposed by past studies to demonstrate the improved oil recovery caused by LSWI. A previous study classified them into two categories [42]. The first category focuses solely on fluid–fluid interactions, including pH increases and soap formation, as well as interfacial viscoelasticity [43,44]. The second category pertains to rock/brine/oil interactions, such as multi-ion exchange, localized pH increases, double layer expansion, adsorption of potential-determining ions, and calcite dissolution [45,46,47,48,49]. The observation of wettability alteration has been attributed to these types of mechanisms [39,50,51,52,53].

Wettability alteration is modeled using flow functions, specifically relative permeability, while capillary pressure is considered negligible due to the high-pressure gradients that dominate fluid flow in core experiments. For multiphase transport, a dimensionless version of the Brooks–Corey-type correlation is employed for the relative permeability functions as follows:

$$k_{ro}=k_{ro}^{\ast }{\left({\displaystyle \frac{1-S_w-S_{or}}{1-S_{or}-S_{wr}}}\right)}^{n_o}$$

(7)

$$k_{rw}=k_{rw}^{\ast }{\left({\displaystyle \frac{S_w-S_{wirr}}{1-S_{or}-S_{wr}}}\right)}^{n_w}$$

(8)

where $k_{ro}$ and $k_{rw}$ are oil and water’s relative permeability after considering the chemical reaction; $k_{ro}^{\ast }$ and $k_{rw}^{\ast }$ are oil and water’s initial relative permeability; $S_w$, $S_{or}$, $S_{wr}$, and $S_{wirr}$ are the saturation of water, residual oil, residual water, and irreducible water.

2.4. Fluid Modeling

Computer Modelling Group (CMG)’s WinProp software (2024.30) was used to develop a fluid model. Fluid modeling was based on data from CMG’s modeling template motivated by the Third SPE Comparative Solution Project [54]. The phase behavior of the reservoir oil and the injection fluid including CO₂ and impurities were calculated using the Peng–Robinson (PR) equation of state (EOS).

Table 4. Oil components and properties of each component for EOS calculation.

Component	Composition	Critical Pressure (atm)	Critical Temperature (K)	Molecular Weight
C1	0.0140	45.4	190.6	16.04
C2	0.0143	48.2	305.4	30.07
C3	0.0243	41.9	369.8	44.09
C4	0.0173	37.5	425.2	58.12
C5	0.0357	33.3	469.6	72.15
C6	0.0418	32.5	507.5	86.00
C7–13	0.3554	26.2	606.5	12.59
C14–20	0.1646	16.9	740.0	22.78
C21–28	0.0854	12.3	823.6	32.55
C29+	0.2472	79.6	925.9	48.47
CO2	0.0000	72.8	304.2	44.01

shows the components and properties of fluid, and the parameters used for fluid modeling. The phase envelope of the fluid model is shown in Figure 1.

2.5. Reservoir Modeling

In this study, a two-dimensional cross-sectional model was modeled with CMG’s Builder to investigate the impacts of impurities in CO₂ gas stream and LSWI on the carbonate reservoir. The reservoir was discretized to 40 × 1 × 10 grids and each grid has a size of 5 m × 10 m × 5 m (Figure 2). This hypothetical reservoir model was generated from UAE field core laboratory experiment data like relative permeability curve, mineral composition, and brine composition [55]. The reservoir layer is composed of calcite, a representative mineral of carbonate rocks, to observe the effects of chemical reactions. The properties of the reservoir layer are summarized in

Table 5. Initial conditions of reservoir property.

Property	Values
Porosity	0.258
Permeability (md)	50/50/5
Mineral Volume Fraction (%)	Calcite 74, Quartz 26
Initial Pressure (kPa)	20,000
Temperature (°C)	70
Initial Oil Saturation	0.86
Initial Water Saturation	0.14
Pore Volume (m3)	25,800

. Figure 3 indicates the relative permeability curves calculated at end-point wettability for simulation. The concentration of Ca²⁺ was used as a relative permeability shift parameter, where the minimum and maximum thresholds were 0.005 and 0.503, respectively [55]. Linear interpolation was used to approximate the modified relative permeability functions under different wettability conditions, based on the degree of alteration in the geochemical properties. This approach is similar to how relative permeability shifts from the initial oil-wet towards the water-wet state. The ions in the formation water are provided in

Table 6. Ion composition from formation water analysis [55].

Ion type	Concentration (ppm)
Na+	56,200
Ca2+	19,800
Mg2+	770
SO42−	56
HCO3−	96
Cl−	124,100
Total Salinity	201,022

[55].

2.6. Injection Design

In this study, WAG was employed as the primary injection strategy for the model. The model consists of a total of eight configurations, categorized by the type of injected gas, geochemistry, the type of injected water, and wettability alteration (

Table 7. Cases categorized by injected gas, geochemistry, water, and wettability alteration (○: included, ×: not included).

Case	Injected Gas	Geochemistry	Injected Water	Wettability Alteration
1	CO2	×	Water	×
2	Impure CO2	×	Water	×
3	CO2	○	Water	×
4	Impure CO2	○	Water	×
5	CO2	○	LSWI	×
6	Impure CO2	○	LSWI	×
7	CO2	○	LSWI	○
8	Impure CO2	○	LSWI	○

). The injection scenarios for all models consist of three years of waterflooding, followed by six months of WAG applied biannually for four years (1:1 WAG ratio) (Figure 4). The ion type of injected low-salinity water is shown in

Table 8. Ion composition from low-salinity water analysis.

Ion Type	Concentration (ppm)
Na+	13,700
Ca2+	521
Mg2+	1620
SO42−	3310
HCO3−	0
Cl−	24,468
Total Salinity	43,619

[55]. The salinity of the injected LSWI is similar to that of typical seawater and is approximately one-fifth of the salinity of formation water.

3. Results and Discussions

3.1. Impact of Impurities

The minimum viscosity observed in Case 1 is 0.152 mPa·s, representing a 9% reduction from the initial oil viscosity. Case 2 shows a minimum viscosity of 0.162 mPa·s, reflecting only a 3% reduction (Figure 5). Consequently, the presence of impurities in the CO₂ stream diminishes the effectiveness of the gas as a solvent in reducing oil viscosity after multiple interactions. The impurities can also affect the IFT between oil and gas streams. The influence of impurity addition on IFT between gas and oil at the grid block coordinates (20, 1, 5) was examined [56,57]. In Case 1, the minimum IFT recorded was 0.007 mN/m between the CO₂ and reservoir fluid, while in Case 2, it rose to 0.09 mN/m, representing an increase of 1258%. As illustrated in Figure 6, the addition of impurities led to a higher IFT. Figure 7 presents the cumulative gas injection under reservoir conditions. The impurities in the CO₂ stream exhibit low critical temperatures and comparatively lower compressibility under reservoir conditions. As a result, CO₂ with impurities leads to an increase in molar volume, meaning that impure CO₂ occupies a greater volume than pure CO₂ under reservoir conditions. Figure 8 illustrates the gas saturation distribution following the injection of 0.12 PV of gas. When comparing the gas front at the top layer of the reservoir, in Case 2, the movement of the gas front is accelerated by 1.6 times compared to Case 1 due to the impurities in the CO₂, resulting in an earlier gas breakthrough. This early breakthrough can negatively impact sweep efficiency and ultimately lower oil recovery. Figure 9 demonstrates that oil recovery was reduced in Case 2, with impurities in CO₂ leading to 4.3% decrease in oil recovery compared to Case 1.

3.2. Impact of Geochemistry

Geochemical reactions can influence porosity and permeability through the dissolution and precipitation of minerals, ultimately impacting oil recovery and CO₂ storage. Figure 10 presents the change in pore volume for each case. Due to mineral dissolution, Case 3 exhibits a slight increase in pore volume of approximately 0.0044%, while Case 4 shows an increase of about 0.0041%. The total amount of injected CO₂ is greater in Case 3 with pure CO₂ than in Case 4 with impure CO₂, leading to a greater decrease. However, the decrease by geochemical reactions is also minimal and does not significantly affect oil production, as shown in Figure 11. In contrast, geochemical reactions have a substantial impact on CO₂ storage. As illustrated in Figure 12, solubility trapping occurs due to geochemical reactions, leading to an overall increase in storage capacity of approximately 56% for pure CO₂ injection and about 45% for impure CO₂ injection, with solubility trapping proportions of roughly 36% and 37%, respectively (Figure 13). This indicates that geochemical reactions have a positive effect on CCS performance.

3.3. Impact of Low-Salinity Water Injection

The ionic components of the injected water can react prior to CO₂ injection, resulting in mineral precipitation and a reduction in pore volume, as illustrated in Figure 14. Since the pore volume only changes to about 99.96% of its initial value, there is negligible impact on oil production or CO₂ storage. Nevertheless, the wettability alteration induced by LSWI changes the rock surface from oil-wet to water-wet conditions, positively affecting additional oil recovery. Figure 15 demonstrates that this wettability alteration results in an approximate 4–5% increase in oil recovery. In contrast, LSWI has a negative impact on CO₂ storage, particularly affecting CO₂ solubility. As salinity increases, the solubility of CO₂ decreases due to the salting-out effect, which refers to the relative reduction in CO₂ absorption in saline solutions compared to pure water [34]. However, in Cases 7 and 8, where wettability alteration is considered, the solubility-trapped CO₂ increased by approximately 3% (Figure 16). This is attributed to the transition to water-wet rock, which results in higher residual water saturation and allows for greater CO₂ dissolution. The final average water saturation increased by 6% compared to the initial value (Figure 17).

3.4. Oil Recovery

As illustrated in Figure 18, impurities in the CO₂ gas stream led to approximately a 5% decrease in oil recovery. Case 7 demonstrates the highest oil recovery of 71.2%, attributable to the combined effects of enhanced displacement efficiency from pure CO₂ and wettability alteration from LSWI. Case 8 demonstrates reduced displacement efficiency as a result of impurities in the CO₂ gas stream. However, it still attains an oil recovery of around 67.4% due to the effects of wettability alteration. The higher recovery in Case 8 compared with Case 1, which injected pure CO₂ injection, underscores the significant role of wettability alteration in improving oil recovery, surpassing the impact of injection gas purity.

3.5. CO₂ Storage

Figure 19 indicates that cases incorporating geochemical factors (Cases 3 and 4) exhibit greater storage capacity than those that do not (Cases 1 and 2). Furthermore, Figure 20 shows that a more stable solubility trap is formed, as opposed to a structural trap. Although LSWI reduces CO₂ solubility due to the salting-out effect which negatively affects the CO₂ solubility trapping mechanism, the wettability alteration induced by LSWI leads to an increase in residual water saturation. As a result, the proportion of solubility trapped CO₂ increases, ultimately demonstrating stable CO₂ storage performance. Considering the combined impacts of impurities in the CO₂ gas stream, geochemical reactions, LSWI, and wettability alteration, impurities affect CO₂ storage by approximately 26%. Geochemical reactions have a more significant impact, contributing 56% to the storage capacity. Although LSWI and wettability alterations do not affect the total storage amount, they affect the storage mechanism.

3.6. Optimization

Since impure CO₂ EOR is a complicated process, an optimized injection scenario was derived based on different objective functions to maximize oil recovery or storage ratio. The parameters used for optimization are shown in

Table 9. Parameters used in the optimization of injection scenarios.

Injected Gas	Water Injection Rate at Standard Condition (bbl/day)	Gas Injection Rate at Standard Condition (m3/day)
Pure CO2	15–25	12,000–20,000
Impure CO2

. For each objective function, 500 cases were generated to find an optimal injection scenario.

Table 10. Optimized injection scenarios.

Injected Gas	Objective Function	Scenario	Gas Injection Rate (m3/day)	Water Injection Rate (bbl/day)	Oil Recovery	Storage Ratio (%)
Pure CO2	Oil Recovery	Base	16,000	20	73.95	6.65
		Optimal	20,000	24.8	74.90	4.78
		142	19,240	24.8	74.76	5.06
		6	12,000	22	73.70	8.68
		Lowest	12,000	15	72.68	9.79
	Storage Ratio	Base	16,000	20	73.95	6.65
		Optimal	12,000	15.25	72.71	9.89
		136	12,000	15.35	72.73	9.61
		90	12,640	16.05	72.99	8.86
		Lowest	20,000	25	74.88	4.74
Impure CO2	Oil Recovery	Base	16,000	20	69.49	6.61
		Optimal	19,640	24.85	70.91	4.51
		1	15,200	15	68.02	7.54
		219	18,680	24.35	70.66	5.12
		Lowest	12,000	15	67.96	9.55
	Storage Ratio	Base	16,000	20	69.49	6.61
		Optimal	12,000	15.5	68.16	9.59
		10	19,200	24	70.68	4.98
		229	12,840	15.35	68.11	8.84
		Lowest	20,000	25	70.86	4.44

indicates the base, optimum, and lowest injection scenarios with two additional scenarios for different objective functions. In the case of maximum recovery optimization of pure, impure CO₂ injection case, maximization of the gas injection rate and the water injection rate during the WAG cycle is effective in increasing oil recovery since injecting CO₂ has a positive effect on displacement and sweep efficiencies. As a result, oil recovery tends to increase with the injection rate, regardless of the purity of the injected CO₂ gas stream. In the case of maximum storage ratio optimization, it is shown that the storage efficiency increases as the injection rate of the injected fluid decreases. Comparing the storage amounts, although a higher amount of CO₂ gas injected leads to an increase in total storage, the higher production of CO₂ negatively affects storage efficiency.

4. Conclusions

This study analyzes the influence of geochemistry and injected CO₂ gas purity on oil-recovery factor, CO₂ storage, and the optimization of injection strategy for objective functions such as oil recovery and CO₂ storage ratio. These evaluations are conducted by integrating pure CO₂ and impure CO₂-EOR methods. These advanced methods are compared against the pure CO₂-WAG approach. A 2D cross-sectional homogeneous carbonate reservoir model was constructed to assess the combined influences of impurities, geochemistry, and wettability alteration on oil recovery and CO₂ storage.

The main conclusions are drawn as follows:

(1)

The injection of CO₂ into a carbonate reservoir results in an increase in the recovery factor of up to 9% compared to waterflooding. The oil-recovery factor from pure CO₂-WAG is 4% higher than that obtained with impure CO₂ WAG injection methods.

(2)

The purity of the injection CO₂ gas stream has a crucial role in the efficiency of both oil recovery and CO₂ sequestration. Impurities in the CO₂ stream exhibit reduced effectiveness in CO₂-EOR. Impure CO₂ demonstrates a 6% less reduction in oil viscosity efficiency compared to pure CO₂, along with a 1258% increase in IFT and increased reservoir pressure. It leads to gas channeling and reduced sweep efficiency, resulting in approximately 4.5% lower oil recovery than pure CO₂ injection. Gas channeling results in a 20–25% decline in storage efficiency compared to pure CO₂.

(3)

The incorporation of CO₂ with low-salinity water in the WAG injection exhibits the highest oil recovery compared to other injection methods. The rock wettability change from oil-wet to water-wet surface has a remarkable impact on the recovery factor.

(4)

Geochemical reaction leads to CO₂ solubility trapping and increases overall CO₂ storage capacity. This proposes that geochemical reaction is a key factor in CCS to estimate CO₂ storage.

(5)

Based on the simulation results, the use of impure CO₂ gas in LSWAG injection leads to a higher oil-recovery factor and CO₂ storage capacity than pure CO₂-WAG injection. This suggests that wettability alteration by LSWI has a greater impact on recovery and geochemical reaction has a greater impact on CO₂ storage than the purity of the CO₂.

(6)

Based on the optimization results, to increase oil recovery, the injection rate of the injected fluid should be increased. In the case of the storage ratio, as the CO₂ injection rate increases, the gravity override effect is intensified, leading to a decrease in the storage ratio and resulting in lower efficiency.