Investigation of the Influence of Formation Water on the Efficiency of CO₂ Miscible Flooding at the Core Scale

Abstract

This study investigated the impact of formation water on the mass transfer between CO₂ and crude oil in low-permeability reservoirs through CO₂ miscible flooding. Formation water leads to water blocks, which affect the effectiveness of CO₂ miscible flooding. Therefore, we studied the impact and mechanisms of formation water on the CO₂-oil miscibility. The microscale interaction between formation water-CO₂-core samples was investigated using CT scanning technology to analyze its influence on core permeability parameters. In addition, CO₂ miscible flooding experiments were conducted using the core displacement method to determine the effects of formation water salinity and average water saturation on minimum miscibility pressure (MMP) and oil displacement efficiency. The CT scanning results indicate that high-salinity formation water leads to a decrease in the porosity and permeability of the core as well as pore and throat sizes under miscible pressure conditions. The experimental results of CO₂ miscible flooding demonstrate that CO₂-oil MMP decreases as the salinity of the formation water increases. Moreover, as the average water saturation in the core increases, the water block effect strengthens, resulting in an increase in MMP. The recovery factors of cores with average water saturations of 30%, 45%, and 60% are 89.8%, 88.6%, and 87.5%, respectively, indicating that the water block effect lowers the oil displacement efficiency and miscibility.

1. Introduction

Low-permeability and ultra-low-permeability reservoirs account for a large proportion of China’s proven reserves, which are highly valuable for exploitation due to their large reserves. Oil production from unconventional (low and ultra-low permeability) reservoirs ensures stable oil production in China [1,2]. CO₂ flooding is a proven enhanced oil recovery (EOR) technique in conventional reservoirs. The mechanisms of CO₂ flooding include viscosity reduction, swelling, miscibility, and re-energized reservoirs. Due to the nature of CO₂, it can be effectively utilized in tight oil and low-permeability reservoirs to improve oil recovery [3]. In addition, CO₂ injection is an important part of CO₂ utilization and storage to achieve the “dual carbon” goal [1,3]. CO₂ flooding can be classified as miscible flooding and immiscible flooding based on the minimum miscibility pressure (MMP) [4,5]. When the injection pressure is above the MMP, the CO₂ flooding is miscible flooding. CO₂ and crude oil undergo multiple contacts in miscible flooding, exchanging mass via evaporation and condensation and finally becoming miscible in one phase. Typically, CO₂ miscible flooding is applied in oilfields after water flooding in China’s domestic reservoirs. Additionally, 67% of CO₂ flooding applications were conducted after water flooding, according to statistics on CO₂ flooding projects in the United States [6]. Therefore, CO₂ flooding technology is an effective method to further enhance the oil recovery of water-flooded reservoirs. Water blocks are formed in reservoirs by either formation water or injected water through water flooding, blocking the mass transfer between CO₂ and reservoir oil [7,8]. Although water does not directly participate in the miscibility process and mass transfer of oil and gas, it indirectly affects the extraction and diffusion between the oil and gas phases.

Currently, research on CO₂ flooding focuses on migration characteristics, influencing factors of CO₂ flooding, and minimum miscibility pressure, but there is a lack of research targeting the impact of formation water. After CO₂ is injected into a reservoir, it reacts with the formation water to form carbonic acid, which causes changes in pore structure. He et al. [9] studied water–rock interaction in the CO₂ flooding process. They found that this interaction could reduce the permeability of natural fractures near the injection well, leading to improved CO₂ flooding efficiency in the fractured reservoirs. Shiraki et al. [10] investigated the main reactions occurring in rock during the CO₂ flooding process. Soong et al. [11] analyzed the rock composition during CO₂ storage in saline aquifers and found a decrease in permeability. Wdowin et al. [12] observed mineral precipitation and dissolution in rock samples before and after CO₂ sequestration using scanning electron microscopy. These studies confirmed that formation water has a negative impact on reservoir structure.

Additionally, water affects various parameters in the CO₂ flooding process based on the literature. Li et al. [13] claimed that CO₂ could reduce the interfacial tension between oil and water, resulting in enhanced oil recovery. However, the alternating gas–water effects hindered the formation of the miscible zone and CO₂-oil miscibility. They also found that injecting appropriate gas plugs could reduce the impact of water on miscibility and significantly improve oil recovery through capillary experiments and numerical simulations [14]. Lv et al. [15] used a microscopic visualization model to study the effect of high water saturation on CO₂ flooding. They concluded that high water saturation blocked the contact between CO₂ and oil, delaying miscibility and prolonging the CO₂ EOR starting time. Tang et al. [16] studied the influence of CO₂ dissolution in formation water during oil displacement using thermodynamic models. The solubility of CO₂ in water was one order of magnitude larger than that of conventional hydrocarbons, resulting in a delay in gas breakthrough time and a 6% difference in oil recovery. Hu et al. [17] investigated the mass transfer mechanisms of water flooding and CO₂ flooding, indicating that CO₂ and crude oil could become miscible under different water saturations. However, high water saturation hindered mass transfer between the oil and gas phases. Liang et al. [18] studied the influence of bound water on gravity drainage under different mixed-phase conditions, finding that bound water reduced the recovery factor under immiscible conditions but increased the recovery of gravity drainage. For the study of the water block effect formed between CO₂ and crude oil, Qin [19] used a micro-visual model to investigate the oil displacement mechanism of CO₂-penetrating water. They found that CO₂ could penetrate the water block, change the wettability between oil and pores, and displace residual oil through column and cylindrical flows in high water saturation regions. Cui et al. [20] indicated that a thicker water film prolonged the time for oil and CO₂ to become miscible through microscopic visualization experiments. Torabi et al. [21] simulated water-alternating-gas injections and found that the solubility of CO₂ in water decreased with reduced CO₂ concentrations, leading to a delay in the oil recovery increment. Kazemi et al. [22] studied the effects of viscosity, gravity, and capillary forces under different miscible and bound water conditions, concluding that the presence of water led to pore throat blocking in near-miscible flooding. Pi et al. [23] studied the interaction between CO₂, rock, and formation water, and the experimental results showed that an increase in formation water salinity reduced the CO₂-oil MMP.

The literature confirms that CO₂ and crude oil become miscible via diffusion. Du et al. [24] studied the effect of nanoconfinement on the CO₂ diffusion coefficient in shale oil reservoirs. They calculated the effective diffusion coefficient in porous media by combining the properties of the reservoir. Hoteit et al. [25,26] used numerical simulation to investigate gas injection and recovery factors in fractured and non-fractured reservoirs. They concluded that diffusion had a minimal impact on gas injection efficiency. Li et al. [27] studied oil swelling in porous media due to CO₂ diffusion and matched experimental pressure curves with mathematical models to determine the effective diffusion coefficient. Mehdi et al. [28] proposed that the solubility of CO₂ in movable oil and connate oil would affect EOR based on numerical studies using artificial intelligence technology.

Currently, the influence of formation water on reservoirs mainly focuses on the carbon sequestration area, and there is a lack of in-depth study on the variation of pore–throat parameters when CO₂ becomes miscible. Generally, water blocks have an impact on CO₂ flooding, but the degree of their influence has not been quantified. The water block effect on CO₂ flooding in the miscible state must urgently be studied. In this study, CT scanning technology was used to study the influence of CO₂-water-rock interactions on the physical properties of the core under the pressure of a miscible state. Miscible flooding experiments of CO₂ were conducted on core samples under different average water saturation conditions to reveal the effects of water blocks on CO₂ flooding. In addition, the minimum miscible pressure between CO₂ and crude oil was obtained via experimental measurements. The findings provide insights into the implementation of CO₂ flooding in the field.

2. Experimental Materials and Methods

2.1. Experimental Materials

Experimental instruments: 1172 micro-CT micro-focus computer scanner (produced by Belgian Sky Scan company, Skyscan, Belgium) with a resolution of 1.0 μm and a maximum X-ray voltage of 100 kV; Teledyne ISCO 260D high-pressure, high-precision syringe pump (produced by American Edyne Isco company, Lincoln, NH, USA) with a flow rate of 0.001–107 mL/min and a pressure of 10–7500 psi; STY-2 gas permeability tester (produced by Haian Petroleum Research Instrument Co., Ltd., Haian, China), with a permeability test range of 0.01 × 10⁻³ µm² to 6 µm².

Experimental oil: Simulated oil with a viscosity of 1.21 mPa·s, volume coefficient of 1.313, gas–oil ratio of 78.35 m³/m³, density of 0.7365 g/cm³, saturation pressure of 11.72 MPa, and experimentally measured minimum miscible pressure of 20.17 MPa.

Experimental water: Distilled water and simulated formation water, with the chemical agent ratio for simulated formation water shown in

Table 1. Composition of simulated formation water.

Compositions	Na2SO4	NaCl	Na2CO3	NaHCO3	CaCl2	MgCl2·6H2O	Salinity (g/L)
Concentration (g/L)	0.0139	0.3835	0.0539	2.262	0.01385	0.04182	2.769
	0.028	0.77	0.108	4.52	0.028	0.084	5.538

.

Experimental gas: Industrial-grade CO₂ gas (purity 99%). Experimental temperature: 69.05 °C.

Experimental core: 12 Berea cylindrical cores (core parameters shown in

Table 2. Physical properties of cores.

Core Number	Length (cm)	Cross-Sectional Area (cm2)	Permeability (×10−3 μm2)	Porosity (%)
A1	30.15	4.91	5.1	12.5
A2	30.12	4.91	5.3	12.8
A3	30.13	4.91	4.9	12.3
B1	30.54	4.91	5.3	12.7
B2	30.57	4.91	5.2	15.4

).

2.2. Experimental Methods

2.2.1. CO₂ Soaking Experiment

In order to study the interactions between CO₂-water-rock during CO₂ miscible flooding, CO₂ soaking experiments were performed using Berea cores. The interactions caused changes in pore-permeability parameters and ultimately affected CO₂-oil miscibility. After saturating the cores with formation water with varying degrees of mineralization, the CO₂ was injected under miscible pressure to study the variation patterns of pore-permeability parameters of the rocks. The 30 cm Berea cores were cut following the cutting plan shown in Figure 1. The soaking plans for CO₂ are presented in

Table 3. Soaking well plan for CO₂.

Core Number	Program
	Experimental Preparation	Plan 1	Plan 2	Plan 3	…	Plan 8
A1	Saturated with distilled water, then injected with CO2 and soaked for varying times.	Soaking 6 h	Soaking 12 h	Soaking 18 h	…	Soaking 48 h
A2	Saturated with 2.769 g/L formation water, then injected with CO2 and soaked for varying times.
A3	Saturated with 5.538 g/L formation, then injected with CO2 and soaked for varying times.

.

The experimental procedure of the CO₂ soaking experiment is as follows:

(1)

Weigh the Berea core, measure the original air permeability, saturate it with distilled water after vacuuming, and measure the original core porosity.

(2)

Dry the core in a constant-temperature oven for 48 h, cut the cores according to the plan (Figure 1), and label the cores as No. 1 to No. 9.

(3)

Scan the cross-section of core No. 1 (acting as the control group) using CT to record the distribution of the pore–throat radius in the core. Saturate cores No. 2 to No. 9 with simulated formation water after vacuuming, and soak the cores corresponding to experimental plans 1 to 8. The experimental setup (as shown in Figure 2) is used to inject CO₂, reach the experimental pressure of 21 MPa, and achieve various soaking times indicated in the experimental plans.

(4)

After soaking, slowly depressurize, remove the cores, and dry them in an oven for 48 h. Measure the air permeability and then saturate with distilled water to measure the porosity.

(5)

Take the Berea core from experimental plan 8, cut it into slices, and scan the cross-section using CT to record the distribution of the core pore–throat radius.

2.2.2. CO₂ Flooding Experiments under Different Water Saturation Conditions

Water always exists in reservoirs and affects the miscibility of CO₂ and crude oil via the water block effect. In this experiment, we evaluated the impact of the water block effect on miscible CO₂ and crude oil using different average water saturation cores. The average water saturation represents the strength of the water block effect. The CO₂ flooding experimental schemes are presented in

Table 4. CO₂ flooding experimental schemes under different water saturation conditions.

Scheme Number	Plan Details
1	Saturate with distilled water to achieve 30% average water saturation	CO2 flooding experimental pressure: 5 MPa, 10 MPa, 15 MPa, 20 MPa, 25 MPa, 30 MPa, and 35 MPa
2	Saturate with formation water with a salinity of 2.769 g/L to achieve 30% average water saturation
3	Saturate with formation water with a salinity of 5.538 g/L to achieve 30% average water saturation
4	Saturate with distilled water to achieve 45% average water saturation
5	Saturate with formation water with a salinity of 2.769 g/L to achieve 45% average water saturation
6	Saturate with formation water with a salinity of 5.538 g/L to achieve 45% average water saturation
7	Saturate with distilled water to achieve 60% average water saturation
8	Saturate with formation water with a salinity of 2.769 g/L to achieve 60% average water saturation
9	Saturate with formation water with a salinity of 5.538 g/L to achieve 60% average water saturation

, and the experimental setup is the same as that shown in Figure 2.

The experimental procedure of the CO₂ flooding experiment is presented below:

(1)

Weigh the Berea rock core under dry conditions, vacuum the core, and saturate it with simulated oil to calculate the porosity of the rock core.

(2)

Connect the experimental setup, conduct water flooding with an injection rate of 0.3 mL/min, and terminate water injection after reaching the target water saturation according to the experimental plan.

(3)

Conduct CO₂ flooding experiments with a 0.3 mL/min rate and adjust the back pressure valve pressure according to the experimental plan. Record the oil production and calculate the recovery factor when no oil is produced under this pressure condition.

(4)

Adjust the pressure of the back pressure valve to the next pressure point, increase the injection pressure above the experimental pressure, and continue the CO₂ flooding experiment. Complete the CO₂ flooding experiment after finishing testing all 7 experimental pressures.

3. Results and Discussion

3.1. Changes in Porosity and Permeability

The changes in the porosity and permeability of the Berea rock core after being saturated with different simulated formation water levels and various CO₂ soaking times are shown in Figure 3 and Figure 4. The porosity and permeability of the Berea rock core initially increase and then decrease with soak time. For the core saturated with distilled water, the ultimate porosity and permeability slightly increase compared to its original state. However, the cores saturated with simulated formation water decrease in both porosity and permeability. The higher the salinity, the more significant the decrease in porosity and permeability. The cores saturated with water of salinity 2.769 g/L and 5.538 g/L lead to a decrease in porosity by 2% and 2.7% and a decrease in permeability by 1.5 × 10⁻³ μm² and 2.4 × 10⁻³ μm², respectively.

The main mineral components of the cores are quartz, potassium feldspar, plagioclase, clay minerals, and carbonate minerals (calcite, dolomite, and aragonite). CO₂ dissolves in water to form carbonic acid through the reaction shown in the chemical Equation (1). The corrosiveness of carbonic acid increases as pressure in multiphase conditions increases, leading to dissolution reactions with calcite and dolomite [29,30]. Chemical Equations (2) and (3) show the chemical changes resulting from these reactions. As the reactions continue, the dissolution of the above components leads to an increase in the concentration of calcium and magnesium ions. Followed by precipitation reactions, calcium and magnesium ions gradually react with bicarbonate ions in the formation water to form insoluble carbonates, as shown in chemical Equations (4) and (5).

$${\mathrm{CO}}_2+{\mathrm{H}}_2\mathrm{O}={\mathrm{HCO}}_3^{-}+{\mathrm{H}}^{+}$$

(1)

$$\mathrm{CaMg}{\left(\mathrm{C}{\mathrm{O}}_3\right)}_2+2{\mathrm{H}}^{+}={\mathrm{Ca}}^{2+}+{\mathrm{Mg}}^{2+}+2{\mathrm{HCO}}_3^{-}$$

(2)

$$\mathrm{Ca}({\mathrm{Fe}}_{0.7}{\mathrm{Mg}}_{0.3}){\left(\mathrm{C}{\mathrm{O}}_3\right)}_2+2{\mathrm{H}}^{+}={\mathrm{Ca}}^{2+}+0.3{\mathrm{Mg}}^{2+}+0.7{\mathrm{Fe}}^{2+}+2{\mathrm{HCO}}_3^{-}$$

(3)

$${\mathrm{Mg}}^{2+}+{\mathrm{HCO}}_3^{-}={\mathrm{MgCO}}_3\downarrow + {\mathrm{H}}^{+}$$

(4)

$${\mathrm{Ca}}^{2+}+{\mathrm{HCO}}_3^{-}={\mathrm{CaCO}}_3\downarrow + {\mathrm{H}}^{+}$$

(5)

The analysis results suggest that the higher the mineralization, the lower the solubility of CO₂ in water. For the core saturated with distilled water, the acidity of carbonic acid is enhanced, increasing the dissolution effect on the reservoir and generating numerous secondary pores. However, the subsequent precipitation of insoluble carbonates gradually migrates to smaller pore throats, blocking the channels with smaller radii. Pi et al. [23] studied the reaction among CO₂, formation water, and rock. The dissolution of CO₂ in the formation water resulted in a decrease in the pH of the formation water from 7.4 to 6.5. With the continued injection of CO₂, the pH of the formation water increased and then decreased. In general, cores saturated with distilled water have lower mineral ion concentrations, dominated by dissolution, resulting in a slight increase in overall porosity and permeability. In contrast, cores saturated with formation water have higher calcium and magnesium ion concentrations, with precipitation dominating, leading to a significant decrease in overall porosity and permeability. Due to the utilization of low-permeability cores in the experiment, alterations in both porosity and permeability exhibit a significantly more noticeable impact.

The CT scan results of the core after 48 h of soaking are shown in Figure 5. The porosity of the core saturated with distilled water is slightly larger than that of the control group. After saturation with formation water with different salinity levels, both the pores and pore throats decrease in size—higher salinity results in larger changes. As a result of precipitation, the dimensions of the primary large pores undergo a noticeable reduction, while numerous secondary pores emerge, thereby instigating substantial alterations in porosity.

3.2. Distribution of Pore Radius and Throat Radius

The distribution of the core’s pore radius and throat radius after 48 h of CO₂ soaking was calculated, and the experimental results are shown in Figure 6, Figure 7, Figure 8 and Figure 9.

After 48 h of soaking in saturated distilled water, the distribution of pore radii below 15.44 μm decreases, while the distribution of pore radii above 19.48 μm increases for the Berea cores. In addition, for cores saturated with formation water with a salinity of 2.769 g/L and 5.538 g/L, the distribution of pore radii below 19.48 μm increases, while the distribution of pore radii above 19.48 μm decreases. Therefore, higher salinity results in a higher distribution of small-size pores. The pattern of throat radius distribution is consistent with that of pore radius distribution, and the distribution of small throats increases as salinity increases. These observations indicate that increasing salinity gradually alters the dominant factor in the pore and throat radius from dissolution to precipitation, causing the blockage of large pores and an increase in the distribution of small pores.

3.3. MMP Alterations under Different Water Saturations

Figure 10 shows the results of MMP experiments at different average water saturations. The MMPs were determined using the slim tube experiment, which was obtained by intersecting the trend lines of the immiscible region recovery rate and the miscible region recovery rate. This experimental pressure represents the minimum pressure required to achieve maximum recovery under different water block conditions. The results indicate that the MMP between CO₂ and oil decreases as the salinity of the formation water increases, and a stronger water block effect (higher average water saturation) leads to a higher MMP. When the average water saturation of the cores is 30%, the obtained MMP values of distilled water, salinity of 2.769 g/L, and salinity of 5.538 g/L scenarios are 20.73 MPa, 20.27 MPa, and 19.33 MPa, respectively. As the average water saturation increases to 45%, the MMP values are 21.25 MPa, 20.66 MPa, and 19.65 MPa, respectively. Further increasing the average water saturation to 60%, the MMP values are 21.89 MPa, 21.01 MPa, and 19.97 MPa, respectively.

Based on the above results, it can be concluded that the salinity of formation water affects the pore–throat structure of the core under miscible pressure, resulting in a decrease in porosity and an increase in small pore channels. The contact surface between oil, gas, and water phases is segmented and compressed, leading to intense mass transfer between CO₂ and crude oil and a slight decrease in MMP.

3.4. Changes in Oil Displacement Effect under Different Water Saturation

The oil recovery of CO₂ miscible flooding experiments is shown in

Table 5. Recovery factors of CO₂ miscible flooding experiments.

Category	Recovery Factors (%)
	Distilled Water	Salinity of 2.769 g/L	Salinity of 5.538 g/L
Average water saturation 30%	89.8	89.1	87.4
Average water saturation 45%	88.6	87.4	85.2
Average water saturation 45%	87.5	85.8	83.3

. The stronger the water block effect, the lower the oil recovery. The average water saturation increases from 30% to 60%. The core samples saturated with distilled water and formation water with a salinity of 2.769 g/L and 5.538 g/L show a decrement in oil recovery of 2.3%, 3.3%, and 4.1%, respectively. These recovery factor decreases are caused by three reasons: (1) The water phase is the wetting phase, which easily enters the small pore throat and traps the residual oil at the dead-end. This phenomenon increases the difficulty of oil recovery, leading to a lower recovery factor. (2) Water affects the mass transfer process between CO₂ and crude oil as the water block effect strengthens, changing the contact mode from direct contact to indirect contact that CO₂ dissolves in water and then comes into contact with crude oil. This change reduces the contact area and decreases the efficiency of miscible flooding. (3) The water block increases MMP and reduces the miscibility, resulting in lower oil recovery. The impact of the formation water salinity on oil recovery is analyzed as follows: the increase in secondary pores enhances the complexity of dead-end residual oil, making it challenging to recover crude oil from dead-end pores and eventually reducing the overall oil recovery.

4. Conclusions

(1)

In the case of miscible flooding, highly mineralized formation water can enhance precipitation, resulting in a decrease in core porosity and permeability as well as a reduction in pore and throat size.

(2)

The higher the average water saturation of the core, the stronger the water block effect and the higher the MMP. However, the formation water with high salinity can decrease the MMP between CO₂ and crude oil. Overall, the impact of the formation water’s salinity is greater than the impact of the average water saturation of the core.

(3)

The average water saturation impacts the oil displacement and the miscible behavior of CO₂ for three reasons: an increase in the proportion of residual oil in dead-end pores, a decrease in the oil displacement efficiency of CO₂ with crude oil, and a decrease in the miscibility. Additionally, the decrease in porosity and permeability of the reservoir makes it challenging to extract the crude oil, thereby affecting the oil displacement.