EXPERIMENTAL INVESTIGATION OF THE EFFECTS OF TEMPERATURE AND OIL COMPOSITION ON CO2-CRUDE OIL SWELLING, EXTRACTION MECHANISMS, AND DISPLACEMENT PERFORMANCE

1. Introduction

CO₂ flooding is a promising Enhanced Oil Recovery (EOR) method that has successfully increased oil production (Ghorbani et al., 2014; Hartono et al., 2021; Zhang et al., 2019). The fundamental mechanism between CO₂ and crude oil interactions is shown in CO₂ solubility (Rezk & Foroozesh, 2019). During the interaction of CO₂ in hydrocarbon oils, the CO₂ will diffuse into these oils and cause the oils to swell (Holm & Josendal, 1974; Wei et al., 2017; Yang & Gu, 2006). The swelling phenomenon will help crude oil obtain several advantageous characteristics in oil recovery, such as lower viscosity, interfacial tension (IFT) reduction, and a larger volume. Furthermore, CO₂ has the ability to extract or vaporize light to intermediate hydrocarbons from crude oil. The extraction mechanism of CO₂-hydrocarbon becomes the principle in developing multi-contact miscibility (Permadi et al., 2021; Siagian & Grigg, 1998; Yellig, 1982). Therefore, the swelling and extraction phenomena in the CO₂ and crude oil interactions are the fundamental mechanisms for oil recovery. An increase in CO₂ injection pressure enhances both its solubility in oil and the oil swelling effect. Conversely, raising the temperature reduces CO₂ solubility, as CO₂ molecules become more active at elevated temperatures, which diminishes their interaction with crude oil (Fakher & Imqam, 2020; Svrcek et al., 1982). Fakher & Imqam (2020) concluded that oil swelling strongly depends on CO₂ injection pressures and reservoir temperatures. Many studies investigated the oil swelling and extraction mechanisms in the interactions of CO₂ and crude oil systems. Also, the swelling and extraction mechanisms have received attention from several researchers to determine the miscibility pressure of CO₂ and crude oil. However, most previous studies and experiments were conducted at relatively low temperatures. Only a few have focused on its application at high reservoir temperatures and the effects of oil composition on swelling extraction mechanisms and CO₂ displacement performance. Investigating the swelling and extraction mechanisms in high-temperatures environments is important for applying CO₂ flooding at high reservoir temperatures. For example, most of Indonesia’s oil fields have reservoir temperatures above 90°C. Fakher & Imqam (2020), based on their data analysis, showed that most swelling tests were conducted at the temperature range of 20 – 50°C. The interpretation of the swelling test data at 20 - 50°C might differ with the higher temperature. Therefore, more swelling test data for high reservoir temperatures is needed to understand the swelling and extraction mechanisms for applying CO₂ flooding in high reservoir temperatures.

Moreover, the extraction of hydrocarbons by dense CO₂ is also strongly influenced by crude oil compositions (Orr & Silva, 1987; Silva et al., 1987). As the principle of multi-contact miscibility in the interaction of CO₂ and crude oil system, the extraction mechanism will significantly affect CO₂ displacement performance, such as oil recovery. As previously mentioned, only a few studies have investigated the effects of temperatures and oil composition on swelling extraction mechanisms and CO₂ displacement performance. Therefore, the comprehensive study investigated the effect of temperature and crude oil compositions on swelling–extraction mechanisms and the impact on CO₂ displacement performance, particularly in high reservoir temperatures, are limited. Understanding the effect of temperatures and oil compositions on CO₂ EOR fundamental mechanisms such as swelling-extraction and CO₂ flow mechanisms in porous media is vital to optimizing CO₂ flooding process implementation. Siagian & Grigg (1998) studied the capacity of CO₂ in extracting hydrocarbons from crude oil as a function of pressure at relatively low temperatures of 35°C and 59°C and compared the results with the slim tube experiments. The findings showed that the CO₂ extraction capacity increased with increasing pressure and formed a sharp transition pressure range which corresponded effectively with the slim tube breakpoint or Minimum Miscibility Pressure (MMP). They considered that the sharp transition pressure range could be used to estimate the MMP reasonably. However, their study did not investigate the effect of change in crude oil composition due to the extraction of light–intermediate hydrocarbon on CO₂ displacement performance. Tsau et al. (2010) investigated the effect of temperature on swelling and extraction at 37°C – 52°C with a small sample size of 3-14 cc. They showed that at a given pressure, the swelling factor of oil decreases with an increase in temperature. The results also showed that the pressure at which extraction starts by CO₂ depends on the initial volume of oil and temperatures. They concluded that the intersection of significant extraction lines could determine the miscibility at these temperature conditions. Abdurrahman et al., investigated the swelling phenomena at 60°C and 66°C using light crude oil samples (Abdurrahman et al., 2015 & 2019). They proposed three stages in swelling factor versus pressure plot: condensation stage, condensation and extraction stage, and extraction stage. They also estimated the MMP using the slim tube but did not investigate the effect of oil composition on the CO₂ displacement performance.

As discussed earlier, the extraction mechanism is a key principles of CO₂ - enhanced oil recovery and will impact displacement performance in porous media. This study aims to provide a comprehensive assessment of the effects of temperature and crude oil composition on swelling–extraction mechanisms and their subsequent impact on displacement performance efficiency. To achieve this, a series of high-pressure, high temperature (HPHT) visual PVT experiments were performed using light oil crude from an Indonesian oil field to obtain swelling data. The observation of CO₂ displacement performance was performed using a slim tube apparatus. The experiments were conducted at 90°C, representing the reservoir temperature. Then, it was re-conducted at 70°C, approximately the average of wellbore temperature condition. This study is expected to provide more data on the swelling and extraction mechanisms for implementing CO₂ flooding at high reservoir temperatures. Moreover, this study is also expected to provide insight into understanding the effect of different parameters such as, temperatures and oil compositions, on CO₂ flow mechanisms in porous media and optimizing CO₂ flooding process implementation.

2. Materials and Experimental Methods

The materials or crude samples in this study were taken from Indonesian oilfield. This experimental was conducted at different crude samples, pressures, and temperatures.

2.1.Materials

Crude oil samples used in this study were dead crude oil with 42^oAPI and 36^oAPI obtained from the RDG and JTB Indonesian oilfield, respectively. The fluid reservoir properties and compositions of the crude oil samples are shown in Table 1 and Table 2, respectively. Meanwhile, Table 3 shows the composition of the crude oil measured based on the fractions of saturates, aromatics, resins, and asphaltenes (SARA). Moreover, the CO₂ used for gas injection was ultra-high pure (99.9%). The field's average reservoir temperature was found to be 90°C which was set as a temperature condition during experiments. The experiment was repeated at 70°C, which approximates the average of wellbore temperature condition, to observe the influence of temperature on oil swelling, extraction behaviour, and the effectiveness of CO₂ displacement.

Table 1. Properties of Dead Oil Samples

Table 2. Compositions of Dead Oil Samples

Table 3. The Composition of SARA Components

2.2. Experimental Apparatus

The experiments were carried out using two main high-pressure and high-temperature (HPHT) systems. The PVT apparatus was utilized to analyze the swelling and extraction behaviour, while the slim tube apparatus was employed to evaluate oil recovery and CO₂ displacement efficiency. Additionally, fluid composition analysis was performed using the Agilent 7890B Gas Chromatography (GC) system.

2.2.1. PVT Set-up

A visual PVT cell was employed to examine CO₂–crude oil interactions under varying conditions. The cell, equipped with a sight glass and magnetic stirrer, allows real-time observation and mixing of fluids. A rotating mechanism was incorporated to accelerate phase equilibrium, while pressure control was achieved through an internal moving piston. Temperature was maintained using a thermostatically controlled oven with a circulating bath. The gas–oil interface was monitored using a high-resolution camera, and key parameters—pressure, temperature, volume, and visual data—were recorded via an integrated data acquisition system. The simplified diagram of visual PVT system is presented in Figure 1.

Figure 1. Schematic Diagram of Visual Fluid Eval PVT System

2.2.2. Slim tube Apparatus

The slim tube apparatus system used in this study was STS 700 with the specifications of high pressure and high temperature measurement. The detail specifications of the slim tube are as stated in Table 4. In general, the slim tube consist of a coil tube with sand pack and includes several components: high-pressure floating piston accumulators for oil, gas, and solvent; oven with a temperature-controller; a back-pressure pump; a gasometer; a remote-control panel; and visual cell. Additionally, a densitometer is installed to monitor the density of fluids exiting the slim tube. The system is illustrated in Figure 2.

Table 4. The Specifications of Slim Tube Apparatus

Figure 2. Schematic Diagram of Slim Tube System

3. Results and Discussions

The discussion begins by examining how temperature and oil composition influence the swelling and extraction mechanisms. This is followed by an analysis of how these same factors affect CO₂ flow behaviour and displacement efficiency within porous media. Additionally, changes in oil composition, specifically the SARA (Saturates, Aromatics, Resins, and Asphaltenes) fractions, resulting from CO₂ injection are also evaluated to understand their impact on the overall displacement performance.

3.1. Effect of Temperature on Swelling – Extraction Mechanisms

The swelling and extraction phenomena of CO₂ and crude oil were observed at different pressures and temperatures. The results of swelling factor versus pressure at temperatures of 70°C and 90°C for JTB and RDG crude samples are shown in Figures 3 and 4, respectively. The swelling curves are divided into three stages, as suggested by Abdurrahman et al. (2015) and Siagian & Grigg (1998). The first stage, known as the condensation region, is characterized by an increase in the swelling factor as pressure rises. The second stage represents the condensation and extraction region, where the oil phase volume drops sharply. The third stage, the extraction region, shows a more gradual decrease in oil phase volume with increasing pressure. The data indicate that the rate of oil swelling declines as temperature increases. Figure 3 for JTB oil shows that the peak of the swelling factor at 90°C is slightly higher than 70°C. Then, the oil volume starts to decrease rapidly at 2500 Psi, indicating that some hydrocarbon components are extracted by dense CO₂. The condensation and extraction regions also show that the oil phase volume of JTB at 70°C decreases sharper than at 90°C. It indicates that CO₂ has a higher capacity to extract hydrocarbon components at lower temperatures than at higher temperatures at the given pressures.

Figure 4 presents the swelling factor as a function of pressure for RDG crude oil. Similar to the trend observed in JTB oil, the swelling rate at 70°C is greater than at 90°C. For the RDG sample, the maximum swollen oil volume reached almost one and half times the initial volume at both 70°C and 90°C. It was found from the figures that the rate of oil swelling decreased as the temperature increased for both samples and a similar trend was observed to have been reported by Hand & Pinczewski (1990) and Rezk & Foroozesh (2019). The influence of crude oil composition on the CO₂ flooding flow mechanisms within porous media will be explained detail in the subsequent chapter.

Figure 3. Swelling Factor curves of CO₂ – JTB oil sample at 70°C and 90°C with various pressures

Figure 4. Swelling Factor curves of CO₂ – RDG oil sample at 70°C and 90°C with various pressures

3.2. Effect of Oil Composition on Swelling – Extraction Mechanisms

The influence of oil composition on swelling and extraction mechanisms is shown by comparing the swelling and extraction curves of JTB and RDG crude oil samples, as presented in Figures 3 and 4, respectively. Even though JTB oil has a higher Molecular Weight (MW) than RDG oil, the pressure required to achieve maximum swell is similar at 90°C. However, at a temperature of 70°C, the pressure required to achieve maximum swell for RDG crude samples was lower than that for JTB oil. Interestingly, JTB oil has a more significant decrease in the condensation-extraction region than RDG oil, although JTB has a higher molecular weight or is heavier than RDG oil. It should be noted that the extraction of hydrocarbon components from oil increases as the gas density increases with the pressure (Dindoruk et al, 2020). However, the amount of extraction also depends on the composition of the oil, particularly the fraction of the oil that includes components that are soluble in dense CO₂. Hence, it requires to be observed the compositions of oil samples.

The extraction phenomena occurred in JTB and RDG oil samples can be seen from the changes of hydrocarbon compositional of the original oil sample and the characterization of the residue oil with various CO₂ injection pressures at a temperature of 90°C, as shown in Figures 5 and 6, respectively. Figures 5 and 6 show that the mole percentage of intermediate components (C₆-C₉) reduces with increasing CO₂ injection pressures. On the other hand, the heavier components (C₂₃-C₃₀) showed a relatively higher mole percentage with increasing CO₂ injection pressures. The depletion of light - intermediate hydrocarbon fractions results in an increase in the bulk fluid density. This compositional shift can also enhance asphaltene solubility, as the removal of volatile components alters the thermodynamic equilibrium and promotes the incorporation of higher-molecular-weight asphaltenes into the crude oil phase (Kokal & Sayegh, 1995; Rezk & Foroozesh, 2019). During CO₂ flooding, the properties of both produced and residual oils can be altered through mutual interaction between CO₂ and crude oil. A reduction in the mole fraction of light to intermediate components—primarily within the saturates fraction—can compromise crude oil stability, leading to the precipitation of heavier hydrocarbon constituents such as asphaltenes (Wang et al., 2016).

Hagedorn & Orr (1994) reported that ring structures of components generally reduce solubility, especially for multi-ring aromatics. As indicated by the SARA analysis in Table 3, the RDG crude oil sample contains a higher fraction of aromatics compared to JTB oil. Aromatics are hydrocarbon components that are generally nonpolar, distinguished by their unsaturated ring structures containing multiple carbon–carbon double bonds (Fakher et al., 2020).

Figure 5. Hydrocarbon compositions of the original JTB sample and the residual oil after the swelling test at 90°C

Figure 6. Hydrocarbon compositions of the original RDG sample and the residual oil after the swelling test at 90°C

3.3. Effect of Temperature on CO₂ Displacement Performance

The performance of CO₂ displacement was examined using a slim tube through seven experimental runs conducted at varying pressures and temperatures. The experiments were carried out at high pressures of 1000 to 5000 Psi and the oil recovery outcomes from the CO₂ flooding process are shown in Table 5. Each displacement test was initially conducted at 90°C, representing the average reservoir temperature, and then repeated at 70°C, which reflects the wellbore temperature condition. As shown in Table 5, oil recovery at 70°C is lower compared to 90°C for both RDG and JTB crude oil samples. Specifically, the maximum recovery at 70°C reached 85.7% for RDG and 89% for JTB, while at 90°C, the recoveries increased to 93.5% and 94.5%, respectively. These results suggest that higher temperatures enhance oil recovery, which is likely due to the reduction in oil viscosity with increasing temperature (Maqbool et al., 2011). Therefore, the oil recovery results from the CO₂ displacement tests are crucial for determining the MMP.

Table 5. Recovery Factor (%) obtained from slim tube experiments at 70°C and 90°C

MMP values for JTB and RDG samples are presented in Figure 7 and 8, respectively. The MMP was determined by plotting recovery factor (%) values against the corresponding injection pressures, as described by Glaso (1990) and Hudgins et al. (1990). Figure 7 shows that the MMP for JTB oil is higher at a higher temperature. Additionally, the figure suggests that miscibility between CO₂ and the crude oil occurs within the extraction region, indicating that the extraction of hydrocarbon components by CO₂ plays a significant role in achieving miscibility. On the other hand, for the RDG crude oil, Figure 8 demonstrates that the MMP at 70°C is notably higher compared to that at 90°C. This phenomenon shows that the extraction of hydrocarbon components by CO₂ is one of the mechanisms of miscibility. In contrast to the MMP of the JTB oil sample, the RDG oil shows that the MMP at 70°C is much higher than at 90°C, as shown in Figure 8. According to Lashkarbolooki & Ayatollahi (2018) and Yellig & Metcalfe (1980), an increase in temperature typically leads to a rise in MMP. However, some of the MMP data summarized from the literature showed that some oil fields with lower reservoir temperatures have higher MMP than those with higher reservoir temperatures, as shown in Figure 11. Therefore, the experimental results on the effect of temperature on displacement performance require further analysis to investigate the effect of oil compositions on the CO₂ displacement process in porous media. The effect of oil composition on displacement performance will be discussed in the subsequent section.

Figure 7. MMP Estimation from slim tube and Swelling Factor JTB oil at 70°C and 90°C

Figure 8. MMP Estimation from slim tube and Swelling Factor RDG oil at 70°C and 90°C

3.4. Effect of Oil Composition on CO₂ Displacement Performance

As previously discussed, Figure 8 shows that the MMP for the RDG sample at a temperature of 70°C is much higher than at 90°C, which contrasts with the JTB oil sample. Therefore, further investigation into the influence of oil composition on CO₂ displacement is important. In this study, the impact of oil composition was examined by analyzing changes in crude oil resulting from CO₂–oil interactions. This was achieved through SARA fraction analysis of produced oil obtained from slim tube experiments at each injection pressure. Figures 9 and 10 present the changes in the wt.% of resins and asphaltene fractions from the produced oil of RDG and JTB samples, respectively. Notably, JTB crude oil is classified as heavier than the RDG and initially contains a higher concentration of asphaltenes. Interestingly, the MMP for RDG at 70°C is considerably higher than at 90°C. The data in both tables reveal a general trend of decreasing resin and asphaltene content with increasing CO₂ injection pressure. Although JTB oil exhibits a higher initial asphaltene content than RDG, it also possesses a higher resin fraction.

Asphaltenes are among the most complex constituents of crude oil, characterized by their insolubility in normal alkanes and composed of highly polar, structurally intricate molecules (Fakher et al., 2020; Soleymanzadeh et al., 2019). In contrast, resins contribute significantly to the stability of crude oil by exhibiting both polar and non-polar properties, enabling them to function as peptizing and bridging agents that connect polar asphaltenes with non-polar hydrocarbon components (Miadonye & Evans, 2010). The observed decline in asphaltene content with increasing injection pressure indicates potential asphaltene deposition within the porous media. This phenomenon is likely driven by a concurrent reduction in resin concentration, which weakens the peptizing effect necessary to maintain asphaltene dispersion. As reported by Deo & Parra (2012), repeated between CO₂ - crude oil interactions can result in asphaltene precipitation within the reservoir. Such deposition may adversely affect both the efficiency of oil recovery and the MMP.

Figure 9 shows that the resin and asphaltene content of RDG oil at 70°C (see Figure 9a) decrease more significantly than at 90°C (see Figure 9b). The decreasing of resin and asphaltene also indicates that temperatures also affect the change of SARA composition during the CO₂ flooding process, which can cause the possibility of the asphaltene precipitation phenomenon in porous media. It can be seen that at 70°C, the resin reduces from 3.9 wt.% at initial composition (before CO₂ was injected) to 1.3 wt.% at a CO₂ injection pressure of 4000 Psi. The asphaltene fraction also reduces from 1.8 wt.% to 0.9 wt. % at 4000 Psi. The reduction in resin and asphaltene content at 70°C is more pronounced compared to 90°C, resulting in lower oil recovery at the lower temperature. A similar finding was also reported by Hagedorn & Orr (1994) that crude oils containing substantial amounts of multi-ring aromatic compounds face challenges in achieving miscibility with CO₂. These aromatic compounds are not easily extracted by dense CO₂, leading to decreased oil recovery in slim tube tests at a given pressure and consequently requiring a higher MMP. As shown in Table 3, RDG sample contains a higher proportion of aromatic components compared to JTB crude oil.

Figure 9. Resin and Asphaltene Fraction (wt.%) of RDG sample at (a) 70°C and (b) 90°C in varying injection pressures

Figure 10 also presents the resin and asphaltene content of JTB oil at 70°C (see Figure 10a) and 90°C (see Figure 10b) under varying pressures. Although the initial asphaltene fraction in JTB is higher than in RDG, the resin content in JTB is also significantly greater. In contrast, the initial aromatic fraction in JTB oil is lower than in RDG oil. As previously discussed, dense CO₂ has limited ability to extract multi-ring aromatic compounds. Due to its high resin and lower aromatic content, JTB crude exhibits greater stability compared to RDG. Consequently, asphaltene precipitation is more likely to occur in RDG oil upon CO₂ injection, despite RDG having a higher API gravity. This difference results in lower oil recovery from CO₂ flooding process in the RDG crude than in the JTB crude.

The findings indicate that variations in pressure, temperature, and crude oil composition resulting from CO₂ injection significantly influence the efficiency of CO₂ displacement. These factors, in turn, affect both oil recovery and the determination of the MMP. The performance of the displacement process is closely linked to the collective behaviour and proportion of all crude oil components—saturates, aromatics, resins, and asphaltenes—as shown in Table 3, rather than being attributed to a single component alone. The findings are also aligned with the work by Fan et al. (2024) that investigated the effect of some complex components in the interaction of the CO₂ and crude oil by the insight of convolutional neural networks.

Figure 10. Resin and Asphaltene Fraction (wt.%) of RDG Sample at (a) 70°C and (b) 90°C in Varying Injection Pressures

Figure 11. Minimum Miscibility Pressure (MMP) oil fields data vs. Reservoir Temperatures (summarized from Hagedorn & Orr, 1994 and Orr & Silva, 1987)

4. Conclusions

This study investigated the effect of temperature and oil compositions on swelling-extraction behaviour and CO₂ displacement mechanisms. Understanding the influence of temperatures and oil compositions on CO₂ EOR fundamental mechanisms such as swelling-extraction and CO₂ flow mechanisms in porous media is vital to optimizing CO₂ flooding process implementation. This study is expected to provide more data on the swelling and extraction mechanisms for implementing CO₂ flooding at high reservoir temperatures. Moreover, this study is also expected to provide insight into understanding the effect of different parameters such as, temperatures and oil compositions, on CO₂ flow mechanisms in porous media and optimizing CO₂ flooding process implementation. The main conclusions from the research that has been carried out are shown below.

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Author’s contribution

Kartika F. Hartono (Dr.): conceptualization, methodology, validation, formal analysis, investigation, writing – original draft, and visualization. Asep K. Permadi (Prof.): conceptualization, formal analysis, writing – review & editing, and supervision. Utjok. W. R. Siagian (Dr.): conceptualization, formal analysis. Andri, L. L. Hakim (Dr.): conceptualization, formal analysis, writing – review & editing. Sumadi Paryoto: resources, methodology, project administration. Ahlul H. Resha: resources, methodology, and project administration. Syaeful A. Satya: methodology, and project administration. Reno Pratiwi (Dr.), Maman Djumantara, Dina A. Chusniah: writing – review & editing.

All authors have read and agreed to the published version of the manuscript.