Comprehensive experimental study to compare the effects of flue gases and CO 2 injection on enhancing oil recovery and asphaltene deposition

Comprehensive experimental study to compare the effects of flue gases and CO 2 injection on enhancing oil recovery and asphaltene deposition | Research Square window.SnipcartSettings = { analytics: { enabled: false } }; (function() { var accessVector = localStorage.getItem('access_vector') || ''; window.dataLayer = window.dataLayer || []; if (accessVector) { window.dataLayer.push({ user: { profile: { profileInfo: { snid: accessVector } } } }); } })(); (function(w,d,s,l,i){w[l]=w[l]||[];w[l].push({'gtm.start':new Date().getTime(),event:'gtm.js'});var f=d.getElementsByTagName(s)[0],j=d.createElement(s),dl=l!='dataLayer'?'&l='+l:'';j.async=true;j.src='https://www.googletagmanager.com/gtm.js?id='+i+dl;f.parentNode.insertBefore(j,f);})(window,document,'script','dataLayer','GTM-K279D39R'); Browse Preprints In Review Journals COVID-19 Preprints AJE Video Bytes Research Tools Research Promotion AJE Professional Editing AJE Rubriq About Preprint Platform In Review Editorial Policies Our Team Advisory Board Help Center Sign In Submit a Preprint Cite Share Download PDF Article Comprehensive experimental study to compare the effects of flue gases and CO 2 injection on enhancing oil recovery and asphaltene deposition Parviz Darvishi, Keyvan Eghtedari, Asghar Lashanizadegan, Shahin Kord This is a preprint; it has not been peer reviewed by a journal. https://doi.org/ 10.21203/rs.3.rs-6779359/v1 This work is licensed under a CC BY 4.0 License Status: Under Review Version 1 posted 10 You are reading this latest preprint version Abstract Non-hydrocarbon injection gases, such as carbon dioxide (CO 2 ) and flue gas, offer cost-effective and environmentally friendly alternatives to traditional hydrocarbon gases for enhanced oil recovery (EOR). However, issues such as asphaltene deposition and formation damage challenge their use in tight carbonate reservoirs. While CO 2 injection has been extensively studied, experimental data on flue gas remain limited. This study presents a detailed experimental comparison of CO 2 and synthetic flue gas through eight core flooding tests using recombined live oil and two low-permeability carbonate cores. Effects of gas type, pressure, temperature, and injected gas volume on oil recovery, asphaltene deposition, and permeability reduction were evaluated. CO 2 injection yielded approximately 15% higher oil recovery than flue gas at the same pressure. However, for equal injected volumes, the flue gas achieved 16 to 46% higher recovery, indicating a more efficient use. Comparable oil recovery was achieved by injecting flue gas at 20 to 30% higher pressure with 10 to 15% less gas volume. Additionally, CO 2 caused up to 18.6% more asphaltene deposition and 67% more formation damage than flue gas under identical conditions. This study also investigates the role of injection pressure and temperature in influencing formation damage behavior. The results confirm that flue gas injection can be used as an alternative to CO 2 for EOR in carbonate reservoirs. Physical sciences/Energy science and technology/Carbon capture and storage Physical sciences/Energy science and technology/Fossil fuels Asphaltene deposition CO2 injection Enhanced oil recovery Flue gas injection Formation damage Permeability reduction Figures Figure 1 Figure 2 Figure 3 Figure 4 Figure 5 Figure 6 Figure 7 Figure 8 Figure 9 Figure 10 Figure 11 Figure 12 Figure 13 Figure 14 Figure 15 Figure 16 Figure 17 Figure 18 Figure 19 Figure 20 Figure 21 Figure 22 Figure 23 Figure 24 Figure 25 Introduction Due to the daily increase in the need for hydrocarbon fluids, increasing the cost-effectiveness of recovery from oil and gas reservoirs has become one of the topics of interest [ 1 ]. After primary and secondary recovery, approximately 50 to 60% of the original oil in place (OOIP) typically remains unrecovered [ 2 – 4 ]. These conventional recovery methods often lack the efficiency needed for effective extraction. As a result, enhanced oil recovery (EOR) techniques have become the most widely adopted approach for maximizing oil production in the later stages of reservoir development [ 5 – 8 ]. Numerous studies have demonstrated the importance of EOR methods and the need to improve their effectiveness [ 9 – 14 ]. Among the various EOR strategies developed, gas injection, thermal injection, and chemical injection are the three primary techniques [ 15 ]. Of these, gas flooding methods are especially prominent in the oil industry due to their reliability and proven success in improving recovery rates [ 4 , 16 , 17 ]. Continued research and development in this field remain critical to overcoming current limitations and optimizing oil recovery. Gas injection processes utilize a range of gases, with carbon dioxide (CO 2 ), natural gas, and nitrogen (N 2 ) being among the most commonly applied [ 18 – 20 ]. Extensive research has investigated CO 2 injection in EOR processes due to its notable impact on sweep efficiency and its role in reducing greenhouse gas emissions [ 21 – 24 ]. Generally, CO 2 -based tertiary recovery methods have been reported to increase oil recovery efficiency by approximately 8 to 16% [ 25 ]. The success of CO 2 flooding is primarily attributed to its ability to reduce oil viscosity, induce oil swelling, and alter the interfacial properties of the crude oil–CO 2 system. These effects collectively contribute to enhancing the overall efficiency of oil recovery [ 26 , 27 ]. Flue gas has also gained significant attention in recent years as a potential agent for enhanced oil recovery [ 28 ]. As a byproduct of industrial combustion processes such as fuel burning and cement production, it is readily available, low cost, and primarily composed of N 2 and CO 2 , along with variable amounts of sulfur dioxide (SO 2 ), nitrogen oxides (NO x ), carbon monoxide (CO), hydrogen sulfide (H 2 S), and particulate matter, depending on the combustion material used [ 29 , 30 ]. Compared to pure CO 2 injection, flue gas presents distinct advantages due to its diverse composition. While it shares certain properties with CO 2 , the presence of nitrogen and other components enables a broader impact on EOR performance. This mixture enhances oil recovery by altering reservoir fluid properties and improving sweep efficiency, while also contributing to environmental sustainability by repurposing industrial emissions [ 31 – 34 ]. As a result, many researchers and companies are actively evaluating flue gas injection as a promising and versatile approach for EOR applications [ 33 ]. Its ability to simultaneously improve oil recovery and mitigate the environmental impact of greenhouse gas emissions highlights its value as a comprehensive EOR solution [ 35 ]. When gas is injected into an oil reservoir, it comes into contact with the reservoir oil and alters the equilibrium conditions and fluid properties, potentially leading to the precipitation of heavy organic compounds, primarily asphaltenes [ 19 , 36 ]. This issue presents a significant technical obstacle, where determining the potential for asphaltene precipitation and assessing its impact on process performance are essential for successful field applications. Therefore, it is vital to investigate the factors that influence asphaltene precipitation. Asphaltenes represent a complex mixture of structurally diverse molecules, primarily characterized by their solubility rather than specific structural and chemical properties. They are insoluble in light hydrocarbon solvents like n-alkenes but dissolve completely in light aromatic hydrocarbons such as toluene, benzene, and xylene [ 37 , 38 ]. The intricate physical and chemical characteristics of asphaltenes present ongoing challenges for researchers. Asphaltene particles tend to aggregate, forming larger, more massive particles [ 39 ]. Variations in pressure, temperature, or composition cause the resin layer, which stabilizes asphaltenes, to shrink, triggering asphaltene precipitation [ 40 ]. This precipitation and subsequent deposition during oil production and processing is one of the costliest technical issues currently faced by the petroleum industry [ 41 ]. Extensive static and dynamic experiments have been conducted on asphaltene behavior during CO 2 injection, highlighting the importance of understanding its precipitation mechanisms in such processes. According to existing literature, asphaltene instability during CO 2 injection is affected by parameters such as pressure, temperature, CO 2 concentration, asphaltene structure, brine chemistry, and the existence of resins in crude oil [ 42 ]. In 2006, Verdier et al. examined the phase behavior of asphaltene precipitation during CO 2 injection at temperatures reaching 110°C and pressures up to 8700 psi. Using two crude oils with °API gravities of 27 and 29, they carried out CO 2 injection experiments in a PVT cell. Their findings showed that asphaltene precipitation decreased with lower temperatures and higher pressures. Furthermore, they observed that less CO 2 was needed to induce precipitation at elevated temperatures [ 43 ]. Zhou and Sarma (2012) conducted experiments using CO 2 concentrations ranging from 10 to 30 mol% at various temperatures between 54.5 and 120.5°C. They observed that increasing the temperature while keeping the CO 2 concentration constant led to a decrease in the asphaltene onset pressure. Conversely, increasing the CO 2 concentration at a constant temperature caused asphaltene precipitation to begin at higher pressures. When comparing the influence of CO 2 concentration and temperature, the concentration was found to have a more pronounced effect on asphaltene onset [ 44 ]. Zanganeh and colleagues (2012, 2015) conducted experiments on two oil samples with 12.8 and 31 °API gravities. They found that reducing pressure and temperature in the presence of CO 2 decreased asphaltene precipitation. However, increasing the CO 2 concentration (5–20 mol %) at constant pressure led to an increase in precipitation. Additionally, elevating the temperature from 35 to 90°C promoted the growth and aggregation of asphaltenes [ 41 , 45 ]. Cao and Gu (2013) experimentally investigated the effects of temperature on the phase behaviour, fluid interactions, and oil recovery in a light crude oil-CO 2 system. Through a series of PVT, miscibility, and interfacial tension tests conducted at both laboratory and reservoir temperatures, they found that temperature significantly influenced saturation pressure and miscibility conditions, while having a marginal effect on the oil-swelling factor. Higher temperatures were shown to improve oil recovery under miscible CO 2 flooding [ 46 ]. In their study on asphaltene phase behavior, Cardoso et al. (2014) employed the quartz crystal resonator technique. The experiment involved gradually depressurizing a mixture containing 31 mol % CO 2 , 38.3 mol % CH 4 , and a dead oil sample at 45°C, with the oil containing 0.235 wt % asphaltenes. The results showed that slower depressurization led to a higher onset pressure, indicating that the rate of depressurization significantly affects asphaltene precipitation [ 47 ]. Cruz et al. (2019) used a variable-volume cell equipped with a near-infrared probe to investigate asphaltene precipitation induced by CO₂ under conditions representative of Brazil’s deep and ultra-deepwater Pre-Salt reservoirs, which are known for their high CO 2 content. The study evaluated the effects of pressure, temperature, asphaltene concentration, and system composition on the onset of precipitation. Their findings showed that temperature and system composition were the most influential factors on asphaltene stability [ 48 ]. Rezk and Foroozesh (2019) investigated the PVT properties of CO 2 and a Malaysian crude oil at temperatures of 50 and 95.5°C and pressures reaching up to 3713 psi. Their findings indicated that CO 2 solubility in oil increased with pressure, whereas elevated temperatures reduced its solubility [ 49 ]. In 2020, Dashti et al. developed a high-pressure visual experimental setup to investigate the rate of asphaltene deposition under various gas injection scenarios. They compared the effects of N 2 , CO 2 , and CH 4 on the deposition process at different pressures. Their findings showed that in the absence of gas injection, the rate of asphaltene deposition increased with pressure. Among the gases, CO 2 injection resulted in a deposition rate 1.2 times faster than CH 4 at 100 bar, while N 2 had a lesser effect. The study concluded that CO 2 injection led to more significant asphaltene deposition compared to CH₄ and N₂, with gas injection promoting the formation of larger flocculated asphaltene particles [ 20 ]. Understanding factors such as miscibility, CO 2 solubility, interfacial tension, aqueous phase, and the porous media characteristics are crucial to the success of flooding experiments, whether conducted at laboratory or field scale [ 42 ]. Hirschberg et al. (1984) studied CO 2 injection into light oil with an °API of 45. They found no asphaltene precipitation when CO 2 was added to the oil at pressures up to 2900 psi and ambient temperature. However, the addition of nC 10 triggered asphaltene precipitation [ 50 ]. In 2008, Dahaghi et al. examined CO 2 injection effects in a Kupal field reservoir in Iran at 71°C and 6000 psi. The crude oil initially had 0.59 wt % asphaltene. CO 2 concentrations ranged from 0.4 to approximately 0.8 mol %. Peak precipitation was observed at the saturation pressure of 3725 psi, while the MMP was recorded at 5300 psi. Initially, asphaltene levels in the produced oil declined, then began to rise after a specific pore volume was injected. The largest amount of precipitation was found near the core sample inlet [ 51 ]. Cao and Gu (2013) carried out core flooding experiments in tight sandstone rocks at two temperatures: 27°C and 53°C. The oil tested had an °API gravity of 36.37 and an asphaltene content of 0.26 wt %. Below the minimum miscibility pressure of the CO 2 -oil system, higher injection pressures led to increased recovery due to enhanced oil swelling, reduced viscosity, and lower interfacial tension. Above the MMP, recovery improvement slowed and was mainly attributed to further reduction in IFT. In both miscible and immiscible scenarios, permeability was negatively affected by asphaltene deposition, with greater impairment under miscible conditions [ 52 ]. Jafari Behbahani et al. (2014) carried out core flooding tests with a live crude oil sample at a constant temperature of 70°C and above MMP. CO 2 was injected at varying flow rates of 6, 12, and 18 cubic centimeters per hour. Analytical methods, including SEM imaging, X-ray analysis, and elemental composition, confirmed that greater asphaltene deposition occurred within the core samples as the CO 2 injection rate increased [ 53 ]. In 2015, Kazemzadeh et al. investigated asphaltene precipitation during CO 2 injection by measuring interfacial tension using oil samples from southwest Iran, which had °API gravities of 21.49 and 24.46 and asphaltene contents of 11 and 10 wt %, respectively. At low pressures, IFT decreased due to intense mass transfer between CO 2 and oil, but increased at higher pressures as asphaltenes began to form. The Bond number, representing the ratio of gravitational to capillary forces, showed an inverse trend compared to IFT. Both parameters exhibited a plateau or slowdown upon the onset of asphaltene precipitation [ 54 ]. Employing a micromodel setup, Song et al. (2018) studied CO 2 injection at 353.15 K and 1450 psi using two oil samples with °API gravities of 14.09 and 0.47, and asphaltene contents of 14.96 and 36.78 wt %, respectively. Microscopic analysis revealed that increasing the pressure to 1450 psi and CO 2 concentration to 80 mol % led to greater deposition and larger particle sizes, particularly near the micromodel inlet, with asphaltene sizes reaching up to 200 µm. When comparing the two oils, higher oil recovery and reduced asphaltene precipitation were observed in heavy oils, due to improved CO 2 solubility and viscosity reduction of up to 95%. In contrast, miscibility in light oils promoted more asphaltene precipitation [ 55 ]. In 2019, Qian et al. performed CO 2 injection experiments on tight sandstone cores with porosity between 16.18 and 17.94% and permeability ranging from 2.67 to 3.31 mD, under conditions of 1160–3770 psi and 61°C. Their findings revealed that asphaltenes were distributed throughout the pore structure, with more noticeable accumulation at elevated pressures due to enhanced solubility and the extraction of light components by CO 2 . They noted that formation damage was more pronounced in medium and large pores compared to smaller ones, attributed to stronger CO 2 -oil interactions. Moreover, the core wettability transitioned from water-wet to oil-wet [ 56 ]. Fakher and Imqam (2019) conducted core flooding experiments using CO 2 injection under different conditions. The tested crude oils had viscosities of 470, 267, and 67 cP, with an asphaltene content of 5.73 wt %. As the CO 2 injection pressure increased, a greater amount of asphaltene appeared in the produced oil. Additionally, raising the temperature led to improved oil recovery and promoted more asphaltene precipitation within the residual oil. The oil with the highest viscosity showed an asphaltene precipitation of 18 wt %, compared to 10 wt % for the least viscous oil [ 57 ]. In a subsequent study in 2020, they discussed that raising the CO 2 injection pressure at 100°C led to reduced oil viscosity and enhanced oil swelling, while also resulting in less asphaltene deposition within the core [ 58 ]. Elturki and Imqam (2022) conducted a visual study of asphaltene precipitation and deposition in a nanopore shale structure, considering the minimum miscibility pressure (MMP). They examined immiscible pressures of 750 and 1250 psi and miscible pressures of 1750 and 2000 psi. When CO 2 was injected under miscible conditions, there was an increase in precipitation, particularly at higher flow rates. Scanning electron microscopy (SEM) images of the filter paper membranes showed pore plugging in shale core samples under both immiscible and miscible conditions. The researchers found that asphaltene precipitation increased with CO 2 injection pressure, which they attributed to the role of resins in facilitating asphaltene suspension. They proposed that at higher pressures, the resins break down and are unable to surround asphaltene molecules, leading to precipitation and deposition [ 59 ]. Xiong et al. (2023) investigated the impact of injecting methane, carbon dioxide, and nitrogen on asphaltene deposition. Their findings indicated that the extent of asphaltene precipitation was closely linked to the miscibility of the injected gases. Consistent with earlier research, nitrogen injection resulted in the least asphaltene deposition, while carbon dioxide led to more precipitation compared to methane [ 60 ]. Li et al. (2024) studied asphaltene precipitation in reservoirs under CO 2 injection, especially under high-pressure, high-temperature conditions, an area that is not fully understood. By combining experiments, numerical simulations, and phase-state simulations, they investigated how different pressures, temperatures, and gas injection amounts affected asphaltene precipitation and its impact on reservoir permeability and oil production. Their findings revealed that CO 2 injection induces the desorption of colloid-asphaltene inclusions, followed by the polymerization of dispersed asphaltene molecules. The injection of CO 2 resulted in more precipitation and shifted the precipitation curve to higher pressures. The core’s permeability decreased by 12.87–37.54% due to asphaltene deposition. Additionally, asphaltene deposition led to a 1.5% reduction in oil recovery and a 17% drop in injection rate [ 61 ]. While CO 2 injection has been extensively studied in the context of asphaltene precipitation and enhanced oil recovery, comparatively fewer investigations (Appendix: Table A1) have focused on the effects of flue gas injection, despite its growing relevance as a cost-effective and readily available alternative. Most of these studies have primarily focused on improving the oil recovery factor. Fong et al. (1992) conducted core flood experiments to evaluate flue gas injection as a potential EOR method for the Lost Hills diatomite reservoir. Despite an early breakthrough, a total recovery of 23% of OOIP was achieved, with a final residual oil saturation of 46% pore volume. The study highlighted that while the recovery was lower compared to CO 2 flooding under similar conditions, flue gas injection still offered incremental oil recovery and could be a technically viable option if a reliable gas source is available [ 62 ]. Srivastava et al. (1999) evaluated the effectiveness of flue gas injection for heavy oil recovery in the Senlac reservoir using both PVT analysis and core flood experiments. The flue gas used consisted of 15.6 mol% CO 2 and 84.4 mol% N 2 . PVT results showed that flue gas had the lowest gas solubility, viscosity reduction, and oil swelling compared to pure CO 2 and produced gas, making it the least effective of the three in terms of oil phase behavior. However, core flood tests demonstrated that flue gas injection can still achieve significant oil recovery, particularly in water-alternating-gas (WAG) schemes [ 28 ]. In 2002, Dong and Huang evaluated flue gas injection for heavy oil recovery in Saskatchewan reservoirs through a combination of PVT analysis and two-dimensional physical model tests. Three synthetic flue gas mixtures were tested, with varying CO 2 concentrations up to 25 mol %. The results showed that increasing the CO 2 content in flue gas led to greater oil swelling and viscosity reduction. Live oils responded more effectively than dead oils. Simulations and phase behavior studies confirmed that the free-gas drive mechanism plays a dominant role in oil recovery due to the high nitrogen content and limited solubility of the gas [ 33 ]. Shokoya et al. (2004) investigated the mechanism of flue gas injection for light oil recovery using slim-tube experiments under reservoir conditions. Three flue gas compositions were tested, with nitrogen content ranging from 69–100%. The experiments were conducted at 116°C and pressures from 1102 to 6686 psi. Results showed that oil displacement occurred through a combined vaporizing-condensing gas drive mechanism. Although true miscibility was not achieved, oil recovery increased with pressure and CO 2 content in the flue gas. The study emphasized that enriched flue gas, even under near-miscible conditions, can enhance light oil recovery effectively [ 35 ]. Shokoya et al. (2005) investigated the performance of flue gas injection for light oil recovery using laboratory displacement tests and compositional simulation. Two light oils with different paraffin and naphthene contents were tested using flue gas containing 16% and 30% CO 2 . Experiments were conducted in long sandstone cores at reservoir pressures up to 6030 psi and temperatures of 80.6°C and 116°C. The results showed that oil recovery improved with higher reservoir pressure and greater CO 2 content in the injected gas. Oils with higher naphthene and lower paraffin content yielded higher recovery [ 63 ]. Same authors (2005) studied the effect of CO 2 concentration in flue gas on oil recovery through core flooding and simulation. Tests were conducted using recombined live oils and sandstone cores under reservoir pressure and temperature conditions. Results showed that higher CO 2 content improved oil swelling and viscosity reduction, leading to increased oil recovery. However, even at lower CO 2 concentrations, significant recovery was achieved due to the free-gas drive effect provided by nitrogen [ 64 ]. Mohsenzadeh et al. (2014) investigated the effects of CO 2 , N 2 , and synthetic flue gas injection on heavy oil recovery in fractured carbonate reservoirs using a long-core laboratory model under reservoir conditions. The results indicated that before gas breakthrough, oil recovery was primarily from the fracture system, with flue gas injection yielding the highest production rate due to a combined effect of oil swelling and piston-like displacement [ 65 ]. Bender and Akin (2017) evaluated flue gas injection as an alternative to pure CO 2 injection for enhanced oil recovery and storage in a mature oil field in Turkey. A compositional reservoir simulation model was developed and history matched using 31 years of field data. The results showed that while continuous pure CO 2 injection provided higher oil recovery and CO 2 storage over the long term, flue gas injection offered comparable oil recovery for injection periods shorter than 25 years [ 66 ]. Li et al. (2017) investigated the effects of flue gas and n-hexane on heavy oil recovery through laboratory experiments involving steam flooding, flue gas–assisted steam flooding, n-hexane flooding, and steam flooding assisted by both flue gas and n-hexane. The results showed that flue gas dissolved in heavy oil effectively reduced viscosity, enhanced flowability, and caused the oil to swell. The combined use of flue gas and n-hexane led to the best performance, resulting in the lowest displacement pressure, the highest oil production rate, and recovery efficiency reaching up to 80% [ 67 ]. Pang et al. (2018) evaluated the effectiveness of flue gas and steam co-injection for enhancing heavy oil recovery. The results showed that the dissolution of CO 2 from flue gas into heavy oil significantly reduced viscosity and improved mobility, while nitrogen, although largely insoluble, contributed to pressure maintenance and reduced heat loss by accumulating at the reservoir top [ 68 ]. Wu et al. (2018) investigated the application of flue gas in combination with steam for enhancing oil recovery in thick extra-heavy oil reservoirs through PVT experiments and 3D physical simulations. The flue gas, composed of 80% N 2 and 20% CO 2 , was shown to reduce oil viscosity by dissolving CO 2 into the crude, increasing oil expansibility and mobility. In the 3D experiments, flue gas–assisted steam flooding achieved an ultimate oil recovery of 49.5%, which was 7.95% higher than steam flooding alone [ 69 ]. Tao et al. (2021) conducted a large-scale 3D physical simulation to investigate the enhanced oil recovery performance of flue gas-assisted steam assisted gravity drainage (SAGD) in heavy oil reservoirs. The results indicated that injecting flue gas alongside steam improved the oil recovery by 5.7% compared to conventional SAGD [ 70 ]. Min and Zhang (2024) investigated the impact of flue gas foam-assisted steam flooding on the development of complex heavy oil reservoirs. Their results indicated that the presence of flue gas enhanced reservoir energy and reduced interfacial tension, with higher CO 2 content being more effective in lowering interfacial tension [ 71 ]. Nassabeh et al. (2025) conducted a comprehensive numerical study to evaluate the performance of flue gas injection compared to CO 2 injection under heterogeneous reservoir conditions. Simulation results showed that flue gases containing higher concentrations of CO 2 and O 2 achieved better oil recovery, while water vapor negatively affected both recovery and reservoir pressure [ 72 ]. Among the literature, only one study has directly investigated asphaltene deposition resulting from flue gas injection under reservoir conditions. Jalili et al. (2024) investigated the effects of CO 2 and flue gas injection on oil recovery and asphaltene-related formation damage under reservoir conditions using an elongated core composed of four connected plugs. The results showed that CO 2 injection achieved a significantly higher oil recovery (86%) compared to flue gas (36%), attributed to better miscibility and a greater swelling effect. However, CO 2 injection also led to more severe asphaltene deposition and formation damage, with a permeability reduction of up to 14.8%, while flue gas injection caused a milder impairment of 4.4%. The most pronounced damage occurred in the first two plugs near the injection point, and the final two plugs showed negligible deposition, suggesting minimal gas–oil interaction in that zone. Although flue gas resulted in lower recovery, it offered improved flow assurance and reduced the risk of plugging, making it a potentially favorable option where formation damage is a concern [ 4 ]. This study did not examine the effects of varying temperatures and injection pressures on asphaltene deposition and the associated formation damage. Additionally, the influence of CO 2 miscibility on formation damage, and a comparison with the formation damage caused by flue gas, were not explored. Table A.1 summarizes key parameters from previous flue gas flooding experiments reported in the literature, including gas type, oil sample, core properties, injection conditions, oil recovery factor, and formation damage. The objective of this study is to experimentally investigate and compare the performance of flue gas and carbon dioxide injection for enhanced oil recovery in low-permeability carbonate reservoirs using recombined live oil. Particular focus is given to understanding the impact of injection pressure, temperature, gas volume, and gas type on oil recovery efficiency, asphaltene deposition, and permeability reduction. A series of core flood experiments were conducted under both immiscible and miscible conditions using two representative carbonate core samples. The results aim to provide quantitative insights into the viability of flue gas as an alternative to carbon dioxide in EOR operations, especially where formation damage and gas availability are critical factors. This work contributes to optimizing gas injection strategies for improved recovery while mitigating reservoir damage in challenging reservoir conditions. Materials and methods Materials Two comparable carbonate core samples, labeled F#1 and C#2, were selected from the Abteymour oilfield and prepared for core flood testing. Two types of non-hydrocarbon gases, pure CO 2 and synthetic flue gas, were used as displacing fluids. The flue gas was prepared by mixing 25 mol% % pure CO 2 with 75 mol% % pure N 2 . The primary liquid solvents used in the experiments included activated silica and ultrapure reagents (>99% purity) of cyclohexane, toluene, n-heptane, methanol, chloroform, and acetonitrile. To prepare the recombined live oil for core saturation, stock tank oil from the specified oilfield was mixed with associated first-stage gas under reservoir conditions. The oil specifications and reservoir conditions are presented in Table 1. The kinematic viscosity and density of the stock tank oil at various temperatures are listed in Table 2. The compositions of the stock tank oil, associated gas, and synthetic recombined live oil are presented in Table 3, and the SARA analysis of the stock tank oil is shown in Table 4. Table 1. Reservoir conditions and oil specifications of the specified oilfield Reservoir pressure (psi) Reservoir temperature (ºC) GOR (SCF/STB) Oil viscosity at reservoir condition (cp) Oil density at reservoir condition (g/cm 3 ) Oil ºAPI gravity 6000 110 342.38 3 0.8128 21 Table 2. Kinematic viscosity and density of stock tank oil at various temperatures Temperature (ºC) Density (g/cm 3 ) Kinematic viscosity (m 2 /s) *1000 15 0.9228 0.177 25 0.9160 0.099 40 0.9047 0.047 50 0.8967 0.031 55 0.8953 0.026 60 0.8922 0.022 Table 3. Compositions of stock tank oil, associated gas, and recombined oil Components Stock tank oil (mole%) Associated gas (mole%) Recombined oil (mole%) H 2 S 0.00 0.00 0.00 N 2 0.00 0.11 0.05 CO 2 0.00 0.69 0.31 C 1 0.00 75.36 34.32 C 2 0.10 12.17 5.60 C 3 0.27 7.15 3.40 iC 4 0.26 1.83 0.97 nC 4 1.50 1.92 1.69 iC 5 1.67 0.36 1.07 nC 5 1.96 0.34 1.22 C 6 10.58 0.06 5.79 C 7 6.36 0.01 3.47 C 8 7.53 0.00 4.10 C 9 10.61 0.00 5.78 C 10 5.31 0.00 2.89 C 11 5.56 0.00 3.03 C 12 + 48.28 0.00 26.30 Table 4. SARA analysis of the stock tank oil used in this study Saturate Aromatic Resin Asphaltene 28.82 33.90 24.41 12.87 Experimental procedure In this study, a core flooding system served as the primary experimental setup, while two additional systems were used for preparing recombined live oil and synthetic flue gas. Details of all setups are described below, along with an explanation of the core preparation process. The recombined oil apparatus consisted of a high-pressure piston cylinder with a 1000 cubic meter capacity and a maximum working allowable pressure (MWAP) of 6000 psi, along with a mechanical shaking device. Two additional high-pressure piston cylinders, identical to the oil apparatus, were used as CO 2 and N 2 gas containers for preparing the flue gas. An ISCO high-pressure syringe pump was employed to transfer and pressurize the fluids. The core flood setup, illustrated in Figure 1, consisted of an ISCO high-pressure pump capable of injecting up to 7000 psi, three high-pressure piston cylinders, a heating jacket, pressure gauges, a thermocouple, a core holder (maximum pressure tolerance of 7000 psi and flow rate range of 0.001 to 60 cm³/min), a back-pressure regulator, and a differential pressure transmitter. The pump’s speed, volume, and movement were fully programmable and digitally controlled. A pressure regulator ensured stable pressure throughout the experiments. All components were enclosed within an air bath equipped with a thermostat to maintain a constant temperature during the displacement tests. The wall-mounted core holder was constructed from a steel tube with a thickness of 0.953 cm, an outer diameter of 8.89 cm, and a length of 32 cm. The core sample was placed inside a sleeve to isolate it from the injected fluids within the core holder. The ring surrounding the sleeve was filled with water to apply an additional confining pressure of 500–700 psi to the core. The volume of gas injected into the core was automatically measured using the ISCO injection pump. The setup, equipped with a back-pressure regulator (BPR), included a precise diaphragm regulator with a stainless-steel diaphragm to maintain port pressure within the core. The produced liquid was collected in a graduated cylinder, while the gas was released into the atmosphere. As presented in Table 5, the experiments in this investigation were categorized into three subgroups: primary (PA), main (MA), and supplementary (SA) tests and activities, performed before, during, and after gas injection, respectively. The primary tests included core and fluid property measurements, as well as the preparation of recombined live oil and synthetic flue gas. The main experiments involved multiple gas injections under varying temperatures, pressures, and gas types. Additionally, related tests, such as water and oil saturation and cyclohexane injection, were conducted before and after gas flooding. The supplementary activities included measurements of core samples and produced oil, such as core deposition and asphaltene content analysis. Table 5. Classification of the experiments conducted in core flooding tests Classification Description Details Primary (PA) Fluid and core properties Fluid properties measurements - Core properties measurements MMP- Recombined oil-Bubble point - Porosity-Permeability Fluid preparation Recombined oil preparation - Synthetic flue gas preparation Mixing and pressurizing dead oil and associated gas at GOR ratio - Mixing and pressurizing CO 2 and N 2 Main (MA) Core preparation Core water & Oil saturating Core flood formation water and then dead and live oil flooding for making saturated Flooding Gas flooding Gas core flooding at constant pressure steps Permeability reduction measurement Cyclohexane injection Cyclohexane core flooding and differential pressure measurement for permeability determination Supplementary (SA) Produced oil measurement Produced asphaltene measurement IP143 Deposition measurement Core deposition measurement Asphaltene deposition measurement by extracting in Soxhlet extractor Primary activities (PA) The minimum miscibility pressure (MMP) of CO 2 and flue gas was determined using CMG software. Following the regression of the synthetic oil with the WINPROP module, the MMP values were obtained using the GEM module. Bubble point pressure was measured using a movable piston-cylinder device equipped with a wire-adjustable heating jacket to maintain a constant temperature and a pressure transmitter positioned at the oil end of the cylinder. In the first stage, the pressure of the recombined live oil was increased to 6000 psi by injecting water into the water compartment of the piston cylinder and was held at this pressure for four days to ensure a single-phase condition. During this time, the piston was constantly shaken. Subsequently, a controlled volume of water was gradually drained from the water compartment in each step, and the corresponding pressure drop was recorded. Throughout the experiment, the temperature was maintained at 110 °C using the heating jacket. A distinct break in the pressure drop curve indicated the bubble point pressure. The porosity of the core samples was measured using a porosity-measuring electronic device. Absolute permeability was determined by conducting formation water flooding and applying Darcy's correlation. For three or four fluid velocity steps within the range of 0.5 to 2 cm 3 per minute, the differential pressure along the core length was recorded. The physical properties of the core samples are summarized in Table 6. The initial core sample used for core flooding tests was F#1. This sample was subjected to flue gas injection at various temperatures and pressures, as well as CO 2 flooding under reservoir temperature and pressure. To investigate CO 2 flooding under different miscibility conditions, immiscible and miscible, a second core sample, coded C#2, was selected. This sample had similar properties and lithology to F#1. The use of two comparable low-permeability carbonate core samples enhances the reliability and repeatability of the results, offering greater confidence than experiments conducted with a single core. Table 6. Core samples properties Core Core F#1 Core C#2 Conducted core flood tests 4 tests # Flue gas &1 test # CO 2 3 tests # CO 2 Specifications Length (cm) 5.121 4.885 Diameter (cm) 3.80 3.84 Porosity (%) 29.5 28.29 Pore volume (cm 3 ) 13.2 7.9 Liquid permeability(mD) 1.5 3.6 Dry weight (g) 120.973 113.838 0.23 0.17 Rock type Carbonate Carbonate The recombined live oil was prepared by mixing stock tank oil with first-stage associated gas at a pressure of 450 psi-g. The associated gas was first transferred into a 1000 cm 3 high-pressure piston cylinder, followed by the injection of a predetermined volume of dead oil based on gas–oil ratio data. The mixture was then pressurized to 4000 psi, well above the bubble point of the live oil, and agitated for 4 days. To prepare the synthetic flue gas, pre-calculated amounts of pure CO 2 and N 2 gases, in a molar ratio of 25 % CO 2 and 75 % N 2 , were transferred into two separate high-pressure piston cylinders at 1000 psi. The CO 2 was then fully transferred into the N 2 cylinder to form the desired gas mixture, representing the synthetic flue gas. Main activities (MA) The core flood experiment was conducted using the main setup and consisted of three primary stages: (I) core preparation, (II) flooding, and (III) permeability reduction measurements. In the first step, the core samples were washed with toluene using a Soxhlet extraction apparatus for 4–5 days until a clear solution was obtained and no organic precipitate remained in the cores. The process was then continued by replacing toluene with methanol for an additional 2 days to extract inorganic materials. After solvent extraction, the cores were dried in an oven at 110 °C. The dried core samples were then placed in the core holder and subjected to vacuum for 5 hours. To reach irreducible water saturation, a 10 % NaCl solution as artificial formation water was injected into the cores. To displace the saline water from the cores, approximately two pore volumes of dead oil were injected until significant water production occurred and irreducible water saturation was achieved. The core samples were maintained in this state for 7 days to allow proper aging. Finally, the cores were subjected to temperature and pressure conditioning before testing. The main gas injection step was performed under predefined conditions of temperature, pressure, and gas type. Throughout the entire core flooding process, the overburden pressure was maintained at 500–700 psi above the injection pressure. Gas injections were carried out at fixed pressures ranging from 3000 to 6000 psi, all above the bubble point pressure. Six pore volume increments of 0.1, 0.3, 0.6, 0.9, 1.2, and 1.5 PV of flue gas and CO 2 were injected. The volume of produced oil, after gas separation, was recorded using a graduated cylinder, while the pressure drop across the core sample was monitored using a differential pressure (DP) cell. The gas core flooding step was conducted according to the following general procedure: Before each gas injection set, the core sample was cleaned, dried, and saturated with formation water and dead oil at the specified pressure, following the core preparation procedure. The pressure and temperature were adjusted to the specified values using the pressure regulator, heating jacket, and air bath container. Saline water was reinjected into the core sample at the specified pressure to remove the dead oil before recombined oil injection. The oil pore volume was determined at each step by measuring the volume of removed dead oil. The recombined oil was injected into the core holder at the specified pressure until irreducible water saturation in the core sample was achieved. Flue gas or carbon dioxide stored in the piston cylinder was injected into the core holder at constant pressure and temperature. At six injection stages, from 0.1 to 1.5 pore volumes, the volume of degassed oil was collected in a graduated cylinder for oil recovery calculation. Cyclohexane injection was carried out according to the following general procedure to measure and compare the permeability of the core sample before and after each gas injection set, which was affected by asphaltene deposition. Before each gas injection set, and after saturating the core sample with formation water and recombined oil, liquid cyclohexane was injected at the specified pressure and temperature until no further oil removal was observed. The differential pressure along the core sample was then measured using a differential pressure cell at four cyclohexane injection rates ranging from 0.2 to 0.5 milliliters per minute. Preparations were performed to ensure the core was properly saturated with formation water and recombined oil. After each gas injection set, the same procedure was repeated to measure the pressure difference following gas flooding. Supplementary activities (SA) The supplementary step included two measurements: (I) asphaltene content in the produced oil and (II) deposition within the core sample. Following each gas injection set, the asphaltene content of the produced oil was measured using the IP143 standard method. According to this standard method (ASTM D6560-00), a portion of the sample is mixed with 40 volumes of n-heptane, which is used as a precipitant. Then, the mixture is heated under reflux for 60 min, and after that, it is stored in a dark space for 90 to 150 min. Then the precipitated asphaltenes, waxy substances, and inorganic material are collected on a 2.5 µm filter paper. The waxy substances are removed by washing with hot heptane in an extractor. After the waxy substances are removed, the asphaltenes are separated from the inorganic material by dissolution in hot toluene, the extraction solvent is evaporated, and the asphaltenes are weighed. To determine core deposition at the end of each pressure step, the core sample was washed using a Soxhlet extractor with toluene as the solvent to extract and quantify the asphaltene deposited on the core. Additionally, the asphaltene deposition percentage was calculated by comparing the asphaltene content of the original and produced oils, taking into account the oil in place and the volume of produced oil. Results and discussion MMP of injection gases The results of slim tube simulations for CO 2 and flue gas, conducted using CMG software, along with their minimum miscibility pressure as a function of temperature, are illustrated in Figures 2, 3, and 4, summarized in Table 7. The data show that CO 2 and flue gas exhibit opposite trends in MMP with changing temperature. For CO 2 , the MMP increases with rising temperature, which is consistent with interfacial tension experimental results reported by Zolghadr et al. Their study demonstrated that at pressures above 754 psi, an increase in temperature leads to higher IFT and consequently higher MMP [73]. In contrast, the simulation results indicate that the MMP of flue gas decreases as temperature increases. This observation is in agreement with IFT experimental findings for nitrogen reported in previous research [74]. Since the flue gas used in this study contains 75 mol percent nitrogen, its behavior more closely resembles that of nitrogen rather than CO 2 . Table 7. MMP (psi-g) of CO 2 and flue gas at different temperatures Gas type Temperature (°C) 110 100 43.3 CO 2 4350 3750 1800 Flue gas 17000 - 20000 Bubble point of recombined oil Based on the experimental data of pressure versus cumulative displaced water volume shown in Figure 5, the bubble point pressure of the recombined oil at 110 degrees Celsius was determined to be 2918 psi. It is important to note that all core flood experiments were conducted at pressures above this bubble point. Core flooding test results Core flood displacement tests were conducted using recombined oil with CO 2 and flue gas under various temperatures and pressures. The injection pressure was selected based on the bubble point of the live oil and the reservoir temperature, with reservoir pressures ranging from 3000 to 6000 psi. For flue gas injection, two experimental sets were performed using core sample F#1: one with a constant pressure of 4000 psi at temperatures of 65 and 110 degrees Celsius, and another with a constant temperature of 110 degrees Celsius at pressures of 3000 and 6000 psi. For CO 2 injection, experiments were conducted on core sample C#2 at a constant temperature of 110°C with pressures of 3000, 4300, and 5000 psi to evaluate immiscible and miscible conditions. An additional CO 2 test was conducted on core sample F#1 at reservoir conditions of 110 degrees Celsius and 6000 psi. The results were categorized into three main areas to assess the effects of flue gas and CO 2 injection: oil recovery factor, asphaltene deposition, and core permeability reduction. A summary of the core flood experiments is shown in Table 8. Table 8. Summary of core flood experiments conducted in this study Test No. Core sample Injected gas Pressure (psi) Temperature ( ºC ) 1 F#1 Flue gas 4000 65 2 F#1 Flue gas 4000 110 3 F#1 Flue gas 3000 110 4 F#1 Flue gas 6000 110 5 C#2 CO 2 3000 110 6 C#2 CO 2 4300 110 7 C#2 CO 2 5000 110 8 F#1 CO 2 6000 110 Oil recovery factor results Figure 6 illustrates the cumulative oil recovery factor versus injected gas pore volume for all test cases using CO 2 and flue gas at various temperatures and pressures, with up to 1.5 pore volumes injected into the core samples. Each experiment was conducted under constant pressure conditions. The overall trend shows that at reservoir temperature (110 °C), the oil recovery factor for flue gas at 4000 and 6000 psi is nearly equivalent to that of CO 2 at 3000 and 5000 psi, respectively. This indicates that a similar oil recovery factor can be achieved by flue gas injection at higher pressures compared to CO 2 . Furthermore, the results reveal that increasing temperature has a negative effect on oil recovery during flue gas injection, with higher temperatures leading to reduced recovery. According to Figure 7, increasing the temperature from 65 °C to 110 °C reduced the ultimate oil recovery factor for flue gas injection from 0.738 to 0.621. This indicates that higher temperatures lead to lower oil recovery during flue gas injection. At elevated temperatures, the solubility of flue gas in oil decreases, resulting in reduced oil swelling and less viscosity reduction. This outcome aligns with the experimental findings of Shokoya et al., who conducted core flood experiments at two reservoir temperatures (80.6 °C and 116 °C) and pressures up to 6030 psi. Their results also demonstrated a decrease in oil recovery efficiency with increasing temperature during flue gas injection [63]. In contrast, the behavior of CO 2 injection differs. The effect of injected gas volume at different pressures and gas types at reservoir temperature (110 °C), originally presented in Figure 6, is further illustrated in Figure 8. This figure highlights the impact of injecting 1.4 pore volumes of gas (from 0.1 to 1.5 PV) on oil recovery. For flue gas flooding, the oil recovery improvement across different pressures is relatively consistent and notably higher than that observed for CO 2 flooding. It can be concluded that injecting an equal volumetric amount of flue gas results in a greater oil recovery, approximately 10–15 % higher, compared to CO 2 . This suggests that flue gas injection requires a smaller gas volume to achieve comparable recovery, offering a more cost-effective alternative to CO 2 flooding. In contrast, for CO 2 flooding, oil recovery shows greater sensitivity to pressure, with higher pressures yielding improved recovery performance. Figure 9 illustrates the ultimate oil recovery factor (URF) as a function of injection pressure for 1.5 pore volumes of gas injected at reservoir temperature (110 °C). For both gases, the recovery factor increases with pressure. Flue gas, operating entirely within the immiscible injection region, shows a consistent and gradual increase in URF. In contrast, CO 2 spans both immiscible and miscible regions, demonstrating a similar trend to flue gas in the immiscible range, but with a distinct change in slope as it enters the miscible region, indicating enhanced recovery efficiency under miscible conditions. However, although the oil recovery factor increases under miscible conditions, the rate of improvement becomes more gradual. In immiscible gas flooding, oil recovery increases with a higher capillary number due to the relatively low interfacial tension between the oil and the injected gas. Miscible flooding enhances oil recovery through several mechanisms, including the elimination of interfacial tension between oil and solvent or an effectively infinite capillary number, which enables efficient oil displacement by the solvent once miscibility is achieved. Additional contributions to recovery include oil swelling and a reduction in oil viscosity [63]. As pressure increases, CO 2 density rises sharply during the immiscible flooding region, leading to faster dissolution of CO 2 in crude oil and a reduction in crude oil viscosity. This decreases the interfacial tension between CO 2 and oil, which in turn causes the crude oil to swell. These beneficial effects result in a rapid increase in oil recovery during the immiscible stage [75]. Additionally, as pressure increases, the length of the transition zone between the injected gas front and the oil zone decreases. This reduction slows the advancement of the gas front toward the core outlet, delaying gas breakthrough and thereby improving sweep efficiency [63]. As the system approaches miscible conditions, the influence of pressure on the transition zone becomes minimal because the zone reaches its smallest possible size, and further pressure increases no longer provide additional benefit [76]. In the miscible flooding stage, due to the reduced contribution of the mechanisms dominant in the immiscible region, only a slight increase in the recovery factor is observed with increasing pressure [75]. In this study, two similar core samples were used independently to investigate the effect of pressure on each type of injected gas. To ensure a more accurate comparison, one core sample (F#1) was used under reservoir conditions at 6000 psi and 110 °C for both gases. The results indicate a higher recovery factor for CO 2 compared to flue gas. Overall, it can be observed that at each pressure level, the oil recovery factor for CO 2 is greater than that for flue gas. However, by applying a higher pressure than that used for CO 2 , a similar oil recovery factor can be achieved with flue gas. Figure 10 shows the effect of gas type on oil recovery and compares it with injection pressure using the same core sample (F#1). By comparing the results for CO 2 injection at 6000 psi and 110 °C with flue gas injection at 4000 psi and 6000 psi at 110 °C, it is observed that the ultimate oil recovery for CO 2 at 6000 psi and 110 °C (reservoir pressure and temperature) is only 10 percent higher than for flue gas at the same temperature and pressure, but up to 30 percent higher than flue gas injection at 4000 psi. This indicates a significantly superior performance compared to flue gas at lower pressures. These findings demonstrate that injection pressure has a greater influence on oil recovery than the type of gas, specifically the CO 2 content in the flue gas. Additionally, the miscible condition of CO 2 and the immiscible condition of flue gas have a smaller impact on oil recovery than the effect of pressure. Therefore, under high pressure, the immiscible nature of flue gas has only a minor influence on oil recovery. Asphaltene deposition results The experimental data for asphaltene mass percentage in the original and produced oil, along with the calculated asphaltene content in the core samples, are presented in Table 9. The asphaltene content was measured using the IP143 standard procedure, and the deposited mass percentage was calculated based on the difference in asphaltene content between the original oil and the produced oil. Table 9. Asphaltene content and deposited asphaltene onto core samples during CO 2 and flue gas flooding Test code Gas type Core sample code Test conditions Asphaltene wt% in original oil (IP143)-Exp Asphaltene wt % in produced oil (IP143)-Exp Deposited asphaltene F-T065-P4000 Flue Gas F#1 T:65 °C P:4000 psi 12.87 5.97 48.61 F-T110-P3000 Flue Gas F#1 T:110 °C P:3000 psi 12.87 5.65 35.21 F-T110-P4000 Flue Gas F#1 T:110 °C P:4000 psi 12.87 6.05 41.12 F-T110-P6000 Flue Gas F#1 T:110 °C P:6000 psi 12.87 6.52 50.41 C-T110-P3000 CO 2 C#2 T:110 °C P:3000 psi 12.87 9.31 20.16 C-T110-P4300 CO 2 C#2 T:110 °C P:4300 psi 12.87 5.77 52.41 C-T110-P5000 CO 2 C#2 T:110 °C P:5000 psi 12.87 9.65 25.55 C-T110-P6000 CO 2 F#1 T:110 °C P:6000 psi 12.87 6.01 59.82 The data presented in Table 8 reveal that at a constant pressure of 4000 psi, increasing the temperature from 65 to 110 °C resulted in a decrease in the percentage of deposited asphaltene from 48.61 to 41.12 percent. At higher temperatures, the solubility of flue gas in the oil decreases, which leads to reduced asphaltene precipitation and deposition. No published studies have been identified that specifically investigate the effect of temperature on asphaltene deposition under similar conditions. Figure 11 presents the percentage of asphaltene deposited within the pores of core samples during CO 2 and flue gas injection. Flue gas exhibits consistent behavior across the entire pressure range since it remains in the immiscible condition. In contrast, CO 2 shows a distinct pattern, with differing behavior in the immiscible region from 3000 to 4300 psi and the miscible region from 4300 to 6000 psi. Under miscible conditions, the injected gas alters the oil composition and disrupts the interaction between resins and asphaltene molecules, which promotes asphaltene precipitation and deposition. However, under immiscible conditions, the oil composition remains largely unchanged, and asphaltene deposition primarily depends on gas solubility. Lower gas solubility leads to less asphaltene precipitation. In the immiscible zone, as shown in Figure 11, both flue gas and CO 2 display a consistent trend in which asphaltene deposition increases with rising injection pressure. As the injection pressure increases, the gas dissolution capacity in crude oil also rises. This leads to a greater proportion of low molecular weight compounds and a reduction in the concentration of asphaltene-resin stabilizers, making asphaltene precipitation more likely [77]. Additionally, at higher pressures, asphaltene molecules are brought closer together, promoting their coagulation and subsequent deposition onto the core samples [76]. Because CO 2 solubility in oil is significantly more sensitive to pressure than that of flue gas, the CO 2 curve demonstrates a steeper slope, indicating greater solubility and, therefore, higher asphaltene deposition for CO 2 . At the minimum miscibility pressure of CO 2 , maximum dissolution of CO 2 in the crude oil occurs, resulting in the highest level of asphaltene deposition during gas flooding. As the system enters the miscible region, the crude oil becomes saturated with CO 2 , and while asphaltene deposition still occurs, it does so at a much lower rate [75]. This reduction is attributed to the formation of a gas phase within the system, which slows the rate of asphaltene deposition [77]. During the miscible injection of CO 2 , flue gas may still operate in the immiscible flooding region. In this case, flue gas continues to exhibit a trend similar to that at lower pressures, where asphaltene deposition increases proportionally with injection pressure [76]. The general behavior of asphaltene deposition onto the core caused by CO2 gas flooding in this study confirms the findings of experimental investigations by Soroush et al. and Cao and Gu, who examined five pressure points with three below and two above the minimum miscibility pressure [52,78]. To investigate the effect of gas type on asphaltene deposition, tests F-T110-P6000 and C-T110-P6000 (Table 8) were performed under identical pressure, temperature, and rock characteristics using the same core sample (F#1) at reservoir conditions. As shown in Fig. 11, the results indicate that under the same conditions, asphaltene deposition caused by CO 2 injection is approximately 20 percent higher than that from flue gas. For CO 2 injection, due to the miscible condition, the percentage of asphaltene deposition is highly sensitive to pressure. In contrast, flue gas injection produces more predictable and consistent asphaltene deposition behavior. To draw more comprehensive conclusions regarding the impact of gas type, an integrated discussion that considers both asphaltene deposition and reduced permeability is presented in the next section. Core permeability reduction results For all tests, two liquid permeability measurements using cyclohexane were conducted before and after the main gas injection test. Figures 12 and 13 illustrate the increase in pressure difference along the core samples for core samples C#2 and F#1, respectively. The increase in pressure difference resulting from CO 2 injection is significantly greater than that from flue gas injection in both figures. This difference is attributed to formation damage caused by asphaltene deposition within the core samples. Using the differential pressure data obtained from cyclohexane injection and applying Darcy’s law, the core permeability was calculated both before and after gas injection. The corresponding permeability curves are presented in Figures 14 through 21. By substituting the pressure difference data obtained from Figures 14 to 21 into Darcy’s law, the core permeabilities before and after the core flood gas injection were calculated and are presented in Table 10. To gain a clearer understanding of the extent of permeability reduction, the damage index can be employed using the following relation [78]: Where and are the core permeabilities after and before gas injection, respectively. The damage indexes presented in Table 9 and Figure 22 indicate that the formation damage resulting from CO 2 injection is, on average, approximately 3.6 times greater than that caused by flue gas injection. Table 10. Permeability of core samples before and after gas injection and damage indexes Test Core sample code Permeability before gas injection ( – mD Permeability after gas injection ( – mD Damage index (DI) CO 2 @ 110 ºC & 3000 psi C#2 1.0621 0.7837 0.262 CO 2 @ 110 ºC & 4300 psi C#2 1.0690 0.7780 0.272 CO 2 @ 110 ºC & 5000 psi C#2 0.9905 0.7611 0.232 CO 2 @ 110 ºC & 6000 psi F#1 0.3499 0.2620 0.251 FG @ 65 ºC & 4000 psi F#1 0.1286 0.1262 0.019 FG @ 110 ºC & 3000 psi F#1 0.3169 0.3071 0.031 FG @ 110 ºC & 4000 psi F#1 0.3014 0.2765 0.083 FG @ 110 ºC & 6000 psi F#1 0.2903 0.2467 0.150 According to Figure 22, the damage index for flue gas injection increases from 0.019 to 0.083 as the temperature rises from 65 °C to 110 °C, indicating an approximately fourfold increase. This demonstrates that increasing temperature significantly amplifies permeability reduction and formation damage due to asphaltene deposition. Considering Figures 23 and 24, a comprehensive investigation of permeability reduction integrated with oil recovery factor and asphaltene deposition for flue gas and CO 2 injection is presented. During immiscible flue gas injection, although permeability reduction and asphaltene deposition intensify with increasing pressure, the oil recovery factor continues to rise. Despite the reduction in permeability, the enhanced pressure significantly boosts oil recovery, resulting in an overall positive effect. A similar trend is observed for CO 2 flooding in the immiscible region (< MMP) between 3000 and 4300 psi. In this range, the behavior of permeability reduction, in contrast to asphaltene deposition, exhibits minimal variation. This may be attributed to additional damage mechanisms besides asphaltene deposition, such as rock–CO 2 interaction or gas trapping in the pore space, which is more probable at lower pressures. Increased pressure suppresses asphaltene precipitation under miscible CO 2 flooding conditions, thereby minimizing permeability impairment. However, this process leads to a slower oil recovery rate than immiscible CO 2 flooding. The resulting damage is primarily due to asphaltene deposition, and other types of rock damage can be considered negligible [78]. Figure 25 compares the permeability reduction resulting from flue gas and CO 2 injection. Under reservoir conditions of 110 °C and 6000 psi using core sample F#1, the permeability reduction caused by CO 2 is approximately 67 % higher than that caused by flue gas. A comparison of permeability reduction in both F#1 and C#2 cores shows that at lower injection pressures, flue gas causes significantly less damage. As the pressure increases, the difference between the damage done becomes smaller, although CO2 still results in greater overall permeability reduction. These findings support the consideration of flue gas as a more favorable injection option compared to pure CO 2 , particularly when minimizing formation damage is a priority. Conclusions Flue gas and CO 2 core flooding experiments were conducted on recombined live oil using two low-permeability carbonate core samples to comprehensively investigate the effects of temperature, pressure, gas volume, and gas type on oil recovery, asphaltene deposition, and permeability reduction. The results offer both quantitative and qualitative evidence supporting the potential of flue gas injection as an effective method for enhancing oil recovery, with notable advantages over CO 2 injection in certain conditions. The key findings from this study can be summarized as follows: At each pressure level, the oil recovery factor for CO 2 injection was approximately 15 % higher than that of flue gas. However, when comparing equal standard volumes of injected gas, flue gas demonstrated greater efficiency, with recovery factors about 16 % to 46 % higher than those of CO 2 . This indicates that a larger standard volume of CO 2 is required to achieve the same level of oil recovery. Therefore, given the greater availability of flue gas, injecting it at a moderately higher pressure (20 % to 30 %) but with a lower gas volume (10 % to 15 %) can yield oil recovery results comparable to CO 2 injection. The injection pressure has a greater effect on oil recovery than the gas type. Increasing the CO 2 content of flue gas from 25 % to 100 % resulted in a modest 12 % improvement in the oil recovery factor. This improvement is comparable to that achieved with a 1000 psi pressure increase. Additionally, the miscibility condition of CO 2 , in comparison to the immiscibility condition of flue gas, has a smaller effect on oil recovery than injection pressure. Therefore, at high pressures, the immiscible state of flue gas has a minimal effect on oil recovery. At the reservoir pressure and temperature, the asphaltene deposition percentage onto the core sample and the formation damage index for CO 2 were 18.6 % and 67 % higher than those for flue gas, respectively. Thus, CO 2 injection poses a higher risk of asphaltene deposition and formation damage compared to flue gas. Flue gas potentially serves as a viable alternative to CO 2 in EOR injection projects due to its competitive oil recovery and lower risk of asphaltene deposition. While requiring additional pressure compared to CO 2 , flue gas injection offers reduced asphaltene inhibition costs and less reservoir damage. Declarations Data availability All data supporting the findings of this study are available within the article. Acknowledgements The authors acknowledge the Ahwaz Petroleum University of Technology Research Centre for providing materials and facilities. 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Petroleum Science and Technology 35 , 313-318 (2017). Soroush, S., Pourafshary, P. & Vafaie-Sefti, M. in SPE EOR Conference at Oil and Gas West Asia. SPE-169657-MS (SPE). Additional Declarations No competing interests reported. Supplementary Files Appendix.docx Cite Share Download PDF Status: Under Review Version 1 posted Editorial decision: Revision requested 25 Jul, 2025 Reviews received at journal 24 Jul, 2025 Reviewers agreed at journal 14 Jul, 2025 Reviews received at journal 17 Jun, 2025 Reviewers agreed at journal 08 Jun, 2025 Reviewers invited by journal 03 Jun, 2025 Editor assigned by journal 03 Jun, 2025 Editor invited by journal 02 Jun, 2025 Submission checks completed at journal 02 Jun, 2025 First submitted to journal 29 May, 2025 You are reading this latest preprint version Research Square lets you share your work early, gain feedback from the community, and start making changes to your manuscript prior to peer review in a journal. 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Also discoverable on Platform About Our Team In Review Editorial Policies Advisory Board Help Center Resources Author Services Accessibility API Access RSS feed Manage Cookie Preferences © Research Square 2026 | ISSN 2693-5015 (online) Privacy Policy Terms of Service Do Not Sell My Personal Information {"props":{"pageProps":{"initialData":{"identity":"rs-6779359","acceptedTermsAndConditions":true,"allowDirectSubmit":false,"archivedVersions":[],"articleType":"Article","associatedPublications":[],"authors":[{"id":466288080,"identity":"a2a0da3f-8a38-4851-b2ac-450ddc681bd9","order_by":0,"name":"Parviz 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and after CO\u003csub\u003e2\u003c/sub\u003e injection at 110 ºC and 3000 psi in core C#2\u003c/p\u003e","description":"","filename":"19.png","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/32b18e27304ecbaab0637395.png"},{"id":83980703,"identity":"36f70a22-1a6c-49f3-b608-9ed1c70e5f1a","added_by":"auto","created_at":"2025-06-05 09:59:59","extension":"png","order_by":20,"title":"Figure 20","display":"","copyAsset":false,"role":"figure","size":32888,"visible":true,"origin":"","legend":"\u003cp\u003ePermeability curve before and after CO\u003csub\u003e2\u003c/sub\u003e injection at 110 ºC and 4300 psi in core C#2\u003c/p\u003e","description":"","filename":"20.png","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/37b9e7a98598d85e077c5a1e.png"},{"id":83980700,"identity":"f1e1d3d1-46c1-4cdc-9273-520cca92b2a8","added_by":"auto","created_at":"2025-06-05 09:59:59","extension":"png","order_by":21,"title":"Figure 21","display":"","copyAsset":false,"role":"figure","size":33632,"visible":true,"origin":"","legend":"\u003cp\u003ePermeability curve before and after CO\u003csub\u003e2\u003c/sub\u003e injection at 110 ºC and 5000 psi in core C#2\u003c/p\u003e","description":"","filename":"21.png","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/cc81398fdd0dc6c57e1a4355.png"},{"id":83980698,"identity":"9aaa3c45-5fe6-4b87-94dd-591eae418f08","added_by":"auto","created_at":"2025-06-05 09:59:59","extension":"png","order_by":22,"title":"Figure 22","display":"","copyAsset":false,"role":"figure","size":18168,"visible":true,"origin":"","legend":"\u003cp\u003eDamage index of formation due to gas injection\u003c/p\u003e","description":"","filename":"22.png","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/bb02175ff64840f29dcd22e0.png"},{"id":83980707,"identity":"f56bf0cb-cf72-4dd4-b660-108fb620520c","added_by":"auto","created_at":"2025-06-05 09:59:59","extension":"png","order_by":23,"title":"Figure 23","display":"","copyAsset":false,"role":"figure","size":56174,"visible":true,"origin":"","legend":"\u003cp\u003eURF, asphaltene dep. %, and permeability red. % during flue gas injection vs. injection pressure\u003c/p\u003e","description":"","filename":"23.png","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/e46e6c06e98c80dc5df9b0d0.png"},{"id":83980699,"identity":"49883514-edb7-4858-9530-40a579fa7331","added_by":"auto","created_at":"2025-06-05 09:59:59","extension":"png","order_by":24,"title":"Figure 24","display":"","copyAsset":false,"role":"figure","size":56685,"visible":true,"origin":"","legend":"\u003cp\u003eURF, asphaltene dep. %, and permeability red. % during CO\u003csub\u003e2\u003c/sub\u003e injection vs. injection pressure\u003c/p\u003e","description":"","filename":"24.png","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/e29c302374bdec27a1238289.png"},{"id":83981176,"identity":"5122a66b-5a85-4431-bd2b-03010f593084","added_by":"auto","created_at":"2025-06-05 10:07:59","extension":"png","order_by":25,"title":"Figure 25","display":"","copyAsset":false,"role":"figure","size":50146,"visible":true,"origin":"","legend":"\u003cp\u003eEffect of pressure on the permeability reduction of cores after gas flooding at 110 ºC\u003c/p\u003e","description":"","filename":"25.png","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/2efe4b69791157ede4dd7b6e.png"},{"id":83983539,"identity":"ac5843cf-82be-4094-b66e-d13c2eb80ad4","added_by":"auto","created_at":"2025-06-05 10:32:08","extension":"pdf","order_by":0,"title":"","display":"","copyAsset":false,"role":"manuscript-pdf","size":2576725,"visible":true,"origin":"","legend":"","description":"","filename":"manuscript.pdf","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/72d93ec2-ed71-45c3-a0d5-49390845af39.pdf"},{"id":83980683,"identity":"42d94406-2481-4d20-8728-9f800baf7749","added_by":"auto","created_at":"2025-06-05 09:59:58","extension":"docx","order_by":0,"title":"","display":"","copyAsset":false,"role":"supplement","size":37181,"visible":true,"origin":"","legend":"","description":"","filename":"Appendix.docx","url":"https://assets-eu.researchsquare.com/files/rs-6779359/v1/669036be455b32905dee3801.docx"}],"financialInterests":"No competing interests reported.","formattedTitle":"Comprehensive experimental study to compare the effects of flue gases and CO 2 injection on enhancing oil recovery and asphaltene deposition","fulltext":[{"header":"Introduction","content":"\u003cp\u003eDue to the daily increase in the need for hydrocarbon fluids, increasing the cost-effectiveness of recovery from oil and gas reservoirs has become one of the topics of interest [\u003cspan citationid=\"CR1\" class=\"CitationRef\"\u003e1\u003c/span\u003e]. After primary and secondary recovery, approximately 50 to 60% of the original oil in place (OOIP) typically remains unrecovered [\u003cspan additionalcitationids=\"CR3\" citationid=\"CR2\" class=\"CitationRef\"\u003e2\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR4\" class=\"CitationRef\"\u003e4\u003c/span\u003e]. These conventional recovery methods often lack the efficiency needed for effective extraction. As a result, enhanced oil recovery (EOR) techniques have become the most widely adopted approach for maximizing oil production in the later stages of reservoir development [\u003cspan additionalcitationids=\"CR6 CR7\" citationid=\"CR5\" class=\"CitationRef\"\u003e5\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR8\" class=\"CitationRef\"\u003e8\u003c/span\u003e]. Numerous studies have demonstrated the importance of EOR methods and the need to improve their effectiveness [\u003cspan additionalcitationids=\"CR10 CR11 CR12 CR13\" citationid=\"CR9\" class=\"CitationRef\"\u003e9\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR14\" class=\"CitationRef\"\u003e14\u003c/span\u003e]. Among the various EOR strategies developed, gas injection, thermal injection, and chemical injection are the three primary techniques [\u003cspan citationid=\"CR15\" class=\"CitationRef\"\u003e15\u003c/span\u003e]. Of these, gas flooding methods are especially prominent in the oil industry due to their reliability and proven success in improving recovery rates [\u003cspan citationid=\"CR4\" class=\"CitationRef\"\u003e4\u003c/span\u003e, \u003cspan citationid=\"CR16\" class=\"CitationRef\"\u003e16\u003c/span\u003e, \u003cspan citationid=\"CR17\" class=\"CitationRef\"\u003e17\u003c/span\u003e]. Continued research and development in this field remain critical to overcoming current limitations and optimizing oil recovery.\u003c/p\u003e \u003cp\u003eGas injection processes utilize a range of gases, with carbon dioxide (CO\u003csub\u003e2\u003c/sub\u003e), natural gas, and nitrogen (N\u003csub\u003e2\u003c/sub\u003e) being among the most commonly applied [\u003cspan additionalcitationids=\"CR19\" citationid=\"CR18\" class=\"CitationRef\"\u003e18\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR20\" class=\"CitationRef\"\u003e20\u003c/span\u003e]. Extensive research has investigated CO\u003csub\u003e2\u003c/sub\u003e injection in EOR processes due to its notable impact on sweep efficiency and its role in reducing greenhouse gas emissions [\u003cspan additionalcitationids=\"CR22 CR23\" citationid=\"CR21\" class=\"CitationRef\"\u003e21\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR24\" class=\"CitationRef\"\u003e24\u003c/span\u003e]. Generally, CO\u003csub\u003e2\u003c/sub\u003e-based tertiary recovery methods have been reported to increase oil recovery efficiency by approximately 8 to 16% [\u003cspan citationid=\"CR25\" class=\"CitationRef\"\u003e25\u003c/span\u003e]. The success of CO\u003csub\u003e2\u003c/sub\u003e flooding is primarily attributed to its ability to reduce oil viscosity, induce oil swelling, and alter the interfacial properties of the crude oil\u0026ndash;CO\u003csub\u003e2\u003c/sub\u003e system. These effects collectively contribute to enhancing the overall efficiency of oil recovery [\u003cspan citationid=\"CR26\" class=\"CitationRef\"\u003e26\u003c/span\u003e, \u003cspan citationid=\"CR27\" class=\"CitationRef\"\u003e27\u003c/span\u003e]. Flue gas has also gained significant attention in recent years as a potential agent for enhanced oil recovery [\u003cspan citationid=\"CR28\" class=\"CitationRef\"\u003e28\u003c/span\u003e]. As a byproduct of industrial combustion processes such as fuel burning and cement production, it is readily available, low cost, and primarily composed of N\u003csub\u003e2\u003c/sub\u003e and CO\u003csub\u003e2\u003c/sub\u003e, along with variable amounts of sulfur dioxide (SO\u003csub\u003e2\u003c/sub\u003e), nitrogen oxides (NO\u003csub\u003ex\u003c/sub\u003e), carbon monoxide (CO), hydrogen sulfide (H\u003csub\u003e2\u003c/sub\u003eS), and particulate matter, depending on the combustion material used [\u003cspan citationid=\"CR29\" class=\"CitationRef\"\u003e29\u003c/span\u003e, \u003cspan citationid=\"CR30\" class=\"CitationRef\"\u003e30\u003c/span\u003e]. Compared to pure CO\u003csub\u003e2\u003c/sub\u003e injection, flue gas presents distinct advantages due to its diverse composition. While it shares certain properties with CO\u003csub\u003e2\u003c/sub\u003e, the presence of nitrogen and other components enables a broader impact on EOR performance. This mixture enhances oil recovery by altering reservoir fluid properties and improving sweep efficiency, while also contributing to environmental sustainability by repurposing industrial emissions [\u003cspan additionalcitationids=\"CR32 CR33\" citationid=\"CR31\" class=\"CitationRef\"\u003e31\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR34\" class=\"CitationRef\"\u003e34\u003c/span\u003e]. As a result, many researchers and companies are actively evaluating flue gas injection as a promising and versatile approach for EOR applications [\u003cspan citationid=\"CR33\" class=\"CitationRef\"\u003e33\u003c/span\u003e]. Its ability to simultaneously improve oil recovery and mitigate the environmental impact of greenhouse gas emissions highlights its value as a comprehensive EOR solution [\u003cspan citationid=\"CR35\" class=\"CitationRef\"\u003e35\u003c/span\u003e].\u003c/p\u003e \u003cp\u003eWhen gas is injected into an oil reservoir, it comes into contact with the reservoir oil and alters the equilibrium conditions and fluid properties, potentially leading to the precipitation of heavy organic compounds, primarily asphaltenes [\u003cspan citationid=\"CR19\" class=\"CitationRef\"\u003e19\u003c/span\u003e, \u003cspan citationid=\"CR36\" class=\"CitationRef\"\u003e36\u003c/span\u003e]. This issue presents a significant technical obstacle, where determining the potential for asphaltene precipitation and assessing its impact on process performance are essential for successful field applications. Therefore, it is vital to investigate the factors that influence asphaltene precipitation. Asphaltenes represent a complex mixture of structurally diverse molecules, primarily characterized by their solubility rather than specific structural and chemical properties. They are insoluble in light hydrocarbon solvents like n-alkenes but dissolve completely in light aromatic hydrocarbons such as toluene, benzene, and xylene [\u003cspan citationid=\"CR37\" class=\"CitationRef\"\u003e37\u003c/span\u003e, \u003cspan citationid=\"CR38\" class=\"CitationRef\"\u003e38\u003c/span\u003e]. The intricate physical and chemical characteristics of asphaltenes present ongoing challenges for researchers. Asphaltene particles tend to aggregate, forming larger, more massive particles [\u003cspan citationid=\"CR39\" class=\"CitationRef\"\u003e39\u003c/span\u003e]. Variations in pressure, temperature, or composition cause the resin layer, which stabilizes asphaltenes, to shrink, triggering asphaltene precipitation [\u003cspan citationid=\"CR40\" class=\"CitationRef\"\u003e40\u003c/span\u003e]. This precipitation and subsequent deposition during oil production and processing is one of the costliest technical issues currently faced by the petroleum industry [\u003cspan citationid=\"CR41\" class=\"CitationRef\"\u003e41\u003c/span\u003e].\u003c/p\u003e \u003cp\u003eExtensive static and dynamic experiments have been conducted on asphaltene behavior during CO\u003csub\u003e2\u003c/sub\u003e injection, highlighting the importance of understanding its precipitation mechanisms in such processes. According to existing literature, asphaltene instability during CO\u003csub\u003e2\u003c/sub\u003e injection is affected by parameters such as pressure, temperature, CO\u003csub\u003e2\u003c/sub\u003e concentration, asphaltene structure, brine chemistry, and the existence of resins in crude oil [\u003cspan citationid=\"CR42\" class=\"CitationRef\"\u003e42\u003c/span\u003e]. In 2006, Verdier et al. examined the phase behavior of asphaltene precipitation during CO\u003csub\u003e2\u003c/sub\u003e injection at temperatures reaching 110\u0026deg;C and pressures up to 8700 psi. Using two crude oils with \u0026deg;API gravities of 27 and 29, they carried out CO\u003csub\u003e2\u003c/sub\u003e injection experiments in a PVT cell. Their findings showed that asphaltene precipitation decreased with lower temperatures and higher pressures. Furthermore, they observed that less CO\u003csub\u003e2\u003c/sub\u003e was needed to induce precipitation at elevated temperatures [\u003cspan citationid=\"CR43\" class=\"CitationRef\"\u003e43\u003c/span\u003e]. Zhou and Sarma (2012) conducted experiments using CO\u003csub\u003e2\u003c/sub\u003e concentrations ranging from 10 to 30 mol% at various temperatures between 54.5 and 120.5\u0026deg;C. They observed that increasing the temperature while keeping the CO\u003csub\u003e2\u003c/sub\u003e concentration constant led to a decrease in the asphaltene onset pressure. Conversely, increasing the CO\u003csub\u003e2\u003c/sub\u003e concentration at a constant temperature caused asphaltene precipitation to begin at higher pressures. When comparing the influence of CO\u003csub\u003e2\u003c/sub\u003e concentration and temperature, the concentration was found to have a more pronounced effect on asphaltene onset [\u003cspan citationid=\"CR44\" class=\"CitationRef\"\u003e44\u003c/span\u003e]. Zanganeh and colleagues (2012, 2015) conducted experiments on two oil samples with 12.8 and 31 \u0026deg;API gravities. They found that reducing pressure and temperature in the presence of CO\u003csub\u003e2\u003c/sub\u003e decreased asphaltene precipitation. However, increasing the CO\u003csub\u003e2\u003c/sub\u003e concentration (5\u0026ndash;20 mol %) at constant pressure led to an increase in precipitation. Additionally, elevating the temperature from 35 to 90\u0026deg;C promoted the growth and aggregation of asphaltenes [\u003cspan citationid=\"CR41\" class=\"CitationRef\"\u003e41\u003c/span\u003e, \u003cspan citationid=\"CR45\" class=\"CitationRef\"\u003e45\u003c/span\u003e]. Cao and Gu (2013) experimentally investigated the effects of temperature on the phase behaviour, fluid interactions, and oil recovery in a light crude oil-CO\u003csub\u003e2\u003c/sub\u003e system. Through a series of PVT, miscibility, and interfacial tension tests conducted at both laboratory and reservoir temperatures, they found that temperature significantly influenced saturation pressure and miscibility conditions, while having a marginal effect on the oil-swelling factor. Higher temperatures were shown to improve oil recovery under miscible CO\u003csub\u003e2\u003c/sub\u003e flooding [\u003cspan citationid=\"CR46\" class=\"CitationRef\"\u003e46\u003c/span\u003e]. In their study on asphaltene phase behavior, Cardoso et al. (2014) employed the quartz crystal resonator technique. The experiment involved gradually depressurizing a mixture containing 31 mol % CO\u003csub\u003e2\u003c/sub\u003e, 38.3 mol % CH\u003csub\u003e4\u003c/sub\u003e, and a dead oil sample at 45\u0026deg;C, with the oil containing 0.235 wt % asphaltenes. The results showed that slower depressurization led to a higher onset pressure, indicating that the rate of depressurization significantly affects asphaltene precipitation [\u003cspan citationid=\"CR47\" class=\"CitationRef\"\u003e47\u003c/span\u003e]. Cruz et al. (2019) used a variable-volume cell equipped with a near-infrared probe to investigate asphaltene precipitation induced by CO₂ under conditions representative of Brazil\u0026rsquo;s deep and ultra-deepwater Pre-Salt reservoirs, which are known for their high CO\u003csub\u003e2\u003c/sub\u003e content. The study evaluated the effects of pressure, temperature, asphaltene concentration, and system composition on the onset of precipitation. Their findings showed that temperature and system composition were the most influential factors on asphaltene stability [\u003cspan citationid=\"CR48\" class=\"CitationRef\"\u003e48\u003c/span\u003e]. Rezk and Foroozesh (2019) investigated the PVT properties of CO\u003csub\u003e2\u003c/sub\u003e and a Malaysian crude oil at temperatures of 50 and 95.5\u0026deg;C and pressures reaching up to 3713 psi. Their findings indicated that CO\u003csub\u003e2\u003c/sub\u003e solubility in oil increased with pressure, whereas elevated temperatures reduced its solubility [\u003cspan citationid=\"CR49\" class=\"CitationRef\"\u003e49\u003c/span\u003e]. In 2020, Dashti et al. developed a high-pressure visual experimental setup to investigate the rate of asphaltene deposition under various gas injection scenarios. They compared the effects of N\u003csub\u003e2\u003c/sub\u003e, CO\u003csub\u003e2\u003c/sub\u003e, and CH\u003csub\u003e4\u003c/sub\u003e on the deposition process at different pressures. Their findings showed that in the absence of gas injection, the rate of asphaltene deposition increased with pressure. Among the gases, CO\u003csub\u003e2\u003c/sub\u003e injection resulted in a deposition rate 1.2 times faster than CH\u003csub\u003e4\u003c/sub\u003e at 100 bar, while N\u003csub\u003e2\u003c/sub\u003e had a lesser effect. The study concluded that CO\u003csub\u003e2\u003c/sub\u003e injection led to more significant asphaltene deposition compared to CH₄ and N₂, with gas injection promoting the formation of larger flocculated asphaltene particles [\u003cspan citationid=\"CR20\" class=\"CitationRef\"\u003e20\u003c/span\u003e].\u003c/p\u003e \u003cp\u003eUnderstanding factors such as miscibility, CO\u003csub\u003e2\u003c/sub\u003e solubility, interfacial tension, aqueous phase, and the porous media characteristics are crucial to the success of flooding experiments, whether conducted at laboratory or field scale [\u003cspan citationid=\"CR42\" class=\"CitationRef\"\u003e42\u003c/span\u003e]. Hirschberg et al. (1984) studied CO\u003csub\u003e2\u003c/sub\u003e injection into light oil with an \u0026deg;API of 45. They found no asphaltene precipitation when CO\u003csub\u003e2\u003c/sub\u003e was added to the oil at pressures up to 2900 psi and ambient temperature. However, the addition of nC\u003csub\u003e10\u003c/sub\u003e triggered asphaltene precipitation [\u003cspan citationid=\"CR50\" class=\"CitationRef\"\u003e50\u003c/span\u003e]. In 2008, Dahaghi et al. examined CO\u003csub\u003e2\u003c/sub\u003e injection effects in a Kupal field reservoir in Iran at 71\u0026deg;C and 6000 psi. The crude oil initially had 0.59 wt % asphaltene. CO\u003csub\u003e2\u003c/sub\u003e concentrations ranged from 0.4 to approximately 0.8 mol %. Peak precipitation was observed at the saturation pressure of 3725 psi, while the MMP was recorded at 5300 psi. Initially, asphaltene levels in the produced oil declined, then began to rise after a specific pore volume was injected. The largest amount of precipitation was found near the core sample inlet [\u003cspan citationid=\"CR51\" class=\"CitationRef\"\u003e51\u003c/span\u003e]. Cao and Gu (2013) carried out core flooding experiments in tight sandstone rocks at two temperatures: 27\u0026deg;C and 53\u0026deg;C. The oil tested had an \u0026deg;API gravity of 36.37 and an asphaltene content of 0.26 wt %. Below the minimum miscibility pressure of the CO\u003csub\u003e2\u003c/sub\u003e-oil system, higher injection pressures led to increased recovery due to enhanced oil swelling, reduced viscosity, and lower interfacial tension. Above the MMP, recovery improvement slowed and was mainly attributed to further reduction in IFT. In both miscible and immiscible scenarios, permeability was negatively affected by asphaltene deposition, with greater impairment under miscible conditions [\u003cspan citationid=\"CR52\" class=\"CitationRef\"\u003e52\u003c/span\u003e]. Jafari Behbahani et al. (2014) carried out core flooding tests with a live crude oil sample at a constant temperature of 70\u0026deg;C and above MMP. CO\u003csub\u003e2\u003c/sub\u003e was injected at varying flow rates of 6, 12, and 18 cubic centimeters per hour. Analytical methods, including SEM imaging, X-ray analysis, and elemental composition, confirmed that greater asphaltene deposition occurred within the core samples as the CO\u003csub\u003e2\u003c/sub\u003e injection rate increased [\u003cspan citationid=\"CR53\" class=\"CitationRef\"\u003e53\u003c/span\u003e]. In 2015, Kazemzadeh et al. investigated asphaltene precipitation during CO\u003csub\u003e2\u003c/sub\u003e injection by measuring interfacial tension using oil samples from southwest Iran, which had \u0026deg;API gravities of 21.49 and 24.46 and asphaltene contents of 11 and 10 wt %, respectively. At low pressures, IFT decreased due to intense mass transfer between CO\u003csub\u003e2\u003c/sub\u003e and oil, but increased at higher pressures as asphaltenes began to form. The Bond number, representing the ratio of gravitational to capillary forces, showed an inverse trend compared to IFT. Both parameters exhibited a plateau or slowdown upon the onset of asphaltene precipitation [\u003cspan citationid=\"CR54\" class=\"CitationRef\"\u003e54\u003c/span\u003e]. Employing a micromodel setup, Song et al. (2018) studied CO\u003csub\u003e2\u003c/sub\u003e injection at 353.15 K and 1450 psi using two oil samples with \u0026deg;API gravities of 14.09 and 0.47, and asphaltene contents of 14.96 and 36.78 wt %, respectively. Microscopic analysis revealed that increasing the pressure to 1450 psi and CO\u003csub\u003e2\u003c/sub\u003e concentration to 80 mol % led to greater deposition and larger particle sizes, particularly near the micromodel inlet, with asphaltene sizes reaching up to 200 \u0026micro;m. When comparing the two oils, higher oil recovery and reduced asphaltene precipitation were observed in heavy oils, due to improved CO\u003csub\u003e2\u003c/sub\u003e solubility and viscosity reduction of up to 95%. In contrast, miscibility in light oils promoted more asphaltene precipitation [\u003cspan citationid=\"CR55\" class=\"CitationRef\"\u003e55\u003c/span\u003e]. In 2019, Qian et al. performed CO\u003csub\u003e2\u003c/sub\u003e injection experiments on tight sandstone cores with porosity between 16.18 and 17.94% and permeability ranging from 2.67 to 3.31 mD, under conditions of 1160\u0026ndash;3770 psi and 61\u0026deg;C. Their findings revealed that asphaltenes were distributed throughout the pore structure, with more noticeable accumulation at elevated pressures due to enhanced solubility and the extraction of light components by CO\u003csub\u003e2\u003c/sub\u003e. They noted that formation damage was more pronounced in medium and large pores compared to smaller ones, attributed to stronger CO\u003csub\u003e2\u003c/sub\u003e-oil interactions. Moreover, the core wettability transitioned from water-wet to oil-wet [\u003cspan citationid=\"CR56\" class=\"CitationRef\"\u003e56\u003c/span\u003e]. Fakher and Imqam (2019) conducted core flooding experiments using CO\u003csub\u003e2\u003c/sub\u003e injection under different conditions. The tested crude oils had viscosities of 470, 267, and 67 cP, with an asphaltene content of 5.73 wt %. As the CO\u003csub\u003e2\u003c/sub\u003e injection pressure increased, a greater amount of asphaltene appeared in the produced oil. Additionally, raising the temperature led to improved oil recovery and promoted more asphaltene precipitation within the residual oil. The oil with the highest viscosity showed an asphaltene precipitation of 18 wt %, compared to 10 wt % for the least viscous oil [\u003cspan citationid=\"CR57\" class=\"CitationRef\"\u003e57\u003c/span\u003e]. In a subsequent study in 2020, they discussed that raising the CO\u003csub\u003e2\u003c/sub\u003e injection pressure at 100\u0026deg;C led to reduced oil viscosity and enhanced oil swelling, while also resulting in less asphaltene deposition within the core [\u003cspan citationid=\"CR58\" class=\"CitationRef\"\u003e58\u003c/span\u003e]. Elturki and Imqam (2022) conducted a visual study of asphaltene precipitation and deposition in a nanopore shale structure, considering the minimum miscibility pressure (MMP). They examined immiscible pressures of 750 and 1250 psi and miscible pressures of 1750 and 2000 psi. When CO\u003csub\u003e2\u003c/sub\u003e was injected under miscible conditions, there was an increase in precipitation, particularly at higher flow rates. Scanning electron microscopy (SEM) images of the filter paper membranes showed pore plugging in shale core samples under both immiscible and miscible conditions. The researchers found that asphaltene precipitation increased with CO\u003csub\u003e2\u003c/sub\u003e injection pressure, which they attributed to the role of resins in facilitating asphaltene suspension. They proposed that at higher pressures, the resins break down and are unable to surround asphaltene molecules, leading to precipitation and deposition [\u003cspan citationid=\"CR59\" class=\"CitationRef\"\u003e59\u003c/span\u003e]. Xiong et al. (2023) investigated the impact of injecting methane, carbon dioxide, and nitrogen on asphaltene deposition. Their findings indicated that the extent of asphaltene precipitation was closely linked to the miscibility of the injected gases. Consistent with earlier research, nitrogen injection resulted in the least asphaltene deposition, while carbon dioxide led to more precipitation compared to methane [\u003cspan citationid=\"CR60\" class=\"CitationRef\"\u003e60\u003c/span\u003e]. Li et al. (2024) studied asphaltene precipitation in reservoirs under CO\u003csub\u003e2\u003c/sub\u003e injection, especially under high-pressure, high-temperature conditions, an area that is not fully understood. By combining experiments, numerical simulations, and phase-state simulations, they investigated how different pressures, temperatures, and gas injection amounts affected asphaltene precipitation and its impact on reservoir permeability and oil production. Their findings revealed that CO\u003csub\u003e2\u003c/sub\u003e injection induces the desorption of colloid-asphaltene inclusions, followed by the polymerization of dispersed asphaltene molecules. The injection of CO\u003csub\u003e2\u003c/sub\u003e resulted in more precipitation and shifted the precipitation curve to higher pressures. The core\u0026rsquo;s permeability decreased by 12.87\u0026ndash;37.54% due to asphaltene deposition. Additionally, asphaltene deposition led to a 1.5% reduction in oil recovery and a 17% drop in injection rate [\u003cspan citationid=\"CR61\" class=\"CitationRef\"\u003e61\u003c/span\u003e].\u003c/p\u003e \u003cp\u003eWhile CO\u003csub\u003e2\u003c/sub\u003e injection has been extensively studied in the context of asphaltene precipitation and enhanced oil recovery, comparatively fewer investigations (Appendix: Table A1) have focused on the effects of flue gas injection, despite its growing relevance as a cost-effective and readily available alternative. Most of these studies have primarily focused on improving the oil recovery factor. Fong et al. (1992) conducted core flood experiments to evaluate flue gas injection as a potential EOR method for the Lost Hills diatomite reservoir. Despite an early breakthrough, a total recovery of 23% of OOIP was achieved, with a final residual oil saturation of 46% pore volume. The study highlighted that while the recovery was lower compared to CO\u003csub\u003e2\u003c/sub\u003e flooding under similar conditions, flue gas injection still offered incremental oil recovery and could be a technically viable option if a reliable gas source is available [\u003cspan citationid=\"CR62\" class=\"CitationRef\"\u003e62\u003c/span\u003e]. Srivastava et al. (1999) evaluated the effectiveness of flue gas injection for heavy oil recovery in the Senlac reservoir using both PVT analysis and core flood experiments. The flue gas used consisted of 15.6 mol% CO\u003csub\u003e2\u003c/sub\u003e and 84.4 mol% N\u003csub\u003e2\u003c/sub\u003e. PVT results showed that flue gas had the lowest gas solubility, viscosity reduction, and oil swelling compared to pure CO\u003csub\u003e2\u003c/sub\u003e and produced gas, making it the least effective of the three in terms of oil phase behavior. However, core flood tests demonstrated that flue gas injection can still achieve significant oil recovery, particularly in water-alternating-gas (WAG) schemes [\u003cspan citationid=\"CR28\" class=\"CitationRef\"\u003e28\u003c/span\u003e]. In 2002, Dong and Huang evaluated flue gas injection for heavy oil recovery in Saskatchewan reservoirs through a combination of PVT analysis and two-dimensional physical model tests. Three synthetic flue gas mixtures were tested, with varying CO\u003csub\u003e2\u003c/sub\u003e concentrations up to 25 mol %. The results showed that increasing the CO\u003csub\u003e2\u003c/sub\u003e content in flue gas led to greater oil swelling and viscosity reduction. Live oils responded more effectively than dead oils. Simulations and phase behavior studies confirmed that the free-gas drive mechanism plays a dominant role in oil recovery due to the high nitrogen content and limited solubility of the gas [\u003cspan citationid=\"CR33\" class=\"CitationRef\"\u003e33\u003c/span\u003e]. Shokoya et al. (2004) investigated the mechanism of flue gas injection for light oil recovery using slim-tube experiments under reservoir conditions. Three flue gas compositions were tested, with nitrogen content ranging from 69\u0026ndash;100%. The experiments were conducted at 116\u0026deg;C and pressures from 1102 to 6686 psi. Results showed that oil displacement occurred through a combined vaporizing-condensing gas drive mechanism. Although true miscibility was not achieved, oil recovery increased with pressure and CO\u003csub\u003e2\u003c/sub\u003e content in the flue gas. The study emphasized that enriched flue gas, even under near-miscible conditions, can enhance light oil recovery effectively [\u003cspan citationid=\"CR35\" class=\"CitationRef\"\u003e35\u003c/span\u003e]. Shokoya et al. (2005) investigated the performance of flue gas injection for light oil recovery using laboratory displacement tests and compositional simulation. Two light oils with different paraffin and naphthene contents were tested using flue gas containing 16% and 30% CO\u003csub\u003e2\u003c/sub\u003e. Experiments were conducted in long sandstone cores at reservoir pressures up to 6030 psi and temperatures of 80.6\u0026deg;C and 116\u0026deg;C. The results showed that oil recovery improved with higher reservoir pressure and greater CO\u003csub\u003e2\u003c/sub\u003e content in the injected gas. Oils with higher naphthene and lower paraffin content yielded higher recovery [\u003cspan citationid=\"CR63\" class=\"CitationRef\"\u003e63\u003c/span\u003e]. Same authors (2005) studied the effect of CO\u003csub\u003e2\u003c/sub\u003e concentration in flue gas on oil recovery through core flooding and simulation. Tests were conducted using recombined live oils and sandstone cores under reservoir pressure and temperature conditions. Results showed that higher CO\u003csub\u003e2\u003c/sub\u003e content improved oil swelling and viscosity reduction, leading to increased oil recovery. However, even at lower CO\u003csub\u003e2\u003c/sub\u003e concentrations, significant recovery was achieved due to the free-gas drive effect provided by nitrogen [\u003cspan citationid=\"CR64\" class=\"CitationRef\"\u003e64\u003c/span\u003e]. Mohsenzadeh et al. (2014) investigated the effects of CO\u003csub\u003e2\u003c/sub\u003e, N\u003csub\u003e2\u003c/sub\u003e, and synthetic flue gas injection on heavy oil recovery in fractured carbonate reservoirs using a long-core laboratory model under reservoir conditions. The results indicated that before gas breakthrough, oil recovery was primarily from the fracture system, with flue gas injection yielding the highest production rate due to a combined effect of oil swelling and piston-like displacement [\u003cspan citationid=\"CR65\" class=\"CitationRef\"\u003e65\u003c/span\u003e]. Bender and Akin (2017) evaluated flue gas injection as an alternative to pure CO\u003csub\u003e2\u003c/sub\u003e injection for enhanced oil recovery and storage in a mature oil field in Turkey. A compositional reservoir simulation model was developed and history matched using 31 years of field data. The results showed that while continuous pure CO\u003csub\u003e2\u003c/sub\u003e injection provided higher oil recovery and CO\u003csub\u003e2\u003c/sub\u003e storage over the long term, flue gas injection offered comparable oil recovery for injection periods shorter than 25 years [\u003cspan citationid=\"CR66\" class=\"CitationRef\"\u003e66\u003c/span\u003e]. Li et al. (2017) investigated the effects of flue gas and n-hexane on heavy oil recovery through laboratory experiments involving steam flooding, flue gas\u0026ndash;assisted steam flooding, n-hexane flooding, and steam flooding assisted by both flue gas and n-hexane. The results showed that flue gas dissolved in heavy oil effectively reduced viscosity, enhanced flowability, and caused the oil to swell. The combined use of flue gas and n-hexane led to the best performance, resulting in the lowest displacement pressure, the highest oil production rate, and recovery efficiency reaching up to 80% [\u003cspan citationid=\"CR67\" class=\"CitationRef\"\u003e67\u003c/span\u003e]. Pang et al. (2018) evaluated the effectiveness of flue gas and steam co-injection for enhancing heavy oil recovery. The results showed that the dissolution of CO\u003csub\u003e2\u003c/sub\u003e from flue gas into heavy oil significantly reduced viscosity and improved mobility, while nitrogen, although largely insoluble, contributed to pressure maintenance and reduced heat loss by accumulating at the reservoir top [\u003cspan citationid=\"CR68\" class=\"CitationRef\"\u003e68\u003c/span\u003e]. Wu et al. (2018) investigated the application of flue gas in combination with steam for enhancing oil recovery in thick extra-heavy oil reservoirs through PVT experiments and 3D physical simulations. The flue gas, composed of 80% N\u003csub\u003e2\u003c/sub\u003e and 20% CO\u003csub\u003e2\u003c/sub\u003e, was shown to reduce oil viscosity by dissolving CO\u003csub\u003e2\u003c/sub\u003e into the crude, increasing oil expansibility and mobility. In the 3D experiments, flue gas\u0026ndash;assisted steam flooding achieved an ultimate oil recovery of 49.5%, which was 7.95% higher than steam flooding alone [\u003cspan citationid=\"CR69\" class=\"CitationRef\"\u003e69\u003c/span\u003e]. Tao et al. (2021) conducted a large-scale 3D physical simulation to investigate the enhanced oil recovery performance of flue gas-assisted steam assisted gravity drainage (SAGD) in heavy oil reservoirs. The results indicated that injecting flue gas alongside steam improved the oil recovery by 5.7% compared to conventional SAGD [\u003cspan citationid=\"CR70\" class=\"CitationRef\"\u003e70\u003c/span\u003e]. Min and Zhang (2024) investigated the impact of flue gas foam-assisted steam flooding on the development of complex heavy oil reservoirs. Their results indicated that the presence of flue gas enhanced reservoir energy and reduced interfacial tension, with higher CO\u003csub\u003e2\u003c/sub\u003e content being more effective in lowering interfacial tension [\u003cspan citationid=\"CR71\" class=\"CitationRef\"\u003e71\u003c/span\u003e]. Nassabeh et al. (2025) conducted a comprehensive numerical study to evaluate the performance of flue gas injection compared to CO\u003csub\u003e2\u003c/sub\u003e injection under heterogeneous reservoir conditions. Simulation results showed that flue gases containing higher concentrations of CO\u003csub\u003e2\u003c/sub\u003e and O\u003csub\u003e2\u003c/sub\u003e achieved better oil recovery, while water vapor negatively affected both recovery and reservoir pressure [\u003cspan citationid=\"CR72\" class=\"CitationRef\"\u003e72\u003c/span\u003e].\u003c/p\u003e \u003cp\u003eAmong the literature, only one study has directly investigated asphaltene deposition resulting from flue gas injection under reservoir conditions. Jalili et al. (2024) investigated the effects of CO\u003csub\u003e2\u003c/sub\u003e and flue gas injection on oil recovery and asphaltene-related formation damage under reservoir conditions using an elongated core composed of four connected plugs. The results showed that CO\u003csub\u003e2\u003c/sub\u003e injection achieved a significantly higher oil recovery (86%) compared to flue gas (36%), attributed to better miscibility and a greater swelling effect. However, CO\u003csub\u003e2\u003c/sub\u003e injection also led to more severe asphaltene deposition and formation damage, with a permeability reduction of up to 14.8%, while flue gas injection caused a milder impairment of 4.4%. The most pronounced damage occurred in the first two plugs near the injection point, and the final two plugs showed negligible deposition, suggesting minimal gas\u0026ndash;oil interaction in that zone. Although flue gas resulted in lower recovery, it offered improved flow assurance and reduced the risk of plugging, making it a potentially favorable option where formation damage is a concern [\u003cspan citationid=\"CR4\" class=\"CitationRef\"\u003e4\u003c/span\u003e]. This study did not examine the effects of varying temperatures and injection pressures on asphaltene deposition and the associated formation damage. Additionally, the influence of CO\u003csub\u003e2\u003c/sub\u003e miscibility on formation damage, and a comparison with the formation damage caused by flue gas, were not explored. Table A.1 summarizes key parameters from previous flue gas flooding experiments reported in the literature, including gas type, oil sample, core properties, injection conditions, oil recovery factor, and formation damage.\u003c/p\u003e \u003cp\u003eThe objective of this study is to experimentally investigate and compare the performance of flue gas and carbon dioxide injection for enhanced oil recovery in low-permeability carbonate reservoirs using recombined live oil. Particular focus is given to understanding the impact of injection pressure, temperature, gas volume, and gas type on oil recovery efficiency, asphaltene deposition, and permeability reduction. A series of core flood experiments were conducted under both immiscible and miscible conditions using two representative carbonate core samples. The results aim to provide quantitative insights into the viability of flue gas as an alternative to carbon dioxide in EOR operations, especially where formation damage and gas availability are critical factors. This work contributes to optimizing gas injection strategies for improved recovery while mitigating reservoir damage in challenging reservoir conditions.\u003c/p\u003e"},{"header":"Materials and methods","content":"\u003cp\u003e\u003cstrong\u003eMaterials\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eTwo comparable carbonate core samples, labeled F#1 and C#2, were selected from the Abteymour oilfield and prepared for core flood testing. Two types of non-hydrocarbon gases, pure CO\u003csub\u003e2\u003c/sub\u003e and synthetic flue gas, were used as displacing fluids. The flue gas was prepared by mixing 25 mol% % pure CO\u003csub\u003e2\u003c/sub\u003e with 75 mol% % pure N\u003csub\u003e2\u003c/sub\u003e. The primary liquid solvents used in the experiments included activated silica and ultrapure reagents (\u0026gt;99% purity) of cyclohexane, toluene, n-heptane, methanol, chloroform, and acetonitrile. To prepare the recombined live oil for core saturation, stock tank oil from the specified oilfield was mixed with associated first-stage gas under reservoir conditions. The oil specifications and reservoir conditions are presented in Table 1. The kinematic viscosity and density of the stock tank oil at various temperatures are listed in Table 2. The compositions of the stock tank oil, associated gas, and synthetic recombined live oil are presented in Table 3, and the SARA analysis of the stock tank oil is shown in Table 4.\u003c/p\u003e\n\u003cp\u003e\u0026nbsp;\u003cstrong\u003eTable 1.\u003c/strong\u003e Reservoir conditions and oil specifications of the specified oilfield\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"605\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 14.0264%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eReservoir pressure\u003c/strong\u003e\u003c/p\u003e\n \u003cp\u003e\u003cstrong\u003e(psi)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 18.6469%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eReservoir temperature (\u0026ordm;C)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 18.6469%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eGOR (SCF/STB)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 18.6469%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eOil viscosity at reservoir condition (cp)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 18.6469%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eOil density at reservoir condition (g/cm\u003csup\u003e3\u003c/sup\u003e)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 11.3861%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eOil \u0026ordm;API gravity\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 14.0264%;\"\u003e\n \u003cp\u003e6000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 18.6469%;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 18.6469%;\"\u003e\n \u003cp\u003e342.38\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 18.6469%;\"\u003e\n \u003cp\u003e3\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 18.6469%;\"\u003e\n \u003cp\u003e0.8128\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 11.3861%;\"\u003e\n \u003cp\u003e21\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003e\u003cstrong\u003e\u0026nbsp;\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003e\u0026nbsp;\u003cstrong\u003eTable 2.\u003c/strong\u003e Kinematic viscosity and density of stock tank oil at various temperatures\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"574\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 34.555%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eTemperature (\u0026ordm;C)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 26.3525%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eDensity (g/cm\u003csup\u003e3\u003c/sup\u003e)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 39.0925%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eKinematic viscosity (m\u003csup\u003e2\u003c/sup\u003e/s) *1000\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 34.555%;\"\u003e\n \u003cp\u003e15\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 26.3525%;\"\u003e\n \u003cp\u003e0.9228\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 39.0925%;\"\u003e\n \u003cp\u003e0.177\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 34.555%;\"\u003e\n \u003cp\u003e25\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 26.3525%;\"\u003e\n \u003cp\u003e0.9160\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 39.0925%;\"\u003e\n \u003cp\u003e0.099\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 34.555%;\"\u003e\n \u003cp\u003e40\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 26.3525%;\"\u003e\n \u003cp\u003e0.9047\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 39.0925%;\"\u003e\n \u003cp\u003e0.047\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 34.555%;\"\u003e\n \u003cp\u003e50\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 26.3525%;\"\u003e\n \u003cp\u003e0.8967\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 39.0925%;\"\u003e\n \u003cp\u003e0.031\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 34.555%;\"\u003e\n \u003cp\u003e55\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 26.3525%;\"\u003e\n \u003cp\u003e0.8953\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 39.0925%;\"\u003e\n \u003cp\u003e0.026\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 34.555%;\"\u003e\n \u003cp\u003e60\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 26.3525%;\"\u003e\n \u003cp\u003e0.8922\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 39.0925%;\"\u003e\n \u003cp\u003e0.022\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003e\u003cbr\u003e\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eTable 3.\u003c/strong\u003e Compositions of stock tank oil, associated gas, and recombined oil\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"576\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eComponents\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eStock tank oil\u0026nbsp;\u003c/strong\u003e\u003c/p\u003e\n \u003cp\u003e\u003cstrong\u003e(mole%)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eAssociated gas\u0026nbsp;\u003c/strong\u003e\u003c/p\u003e\n \u003cp\u003e\u003cstrong\u003e(mole%)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eRecombined oil\u0026nbsp;\u003c/strong\u003e\u003c/p\u003e\n \u003cp\u003e\u003cstrong\u003e(mole%)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eH\u003csub\u003e2\u003c/sub\u003eS\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eN\u003csub\u003e2\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.11\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e0.05\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.69\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e0.31\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e1\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e75.36\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e34.32\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e2\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.10\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e12.17\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e5.60\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e3\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.27\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e7.15\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e3.40\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eiC\u003csub\u003e4\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.26\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e1.83\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e0.97\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003enC\u003csub\u003e4\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e1.50\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e1.92\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e1.69\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eiC\u003csub\u003e5\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e1.67\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.36\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e1.07\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003enC\u003csub\u003e5\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e1.96\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.34\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e1.22\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e6\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e10.58\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.06\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e5.79\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e7\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e6.36\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.01\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e3.47\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e8\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e7.53\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e4.10\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e9\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e10.61\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e5.78\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e10\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e5.31\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e2.89\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e11\u003c/sub\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e5.56\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e3.03\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 19.5841%;\"\u003e\n \u003cp\u003e\u003cstrong\u003eC\u003csub\u003e12\u003c/sub\u003e\u003csup\u003e+\u003c/sup\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e48.28\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 27.7296%;\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 24.9567%;\"\u003e\n \u003cp\u003e26.30\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003e\u003cbr\u003e\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eTable 4.\u003c/strong\u003e SARA analysis of the stock tank oil used in this study\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"538\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 24.8609%;\"\u003e\n \u003cp dir=\"RTL\"\u003e\u003cstrong\u003e\u003cspan dir=\"LTR\"\u003eSaturate\u003c/span\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 25.0464%;\"\u003e\n \u003cp dir=\"RTL\"\u003e\u003cstrong\u003e\u003cspan dir=\"LTR\"\u003eAromatic\u003c/span\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 25.0464%;\"\u003e\n \u003cp dir=\"RTL\"\u003e\u003cstrong\u003e\u003cspan dir=\"LTR\"\u003eResin\u003c/span\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 25.0464%;\"\u003e\n \u003cp dir=\"RTL\"\u003e\u003cstrong\u003e\u003cspan dir=\"LTR\"\u003eAsphaltene\u003c/span\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd valign=\"bottom\" style=\"width: 24.8609%;\"\u003e\n \u003cp\u003e28.82\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 25.0464%;\"\u003e\n \u003cp\u003e33.90\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 25.0464%;\"\u003e\n \u003cp\u003e24.41\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 25.0464%;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003e\u003cstrong\u003eExperimental\u0026nbsp;\u003c/strong\u003e\u003cstrong\u003eprocedure\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eIn this study, a core flooding system served as the primary experimental setup, while two additional systems were used for preparing recombined live oil and synthetic flue gas. Details of all setups are described below, along with an explanation of the core preparation process.\u003c/p\u003e\n\u003cp\u003eThe recombined oil apparatus consisted of a high-pressure piston cylinder with a 1000 cubic meter capacity and a maximum working allowable pressure (MWAP) of 6000 psi, along with a mechanical shaking device. Two additional high-pressure piston cylinders, identical to the oil apparatus, were used as CO\u003csub\u003e2\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e gas containers for preparing the flue gas. An ISCO high-pressure syringe pump was employed to transfer and pressurize the fluids.\u003c/p\u003e\n\u003cp\u003eThe core flood setup, illustrated in Figure 1, consisted of an ISCO high-pressure pump capable of injecting up to 7000 psi, three high-pressure piston cylinders, a heating jacket, pressure gauges, a thermocouple, a core holder (maximum pressure tolerance of 7000 psi and flow rate range of 0.001 to 60 cm\u0026sup3;/min), a back-pressure regulator, and a differential pressure transmitter. The pump\u0026rsquo;s speed, volume, and movement were fully programmable and digitally controlled. A pressure regulator ensured stable pressure throughout the experiments. All components were enclosed within an air bath equipped with a thermostat to maintain a constant temperature during the displacement tests. The wall-mounted core holder was constructed from a steel tube with a thickness of 0.953 cm, an outer diameter of 8.89 cm, and a length of 32 cm. The core sample was placed inside a sleeve to isolate it from the injected fluids within the core holder. The ring surrounding the sleeve was filled with water to apply an additional confining pressure of 500\u0026ndash;700 psi to the core.\u003c/p\u003e\n\u003cp\u003eThe volume of gas injected into the core was automatically measured using the ISCO injection pump. The setup, equipped with a back-pressure regulator (BPR), included a precise diaphragm regulator with a stainless-steel diaphragm to maintain port pressure within the core. The produced liquid was collected in a graduated cylinder, while the gas was released into the atmosphere.\u003c/p\u003e\n\u003cp\u003eAs presented in Table 5, the experiments in this investigation were categorized into three subgroups: primary (PA), main (MA), and supplementary (SA) tests and activities, performed before, during, and after gas injection, respectively. The primary tests included core and fluid property measurements, as well as the preparation of recombined live oil and synthetic flue gas. The main experiments involved multiple gas injections under varying temperatures, pressures, and gas types. Additionally, related tests, such as water and oil saturation and cyclohexane injection, were conducted before and after gas flooding. The supplementary activities included measurements of core samples and produced oil, such as core deposition and asphaltene content analysis.\u003c/p\u003e\n\u003cp\u003e\u0026nbsp;\u003cstrong\u003eTable 5.\u003c/strong\u003e Classification of the experiments conducted in core flooding tests\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"592\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd colspan=\"2\" style=\"width: 198px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eClassification\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 190px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eDescription\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 204px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eDetails\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd rowspan=\"2\" style=\"width: 38px;\"\u003e\n \u003cp\u003e\u003cstrong\u003ePrimary (PA)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 161px;\"\u003e\n \u003cp\u003eFluid and core properties\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 190px;\"\u003e\n \u003cp\u003eFluid properties measurements - Core properties measurements\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 204px;\"\u003e\n \u003cp\u003eMMP- Recombined oil-Bubble point - Porosity-Permeability\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 161px;\"\u003e\n \u003cp\u003eFluid preparation\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 190px;\"\u003e\n \u003cp\u003eRecombined oil preparation - Synthetic flue gas preparation\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 204px;\"\u003e\n \u003cp\u003eMixing and pressurizing dead oil and associated gas at GOR ratio - Mixing and pressurizing CO\u003csub\u003e2\u0026nbsp;\u003c/sub\u003eand N\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd rowspan=\"3\" style=\"width: 38px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eMain (MA)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 161px;\"\u003e\n \u003cp\u003eCore preparation\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 190px;\"\u003e\n \u003cp\u003eCore water \u0026amp; Oil saturating\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 204px;\"\u003e\n \u003cp\u003e\u0026nbsp;\u003c/p\u003e\n \u003cp\u003eCore flood formation water and then dead and live oil flooding for making saturated\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 161px;\"\u003e\n \u003cp\u003eFlooding\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 190px;\"\u003e\n \u003cp\u003eGas flooding\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 204px;\"\u003e\n \u003cp\u003eGas core flooding at constant pressure steps\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 161px;\"\u003e\n \u003cp\u003ePermeability reduction measurement\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 190px;\"\u003e\n \u003cp\u003eCyclohexane injection\u003c/p\u003e\n \u003cp\u003e\u0026nbsp;\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 204px;\"\u003e\n \u003cp\u003eCyclohexane core flooding and differential pressure measurement for permeability determination\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd rowspan=\"2\" style=\"width: 38px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eSupplementary (SA)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 161px;\"\u003e\n \u003cp\u003eProduced oil measurement\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 190px;\"\u003e\n \u003cp\u003eProduced asphaltene measurement\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 204px;\"\u003e\n \u003cp\u003eIP143\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 161px;\"\u003e\n \u003cp\u003eDeposition measurement\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 190px;\"\u003e\n \u003cp\u003eCore deposition measurement\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 204px;\"\u003e\n \u003cp\u003eAsphaltene deposition\u003c/p\u003e\n \u003cp\u003emeasurement by extracting in\u003c/p\u003e\n \u003cp\u003eSoxhlet extractor\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003e\u003cstrong\u003ePrimary activities (PA)\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eThe minimum miscibility pressure (MMP) of CO\u003csub\u003e2\u003c/sub\u003e and flue gas was determined using CMG software. Following the regression of the synthetic oil with the WINPROP module, the MMP values were obtained using the GEM module.\u003c/p\u003e\n\u003cp\u003e\u0026nbsp;Bubble point pressure was measured using a movable piston-cylinder device equipped with a wire-adjustable heating jacket to maintain a constant temperature and a pressure transmitter positioned at the oil end of the cylinder. In the first stage, the pressure of the recombined live oil was increased to 6000 psi by injecting water into the water compartment of the piston cylinder and was held at this pressure for four days to ensure a single-phase condition. During this time, the piston was constantly shaken. Subsequently, a controlled volume of water was gradually drained from the water compartment in each step, and the corresponding pressure drop was recorded. Throughout the experiment, the temperature was maintained at 110 \u0026deg;C using the heating jacket. A distinct break in the pressure drop curve indicated the bubble point pressure.\u003c/p\u003e\n\u003cp\u003eThe porosity of the core samples was measured using a porosity-measuring electronic device. Absolute permeability was determined by conducting formation water flooding and applying Darcy\u0026apos;s correlation. For three or four fluid velocity steps within the range of 0.5 to 2 cm\u003csup\u003e3\u003c/sup\u003e per minute, the differential pressure along the core length was recorded. The physical properties of the core samples are summarized in Table 6.\u003cspan dir=\"RTL\"\u003e\u0026nbsp;\u003c/span\u003eThe initial core sample used for core flooding tests was F#1. This sample was subjected to flue gas injection at various temperatures and pressures, as well as CO\u003csub\u003e2\u003c/sub\u003e flooding under reservoir temperature and pressure. To investigate CO\u003csub\u003e2\u003c/sub\u003e flooding under different miscibility conditions, immiscible and miscible, a second core sample, coded C#2, was selected. This sample had similar properties and lithology to F#1. The use of two comparable low-permeability carbonate core samples enhances the reliability and repeatability of the results, offering greater confidence than experiments conducted with a single core.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003e\u0026nbsp;\u003cstrong\u003eTable 6.\u003c/strong\u003e Core samples properties\u003c/strong\u003e\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"588\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eCore\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003eCore F#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003eCore C#2\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eConducted core flood tests\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e4 tests # Flue gas\u003c/p\u003e\n \u003cp\u003e\u0026amp;1 test #\u0026nbsp;CO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e3 tests #\u0026nbsp;CO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eSpecifications\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e\u0026nbsp;\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e\u0026nbsp;\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eLength (cm)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e5.121\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e4.885\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eDiameter\u003cspan dir=\"RTL\"\u003e\u0026nbsp;\u003c/span\u003e(cm)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e3.80\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e3.84\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003ePorosity\u003cspan dir=\"RTL\"\u003e\u0026nbsp;\u003c/span\u003e(%)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e29.5\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e28.29\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003ePore volume (cm\u003csup\u003e3\u003c/sup\u003e)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e13.2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e7.9\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eLiquid permeability(mD)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e1.5\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e3.6\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eDry weight (g)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e120.973\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e113.838\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cimg height=\"24\" src=\"data:image/png;base64,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\" alt=\"image\" width=\"36\"\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e0.23\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003e0.17\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 228px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eRock type\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003eCarbonate\u0026nbsp;\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 180px;\"\u003e\n \u003cp\u003eCarbonate\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003eThe recombined live oil was prepared by mixing stock tank oil with first-stage associated gas at a pressure of 450 psi-g. The associated gas was first transferred into a 1000 cm\u003csup\u003e3\u003c/sup\u003e high-pressure piston cylinder, followed by the injection of a predetermined volume of dead oil based on gas\u0026ndash;oil ratio data. The mixture was then pressurized to 4000 psi, well above the bubble point of the live oil, and agitated for 4 days.\u003c/p\u003e\n\u003cp\u003eTo prepare the synthetic flue gas, pre-calculated amounts of pure CO\u003csub\u003e2\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e gases, in a molar ratio of 25 % CO\u003csub\u003e2\u003c/sub\u003e and 75 % N\u003csub\u003e2\u003c/sub\u003e, were transferred into two separate high-pressure piston cylinders at 1000 psi. The CO\u003csub\u003e2\u003c/sub\u003e was then fully transferred into the N\u003csub\u003e2\u003c/sub\u003e cylinder to form the desired gas mixture, representing the synthetic flue gas.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eMain activities (MA)\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eThe core flood experiment was conducted using the main setup and consisted of three primary stages: (I) core preparation, (II) flooding, and (III) permeability reduction measurements.\u003c/p\u003e\n\u003cp\u003eIn the first step, the core samples were washed with toluene using a Soxhlet extraction apparatus for 4\u0026ndash;5 days until a clear solution was obtained and no organic precipitate remained in the cores. The process was then continued by replacing toluene with methanol for an additional 2 days to extract inorganic materials. After solvent extraction, the cores were dried in an oven at 110 \u0026deg;C. The dried core samples were then placed in the core holder and subjected to vacuum for 5 hours. To reach irreducible water saturation, a 10 % NaCl solution as artificial formation water was injected into the cores. To displace the saline water from the cores, approximately two pore volumes of dead oil were injected until significant water production occurred and irreducible water saturation was achieved. The core samples were maintained in this state for 7 days to allow proper aging. Finally, the cores were subjected to temperature and pressure conditioning before testing.\u003c/p\u003e\n\u003cp\u003eThe main gas injection step was performed under predefined conditions of temperature, pressure, and gas type. Throughout the entire core flooding process, the overburden pressure was maintained at 500\u0026ndash;700 psi above the injection pressure. Gas injections were carried out at fixed pressures ranging from 3000 to 6000 psi, all above the bubble point pressure. Six pore volume increments of 0.1, 0.3, 0.6, 0.9, 1.2, and 1.5 PV of flue gas and CO\u003csub\u003e2\u003c/sub\u003e were injected. The volume of produced oil, after gas separation, was recorded using a graduated cylinder, while the pressure drop across the core sample was monitored using a differential pressure (DP) cell.\u003c/p\u003e\n\u003cp\u003eThe gas core flooding step was conducted according to the following general procedure:\u003c/p\u003e\n\u003col\u003e\n \u003cli\u003eBefore each gas injection set, the core sample was cleaned, dried, and saturated with formation water and dead oil at the specified pressure, following the core preparation procedure.\u003c/li\u003e\n \u003cli\u003eThe pressure and temperature were adjusted to the specified values using the pressure regulator, heating jacket, and air bath container.\u003c/li\u003e\n \u003cli\u003eSaline water was reinjected into the core sample at the specified pressure to remove the dead oil before recombined oil injection. The oil pore volume was determined at each step by measuring the volume of removed dead oil.\u003c/li\u003e\n \u003cli\u003eThe recombined oil was injected into the core holder at the specified pressure until irreducible water saturation in the core sample was achieved.\u003c/li\u003e\n \u003cli\u003eFlue gas or carbon dioxide stored in the piston cylinder was injected into the core holder at constant pressure and temperature. At six injection stages, from 0.1 to 1.5 pore volumes, the volume of degassed oil was collected in a graduated cylinder for oil recovery calculation.\u003c/li\u003e\n\u003c/ol\u003e\n\u003cp\u003eCyclohexane injection was carried out according to the following general procedure to measure and compare the permeability of the core sample before and after each gas injection set, which was affected by asphaltene deposition.\u003c/p\u003e\n\u003col start=\"1\" type=\"1\"\u003e\n \u003cli\u003eBefore each gas injection set, and after saturating the core sample with formation water and recombined oil, liquid cyclohexane was injected at the specified pressure and temperature until no further oil removal was observed.\u003c/li\u003e\n \u003cli\u003eThe differential pressure along the core sample was then measured using a differential pressure cell at four cyclohexane injection rates ranging from 0.2 to 0.5 milliliters per minute. Preparations were performed to ensure the core was properly saturated with formation water and recombined oil.\u003c/li\u003e\n \u003cli\u003eAfter each gas injection set, the same procedure was repeated to measure the pressure difference following gas flooding.\u003c/li\u003e\n\u003c/ol\u003e\n\u003cp\u003e\u003cstrong\u003eSupplementary activities (SA)\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eThe supplementary step included two measurements: (I) asphaltene content in the produced oil and (II) deposition within the core sample.\u003c/p\u003e\n\u003cp\u003eFollowing each gas injection set, the asphaltene content of the produced oil was measured using the IP143 standard method. According to this standard method (ASTM D6560-00), a portion of the sample is mixed with 40 volumes of n-heptane, which is used as a precipitant. Then, the mixture is heated under reflux for 60 min, and after that, it is stored in a dark space for 90 to 150 min. Then the precipitated asphaltenes, waxy substances, and inorganic material are collected on a 2.5 \u0026micro;m filter paper. The waxy substances are removed by washing with hot heptane in an extractor. After the waxy substances are removed, the asphaltenes are separated from the inorganic material by dissolution in hot toluene, the extraction solvent is evaporated, and the asphaltenes are weighed. To determine core deposition at the end of each pressure step, the core sample was washed using a Soxhlet extractor with toluene as the solvent to extract and quantify the asphaltene deposited on the core. Additionally, the asphaltene deposition percentage was calculated by comparing the asphaltene content of the original and produced oils, taking into account the oil in place and the volume of produced oil.\u003c/p\u003e"},{"header":"Results and discussion","content":"\u003cp\u003e\u003cstrong\u003eMMP of injection gases\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eThe results of slim tube simulations for CO\u003csub\u003e2\u003c/sub\u003e and flue gas, conducted using CMG software, along with their minimum miscibility pressure as a function of temperature, are illustrated in Figures 2, 3, and 4, summarized in Table 7. The data show that CO\u003csub\u003e2\u003c/sub\u003e and flue gas exhibit opposite trends in MMP with changing temperature. For CO\u003csub\u003e2\u003c/sub\u003e, the MMP increases with rising temperature, which is consistent with interfacial tension experimental results reported by Zolghadr et al. Their study demonstrated that at pressures above 754 psi, an increase in temperature leads to higher IFT and consequently higher MMP [73]. In contrast, the simulation results indicate that the MMP of flue gas decreases as temperature increases. This observation is in agreement with IFT experimental findings for nitrogen reported in previous research [74].\u003csup\u003e\u0026nbsp;\u003c/sup\u003eSince the flue gas used in this study contains 75 mol percent nitrogen, its behavior more closely resembles that of nitrogen rather than CO\u003csub\u003e2\u003c/sub\u003e.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eTable 7.\u003c/strong\u003e MMP (psi-g) of CO\u003csub\u003e2\u003c/sub\u003e and flue gas at different temperatures\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"595\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd rowspan=\"2\" style=\"width: 154px;\"\u003e\n \u003cp\u003eGas type\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd colspan=\"3\" style=\"width: 441px;\"\u003e\n \u003cp\u003eTemperature (\u0026deg;C)\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 154px;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 154px;\"\u003e\n \u003cp\u003e100\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 133px;\"\u003e\n \u003cp\u003e43.3\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 154px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 154px;\"\u003e\n \u003cp\u003e4350\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 154px;\"\u003e\n \u003cp\u003e3750\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 133px;\"\u003e\n \u003cp\u003e1800\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 154px;\"\u003e\n \u003cp\u003eFlue gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 154px;\"\u003e\n \u003cp\u003e17000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 154px;\"\u003e\n \u003cp\u003e-\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 133px;\"\u003e\n \u003cp\u003e20000\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003e\u003cstrong\u003eBubble point of recombined oil\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eBased on the experimental data of pressure versus cumulative displaced water volume shown in Figure 5, the bubble point pressure of the recombined oil at 110 degrees Celsius was determined to be 2918 psi. It is important to note that all core flood experiments were conducted at pressures above this bubble point.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eCore flooding test results\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eCore flood displacement tests were conducted using recombined oil with CO\u003csub\u003e2\u003c/sub\u003e and flue gas under various temperatures and pressures. The injection pressure was selected based on the bubble point of the live oil and the reservoir temperature, with reservoir pressures ranging from 3000 to 6000 psi. For flue gas injection, two experimental sets were performed using core sample F#1: one with a constant pressure of 4000 psi at temperatures of 65 and 110 degrees Celsius, and another with a constant temperature of 110 degrees Celsius at pressures of 3000 and 6000 psi. For CO\u003csub\u003e2\u003c/sub\u003e injection, experiments were conducted on core sample C#2 at a constant temperature of 110\u0026deg;C with pressures of 3000, 4300, and 5000 psi to evaluate immiscible and miscible conditions. An additional CO\u003csub\u003e2\u003c/sub\u003e test was conducted on core sample F#1 at reservoir conditions of 110 degrees Celsius and 6000 psi. The results were categorized into three main areas to assess the effects of flue gas and CO\u003csub\u003e2\u003c/sub\u003e injection: oil recovery factor, asphaltene deposition, and core permeability reduction. A summary of the core flood experiments is shown in Table 8.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eTable 8.\u003c/strong\u003e Summary of core flood experiments conducted in this study\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"595\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eTest No.\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eCore sample\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003ctable border=\"0\" cellpadding=\"0\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 112px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eInjected gas\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n \u003cp\u003e\u003cbr\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e\u003cstrong\u003ePressure (psi)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003ctable border=\"0\" cellpadding=\"0\" width=\"121\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 117px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eTemperature (\u003c/strong\u003e\u003cstrong\u003e\u0026ordm;C\u003cstrong\u003e)\u003c/strong\u003e\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n \u003cp\u003e\u003cbr\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003eFlue gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e4000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003cp\u003e65\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003eFlue gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e4000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e3\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003eFlue gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e3000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e4\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003eFlue gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e6000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e5\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e3000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e6\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e4300\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e7\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e5000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 67px;\"\u003e\n \u003cp\u003e8\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 130px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 131px;\"\u003e\n \u003cp\u003e6000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 136px;\"\u003e\n \u003cp\u003e110\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003e\u003cstrong\u003eOil recovery factor results\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eFigure 6 illustrates the cumulative oil recovery factor versus injected gas pore volume for all test cases using CO\u003csub\u003e2\u003c/sub\u003e and flue gas at various temperatures and pressures, with up to 1.5 pore volumes injected into the core samples. Each experiment was conducted under constant pressure conditions. The overall trend shows that at reservoir temperature (110 \u0026deg;C), the oil recovery factor for flue gas at 4000 and 6000 psi is nearly equivalent to that of CO\u003csub\u003e2\u003c/sub\u003e at 3000 and 5000 psi, respectively. This indicates that a similar oil recovery factor can be achieved by flue gas injection at higher pressures compared to CO\u003csub\u003e2\u003c/sub\u003e. Furthermore, the results reveal that increasing temperature has a negative effect on oil recovery during flue gas injection, with higher temperatures leading to reduced recovery.\u003c/p\u003e\n\u003cp\u003eAccording to Figure 7, increasing the temperature from 65 \u0026deg;C to 110 \u0026deg;C reduced the ultimate oil recovery factor for flue gas injection from 0.738 to 0.621. This indicates that higher temperatures lead to lower oil recovery during flue gas injection. At elevated temperatures, the solubility of flue gas in oil decreases, resulting in reduced oil swelling and less viscosity reduction. This outcome aligns with the experimental findings of Shokoya et al., who conducted core flood experiments at two reservoir temperatures (80.6 \u0026deg;C and 116 \u0026deg;C) and pressures up to 6030 psi. Their results also demonstrated a decrease in oil recovery efficiency with increasing temperature during flue gas injection [63]. In contrast, the behavior of CO\u003csub\u003e2\u003c/sub\u003e injection differs.\u003c/p\u003e\n\u003cp\u003eThe effect of injected gas volume at different pressures and gas types at reservoir temperature (110 \u0026deg;C), originally presented in Figure 6, is further illustrated in Figure 8. This figure highlights the impact of injecting 1.4 pore volumes of gas (from 0.1 to 1.5 PV) on oil recovery. For flue gas flooding, the oil recovery improvement across different pressures is relatively consistent and notably higher than that observed for CO\u003csub\u003e2\u003c/sub\u003e flooding. It can be concluded that injecting an equal volumetric amount of flue gas results in a greater oil recovery, approximately 10\u0026ndash;15 % higher, compared to CO\u003csub\u003e2\u003c/sub\u003e. This suggests that flue gas injection requires a smaller gas volume to achieve comparable recovery, offering a more cost-effective alternative to CO\u003csub\u003e2\u003c/sub\u003e flooding. In contrast, for CO\u003csub\u003e2\u003c/sub\u003e flooding, oil recovery shows greater sensitivity to pressure, with higher pressures yielding improved recovery performance.\u003c/p\u003e\n\u003cp\u003eFigure 9 illustrates the ultimate oil recovery factor (URF) as a function of injection pressure for 1.5 pore volumes of gas injected at reservoir temperature (110 \u0026deg;C). For both gases, the recovery factor increases with pressure. Flue gas, operating entirely within the immiscible injection region, shows a consistent and gradual increase in URF. In contrast, CO\u003csub\u003e2\u003c/sub\u003e spans both immiscible and miscible regions, demonstrating a similar trend to flue gas in the immiscible range, but with a distinct change in slope as it enters the miscible region, indicating enhanced recovery efficiency under miscible conditions. However, although the oil recovery factor increases under miscible conditions, the rate of improvement becomes more gradual. In immiscible gas flooding, oil recovery increases with a higher capillary number due to the relatively low interfacial tension between the oil and the injected gas. Miscible flooding enhances oil recovery through several mechanisms, including the elimination of interfacial tension between oil and solvent or an effectively infinite capillary number, which enables efficient oil displacement by the solvent once miscibility is achieved. Additional contributions to recovery include oil swelling and a reduction in oil viscosity [63].\u003c/p\u003e\n\u003cp\u003eAs pressure increases, CO\u003csub\u003e2\u003c/sub\u003e density rises sharply during the immiscible flooding region, leading to faster dissolution of CO\u003csub\u003e2\u003c/sub\u003e in crude oil and a reduction in crude oil viscosity. This decreases the interfacial tension between CO\u003csub\u003e2\u003c/sub\u003e and oil, which in turn causes the crude oil to swell. These beneficial effects result in a rapid increase in oil recovery during the immiscible stage [75]. Additionally, as pressure increases, the length of the transition zone between the injected gas front and the oil zone decreases. This reduction slows the advancement of the gas front toward the core outlet, delaying gas breakthrough and thereby improving sweep efficiency [63]. As the system approaches miscible conditions, the influence of pressure on the transition zone becomes minimal because the zone reaches its smallest possible size, and further pressure increases no longer provide additional benefit [76]. In the miscible flooding stage, due to the reduced contribution of the mechanisms dominant in the immiscible region, only a slight increase in the recovery factor is observed with increasing pressure [75].\u003c/p\u003e\n\u003cp\u003eIn this study, two similar core samples were used independently to investigate the effect of pressure on each type of injected gas. To ensure a more accurate comparison, one core sample (F#1) was used under reservoir conditions at 6000 psi and 110 \u0026deg;C for both gases. The results indicate a higher recovery factor for CO\u003csub\u003e2\u003c/sub\u003e compared to flue gas. Overall, it can be observed that at each pressure level, the oil recovery factor for CO\u003csub\u003e2\u003c/sub\u003e is greater than that for flue gas. However, by applying a higher pressure than that used for CO\u003csub\u003e2\u003c/sub\u003e, a similar oil recovery factor can be achieved with flue gas.\u003c/p\u003e\n\u003cp\u003eFigure 10 shows the effect of gas type on oil recovery and compares it with injection pressure using the same core sample (F#1). By comparing the results for CO\u003csub\u003e2\u003c/sub\u003e injection at 6000 psi and 110 \u0026deg;C with flue gas injection at 4000 psi and 6000 psi at 110 \u0026deg;C, it is observed that the ultimate oil recovery for CO\u003csub\u003e2\u003c/sub\u003e at 6000 psi and 110 \u0026deg;C (reservoir pressure and temperature) is only 10 percent higher than for flue gas at the same temperature and pressure, but up to 30 percent higher than flue gas injection at 4000 psi. This indicates a significantly superior performance compared to flue gas at lower pressures. These findings demonstrate that injection pressure has a greater influence on oil recovery than the type of gas, specifically the CO\u003csub\u003e2\u003c/sub\u003e content in the flue gas. Additionally, the miscible condition of CO\u003csub\u003e2\u003c/sub\u003e and the immiscible condition of flue gas have a smaller impact on oil recovery than the effect of pressure. Therefore, under high pressure, the immiscible nature of flue gas has only a minor influence on oil recovery.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eAsphaltene deposition results\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eThe experimental data for asphaltene mass percentage in the original and produced oil, along with the calculated asphaltene content in the core samples, are presented in Table 9. The asphaltene content was measured using the IP143 standard procedure, and the deposited mass percentage was calculated based on the difference in asphaltene content between the original oil and the produced oil.\u0026nbsp;\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eTable 9.\u003c/strong\u003e Asphaltene content and deposited asphaltene onto core samples during CO\u003csub\u003e2\u003c/sub\u003e and flue gas flooding\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"595\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eTest code\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eGas type\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eCore sample code\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eTest conditions\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eAsphaltene wt% in original oil (IP143)-Exp\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eAsphaltene wt % in produced oil (IP143)-Exp\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eDeposited asphaltene\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003eF-T065-P4000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003eFlue Gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003eT:65\u0026nbsp;\u0026deg;C\u003c/p\u003e\n \u003cp\u003eP:4000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e5.97\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e48.61\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003eF-T110-P3000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003eFlue Gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003eT:110\u0026nbsp;\u0026deg;C\u003c/p\u003e\n \u003cp\u003eP:3000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e5.65\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e35.21\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003eF-T110-P4000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003eFlue Gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003eT:110\u0026nbsp;\u0026deg;C\u003c/p\u003e\n \u003cp\u003eP:4000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e6.05\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e41.12\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003eF-T110-P6000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003eFlue Gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003eT:110\u0026nbsp;\u0026deg;C\u003c/p\u003e\n \u003cp\u003eP:6000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e6.52\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e50.41\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003eC-T110-P3000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003eT:110\u0026nbsp;\u0026deg;C\u003c/p\u003e\n \u003cp\u003eP:3000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e9.31\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e20.16\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003eC-T110-P4300\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003eT:110\u0026nbsp;\u0026deg;C\u003c/p\u003e\n \u003cp\u003eP:4300 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e5.77\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e52.41\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003eC-T110-P5000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003eT:110\u0026nbsp;\u0026deg;C\u003c/p\u003e\n \u003cp\u003eP:5000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e9.65\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e25.55\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003eC-T110-P6000\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 57px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 66px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003eT:110\u0026nbsp;\u0026deg;C\u003c/p\u003e\n \u003cp\u003eP:6000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 104px;\"\u003e\n \u003cp\u003e12.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 109px;\"\u003e\n \u003cp\u003e6.01\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 70px;\"\u003e\n \u003cp\u003e59.82\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003eThe data presented in Table 8 reveal that at a constant pressure of 4000 psi, increasing the temperature from 65 to 110 \u0026deg;C resulted in a decrease in the percentage of deposited asphaltene from 48.61 to 41.12 percent. At higher temperatures, the solubility of flue gas in the oil decreases, which leads to reduced asphaltene precipitation and deposition. No published studies have been identified that specifically investigate the effect of temperature on asphaltene deposition under similar conditions.\u003c/p\u003e\n\u003cp\u003eFigure 11 presents the percentage of asphaltene deposited within the pores of core samples during CO\u003csub\u003e2\u003c/sub\u003e and flue gas injection. Flue gas exhibits consistent behavior across the entire pressure range since it remains in the immiscible condition. In contrast, CO\u003csub\u003e2\u003c/sub\u003e shows a distinct pattern, with differing behavior in the immiscible region from 3000 to 4300 psi and the miscible region from 4300 to 6000 psi. Under miscible conditions, the injected gas alters the oil composition and disrupts the interaction between resins and asphaltene molecules, which promotes asphaltene precipitation and deposition. However, under immiscible conditions, the oil composition remains largely unchanged, and asphaltene deposition primarily depends on gas solubility. Lower gas solubility leads to less asphaltene precipitation.\u003c/p\u003e\n\u003cp\u003eIn the immiscible zone, as shown in Figure 11, both flue gas and CO\u003csub\u003e2\u003c/sub\u003e display a consistent trend in which asphaltene deposition increases with rising injection pressure. As the injection pressure increases, the gas dissolution capacity in crude oil also rises. This leads to a greater proportion of low molecular weight compounds and a reduction in the concentration of asphaltene-resin stabilizers, making asphaltene precipitation more likely [77].\u003csup\u003e\u0026nbsp;\u003c/sup\u003eAdditionally, at higher pressures, asphaltene molecules are brought closer together, promoting their coagulation and subsequent deposition onto the core samples [76]. Because CO\u003csub\u003e2\u003c/sub\u003e solubility in oil is significantly more sensitive to pressure than that of flue gas, the CO\u003csub\u003e2\u003c/sub\u003e curve demonstrates a steeper slope, indicating greater solubility and, therefore, higher asphaltene deposition for CO\u003csub\u003e2\u003c/sub\u003e.\u003c/p\u003e\n\u003cp\u003eAt the minimum miscibility pressure of CO\u003csub\u003e2\u003c/sub\u003e, maximum dissolution of CO\u003csub\u003e2\u003c/sub\u003e in the crude oil occurs, resulting in the highest level of asphaltene deposition during gas flooding. As the system enters the miscible region, the crude oil becomes saturated with CO\u003csub\u003e2\u003c/sub\u003e, and while asphaltene deposition still occurs, it does so at a much lower rate [75]. This reduction is attributed to the formation of a gas phase within the system, which slows the rate of asphaltene deposition [77]. During the miscible injection of CO\u003csub\u003e2\u003c/sub\u003e, flue gas may still operate in the immiscible flooding region. In this case, flue gas continues to exhibit a trend similar to that at lower pressures, where asphaltene deposition increases proportionally with injection pressure [76].\u003c/p\u003e\n\u003cp\u003eThe general behavior of asphaltene deposition onto the core caused by CO2 gas flooding in this study confirms the findings of experimental investigations by Soroush et al. and Cao and Gu, who examined five pressure points with three below and two above the minimum miscibility pressure [52,78].\u003c/p\u003e\n\u003cp\u003eTo investigate the effect of gas type on asphaltene deposition, tests F-T110-P6000 and C-T110-P6000 (Table 8) were performed under identical pressure, temperature, and rock characteristics using the same core sample (F#1) at reservoir conditions. As shown in Fig. 11, the results indicate that under the same conditions, asphaltene deposition caused by CO\u003csub\u003e2\u003c/sub\u003e injection is approximately 20 percent higher than that from flue gas. For CO\u003csub\u003e2\u003c/sub\u003e injection, due to the miscible condition, the percentage of asphaltene deposition is highly sensitive to pressure. In contrast, flue gas injection produces more predictable and consistent asphaltene deposition behavior. To draw more comprehensive conclusions regarding the impact of gas type, an integrated discussion that considers both asphaltene deposition and reduced permeability is presented in the next section.\u0026nbsp;\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eCore permeability reduction results\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eFor all tests, two liquid permeability measurements using cyclohexane were conducted before and after the main gas injection test. Figures 12 and 13 illustrate the increase in pressure difference along the core samples for core samples C#2 and F#1, respectively. The increase in pressure difference resulting from CO\u003csub\u003e2\u003c/sub\u003e injection is significantly greater than that from flue gas injection in both figures. This difference is attributed to formation damage caused by asphaltene deposition within the core samples. Using the differential pressure data obtained from cyclohexane injection and applying Darcy\u0026rsquo;s law, the core permeability was calculated both before and after gas injection. The corresponding permeability curves are presented in Figures 14 through 21.\u003c/p\u003e\n\u003cp\u003eBy substituting the pressure difference data obtained from Figures 14 to 21 into Darcy\u0026rsquo;s law, the core permeabilities before and after the core flood gas injection were calculated and are presented in Table 10. To gain a clearer understanding of the extent of permeability reduction, the damage index can be employed using the following relation [78]:\u003c/p\u003e\n\u003cp\u003e\u003cimg width=\"109\" height=\"22\" src=\"data:image/png;base64,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\" alt=\"image\"\u003e\u003c/p\u003e\n\u003cp\u003eWhere\u003cem\u003e\u0026nbsp;\u003c/em\u003e\u003cimg width=\"18\" height=\"22\" src=\"data:image/png;base64,iVBORw0KGgoAAAANSUhEUgAAABIAAAAWCAMAAAD6gTxzAAAAAXNSR0IArs4c6QAAAF1QTFRFAAAAAAAAAAA6AABmADqQAGa2OgAAOgA6OgBmOjoAOjqQOma2OpDbZgAAZgA6ZjoAZjpmZpCQkDoAkNv/tmYAtmY6ttv/tv//25A627Zm2////9uQ/9u2//+2///brrAJdgAAAAF0Uk5TAEDm2GYAAAAJcEhZcwAADsQAAA7EAZUrDhsAAAAZdEVYdFNvZnR3YXJlAE1pY3Jvc29mdCBPZmZpY2V/7TVxAAAAdUlEQVQoU7VQxw6AMAgFR5111VGL+v+faauJFr2ZyIEDvAUA/9YqMVDQI0bmMqJEAayVbWy0NKOfxaLm/Ca5FQmmc4wSRaJkNzh5bU0f8lvnRTiITtCjnlE1YjgB1Vg8vHND6cSMtiFzWL909EKRCFoZf//yDok6BgVQpK39AAAAAElFTkSuQmCC\" alt=\"image\"\u003e\u0026nbsp;and \u003cimg width=\"18\" height=\"22\" src=\"data:image/png;base64,iVBORw0KGgoAAAANSUhEUgAAABIAAAAWCAMAAAD6gTxzAAAAAXNSR0IArs4c6QAAAFpQTFRFAAAAAAAAAAA6AABmADqQOgAAOgA6OgBmOjqQOpDbZgAAZgA6ZjpmZpBmZpDbZrbbZrb/kDoAkDo6kNv/tmYAttv/tv//25A627Zm2////9uQ/9u2//+2///bqrH/dwAAAAF0Uk5TAEDm2GYAAAAJcEhZcwAADsQAAA7EAZUrDhsAAAAZdEVYdFNvZnR3YXJlAE1pY3Jvc29mdCBPZmZpY2V/7TVxAAAAfUlEQVQoU7VQSRKEIAzsoLiOo4jboPz/mxO0VHK1Sg45dHoLwLtvq0hZDETp7wpymQW2moeA1s8Yd2HWUtyisHJa+OxQZp0uxQ3BfuZQYNjnwYI3oYLvI4gNWXpCR9WZKJl832j1Fa7elHD5FGNBKM/gkBZLIllGk+qe//If1UAGky8x2HcAAAAASUVORK5CYII=\" alt=\"image\"\u003e are the core permeabilities after and before gas injection, respectively. The damage indexes presented in Table 9 and Figure 22 indicate that the formation damage resulting from CO\u003csub\u003e2\u003c/sub\u003e injection is, on average, approximately 3.6 times greater than that caused by flue gas injection.\u003c/p\u003e\n\u003cp\u003e\u0026nbsp;\u003cstrong\u003eTable 10.\u003c/strong\u003e Permeability of core samples before and after gas injection and damage indexes\u003c/p\u003e\n\u003cdiv align=\"\"\u003e\n \u003ctable border=\"1\" cellspacing=\"0\" cellpadding=\"0\" width=\"604\"\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eTest\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eCore sample code\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e\u003cstrong\u003ePermeability before gas injection (\u003c/strong\u003e\u003cimg width=\"24\" height=\"20\" src=\"data:image/png;base64,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\" alt=\"image\"\u003e\u003cstrong\u003e\u0026nbsp;\u0026ndash; mD\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e\u003cstrong\u003ePermeability after gas injection (\u003c/strong\u003e\u003cimg width=\"25\" height=\"20\" src=\"data:image/png;base64,iVBORw0KGgoAAAANSUhEUgAAABkAAAAUCAMAAABPqWaPAAAAAXNSR0IArs4c6QAAAG9QTFRFAAAAAAAAAAA6AABmADpmADqQAGa2OgAAOgA6OjpmOmaQOma2OpDbZgAAZjoAZra2ZrbbZrb/kDoAkGZmkJDbkLbbkNvbkNv/tmYAttv/tv/btv//25A627Zm27aQ2////7Zm/9uQ/9u2//+2///b9PmaUAAAAAF0Uk5TAEDm2GYAAAAJcEhZcwAADsQAAA7EAZUrDhsAAAAZdEVYdFNvZnR3YXJlAE1pY3Jvc29mdCBPZmZpY2V/7TVxAAAArUlEQVQoU7WQXReCIAyGGYqUZSZ9SIEByv//jcFEOdZlJy52YC/b826E/Pvog5kREqBQUwPQLUi3V3gNyS4EesteLMMqxws1NnXqgLIXWG+heu3OW/PymDhA+62iYzsv6F0A/vkARYwO7r4VC8w4ni3jD+wmoUqBkPEE9SVWy5AbOJQPLwCCu6lhRs7sdeoZYmnvRfSSJs1oXaiBt1eybCcrjpdPwcy60e0kP73e2VEKULXiI0QAAAAASUVORK5CYII=\" alt=\"image\"\u003e\u003cstrong\u003e\u0026nbsp;\u0026ndash; mD\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e\u003cstrong\u003eDamage index (DI)\u003c/strong\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e @ 110 \u0026ordm;C \u0026amp; 3000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e1.0621\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e0.7837\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e0.262\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e @ 110 \u0026ordm;C \u0026amp; 4300 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e1.0690\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e0.7780\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e0.272\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e @ 110 \u0026ordm;C \u0026amp; 5000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003eC#2\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e0.9905\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e0.7611\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e0.232\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e @ 110 \u0026ordm;C \u0026amp; 6000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e0.3499\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e0.2620\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e0.251\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003eFG @ \u0026nbsp; 65 \u0026ordm;C \u0026amp; 4000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e0.1286\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e0.1262\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e0.019\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003eFG @ 110 \u0026ordm;C \u0026amp; 3000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e0.3169\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e0.3071\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e0.031\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003eFG @ 110 \u0026ordm;C \u0026amp; 4000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e0.3014\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e0.2765\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e0.083\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd style=\"width: 169px;\"\u003e\n \u003cp\u003eFG @ 110 \u0026ordm;C \u0026amp; 6000 psi\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 58px;\"\u003e\n \u003cp\u003eF#1\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 141px;\"\u003e\n \u003cp\u003e0.2903\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 151px;\"\u003e\n \u003cp\u003e0.2467\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd style=\"width: 85px;\"\u003e\n \u003cp\u003e0.150\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n\u003c/div\u003e\n\u003cp\u003eAccording to Figure 22, the damage index for flue gas injection increases from 0.019 to 0.083 as the temperature rises from 65 \u0026deg;C to 110 \u0026deg;C, indicating an approximately fourfold increase. This demonstrates that increasing temperature significantly amplifies permeability reduction and formation damage due to asphaltene deposition.\u003c/p\u003e\n\u003cp\u003eConsidering Figures 23 and 24, a comprehensive investigation of permeability reduction integrated with oil recovery factor and asphaltene deposition for flue gas and CO\u003csub\u003e2\u003c/sub\u003e injection is presented. During immiscible flue gas injection, although permeability reduction and asphaltene deposition intensify with increasing pressure, the oil recovery factor continues to rise. Despite the reduction in permeability, the enhanced pressure significantly boosts oil recovery, resulting in an overall positive effect. A similar trend is observed for CO\u003csub\u003e2\u003c/sub\u003e flooding in the immiscible region (\u0026lt; MMP) between 3000 and 4300 psi. In this range, the behavior of permeability reduction, in contrast to asphaltene deposition, exhibits minimal variation. This may be attributed to additional damage mechanisms besides asphaltene deposition, such as rock\u0026ndash;CO\u003csub\u003e2\u003c/sub\u003e interaction or gas trapping in the pore space, which is more probable at lower pressures. Increased pressure suppresses asphaltene precipitation under miscible CO\u003csub\u003e2\u003c/sub\u003e flooding conditions, thereby minimizing permeability impairment. However, this process leads to a slower oil recovery rate than immiscible CO\u003csub\u003e2\u003c/sub\u003e flooding. The resulting damage is primarily due to asphaltene deposition, and other types of rock damage can be considered negligible [78].\u003c/p\u003e\n\u003cp\u003eFigure 25 compares the permeability reduction resulting from flue gas and CO\u003csub\u003e2\u003c/sub\u003e injection. Under reservoir conditions of 110 \u0026deg;C and 6000 psi using core sample F#1, the permeability reduction caused by CO\u003csub\u003e2\u003c/sub\u003e is approximately 67 % higher than that caused by flue gas. A comparison of permeability reduction in both F#1 and C#2 cores shows that at lower injection pressures, flue gas causes significantly less damage. As the pressure increases, the difference between the damage done becomes smaller, although CO2 still results in greater overall permeability reduction. These findings support the consideration of flue gas as a more favorable injection option compared to pure CO\u003csub\u003e2\u003c/sub\u003e, particularly when minimizing formation damage is a priority.\u003c/p\u003e"},{"header":"Conclusions","content":"\u003cp\u003eFlue gas and CO\u003csub\u003e2\u003c/sub\u003e core flooding experiments were conducted on recombined live oil using two low-permeability carbonate core samples to comprehensively investigate the effects of temperature, pressure, gas volume, and gas type on oil recovery, asphaltene deposition, and permeability reduction. The results offer both quantitative and qualitative evidence supporting the potential of flue gas injection as an effective method for enhancing oil recovery, with notable advantages over CO\u003csub\u003e2\u003c/sub\u003e injection in certain conditions. The key findings from this study can be summarized as follows:\u003c/p\u003e\n\u003cul class=\"decimal_type\"\u003e\n \u003cli\u003eAt each pressure level, the oil recovery factor for CO\u003csub\u003e2\u003c/sub\u003e injection was approximately 15 % higher than that of flue gas. However, when comparing equal standard volumes of injected gas, flue gas demonstrated greater efficiency, with recovery factors about 16 % to 46 % higher than those of CO\u003csub\u003e2\u003c/sub\u003e. This indicates that a larger standard volume of CO\u003csub\u003e2\u003c/sub\u003e is required to achieve the same level of oil recovery. Therefore, given the greater availability of flue gas, injecting it at a moderately higher pressure (20 % to 30 %) but with a lower gas volume (10 % to 15 %) can yield oil recovery results comparable to CO\u003csub\u003e2\u003c/sub\u003e injection.\u003c/li\u003e\n \u003cli\u003eThe injection pressure has a greater effect on oil recovery than the gas type. Increasing the CO\u003csub\u003e2\u003c/sub\u003e content of flue gas from 25 % to 100 % resulted in a modest 12 % improvement in the oil recovery factor. This improvement is comparable to that achieved with a 1000 psi pressure increase. Additionally, the miscibility condition of CO\u003csub\u003e2\u003c/sub\u003e, in comparison to the immiscibility condition of flue gas, has a smaller effect on oil recovery than injection pressure. Therefore, at high pressures, the immiscible state of flue gas has a minimal effect on oil recovery.\u003c/li\u003e\n \u003cli\u003eAt the reservoir pressure and temperature, the asphaltene deposition percentage onto the core sample and the formation damage index for CO\u003csub\u003e2\u003c/sub\u003e were 18.6 % and 67 % higher than those for flue gas, respectively. Thus, CO\u003csub\u003e2\u003c/sub\u003e injection poses a higher risk of asphaltene deposition and formation damage compared to flue gas.\u003c/li\u003e\n \u003cli\u003eFlue gas potentially serves as a viable alternative to CO\u003csub\u003e2\u003c/sub\u003e in EOR injection projects due to its competitive oil recovery and lower risk of asphaltene deposition. While requiring additional pressure compared to CO\u003csub\u003e2\u003c/sub\u003e, flue gas injection offers reduced asphaltene inhibition costs and less reservoir damage.\u003c/li\u003e\n\u003c/ul\u003e"},{"header":"Declarations","content":"\u003cp\u003e\u003cstrong\u003eData availability\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eAll data supporting the findings of this study are available within the article.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eAcknowledgements\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eThe authors acknowledge the Ahwaz Petroleum University of Technology Research Centre for providing materials and facilities. The authors also wish to thank Mr. I. Abasali and Mr. A. Daryasafar for their technical assistance in core flood tests.\u0026nbsp;\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eAuthor contributions\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eK. E.: Conceptualization, Data curation, Formal analysis, Investigation, Methodology, Visualization, Writing-original draft. P. D.: Data curation, Investigation, Lab equipment, Review \u0026amp; editing. A. L.: Project administration, Resources, Review \u0026amp; editing. S. K.: Investigation, Review \u0026amp; editing, Supervision.\u0026nbsp;\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eCompeting interests\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eThe authors declare no competing interests.\u003c/p\u003e"},{"header":"References","content":"\u003col\u003e\n \u003cli\u003eTaber, J. J., Martin, F. D. \u0026amp; Seright, R. 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Investigating the effects of temperature, pressure, and paraffin groups on the N2 miscibility in hydrocarbon liquids using the interfacial tension measurement method. \u003cem\u003eIndustrial \u0026amp; Engineering Chemistry Research\u003c/em\u003e\u003cstrong\u003e52\u003c/strong\u003e, 9851-9857 (2013).\u003c/li\u003e\n \u003cli\u003eWang, C., Li, T., Gao, H., Zhao, J. \u0026amp; Li, H. A. Effect of asphaltene precipitation on CO 2-flooding performance in low-permeability sandstones: a nuclear magnetic resonance study. \u003cem\u003eRSC advances\u003c/em\u003e\u003cstrong\u003e7\u003c/strong\u003e, 38367-38376 (2017).\u003c/li\u003e\n \u003cli\u003eWang, X. \u0026amp; Gu, Y. Oil recovery and permeability reduction of a tight sandstone reservoir in immiscible and miscible CO2 flooding processes. \u003cem\u003eIndustrial \u0026amp; Engineering Chemistry Research\u003c/em\u003e\u003cstrong\u003e50\u003c/strong\u003e, 2388-2399 (2011).\u003c/li\u003e\n \u003cli\u003eZhang, W., Wang, Y. \u0026amp; Ren, T. Influence of injection pressure and injection volume of CO2 on asphaltene deposition. \u003cem\u003ePetroleum Science and Technology\u003c/em\u003e\u003cstrong\u003e35\u003c/strong\u003e, 313-318 (2017).\u003c/li\u003e\n \u003cli\u003eSoroush, S., Pourafshary, P. \u0026amp; Vafaie-Sefti, M. in \u003cem\u003eSPE EOR Conference at Oil and Gas West Asia.\u003c/em\u003e SPE-169657-MS (SPE).\u003c/li\u003e\n\u003c/ol\u003e"}],"fulltextSource":"","fullText":"","funders":[],"hasAdminPriorityOnWorkflow":false,"hasManuscriptDocX":true,"hasOptedInToPreprint":true,"hasPassedJournalQc":"","hasAnyPriority":false,"hideJournal":false,"highlight":"","institution":"","isAcceptedByJournal":true,"isAuthorSuppliedPdf":false,"isDeskRejected":"","isHiddenFromSearch":false,"isInQc":false,"isInWorkflow":false,"isPdf":false,"isPdfUpToDate":true,"isWithdrawnOrRetracted":false,"journal":{"display":true,"email":"[email protected]","identity":"scientific-reports","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":false,"externalIdentity":"scirep","sideBox":"Learn more about [Scientific Reports](http://www.nature.com/srep/)","snPcode":"","submissionUrl":"","title":"Scientific Reports","twitterHandle":"","acdcEnabled":true,"dfaEnabled":true,"editorialSystem":"stoa","reportingPortfolio":"Scientific Reports","inReviewEnabled":true,"inReviewRevisionsEnabled":true},"keywords":"Asphaltene deposition, CO2 injection, Enhanced oil recovery, Flue gas injection, Formation damage, Permeability reduction","lastPublishedDoi":"10.21203/rs.3.rs-6779359/v1","lastPublishedDoiUrl":"https://doi.org/10.21203/rs.3.rs-6779359/v1","license":{"name":"CC BY 4.0","url":"https://creativecommons.org/licenses/by/4.0/"},"manuscriptAbstract":"\u003cp\u003eNon-hydrocarbon injection gases, such as carbon dioxide (CO\u003csub\u003e2\u003c/sub\u003e) and flue gas, offer cost-effective and environmentally friendly alternatives to traditional hydrocarbon gases for enhanced oil recovery (EOR). However, issues such as asphaltene deposition and formation damage challenge their use in tight carbonate reservoirs. While CO\u003csub\u003e2\u003c/sub\u003e injection has been extensively studied, experimental data on flue gas remain limited. This study presents a detailed experimental comparison of CO\u003csub\u003e2\u003c/sub\u003e and synthetic flue gas through eight core flooding tests using recombined live oil and two low-permeability carbonate cores. Effects of gas type, pressure, temperature, and injected gas volume on oil recovery, asphaltene deposition, and permeability reduction were evaluated. CO\u003csub\u003e2\u003c/sub\u003e injection yielded approximately 15% higher oil recovery than flue gas at the same pressure. However, for equal injected volumes, the flue gas achieved 16 to 46% higher recovery, indicating a more efficient use. Comparable oil recovery was achieved by injecting flue gas at 20 to 30% higher pressure with 10 to 15% less gas volume. Additionally, CO\u003csub\u003e2\u003c/sub\u003e caused up to 18.6% more asphaltene deposition and 67% more formation damage than flue gas under identical conditions. This study also investigates the role of injection pressure and temperature in influencing formation damage behavior. The results confirm that flue gas injection can be used as an alternative to CO\u003csub\u003e2\u003c/sub\u003e for EOR in carbonate reservoirs.\u003c/p\u003e","manuscriptTitle":"Comprehensive experimental study to compare the effects of flue gases and CO 2 injection on enhancing oil recovery and asphaltene deposition","msid":"","msnumber":"","nonDraftVersions":[{"code":1,"date":"2025-06-05 09:59:54","doi":"10.21203/rs.3.rs-6779359/v1","editorialEvents":[{"type":"communityComments","content":0},{"type":"decision","content":"Revision requested","date":"2025-07-25T06:55:34+00:00","index":"","fulltext":""},{"type":"editorInvitedReview","content":"","date":"2025-07-24T10:35:14+00:00","index":"hide","fulltext":""},{"type":"reviewerAgreed","content":"209602291600212046516829696170911000128","date":"2025-07-14T06:39:44+00:00","index":"hide","fulltext":""},{"type":"editorInvitedReview","content":"","date":"2025-06-18T03:13:14+00:00","index":"hide","fulltext":""},{"type":"reviewerAgreed","content":"301077493490030051389912535759723999947","date":"2025-06-08T23:09:53+00:00","index":"hide","fulltext":""},{"type":"reviewersInvited","content":"","date":"2025-06-03T09:17:17+00:00","index":"","fulltext":""},{"type":"editorAssigned","content":"","date":"2025-06-03T09:16:02+00:00","index":"","fulltext":""},{"type":"editorInvited","content":"","date":"2025-06-03T01:48:39+00:00","index":"","fulltext":""},{"type":"checksComplete","content":"","date":"2025-06-02T04:07:23+00:00","index":"","fulltext":""},{"type":"submitted","content":"Scientific Reports","date":"2025-05-29T20:44:42+00:00","index":"","fulltext":""}],"status":"published","journal":{"display":true,"email":"[email protected]","identity":"scientific-reports","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":false,"externalIdentity":"scirep","sideBox":"Learn more about [Scientific Reports](http://www.nature.com/srep/)","snPcode":"","submissionUrl":"","title":"Scientific Reports","twitterHandle":"","acdcEnabled":true,"dfaEnabled":true,"editorialSystem":"stoa","reportingPortfolio":"Scientific Reports","inReviewEnabled":true,"inReviewRevisionsEnabled":true}}],"origin":"","ownerIdentity":"abad85a5-4285-4cc3-b21d-1816cac0e73b","owner":[],"postedDate":"June 5th, 2025","published":true,"recentEditorialEvents":[],"rejectedJournal":[],"revision":"","amendment":"","status":"under-review","subjectAreas":[{"id":49502020,"name":"Physical sciences/Energy science and technology/Carbon capture and storage"},{"id":49502021,"name":"Physical sciences/Energy science and technology/Fossil fuels"}],"tags":[],"updatedAt":"2026-04-06T05:39:40+00:00","versionOfRecord":[],"versionCreatedAt":"2025-06-05 09:59:54","video":"","vorDoi":"","vorDoiUrl":"","workflowStages":[]},"version":"v1","identity":"rs-6779359","journalConfig":"researchsquare"},"__N_SSP":true},"page":"/article/[identity]/[[...version]]","query":{"redirect":"/article/rs-6779359","identity":"rs-6779359","version":["v1"]},"buildId":"8U1c8b4HqxoKbykW_rLl7","isFallback":false,"isExperimentalCompile":false,"dynamicIds":[84888],"gssp":true,"scriptLoader":[]}