Effective Enhanced Oil Recovery Research Articles

3D Physical Simulation Experiment of Edge Water Reservoir by Polymer/Surfactant Binary Flooding

To investigate the enhanced oil recovery (EOR) technology by chemical flooding in an edge water reservoir, a 3D physical simulation experimental device for the edge water reservoir was developed, and polymer/surfactant binary flooding experiments were carried out under different edge water energies. In addition, the effect and mechanism of binary flooding on EOR under different edge water energies were comprehensively analyzed. Experimental results show that edge water intrusion considerably affects EOR by binary flooding. The stronger the edge water energy, the worse the effect of EOR by binary flooding. Edge water possibly diluted the concentration of the chemical agent medium that is injected into the reservoir, and the degree of dilution varied in different regions. The dilution region was mainly distributed between the injection wells and edge water. The stronger the edge water energy, the higher the dilution multiple of chemical agent and the greater the recovery loss rate by binary flooding.

Experimental Investigation of Molecular Deposition Filming Flooding in a Low-Permeability Oil Reservoir

Molecular deposition (MD) filming flooding has proved to be an effective enhanced oil recovery (EOR) method in reservoirs where recovery was relatively difficult. The B425 block with a low permeabi...

Low-Salinity Water, CO2, Alkaline, and Surfactant EOR Methods Applied to Heavy Oil in Sandstone Cores

Summary Generally, injecting carbon dioxide (CO2) into oil reservoirs is an effective enhanced oil recovery (EOR) technique that improves oil recovery, but injecting CO2 alone can be compromised by problems, such as early breakthrough, viscous fingering, and gravity override. The base CO2 injection method was improved by water-alternating-gas (WAG) injection with formation water (FW) and with low-salinity (LS) water (LSW), with LSW WAG achieving greater recovery than WAG with FW. This study investigates various combinations of standard waterflooding (with FW); flooding with nonmiscible gaseous CO2; WAG with CO2 and FW and/or LSW; foam flooding by adding a surfactant with CO2; adding an alkaline treatment step; and finally adding an LSW spacer between the alkaline step and the foam. These various EOR combinations were tested on Bartlesville sandstone cores (ϕ of approximately12%, K of approximately 20 md) saturated with a heavy oil diluted slightly with 10% heptane for workability. The ultimate outcome from this work is a “recipe” of EOR methods in combination that uses alkaline, LSW, surfactant, and CO2 steps to achieve recovery of more than 63% of the oil originally in place (OOIP) in coreflooding tests. Combining CO2 injection with surfactant [sodium dodecyl sulfonate (SDS)] to produce a foam resulted in better recovery than the WAG methods. Adding alkaline as a leading step appeared to precipitate the surfactant and lower recovery somewhat. Adding an LSW spacer between the alkaline treatment and the foam resulted in a dramatic increase in recovery. The various cases of alkaline + LSW spacer + surfactant + CO2 (each with various concentrations of alkaline and surfactant) achieved an average improvement of 7.71% of OOIP over the identical case(s) without the LSW spacer. The synergistic effect of the LSW spacer was remarkable. ERRATUM NOTICE:An erratum has been added to this paper detailing addition of an omitted reference.

Mechanistic study of cyclic water injection to enhance oil recovery in tight reservoirs with fracture deformation hysteresis

As an effective enhanced oil recovery (EOR) technique in tight reservoirs, cyclic water injection has been extensively studied recently. However, very few studies have considered the impacts of loading-path dependent fracture deformation, i.e. deformation hysteresis. In this study, an efficient coupled two-phase flow and geomechanics model is developed to simulate cyclic water injection in a tight oil reservoir with the consideration of fracture deformation hysteresis. The embedded discrete fracture model (EDFM) is applied to handle complex fracture geometries. Different loading-path dependent constitutive models are used to describe the deformations of hydraulic fractures and natural fractures, respectively. Then simulation studies are performed to demonstrate the impacts of deformation hysteresis of hydraulic fractures and natural fractures on EOR performance. The sensitivities to injection rate, depletion pressure and soaking time are examined. The results show that the deformation hysteresis of hydraulic fracture has significant effect on oil production, while that of natural fracture has negligible impact. The effects of fracture deformation hysteresis are more pronounced under high injection rate and depletion pressure, but less sensitive to soaking time.

Investigation of an Improved Polymer Flooding Scheme by Compositionally-Tuned Slugs

Polymer flooding is an effective enhanced oil recovery technology used to reduce the mobility ratio and improve sweep efficiency. A new polymer injection scheme is investigated that relies on the cyclical injection of low-salinity, low-concentration polymer slugs chased by high-salinity, high-concentration polymer slugs. The effectiveness of the process is a function of several reservoir and design parameters related to polymer type, concentration, salinity, and reservoir heterogeneity. We use reservoir simulations and design-of-experiments (DoE) to investigate the effectiveness of the proposed polymer injection scheme. We show how key objective functions, such as recovery factor and injectivity, are impacted by the reservoir and design parameters. In this study, simulations showed that the new slug-based process was always superior to the reference polymer injection scheme using the traditional continuous injection scheme. Our results show that the process is most effective when the polymer weight is high, corresponding to large inaccessible pore-volumes, which enhances polymer acceleration. High vertical heterogeneity typically reduces the process performance because of increased mixing in the reservoir. The significance of this process is that it allows for increased polymer solution viscosity in the reservoir without increasing the total mass of polymer, and without impairing polymer injectivity at the well.

Development of a novel model to predict HPAM viscosity with the effects of concentration, salinity and divalent content

Polymer flooding has been established as an effective enhanced oil recovery (EOR) technique and can be utilized in large-scale field expansions. With high success rates and efficiency, polymer flooding operates by increasing the viscosity of water, promoting greater sweep efficiency and resulting in higher oil recovery beyond conventional waterflooding. Predicting viscosity has been established by numerous researchers as an essential tool to study polymers behavior under varying conditions. Previous model has proven a link between polymer viscosity and zero shear rate viscosity, relaxation time, hardness, and many other factors. This research initially reviews different types of polymers that can be applied successfully in EOR, demonstrate conditions that can alter polymer viscosity in porous medium, and analyze models that predict polymer bulk and in situ viscosity. The research then discusses a novel modification of the power law model to predict HPAM (SAV10) viscosity in a wide range of shear rates based on polymer concentration, fluid salinity, and divalent content. A polymer rheology study was carried out on SAV10 at various concentrations (750–5000 ppm) and brine salinities (43–210 k ppm). Results show the effectiveness of the model and the ability to predict viscosity accurately in low to medium shear rates, while in high shear rate, a slight deviation was noticeable.

Laboratory investigation of cyclic gas injection using CO2/N2 mixture to enhance heavy oil recovery in a pressure-depleted reservoir

CO2 has strong abilities of oil swelling and viscosity reduction for heavy oil extraction, N2 is a preferable gas media for pressure maintenance, and their mixture is then considered as an alternative method for enhanced oil recovery (EOR) in a pressure-depleted heavy oil reservoir. PVT analysis and cyclic gas injection experiments are conducted to reveal EOR mechanisms for CO2/N2 mixture, and five different CO2/N2 molar ratios (1:0 (pure CO2), 4:1, 7:3, 1:1, and 0:1 (pure N2)) are designed in this paper. PVT analysis shows that the changes of oil properties including saturation pressure, volume factor, and viscosity are highly related to CO2/N2 ratio of the mixture, and a higher CO2/N2 ratio can always lead to better gas/oil interactions. When CO2/N2 ratio is higher than 7:3, the viscosity can reduce to less than 60% of the initial oil viscosity. Gas injection experimental results show that 4:1 mixture can achieve an oil recovery of 17.31%, which is close to the recovery obtained by pure CO2. For the pressure-depleted oil reservoir, simultaneous CO2/N2 injection or N2 followed by CO2 injection is suitable injection mode for the mixture. With such a design of CO2/N2 mixture, an optimized EOR effect can be achieved with gas/oil interactions dominated by CO2 coupled with energy supplement provided by N2. A pilot test of CO2/N2 mixture injection is successfully conducted in a test well, and an oil increment of 337 t is obtained after 40,000 m3 of N2 injection followed by 80,000 m3 of CO2 injection.

A Pore-Scale Investigation of Residual Oil Distributions and Enhanced Oil Recovery Methods

Water flooding is an economic method commonly used in secondary recovery, but a large quantity of crude oil is still trapped in reservoirs after water flooding. A deep understanding of the distribution of residual oil is essential for the subsequent development of water flooding. In this study, a pore-scale model is developed to study the formation process and distribution characteristics of residual oil. The Navier–Stokes equation coupled with a phase field method is employed to describe the flooding process and track the interface of fluids. The results show a significant difference in residual oil distribution at different wetting conditions. The difference is also reflected in the oil recovery and water cut curves. Much more oil is displaced in water-wet porous media than oil-wet porous media after water breakthrough. Furthermore, enhanced oil recovery (EOR) mechanisms of both surfactant and polymer flooding are studied, and the effect of operation times for different EOR methods are analyzed. The surfactant flooding not only improves oil displacement efficiency, but also increases microscale sweep efficiency by reducing the entry pressure of micropores. Polymer weakens the effect of capillary force by increasing the viscous force, which leads to an improvement in sweep efficiency. The injection time of the surfactant has an important impact on the field development due to the formation of predominant pathway, but the EOR effect of polymer flooding does not have a similar correlation with the operation times. Results from this study can provide theoretical guidance for the appropriate design of EOR methods such as the application of surfactant and polymer flooding.

Robust Three-Phase Vapor–Liquid–Asphaltene Equilibrium Calculation Algorithm for Isothermal CO2 Flooding Applications

CO2 flooding is an effective enhanced oil recovery process for light oil reservoirs. Asphaltenes can easily precipitate during CO2 flooding, leading to the appearance of three-phase vapor–liquid–asphaltene (VLS) equilibria. A prerequisite for accurately simulating the CO2 flooding process is developing a robust three-phase VLS equilibrium calculation algorithm. In this study, we develop a robust and efficient three-phase VLS equilibrium calculation algorithm with the use of asphaltene precipitation model proposed by Nghiem et al. [ Efficient Modelling of Asphaltene Precipitation, SPE, 1993]. To develop this algorithm, a two-phase flash calculation algorithm is first developed to split the mixture into an asphaltene phase and a nonasphaltene phase. Moreover, two different three-phase VLS flash calculation algorithms are developed and incorporated into our three-phase equilibrium calculation algorithm. New initialization approaches for both stability test and flash calculations are proposed. The performance...

Effect of oil reactivity on salinity profile design during alkaline-surfactant-polymer flooding

This study focused on the influence of oil reactivity (ability to react with alkali to generate in situ surfactants) on salinity profile design during alkaline/surfactant/polymer (ASP) flooding. Two surrogate oils with different total acid number (TAN) were used. After determination of optimum salinity via phase behavior tests, 3 ASP corefloods with I-III-I, II-III-I (negative salinity gradient), and I-II-I salinity profiles were performed for each oil. ASP flooding was applied as a post-polymer enhanced oil recovery (EOR) method in this study. The results demonstrated: (1) for both low TAN oil and high TAN oil, when I-III-I salinity profile was employed, incremental oil recovery was less than 20% original oil in place (OOIP); (2) when negative salinity gradient was applied, high oil recovery from 33.5% to 38.5% OOIP was achieved over polymer flooding, resulting in cumulative recovery over 95% in spite of oil reactivity; (3) distinct trends were observed for corefloods with I-II-I salinity profile. For low TAN oil, an incremental recovery of only 20% OOIP was attained; by contrast, for high TAN oil, the incremental recovery was as high as 35.1%, which could be attributed to the generation of a large amount of in situ soaps that had lower optimum salinity compared to the added surfactants; and (4) ASP flooding proved to be an effective EOR approach to significantly reduce residual oil after polymer flooding if appropriate salinity profile was adopted. This study provides some guidance on salinity profile design when ASP flooding is considered for oils with different reactivity.

Experimental investigation of driving brine water for enhanced oil recovery in tight sandstones by DC voltage

A large percentage of tight oil is trapped underground due to the lack of effective enhanced oil recovery methods. Direct current (DC) voltage flooding has become one of the emerging and promising methods for in situ enhanced oil recovery because of its economic and environmental advantages. Nevertheless, the effect of DC voltage on the enhanced oil recovery for tight sandstone reservoirs is still unclear. In this study, the effects of DC voltage, the concentration of brine water and flooding styles on enhanced oil recovery have been investigated. The experimental results show that there are an optimum DC voltage (∼10V) and an optimum concentration of brine water (∼0.7 mol/L). The oil displacement efficiency with the DC voltage (∼10V) increases by 50% compared with that the oil displacement efficiency of the conventional flooding with 0.1 mol/L sodium chloride. A low concentration of brine water would increase the oil displacement efficiency when the DC voltage is applied, while a high concentration of brine water would reduce the oil displacement efficiency. Moreover, the results of different flooding styles indicate that the sequential flooding obtains more oil than the simultaneous flooding and conventional flooding under the condition of a relatively high concentration of brine water. Several mechanisms of electrokinetics have been revealed in this study. Laboratory experiments indicate that electrokinetic flooding would be a promising enhanced oil recovery technique and needs to be investigated further.

Experimental and Numerical Study on CO2 Sweep Volume during CO2 Huff-n-Puff Enhanced Oil Recovery Process in Shale Oil Reservoirs

CO2 huff-n-puff has been proven to be the most effective enhanced oil recovery (EOR) method in shale oil reservoirs. The injected CO2 will replenish reservoir energy and penetrate the reservoir matrix to extract oil. However, the CO2 sweep volume during the huff-n-puff process has not been accurately evaluated by existing studies. In this paper, the CO2 sweep volume was investigated through experimental and numerical simulation methods. In the experimental study, the CO2 sweep areas were depicted by X-ray computed tomography scan technology. The results indicated that the ratio of the CO2 sweep area was 78.63% in the seventh huff-n-puff cycle, leading to a total oil recovery of 56.80%. The numerical simulation considered the mechanisms of molecular diffusion and nanopore confinement. The results showed that in the first huff-n-puff cycle, the gas sweep volume percentage was 9.47% after 100 days of huff period. In the gas swept volume, oil viscosity was reduced by 25.9% to 68.2%. After three cycles of CO2 ...

A dual-porosity dual-permeability model for acid gas injection process evaluation in hydrogen-carbonate reservoirs

The Pre-Caspian basin is one of the most prolific in terms of oil and gas exploration and hydrogen and carbon compounds energy production around the world. The major hydrogen and carbon compounds reservoirs are Carboniferous reef and platform hydrogen-carbonate rocks. The original fluids under subsurface conditions contain 15% hydrogen sulfide and 4% carbon dioxide. Acid hydrogen and carbon compounds reinjection is not only an environmentally friendly solution for disposal of produced greenhouse gases but also enhances oil recovery and supplies more fuel energy. On the other hand, the presence of fractures makes hydrogen-carbonate reservoir characteristics nature more complicated than conventional sandstone reservoirs, which leads to a tremendous challenge to evaluate the gas injection process. In this work, a dual-porosity dual-permeability formulation was used to model the dual-medium nature incorporating matrix system with high porosity and low permeability and fracture network with low porosity and high permeability. After matching PVT experiments, a ten pseudo-components fluid model was generated for running compositional simulation. The miscible hydrogen and carbon compounds injection was simulated as an effective enhanced oil recovery approach. Sensitivity analysis such as timing of injection gas, injection rate, well spacing and completion interval have proposed the optimal condition for the miscible hydrogen and carbon compounds flooding. The recommended optimum hydrogen and carbon compounds injection scenario is twice higher oil recovery compared with natural depletion. The results of this study illustrate further the practicability of pseudo-components splitting and lumping for compositional simulation to evaluate the performance of hydrogen and carbon compounds injection processes, and are of great importance using the dual-porosity dual-permeability method performing numerical simulation of naturally fractured hydrogen-carbonate reservoirs.

Role of chemical additives and their rheological properties in enhanced oil recovery

Abstract A significant amount of oil (i.e. 60–70%) remains trapped in reservoirs after the conventional primary and secondary methods of oil recovery. Enhanced oil recovery (EOR) methods are therefore necessary to recover the major fraction of unrecovered trapped oil from reservoirs to meet the present-day energy demands. The chemical EOR method is one of the promising methods where various chemical additives, such as alkalis, surfactants, polymer, and the combination of all alkali–surfactant–polymer (ASP) or surfactant–polymer (SP) solutions, are injected into the reservoir to improve the displacement and sweep efficiency. Every oil field has different conditions, which imposes new challenges toward alternative but more effective EOR techniques. Among such attractive alternative additives are polymeric surfactants, natural surfactants, nanoparticles, and self-assembled polymer systems for EOR. In this paper, water-soluble chemical additives such as alkalis, surfactants, polymer, and ASP or SP solution for chemical EOR are highlighted. This review also discusses the concepts and techniques related to the chemical methods of EOR, and highlights the rheological properties of the chemicals involved in the efficiency of EOR methods.

Experimental Study on EOR Performance of Natural Gas Injection in Tight Oil Reservoirs

Gas injection is an effective enhanced oil recovery method in tight oil reservoirs. In the case of tight oil fields with sufficient natural gas supply, natural gas injection can significantly reduce the cost of operation, leading economic benefit. Natural gas flooding might be a promising EOR method for tight oil development. Based on the material and reservoir condition of a tight formation in Changqing Oilfield, this study conducted a series of natural gas injection experiments to evaluate the feasibility of natural gas injection after water flooding and analysed the influence of gas injection rate to EOR performance. Experiment results shows that natural gas injection can recover 20.8% more oil after water flooding. Sensitivity analyses indicates that natural gas injection had a higher oil recovery with low injection rate.

Molecular Simulation of Enhanced Oil Recovery in Shale

Enhanced oil recovery (EOR) techniques (miscible/near miscible gas injection, chemical flooding and thermal) aim at increasing oil recovery factor, over which that would be achieved from natural depletion and pressure maintenance methods. As we embark on more complex EOR processes (e.g. miscible hydrocarbon/non-hydrocarbon, surfactant/polymer, smart water and combination of the three), complex phase equilibria, complicated rock/fluid interaction, and sophisticated transport through porous media will create a number of key technical challenges that must be addressed. The issue is significantly increased in unconventional resources as the physics behind the process is not very well understood.For these resources, effective enhanced oil recovery (EOR) techniques are required to displace oil from nanoscale shale matrix. Due to small permeability, it is difficult to conduct water and chemical flooding in these resources. Maintaining a stable flood front in immiscible gas flooding due to the severe fingering phenomenon in fractured shale formations. Gas huff-n-puff becomes the most suitable EOR method in shale reservoir development. For decades, CO2 (EOR) techniques that have been successfully applied in conventional reservoirs to improve oil production. In this work, we will investigate the physics behind CO2 injection into organic nanopores of shale using molecular dynamics simulations. A 3D kerogen structure is used with dodecane to study the huff-n-puff process at a molecular level. Results show that there is an optimal soaking time after which the recovery factor is not affected by soaking time anymore. Furthermore, carbon dioxide has high affinity to be adsorbed to kerogen walls and therefore desorbing the hydrocarbon molecules.

Combination of a new natural surfactant and smart water injection for enhanced oil recovery in carbonate rock: Synergic impacts of active ions and natural surfactant concentration

By increasing oil demand in carbonate reservoirs, enhanced oil recovery techniques play key role in improving oil production. Surfactant flooding and smart water injection are already well known as effective enhanced oil recovery techniques that increase oil recovery by reduction of oil-water interfacial tension and the alteration of rock wettability. In this work, a new plant-base natural surfactant, named Tribulus Terrestris is introduced and combined with smart water samples (i.e. synthetic seawater with different concentrations of active Ca2+, Mg2+ and SO42− ions) to determine their individual and integrated effects on reduction in interfacial tension, wettability alteration and oil recovery in carbonate rock samples.It was observed that increasing concentrations of SO42− up to 2.5 times resulted in maximum wettability restoration among active ions (by changing contact angle from 145.9° to 54.4°). Experimental results also showed that the effect of the concentration of active ions on wettability alteration was more significant compared to their effect on decreasing oil-water interfacial tension. In addition, the Tribulus Terrestris surfactant reduced oil-water interfacial tension considerably (from 45.3 mN/m to 13.5 mN/m at Critical Micelle Concentration of 0.3 wt %); hence, it was used as smart water modifier to integrate effects of wettability alteration (by smart water) and reduction in interfacial tension (by new natural surfactant). Core flooding experiments demonstrated increased oil recovery from 45.2% for distilled water injection up to 64% and 72% for smart water and combined smart water-surfactant respectively.

Prevention of network destruction of partially hydrolyzed polyacrylamide (HPAM): Effects of salt, temperature, and fumed silica nanoparticles

Polymer flooding is one of the most effective enhanced oil recovery (EOR) methods. High temperature and a high salt content in oil reservoirs significantly decrease the performance of polymer flooding. In this work, the viscoelastic properties of a partially hydrolyzed polyacrylamide (HPAM) solution with and without salt (NaCl) and at two different temperatures (35 °C and 70 °C) were evaluated using rheological approaches. Two fumed silica nanoparticles (NPs) featuring different surface chemistries were used, and their ability to prevent destruction of the polymer network structure against salt addition and temperature increase was investigated. Linear rheological tests (frequency sweep, creep, and creep recovery) and nonlinear rheological tests (large amplitude oscillatory shear) were employed to evaluate the network structure of these systems. The results showed that either adding salt or increasing the temperature destroyed the mechanical integrity of the HPAM 3-dimensional elastic network. However, the introduction of both types of NPs at a sufficient concentration maintained the network structure of HPAM solutions in the small deformation region. In the large deformation region, it was shown that the extent of intra-cycle shear-thickening behavior in the HPAM solution (T = 35 °C and without any salt) decreased by incorporating salt or by increasing the temperature. Moreover, upon incorporating either of the NPs to the HPAM solution, the nonlinear viscoelastic behavior dramatically changed, and the critical strain (linear to nonlinear transition) decreased to a much lower strain amplitude. The outcomes of this study will help petroleum scientists to design more efficient EOR methods.

An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs

Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.

Swelling behavior of heavy crude oil during injection of carbonated brine containing chloride anion

Carbonated brine (CB) injection, known as one of the effective enhanced oil recovery processes, is highly dependent on the reservoir conditions (i.e. temperature and pressure) as well as the type of dissolved salt in aqueous solution. This study is aimed to investigate the influential parameters on the swelling of crude oil as the most important mechanism during CB injection. The swelling of crude oil in the presence of different CB solutions consisted of different salts such as KCl, NaCl, CaCl2 and MgCl2 with constant concentration of 15,000 ppm is studied using a high-pressure, high-temperature visual cell which measures the volume of drop using image processing software based on Young-Laplace method. Also, the Δ Bond number of crude oil is examined to more reliably find out the mechanisms. According to the results, it can be concluded that the solubility of CO2 in aqueous phase is not the only parameter affecting the swelling behavior, and that the crude oil and ion type as well as temperature have remarkable effect on the mobility of CO2 molecules and their partitioning from aqueous phase toward oil phase.