Water Injection Process Research Articles

Research on Oil Layer Protection and Seepage Improvement Capacity Technology in Untabulated Reservoir of Oilfield A

On the basis of the experience and practices accumulated in the development of low-permeability untabulated reservoirs in oilfield A, in this paper, oil layer protection and seepage improvement technology of low-permeability untabulated reservoir formed in the well completion process, water injection process and subsequent adjustment process were described, the formation of the above mature technologies has laid the technical foundation for the industrialized development of untabulated reservoir in the oilfield A, and it is of great significance to the effective and efficient development of this type of oil layer.

A comprehensive model for simulating supercritical water flow in a vertical heavy oil well with parallel double tubes

At present, there is no research on parallel double pipe injection of supercritical water. The research on the process of SAGD supercritical water injection is insufficient. This paper first established a mathematical model of parallel twin-pipe injection supercritical water pipe flow. On this basis, the SAGD supercritical water injection development numerical model was established using numerical simulation software, and the variation characteristics of the temperature field, crude oil viscosity field and oil saturation field in the reservoir were analyzed. The main conclusions obtained are as follows: (a) the high temperature area first developed from the lower part of the vertical well. (b) After 150 days, the temperature in the reservoir gradually increased. (c) When the injection time reaches 210 days, the viscosity of the heavy oil between the vertical wells has been sufficiently reduced. (d) Condensed water occupies a lot of pore space, resulting in a decrease in oil saturation.

Precipitation/dissolution and precipitants movement mechanisms effects on injectivity variations during diluted produced water re-injection into a layered reservoir - experimental investigation

ABSTRACT Permeability reduction is one of the significant problems in the water injection process. Several mechanisms may be involved in permeability reduction including scale formation, suspended particle invasion and fines migration. On the other hand, rock dissolution may also lead to permeability improvement of carbonate rocks. In this research, effect of rock lithology along with incompatibility of injection and formation brines, scale formation and plugging of pores by particles in the injection water for a layered reservoir were examined. Diluted formation brine (produced from desalination unit) was considered as injection water. Simulation of scale formation due to thermodynamic conditions and mixing of formation and injection brines were performed to investigate amount and types of scales. Simulation and jar tests showed that Scale precipitation decreased with increasing the mixing ratio of injection water to 75%. For core flooding tests, both carbonate and sandstone core samples from a layered candidate reservoir were selected for monitoring of formation damage and permeability variation due to incompatibility of fluids. SEM and EDX analysis were used for static and dynamic tests. Carbonate core sample showed sever damage and competition between scale precipitation and rock dissolution. Higher flow rates contribute to permeability enhancement of carbonate rocks by prevention of scale sedimentation (less scale formation) and acceleration of carbonate rock dissolution. As a pressure difference increasing of 60% was shown in the first stage of water injection process into the carbonate rock. Eventually, after increasing and decreasing the injection rate, the pressure difference decreased to 30 presences. Scale formation mechanism is dominant in sandstone rock samples and can be removed by backflow. As pressure difference decreased 27% in sandstone rock sample, which resulted in permeability decrease from 365 to 265 mD.

Two-Dimensional SPH Analysis of Seepage with Water Injection Process for Different Crack Morphologies

Crack seepage in nature involves natural and water injection flow, causing crack morphology in nature to be varied. Using the numerical simulation method of smoothed particle hydrodynamics (SPH), the natural free flow process in a crack was analyzed. With the interference of the initial velocity of the x = 0 particles, the other terminal particles were shifted, and the particles with initial velocities were reversed. For water injection simulations, ghost particles were set to block particles from overflowing, as particles subjected to injection water were mobilized more quickly than under free flow conditions. For rough cracks, particle magnitude was affected by the boundary shape, but overall particle velocity was influenced little, and the distribution of particles was sparse and densely spaced. For the branch crack simulation, overall particle seepage velocity decreased, but particles moved faster through the wider branch than through the narrower branch. SPH can simulate the seepage through crack networks and be used to analyze the effects of different crack geometries and physical properties.

Wireline Logs Constraint Borehole-to-Surface Resistivity Inversion Method and Water Injection Monitoring Analysis

Detection of the oil–water encroachment front is of great importance to water injection of oil reservoirs. In borehole-to-surface electrical imaging (BSEI), a high-power direct current is applied into a borehole through a well case and the electric potential on the surface, which is affected by the subsurface electrical change, is measured. However, further accurate interpretation of BSEI data is difficult due to the weak surface response, deep target layer, long inversion time, and uncertainty in unconstrained inversion. Therefore, a new method to enhance the surface response of the anomalous body and a new three-dimensional inversion approach based on the damped least-squares method are proposed. Simulation of the water injection and fracturing process was modeled in three dimensions using the finite difference method and the incomplete Cholesky conjugate gradient method. The inversion approach was applied by using the log data to construct a layered resistivity model and constrain the inversion. The forward modeling results suggest that the electric potential gradient can enhance the response of electrical variations in the target layer and help estimate the water injection direction, depending on the distance of electrical anomalies and the current source. In actual water injection monitoring, the BSEI inversion results suggest that layered resistivity model constrained three-dimensional inversion can improve the precision and accuracy of the resistivity inversion results and outline the water injection channeled to the adjacent wells.

Measures of Formation Damage and Protection in the Water-Injection Process —the A block in Xinjiang Oil Filed

On the basis of re-recognizing the geological characteristics of the reservoir in Well A, using laboratory experiments, statistical analysis and other methods, systematically carry out injection and production dynamic analysis in Well A, analysis of damage mechanism of water injection wells, analysis of reservoir damage factors and reservoir Research on protection technology, put forward suggestions on reservoir protection technology and augmented injection technology for well An area. Mixed injection of water is likely to cause insoluble scaling and lead to blockage of water injection pipelines and reservoir pore throats. Working fluids that are not compatible with the formation enter the formation and also cause blockage of the reservoir. Therefore, oil reservoirs must not only pay attention to reservoir protection measures during water injection development It is also necessary to strictly control the quality of the injected water and strictly select additional injection fluids to effectively protect the reservoir and carry out long-term and efficient water injection operations.

Representative Sector Modeling and Waterflooding Performance in Rumaila Oilfield

Rumaila supergiant oilfield, located in Southern Iraq has a huge footprint and is considered as the second largest oilfield in the world. It contains many productive reservoirs, some known but without produced zones, and significant exploration potential. A fault divides the field into two domes to the north and south. Mishrif reservoir is the main producing reservoir in the North Rumaila oilfield. It has been producing for more than 40 years and is under depletion. However, it was subjected to water injection processes in 2015, which assisted in recovery and pressure support. Thus, requirements of managing flooding strategies and water-cut limitations are necessary in the next stages of the field life.
 In this paper, sector modeling was applied to a specific portion of the field, rather than full-field modeling, to accelerate history matching strategy and correlate static to dynamic models’ efficiently, with a minimum level of tolerance. The sector was modeled by surrounding with additional grid blocks and two pseudo wells to achieve a good matching with actual available data.
 PVT data were used for fluid modeling of a well contained in the sector, and two rock functions were inserted to the model to achieve acceptable history matching. Twelve wells were considered in this research, two of them were injectors and the remaining are producers. For future performance, some of these wells were subjected to new completion and workover processes for field development and pressure maintenance. The importance of the development plan is to represent a way for field development without new wells to be drilled. This was conducted by adding perforations to some wells, plugging the high water-cut production zones, changing production and injection rates, and converting the producers to injectors.

High In Situ Stress Anisotropy Lead to Formation of Complex Fracture Patterns

During the process of water injection, due to solid particle deposition and foreign liquid intrusion, the formation near the wellbore was contaminated and blocked. As a result, water injection rate reduced and failed to meet the injection requirements. In order to improve water injection rate and improve oil recovery of offshore oilfields, hydraulic injection tests were carried out in controlled laboratory conditions. In general, the formation of complex fracture patterns is an ideal outcome of the hydraulic fracturing stimulation seeks to achieve. In situ stress condition is an inherited geological condition one can only adopt to. By comparing test results of different experiments that had varied stress and hydraulic injection conditions imposed, we can investigate their impact on the fracture patterns created. This paper presents laboratory evidences to support that if the hydraulic injection condition is managed properly, a complex fracture pattern is possible even under a high in situ stress anisotropy. Even if the in situ stress condition has a large anisotropy, proper hydraulic stimulation operations can still cause complex fracture patterns and thus provide good stimulation efficiency.

Study on dynamic damage characteristics of coal under alternating hydraulic pressure

This study uses laboratory tests and theoretical analysis to adopt a triaxial computer-controlled rock deformation system for studying the dynamic damage characteristics of coal during the process of coal seam water injection in a low-porosity coalbed. The effects of alternating hydraulic pressure on the mechanical properties and the damage evolution of coal under four different stress states are investigated. The results show the following: (1) Under the action of alternating hydraulic pressure, the process of damage and deformation of coal undergoes three deformation stages: initial damage, cumulative damage, and accelerated damage. The second and third stages develop rapidly, and cumulative deformation accounts for more than 90% of the total distortion. (2) Alternating hydraulic pressure has a specific destructive effect on coal, which is cumulative. After 1000 cycles, the limit value of the triaxial compressive strength is much lower than that after 50 alternating hydraulic pressure cycles. (3) With higher amplitudes of alternating hydraulic pressure, the stress generated inside the coal increases, and the coal experiences more damage. (4) Based on the principle of effective stress and mechanical fatigue theory, it can be found that alternating hydraulic pressure can enhance the strain stress sensitivity of coal.

Synergic effects of dissolved carbon dioxide and an anionic surfactant synthesized from Rapeseed oil on interfacial tension (IFT) reduction, wettability alteration, and oil swelling in the process of chemical water injection into carbonate oil reservoirs

It is common to upgrade chemical enhanced oil recovery (CEOR) method by using two or more additives to simultaneously benefit from their mechanisms in EOR process. Chemical water engineering in combinational methods should be such that additives do not neutralize each other's effects and do not change EOR mechanisms. Dissolved carbon dioxide is considered as an additive in carbonated water injection process. Oil swelling is the most important mechanism of carbonated water injection. Besides, wettability of reservoir rock, especially carbonate rock, in this method shifts to hydrophilicity. Injection of carbonated water and injection of surfactant solution are two important methods of EOR. When dissolved carbon dioxide is used as an additive, in addition to EOR, a large amount of carbon dioxide is stored in underground reservoir. In other words, carbonated water injection method follows a process with economic and environmental goals. However, its effect on water and crude oil interfacial tension (IFT) is not significant. In this study, the technique of combining additives was investigated to solve this challenge, i.e. to strengthen the mechanism of reducing interfacial tension. An anionic surfactant synthesized from Rapeseed oil at lower concentrations than critical micelle concentration (CMC), CMC and above CMC in combination with enriched chemical water by dissolved carbon dioxide was used. The experiments of IFT, oil swelling and contact angle were performed for this purpose. Pressure, temperature and salinity effects as parameters affecting carbonated water performance were studied in the experiments. According to the findings, the combination of using the surfactant with carbonated water significantly reduces the IFT even at higher concentrations than CMC. At 80 °C and 2000 psi, the IFT of carbonated fluids at the surfactant concentrations of 0, 3500, 4500, and 5500 ppm were 10.927, 4.948, 3.596, and 1.503 mN/m, respectively. The contact angle increases at a lower concentration than CMC, decreases sharply at CMC and the intensity of the decreasing trend decreases at a higher concentration than CMC but it remains less than the contact angle at CMC. At 80 °C and 2000 psi, the contact angle values at the surfactant concentrations of 0, 3500, 4500 and 5500 ppm were 71.41°, 80.52°, 60.44° and 55.18°, respectively. Crude oil swelling rises at a lower concentration than CMC and CMC but decreases at a higher concentration than CMC as it has the highest value at CMC. At 80 °C and 2000 psi, increased oil swelling values at the surfactant concentrations of 0, 3500, 4500 and 5500 ppm were 10.10%, 15.41%, 15.62% and 14.52%, respectively.

Polymeric surfactants as alternative to improve waterflooding oil recovery efficiency

Chemical formulations, including surfactants, polymers, alkalis, or their combinations, are widely used in different oil recovery processes to improve water injection performance. However, based on challenging profit margins in most mature waterfloods in Colombia and overseas, it is necessary to explore alternatives that could offer better performance and greater operational flexibility than the conventional technologies used for enhanced oil recovery (EOR) processes.
 Polymeric surfactants are compounds widely used in the manufacture of domestic and industrial cleaning, pharmaceutical, cosmetic, and food products. These compounds represent an interesting alternative as they can simultaneously increase the viscosity in water solution and reduce the interfacial tension (IFT) in the water/oil system, which would increase the efficiency of EOR processes.
 This article shows a methodological evaluation through laboratory studies, numerical reservoir simulation, and conceptual engineering design to apply polymeric surfactants (Block Copolymer Polymeric Surfactants or BCPS) as additives to improve efficiency in water injection processes. Block copolymer type products of ethylene oxide (EO) - propylene oxide (PO) - ethylene oxide (EO) in aqueous solution were studied to determine their rheological and surfactant behavior under the operating conditions of a Colombian field.
 In the conditions studied, these products allow to reduce the interfacial tension up to 2x10-1 mN/m values and also cause a shear-thinning rheological behavior following the power law at very low shear rates (0.1 s-1– 1 s-1), which corresponds to an increase up to four orders of magnitude in the capillary number (Nc). The IFT and the viscosity reached are maintained in wide ranges of salinity, BCPS concentration, and shear rates, making it a robust performance formulation.
 In a model porous medium, BCPS tested have moderate adsorption, less than conventional surfactants but higher than HPAM polymers, in any way allowing a favorable wettability condition. Additionally, it was observed that they offer a resistance factor up to 16 times, causing greater displacement efficiency than water injection, allowing better sweeping in low permeability areas without injectivity restrictions.
 Numerical simulation shows that it is possible to reach incremental production up to 238,5 TBO by injecting a continuous slug of 0.15 pore volumes of BCPS and HPAM, each with 2,000 ppm concentration and a flow rate of 2,500 BPD. As BCPS are simple handling and dilution products, these could be injected directly in water injection flow using a high precision dosing pump with high pressure and flow rate operational variables.

Effect of ionic strength in low salinity water injection processes

Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks.
 The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions.
 Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies.
 Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.

A Feasibility Study of Coal Seam Water Injection Processes: The Effects of Coal Porosity and Mass Flow Rates of Injected Water on Wetting Radii

Various effective methods of water injections for coal seams, which have been implemented in order to control coal-mine disasters, have attracted substantial renewed interest in the fields related ...

Experimental investigation of competitive mechanisms of precipitation and dissolution due to seawater and low salinity water injection in carbonate reservoirs

The dissolution and precipitation mechanisms are very effective in the water injection process, especially at low salinity and smart water injection. In this research, the focus is on competition between dissolution and precipitation mechanisms in the presence of calcite rock samples at reservoir conditions (100 °c and 2500 psi). Static experiments were designed in two parts; a) mixing of incompatible brines for investigation of precipitation process and b) repeating the process in presence of reservoir rock samples for precipitation/dissolution competition. Incompatible real formation and sea water brines were used to determine maximum scale formation ratio and dominate scale types. Based on high pressure static experimental results, mixing ratio of 50% of the formation water, as the maximum-precipitate-producing ratio, has been considered as the desired ratio for the experiments with rock samples in this study. The synthetic water compositions were designed to have the dominant scales as those were found in initial experiments of oil field water samples. In the next stage, the compatibility experiments were carried out for the mixture of 20-times diluted seawater and formation water. This was followed by mixing experiments in presence of the reservoir rock in the reservoir condition. The results were interpreted with ICP, SEM and EDX. The results of water mixing experiments with rock sample showed that most of the precipitations were sulfate scales types as strontium and calcium sulfates precipitations were significant in the ratio of 50% of formation water. Both precipitation and dissolution were detected in all experiments based on change in ions, rock surface chemical analysis and scale properties. The concentration of Ca2+, Sr2+ and SO42− ions determines the dominant mechanism. For 20-times diluted sea water, dissolution was dominant mechanism despite the presence of sulfate precipitations. However, this mechanism was indicated in sea water with less impact. In the compatibility tests, Mg2+ ion did not contribute to the precipitation process. In the process of mixing in presence of reservoir rock, the Mg2+ concentration was reduced in the end of experiment. Increase in calcium ion and decrease in magnesium ion indicated ion exchange at calcite rock surface.

Development of rational method of water injection for production of light hydrocarbon fluid deposited in reservoir in the last exploitation phase

The complications in production of liquid hydrocarbons became immovable due to the retrograde phenomenon or degassing process in the last stage phase of exploitation of gascondensate, gascondensate-oil or light oil fields, operated in depletion mode have been researched and the impact of advanced method of water injection considered the most efficient for heterogeneous formation studied as well. For the efficiency increase of water injection process, a new polymer-disperse system injected into the reservoir in small dozes as a bank, therefore selectively closing the zones with high permeability and increasing the cover zone of injected reservoirs is proposed. Based on the polyacrylamide and taken bentonite clay samples from Dash Salahly field of Azerbaijan including the nanoparticles, a new composition of polymer-disperse system has been developed, as well as the efficiency of the system in laboratory investigations studied. To control the effectiveness of the new composition, a physical reservoir model based on similar conditions has been developed and the experiments carried out through a special procedure.

Advanced Combustion Modelling of High BMEP Engines under Water Injection Conditions with Chemical Correlations Generated with Detailed Kinetics and Machine Learning Algorithms

<div class="section abstract"><div class="htmlview paragraph">Water injection is becoming a technology of increasing interest for SI engines development to comply with current and prospective regulations. To perform a rapid optimization of the main parameters involved by the water injection process, it is necessary to have reliable CFD methodologies capable of capturing the most important phenomena. In the present work, a methodology for the CFD simulation of combustion cycles of SI GDI turbocharged engines under water injection operation is proposed. The ECFM-3Z model adopted for combustion and knock simulations takes advantages by the adoption of correlations for the laminar flame speed, flame thickness and ignition delay times prediction obtained by a detailed chemistry calculation. The latter uses machine learning algorithms to reduce the time to generate the full database while still maintaining an even distribution along the variables of interest. The results demonstrate the applicability of the proposed methodology, capable of capturing not only the thermodynamic effects of water injection but also the chemical kinetics aspects related to the mixture water dilution whose prediction is mandatory for addressing the engine design according to different goals: complying with new emission directives and limits, turbine inlet temperature constraints, minimization of the BSFC and possibly engine power increase.</div></div>

Investigation of water spray evolution process of port water injection and its effect on engine performance

In this study, a 1.5L turbocharged gasoline direct injection (GDI) engine was modified by installing a port water injection (PWI) system adjacent to the intake valve to simulate the “quasi-direct” water injection. Experiments was performed at 1500 rpm wide throttle open (WOT) condition to investigate the effect of PWI on knock suppression, and 4850 rpm WOT condition to test the removal of fuel enrichment through PWI. Then, numerical simulation was conducted to investigate the water spray evolution process and subsequent influence on mixture formation. The experimental results showed that PWI could effectively suppress knock and decrease combustion temperature. Therefore, at 4850 rpm WOT condition, the engine was able to operate at a stoichiometric air/fuel ratio with moderate advancement of spark timing. The combined effect finally resulted in nearly 6% thermal efficiency improvement. At 1500 rpm WOT, 3.8% efficiency gain was achieved solely due to knock mitigation. Nitrogen oxides (NOx), soot and hydrocarbon (HC) emissions also showed a decreasing trend with the increase of water injection amount. The simulation results indicated that about 80% of total injected water collided on the inner surface of the intake port which became the major source of water vapor. The portion of water vaporized in the air is small. Sufficient time was important for intake port water film evaporation. PWI also resulted in in-cylinder wall wetting. The in-cylinder water wall wetting in 4850 rpm was sober than that at 1500 rpm due to stronger intake air motion and higher cylinder temperature. Although port water injection imposes limited impacts on the whole in-cylinder equivalent ratio, it can induce part fuel-rich zones inside the combustion chamber.

Multiphase flow characteristics and EOR mechanism of immiscible CO2 water-alternating-gas injection after continuous CO2 injection: A micro-scale visual investigation

Water-alternating-gas (WAG) injection has been widely applied in fossil fuel reservoirs to enhance oil recovery (EOR) and CO2 capture and storage (CCS) efficiency. However, no systematic investigation on the multiphase flow characteristics and EOR mechanism of WAG injection after continuous CO2 injection has been conducted at the micro-scale. Therefore, a visual micromodel was developed using CT scanning and microelectronic photolithography. Subsequently, micro-scale visual experiments were conducted to simulate the water injection, CO2 injection and WAG injection processes. Then, the multiphase flow characteristics and residual oil trapping mechanism were observed and analyzed. Finally, the volumetric sweep efficiency (VSE), oil displacement efficiency (ODE), residual oil distribution, and improvement effects of WAG-EOR and WAG-CCS were quantitatively studied. Experimental results revealed the flow characteristics of oil–water, oil–gas, and oil–gas–water were different. Pore throat morphology, wettability, and injection parameters all affects the multiphase flow process. Six types of residual oil were trapped and observed at various locations. The multiphase flow characteristics of jumping displacement, multiple displacement, and compression-release were identified. The VSE of water injection, gas injection, and WAG injection were 68.0%, 53.5%, and 86.0%, respectively. WAG injection significantly reduced “cluster-shaped” and “island-shaped” residual oil and oil film/ring. Therefore, the WAG-EOR mechanism is a combination of the macroscopic VSE of water injection and the microscopic ODE of CO2 injection. WAG injection after continuous CO2 injection increased oil recovery by 23.15% and CCS by 0.174 PV. However, the improvement effects of EOR and CCS capacity were dominated by the first and second WAG injection cycles, respectively.

Machine learning-based models for predicting permeability impairment due to scale deposition

Water injection is one of the robust techniques to maintain the reservoir pressure and produce trapped oil from oil reservoirs and improve an oil recovery factor. However, incompatibility between injected water and reservoir water causes an unflavored issue named “scale deposition.” Owing to the deposited scales, effective permeability of a reservoir reduced, and pore throats might be plugged. To determine formation damage owing to scale deposition during a water injection process, two well-known machine learning methods, least squares support vector machine (LSSVM) and artificial neural network (ANN), are employed in the present paper. To improve the performance of the LSSVM method, a metaheuristic optimization algorithm, genetic algorithm (GA), is used. The constructed LSSVM model is examined using real formation damage data samples experimentally measured, which was reported in the literature. According to the obtained outputs of the above models, LSSVM has a high performance based on the correlation coefficient, and infinitesimal uncertainty based on a relative error between the model predictions and the corresponding actual data samples was less than 15%. Outcomes from this study indicate the useful application of the LSSVM approach in the prediction of permeability reduction due to scale deposition, and it can lead to a better and more reliable understanding of formation damage effects through water flooding without expensive laboratory measurements.

Swelling behavior of heavy crude oil in carbonated water at the presence of Na2SO4 and Mg2SO4

Carbonated water (CW) and low salinity (LS) injection processes are among the most widely investigated method during the past decade due to their unique advantages. Although the results revealed rather efficiency of these two methods, it is reported that using the combination of these two methods can introduce new insight about the smart and newly developed enhance oil recovery processes. Respect to these facts, the current work is aimed to investigate the swelling behavior of heavy crude oil in carbonated water at the presence of Na2SO4 and Mg2SO4. In this way, one of the main effective mechanisms through the carbonated water injection which is swelling factor is examined in the presence of two different salts, namely, Na2SO4 and Mg2SO4, under different pressures (500–4000 psi) and temperatures (30–80 °C). The results obtained in this investigation are compared with the previously reported results regarding the carbonated brine (CB) solutions consisted of different salts such as KCl, NaCl, CaCl2, and MgCl2 with the same concentration of 15,000 ppm. The results not only reveal the possible mechanism behind the swelling factor variation, but also reveal that crude oil and ion type as well as temperature besides the solubility of CO2 in aqueous phase can introduce tremendous influence on the mobility of CO2 molecules and their partitioning from aqueous phase towards the oil phase. Also, the obtained results reveal that the presence of divalent ions can directly affect the crossover pressure toward lower values.