Solubility In Brine Research Articles

Estimating Carbon Dioxide Solubility in Brine Using Mixed Effects Random Forest Based on Genetic Algorithm: Implications for Carbon Dioxide Sequestration in Saline Aquifers

Summary Accurate prediction of carbon dioxide (CO2) solubility in brine is crucial for the success of carbon capture and storage (CCS) by means of geological formations like aquifers. This study investigates the effectiveness of a novel genetic algorithm-mixed effects random forest (GA-MERF) model for estimating CO2 solubility in brine. The model’s performance is compared with established methods like the group method of data handling (GMDH), backpropagation neural networks (BPNN), and traditional thermodynamic models. The GA-MERF model utilizes experimental data collected from literature, encompassing key factors influencing CO2 solubility: temperature (T), pressure (P), and salinity. These data are used to train and validate the model’s ability to predict CO2 solubility values. The results demonstrate the superiority of GA-MERF compared to the other models. Notably, GA-MERF achieves a high coefficient of determination (R) of 0.9994 in unseen data, indicating a strong correlation between estimated and actual CO2 solubility values. Furthermore, the model exhibits exceptionally low error metrics, with a root mean squared error (RMSE) of 2×10-8 and a mean absolute error (MAE) of 1.8×10-11, signifying outstanding accuracy in estimating CO2 solubility in brine. Beyond its high accuracy, GA-MERF offers an additional benefit—reduced computational time compared to the other models investigated, with 65 seconds. This efficiency makes GA-MERF a particularly attractive tool for real-world applications where rapid and reliable CO2 solubility predictions are critical. In conclusion, this study presents GA-MERF as a powerful and efficient model for predicting CO2 solubility in brine. Its superior performance compared to existing methods and previous literature highlights its potential as a valuable tool for researchers and engineers working on CCS projects utilizing aquifer storage. The high accuracy, low error rates, and reduced computational time make GA-MERF a promising candidate for advancing the development of effective and efficient CCS technologies.

Effects of block and random copolymerization on the properties of fatty alcohol polyoxypropylene‐polyoxyethylene ether sulfates for enhanced oil recovery

AbstractEnhanced oil recovery (EOR) by surfactant flooding has been attractive. Among the surfactants developed alcohol polyoxypropylene (PO)‐polyoxyethylene (EO) ether sulfates (APES), also named extended surfactants, have been proved efficient. However, the arrangement of the PO and EO chains as well as the hydrocarbon structure in the molecules may significantly affect their performances. In this paper three APES, C18−16PO25EO10SO4Na (I), C18−16(PO/EO)25+10SO4Na (II), and C16GA(PO/EO)25+10SO4Na (III) were prepared and investigated, in which APES (I) and APES (II) were designed to have same PO and EO numbers but block and randomly copolymerized respectively with linear C18−16 fatty alcohols as starting agent, whereas the APES (III) was derived from double chain C16 Guerbet alcohol (C16GA) with PO and EO randomly copolymerized. The results show that the block copolymerized APES (I) gives much better brine solubility and counterion tolerance than the randomly copolymerized APES (II) and (III). Although all APES synthesized are highly surface‐active and can reduce Daqing crude oil/simulated brine interfacial tension (IFT) to ultralow by mixing with more hydrophobic surfactants in presence or absence of alkali, the APES (III) gives the lowest IFT due to with double hydrocarbon chains. In addition, it is found that for APES (I) gelation occurs in neutralization process and the corresponding nonionic intermediate is highly viscous, whereas the randomly copolymerized two intermediates are liquid‐like with low viscosity, which may be feasible to apply SO3/air falling film sulfation. This study provided useful information for arrangement of embedded nonionic moiety and hydrocarbon structure in designing extended surfactants for EOR.

Solubility of H2-CH4 mixtures in brine at underground hydrogen storage thermodynamic conditions

Concerning the emerging power-to-gas technologies, which are considered the most promising technology for seasonal renewable energy storage, Underground Hydrogen Storage (UHS) has gained attention in the last few years. For safe and efficient storage, possible hydrogen losses due to dissolution into the aquifer must be estimated accurately. Due to safety concerns, experimental measurements of hydrogen solubility in brine at reservoir conditions are limited. In this study, a PVT cell is used to characterize the solubility of hydrogen and its mixtures with methane in saline water/brine. The experiments were carried out at 45, 50, and 55°C and from 1 bar up to 500 bar, mimicking a significant range of possible reservoir conditions. Two brine samples representative of two different reservoirs were tested. Two mixtures of methane and hydrogen (10 mol% H2 and 50 mol% H2, respectively) were considered, along with pure hydrogen, to account for the presence of methane in the primary phase of hydrogen storage in a depleted gas reservoir. In the current paper, a comparison of the experimental results with literature models is provided. At the experiment conditions, the impact of the differences in the composition of the two analyzed brines as well as the impact of the analyzed range of temperatures was not significant. Conversely, a non-negligible variation in terms of the slope of the solubility curve was observed as a function of the gas mixture composition: the curve increased more steeply as the percentage of hydrogen reduced.

Solubility of CO in water and NaCl(aq) at high pressures

Experimental measurements of CO solubility in water and in NaCl(aq) solutions are reported at temperatures, pressures and salt molalities of relevance to geological carbon storage: (323.15 to 423.15) K, (2 to 28) MPa and (2 and 4) mol·kg−1, respectively. The expanded relative uncertainty of the CO solubility is estimated to be 4.4% at 95% confidence intervals. This study provides the first data for CO solubility in brine with high molality of salt. The results from this study were used to develop simple models for the solubility of CO in aqueous NaCl solutions as a function of temperature, pressure and salt molality dependent, up to 4 mol·kg−1.

Transport Properties of NaCl in Aqueous Solution and Hydrogen Solubility in Brine.

Ion transport properties and hydrogen solubility in brine play pivotal roles in various engineering and scientific scopes including chemical, physical, geochemical, and geothermal domains. Molecular dynamics simulations were performed to obtain transport properties of NaCl in the binary H2O + NaCl system using different force fields. Brine density, ion diffusivity, molar conductivity, conductivity, and hydrogen solubilities were obtained as functions of temperature and salt concentration. We compared the performance of different force fields against the experimental correlation model and developed three mathematical models. The first was the modified brine density model based on the simulated brine density over a wide range of salinity levels, and the second and third analytical mathematical models were derived for the ion diffusivity and molar conductivity as a function of salinity and temperature. The results of this study illustrated that the modified brine density model not only produced the same results of the previous model for lower salinity levels but also applied well to predict the brine density for a higher salinity level. The derived mathematical models indicated that the ion diffusivity and molar conductivity decreased linearly with salinity, and the slope and y-intercept of the lines of diffusivity and molar conductivity versus temperature were third-order polynomials of temperature. The developed models provided the mechanism for the behavior of decreasing molar conductivity with increasing salinity and increasing conductivity with increasing salinity. The directions of the effect of salinity on the molar conductivity and conductivity were opposite. The molar conductivity increased with a decreasing salinity level. However, the conductivity increased with increasing salinity, as the contribution of the ion concentration or salinity level to conductivity dominated over that of the ion movement.

Assessing the impact of dip angle on carbon storage in saline reservoirs to aid site selection

Reservoir dip angle and permeability significantly impact CO2 plume migration and the amount of secondary phase trapping in storage formations. There is a fundamental trade-off between up-dip plume migration and secondary trapping that can be advantageous, or disadvantageous, for selecting an optimal CO2 storage site. For example, low permeability reservoirs have limited plume migration up-dip, consequently, residual and solubility trapping are also limited. On the contrary, for highly permeable reservoirs, up-dip migration can be fast and extensive, leading to accelerated residual and solubility trapping. By performing a systematic simulation study of plume migration and secondary trapping in reservoirs with a range of permeabilities and dip angles, we found that having a dip angle of at least 1° and permeability of at least 500mD results in up to 88% of the plume being immobilized 100 years post-injection. In reservoirs with a permeability of at least 500mD, we can optimize the amount of immobilized CO2 while limiting the amount of plume migration. As reservoir dip angles increase up to 2° and permeability increases, CO2 plume migration increases progressively, and up to 8x more mass of CO2 can migrate up-dip versus down-dip. At the same time, CO2 solubility in brine and residual trapping work to decrease the plume volume and can immobilize 28% to 90% of the CO2 plume over 100 years post-injection. Five influential parameters were identified that strongly influence the plume volume during the post-injection period for these dipping reservoirs: CO2 saturation, residual gas saturation, CO2 solubility in brine, CO2 density, and formation permeability. We also investigated the impact of simulation grid resolution, the maximum non-wetting phase saturation, and the pore-size distribution parameter on predicted plume behavior. This work provides simple, reliable relationships between key site screening metrics, reservoir dip angle, and permeability to inform the site selection process and monitoring, measurement, and verification (MMV) design.

CO2 concentration in aqueous solution from gas–liquid equilibrium system to gas–liquid–hydrate coexistence system

Hydrate-based CO2 sequestration is a new CCUS technology. The main concern for this method is the safe and long-term storage of CO2, which is related to the gas concentration in the surrounding aqueous solution. This work conducted a series of experiments to measure the saturated CO2 concentration in aqueous solution from gas-liquid (V–Lw) two-phase equilibrium system, gas-liquid-hydrate (V–Lw–H) three-phase equilibrium system up to hydrate stability region. The CO2 solubility curves in wider temperature and pressure range from V–Lw two-phase equilibrium system to V–Lw–H coexistence system were achieved in this work. When decreasing the temperature from V-Lw two-phase region into hydrate stability region under the constant pressure, the CO2 solubility in liquid phase would firstly increase with the decrease of temperature, and reach the maximum value at the V–Lw–H three-phase equilibrium temperature. After that, it would conversely turn to decrease with the decrease of temperature in hydrate stability region. When increasing the pressure from V–Lw two-phase region into hydrate stability region at constant temperature, the CO2 solubility would increase with the increase of pressure up to the point where the system pressure is equal to V–Lw–H three-phase equilibrium pressure. After that, it barely changes with the increase of pressure in hydrate stability region, indicating that the intrinsic formation reaction that the dissolved gas combines with water molecules to form gas hydrate is fast step, and the gas molecules dissolve at gas-liquid interface is the rate-determining step for hydrate formation process. The CO2 solubility in brine under V–Lw–H three-phase equilibrium conditions is higher than that in deionized water, which may contribute to revealing the mechanism that salt can promote hydrate formation rate at low concentrations.

A novel computational strategy to estimate CO2 solubility in brine solutions for CCUS applications

Estimation of CO2 solubility in brine is crucial to various CCUS (carbon capture utilization and storage) applications, especially for engineering design of the physical/chemical processes. In this work, we developed machine learning based workflow to calculate CO2 solubility in brine at various combinations of salt mixtures, pressure, and temperatures. Most importantly, the performance of predictive models and workflow were tested against extensive experimental observations and key features of brine components with significant contributions were determined.

Phase equilibrium modeling for carbon dioxide Capture and Storage (CCS) fluids in brine using an electrolyte association equation of state

A modified electrolyte cubic plus association equation of state (eCPA EoS) is proposed here as a suitable model for CO2 Capture and Storage (CCS) fluids to model CO2, CH4, H2S, N2, O2, Ar, and air solubility in multi-component brines containing NaCl, KCl, CaCl2, MgCl2, and Na2SO4. A new correlation of the g-factor of water as a function of temperature is presented to accurately calculate the dielectric properties of pure water with CPA EoS and a new formula related to ions associated with polar molecules is presented to describe the mixed solvents containing salts by neglecting ion–solvent association, which avoid the computational complexity of hydrogen bond formation. The performance of the modified eCPA model is improved for modeling the gas–water system by considering the cross association between H2S/CO2 and water. The modified eCPA model can accurately calculate the gas solubility in brine and water content in gas phase for water-salt-gas systems.

Literature Review of Hybrid CO2 Low Salinity Water-Alternating-Gas Injection and Investigation on Hysteresis Effect

Low salinity water injection (LSWI) is considered to be more cost-effective and has less environmental impacts over conventional chemical Enhanced Oil Recovery (EOR) methods. CO2 Water-Alternating-Gas (WAG) injection is also a leading EOR flooding process. The hybrid EOR method, CO2 low salinity (LS) WAG injection, which incorporates low salinity water into CO2 WAG injection, is potentially beneficial in terms of optimizing oil recovery and decreasing operational costs. Experimental and simulation studies reveal that CO2 LSWAG injection is influenced by CO2 solubility in brine, brine salinity and composition, rock composition, WAG parameters, and wettability. However, the mechanism for increased recovery using this hybrid method is still debatable and the conditions under which CO2 LSWAG injection is effective are still uncertain. Hence, a comprehensive review of the existing literature investigating LSWI and CO2 WAG injection, and laboratory and simulation studies of CO2 LSWAG injection is essential to understand current research progress, highlight knowledge gaps and identify future research directions. With the identified research gap, a core-scale simulation study on hysteresis effect in CO2 LSWAG injection is carried out. The results indicate different changing trend in oil recovery due to the impact of salinity on hysteresis and excluding of hysteresis effect in CO2 LSWAG injection simulation and optimization might lead to significant errors.

Enhanced oil recovery through synergy of the interfacial mechanisms by low salinity water alternating carbon dioxide injection

During this study, a comprehensive investigation of low salinity water alternating CO2 injection was performed for enhanced oil recovery in oil-wet carbonate reservoirs. A synergy of interfacial mechanisms such as IFT, wettability alteration, CO2 solubility, oil swelling, water shielding effect, and rock dissolution was considered in two and three-phase systems. Results showed that the monovalent ions, such as NaCl or KCl, inhibit the dissolution of carbon dioxide in brine in excess of divalent salt solutions, e.g. CaCl2 or MgCl2 due to the salting-out effect. In addition, more water shielding effect was observed in low salinity formation water than it in low salinity seawater. The significant change in the reservoir wettability of oil/brine/CO2 system compared to oil/brine referred to the CO2 solubility in brine which could cause stronger carbonated water in the reservoir. Consequently, the low salinity alternating CO2 injection overpowers the late-production problem that occurred commonly in conventional WAG injection.

CO2–Brine–rock interaction and sequestration capacity in carbonate reservoirs of the Tahe Oilfield, Xinjiang, China

AbstractThe characteristics of each carbonate reservoir are greatly different, and current databases are insufficient to support engineering scheme design and optimization of carbon dioxide (CO2) sequestration and enhanced oil recovery. In this paper, the behavior of CO2‐brine‐rock interactions was investigated under supercritical CO2 (50°C and 8.5 MPa) conditions. Five experiments were carried out, including CO2 solubility in brine, mass loss analysis by static reaction of CO2–brine–rock, mineralogical composition analysis by X‐ray diffraction (XRD), core surface morphology analysis by scanning electron microscopy (SEM), and wettability alteration by contact angle analysis. The experimental results showed that: (a) the CO2 solubility in brine increases with increasing pressure, but it increases slowly and gradually reaches equilibrium; (b) the mass loss of carbonate increases with reaction time, but its increments decrease with reaction time; (c) the calcite content gradually decreases and the quartz content slightly increases with reaction time, as evidenced by XRD analysis; (d) based on SEM image analysis, calcite was dissolved into brine by carbonic acid to make the pores larger, and then subsequent precipitation made the pores smaller; and (e) the carbonate rock surface became more water‐wet after CO2–brine–rock interaction experiments due to surface corrosion and increased quartz content. Using the experimental results, a mathematical model was developed to predict CO2 sequestration capacity under reservoir conditions. The results suggest that CO2 solubility in brine was the main aspect compared with mineral trapping in carbonate reservoirs, and CO2 sequestration capacity increased with increasing temperature and pressure. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd.

Review of barium sulphate solubility measurements

Barium sulphate (BaSO4) scaling is a known issue but still an unresolved problem in the petroleum and geothermal industries. It can cause severe damage to the wellbore and surface facilities. Prevention of scale formation is the technically and economically advantageous solution to apply. This requires knowledge of the BaSO4 solubility in different brines at elevated pressure and temperature. This work aims at obtaining a comprehensive understanding of the status of BaSO4 solubility and to outline the way for future research. It provides a review of the experimental methods used to measure BaSO4 solubility, followed by a critical analysis of the general trends indicated by data from the different references. This information was used to draw recommendations for future studies regarding the measurement and calculation of BaSO4 solubility in brines. A comprehensive literature search was done to retrieve data on BaSO4 solubility in various electrolyte solutions. The findings were summarized and compared to phase equilibrium calculations performed using the Extended UNIQUAC model. Existing experimental data does not allow for unambiguous modelling of the solubility curve in such mixtures. This review also suggests there is only one reliable report of solubility measurements in pure water at temperatures greater than 100 °C. This points to the urgent need of extending the knowledge of the equilibrium properties of such solutions. Moreover, data on BaSO4 solubility in multicomponent aqueous solutions are limited to a few electrolytes and organic solvents. The addition of chlorides (NaCl, CaCl2, and MgCl2) into the solution increases BaSO4 solubility; whereas sulphates (Na2SO4) greatly reduce BaSO4 solubility due to a common ion effect. Development of a fine-tuned Extended UNIQUAC parameter set, with more ions, is challenging due to the low number of solubility measurements reported in the literature. The comparisons between experimental data and model clearly indicate that further experimental work is crucial to improve the accuracy of barite scale calculations.

Evaluation of Different Machine Learning Frameworks to Estimate CO2 Solubility in NaCl Brines: Implications for CO2 Injection into Low-Salinity Formations

Abstract An accurate estimation of carbon dioxide (CO2) solubility in brine is of great significance for industrial applications such as quantifying CO2 sequestration in subsurface formations, CO2 surface mixing, and different CO2-based enhanced recovery methods (EOR). In this research, four different data-driven/machine learning techniques, extreme gradient boosting (XGB), multilayer perceptron (MLP), K-nearest neighbor (KNN), and in-house genetic algorithm (GA), were used to estimate solubility in terms of pressure, temperature, and salinity. Pressure, temperature, and salinity were used as model inputs, while CO2 solubility was the output. The experimental database used in this study was collected by dissolving CO2 into NaCl brines at salinity ranging from 0 to 15000 ppm, temperature ranging from 298 to 373 K, and pressures up to 200 atm. All data-driven models accurately estimated solubility through a coefficient of correlation (R2) ranging from 0.95 to 0.99, and a precise simple-to-use empirical solubility equation was developed using GA. The performance of the models was analyzed using proper model metrics (such as mean absolute error and relative error). A detailed feature importance analysis was conducted using feature importance, permutation, and Shapley values to clarify the correlation between the input and output parameters. The pressure was found to be the most impactful feature, followed by temperature and salinity. The model’s accuracy was compared to a well-established solubility model from the literature, and a good agreement between the two models’ results was observed. Lastly, conducting sensitivity analysis on the model revealed that the model’s estimations were still accurate when pressure and salinity were beyond the scopes of the original dataset.

CALCIUM SULFATE SCALE IN THE PETROLEUM INDUSTRY

Oilfield scale is defined as the precipitation of hard, adherent deposits of inorganic solid originating from aqueous media. This constitutes sulfate and carbonate of the alkaline earth metals calcium, barium and strontium and complex salts of iron. Generally, the process of the scale deposition occurs when the product solubility of a compound considered is exceeded. The formation of scale, such as calcium sulfate, has long recognised as one of the serious problems in oil and gas production leading to reduced production rates as flow becomes restricted. Calcium sulfate scale found in the oilfield is in the form of gypsum (CaSO4, 2H2,0) which is the most stable form at temperatures of 40 °C or less at atmosphere pressure. Above this temperature, anhydrite (CaSO4,) may be found, although hemihydrate (CaSO. 1/2H,O) may form under certain conditions. The reaction for precipitation of calcium sulfate is as follows: Ca+2 (aq) + so4-2 (aq) = CaSO4 (solid) The solubility of calcium sulfate in distilled water is 2080 mg/l at 25 "C. Calcium sulfate scale arises from several causes, such as temperature, dissolved salts, pressure, and time. The main points of this paper are focused on nomenclature, chemical structure, the occurrence of calcium sulfate scale, example of calcium sulfate scale in the petroleum industry, and calculation of calcium sulfate solubility in brine.

Experimental Study on the Interplay between Different Brine Types/Concentrations and CO2 Injectivity for Effective CO2 Storage in Deep Saline Aquifers

Salt precipitation during CO2 storage in deep saline aquifers can have severe consequences on injectivity during carbon storage. Extensive studies have been carried out on CO2 solubility with individual or mixed salt solutions; however, to the best of the authors’ knowledge, there is no substantial study to consider pressure decay rate as a function of CO2 solubility in brine, and the range of brine concentration for effective CO2 storage. This study presents an experimental core flooding of the Bentheimer sandstone sample under simulated reservoir conditions to examine the effect of four different types of brine at a various ranges of salt concentration (5 to 25 wt.%) on CO2 storage. Results indicate that porosity and permeability reduction, as well as salt precipitation, is higher in divalent brines. It is also found that, at 10 to 20 wt.% brine concentrations in both monovalent and divalent brines, a substantial volume of CO2 is sequestered, which indicates the optimum concentration ranges for storage purposes. Hence, the magnitude of CO2 injectivity impairment depends on both the concentration and type of salt species. The findings from this study are directly relevant to CO2 sequestration in deep saline aquifers as well as screening criteria for carbon storage with enhanced gas and oil recovery processes.

Geochemical reactions-induced hydrogen loss during underground hydrogen storage in sandstone reservoirs

Underground hydrogen storage (UHS) appears to be an important means as a large-scale and long-term energy storage solution. A primary concern of UHS is the in-situ geochemical reactions-induced hydrogen loss. In this context, we performed geochemical modelling to examine the hydrogen loss associated with hydrogen dissolution and fluid-rock interactions using PHREEQC (Version 3) as a function of temperature and pressure. We also performed geochemical modelling with kinetics to investigate the potential hydrogen loss in two commercial gas storage reservoirs (Tubridgi and Mondarra) in Western Australia against the reservoir mineralogy, fluid properties, depth and temperature.Our results show that increasing pressure and temperature only slightly increases hydrogen solubility in brines without minerals. Increasing salinity slightly decreases the solubility of hydrogen in brines. The saturated hydrogen aqueous solution almost does not react with silicate and clay minerals, which is favorable for underground hydrogen storage in quartz-rich sandstone reservoirs. However, unlike silicate and clay minerals, carbonates like calcite triggers up to 9.5% hydrogen loss due to calcite dissolution induced hydrogen dissociation process. Kinetic simulations show that Tubridgi only leads to 0.72% of hydrogen loss, and Mondarra causes 2.76% of hydrogen loss as a result of reservoir calcite dissolution and hydrogen dissociation in brines in 30-year time. Nearly over 87% of calcite cement from Mondarra may be dissolved in 30-year, suggesting potential risks associated with wellbore stability. In conclusion, geochemical reactions-induced hydrogen loss would be minor for UHS in porous media, and we argue that deep calcite-free reservoirs together with calcite-free caprocks would be preferable for underground hydrogen storage.

Investigation of gas solubility and its effects on natural gas reserve and production in tight formations

In this study, the natural gas solubility in brine and its influence on natural gas reserve and production in a tight gas reservoir have been investigated by the integration of laboratory experiments, phase equilibrium calculations, and numerical evaluation. Experimentally, a visualized PVT cell has been used to measure natural gas solubility at various pressures, temperatures, and salinity. Theoretically, the solubilities of natural gas and natural gas components are calculated using the phase equilibrium theory and equation of state (EOS), which are calibrated by the experimental data first. A sensitivity analysis is implemented to investigate the effects of pressure, temperature, and salinity on natural gas solubility. Subsequently, with the assistance of numerical simulation, the influence of the dynamic gas solubility on the natural gas reserve and production is examined in a tight gas reservoir in Middle Permian Shihezi Formation, Ordos Basin, China. The natural gas solubility is found to be 2.91 m3/m3 at initial reservoir conditions, which contributes to an increase of 1.33% in natural gas reserve. For natural gas and formation brine with specific composition, the gas solubility decreases gradually with the reservoir pressure reduction in the production process. The production prediction indicates that the cumulative gas production from tight formation requires calibration if the dynamic gas solubility is considered. In the field-scale simulation, the cumulative gas production after 10 years is 0.52% higher than the case not considering the dynamic natural gas solubility.

Experimental analysis of hybrid low salinity water alternating gas injection and the underlying mechanisms in carbonates

Enhanced oil recovery methods have been widely used around the world to improve ultimate hydrocarbon recovery. Among them, low salinity water flooding has gained attention as a practical enhanced oil recovery method which modifies the rock wettability to a more hydrophilic state. Besides, gas, mainly CO2, injection by means of water alternating gas process is proved to improve un-swept oil recovery due to the mobility control of displacing fluids. Hence, the mutual application of these two enhanced oil recovery techniques, as low salinity water alternating gas) injection, benefits the driving mechanisms subjected by both methods resulting in higher oil production. In this study, a series of experiments including contact angle measurements, gas solubility in brine, emulsion formation, and coreflooding were conducted. Wettability alteration of the carbonate samples towards the more water wet state was observed by the contact angle measurements for diluted sea waters which shows salinity of the injected water can play a significant role in the enhancement of ultimate oil recovery. 10 times diluted brine was found to be the optimum one which changed the contact angle for 52°. It shows that there is an optimum concentration for different CBR systems under which the available PDIs are not sufficient to alter the rock wettability to a greater extent. The presence of gas phases favorably improved the wettability modification. The successful performance of 10 times diluted brine was also confirmed by emulsion formation tests. For this case, the number of the generated water in oil emulsion droplets was 1.54 times that of SW. Stable emulsions enhance the oil displacement through provoking wettability alteration by low salinity water and mobilizing the residual oil via the osmotic effect. Finally, a 10.8% incremental oil recovery by low salinity water alternating gas flooding verified the synergistic effects of this method regarding enhanced oil recovery.

Numerical Investigation of CO2 Solubility in brine during Continuous CO2 flooding and optimization of different parameters

Numerical Investigation of CO2 Solubility in brine during Continuous CO2 flooding and optimization of different parameters