Smart Water Flooding Research Articles

Experimental study of the effect of oil polarity on smart waterflooding in carbonate reservoirs

This study investigates the influence of oil polarity on interfacial tension (IFT), contact angle, oil recovery, and effluent pH in smart water and Low-salinity water injection. The results indicate that the interaction between the hydration shell of ions and the polar components (PCs) of oil is crucial. Increasing oil polarity enhances the potential for interaction with the hydration shell of ions, leading to reduced IFT, altered wettability, and improved oil recovery; which could be boosted by the contribution of a higher number of anions in the smart water bulk through the enhancement of their interaction with the PCs (especially acidic components) of oil. The study demonstrates that increasing the SO42− concentration in seawater increased oil recovery for oils with higher acid component content, as indicated by total acid number values of 0.87, 0.99, and 1.32 mgKOH/g, the tertiary oil recovery factors for these oils were 61.10%, 69.82%, and 87.09%, respectively. The effluent pH results align with the findings of contact angle and oil recovery, confirming the dominant influence of anions on oil recovery. The interaction between the PCs of oil and the hydration shell of ions is thus highlighted as a critical factor in the observed outcomes.

Experimental investigation of carbamide-assisted smart water flooding for enhancing heavy oil recovery from carbonate reservoirs

This study explores the impact of carbamide at different concentrations on smart water flooding into carbonate reservoirs. The aim is to find out how the presence of carbamide can influence the mechanisms of smart water flooding at rock/brine and oil/brine interfaces. The results revealed that interfacial tension (IFT) reduces as the carbamide concentration increases in the brine. Indeed, the carbamide decomposes at elevated temperatures, and in-situ surface active agents are formed at the oil/brine interface, reducing IFT values. Further, while the dilution of seawater (SW) is unable to change the oil-wet wettability, the carbamide can make the carbonate surface more water-wet by elevating its concentration. Additionally, the corresponding mechanisms of this wettability alteration would be the formation of in-situ surface active agents, electrostatic interactions, and hydrogen bond formation at the rock/brine interface. Among K+, Mg2+, and SO42−, adjusting the concentration of sulfate ions in SW leads to greater IFT reduction in the presence of carbamide. In addition, the contact angle is further reduced as K+ concentration is doubled in the solution; however, this reduction is not significant as compared to Mg2+ and SO42−. Also, ten-times diluted seawater (10dsw) produced more micro-dispersions in the oil phase. Nevertheless, the presence of carbamide in 10dws had a negative impact on the micro-dispersion formation, which is one of the driving mechanisms of smart water flooding. At a lower carbamide concentration (1000 ppm), more carboxylic acids and ketones were observed in the brines due to the partitioning and dissociation of naphthenic acids. On the contrary, as carbamide concentration increased to 10000 ppm, amounts of carboxylic acids declined due to the production of in-situ surface active agents at the oil/brine interface. Bottle test experiments indicated that water-in-oil emulsions were generated in the presence of carbamide. The mean water droplet size grew as carbamide concentration rose to 25000 ppm; nonetheless, further increase in the carbamide concentration resulted in mean droplet size reduction. Calcite-coated micromodel flooding illustrated that oil recovery of 21.6, 24, and 27.2 % was found at carbamide concentrations of 1000, 10000, and 100000 ppm. Furthermore, a three-time increase in SO42− concentration at 10000 ppm of carbamide offered a better performance in boosting oil recovery than tuning K+ and Mg2+ concentrations in carbamide/SW solutions. The findings of this study underscore the promising prospects of leveraging carbamide to enhance the efficacy of smart water solutions in carbonate reservoirs, particularly regarding IFT modification, wettability alteration, and oil recovery enhancement.

Effects of nano-smart water on enhanced oil recovery in carbonate reservoirs: Interfacial tension reduction and wettability alteration

Several studies have revealed that nanofluid and smart water flooding are cost-effective methods, considering the effect of nanoparticles and potential determining ions (PDIs) for enhanced oil recovery in carbonated reservoirs. This study presents the performance of nano-smart water synthesized with surface-modified SiO2 nanoparticles dispersed in PDI-controlled seawater (SW), ensuring dispersion stability in high-temperature and high-salinity reservoirs. The interfacial tension (IFT) and contact angle of the oil/nano-smart water/carbonate rock system were measured using kerosene as an oil phase. At this time, nanoparticle concentrations ranged from 0.5 to 3 wt% and PDI concentrations ranged from 1,000 to 5,000 ppm, such as KCl, MgCl2, MgSO4, and K2SO4. In addition, the IFT and contact angle of SW, low salinity water (LSW), and nanofluid were measured for comparison. It was observed that at nanoparticle concentrations higher than 1 wt%, the IFT values of nano-smart water remained constant or decreased slightly to below 31.91 mN/m compared with nanofluids at 32.18 mN/m, regardless of PDI type and concentration. This indicates that using nano-smart water instead of LSW and SW is expected to reduce the IFT in the oil/water system. The contact angle measurements revealed that the wettability index is 2.57–5.07 times higher in nano-smart water than in nanofluids. This implies that wettability alteration is accelerated by the synergistic effect of PDIs and nanoparticles. Specifically, PDI control with MgSO4 or K2SO4 is highly effective in changing the contact angle of carbonate from strongly oil-wet to strongly water-wet due to the ion exchange reaction of SO42- in oil/water/carbonate rock system. The nano-smart water used in this study is expected to be utilized as an injection fluid under harsh conditions for enhanced oil recovery.

Formation and stability of emulsion in the presence of nano particles in the modified smart aqueous phase: Effect of ultrasonic, salt, and surfactant

Synergistic effects of nanoparticles (NPs) and smart water flooding are new methods for enhanced oil recovery (EOR). One of the vital issues, in this case, is the formation and stability of emulsion. Therefore, investigating the role and performance of NPs and ions during the processes of EOR, which are based on smart water injection and natural reservoir production, is of significant importance. Previous studies have investigated various factors (i.e., compounds present in oil and water) that affect emulsion stability mainly at ambient temperatures. In this research, the effect of various factors, including the effect of surfactants, salts, and NPs, on the dynamics and thermodynamics of this phenomenon, has been studied through the visual analysis of emulsion droplets under high pressure (HP) and high-temperature (HT) conditions. Based on the results obtained from the experiments, the rate of formation and stability of emulsions increases by increasing the pressure, and after a certain pressure level, it decreases. On the other hand, in general, the rate of emulsion stability follows a decreasing trend by increasing the system temperature. Additionally, in this study, three salts, namely MgCl2, CaCl2, and NaCl, and two surfactants, AOS (alpha olefin sulfonate) and CTAB (cetrimonium bromide), were used. After finding the optimal weight percentage of these salts and surfactants in the formation and emulsion stability, they were combined with nanoparticles of silica oxide in different volume percentages, and the effect of these nanoparticles on the emulsion stability was investigated. The effect of ultrasonication on solutions containing NPs was also investigated from the point of view of emulsion formation and stability. Based on the results obtained, as the power consumption of the ultrasonic device increases to form an emulsion, the rate of rotation for its separation will also increase.

Chemical-Enhanced Oil Recovery by Alkali/Sulfate Smart Water Flooding in Carbonate Reservoirs Using a Green Polymer Extracted from Plantago ovata Seed

Chemical-Enhanced Oil Recovery by Alkali/Sulfate Smart Water Flooding in Carbonate Reservoirs Using a Green Polymer Extracted from <i>Plantago ovata</i> Seed

Modeling of formation damage during smart water flooding in sandstone reservoirs

Impairment of permeability has been observed as an effective factor in production decline during secondary and tertiary recovery processes such as water flooding. Among different permeability damage mechanisms, fines migration and deposition is known as the main mechanism which occurs due to pore throat clogging and blocking. Because injected water and formation water are usually incompatible, permeability damage evaluation and scale formation prediction must be done before the water flooding process in the oil field is implemented. For this purpose, compatibility tests and core flood experiments are common, but experimental approaches with time and facility limitations are expensive. Thus, by decreasing the time required for conducting experiments, modeling approaches can replace the routine laboratory experiments. Based on thermodynamic balance and the solubility of ions in water, scale development due to seawater injection in an Iranian oil field was predicted in this work using the OLI ScaleChem software. After that, it was suggested that special water be introduced to help reduce the amount of scales that had accumulated in the rock pore space. The extent of permeability damage in various seawater injection scenarios was then assessed via dynamic core flood experiments. Finally, scales-seawater injection into the core was simulated using digital core analysis (DCA) results and the pore scale modeling approach. The core flood experiment data are consistent with the scale formation prediction made by the OLI ScaleChem software, which indicates that smart water can be determined by optimizing the salinity and ion content of injected water. Also, results of permeability damage prediction by our modeling approach have good agreement with the core flood experiment data. Therefore, our modeling approach can replace the conventional core flood experiments as a low-cost method with high computational efficiency and high enough accuracy to evaluate formation damage in the water flooding process.

Effect of the Type and Concentration of Salt on Production Efficiency in Smart Water Injection into Carbonate Oil Reservoir Rocks.

Smart waterflooding is one of the most practical emerging methods of enhanced oil recovery in carbonate reservoirs. In this study, the effect of salt type and its concentration in smart water on oil recovery from a carbonate reservoir rock is investigated. A series of experimental measurements, including zeta potential (ZP), interfacial tension (IFT), and contact angle (CA), were conducted to examine the effect of ions on the oil/brine/rock interaction. IFT, ZP, and CA were also used as screening methods to select effective solutions for flooding experiments. The results of the study show that synthesized brines containing sodium acetate and potassium acetate salts have a significant effect on the reduction of IFT; however, rock surface wettability due to such brines is insignificant. The presence of organic salts in the injected water can alter the properties of the fluid and rock surface, leading to improved oil recovery. The salts can reduce the interfacial tension between the oil and water phases, making it easier for the water to displace and mobilize trapped oil. This effect is particularly beneficial in reservoirs with high oil-water interfacial tension as it enhances the capillary forces and improves the sweep efficiency. Smart water with sodium acetate (MSW.NaOAc) caused a 7% increase in oil production in the tertiary injection process due to IFT and CA reduction. The secondary injection of MSW.NaOAc led to an oil production efficiency of 76%, which is 10% higher than that of the secondary injection of seawater (SW), confirming the effectiveness of acetate ions in enhancing oil recovery. Doubling the concentration of sulfate ions in modified SW (MSW.NaOAc.2S) caused a 19% increase in oil production in tertiary injections after SW flooding. The secondary injection of MSW.NaOAc.2S produced a 13% increase in the recovery factor compared to SW flooding in the secondary mode. The main driving mechanism for oil mobilization was found to be wettability alteration, which is supported by the analyses of CA and ZP. This study confirms that the salt type and concentration present in a brine solution play a vital role in the movement of trapped oil in carbonate reservoirs.

Experimental investigation of wettability alteration, IFT reduction, and injection schemes during surfactant/smart water flooding for EOR application

In recent years, the application of smart water and surfactant in order to improve oil recovery has attracted special attention in carbonate reservoirs. In this research, the effects of various salts in smart water and two surfactants of Cetyl Trimethyl Ammonium Bromide (CTAB) and Sodium Dodecyl Sulfate (SDS) on the wettability alteration of carbonate rock and IFT were studied. Besides, along with micromodel flooding, core flooding tests were conducted to assess the amount of oil recovery at reservoir conditions as an injection scheme was used. In this regard, the results illustrated that the presence of CTAB or SDS in seawater (SW) can act better in contact angle reduction compared to smart water. Also, a four times increase in the concentration of SO42− and removing Na+ from SW reduced the contact angle to 68° and 71°, respectively, being the best possible options to alter the carbonate surface wettability to more water-wet states. Moreover, in the second-order process in which the rock section was first placed in SW, and then was put in the smart solution (with or without surfactant), CTAB had a great effect on the wettability alteration. In the case of IFT reduction, although SW4Mg2+, compared to other ions, better decreased the IFT to 17.83 mN/m, SW + SDS and SW + CTAB further declined the IFT to 0.67 and 0.33 mN/m, respectively. Concerning different ions, divalent cations (Mg2+ and Ca2+) show better results in improving oil recovery factor. However, the combination of SW and surfactants has a more positive effect on boosting oil recovery, as compared to smart water flooding. It should be mentioned that the first-order injection is better than the second-order one since SW is flooded at first, and then, after the breakthrough, smart water is injected into the micromodel. In addition, the core flooding tests showed that SW + CTAB and SW + SDS in tertiary injection increased the oil recovery to about 59 and 57%, respectively, indicating that the presence of CTAB could be more effective than that of SDS.

Uncovering Smart Water Flooding Mechanisms in Carbonate Reservoir Rocks by Integrating the Impact of Zeta Potential on Wettability Alteration

Uncovering Smart Water Flooding Mechanisms in Carbonate Reservoir Rocks by Integrating the Impact of Zeta Potential on Wettability Alteration

Effect of Polar Hydrocarbon Contents on Oil-Water Interfacial Tension and Implications for Recent Observations in Smart Water Flooding Oil Recovery Schemes.

For decades now, low salinity water flooding (LSWF) oil recovery has emerged as an environmentally benign and cost-effective method for improved oil recovery, where research findings have reported pH and interfacial tension effects. Considering the effect of oil chemistry on interfacial tension and the potential of this chemistry to have a direct relationship with LSWF, we measured the interfacial tension of four crude oils with composition varying from those of conventional to unconventional ones. We also characterized the crude oil samples using infrared spectroscopy and a wet chemistry method based on asphaltene precipitation. Our research approach has enabled us to relate the composition of crude oil to the interfacial tension trend at pH encountered in improved oil recovery schemes. Our research methodology, based on an integrated approach to using infrared spectroscopy and interfacial tensiometry, has also enabled us to propose a more robust theoretical explanation for current observations in LSWF related to pH and interfacial tension. In this regard, oil-water interfacial tension depends on the concentration of polar components, such that the higher the concentration of polar groups in crude oil, the higher the interfacial tension at a given pH of aqueous solution. We have also shown that the acid-base behavior of polar groups at the oil-water interface provides a theoretical interpretation of the explicit relationship between oil-water interfacial tension and the electrostatic components of interfacial tension as given by the energy additivity theory.

Rock–Oil–Brine Dominant Mechanisms in Smart Water Flooding

Recent research has highlighted wettability alteration as the main consequence of the different mechanisms involved in technologies such as adjusted brine composition water flooding (ABCW) and low-salinity water flooding (LSW). However, studies are still needed to give a phenomenological explanation, and the most influential components of the system (rock–oil–brine) must be clarified. This work focuses on determining the most relevant variables for the smart water effects to occur. Static (contact angles) and dynamic tests (coreflooding) were conducted. For the static tests, aged Berea slices, a specific crude oil (27° API, 10.5 cp at 60 °C), and mono and divalent inorganic salts (Na+, K+, Ca2+, and Mg2+/Cl−) were used in 3 different concentrations of 1000, 3000, and 5000 ppm (ionic strength variation between 0.015 and 0.06) to establish the wettability state by measuring the contact angles of the system. When salts containing chloride were evaluated, a decrease in oil wettability was observed at 5000 ppm. At 3000 and 1000 ppm, tendencies depended on the particular cation. Three brines were selected from the contact angle experiments to be used in coreflooding assays, considering a particular design to identify ion exchange from the rock–oil–brine system. The first assay was carried out in the absence of crude oil as a baseline to determine the ion exchange between the brine and the rock, and a second test considered crude oil to provide insight into ion exchange and its effect on displacement efficiency. Capillary electrophoresis was used in this research as a novel contribution to the systematic study of oil displacement tests, and it has proven to be a powerful tool for understanding the mechanisms involved. The results show that the variations in the concentrations detected in the displacement effluents were the product of the interactions between rock, oil, and brine since the concentrations measured in the absence of oil phase were comparable to those in the injection brine. Significant variations in the effluent ion concentrations were determined for the different brines used, and increases in the pressure differentials were observed for the KCl and CaCl2 brines. These results suggest that the oil–brine ion exchange (salting in/out) represents a relevant mechanism to explain the observed displacement efficiencies and differential pressures. The ionic enrichment of the water phase due to the salting in/out effect needs to be better understood.

Analyses of Interpolant Ion Effects on Smart Water Core Flooding in Carbonate

Smart water flooding (SWF) is a promising enhanced oil recovery (EOR) technique due to its economic advantages. For this process, wettability alteration is the most accepted controlling effect that leads to increased recovery factors (RFs). The main objective of this work is to investigate how the relative permeability curves’ interpolant affects the SWF mechanisms’ assessment. Wettability alteration is described by shifting these curves in simulations. Numerical simulations of core flooding tests are applied to carbonate at 114.4 °C. A comparison of oil recovery factor (RF), pH and effluent composition is performed for different injection approaches. Mg2+ and SO42− are the interpolant ions and the salinity levels range from 30 to 1 kppm. A simulation of 24 scenarios, 12 for each type of interpolant, is presented. Results show that RF changes significantly, due to salinity and composition, for each interpolant. This has a relevant influence on the interpolant. The greater the dilution, the smaller the effect of the interpolant and brine composition on the recovery estimates. When considering SO42− as an interpolant, the trend is that divalent rich brine (DV) has a higher recovery factor. In contrast, when Mg2+ is the interpolant, DV tends to have a lower recovery. The analysis of ionic exchange and pH variation corroborate the wettability alteration behavior. A pH increase was observed in all scenarios, regardless of the salinity, ion composition or interpolant variation. Also, monitoring the CH3COO-X reduction and SO4-X2 increase equivalent fractions indicated the ion exchange mechanism as being well represented in all simulations. In addition, the results emphasize that even at very low concentrations, SO42− plays a fundamental role in initiating the ion exchange process that culminates in the wettability alteration as a consequence of smart water injection.

Mechanistic investigation of using optimum saline water in carbonate reservoirs low asphaltenic crude oil with high resin content: A carbonate-coated microfluidic study

Many mature reservoirs around the world have entered the second period of their life and their production rates are going to decline. In addition, after producing from the reservoir at the primary and secondary stages more than 50 percent of hydrocarbons would remain in place. Therefore, it is essential to find a suitable method to increase oil recovery in the tertiary stage. In recent two decades, smart water or low saline water (LSW) flooding has been introduced as a dominant method, especially on wettability alteration from oil-wet to water-wet or neutral wet conditions, which is leading to more oil production. On the contrary, there are an inadequate number of researches on low asphaltenic crude oil with high resin content in water flooding. In this type of crude oil, the role of asphaltene in changing the wettability and reducing the interfacial tension (IFT) is not as great as the other surface active agents of crude oil. Hence, the role of each ion and its synergism with the surface active agents of crude oil may be different from previous studies. The fluid–fluid and rock-fluid interactions between diluted seawater and a low asphaltenic crude oil were investigated by performing different types of experiments, such as pendant drop IFT measurement tests, sessile drop contact angle (CA) measurement experiments, zeta potential analysis, and pH determination. In the next step, the impact of ten different salts on reducing the interfacial tension, and wettability alteration was determined to show the underlying mechanisms of optimum brine based on the same ionic strength (IS). Finally, some microfluidic tests were utilized in a carbonate-coated micromodel to show the confirmation of previous results in porous media visually and determine the fluid–fluid and rock-fluid interactions on the recovery factor (RF). Based on IFT and CA results, the optimum brine was seawater (SW) that could reduce the IFT from 21.13 to 16.21 mN/m and change the CA from 137° to 46° (Δϴ = 91°). Due to the lower asphaltene content in such crude oil, the presence of Na+ with SO42-, and Mg2+ with Cl- plays a significant role in IFT reduction by creating a synergistic effect between these ions with a high fraction of resin. Na2SO4 and MgSO4 reduce the IFT from 21.13 to 6.21 and 8.46 mN/m, respectively due to the existence of the high amount of Mg and SO4 in aqueous solution which has a considerable effect on fluid–fluid interaction. Also, Mg2+ and SO42- can obtain 89° wettability alteration (Δϴ) and provide a water-wet condition (ϴ = 48°) because of the synergistic of the presence of divalent anions and cations through the solution and the presence of high resin content that leads to excellent wettability change. Additionally, Na2SO4 can change the contact angle from 137° to 67° (Δϴ = 70°). Although the greatest impact of single salts on IFT reduction and wettability alteration was obtained by Na2CO3 and NaHCO3 because of saponification and pH elevation; however, the concentration of these salts in SW was negligible. Thus, the main salts for fluid–fluid and rock-fluid interactions in SW/low asphaltenic crude oil/calcite systems were Na2SO4, MgSO4, and MgCl2. Moreover, due to the presence of Na+, Mg2+, and SO42- in SW, the wettability of the pore surface was altered from oil-wet to water-wet during SW flooding in the micromodel. Furthermore, reducing the IFT and changing the wettability lead to decreasing the capillary number and delay in breakthrough (BT) time, which consequently improved the oil recovery from 25.42 % (DIW flooding) to 46.59 %. The findings of this study can help for a better understanding of the effect of low asphaltenic with high resin crude oil and ions on the fluid–fluid and rock-fluid interaction through porous media at static and dynamic conditions in order to increase the final oil recovery.

Experimental Core Flooding Investigation of New ZnO-γAl2O3 Nanocomposites for Enhanced Oil Recovery in Carbonate Reservoirs.

Generally, crude oil production in mature oil reservoirs is difficult. In this regard, some nanoparticles have been used to upgrade injected water into oil reservoirs. These nanoparticles can be used in a variety of injectable waters, including smart water (SMW) with special salinity. This study aims to evaluate the performance of the injection of SMW with ZnO-γAl2O3 nanoparticles in enhanced oil recovery (EOR). The performance of SMW with ZnO-γAl2O3 nanoparticles in regard to contact angle (CA), interfacial tension (IFT) reduction, and oil production with core flooding tests was investigated. The newly prepared ZnO-γAl2O3 structure was characterized by energy dispersive X-ray (EDX), Fourier transform infrared (FT-IR) spectroscopy, transmission electron microscopy (TEM), scanning electron microscopy (SEM), and X-ray diffraction (XRD) analyses in this research. The effects of different concentrations of nanofluids on zeta potential (ZP) and conductivity were investigated. The ZP test confirmed the results of the stability tests of the developed nanofluids in water-based solutions. After the introduction of ZnO-γAl2O3 nanoparticles into the formation of brine and SMW solutions, oil-water (O/W) IFT was reduced. Based on the results, the IFT decreased more when nanoparticles and ions were present in the system. The results of the present study showed that at the concentration of SW+300 ppm ZnO-γAl2O3, the IFT value reached 11 mN/m from 27.24 mN/m. The results of the CA tests showed that improving the capabilities of salt water in the presence of nanoparticles has resulted in a very effective reduction. Also, in this regard, very hydrophilic wettability was achieved using SMW with stable nanoparticles. Moreover, the results of the present study showed that at the concentration of SMW+300 ppm ZnO-γAl2O3 nanoparticles, the CA value reached 31 from 161°. In the end, the solution of SW+300 ppm ZnO-γAl2O3 improved the OR by 15 and 24%. This research indicated that it is possible to develop and implement different nanoparticles by combining SMW to manage reservoir rock wettability and maximize OR from carbonate reservoirs. Thus, this combination as an effective agent could significantly increase reservoir sweep efficiency. Thus, as a result, using the established hybrid technique has distinct advantages over using SMW flooding alone.

Effect of ion concentration of smart water on oil recovery by spontaneous imbibition test

Smart waterflooding has proven successfully improving oil recovery in numbers of laboratory and field scale applications. The phenomena behind the positive outcome is concluded to be wettability alteration. The smart water composition changes the wettability of the rock surface into partially water-wet, thus promoting a spontaneous imbibition of the aqueous phase and displacing the oil. However, there are some mechanisms causing the wettability alteration that have been proposed by researchers. The present study examines the oil recovery from spontaneous imbibition tests by modifying certain ion composition of the smart water. Prepared core samples with initial water and oil saturation were immersed in spontaneous imbibition cells filled with smart water and the oil recovered was monitored for some period of time. The predesigned smart water compositions consist of different ions concentration, i.e., Na+, Ca2+, and Mg2+, while maintaining identical total dissolved solid (TDS). The experimental results found that the ion composition of smart water affects the oil recovery regardless of the TDS, and low Ca2+ and Mg2+ concentrations shows the highest recovery factor.

Synergistic SmartWater based surfactant polymer flooding for enhanced oil recovery in carbonates

SmartWater flooding has been recognized as an efficient and practical technology to synergize with different enhanced oil recovery methods for increasing oil recovery. This article aims to investigate the beneficial synergy effect between the SmartWater and surfactant-polymer (SP) flooding for carbonate reservoirs. Both zeta potential and contact angle measurements revealed that a favorable wettability alteration was induced with SmartWater. Coreflooding experiments were performed using preserved carbonate core samples at reservoir conditions. Results demonstrated that SP flooding combined with SmartWater achieved higher oil recovery with less chemical consumption when compared to conventional SP flooding.

Experimental investigation of smart water injection in dolomite rocks

Water flooding has already been shown to be one of the most cost-effective ways to enhance oil recovery in carbonate reservoirs. The main obstacle of this type of reservoir is the low recovery rate due to the oil-wet rock surfaces and modifying the chemistry of water injection could significantly increase oil production. This article aimed at the optimization of salinity and composition of divalent ions in Smart water flooding in dolomite reservoir rocks. Contact angle measurements performed in two steps to screen and select the optimal composition among several types of waters. Core flooding experiments conducted to evaluate the performance of the chosen waters in two different scenarios; It was carried out in three steps including brine (FW) injection, followed by best water (RW) and finally smart water (RW2S) and the second scenario was applied in reverse. Maximum recovery of 59.65% original oil in place (OOIP) was recorded for the second scenario and a lower recovery of 50.72% OOIP was observed for the first. Experimental results confirms that a higher concentration of sulfate ions enhances the water-wetness of dolomite rocks and two main mechanisms behind the smart water injection are wettability alteration and pH increase.

A systematic study of Smart Water technology in improving the reservoir recovery performance

Smart Water flooding, as an emerged technique in improving reservoir performance, demands systematic research. Determining the effective range of water ionic concentration has erupted the argumentative debates. Along with this, there is still a requirement to identify the in-situ wettability change and optimum water concentration. This research navigates to improve water chemistry knowledge using a systematic scheme of experimental and simulation approaches by the contribution of monovalent (Na+) and divalent (Ca2+) ions. To do this, one-factor-at-a-time (OFAT) and design of experiments (DOE) methods were employed to conduct contact angle and interfacial tension (IFT) measurements. Then, water force displacement tests and reservoir simulations were run to ascertain the in-situ changes and optimum brine concentration considering relative permeability, fractional flow, and ultimate oil recovery curves. In conclusion, two new analytical/empirical models were generated to predict contact angle and IFT based on brine concentration. The effective range of brine concentration was found to be 1000 to 15,000 ppm NaCl and 15,000 to 20,000 ppm CaCl2 in sandstone and 1000 to 10,000 ppm of both brines in carbonate. The IFT results showed the same range of concentration in sandstone, but irregular range in carbonate. In addition, according to water force displacement tests and simulation outcomes, the optimal value of Smart Water flooding was measured to be 8000 ppm NaCl-20,000 ppm CaCl2 brine concentration, resulting in about 4% increase in ultimate oil recovery. This study offers practical findings that advance water flooding technology understanding.

Date-Leaf Carbon Particles for Green Enhanced Oil Recovery.

Green enhanced oil recovery (GEOR) is an environmentally friendly enhanced oil recovery (EOR) process involving the injection of green fluids to improve macroscopic and microscopic sweep efficiencies while boosting tertiary oil production. Carbon nanomaterials such as graphene, carbon nanotube (CNT), and carbon dots have gained interest for their superior ability to increase oil recovery. These particles have been successfully tested in EOR, although they are expensive and do not extend to GEOR. In addition, the application of carbon particles in the GEOR method is not well understood yet, requiring thorough documentation. The goals of this work are to develop carbon nanoparticles from biomass and explore their role in GEOR. The carbon nanoparticles were prepared from date leaves, which are inexpensive biomass, through pyrolysis and ball-milling methods. The synthesized carbon nanomaterials were characterized using the standard process. Three formulations of functionalized and non-functionalized date-leaf carbon nanoparticle (DLCNP) solutions were chosen for core floods based on phase behavior and interfacial tension (IFT) properties to examine their potential for smart water and green chemical flooding. The carboxylated DLCNP was mixed with distilled water in the first formulation to be tested for smart water flood in the sandstone core. After water flooding, this formulation recovered 9% incremental oil of the oil initially in place. In contrast, non-functionalized DLCNP formulated with (the biodegradable) surfactant alkyl polyglycoside and NaCl produced 18% more tertiary oil than the CNT. This work thus provides new green chemical agents and formulations for EOR applications so that oil can be produced more economically and sustainably.

Experimental investigation of synergistic effect of non-ionic surfactant and smart water injection methods for enhanced oil recovery from carbonate reservoirs

In the water-based EOR methods, surfactants and smart water injection methods usually are employed to reduce the water-oil interfacial tension and altered the rock wettability, respectively. The main objective of this study is to employ the combination effects of non-ionic Surfactants (including KEPS 80 and Behamid D) and Smart water Flooding to alter the wettability and interfacial tension (IFT) towards the most favorable conditions. Contact angle, spontaneous imbibition, capillary pressure (P c ), and relative permeability (k r ) experiments were performed at various concentrations of the surfactants and ions using carbonate rock to identify the various mechanisms occurring in the Surfactant and Smart water (SSW) flooding process and also to determine the additional oil recovery. The optimum concentrations of surfactant and positive ions (Mg 2+ , Ca 2+ ) were also obtained. In this regard, concentrations of the employed ions were optimized for altering the carbonate rock surface wettability toward the water-wet. The optimum surfactant concentrations obtained by Mohammadshahi et al. (2019) were also used, in this study. After obtaining the optimum concentrations, some promising aqueous solutions were designed for Amott cell, relative permeability, and capillary pressure experiments using the combination of surfactant and ions. Amott cell tests were implemented for comparing the ability of different aqueous solutions such as base water (Brine with 30,000 ppm NaCl), surfactant solution, smart water, and SSW solution in the oil recovery from the cores. Subsequently, relative permeability and capillary pressure experiments were performed. The results of contact angle experiments depicted that brine containing 24,000 ppm NaCl +6000 ppm Mg 2+ yielded the lowest contact angle among the studied samples. In the spontaneous imbibition tests, the oil recovery was obtained to be 7.6% for the base water, 9.5% for the smart water (24,000 ppm NaCl + 6000 ppm Mg), 15.09% for the surfactant solution (1500 ppm KEPE in 30,000 NaCl), and 20.8% for the SSF water. The relative permeability and capillary pressure tests have demonstrated the change of residual oil saturation and wettability of rock while using the SSW method compared to other techniques (i.e. base water, surfactant injection, smart water flooding). Finally, the results indicated that the combination of smart water and surfactant injection could lead to a much higher recovery factor than each method alone. • The brine with concentrations of 6000 and 2000 ppm of Mg ++ achieved the highest improvement in wettability alteration towards the water wetness. • The kr measurement highlighted that smart water can slightly improve oil relative permeability and the surfactant, was not very successful in improvingkr. • The brine designed with optimum ion and surfactant incredibly improved the kroand highly reduced the krw compared to the cases where each of surfactant and smart water are used separately. • The Pc tests demonstrated that the smart-surfactant water has the most favorable Pc with the least residual oil saturation.