Surfactant Flooding Research Articles

Spontaneous imbibition and core flooding analysis of pH adjusted alkali and surfactant system in high salinity sandstone reservoir

Some of the limitations of a cost-effective alkaline surfactant flooding method include chemical precipitation and other formation damage issue which has greatly affected the application of chemical flooding especially in high salinity reservoirs. This study ascertains the chelating attributes of Ethylene-diamine-tetracetic Acid-(EDTA/NaOH), investigates the ability of EDTA/NaOH and an anionic surfactant to improve oil recovery in heavy oil sandstone formation. Petrophysical analysis of the crude oil and core samples were performed. Hard brine at 5.1% optimal salinity and 0.2 wt.% surfactant imbibition were performed on the sandstone core plug for over 240 hrs. and the volume of oil recovered was determined using Amott imbibition cells. Sandstone core flooding test was thereafter conducted using the alkaline -surfactant solution at optimal salinity. Spontaneous imbibition results showed that surfactant imbibition (26.6%) produced a higher recovery than hard brine recovery (18.7%) after 240hrs. Sandstone core flooding results showed increased heavy oil recovery of 37% OOIP with alkaline-surfactant solution and additional 8% recovery was achieved by performing a final chase brine flooding, totaling 45% indicating that traces of alkaline-surfactant, in the core, aided the final imbibition process. This study underpins and complements several research solutions concerned with flooding in harsh oilfield terrains, thus making the overall process cost-effective and less time- consuming.

Smartwater Synergy with Chemical EOR: Studying the Potential Synergy with Surfactants

Summary The potential synergy between smartwater and various enhanced oil recovery (EOR) processes has recently attracted significant attention. In previous work, we demonstrated such favorable synergy for polymer floods not only from a viscosity standpoint but also in terms of wettability. Recent studies suggest that smartwater synergy might even extend to surfactant floods. In this work, we investigate the potential synergy between smartwater and surfactant flooding. Opposed to previous work, the potential synergy is investigated from ground zero. We concurrently developed two surfactant formulations for conventional high-salinity injection water and low-salinity smartwater. To design the optimal surfactant-polymer (SP) formulations, we followed a systematic all-inclusive laboratory workflow. Oil displacement studies were performed in preserved core samples using the two developed formulations with conventional injection water and smartwater. The results demonstrated the promising potential of binary surfactant mixtures of olefin sulfonate (OS) and alkyl glyceryl ether sulfonate (AGES) for both waters. The designed binary formulations were able to form Winsor Type III emulsions besides achieving ultralow interfacial tensions (IFTs). Most importantly, in terms of oil displacement, the developed SP formulations in both injection water and low-salinity smartwater were capable of recovering more than 60% of the remaining oil post waterflooding. A key novelty of this work is that it investigates the potential synergy between smartwater and surfactant-based processes from the initial step of surfactant formulation design. Through well-designed from-scratch evaluation, we demonstrate that surfactant-based processes exhibit limited synergies with smartwater. Comparable processes in terms of performance can be designed for both high-salinity and low-salinity waters. It is also quite possible that the synergistic benefits of smartwater on oil recovery cannot be effective in SP flooding processes, especially with specific surfactant formulations under optimal salinity conditions.

Using Sodium Dodecyl Sulfate (SDS) and CO2 as Environmentally Friendly Method for Reducing Residual Oil Saturation

Dioxide carbon is essentially blamed to be the main factors causing the climate change effect because it is the most important anthropogenic greenhouse gas. Carbon capture and storage (CCS) technology is widely embraced as one of the leading and easiest Environmentally Friendly ways of mitigating carbon emissions to the atmosphere. By reducing interfacial tension and enhancing oil mobility, surfactant flooding increases oil production by improving the displacement of the oil by water injection. When porous rocks’ wettability is improved with surfactant EOR, more oil is displaced from the water that passes through them more efficiently. One of the major problems with Enhanced Oil Recovery (EOR) operations is surfactant adsorption. The injection of surfactants into the field to reduce interfacial tension, modify wettability, and regulate mobility in order to increase the amount of oil recovered from a previously water-flooded reservoir is one method of enhanced oil recovery (the extraction of previously unattainable petroleum from an oil deposit using non-traditional methods). The loss of surfactant resulting from adsorption on formation rocks is one of the process’ major challenges. In fact, significant surfactant adsorption can cause chemical EOR procedures uneconomical. After studying the phase behavior and the interfacial characteristics of 10 surfactants with oil, sodium dodecyl sulfate (SDS) was chosen as the surfactant. Since sodium dodecyl sulfate had a higher oil recovery rate than the other surfactants, it was chosen among those Furthermore, it can produce stable emulsions at low concentrations without the need of a co-surfactant or an alkaline agent, and it can also do so while maintaining ultra-low interfacial tension (IFT). Carbon dioxide injection is a safe way to reduce its concentration in the atmosphere.

Design of salinity tolerant in alkaline surfactant systems for high salinity reservoirs

Chemical oil recovery from offshore reservoirs which are usually characterised by harsh conditions such as high salinities have remained a source of concern. This study assesses chemical compatibilities of alkalis –surfactant systems under high salinity and divalent ions (Ca2+ and Mg2+). It analysed the synergy between alkali-surfactant slugs and crude oil, leading to the design of an optimal low-cost alkaline- surfactant flooding. Three alkali systems: sodium hydroxide, sodium metaborate and ethylene-diamine-tetracetic acid-(EDTA/NaOH) were evaluated with two high salinity synthetic brines; one without divalent ions (soft brine) and the other containing divalent ions (hard brine). Compatibility of these alkali systems with the commercial-grade surfactant was evaluated based on fluid-fluid interaction. Phase behaviour experiments were conducted to determine the alkali–surfactant compatibility with brine. Solutions free of precipitation were used for the interfacial-tension (IFT) and phase separation analysis, obtained level readings were used to calculate optimal salinity. Results showed that all alkali systems were compatible with soft brine, while compatibility with hard brine was highly controlled by the pH. Alkali-crude oil failed to produce Type III micro-emulsion; however, the addition of surfactant achieved an ultra-low IFT. EDTA/NaOH effectively sequestered the divalent ions like sodium metaborate hence increasing the solubilisation of surfactant at higher salinity. Comparison of both alkalis with commercial surfactant, alcohol alkoxy sulphate at controlled pH exhibited a higher optimum salinity for EDTA/NaOH than for sodium metaborate. This study shows that at pH ≥ 11 and an increased salinity above optimal salinity, chemical precipitation occurs resulting in reduced oil recovery.

Developing methodology and experimental procedure эfor experimental microfluidic study of chemical enhanced oil recovery

The concern of this research was to review the different methodology on microfluidic experiments conducted to study chemical enhanced oil recovery methods on micromodel chips. In general, there are several ways to study EOR methods such core flooding and microfluidics. The disadvantage of first method is that the flow processes inside the core sample cannot be imagined. Hence, the second method helps us to fully visualize how fluid flow behaviour occurs though the porous medium of the rocks. The various chemical EOR processes such as surfactant flooding, polymer flooding and ASP flooding were studied on microfluidic chips. These chemicals were injected into micromodels to drive out crude oil. It helps to understand the interactions between crude oil and chemicals, the advancement of front developed between displacing and displaced fluids and the viscous fingering effect. Visual studies enabled us to understand the effectiveness of polymer, surfactant and alkaline separately and as combined. The different experimental methodologies to study the EOR methods are reviewed. Mainly experiments divided into two main groups: methods of geological characterisations influence to fluid transport while others study oil displacement at different condition, such high temperature, high pressure, low or high salinity, highly viscous oil. We reviewed methodologies applied to study an oil displacement by polymer, surfactant-polymer (SP) and alkaline surfactant polymer (ASP) solutions, their interactions and transport in porous media. Based on reviewed article the experimental procedure was developed. Analyses of published materials have helped to design and direct the methodology of research.

Molecular insight into the effect of the number of introduced ethoxy groups on the calcium resistance of anionic-nonionic surfactants at the oil/water interface

The salinity seriously affects the recovery efficiency of surfactant flooding, and it is demonstrated the introduced ethoxy (EO) groups can enhance the interfacial activity of surfactants at harsh salinity via various experimental methods. In this study, sodium dodecyl sulfate (SDS) and sodium dodecyl ether sulfate (AES) are selected to investigate the effects of EO group number on the salt resistance of surfactants at the air/water interface by experiments and molecular dynamics (MD) simulation method. Optical microscopy and static multiple light scattering results show that the AES stabilized emulsions with Ca2+ ions have better stability than those of SDS, which is further explored by molecular MD simulation method. The interface formation energy (IFE) and self-diffusion coefficients (Dα) are calculated to systematically study the effects of introduced EO group number on calcium resistance of surfactants. The interaction between surfactants and Ca2+ ions at the oil/water interface is evaluated by the potential of mean of force (PMF) and the radial direction functions (RDF), which is confirmed by the calculation of molecular electrostatic potential (MEP) and coordination number. The simulation results indicate that the introduced EO groups can combine Ca2+ ions to fabricate salt bridge via intermolecular or intramolecular interactions to highly improve the calcium resistance of surfactants. The present work proposes a microcosmic perspective of the roles of EO group number on the calcium resistance of AES at the oil/water interface.

The role of adsorption of a natural surfactant at oil–water interface in enhanced oil recovery: interfacial rheology, and structural, and emulsifying analyses

The enhanced oil recovery (EOR) method is widely used for recovering residual crude oil after implementing conventional oil recovery techniques. Chemical additives, such as surfactants, are considered beneficial for EOR. Their efficacy is assessed based on their ability to reduce interfacial tension, modify wettability, and establish a stable emulsion system. Understanding the mechanism of surfactant adsorption at the oil–water interface is critical for effectively implementing surfactant flooding. In this work, we have studied the adsorption of a natural surfactant synthesized from Eichhornia crassipes at the oil–water interface using numerous interfacial analyses. The results show substantial adsorption at the oil–water interface, indicated by a 27% increase in zeta potential (i.e. −25.2 to −37.2 mV) and ∼27 times increase in film elasticity (i.e. 0.15–4.12 Pa at 0.01 Hz frequency and 0.01% strain). The synthesized natural surfactant demonstrates a noteworthy improvement in the stability of the oil-in-water emulsion and interfacial rheological properties, indicating its potential application in EOR.

Influence of Henna Extracts on Static and Dynamic Adsorption of Sodium Dodecyl Sulfate and Residual Oil Recovery from Quartz Sand.

The application of surfactant flooding for enhanced oil recovery (EOR) promotes hydrocarbon recovery through reduction of oil-water interfacial tension and alteration of oil-wet rock wettability into the water-wet state. Unfortunately, surfactant depletion in porous media, due to surfactant molecule adsorption and retention, adversely affects oil recovery, thus increasing the cost of the surfactant flooding process. Chemical-based materials are normally used as inhibitors or sacrificial agents to minimize surfactant adsorption, but they are quite expensive and not environmentally friendly. Plant-based materials (henna extracts) are far more sustainable because they are obtained from natural sources. However, there is limited research on the application of henna extracts as inhibitors to reduce dynamic adsorption of the surfactant in porous media and improve oil recovery from such media. Thus, henna extracts were introduced as an eco-friendly and low-cost sacrificial agent for minimizing the static and dynamic adsorption of sodium dodecyl sulfate (SDS) onto quartz sand in this study. Results showed that the extent of surfactant adsorption was inversely proportional to the henna extract concentration, and the adsorption of the henna extract onto the quartz surface was a multilayer adsorption that followed the Freundlich isotherm model. Precisely, the henna extract adsorption on quartz sand is in the range of 3.12-4.48 mg/g (for static adsorption) and 5.49-6.73 mg/g (for dynamic adsorption), whereas the SDS adsorption on quartz sand was obtained as 2.11 and 4.79 mg/g at static and dynamic conditions, respectively. In the presence of 8000 mg/L henna extract, SDS static and dynamic adsorption was significantly reduced by 64 and 82%, respectively. At the same conditions, the residual oil recovery increased by 9.2% over normal surfactant flooding. The study suggests that the use of henna extracts as a sacrificial agent during SDS flooding could result in the reduction of static and dynamic adsorption of surfactant molecules on quartz sand, thus promoting hydrocarbon recovery from sandstone formations.

Adsorption reduction of a gemini surfactant on carbonate rocks using formic acid: Static and dynamic conditions

Surfactant flooding improves oil recovery by lowering the interfacial tension and/or altering the reservoir rock’s wettability. However, surfactant losses caused by adsorption on the surface of the rock weaken the efficiency of this chemical enhanced oil recovery process. This study focuses on reducing the adsorption of a cationic gemini surfactant on carbonate rocks using formic acid. High-performance liquid chromatography integrated with an evaporative light scattering detector was employed to quantify both static and dynamic surfactant adsorptions. The results showed that the surfactant’s adsorption on carbonate rocks was reduced dramatically by adding 1% formic acid to the surfactant solution. Static adsorption was reduced from 2.44, 1.62, and 1.51 mg/g-rock to 0.16, 0.14, and 0.13 mg/g-rock on Guelph dolomite, Guff dolomite, and Indiana limestone, respectively. The dynamic adsorption of the surfactant on Indiana limestone was reduced from 0.269 to 0.041 mg/g-rock. It is believed that the carboxyl group released by the formic acid-rock reaction shields the surfactant from the rock surface resulting in lower adsorption. This is evidenced by the surfactant solution’s pH dropping below the point of zero charge of the rock, causing the repulsion of the cationic surfactant molecules off the surface. This study provides a low-cost option that provides a remarkable reduction in cationic surfactant adsorption on carbonate rocks.

Molecular dynamics simulation study on interfacial behaviors of betaines and extended surfactants

The mixed system between different surfactants has characteristic and synergy to reduce the oil/water interfacial tension (IFT). As the reservoir conditions become more and more severe, it is necessary to explore new surfactants suitable for complex geological environments. In this work, we designed the mixed systems between betaine and extended surfactants, and studied the interfacial properties at the decane/water interface by molecular dynamics (MD) simulations and interfacial tension measurements. The effects of betaine structure and oxypropylene (PO) chain length of extended surfactant on the interfacial behaviors were analyzed in detail from the density profile, tilt angle, average rising height of PO unit and radial distribution function. The results showed that the polar part of betaine extended into the water phase and the hydrophobic chain was more upright in the mixed system due to the electrostatic interaction. For the mixed system, the rise height change of the PO unit indicated that the interfacial behavior of short PO chain was controlled by betaine structure, while that of long PO chain was independent of betaine structure because of the poor deformation ability of it. IFT experiments showed that xylyl substituted alkyl sulfobetaine (XSB) mixing with the short PO chain extended surfactant system had a significant synergistic effect to produce ultra-low IFT but had a negative effect with the long PO chain extended surfactant. This work demonstrated that the steric hindrance of betaine and the PO chain length of extended surfactant synergistically affected the interfacial arrangement and IFT of surfactants, which was of significance for improving and designing more effective surfactant flooding systems to enhance oil recovery.

Wettability Alteration with Weak Acid-Assisted Surfactant Flood

Summary Oil-wetness and heterogeneity are two key reasons for low oil recovery by waterflooding in carbonate reservoirs. Surfactants have been effective in altering the oil-wet matrix to a more water-wet condition and initiating spontaneous imbibition. Because it takes time for the surfactant to alter wettability, oil recovery from the tight matrix is slow and sometimes not economically feasible. Acids have the potential of dissolving minerals, which may alter wettability. In this study, the enhanced oil recovery (EOR) performance of an acid-assisted surfactant solution, a novel technique, was evaluated for low-temperature applications. A set of acids and their acetates were tested. Bulk rock-acid reaction, wettability alteration (WA) tests, and spontaneous imbibition measurements were conducted at reservoir temperature (35°C) to identify effective candidates. Coreflood tests were then performed to evaluate the selected acid-surfactant formulations. Before and after a coreflood test, the core was scanned using micro-computed tomography (CT) to investigate pore structure alteration. Bulk reaction measurements showed that weak acids, especially acetic acid (AA), have the desired low reaction rates at 35°C. WA tests showed that AA can remove the crude oil off the rock surface and alter wettability through mineral dissolution. The surfactant can reduce contact angles from 160° to 58°; adding acid into the surfactant can further reduce it to 52°. Spontaneous imbibition experiments showed the synergy between the acid and the surfactant; the AA-surfactant solution had the highest oil recovery (62.6%) among acid-surfactant formulations. The acid improves the WA efficiency by the surfactant through surface mineral dissolution and lower ζ-potential. The imbibition transports the acid-surfactant solutions into the matrix, which minimizes face dissolution. Coreflood tests show that the AA-surfactant flood can increase the oil recovery rate and recover about 8% more oil compared to the surfactant flood. Micro-CT showed that a few mineral particles were transported along the core and partially plugged pore throats, which reduced permeability and diverted flow leading to improved oil recovery. The transport of the acid in reservoirs and the potential plugging issues have to be carefully evaluated in future studies.

Experimental investigation of hydrophobic and hydrophilic silica nanoparticles on extended surfactant properties: Micro-emulsion, viscosity, and adsorption behaviors

The novel applications of nanoparticles and surfactants are of interest for improving chemical oil recovery performance. In this study, two types of hydrophobic and hydrophilic SiO2 nanoparticles (NPs) were used in conjunction with a binary surfactant system (extended Carboxylate and Dioctyl sulfosuccinate (AOT) surfactants at the ratio of 0.6:0.4 by volume). An extensive series of experiments were performed in the presence of API brine containing NaCl: CaCl2 at the 8:2 wt ratio to study microemulsion phase behavior, interfacial tension (IFT), surfactant adsorption onto NP surfaces, solution and microemulsion viscosity, and oil recovery. The results indicate that the microemulsion phase behavior, optimum salinity (S*), and IFT were influenced by the concentrations and surface characteristics of the NPs. Hydrophobic or hydrophilic NPs at 500 ppm in the binary surfactant system could form Type III microemulsion and decrease the S* from 2 to 1.75 wt%. When the NP concentration reached 1000 ppm, the S* reduced to 1.5 wt%. The IFT value of the neat binary surfactant system at the S* was obtained in an ultralow range (0.0013 mN/m), and the IFT value of the hydrophobic NPs exhibited a more significant reduction than the hydrophilic NP systems. The adsorption result demonstrates that Carboxylate surfactant had lower adsorption onto hydrophilic NP than AOT. COSMO σ-profile and screened charge density illustrated that the low coverage of Carboxylate surfactant was from hydrogen bonding interaction, making the surfactant lie flat on the surface. The viscosity of the NP-surfactant solution was affected by the capacity of the surfactant adsorption onto the NP surface. In this regard, adding the hydrophobic NPs at 1000 ppm provided the highest solution viscosity over the entire shear rate and temperature range. The viscosity of the microemulsion formulated by hydrophobic NPs was higher than that of the microemulsion formulated by the hydrophilic NPs. The system with the lower NP concentration had higher microemulsion viscosity than the system with the higher NP concentration. The oil recovery results indicate that the appropriate NP type and concentration in the surfactant system could increase the displacing viscosity and decrease the microemulsion viscosity compared with the neat surfactant flooding system. The success in improving oil recovery was achieved with recovery efficiency of 88% original oil in place (OOIP).

Spontaneous Imbibition and Core Flooding Experiments of Enhanced Oil Recovery in Tight Reservoirs with Surfactants

Despite the implementation of hydraulic fracturing technologies, the oil recovery in tight oil reservoirs is still poor. In this study, cationic, anionic, and nonionic surfactants of various sorts were investigated to improve oil recovery in tight carbonate cores from the Middle Bakken Formation in the Williston Basin. Petrophysical investigations were performed on the samples prior to the imbibition and core-flooding experiments. The composition of the minerals was examined using the XRD technique. To investigate the pore-size distribution and microstructures, nitrogen adsorption and SEM techniques were applied. The next step involved brine and surfactant imbibition for six Bakken cores and two Berea sandstone cores. The core samples were completely saturated with Bakken crude oil prior to the experiments. The core plugs were then submerged into the brine and surfactant solutions. The volume of recovered oil was measured using imbibition cells as part of experiments involving brine and surfactant ingestion into oil-filled cores. According to the findings, oil recovery from brine imbibition ranges from 4.3% to 15%, whereas oil recovery from surfactant imbibition can range from 9% to 28%. According to the findings, core samples with more clay and larger pore diameters produce higher levels of oil recovery. Additionally, two tight Bakken core samples were used in core-flooding tests. Brine and a separate surfactant solution were the injected fluids. The primary oil recovery from brine flooding on core samples is between 23% and 25%, according to the results. The maximum oil recovery by second-stage surfactant flooding is approximately 33% and 35%. The anionic surfactants appear to yield a better oil recovery in tight Bakken rocks, possibly due to their higher carbonate mineral concentrations, especially clays, according to both the core-scale imbibition and flooding experiments. For studied samples with larger pore sizes, the oil recovery is higher. The knowledge of the impacts of mineral composition, pore size, and surfactant types on oil recovery in tight carbonate rocks is improved by this study.

Pore-Scale Investigation of Low-Salinity Nanofluids on Wetting Properties of Oil Carbonate Reservoir Rocks Studied by X-ray Micro-Tomography

Low-salinity surfactant nanofluids have recently shown promising results in the wettability alteration of reservoir rocks from oil-wet state towards more water-wet state. However, the investigation of pore-level interactions of nanofluids injection in real oil carbonate rocks at reservoir conditions, which determines the overall fluid dynamics, is lacking. Therefore, in this work, we studied the effect of nanoparticles augmented low-salinity surfactant flooding on the wettability alteration of hydrophobic carbonate rocks with harsh reservoir conditions via X-ray micro-tomography. The designed experiment scheme involved core flooding with an X-ray transparent core-holder developed for studying the flow properties of fluids at the micro level (pore scale). The wettability was quantified by measuring the differences in contact angles after the injection of low salinity, low-salinity surfactant, and low-salinity surfactant nanofluid. The findings illustrate that surfactant flooding with silica nanoparticles had a more pronounced influence on the contact angle among other injected fluids. The contact angle of the rock fell from 144° to 49°, corresponding to the water-wet conditions of carbonate rocks. The results show that the addition of a low concentration (0.005 wt.%) of SiO2 nanoparticles was enough for wettability changes in oil carbonate rocks. This study illustrates that a combination of surfactant, low-salinity, and nanoparticle features has a more pronounced effect on the three-phase contact angle than if applied separately.

Experimental Study on Switchable Acetamidine Surfactant Flooding in Sandstone Using NMR

As a promising chemical-enhanced oil recovery method (CEOR), switchable acetamidine surfactant flooding is investigated in sandstone oil reservoirs. To describe the distributions of the injected water during the surfactant flooding, long-time and multifrequency NMR scanning was employed in combination with core displacement experiments. We found that the water saturation increased and swept volume was improved with the injection rates increasing from 0.01 to 0.5 mL/min in all pores. During water flooding, the water injection rate and distribution had a positive correlation. The water saturation increased as the surfactant concentration increased, and the water saturation and the swept volume of surfactant flooding were larger than those of the water flooding. Furthermore, the water saturation increase in migration pore (MP) was much larger than that in other pores during the switchable acetamidine surfactant flooding. As a result, the water saturation increased and the oil recovery enhanced. Our research results provided novel perspectives on switchable acetamidine surfactant flooding for enhanced oil recovery (EOR).

Effect of nanoparticles and nanosheets on improving the oil/water interface performance of surfactants in enhancing oil recovery: A comparative study by molecular simulation

In recent years, nanoparticles have become the most potential enhanced oil recovery technology because of their unique small size effect and specific surface area effect. With the research and application of graphene and its derivative materials, nanosheets are one of the research hotspots of nanomaterials for enhanced surfactant flooding. However, as far as we know, the molecular simulation comparison of nanoparticles and nanosheets to enhance the performance of surfactants has not been reported so far. Therefore, in this paper, we constructed nano-SiO2 particles grafted with hydroxyl and pentyl alkane activator, graphene nanosheets grafted with carboxylic acid chain and pentyl alkane activator for the first time. On this basis, the interfacial tension, interfacial density, interfacial generation energy and radial distribution function were analyzed by molecular dynamics simulation. The results show that nanoparticles and nanosheets have synergistic effect with amphoteric surfactant dodecyl dimethyl aminoethyl lactone (BS-12). The synergistic effect of nanosheets and BS-12 was stronger after carboxylic acid chain and pentyl alkane activator are grafted on the surface of nanosheets. The interfacial tension of n-dodecane/water could be reduced to 13.58 mN/m after the modified nanosheets are compounded with BS-12. The interfacial tension of n-dodecane/water could be reduced to 4.15 mN/m by the modified nanosheets are compounded with BS-12, and the ability of reducing the interfacial tension between oil and water is significantly improved. The calculation of n-dodecane/water interface thickness and interface formation energy showed that compared with the modified nanoparticles and BS-12 compound system, the interface thickness of the modified nanosheets and BS-12 compound system increased by 9.24%, and the interface formation energy increased by 17.85%. In addition, the results of radial distribution function analysis also demonstrated that the modified nanosheets had strong hydration with water molecules after being compounded with BS-12. The results of this work can provide new ideas for further research on the synergistic effect of surfactants and nanomaterials, as well as the development of oil displacement technology based on surfactants/nanomaterials.

Microscopic experiment study on mechanisms of oil-gas interaction and CO2 -surfactant flooding with different temperatures and pressures

For secondary and tertiary oil recovery processes, the interfacial interactions between injected gas and crude oil contributes significantly at the pore-scale. We experimentally examine the effect of temperatures, pressures and surfactants on interfacial interaction, contact angle and oil displacement efficiency of CO2 flooding at the pore-scale using microfluidics. Two types of flow channel designs are utilized in this study, blind end of direct channels and curved channels with different diameters. The results indicate that increasing pressure and adding surfactants can promote the contact between oil and gas and reduce the interfacial tension, which has a certain impact on oil displacement efficiency. In the process of gas flooding, CO2 dissolution, expansion and miscibility are the key oil-gas interactions. The results of experiments in curved and direct channels show that the curved channels increase the resistance of fluid flow and limit the contact between CO2 and oil. And with the decrease of the porous medium radius, the capillary action in the pores increases, and the higher the viscous force needed for displacing the oil, which will affect the interaction between oil and gas and the oil recovery in micro pores. Then, two non-ionic alkoxylated surfactants (i.e. ethylene glycol butyl ether and Span 80) were selected to enhance the interaction between CO2 and crude oil. The presence of surfactants increases the solubility of CO2 in crude oil, which reduces the interfacial tension of the system and results in higher oil recovery.

Pilot test of polymer microsphere alternate surfactant flood (PMAS) with mixtures of anionic-cationic surfactants under harsh conditions in a sandstone reservoir

The first pilot test of polyacrylamide microsphere alternate surfactant flood (PMAS) with mixtures of anionic-cationic surfactants (Sa/c) was carried out for a high-temperature, high-salinity, and high-hardness sandstone reservoir to demonstrate the potential of this novel technique to improve oil recovery. A critical micelle concentration (CMC) of 4.82 mg/L, an ultralow interfacial tension (IFT) of 8 × 10−4 mN/m, and a high oil solubilization of 22 were obtained. Static and dynamic adsorptions of Sa/c on natural core containing 15 wt% clay were reduced to about 2.20 and 0.30 mg/g-core, respectively, with the addition of adsorption inhibitor (AI). Since June 2014, the pilot test of PMAS was carried out in a Sinopec reservoir with a temperature of 87 °C, a salinity of 260,393 mg/L, and a hardness of 6,401 mg/L. Twelve cycles of alternative injection of 0.0125 PV Sa/c with a concentration of 0.1% and 0.0125 PV polyacrylamide microsphere with a concentration of 0.2% were conducted at an injection rate of 0.1 PV/yr, for a total of 0.3 PV chemical injection. As a result, the net daily oil production increased from 0 t to 6.5 t, and the water cut decreased from 96.3% to 93.8%, leading to an ultimate improved oil recovery of 6.3% original oil-in-place.

Remediation of Pool Dominated Trichloroethene Source Zones in Heterogeneous Porous Media by Cosmetic Surfactant Flooding

<p>A series of flow-cell experiments were performed to investigate the performance of cosmetic rhamnolipid surfactant flooding on the relationship between source zone mass removal and mass flux reduction for pool-dominated DNAPL TCE source zones in heterogeneous porous media. The results were also compared to those of water-flood control experiments to assess the surfactant enhanced flushing efficacy. The flooding experiments were performed for silica sand and natural calcareous soil representing two different degrees of physical heterogeneity. The result from the flow-cell experiments showed that higher than 97% of TCE mass was removed during rhamnolipid flooding for both porous media scenarios. Although, rhamnolipid flooding experiment results showed successful remediation performance, DNAPL TCE dissolution and rhamnolipid-enhanced dissolution in heterogeneous porous media system exhibited multi-step mass-flux reduction/mass-removal behavior due to the presence of less hydraulically-accessible pool-dominated TCE source zone. However, mass removal and mass-flux reduction relationships for rhamnolipid flushing cases exhibited more ideal removal behavior, indicating the more efficient remediation performance compared to water flooding alone. For all cases, the later stage of mass removal was controlled by the more poorly-accessible mass associated with pool-dominated source zones. The results of this study revealed the impact of non-uniformity of the flow-field and effect of enhanced-solubilization agent on mass removal and mass-flux reduction behavior for DNAPL source zones in saturated porous media</p>

Investigating Effects of Chelating Agents on Viscoelastic Surfactant Flooding at the Pore Scale Using Micromodels

Viscoelastic surfactants (VES) have proven their suitability for enhanced oil recovery (EOR) because they increase the viscosity and decrease the interfacial tension (IFT). In this work, we are proposing chelating agents to suppress the effect of salinity and maintain the required value to build the viscosity to optimize the amount of VES needed for a successful EOR job. Two different VES concentrations were investigated, 0.5 and 1.25 wt %. The chelating agents were diethylenetriaminepentaacetic acid (DTPA) and glutamic acid diacetic acid (GLDA), with different chelating agent concentrations ranging from 2 to 8% for each VES concentration. Rheology results showed that, for DTPA, the highest viscosity at the working shear rate of 1 s–1 is 717 cP achieved by 6% DTPA with 1.25% VES. While for GLDA, the highest viscosity at the working shear rate is 738 cP achieved by 8% GLDA with 1.25% VES. On the other hand, the IFT results for GLDA showed the lowest value of 0.0022 mN/m at 4% GLDA with 1.25% VES, and for DTPA, the lowest value was 0.0068 mN/m at 8% DTPA with 1.25% VES. The microfluidic recovery test was done for the selected best performance in IFT and rheology for each chelating agent with the pure VES. The ultimate recovery from 4% GLDA with 1.25% VES is 56% out of the original oil in place, while 43% using 8% DTPA with 1.25% VES. The pure VES at 1.25% gave 48% ultimate recovery. The chelating agent proved to be successful in suppressing the effect of salinity in reducing the IFT. Therefore, normal seawater without sweetening can be used with VES and GLDA and achieve promising recovery.