An overview of chemical enhanced oil recovery: recent advances and prospects

Effect of ethylene oxide groups on calcite wettability reversal by nonionic surfactants: An experimental and molecular dynamics simulation investigation

HYPOTHESIS

Ethoxylated nonionic surfactants are promising candidates for enhanced oil recovery (EOR) from oil-wet carbonate reservoirs due to their ability to reverse the mineral wettability. The wettability-reversal efficiency increases with the number of the ethoxy (EO) groups in the surfactant molecule.

METHODOLOGY

Contact angle measurements, scanning electron microscopy (SEM) and molecular dynamics (MD) simulations were combined to investigate the wettability reversal of an oil-wet calcite by three ethoxylated nonionic surfactants with 1, 4 and 8 EO groups, respectively, to directly probe the role of the EO groups and to uncover the molecular mechanism responsible for the wettability reversal.

FINDINGS

Both experiments and simulations consistently show a clear correlation between the number of EO groups and the wettability reversal efficiency of the surfactants, whereby the higher number of EO groups results in greater degree of wettability reversal. This is due to 1) the more hydrophilic surfactant headgroup weakening the carboxylate interactions with the surface by expanding the surface-adjacent water layer, and 2) the physically larger surfactant molecule attracting the carboxylates more strongly, thus aiding in their removal from the surface.

Advancements in Surfactant Carriers for Enhanced Oil Recovery: Mechanisms, Challenges, and Opportunities

Enhanced oil recovery (EOR) techniques are crucial for maximizing the extraction of residual oil from mature reservoirs. This review explores the latest advancements in surfactant carriers for EOR, focusing on their mechanisms, challenges, and opportunities. We delve into the role of inorganic nanoparticles, carbon materials, polymers and polymeric surfactants, and supramolecular systems, highlighting their interactions with reservoir rocks and their potential to improve oil recovery rates. The discussion includes the formulation and behavior of nanofluids, the impact of surfactant adsorption on different rock types, and innovative approaches using environmentally friendly materials. Notably, the use of metal oxide nanoparticles, carbon nanotubes, graphene derivatives, and polymeric surfacants and the development of supramolecular complexes for managing surfacant delivery are examined. We address the need for further research to optimize these technologies and overcome current limitations, emphasizing the importance of sustainable and economically viable EOR methods. This review aims to provide a comprehensive understanding of the emerging trends and future directions in surfactant carriers for EOR.

Preparation and Performance Evaluation of Self-Cementing Nanoscale Polymeric Microspheres with Salt and Temperature Tolerance

Polymer microspheres with temperature and salt resistance were synthesized using the anti-suspension polymerization method, incorporating the functional monomers AMPS, AM, and AA. To enhance their self-gelling properties, the microspheres were designed with a core-shell structure. The shell is composed of a polymeric surfactant, fatty alcohol polyoxyethylene ether methacrylate (AEOMA), which serves as a thermosensitive crosslinking agent, enabling self-crosslinking upon shell decomposition, addressing compatibility with reservoir pore throat dimensions. Comprehensive characterizations including infrared spectroscopy, scanning electron microscopy, optical microscopy, and laser particle size analysis were conducted. The microspheres exhibited successful synthesis, a nanoscale size, and regular spherical morphology. They demonstrated excellent temperature and salt resistance, making them suitable for high-temperature, high-salinity reservoir profile control. With a stable three-dimensional network structure, the microspheres displayed good expansion behavior due to hydrophilic groups along the polymer chains, resulting in favorable water affinity. Even after aging, the microspheres maintained their gelling state with a distinct and stable microscopic network skeleton. They exhibited superior plugging performance in low-permeability reservoirs, while effectively improving water absorption profiles in reservoirs with permeability contrasts of 10 to 80, thereby enhancing oil recovery.

Break oily water emulsion during petroleum enhancing production processes using green approach for the synthesis of SnCuO@FeO nanocomposite from microorganisms

The aim of this work was to synthesize a green nanoparticle SnCuO@FeO nanocomposite core-shell to break oily water emulsions during petroleum-enhancing production processes as an alternative to chemical and physical processes. In this study, eight bacterial isolates (MHB1-MHB8) have been isolated from tree leaves, giant reeds, and soil samples. The investigation involved testing bacterial isolates for their ability to make FeO nanoparticles and choosing the best producers. The selected isolate (MHB5) was identified by amplification and sequencing of the 16S rRNA gene as Bacillus paramycoides strain OQ878685. MHB5 produced the FeO nanoparticles with the smallest particle size (78.7 nm) using DLS. XRD, FTIR, and TEM were used to characterize the biosynthesized nanoparticles. The jar experiment used SnCuO@FeO with different ratios of Sn to CuO (1:1, 2:1, and 3:1) to study the effect of oil concentration, retention time, and temperature. The most effective performance was observed with a 1:1 ratio of Sn to CuO, achieving an 85% separation efficiency at a concentration of 5 mg/L, for a duration of 5 min, and at a temperature of 373 K. Analysis using kinetic models indicates that the adsorption process can be accurately described by both the pseudo-first-order and pseudo-second-order models. This suggests that the adsorption mechanism likely involves a combination of film diffusion and intraparticle diffusion. Regarding the adsorption isotherm, the Langmuir model provides a strong fit for the data, while the D-R model indicates that physical interactions primarily govern the adsorption mechanism. Thermodynamic analysis reveals a ∆H value of 18.62 kJ/mol, indicating an exothermic adsorption process. This suggests that the adsorption is a favorable process, as energy is released during the process. Finally, the synthesized green SnCuO@FeO nanocomposite has potential for use in advanced applications in the oil and gas industry to help the industry meet regulatory compliance, lower operation costs, reduce environmental impact, and enhance production efficiency.

Unraveling the Impact of Ethylenediaminetetraacetic Acid Chelating Agents on the Oil Recovery Processes: An Insight into Its Role in Fluid-Fluid and Rock-Fluid Interactions

In recent years, chelating agents have garnered increasing attention due to their unique capabilities in addressing challenges associated with chemically enhanced oil recovery materials. Most previous studies have primarily focused on examining the influence of chelating agents on rock-fluid interactions. However, their effects on fluid-fluid interactions, specifically on interfacial tension (IFT) characteristics under various conditions, remain relatively unknown. This study investigates the effect of crucial reservoir parameters on the performance of ethylenediaminetetraacetic acid (EDTA) chelating agents in the IFT between crude oil and brine. Furthermore, the study evaluated the impact of varying concentrations of this agent on rock wettability alteration, zeta potential, and spontaneous imbibition. The results illustrated that introducing EDTA at high concentration into seawater (SW) solution reduced the IFT by 85%. Additionally, while higher pH levels contributed to IFT reduction due to increased hydroxyl ions, excessive salinity levels resulted in elevated IFT. Raising the temperature from 30 to 75 °C further decreased the IFT, changing the IFT for optimal EDTA concentration from 20.43 to 2.56 mN/m (∼88% reduction). The changes in zeta potential and contact angle measurements indicated that solutions of 5 and 7 wt % EDTA shifted rock wettability from oil-wet to strongly water-wet, resulting in the wettability alteration index of 1.01 and 1.02, respectively. Inductively coupled plasma analysis, on the other hand, revealed substantial chelation of metal ions from both the solution and rock when EDTA was added to the rock/SW system. This resulted in a significant increase in Ca2+ ions and a decrease in Mg2+ ions, attributed to the multi-ion exchange phenomenon.

Liquid-liquid surfactant partitioning drives dewetting of oil from hydrophobic surfaces

HYPOTHESIS

Sessile droplets solubilizing in surfactant solution are frequently encountered in practice, but the factors governing their non-equilibrium dynamics are not well understood. Here, we investigate mechanisms by which solubilizing, sessile oil droplets in aqueous surfactant solution dewet from hydrophobic substrates and spread on hydrophilic substrates.

EXPERIMENTS

We quantify the dependence of droplet contact line dynamics on drop size and oil, surfactant, and substrate chemistries. We consider halogenated alkane oils as well as aromatic oils and focus on common nonionic nonylphenol ethoxylate surfactants. We correlate these results with measurements of the interfacial tensions.

FINDINGS

Counter-intuitively, under a range of conditions, we observe complete dewetting of oil from hydrophobic substrates but spreading on hydrophilic substrates. The timescales needed to reach a steady-state contact angle vary widely, with some droplets examined taking over a day. We find that surfactant surface adsorption governs the contact angle on shorter timescales, while partitioning of surfactant from water to oil, and oil solubilization into the water, act on longer timescales to facilitate the complete dewetting. Understanding of the role played by surfactant and oil transport presents opportunities for tailoring sessile droplet behaviors and controlling droplet dynamics under conditions that would previously not have been considered.

Molecular dynamics simulation of surfactant reducing MMP between CH4 and n-decane

Reinjecting produced methane offers cost-efficiency and environmental benefits for enhances oil recovery. High minimum miscibility pressure (MMP) in methane-oil systems poses a challenge. To overcome this, researchers are increasingly focusing on using surfactants to reduce MMP, thus enhancing the effectiveness of methane injections for oil recovery. This study investigated the impact of pressure and temperature on the equilibrium interfacial tension of the CH4+n-decane system using molecular dynamics simulations and the vanishing interfacial tension technique. The primary goal was to assess the potential of surfactants in lowering MMP. Among four tested surfactants, ME-6 exhibited the most promise by reducing MMP by 14.10% at 373 K. Key findings include that the addition of ME-6 enriching CH4 at the interface, enhancing its solubility in n-decane, improving n-decane diffusion capacity, CH4 weakens n-decane interactions and strengthens its own interaction with n-decane. As the difference in interactions of n-decane with ME-6's ends decreases, the system trends towards a mixed phase. This research sets the stage for broader applications of mixed-phase methane injection in reservoirs, with the potential for reduced gas flaring and environmental benefits.

Effects of Core Size and Surfactant Choice on Fluid Saturation Development in Surfactant/Polymer Corefloods

Surfactant/polymer flooding allows for a significant increase in oil recovered at both laboratory and field scales. Limitations in application at the reservoir scale are, however, present and can be associated with both the complexity of the underlying displacement process and the time-intensive nature of the up-scaling workflow. Pivotal to this workflow are corefloods which serve to both validate the extent of oil recovery and extract modeling parameters used in upscaling. To enhance the understanding of the evolution of the saturation distribution within the rock sample, we present the utilization of X-ray computed tomography to image six distinct surfactant/polymer corefloods. In doing so, we visualize the formation and propagation of an oil bank by reconstructing multidimensional saturation maps. We conduct experiments on three distinct core sizes and two different surfactants, an SBDS/isbutanol formulation and an L-145-10s 90 formulation, in order to decouple the effect of these two parameters on the flow behavior observed in situ. We note that the oil production post oil bank breakthrough is primarily influenced by the surfactant choice, with the SDBS/isobutanol formulation displaying longer tailing production of a low oil cut. On the other hand, the core size dominated the extent of self-similarity of the saturation profiles with smaller cores showing less overlap in the self-similarity profiles. Consequently, we highlight the difference in applicability of a fractional flow approach to larger and smaller cores for upscaling parameter extraction and thus provide guidance for corefloods where direct imaging is not available.

Effects of conventional and ionic liquid-based surfactants and sodium tetraborate on interfacial tension of acidic crude oil

The application of a new class of surfactants such as ionic liquids (ILs) compared with the conventional surfactants and their interactions with each other concomitant and alkaline under salinities is not well examined based on the best knowledge of the authors. So, the current work focused on the impact of sodium lauryl sulfate (SDS), sodium dodecyl benzene sulfonate (SDBS), 1-dodecyl 3-methyl imidazolium chloride (C12mim][Cl]), 1-octadecyl 3-methyl imidazolium chloride ([C18mim][Cl]) in the presence and absence of alkali namely sodium tetraborate known as borax (Na2B4O7) on the IFT variation while the salinity was changed 0-82,000 ppm (ionic strength of 0-1.4 M). The results showed the positive impact of salinity on the pH reduction and reduced the alkaline effect for pH reduction. Also, the measurements showed that the presence of surfactant reduces the role of alkaline for pH variation as it moved from 9.2 to 6.63 for the solution prepared using SLS and SDBS. The measured IFT values showed that not only alkali has a significant impact as it combined with SLS and SDBS due to a desired synergy between these chemicals, it can reduce the critical micelle concentration (CMC) for the SDBS from 1105 to 852 ppm and much higher for [C12mim][Cl].

Influence of the cationic degree and molar mass of modified starches on their physicochemical properties and capability to enhance the oil recovery process

Polysaccharides and their derivatives are used as additives in numerous petroleum industrial processes, especially in enhanced oil recovery (EOR). There exists however, a lack of studies concerning how their physicochemical properties affect the oil recovery process. This work presents an investigation of a series of 2-hydroxy-3-(trimethylammonium)propyl starches (HTPS) with different molar masses and cationic degrees that are potentially useful for EOR. It was investigated surface/interfacial tensions, rheological profile, emulsion index and wettability alteration. The results provide experimental evidence that the HTPS intrinsic properties affect the measured properties. The HTPS solution/oil interfacial tension (IFT) ranged from a low value of 19.0 to a high value of 34.0 mN/m and correlates positively with the molar mass of the HTPS. In contrast, the rheological behavior displays correlations with the molar mass and the degree of cationization. Furthermore, the 1 % HTPS solutions presented around 10 % of viscosity increase in comparison to brines typically used in waterflooding. The derivative with a higher molar mass and intermediate degree of cationization (HTPS 2) was more effective in changing the wetting condition of an aged limestone with a wettability alteration index (WAI) of 52 % while the commercial surfactant cetyltrimethylammonium bromide (CTAB) presented a WAI of 32.6 %.

A comprehensive review of viscoelastic polymer flooding in sandstone and carbonate rocks

Polymer flooding is a proven chemical Enhanced Oil Recovery (cEOR) method that boosts oil production beyond waterflooding. Thorough theoretical and practical knowledge has been obtained for this technique through numerous experimental, simulation, and field works. According to the conventional belief, this technique improves macroscopic sweep efficiency due to high polymer viscosity by producing moveable oil that remains unswept after secondary recovery. However, recent studies show that in addition to viscosity, polymer viscoelasticity can be effectively utilized to increase oil recovery by mobilizing residual oil and improving microscopic displacement efficiency in addition to macroscopic sweep efficiency. The polymer flooding is frequently implemented in sandstones with limited application in carbonates. This limitation is associated with extreme reservoir conditions, such as high concentrations of monovalent and divalent ions in the formation brine and ultimate reservoir temperatures. Other complications include the high heterogeneity of tight carbonates and their mixed-to-oil wettability. To overcome the challenges related to severe reservoir conditions, novel polymers have been introduced. These new polymers have unique monomers protecting them from chemical and thermal degradations. Monomers, such as NVP (N-vinylpyrrolidone) and ATBS (2-acrylamido-2-methylpropane sulfonic acid), enhance the chemical resistance of polymers against hydrolysis, mitigating the risk of viscosity reduction or precipitation in challenging reservoir conditions. However, the viscoelasticity of these novel polymers and their corresponding impact on microscopic displacement efficiency are not well established and require further investigation in this area. In this study, we comprehensively review recent works on viscoelastic polymer flow under various reservoir conditions, including carbonates and sandstones. In addition, the paper defines various mechanisms underlying incremental oil recovery by viscoelastic polymers and extensively describes the means of controlling and improving their viscoelasticity. Furthermore, the polymer screening studies for harsh reservoir conditions are also included. Finally, the impact of viscoelastic synthetic polymers on oil mobilization, the difficulties faced during this cEOR process, and the list of field applications in carbonates and sandstones can also be found in our work. This paper may serve as a guide for commencing or performing laboratory- and field-scale projects related to viscoelastic polymer flooding.

Synthesis of Polyether Carboxylate and the Effect of Different Electrical Properties on Its Viscosity Reduction and Emulsification of Heavy Oil

Heavy oil exploitation needs efficient viscosity reducers to reduce viscosity, and polyether carboxylate viscosity reducers have a significant viscosity reduction effect on heavy oil. Previous work has studied the effect of different side chain lengths on this viscosity reducer, and now a series of polyether carboxylate viscosity reducers, including APAD, APASD, APAS, APA, and AP5AD (the name of the viscosity reducer is determined by the name of the desired monomer), with different electrical properties have been synthesized to investigate the effect of their different electrical properties on viscosity reduction performance. Through the performance tests of surface tension, contact angle, emulsification, viscosity reduction, and foaming, it was found that APAD viscosity reducers had the best viscosity reduction performance, reducing the viscosity of heavy oil to 81 mPa·s with a viscosity reduction rate of 98.34%, and the worst viscosity reduction rate of other viscosity reducers also reached 97%. Additionally, APAD viscosity reducers have the highest emulsification rate, and the emulsion formed with heavy oil is also the most stable. The net charge of APAD was calculated from the molar ratio of the monomers and the total mass to minimize the net charge. While the net charge of other surfactants was higher. It shows that the amount of the surfactant's net charge affects the surfactant's viscosity reduction effect, and the smaller the net charge of the surfactant itself, the better the viscosity reduction effect.

Efficiency and microbial community characteristics of strong alkali ASP flooding produced water treated by composite biofilm system

Strong alkali alkali-surfactant-polymer (ASP) flooding produced water is a by-product of oil recovery, and it is a stable system composed of petroleum, polyacrylamide, surfactant, and inorganic salts. Efficient, green, and safe ASP produced water treatment technology is essential for oilfield exploitation and environmental protection. In this study, an anaerobic/anoxic/moving bed biofilm reactor with a microfiltration membrane was established and assessed for the real strong alkali ASP flooding produced water (pH 10.1-10.4) treatment. The results show that the average removal rates of COD, petroleum, suspended solids, polymers and surfactants in this process are 57, 99, 66, 40, and 44%, respectively. GC-MS results show that most of the organic compounds such as alkanes and olefins in the strong alkali ASP produced water are degraded. Microfiltration membrane can significantly improve the efficiency and stability of sewage treatment system. Paracoccus (AN), Synergistaceae (ANO) and Trichococcus (MBBR) are the main microorganisms involved in the degradation of pollutants. This study reveals the potential and adaptability of composite biofilm system in treating the produced water of strong alkali ASP produced water.

Effect of Salinity on Hydroxyapatite Nanoparticles Flooding in Enhanced Oil Recovery: A Mechanistic Study

Fluid-fluid interactions can affect any enhanced oil recovery (EOR) method, including nanofluid (NF) brine-water flooding. Flooding with NFs changes wettability and lowers oil-water interfacial tension (IFT). Preparation and modification affect the nanoparticle (NP) performance. Hydroxyapatite (HAP) NPs in EOR are yet to be properly verified. HAP was synthesized in this study using co-precipitation and in situ surface functionalization with sodium dodecyl sulfate in order to investigate its impact on EOR processes at high temperatures and different salinities. The following techniques were employed, in that sequence, to verify its synthesis: transmission electron microscopy, zeta potential, thermogravimetric analysis, Fourier transform infrared spectroscopy, X-ray diffraction, particle size analysis, and energy-dispersive X-ray spectra. The outcomes showed the production of HAP, with the particles being evenly dispersed and stable in aqueous solution. The particles' surface charge increased from -5 to -27 mV when the pH was changed from 1 to 13. The HAP NFs at 0.1 wt % altered the wettability of sandstone core plugs from oil-wet at 111.7 to water-wet at 9.0 contact angles at salinity ranges of 5000 ppm to 30,000 ppm. Additionally, the IFT was reduced to 3 mN/m HAP with an incremental oil recovery of 17.9% of the initial oil in place. The HAP NF thus demonstrated excellent effectiveness in EOR through IFT reduction, wettability change, and oil displacement in both low and high salinity conditions.

Advances in CO2-switchable surfactants towards the fabrication and application of responsive colloids

CO₂-switchable surfactants have selective surface-activity, which can be activated or deactivated either by adding or removing CO₂ from the solution. This feature enables us to use them in the fabrication of responsive colloids, a group of dispersed systems that can be controlled by changing the environmental conditions. In chemical processes, including extraction, reaction, or heterogeneous catalysis, colloids are required in some specific steps of the processes, in which maximum contact area between immiscible phases or reactants is desired. Afterward, the colloids must be broken for the postprocessing of products, solvents, and agents, which can be facilitated by using CO₂-switchable surfactants in surfactant-stabilized colloids. These surfactants are mainly cationic and can be activated by the protonation of a nitrogen-containing group upon sparging CO₂ gas. Also, CO₂-switchable superamphiphiles can be formed by non-covalent bonding between components at least one of which is CO₂-switchable. So far, CO₂-switchable surfactants have been used in CO₂-switchable spherical and wormlike micelles, vesicles, emulsions, foams, and Pickering emulsions. Here, we review the fabrication procedure, chemical structure, switching scheme, stability, environmental conditions, and design philosophy of such responsive colloids. Their fields of application are wide, including emulsion polymerization, catalysis, soil washing, drug delivery, extraction, viscosity control, and oil transportation. We also emphasize their application for the CO₂-assisted enhanced oil recovery (EOR) process as a promising approach for carbon capture, utilization, and storage to combat climate change.

Preparation and Study of Polyvinyl Alcohol Gel Structures with Acrylamide and 2-Acrylamido-2-methyl-1-propanesulfonic Acid for Application in Saline Oil Reservoirs for Profile Modification

Polymer gels can be effectively applied to plug fractured reservoirs and carbonate cave strata. Herein, polyvinyl alcohol (PVA), acrylamide, and 2-acrylamido-2-methyl-1-propanesulfonic acid (AMPS) were used as raw materials to prepare interpenetrating three-dimensional network polymer gels using formation saltwater in the Tahe oilfield (Tarim Basin, NW China) as a solvent. The effect of AMPS concentration on the gelation properties of PVA in high-temperature formation saltwater was analyzed. Further, the effect of PVA concentration on the strength and viscoelastic properties of polymer gel was studied. The polymer gel could retain stable continuous entanglement at 130 °C and exhibited satisfactory thermal stability. Continuous step oscillation frequency tests showed that it exhibited an excellent self-healing performance. Scanning electron microscopy images of the simulated core by gel plugging showed that the polymer gel could firmly fill the porous media, indicating that the polymer gel exhibits excellent application prospects in oil and gas reservoirs under high-temperature and high-salinity conditions.

A review on application of nanoparticles for EOR purposes: history and current challenges

Applications of nanotechnology in several fields of petroleum industry, e.g., refinery, drilling and enhanced oil recovery (EOR), have attracted a lot of attention, recently. This research investigates the applications of nanoparticles in EOR process. The potential of various nanoparticles, in hybrid and bare forms for altering the state of wettability, reducing the interfacial tension (IFT), changing the viscosity and activation of other EOR mechanisms are studied based on recent findings. Focusing on EOR, hybrid applications of nanoparticles with surfactants, polymers, low-salinity phases and foams are discussed and their synergistic effects are evaluated. Also, activated EOR mechanisms are defined and specified. Since the stabilization of nanofluids in harsh conditions of reservoir is vital for EOR applications, different methods for stabilizing nanofluids through EOR procedures are reviewed. Besides, a discussion on different functional groups of NPs is represented. Later, an economic model for evaluation of EOR process is examined and "Hotelling" method as an appropriate model for investigation of economic aspects of EOR process is introduced in detail. The findings of this study can lead to better understanding of fundamental basis about efficiency of nanoparticles in EOR process, activated EOR mechanisms during application of nanoparticles, selection of appropriate nanoparticles, the methods of stabilizing and economic evaluation for EOR process with respect to costs and outcomes.

A Critical Overview of ASP and Future Perspectives of NASP in EOR of Hydrocarbon Reservoirs: Potential Application, Prospects, Challenges and Governing Mechanisms

Oil production from depleted reservoirs in EOR (Enhanced Oil Recovery) techniques has significantly increased due to its huge demands in industrial energy sectors. Chemical EOR is one of the best approaches to extract the trapped oil. However, there are gaps to be addressed and studied well for quality and cost consideration in EOR techniques. Therefore, this paper addresses for the first time a systematic overview from alkaline surfactant polymer ((ASP)) and future perspectives of nano-alkaline surfactant polymer ((NASP)), its synergy effects on oil recovery improvement, and the main screening criteria for these chemicals. The previous findings have demonstrated that the optimum salinity, choosing the best concentration, using effective nano-surfactant, polymer and alkaline type, is guaranteed an ultra-low IFT (Interfacial Tension). Core flood results proved that the maximum oil is recovered by conjugating nanoparticles with conventional chemical EOR methods (surfactant, alkaline and polymer). This work adds a new insight and suggests new recommendation into the EOR application since, for the first time, it explores the role and effect of nanotechnology in a hybrid with ASP. The study illustrates detailed experimental design of using NASP and presents an optimum micro-model setup for future design of NASP flow distribution in the porous media. The presence of nano along with other chemicals increases the capillary number as well as the stability of chemicals in the solution and strengthens the effective mechanisms on the EOR.

Upgrading the Properties of the Crude Oil-Water System for EOR with Simultaneous Effects of a Homologous Series of NanoGemini Surface-Active Ionic Liquids, Electrolytes, and pH

This study investigated the simultaneous effects of electrolytes, NaCl and MgCl₂ electrolytes, individually and as a mixture, and pH on a homologous series of imidazolium nano-Gemini surface-active ionic liquids (GSAILs), [C₄im-C _m -imC₄][Br₂], where m = 2, 4, and 6. These can improve the properties of the crude oil-water system and consequently enhance the oil recovery. The results precisely revealed that interfacial tension (IFT) and critical micelle concentration were initially decreased with electrolyte concentration up to 55.7 and 58.6%, respectively, in comparison to the salt-free condition, followed by a slight increase. Moreover, adjusting the pH can provide a further improvement so that 79.2% IFT reduction is attained at pH 9.5 compared to that at the natural pH and that GSAILs show high stability in the pH range of 2.5-9.5. Meanwhile, aqueous solutions of crude oil and electrolyte presented 1 day emulsification indices within 43-53%, followed by minor changes after 1 week. Interestingly, the emulsification index of 77.1% was attained at pH 9.5. Surface wettability was also favorably altered from oil-wet to water-wet with the nanoGSAILs. The findings of this study help gain a better understanding of the effects of nanosurface active materials to improve oil extraction under reservoir conditions.

Adsorption of the Xanthan Gum Polymer and Sodium Dodecylbenzenesulfonate Surfactant in Sandstone Reservoirs: Experimental and Density Function Theory Studies

Chemical flooding using a polymer and/or surfactant has been widely applied in oilfields worldwide for enhanced oil recovery. Chemical adsorption in reservoirs has a significant effect on the rock permeability and wettability and hence can affect the overall oil production. In this work, two chemicals, namely, the xanthan gum (XG) biopolymer and sodium dodecylbenzenesulfonate (SDBS) anionic surfactant, were used individually as displacement fluids. The amount of chemical adsorption on the rock surface and the residual resistance factor (permeability reduction) were calculated throughout the flooding experiments using an unconsolidated sandstone (SS) pack model. The effects of the injected chemicals' concentration and reservoir salinity on adsorption capacity have been examined. Additionally, the effect of the addition of nanosilica particles (NSPs) to the injected fluid on the rock adsorption was also investigated. The results showed that the amount of XG and SDBS adsorption on the rock surface increased, albeit to a different extent, by increasing the chemical concentration at the applied salinities (0, 3.5, 5, and 10%) of the displacement fluids. Also, the permeability reduction increased with the increase in XG and SDBS concentrations; however, permeability reduction due to SDBS flooding was lower than that of XG in SS. The use of NSPs as a coinjectant to the XG and SDBS displacement fluids increased the adsorption on the SS rock. A plausible mechanism for the adsorption of the XG/NSP and SDBS/NSP blends on the SS surface was proposed. A density function theory calculation was employed to establish a relation between the adsorptivity of NSPs on SDBS and XG and the total energy and dipole moment of the molecules.

Adsorption Dynamics of Surface-Modified Silica Nanoparticles at Solid-Liquid Interfaces

Understanding the adsorption dynamics of nanoparticles at solid-liquid interfaces is of paramount importance to engineer nanoparticles for a variety of applications. The nanoparticle surface chemistry is significant for controlling the adsorption dynamics. This study aimed to experimentally examine the adsorption of surface-modified round-shaped silica nanoparticles (with an average diameter of 12 nm), grafted with hydrophobic (propyl chains) and/or hydrophilic (polyethylene glycol chains) agents, at an aqueous solution-silica interface with spherical soda-lime glass beads (diameter of 3 mm) being used as adsorbents. While no measurable adsorption was observed for solely hydrophobic or hydrophilic nanoparticles, a considerable level of adsorption was detected for nanoparticles comprising both hydrophobic and hydrophilic agents. Various kinetic models were employed to model the adsorption dynamics of the responsive nanoparticles. The results demonstrated that the mixed diffusion-kinetics models could predict the dynamics better than the adsorption diffusion models, indicating that the dynamics is controlled by a combination of liquid film diffusion, intra-particle diffusion, and mass action. Additionally, the adsorption of the surface-modified silica nanoparticles onto a mineral silica surface was examined using molecular dynamics simulations. The interaction energy for nanoparticles comprising both hydrophobic and hydrophilic agents was evaluated to be more favorable than that of solely hydrophobic or hydrophilic nanoparticles.

Silicate Scaling Formation: Impact of pH in High-Temperature Reservoir and Its Characterization Study

Silicate scaling tends to form and be aggravated during high pH Alkaline Surfactant Polymer (ASP) floods and this silicate scale deposition affects oil production. Hence, it is important to examine the conditions that lead to silicate scale forming. The severity of the silicate scaling reaction, the type and morphology of silica/silicate scale formed in an experimental ASP flood were studied for pH values 5, 8.5, and 11, whilst the temperature was kept constant at 90 ℃. In addition, the impact of calcium ion was studied and spectroscopic analyses were used to identify the extent of scaling reaction, morphology type and the functional group present in the precipitates. This was performed using imagery of the generated precipitates. It was observed that the silica/silicate scale is most severe at the highest pH and Ca:Mg molar ratios examined. Magnesium hydroxide and calcium hydroxide were observed to precipitate along with the silica and Mg-silicate/Ca-silicate scale at pH 11. The presence of calcium ions altered the morphology of the precipitates formed from amorphous to microcrystalline/crystalline. In conclusion, pH affects the type, morphology, and severity of the silica/silicate scale produced in the studied scaling system. The comprehensive and conclusive data showing how pH affects the silicate scaling reaction reported here are vital in providing the foundation to further investigate the management and prevention of this silicate scaling. Copyright © 2022 by Authors, Published by BCREC Group. This is an open access article under the CC BY-SA License (https://creativecommons.org/licenses/by-sa/4.0)

Directly Mapping the Spatial Distribution of Organic Compounds on Mineral Rock Surfaces by DESI and LAESI Mass Spectrometry Imaging

Here, we present a new application of desorption electrospray ionization (DESI) and laser ablation electrospray ionization (LAESI) mass spectrometry imaging to assess the spatial location of organic compounds, both polar and nonpolar, directly from rock surfaces. Three carbonaceous rocks collected from an aquatic environment and a berea sandstone subjected to a small-scale oil recovery experiment were analyzed by DESI and LAESI. No rock pretreatment was required before DESI and LAESI analyses. DESI detected and spatially mapped several fatty acids and a disaccharide on the surfaces of carbonaceous rocks, and various nitrogenated and oxygenated compounds on the surfaces of berea sandstone. In contrast, LAESI using a 3.4 μm infrared laser beam was able to detect and map hydrocarbons on the surfaces of all rock samples. Both techniques can be combined to analyze polar and nonpolar compounds. DESI can be used first to detect polar compounds, as it does not destroy the rock surface, and LAESI can then be used to analyze nonpolar analytes, as it destroys a layer of the sample surface. Both techniques have the potential to be used in several scientific areas involving rocks and minerals, such as in the analysis of industry-derived contaminants in aquatic sediments or in small-scale rock-fluid interaction experiments.

Application of α-MnO2 nanoparticles for residual oil mobilization through surfactant polymer flooding

Injection of surfactant and polymer slug is among the most effective chemical enhanced oil recovery processes. The only problem encountered with the surfactant polymer (SP) flooding is the loss of surface-active agents that reduce the efficiency of surfactants in the chemical slug. Various attempts to modify SP flooding have been made previously so that the surfactant loss due to adsorption could be reduced. Nanoparticles (NPs) are one of the most effective ways of reducing surfactant adsorption as surfactant particles are held in the liquid phase by nanoparticles, resulting in lower surfactant losses due to adsorption. However, the high cost of the NPs limits their use on the field scale. To encounter this problem, the present study focuses on the application of the manganese dioxide NPs, synthesized through a green route that is economically viable. These NPs are found to be cost-effective as compared to commercially available NPs as well as the synthesis of these NPs does not require the use of toxic chemicals. The 1000 ppm NPs effectively reduced the surfactant adsorption by 46%. The surface tension was lowered from 29.4 to 26.1 mN/m when 1000 ppm NPs were applied to 2500 ppm surfactant solution. Also, the nanoparticles were found to increase the viscosity of the chemical slug by increasing the solid particles present in the slug. The sand pack flooding experiments were carried out to assess the crude oil mobilization ability of the NPs assisted SP flooding. The oil recovery was found to increase from 5% of the original oil in place, resulting in ~ 75% of the crude oil recovery, which was only ~ 70% when NPs were not introduced into the system.

Modified smart water flooding for promoting carbon dioxide utilization in shale enriched heterogeneous sandstone under surface conditions for oil recovery and storage prospects

Modern oil reservoirs exhibit high macro-scale heterogeneity, i.e., presence of shales and clays, which complicate the implementation of conventional enhanced oil recovery (EOR) practices. Hence, there is a need to investigate new class of EOR methods which not only improve recovery of oil from reservoir but also reduce formation damage. Thus, in this study, synthetic smart brines of varying salinity were formulated to investigate carbon utilization in shaly-sandstone for oil recovery and sequestration applications. To prepare shaly-sandstone samples, shale content in sand varied between 0 and 25 wt%. The addition of shale reduced porosity and permeability of sand-packs, and porosity ~ 25 and permeability < 10 md were measured for a combination of 75% sand + 25% shale which were originally 38% and 692 md for 100% sand + 0% shale. The oil recovery experiments were performed at temperature ≈ 40 °C and ambient pressure. The impact of shale content was insignificant on CO₂-based oil recovery resulting its value remained nearly constant (5-7%). Smart saline water (SSW) solutions were prepared through the dilution of formation water (FW) of typical oilfield salinity and used these SSW solutions in investigating shale swelling and interfacial tension with CO₂. Compared to other SSW solutions, SSW-2 (1 part FW/9 part water: 1/10th of FW) demonstrated superior control on mitigating shale swelling (by 67%) and reduce interfacial tension (by 30%) when compared to FW. Moreover, it helped to mobilize higher amount of oil (50% OOIP) from sand-pack (80% sand + 20% shale) in which conventional water flood failed to perform, indicating its viability for EOR from heterogeneous reservoir. In addition, SSW solutions promoted use of carbonated (CO₂-enriched) water injection for oil recovery from sandstone exhibiting high shale content of 20% as over 5-8% higher oil recovery was obtained compared to conventional water flooding. Comparative performance of water flooding, salinity water-alternating CO₂ flooding and carbonated smart water injection in heterogeneous sandstone.

Hydrophobically Associating Polymers Dissolved in Seawater for Enhanced Oil Recovery of Bohai Offshore Oilfields

As compared to China’s overall oil reserves, the reserve share of offshore oilfields is rather significant. However, offshore oilfield circumstances for enhanced oil recovery (EOR) include not just severe temperatures and salinity, but also restricted space on offshore platforms. This harsh oil production environment requires polymers with relatively strong salt resistance, solubility, thickening ability, rapid, superior injection capabilities, and anti-shearing ability. As a result, research into polymers with high viscosity and quick solubility is recognized as critical to meeting the criteria of polymer flooding in offshore oil reservoirs. For the above purposes, a novel hydrophobically associating polymer (HAP) was prepared to be used for polymer flooding of Bohai offshore oilfields. The synthetic procedure was free radical polymerization in aqueous solutions starting at 0 °C, using acrylamide (AM), acrylic acid (AA), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), and poly(ethylene glycol) octadecyl methacrylate (POM) as comonomers. It was discovered that under ideal conditions, the molecular weight of HAP exceeds 2.1 × 10⁷ g⋅mol⁻¹. In a simulated reservoir environment, HAP has substantially greater solubility, thickening property, and salt resistance than conventional polyacrylamide (HPAM), with equivalent molecular weight. Finally, the injectivity and propagation of the two polymers in porous media were investigated. Compared with HPAM, which has a similar molecular weight, HAP solution with the concentration of 0.175% had a much better oil displacement effect in the porous medium, which can enhance oil recovery by 8.8%. These discoveries have the potential to pave the way for chemical EOR in offshore oilfields.

The Degassing Processes for Oil Media in Acoustic Fields and Their Applications

Numerous experiments on the effect of acoustic fields on oil media have shown the changing nature of oil physicochemical properties. In the present paper, we present a concept of internal airlift for oil medium with dissolved gas which could be propelled by external acoustic field. The mechanism determining gas bubble size as a function of pressure change is discussed. Model of interaction for the growing bubbles with acoustic fields is presented. Relationships specifying the characteristics of both the required acoustic field and oil medium are derived. The use of these relations makes it possible to define the available range of parameters for the system under consideration where one can obtain the expected effect on oil medium. It is demonstrated how the change in pressure and oil saturation (namely, the density of oil particles in the entire flow) of the medium is associated with temperature fields in the system. In particular, it is shown that the maximum deviation between the temperature change in oil and gas and gas–liquid media reaches a significant value, namely 10⁻² K for a gas–liquid medium, while this difference is −0.1 K in an oil-and-gas medium. Using this approach, thermograms of oil producing wells have been analysed at a qualitative level.

Application of Polymers for Chemical Enhanced Oil Recovery: A Review

Polymers play a significant role in enhanced oil recovery (EOR) due to their viscoelastic properties and macromolecular structure. Herein, the mechanisms of the application of polymeric materials for enhanced oil recovery are elucidated. Subsequently, the polymer types used for EOR, namely synthetic polymers and natural polymers (biopolymers), and their properties are discussed. Moreover, the numerous applications for EOR such as polymer flooding, polymer foam flooding, alkali–polymer flooding, surfactant–polymer flooding, alkali–surfactant–polymer flooding, and polymeric nanofluid flooding are appraised and evaluated. Most of the polymers exhibit pseudoplastic behavior in the presence of shear forces. The biopolymers exhibit better salt tolerance and thermal stability but are susceptible to plugging and biodegradation. As for associative synthetic polyacrylamide, several complexities are involved in unlocking its full potential. Hence, hydrolyzed polyacrylamide remains the most coveted polymer for field application of polymer floods. Finally, alkali–surfactant–polymer flooding shows good efficiency at pilot and field scales, while a recently devised polymeric nanofluid shows good potential for field application of polymer flooding for EOR.

Interfacial Properties, Wettability Alteration and Emulsification Properties of an Organic Alkali-Surface Active Ionic Liquid System: Implications for Enhanced Oil Recovery

Combinatory flooding techniques evolved over the years to mitigate various limitations associated with unitary flooding techniques and to enhance their performance as well. This study investigates the potential of a combination of 1-hexadecyl-3-methyl imidazolium bromide (C₁₆mimBr) and monoethanolamine (ETA) as an alkali–surfactant (AS) formulation for enhanced oil recovery. The study is conducted comparative to a conventional combination of cetyltrimethylammonium bromide (CTAB) and sodium metaborate (NaBO₂). The study confirmed that C₁₆mimBr and CTAB have similar aggregation behaviors and surface activities. The ETA–C₁₆mimBr system proved to be compatible with brine containing an appreciable concentration of divalent cations. Studies on interfacial properties showed that the ETA–C₁₆mimBr system exhibited an improved IFT reduction capability better than the NaBO₂–CTAB system, attaining an ultra-low IFT of 7.6 × 10⁻³ mN/m. The IFT reduction performance of the ETA–C₁₆mimBr system was improved in the presence of salt, attaining an ultra-low IFT of 2.3 × 10⁻³ mN/m. The system also maintained an ultra-low IFT even in high salinity conditions of 15 wt% NaCl concentration. Synergism was evident for the ETA–C₁₆mimBr system also in altering the carbonate rock surface, while the wetting power of CTAB was not improved by the addition of NaBO₂. Both the ETA–C₁₆mimBr and NaBO₂–CTAB systems proved to form stable emulsions even at elevated temperatures. This study, therefore, reveals that a combination of surface-active ionic liquid and organic alkali has excellent potential in enhancing the oil recovery in carbonate reservoirs at high salinity, high-temperature conditions in carbonate formations.

Adsorption Study of Novel Gemini Cationic Surfactant in Carbonate Reservoir Cores-Influence of Critical Parameters

Surfactant flooding is an enhanced oil recovery method that recovers residual and capillary trapped oil by improving pore-scale displacement efficiency. Low retention of injected chemicals is desired to ensure an economic and cost-effective recovery process. This paper examines the adsorption behavior of a novel gemini cationic surfactant on carbonate cores. The rock cores were characterized using an X-ray diffraction (XRD) spectroscope. In addition, the influence of critical parameters on the dynamic adsorption of the cationic gemini surfactant was studied by injecting the surfactant solution through carbonate cores in a core flooding apparatus until an equilibrium state was achieved. The concentration of surfactant was observed using high performance liquid chromatography. Experimental results showed that an increasing surfactant concentration causes higher retention of the surfactant. Moreover, increasing the flow rate to 0.2 mL/min results in lowering the surfactant retention percentage to 17%. At typical high salinity and high temperature conditions, the cationic gemini surfactant demonstrated low retention (0.42 mg/g-rock) on an Indiana limestone core. This study extends the frontier of knowledge in gemini surfactant applications for enhanced oil recovery.

Recovery Observations from Alkali, Nanoparticles and Polymer Flooding as Combined Processes

We have studied wettability alterations through imbibition/flooding and their synergy with interfacial tension (IFT) for alkalis, nanoparticles and polymers. Thus, the total acid number (TAN) of oil may determine the wetting-state of the reservoir and influence recovery and IFT. Data obtained demonstrate how the oil TAN number (low and high), chemical agent and reservoir mineralogy influence fluid–fluid and rock–fluid interactions. We used a laboratory evaluation workflow that combines complementary assessments such as spontaneous imbibition tests, IFT, contact angle measurements and selected core floods. The workflow evaluates wettability alteration, IFT changes and recovery when injecting alkalis, nanoparticles and polymers, or a combination of them. Dynamics and mechanisms of imbibition were tracked by analyzing the recovery change with the inverse bond number. Three sandstone types (outcrops) were used, which mainly differed in clay content and permeability. Oils with low and high TANs were used, the latter from the potential field pilot 16 TH reservoir in the Matzen field (Austria). We have investigated and identified some of the conditions leading to increases in recovery rates as well as ultimate recovery by the imbibition of alkali, nanoparticle and polymer aqueous phases. This study presents novel data on the synergy of IFT, contact angle Amott imbibition, and core floods for the chemical processes studied.

Sorption of Nanomaterials to Sandstone Rock

We investigated the interaction of silica nanostructured particles and sandstone rock using various experimental approaches, such as fluid compatibility, batch sorption and single-phase core-floods. Diol and polyethylenglycol (PEG) surface-modified nanostructured silica materials were tested using two brines differing in ionic strength and with the addition of sodium carbonate (Na₂CO₃). Berea and Keuper outcrop materials (core plug and crushed samples) were used. Core-flood effluents were analysed to define changes in concentration and a rock's retention compared to a tracer. Field Flow Fractionation (FFF) and Dynamic Light Scattering (DLS) were performed to investigate changes in the effluent's size distribution. Adsorption was evaluated using UV-visible spectroscopy and scanning electron microscopy (SEM). The highest adsorption was observed in brine with high ionic strength, whereas the use of alkali reduced the adsorption. The crushed material from Berea rock showed slightly higher adsorption compared to Keuper rock, whereas temperature had a minor effect on adsorption behaviour. In core-flood experiments, no effects on permeability have been observed. The used particles showed a delayed breakthrough compared to the tracer, and bigger particles passed the rock core faster. Nanoparticle recovery was significantly lower for PEG-modified nanomaterials in Berea compared to diol-modified nanomaterials, suggesting high adsorption. SEM images indicate that adsorption spots are defined via surface roughness rather than mineral type. Despite an excess of nanomaterials in the porous medium, monolayer adsorption was the prevailing type observed.